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, 2013

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.)
1001 Louisiana Street, Suite 2900 Houston, TX	77002
Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (713) 654-2200

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

As of June 30, 2013, 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 28, 2013 was $4.07 billion). As of February 17, 2014, there were 158,613,126 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, 2013

TABLE OF CONTENTS

		Page
PART I
Item 1	Business		4
	Executive Officers of Registrant		9
Item 1A	Risk Factors		10
Item 1B	Unresolved Staff Comments		16
Item 2	Properties		16
Item 3	Legal Proceedings		16
Item 4	Mine Safety Disclosures		16
PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities		17
Item 6	Selected Financial Data		19
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		20
Item 7A	Quantitative and Qualitative Disclosures about Market Risk		34
Item 8	Financial Statements and Supplementary Data		36
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		81
Item 9A	Controls and Procedures		81
Item 9B	Other Information		84
PART III
Item 10	Directors, Executive Officers and Corporate Governance		84
Item 11	Executive Compensation		84
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		84
Item 13	Certain Relationships and Related Transactions, and Director Independence		84
Item 14	Principal Accounting Fees and Services		84
PART IV
Item 15	Exhibits, Financial Statement Schedules		85

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FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K, as well as other filings made by us with the Securities and Exchange Commission (SEC), and our releases to the public, contain 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. Forward-looking statements involve risks and uncertainties. All statements other than statements of historical fact included in this Annual Report on Form 10-K regarding our financial position and liquidity, strategic alternatives, future capital needs, business strategies and other plans and objectives of our management for future operations and activities are forward-looking statements. These statements are based on certain assumptions and analyses made by our management in light of its experience and its perception of historical trends, current market and industry conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such forward-looking statements are subject to uncertainties that could cause our actual results to differ materially from such statements. Such uncertainties include, but are not limited to: risks inherent in acquiring businesses, the effect of regulatory programs and environmental matters on our performance, including the risk that future changes in the regulation of hydraulic fracturing could reduce or eliminate demand for our pressure pumping services; risks associated with business growth outpacing the capabilities of our infrastructure and workforce; risks associated with the uncertainty of macroeconomic and business conditions worldwide; the cyclical nature and volatility of the oil and gas industry, including the level of exploration, production and development activity and the volatility of oil and gas prices; changes in competitive factors affecting our operations; political, economic and other risks and uncertainties associated with international operations; the impact that unfavorable or unusual weather conditions could have on our operations; the potential shortage of skilled workers; our dependence on certain customers; the risks inherent in long-term fixed-price contracts; and, operating hazards, including the significant possibility of accidents resulting in personal injury or death, property damage or environmental damage. These risks and other uncertainties related to our business are described in detail below in Part I, Item 1A of this Annual Report on Form 10-K. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. 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, including for example the market prices of oil and natural gas and regulations affecting oil and gas operations, which we cannot control or anticipate. Further, we may make changes to our business plans that could or will affect our results. We undertake no obligation to update any of our forward-looking statements and we do not intend to update our forward-looking statements more frequently than quarterly, notwithstanding any changes in our assumptions, changes in our business plans, our actual experience, or other changes. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof.

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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 enhanced our full suite of intervention services used to carry out wellbore maintenance operations during a well’s producing phase.

We serve energy industry customers who focus on developing and producing oil and gas worldwide. Our operations are managed and organized by both business units and geomarkets, which offer products and services within the various phases of a well’s economic life cycle. 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: U.S. land, Gulf of Mexico and international.

For information about our operating segments and financial information by geographic area refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in Part II, Item 7 of this Annual Report on Form 10-K and note 12 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

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 February 2012 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 a leading provider 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;

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

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

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. A description of the products and services offered by our four segments is as follows:

• 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 management – 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 – Includes 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 – Includes products and services that 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.

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• 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.

• 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 subsea and offshore Marine engineering and design, harsh environment engineering, 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 10% and 13% of our revenues in 2013 and 2012, respectively, primarily within the Onshore Completion and Workover segment. 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, disruptions caused by weather 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 geographic markets for products and services.

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 personnel 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, in all cases 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

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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.

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 and equipment, including our underground injection wells, marine vessels, trucks and other heavy equipment. These permits can be revoked, modified or renewed by issuing authorities based on factors both within and outside our control.

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 2014.

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, 2013, we had approximately 14,500 employees. Approximately 7% of our employees are subject to union contracts, all of which are in international locations. We believe that our relationship with our employees is good.

Facilities

Our principal executive offices are located at 1001 Louisiana Street, Suite 2900, Houston, Texas, 77002. 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.

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Other Information

We have our principal executive offices at 1001 Louisiana Street, Suite 2900, Houston, Texas 77002. Our telephone number is (713) 654-2200. We also have a website at http://www.superiorenergy.com. Copies of the annual, quarterly and current reports we file with the SEC, and any amendments to those reports, are available on our website free of charge soon after such reports are filed with or furnished to the SEC. The information posted on our website is not incorporated into this Annual Report on Form 10-K. Alternatively, you may access these reports at the SEC’s website at 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.

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Executive Officers of Registrant

David D. Dunlap, age 52, 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 59, 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 56, 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 57, was appointed Senior Executive Vice President of North America Services on February 7, 2012. From March 2007 until the effectiveness of the Complete acquisition in 2012, 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 42, 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 45, 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 56, 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 LLP for more than 20 years.

Gregory A. Rosenstein, age 46, 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 previously served as Vice President of Investor Relations. He has been with us since March 2000.

Danny R. Young, age 58, 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.

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Item 1A. Risk Factors

The following information should be read in conjunction with management’s discussion and analysis of financial condition and results of operations contained in Part II, Item 7 and the consolidated financial statements and related notes contained in Part II, Item 8 of this Annual Report on Form 10-K, as well as, in conjunction with the matters contained under the caption “Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K.

The risks described below could materially and adversely affect our business, results of operations, financial condition and liquidity, as well as adversely affect the value of an investment in our securities. These risks are not the only risks that we face. Our business operations could also be affected by additional factors that apply to all companies operating in the U.S. and globally, as well as other risks that are not presently known to us or that we currently consider to be immaterial to our operations. These risks include:

Our business depends on conditions in the oil and gas industry, especially oil and gas prices and capital expenditures by oil and natural gas companies.

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. Lower oil and natural gas prices generally lead to decreased spending by our customers. While higher oil and natural gas prices generally lead to increased spending by our customers, sustained high energy prices can be an impediment to economic growth, and can therefore negatively impact spending by our customers. Our customers also take into account the volatility of energy prices and other risk factors by requiring higher returns for individual projects if there is higher perceived risk. Any of these factors could affect the demand for oil and natural gas and could have a material effect on our results of operations.

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 cost of exploring for, producing and delivering oil and natural 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 natural 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;

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• 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.

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 generally 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.

Lower capital spending by our customers could affect demand and pricing for our services which could adversely affect our results of operations.

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 not reached the levels 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.

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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 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 remains 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 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 and/or cost to retain key employees and skilled workers could adversely affect our operations.

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.

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Our international operations and revenue are affected by political, economic and other uncertainties worldwide.

In 2013, we conducted business in approximately 75 countries, and we intend to expand our international operations. 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.

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. International 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, and to enforce those 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

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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 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.

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. 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 international markets 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

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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 lead to, among other things, a loss of our investment in the country, impairment of the safety of our employees and impairment of our ability to conduct our operations. 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 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.

Our operations may be subject to cyber attacks that could have an adverse effect on our business operations.

Our operations may be subject to the risk of cyber attacks. If our systems for protecting against cybersecurity risks prove not to be sufficient, we could be adversely affected by, among other things, loss or damage of proprietary information or customer data, having our business operations interrupted, and increased costs to prevent, respond to, or mitigate cybersecurity attacks.

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 or deliver a product for a fixed price. Prices for

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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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Information on properties is contained in Part I, Item 1 of this Annual Report on Form 10-K.

Item 3. Legal Proceedings

We are involved in various legal and other proceedings and claims that are incidental to the conduct of our business. Our management does not believe that the outcome of any ongoing proceedings, individually or collectively, would have a material adverse effect on our financial condition, results of operations or cash flows.

Item 4. Mine Safety Disclosures

Not Applicable.

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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
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
2013
First Quarter	$	27.36	$	21.10
Second Quarter		29.22		22.89
Third Quarter		28.13		24.43
Fourth Quarter		28.32		24.28

As of February 17, 2014, there were 158,613,126 shares of our common stock outstanding, which were held by 136 record holders.

Dividend Information

On December 10, 2013, our Board of Directors initiated a quarterly dividend program and declared an initial quarterly dividend of $0.08 per share on the outstanding common stock. The initial dividend was paid on February 19, 2014 to all shareholders of record as of January 30, 2014.

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 Form 10-K.

Issuer Purchases of Equity Securities

The following table provides information about shares of our common stock repurchased and retired during each month for the three months ended December 31, 2013:

Period	Total Number of Shares Purchased (1)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2)		Approximate Dollar Value of Shares that May Yet be  Purchased Under the Plan or Programs
October 1 - 31, 2013		663	$	20.72		—	$	400,000,000
November 1 - 30, 2013		300	$	26.76		—	$	400,000,000
December 1 - 31, 2013		426,883	$	24.91		426,883	$	389,364,000
Total		427,846	$	24.91		426,883	$	389,364,000

⁽¹⁾  Through our stock incentive plans, 963 shares were delivered to us by our employees to satisfy their tax withholding requirements upon vesting of restricted stock.

⁽²⁾ On October 14, 2013, we announced that our Board of Directors authorized a $400 million share repurchase program of our common stock, which will expire on December 31, 2015.

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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, 2013 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, 2009 at closing prices on December 31, 2008.

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

	Years Ended December 31,
	2009		2010		2011		2012		2013
Superior Energy Services, Inc.	$	152	$	220	$	179	$	130	$	167
S&P 500 Stock Index	$	126	$	146	$	149	$	172	$	228
Peer Group	$	164	$	221	$	196	$	193	$	255

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, 2008.

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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 of our Board of Directors 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” included in Part II, Item 7 of this Annual Report on Form 10-K and our consolidated financial statements included in Part I, Items 7 and 8, respectively, in this Annual Report on Form 10-K. The financial data is in thousands, except per share amounts.

				Years Ended December 31,
	2013			2012			2011			2010			2009
Revenues	$	4,611,824		$	4,568,068		$	1,964,332		$	1,563,043		$	1,320,641
Income (loss) from operations		30,789			706,522			296,389			173,852			(81,396	)
Net income (loss) from continuing operations		(111,418	)		383,142			159,389			86,146			(120,540	)
Income (loss) from discontinued operations, net of tax		—			(17,207	)		(16,835	)		(4,329	)		18,217
Net income (loss)		(111,418	)		365,935			142,554			81,817			(102,323	)
Net income (loss) from continuing operations per share:
Basic		(0.70	)		2.57			2.00			1.09			(1.54	)
Diluted		(0.70	)		2.54			1.97			1.08			(1.54	)
Net income (loss) from discontinued operations per share:
Basic		—			(0.12	)		(0.21	)		(0.05	)		0.23
Diluted		—			(0.12	)		(0.21	)		(0.05	)		0.23
Net income (loss) per share:
Basic		(0.70	)		2.45			1.79			1.04			(1.31	)
Diluted		(0.70	)		2.42			1.76			1.03			(1.31	)
Cash dividends per share		0.08			—			—			—			—
Total assets*		7,411,307			7,802,886			4,048,145			2,907,533			2,516,665
Long-term debt, net, net of current portion*		1,646,535			1,814,500			1,685,087			681,635			848,665
Decommissioning liabilities, less current portion		56,197			93,053			108,220			100,787			—
Stockholders’ equity		4,131,444			4,231,079			1,453,599			1,280,551			1,178,045

* Total assets and long-term debt, net include amounts related to discontinued operations for years 2009 through 2011.

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

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

Executive Summary

We believe we are a leading provider of specialized oilfield services and equipment. We offer a wide variety of products and services throughout the life cycle of an oil and gas well. The acquisition of Complete Production Services, Inc. (Complete) in February 2012 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 life cycle, 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: U.S. land, Gulf of Mexico and international.

The fourth quarter of 2013 continued to present us with challenges primarily relating to the execution of our strategies within our Subsea and Technical Solutions segment. We also took actions based on negative outlooks in Venezuela and Mexico. As a result of these circumstances, we recorded $419.4 million of pre-tax charges for reduction in value of assets during the quarter. The charges were as follows:

• We incurred pre-tax charges of $91.0 million relating to reduction in value of goodwill and $328.4 million relating to the reduction in value of certain assets. The entire reduction in value of goodwill and $280.5 million of the reduction in value of assets are within the Subsea and Technical Solutions segment, relating primarily to our Asia Pacific-based subsea construction business and the Marine Technical Services business. During the fourth quarter, our management began a strategic review and analysis of our subsea construction business and has determined to pursue strategic alternatives for that business. Also included in the charges for reduction in value of assets was approximately $28.7 million related to the write down of assets in Venezuela and the diminished value of assets located in Mexico. Based on actions taken by Petroleos de Venezuela SA, the Venezuelan state oil company, including the seizure of certain of our assets in 2013, we have decided to exit this non-core market. The charge for our assets in Mexico relates to the decline of activity in the northern part of that country. The remaining charges relate to assets across our Drilling Products and Services, Onshore Completion and Workover Services and Production Services segments that are either obsolete or no longer used or useful in our businesses.

• We incurred a pre-tax charge of $23.6 million relating to an ongoing specialized platform decommissioning project in the Gulf of Mexico. The charge for the specialized platform decommissioning project is attributable to increases in the estimated total cost of that project. Our specialized wreck removal and platform decommissioning projects in the Gulf of Mexico are long term contracts that are accounted for using the percentage-of-completion method, which necessarily involve difficult estimates due to the nature and duration of these projects and contingencies unknown to us at the time we enter into the contract. We expect to complete this project by mid-2014. While we will retain the expertise to manage a large specialized platform decommissioning project, we will

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discontinue participating in the routine end of life decommissioning business and owning derrick barges. We have no other similar projects that are ongoing at this time. This will not, however, affect our Gulf of Mexico plug and abandonment business, which has been a core service since our founding.

• We incurred a pre-tax charge of $5.6 million primarily relating to cost saving initiatives in certain of our U.S. land market areas due to changed market conditions. These charges relate primarily to severance costs and lease costs for facilities where we no longer operate. As a result of these restructuring efforts, we expect to realize annualized savings of approximately $20 million to $30 million, beginning in the second quarter of 2014.

For further discussion about these pre-tax charges, see note 4 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Overview of our business segments

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 2013, approximately 34% of segment revenue was derived from U.S. land market areas (down from 44% in 2012), while approximately 38% of segment revenue was from the Gulf of Mexico market area (up from 31% in 2012) and approximately 28% of segment revenue was from international market areas (up from 25% in 2012). Premium drill pipe accounted for more than 40% of this segment’s revenue in 2013, while bottom hole assemblies and accommodations each accounted for more than 20% of this segment’s revenue in 2013.

The Onshore Completion 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. Virtually all of this segment’s revenue is derived in the U.S. land market areas by businesses acquired in the Complete acquisition in February 2012. 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 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 this segment’s revenue in 2013, while well service rigs and fluid management each account for more than 20% of this segment’s revenue in 2013.

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 2013, approximately 61% of segment revenue was derived from the U.S. land market area (down from 69% in 2012), while approximately 15% of segment revenue was from the Gulf of Mexico market area (up from 11% in 2012) and approximately 24% of this segment’s revenue was from international market areas (up from 20% in 2012). Coiled tubing is the largest service offering in this segment, accounting for more than 25% of segment revenue in 2013.

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 2013, revenue derived from the U.S. land market area was approximately 10% of

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segment revenue (essentially unchanged from 2012), while approximately 54% of segment revenue was from the Gulf of Mexico market area (up from 46% in 2012) and approximately 36% of segment revenue was from international market areas (down from 44% in 2012). 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. Well control and associated services represent the largest service offering in this segment, accounting for approximately 25% of this segment’s revenue in 2013.

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.

Historical market indicators are listed below:

	2013		% Change			2012		% Change			2011
Worldwide Rig Count (1)
U.S. (land and offshore)		1,761		-8	%		1,919		0	%		1,879
International (2)		1,296		5	%		1,234		6	%		1,167
Commodity Prices (average)
Crude Oil (West Texas Intermediate)	$	97.98		4	%	$	94.22		-1	%	$	95.47
Natural Gas (Henry Hub)	$	3.73		36	%	$	2.75		-33	%	$	4.09

⁽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.

The following table compares our revenues generated from major geographic regions for the years ended December 31, 2013 and 2012 (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
	2013		%			2012		%			Change
U.S. Land	$	2,847,427		62	%	$	3,043,599		67	%	$	(196,172	)
Gulf of Mexico		912,849		20	%		725,929		16	%		186,920
International		851,548		18	%		798,540		17	%		53,008
Total	$	4,611,824		100	%	$	4,568,068		100	%	$	43,756

In 2013, our U.S. land revenue decreased 6% to $2,847.4 million as a result of the decline in general market conditions in the U.S land market area, including competitive pressures and resulting lower pricing and utilization. Production Services segment revenue from the U.S. land market area declined by 15%, primarily as a result of the decline in market demand for coiled tubing, wireline, hydraulic workover and snubbing, and remedial pumping services. Drilling Products and Services segment’s revenue derived from the U.S. land market area decreased approximately 16% primarily due to decreased demand for premium drill pipe and accommodations. Onshore Completion and Workover Services Segment derives virtually all of its revenue from the U.S. land market area. This segment’s revenue was essentially unchanged from 2012. U.S. land market area

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revenue from our Subsea and Technical Solutions segment increased 9%, primarily as a result of increased demand for environmental services and sand control and stimulation services.

Our Gulf of Mexico revenue increased 26% to $912.9 million primarily as a result of a demand for our drilling products and services and completion tools in the deepwater. The Drilling Products and Services segment, which has significant deepwater Gulf of Mexico exposure, experienced a 30% increase in revenue in this market, with downhole drilling tools, such as bottom hole assemblies and premium drill pipe, experiencing the most growth. The Subsea and Technical Solutions segment revenue from the Gulf of Mexico increased 23%, and the Production Services segment revenue from the Gulf of Mexico grew 24% in 2013.

Our international revenue increased 7% to $851.5 million primarily as a result of acquisitions in Latin America and continued expansion of our drilling products and services. Production Services segment revenue from international market areas increased 15%, primarily due to our acquisitions of a wireline and well testing company and a cementing company in Latin America. The Drilling Products and Services segment experienced a 23% increase in revenue from international market areas due to increases in most of our product lines within the segment. These increases were partially offset by a 12% decrease in revenue from our Subsea and Technical Solutions segment from international market areas, primarily as a result of decreases in well control and subsea construction work.

Industry Outlook

Based on current expectations of activity indicators for oilfield services (commodity prices and drilling rig counts), we believe overall activity in U.S. land market areas will be flat or slightly higher in 2014 than in 2013 with rig count increases anticipated in basins more focused on drilling and producing oil than natural gas. In the Gulf of Mexico market area, year-over-year activity levels should increase, albeit at a slower pace of growth than 2013. Demand and activity levels in international market areas should grow at a slightly faster pace than 2013.

Due to overcapacity in several completion and production-related service lines in the U.S. land market, a flat-to-slightly higher market scenario would most likely result in moderate revenue growth with margins remaining relatively unchanged from 2013. As excess equipment is re-deployed, utilization should improve but not enough to drive price increases. In addition to overall changes in activity levels, revenue and margins are driven by the types of projects we perform, especially in completion-related applications such as horizontal fracturing and coiled tubing. In 2013, we had a favorable project mix in horizontal fracturing characterized by pumping high volumes of sand and fracturing a high number of stages. We do not anticipate that those volumes will repeat in 2014.

In addition, coiled tubing would most likely benefit more from an increase in natural gas drilling than oil as there are fewer substitutes for completing a natural gas well with coiled tubing due to the higher well pressures associated with dry gas wells. We believe the U.S. land market will continue to generate strong free cash flow as our growth capital expenditure requirements are minimal.

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 increase as the number of permits for deep water drilling increases. 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 in 2014 for products and services participating in these market areas will remain stable.

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Our outlook for our international market areas could yield favorable revenue growth in 2014 as we start new projects in Latin America and expand our product and service footprint to markets in Africa, the Middle East and Asia Pacific. Our 2013 revenue growth from international market areas fell short of expectations primarily due to changes in activity in Mexico. We do not anticipate significant improvements in demand from our services in Mexico during 2014.

Comparison of the Results of Operations for the Years Ended December 31, 2013 and 2012

For the year ended December 31, 2013, our revenue was $4,611.8 million and our net loss from continuing operations was $111.4 million, or $0.70 diluted loss per share from continuing operations. Included in the results for 2013 were pre-tax charges for $419.4 million related to the reduction in value of assets, $23.6 million related to an ongoing specialized platform decommissioning project and $5.6 million, primarily related to cost savings initiatives in certain of our U.S. land market areas. 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. Included in the results for 2012 were $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, 2013 and 2012 (in thousands). Cost of services excludes depreciation, depletion, amortization and accretion for each of our business segments.

	Revenue							Cost of Services
	2013		2012		Change			2013		%			2012		%			Change
Drilling Products and Services	$	838,514	$	775,066	$	63,448		$	276,131		33	%	$	255,853		33	%	$	20,278
Onshore Completion and Workover Services		1,596,704		1,593,977		2,727			1,083,494		68	%		1,039,732		65	%		43,762
Production Services		1,445,555		1,510,990		(65,435	)		1,011,933		70	%		929,552		62	%		82,381
Subsea and Technical Solutions		731,051		688,035		43,016			530,292		73	%		464,336		67	%		65,956
Total	$	4,611,824	$	4,568,068	$	43,756		$	2,901,850		63	%	$	2,689,473		59	%	$	212,377

The following discussion analyzes our results on a segment basis:

Drilling Products and Services Segment

Revenue for our Drilling Products and Services segment was $838.5 million for the year ended December 31, 2013, an approximate 8% increase from 2012. Cost of services remained at 33% of segment revenue in 2013. The increase in revenue for this segment is primarily related to rentals of bottom hole assemblies, drill pipe and specialty tubulars in the international and Gulf of Mexico market areas, which was offset by a decrease in rentals of accommodation modules and premium drill pipe in the U.S. land market area. Revenue from our Gulf of Mexico market increased approximately 30% for the year ended December 31, 2013 over the same period in 2012 due to increases in most of our product lines within this segment, particularly drill pipe. Revenue generated from our international market areas increased approximately 23% for the year ended December 31, 2013 over the same period in 2012. This increase was primarily related to increased rentals of bottom hole assemblies, drill pipe and specialty tubulars. Revenue derived from the U.S. land market area decreased approximately 16% for the year ended December 31, 2013 over the same period in 2012, primarily due to decreased demand for premium drill pipe and accommodation modules.

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Onshore Completion and Workover Services Segment

Revenue for our Onshore Completion and Workover Services segment was $1,596.7 million for the year ended December 31, 2013, a slight increase from 2012. Cost of services increased to 68% of segment revenue in 2013 from 65% in 2012. Virtually all of this segment’s revenue is derived in the U.S. land market areas by businesses acquired in the February 2012 acquisition of Complete. This segment’s results were negatively impacted during the year ended December 31, 2013 as a result of the decline in general market conditions in the U.S. land market area, including competitive pressures and resulting lower pricing and utilization.

Production Services Segment

Revenue for our Production Services segment was $1,445.6 million for the year ended December 31, 2013, an approximate 4% decline from 2012. Cost of services increased to 70% of segment revenue from 62% in 2012. Market demand for coiled tubing, wireline, hydraulic workover and snubbing, and remedial pumping services in the U.S. land market areas declined, which were the primary drivers of the decline in revenue and the increase in cost of services as a percentage of revenue. Revenue derived from the Gulf of Mexico market area increased 24% due to increases in demand for most of our product lines within this segment. Revenue from international market areas increased 15% primarily due to our acquisitions of a wireline company and a cementing company in Latin America. These increases more than offset the decline in coiled tubing services revenue in Mexico as work slowed down in the northern part of the country.

Subsea and Technical Solutions Segment

Revenue for our Subsea and Technical Solutions segment was $731.1 million for the year ended December 31, 2013, an approximate 6% increase from 2012. Cost of services increased to 73% of segment revenue in 2013 from 67% in 2012, primarily due to increases to the estimated total cost of an ongoing specialized platform decommissioning project in the Gulf of Mexico. Revenue in our Gulf of Mexico market area increased 23% primarily due to increases in well control work, sand control and stimulation services and other technical service projects. These increases were partially offset by decreases in oil and gas sales and plug and abandonment services. Revenue in our international market areas decreased 12% primarily as a result of a decrease in well control work. Revenue in our U.S. land market area increased 9% primarily as a result of increased demand for environmental services.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $625.9 million for the year ended December 31, 2013 from $509.3 million in 2012. Depreciation and amortization expense increased for our Drilling Products and Services segment by $18.6 million, or 12%, due to capital expenditures. Depreciation and amortization expense for our Onshore Completion and Workover Services segment increased by $43.7 million, or 25%, some of which was attributable to the fact that the product offerings comprising this segment were acquired in the February 2012 acquisition of Complete and the remainder is attributable to capital expenditures. Depreciation and amortization expense for our Production Services segment increased by $42.5 million, or 31%, partly because a portion of the product offerings comprising this segment were acquired in the Complete acquisition and the remainder is attributable to other acquisitions and capital expenditures. Depreciation, depletion, amortization and accretion expense for our Subsea and Technical Solutions segment increased by $11.8 million, or 23%, primarily due to capital expenditures.

General and Administrative Expenses

General and administrative expenses decreased to $633.9 million for the year ended December 31, 2013 from $662.8 million in 2012. General and administrative expenses declined year over year primarily due to nonrecurring acquisition-related expenses and other expenses incurred during 2012.

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Reduction in Value of Assets

During the year ended December 31, 2013, we recorded approximately $419.4 million of reduction in value of assets. The reduction in value of assets expense included $294.0 million related to long-lived assets and certain other assets in our Subsea and Technical Solutions, Onshore Completion and Workover Services and Production Services segments, $91.0 million related to the write-off of the goodwill balance for our Subsea and Technical Solutions segment, $20.1 million related to retirement and abandonment of long-lived assets in multiple operating segments and $14.3 million related to reduction in the value of assets related to Venezuela exit activities. See note 4 to our consolidated financial statements for further discussion of the reduction in value of assets.

Income Taxes

The increase in the effective tax rate during 2013 was primarily due to the asset value reductions recorded during the fourth quarter of 2013, which were attributable to foreign jurisdictions with low or zero statutory income tax rates. See note 11 to our consolidated financial statements.

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. 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 pre-tax loss on early extinguishment of debt in connection with the sale of our former Marine segment.

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

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.

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 were $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 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

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 by Complete prior to February 7, 2012 and operating results of other businesses acquired by us in 2011 and 2012. The pro forma results do not include any potential synergies, cost savings or other expected benefits of any 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

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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 modules and premium drill pipe in the U.S. land market area. Revenue from our Gulf of Mexico market increased approximately 61% for the year ended December 31, 2012 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 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

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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 continued 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 pre-tax loss on early extinguishment of debt in connection with the sale of our former Marine segment. In 2011, we recorded a pre-tax 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.

Liquidity and Capital Resources

In the year ended December 31, 2013, we generated net cash from operating activities of $892.8 million as compared to $1,035.0 million in 2012. 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 $196.0 million as of December 31, 2013 compared to $91.2 million as of December 31, 2012. As of December 31, 2013, approximately $86.5 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 taxes, less applicable foreign tax credits. Our current plans do not demonstrate a need to repatriate these balances to fund our U.S. operations. 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 approximately $609.0 million of cash on capital expenditures during the year ended December 31, 2013. Approximately $248.0 million was used to expand and maintain our Drilling Products and Services segment’s equipment inventory, and approximately $101.9 million, $122.9 million and $136.2 million was spent to expand and maintain the asset bases of our Onshore Completion and Workover Services, Production Services and Subsea and Technical Solutions segments, respectively.

We have a $1.0 billion bank credit facility which is comprised of a $600 million revolving portion and 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. As of December 31, 2013, we had $365 million outstanding under the term loan. As of December 31, 2013, we had no amounts outstanding under the revolving portion of our credit facility and approximately $46.8 million of letters of credit outstanding, which reduce our borrowing capacity under this portion of the credit facility. The average amount outstanding under the revolving portion of our credit facility during 2013 was approximately $113.9 million with a weighted average interest rate of 3.3% per annum. The maximum amount outstanding under the revolving portion of our credit facility during 2013 was $180.0 million,

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primarily related to the redemption of the remaining $150 million 6 7/8% senior notes in May 2013. As of February 17, 2014, we had no amounts outstanding under the revolving portion of our credit facility, and approximately $46.8 million of letters of credit outstanding. Any amounts outstanding on the bank revolving credit facility and the term loan are due on February 7, 2017. 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. As of December 31, 2013, we were in compliance with all such covenants.

We have 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 customary events of default and requires that we satisfy various covenants. As of December 31, 2013, we were in compliance with all such covenants.

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 customary events of default and requires that we satisfy various covenants. As of December 31, 2013, we were in compliance with all such covenants.

The following table summarizes our contractual cash obligations and commercial commitments as of December 31, 2013 (amounts in thousands). We do not have any other material obligations or commitments.

Contractual Obligations	< 1 Year		1 - 3 Years		3 - 5 Years		More Than 5 Years		Total
Long-term debt, including estimated interest payments	$	124,353	$	247,276	$	484,586	$	1,486,938	$	2,343,153
Capital lease obligations, including estimated interest payments		6,225		12,450		12,969		—		31,644
Decommissioning liabilities, undiscounted		28,138		3,517		1,226		184,677		217,558
Operating leases		72,255		88,242		45,764		26,046		232,307
Other long-term liabilities		—		46,749		29,417		104,089		180,255
Total	$	230,971	$	398,234	$	573,962	$	1,801,750	$	3,004,917

We currently believe that we will spend approximately $600 million to $650 million on capital expenditures, excluding acquisitions, during 2014. 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.

Subject to Board of Directors approval, we expect to pay quarterly dividends totaling approximately $50 million during 2014. We paid $12.7 million to stockholders on February 19, 2014. In addition, in October 2013, our Board of Directors authorized a $400 million share repurchase program of our common stock, which will expire on December 31, 2015. As of February 17, 2014, we repurchased 294,000 shares for $7.3 million and have $382.0 million available under the program for future share repurchases.

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.

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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 on Form 10-K, 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 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 generally 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.

During 2013, we recorded a reduction in value of long-lived assets of $221.2 million related to certain marine vessels and equipment included in the Subsea and Technical Solutions segment, $11.4 million related to equipment in our coiled tubing division included in the Production Services segment and $11.2 million related to mechanical drilling rigs included in the Onshore Completion and Workover Services segment. In addition, we recorded $18.3 million expense, primarily, related to reduction in carrying values of the intangible assets in the subsea construction division included in the Subsea and Technical Solutions segment.

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The reduction in value of assets in our Subsea and Technical Solutions segment was primarily driven by the decline in demand for services in our subsea construction and marine technical services businesses. During the fourth quarter of 2013, the demand for these services continued to decline and the forecast for these markets did not indicate a timely recovery sufficient to support the carrying values of these assets. The reduction in value of assets in our Onshore Completion and Workover Services segment related to the reduction in carrying values of our mechanical drilling rigs, primarily driven by the recent shift in customer demand away from mechanically powered rigs to electrically powered drilling rigs. The reduction in value of assets in our Production Services segment related to our coiled tubing business in Mexico and was primarily driven by the decrease in demand for our services during 2013 coupled with a decrease in our forecast for future activities in that region.

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 be 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.

We performed an annual test for goodwill impairment as of December 31, 2013, which indicated that the carrying value of the Subsea and Technical Solutions segment exceeded its fair value. As such, we performed 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 Subsea and Technical Solutions segment to all of the assets and liabilities other than goodwill and comparing it to the carrying amount of goodwill. We determined that the implied fair value of the goodwill for the Subsea and Technical Solutions segment was less than its carrying value and fully wrote-off the goodwill balance of $91.0 million, which is included in reduction in value of assets in the consolidated statement of operations. The reduction in value of goodwill in our Subsea and Technical Solutions segment was primarily driven by the decline in demand for services in our subsea construction and marine technical services divisions. During the fourth quarter of 2013, the demand for these services continued to decline and the forecast for these markets did not indicate a timely recovery sufficient to support the carrying values of the goodwill.

As of December 31, 2013, the fair values of the Drilling Products and Services and Production Services segments were substantially in excess of their carrying values. The fair value of the Onshore Completion and Workover Services segment exceeded its carrying value by approximately 6%. A significant amount of judgment was 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.

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

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

33

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

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

Discontinued Operations. We classify assets and liabilities of a disposal group as held for sale and discontinued operations when all 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 operations, we present discontinued operations, net of tax effect, as a separate caption below net income from continuing operations.

Off-Balance Sheet Arrangements

We have no off-balance sheet financing arrangements other than a guarantee on the performance of certain decommissioning liabilities, see note 13 to our consolidated financial statements. We do not have any other financing arrangements that are not required under generally accepted accounting principles to be reflected in our financial statements.

Hedging Activities

In July 2013, June 2013 and April 2012, we entered into interest rate swap agreements for notional amounts of $100 million each related to our 7 1/8% senior notes maturing in December 2021, 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 variable rates. The variable interest rates, which are adjusted every 90 days, are based on LIBOR plus a fixed margin and are scheduled to terminate on December 15, 2021.

Recently Adopted Accounting Pronouncements

See Part II, Item 8, “Financial Statements and Supplementary Data – Note 1 – Summary of Significant Accounting Policies – Recently Adopted 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 Rate Risk

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

34

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. We do not enter into forward foreign exchange contracts for trading purposes. As of December 31, 2013, we had no outstanding foreign currency forward contracts.

Interest Rate Risk

As of December 31, 2013, our debt (exclusive of discounts), was comprised of the following (in thousands):

	Fixed Rate Debt		Variable Rate Debt
Term loan due 2017	$	—	$	365,000
6 3/8 % Senior notes due 2019		500,000		—
7 1/8% Senior notes due 2021		500,000		300,000
Other		1,535		—
Total Debt	$	1,001,535	$	665,000

Based on the amount of this debt outstanding as of December 31, 2013, a 10% increase in the variable interest rate would increase our interest expense for the year ended December 31, 2013 by approximately $2.3 million, while a 10% decrease would decrease our interest expense by approximately $2.3 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, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2013. In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule II, 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, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2013, 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, 2013, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2014 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

KPMG LLP

New Orleans, Louisiana

February 27, 2014

36

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2013 and 2012

(in thousands, except share data)

	2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	196,047		$	91,199
Accounts receivable, net of allowance for doubtful accounts of $31,030 and $28,715 as of December 31, 2013 and 2012, respectively		937,195			1,027,218
Income taxes receivable		5,532			—
Deferred income taxes		8,785			34,120
Prepaid expenses		70,421			93,190
Inventory and other current assets		258,449			214,630
Total current assets		1,476,429			1,460,357
Property, plant and equipment, net of accumulated depreciation and depletion		3,002,194			3,255,220
Goodwill		2,458,109			2,532,065
Notes receivable		23,708			44,838
Intangible and other long-term assets, net of accumulated amortization		450,867			510,406
Total assets	$	7,411,307		$	7,802,886
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	216,029		$	252,363
Accrued expenses		376,049			346,490
Income taxes payable		—			153,212
Current maturities of long-term debt		20,000			20,000
Current portion of decommissioning liabilities		27,322			—
Total current liabilities		639,400			772,065
Deferred income taxes		736,080			745,144
Decommissioning liabilities		56,197			93,053
Long-term debt, net		1,646,535			1,814,500
Other long-term liabilities		201,651			147,045
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—158,976,784, Outstanding—159,158,022 as of December 31, 2013
Authorized—250,000,000, Issued—157,501,635, Outstanding—157,933,224 as of December 31, 2012		159			158
Additional paid in capital		2,873,579			2,850,855
Accumulated other comprehensive loss, net		(17,500	)		(19,317	)
Retained earnings		1,275,206			1,399,383
Total stockholders’ equity		4,131,444			4,231,079
Total liabilities and stockholders’ equity	$	7,411,307		$	7,802,886

See accompanying notes to consolidated financial statements.

37

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Operations

Years Ended December 31, 2013, 2012 and 2011

(in thousands, except per share data)

	2013			2012			2011
Revenues	$	4,611,824		$	4,568,068		$	1,964,332
Costs and expenses:
Cost of services (exclusive of items shown separately below)		2,901,850			2,689,473			1,046,409
Depreciation, depletion, amortization and accretion		625,928			509,281			244,915
General and administrative expenses		633,877			662,792			376,619
Reduction in value of assets		419,380			—			—
Income from operations		30,789			706,522			296,389
Other income (expense):
Interest expense		(106,954	)		(117,682	)		(72,994	)
Interest income		2,978			3,170			6,226
Other income		2,486			853			(822	)
Loss on early extinguishment of debt		(884	)		(2,294	)		—
Earnings (losses) from equity-method investments, net		—			(287	)		16,394
Gain on sale of equity-method investment		—			17,880			—
Income (loss) from continuing operations before income taxes		(71,585	)		608,162			245,193
Income taxes		39,833			225,020			85,804
Net income (loss) from continuing operations		(111,418	)		383,142			159,389
Loss from discontinued operations, net of income tax		—			(17,207	)		(16,835	)
Net income (loss)	$	(111,418	)	$	365,935		$	142,554
Earnings (loss) per share information:
Basic
Continuing operations	$	(0.70	)	$	2.57		$	2.00
Discontinued operations		—			(0.12	)		(0.21	)
Basic earnings (loss) per share	$	(0.70	)	$	2.45		$	1.79
Diluted
Continuing operations	$	(0.70	)	$	2.54		$	1.97
Discontinued operations		—			(0.12	)		(0.21	)
Diluted earnings (loss) per share	$	(0.70	)	$	2.42		$	1.76
Weighted average common shares used in computing earnings (loss) per share:
Basic		159,206			149,288			79,654
Incremental common shares from stock options		—			1,081			1,271
Incremental common shares from restricted stock units		—			737			170
Diluted		159,206			151,106			81,095

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income (Loss)

Years Ended December 31, 2013, 2012 and 2011

(in thousands)

	2013			2012			2011
Net income (loss)	$	(111,418	)	$	365,935		$	142,554
Unrealized net loss on investment securities, net of tax		(256	)		(897	)		—
Change in cumulative translation adjustment, net of tax		2,073			8,516			(1,236	)
Comprehensive income (loss)	$	(109,601	)	$	373,554		$	141,318

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, 2013, 2012 and 2011

(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, 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
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.

39

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Changes in Stockholders’ Equity

Years Ended December 31, 2013, 2012 and 2011

(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, 2012		—	$	—		157,501,635		$	158	$	2,850,855		$	(19,317	)	$	1,399,383		$	4,231,079
Net loss		—		—		—			—		—			—			(111,418	)		(111,418	)
Foreign currency translation adjustment		—		—		—			—		—			2,073			—			2,073
Unrealized net loss on investment securities		—		—		—			—		—			(256	)		—			(256	)
Grant of restricted stock units		—		—		—			—		1,026			—			—			1,026
Restricted stock grant and compensation expense, net of forfeitures		—		—		1,154,032			1		21,459			—			—			21,460
Vesting of restricted stock assumed with acquisition of Complete Production Services, Inc.		—		—		210,951			—		—			—			—			—
Exercise of stock options		—		—		470,712			—		6,263			—			—			6,263
Tax expense from exercise of stock options		—		—		—			—		(1,185	)		—			—			(1,185	)
Stock option compensation expense		—		—		—			—		3,586			—			—			3,586
Shares issued under Employee Stock
Purchase Plan		—		—		185,407			—		5,013			—			—			5,013
Cash dividends ($0.08 per share)		—		—		—			—		—			—			(12,759	)		(12,759	)
Shares repurchased and retired		—		—		(426,883	)		—		(10,627	)		—			—			(10,627	)
Shares withheld and retired		—		—		(119,070	)		—		(2,811	)		—			—			(2,811	)
Balances, December 31, 2013		—	$	—		158,976,784		$	159	$	2,873,579		$	(17,500	)	$	1,275,206		$	4,131,444

See accompanying notes to consolidated financial statements.

40

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

Years Ended December 31, 2013, 2012 and 2011

(in thousands)

	2013			2012			2011
Cash flows from operating activities:
Net income (loss)	$	(111,418	)	$	365,935		$	142,554
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		625,928			510,526			257,313
Loss on early extinguishment of debt		884			3,460			—
Deferred income taxes		14,435			11,218			48,073
Excess tax benefit from stock-based compensation		(689	)		(1,555	)		(9,004	)
Gain on sale of equity method investment		—			(17,880	)		—
Reduction in value of assets		419,380			—			46,096
Stock based and performance share unit compensation expense		35,832			36,570			14,032
Retirement and deferred compensation plan expense		294			1,607			1,990
(Earnings) losses from equity-method investments, net of cash received		—			3,360			(13,152	)
Amortization of debt acquisition costs and note discount		8,919			9,856			25,178
(Gain) loss on sale of businesses		—			6,649			(8,558	)
Other reconciling items, net		(2,045	)		1,205			(6,426	)
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable		85,423			(42,946	)		(86,814	)
Inventory and other current assets		(70,995	)		62,720			2,182
Accounts payable		(32,304	)		(30,977	)		40,289
Accrued expenses		25,154			(26,107	)		24,961
Decommissioning liabilities		(87	)		(4,660	)		(504	)
Income taxes		(162,148	)		152,093			(1,378	)
Other, net		56,245			(6,031	)		15,972
Net cash provided by operating activities		892,808			1,035,043			492,804
Cash flows from investing activities:
Payments for capital expenditures		(608,960	)		(1,141,922	)		(484,648	)
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		(23,797	)		(1,091,161	)		(1,748	)
Cash proceeds from sale of businesses		—			183,094			22,349
Cash proceeds from sale of equity method investment		—			34,087			—
Cash proceeds from insurance recovery		22,650			—			—
Purchase of short-term investments		—			—			(223,491	)
Proceeds from sale of short-term investments		—			—			223,630
Other		4,539			31,630			(721	)
Net cash used in investing activities		(605,568	)		(1,157,118	)		(1,249,909	)
Cash flows from financing activities:
Proceeds from revolving line of credit		581,771			696,439			324,913
Payments on revolving line of credit		(581,771	)		(771,439	)		(424,913	)
Proceeds from issuance of long-term debt		1,535			400,000			1,300,000
Principal payments on long-term debt		(170,000	)		(177,546	)		(400,810	)
Payment of debt acquisition costs		—			(25,274	)		(24,428	)
Proceeds from exercise of stock options		6,264			14,777			10,263
Excess tax benefit from stock-based compensation		689			1,555			9,004
Proceeds from issuance of stock through employee benefit plans		4,123			2,855			2,206
Purchase and retirement of common stock		(10,627	)		—			—
Other		(13,187	)		(10,383	)		(9,662	)
Net cash provided by (used in) financing activities		(181,203	)		130,984			786,573
Effect of exchange rate changes on cash		(1,189	)		2,016			79
Net increase in cash and cash equivalents		104,848			10,925			29,547
Cash and cash equivalents at beginning of period		91,199			80,274			50,727
Cash and cash equivalents at end of period	$	196,047		$	91,199		$	80,274

See accompanying notes to consolidated financial statements.

41

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Years Ended December 31, 2013, 2012 and 2011

(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 2013 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 February 2012 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 life cycle. 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 2013 and 2012, EOG Resources, Inc. accounted for approximately 10% and 13%, respectively, of total revenue, primarily within the Onshore Completion and Workover segment. There were no customers that exceeded 10% of total revenues in 2011.

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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 for which reduction in value is recorded during the period and 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.

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Capitalized Interest

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 $8.7 million, $12.4 million and $7.1 million of interest expense in the years ended December 31, 2013, 2012 and 2011, respectively, for various capital projects.

Reduction in Value of Long-Lived Assets

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. See note 4 for a discussion of reduction in values of long-lived assets recorded during 2013.

Goodwill

During 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.

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The following table summarizes the activity for the Company’s goodwill for the years ended December 31, 2013 and 2012 (amounts in thousands):

	Drilling Products and Services			Subsea and Well Enhancement			Onshore Completion Services		Production Services		Subsea and Technical Solutions			Total
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
Acquisition activities		—			—			1,500		15,099		—			16,599
Disposition activities		(756	)		—			—		—		—			(756	)
Reduction in value of assets		—			—			—		—		(91,016	)		(91,016	)
Foreign currency translation adjustment		681			—			—		536		—			1,217
Balance, December 31, 2013	$	144,872		$	—		$	1,419,550	$	893,687	$	—		$	2,458,109

Goodwill is tested for impairment annually as of December 31 or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. In order to estimate the fair value of the reporting units (which is consistent with the reported business segments), the Company used a weighting of the discounted cash flow method and the public company guideline method of determining fair value of each reporting unit. The Company weighted the discounted cash flow method 80% and the public company guideline method 20% due to differences between the Company’s reporting units and the peer companies’ size, profitability and diversity of operations. In order to validate the reasonableness of the estimated fair values obtained for the reporting units, a reconciliation of fair value to market capitalization was performed for each unit on a standalone basis. A control premium, derived from market transaction data, was used in this reconciliation to ensure that fair values were reasonably stated in conjunction with the Company’s capitalization. These fair value estimates were then compared to the carrying value of the reporting units. See note 4 for a discussion of reduction in value of goodwill recorded during 2013. As of December 31, 2013, the Company’s accumulated reduction in value of goodwill was $91.0 million.

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 its ownership of 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 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

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removal. During the fourth quarter of 2013, the Company revised its timing estimate for the Bullwinkle platform removal, resulting in a reduction of the present value of the notes receivable. The Company recorded interest income related to notes receivable of $2.6 million, $2.8 million and $4.5 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Intangible and Other Long-Term Assets

Intangible and other long-term assets consist of the following as of December 31, 2013 and 2012 (amounts in thousands):

	December 31, 2013							December 31, 2012
	Gross Amount		Accumulated Amortization			Net Balance		Gross Amount		Accumulated Amortization			Net Balance
Customer relationships	$	335,590	$	(44,117	)	$	291,473	$	348,160	$	(25,357	)	$	322,803
Tradenames		45,025		(9,175	)		35,850		53,063		(7,017	)		46,046
Non-compete agreements		4,256		(2,163	)		2,093		2,938		(1,062	)		1,876
Debt issuance costs		63,829		(28,250	)		35,579		63,829		(18,948	)		44,881
Deferred compensation plan assets		13,731		—			13,731		11,343		—			11,343
Escrowed cash		58,406		—			58,406		58,305		—			58,305
Long-term assets held as major replacement spares		1,000		—			1,000		7,241		—			7,241
Other		13,597		(862	)		12,735		18,675		(764	)		17,911
Total	$	535,434	$	(84,567	)	$	450,867	$	563,554	$	(53,148	)	$	510,406

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, 11 years, and 3 years, respectively. Amortization expense (exclusive of debt issuance costs) was approximately $27.6 million, $24.0 million and $3.4 million for the years ended December 31, 2013, 2012 and 2011, respectively. During 2013, the Company recorded approximately $18.3 million of expense related primarily to reduction in carrying values of the customer relationships and tradenames in the subsea construction division in the Subsea and Technical Solutions segment (see note 4). Estimated annual amortization of intangible assets (exclusive of debt acquisition costs) will be approximately $26.3 million for 2014, $25.5 million for 2015, $24.5 million for 2016, $23.8 million for 2017 and 2018, excluding the effects of any acquisitions or dispositions subsequent to December 31, 2013.

Debt issuance costs are amortized 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 operations.

In accordance with the asset purchase agreement between Wild Well and the seller 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 a $50.0 million into an escrow account. Included in intangible and other long-term assets, net is escrowed cash related to the Bullwinkle platform of $50.4 million and $50.3 million as of December 31, 2013 and 2012, respectively.

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.

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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. As a result of continuing development activities, the Company revised its estimates during the fourth quarter of 2013 relating to the timing of decommissioning work on its Bullwinkle assets, including a 10 year postponement of the platform decommissioning to an estimated date of 2038. This change in estimate resulted in a reduction in the present value of decommissioning liabilities.

In connection with the February 2012 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, 2013 and 2012 (in thousands):

	Years Ended December 31,
	2013			2012
Decommissioning liabilities, December 31, 2012 and 2011, respectively	$	93,053		$	123,176
Liabilities acquired and incurred		445			4,620
Liabilities settled		(87	)		(4,660	)
Accretion		5,320			4,670
Revision in estimated liabilities		(15,212	)		(34,753	)
Total decommissioning liabilities, December 31, 2013 and 2012 , respectively	$	83,519		$	93,053
Less: current portion of decommissioning liabilities as of December 31, 2013 and 2012, respectively		27,322			—
Long-term decommissioning liabilities, December 31, 2013 and 2012, respectively	$	56,197		$	93,053

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 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.

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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 shares of common stock 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 shares of common stock 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 February 2012 acquisition of Complete.

For the year ended December 31, 2013, the Company incurred a loss from continuing operations; therefore, the impact of any incremental shares would be anti-dilutive. Stock options for approximately 2,100,000 shares and 540,000 shares of the Company’s common stock were excluded in the computation of diluted earnings per share for the years ended December 31, 2012 and 2011, respectively, as the effect would have been anti-dilutive.

Cash Dividends

In December 2013, the Company’s Board of Directors had approved initiating a quarterly dividend program and declared an initial quarterly dividend of $0.08 per share on its outstanding common stock. The initial dividend was paid on February 19, 2014 to all shareholders of record as of January 30, 2014. The dividend payable of $12.8 million is included in accrued expenses in the consolidated balance sheet as of December 31, 2013.

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 operations, losses from discontinued operations are presented, net of tax effect, as a separate caption below net income (loss) from continuing operations.

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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 $1,789.0 million and $1,960.0 million as of December 31, 2013 and 2012, respectively, and was categorized as Level 1 in the fair value hierarchy. 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 operations in the period in which the currency exchange rates change. For the years ended December 31, 2013, 2012 and 2011, the Company recorded approximately ($9.4) million, ($2.7) million and $1.4 million of foreign currency gains (losses), respectively.

Stock-Based Compensation

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

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Derivative Instruments and Hedging Activities

The Company recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. Interest rate swap agreements that are effective at hedging the fair value of fixed-rate debt agreements are designated and accounted for as fair value hedges. The Company also assesses, both at inception of the hedging relationship and on an ongoing basis, whether the derivatives used in hedging relationships are highly effective in offsetting changes in fair value.

In an attempt to achieve a more balanced debt portfolio, the Company 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 60% and 74% of its long-term debt as of December 31, 2013 and 2012, respectively. The Company had notional amounts of $300 million and $100 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, 2013 and 2012, respectively.

Equity–Method Investments

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

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 Adopted Accounting Pronouncements

In February 2013, the Financial Accounting Standards Board issued an update to existing guidance on the presentation of comprehensive income. This update requires companies to report the effect of significant reclassifications out of accumulated other comprehensive income (AOCI) by component. For significant items reclassified out of AOCI to net income in their entirety during the reporting period, companies must report the effect on the line items in the statement where net income is presented. For significant items not reclassified to net income in their entirety during the period, companies must provide cross-references in the notes to other disclosures that already provide information about those amounts. The Company adopted this update effective January 1, 2013, and it did not have an impact on its consolidated financial statements.

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.

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(2) Supplemental Cash Flow Information

The following table includes the Company’s supplemental cash flow information for the years ended December 31, 2013, 2012 and 2011 (amounts in thousands):

	2013			2012			2011
Cash paid for interest, net of amounts capitalized	$	97,129		$	109,112		$	39,539
Cash paid for income taxes, net of refunds	$	164,158		$	42,261		$	22,320
Details of business acquisitions:
Fair value of assets	$	34,964		$	4,364,872		$	8,650
Fair value of liabilities		(10,942	)		(695,243	)		(6,902	)
Common stock issued		—			(2,361,466	)		—
Cash paid		24,022			1,308,163			1,748
Less cash acquired		(225	)		(217,002	)		—
Net cash paid for acquisitions	$	23,797		$	1,091,161		$	1,748
Details of proceeds from sale of businesses:
Book value of assets	$	—		$	198,369		$	13,791
Book value of liabilities		—			(8,626	)		—
Gain on sale of business		—			(6,649	)		8,558
Proceeds from sale of businesses	$	—		$	183,094		$	22,349
Capital expenditures included in accounts payable, accrued expenses and other long term liabilities	$	70,463		$	61,035		$	23,053
Additional consideration payable on acquisitions	$	136		$	9,890		$	—
Non-cash financing activity:
Dividends declared	$	12,759		$	—		$	—

(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.

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 of its common stock 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). 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. 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 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.

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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

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.

Other Acquisitions

In March 2013, the Company acquired 100% of the equity interest in a company that provides cementing services to oil and gas companies in Colombia. This acquisition provides the Company with a platform for continued expansion in the South American market area. The Company paid approximately $20.4 million at closing and repaid $3.0 million of the acquired company’s debt. The Company will pay an additional $3.6 million over the next two years, subject to the settlement of certain liabilities. Goodwill of approximately $15.1 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 assigned to the Production Services segment.

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. The Company paid approximately $37.6 million in cash related to this acquisition, including approximately $6.5 million of contingent consideration which was paid during 2013 based upon achievement of certain performance metrics. 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. The goodwill has been allocated to the Onshore Completion and Workover Services, the Production Services, and the Subsea and Technical Solutions 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 operations for the year ended December 31, 2012, and the revenue and earnings of the

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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 operations 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 by 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 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

As of December 31, 2013 and 2012, the Company’s maximum additional consideration payable as a result of prior acquisitions was approximately $0.1 million and $10.0 million, respectively. These liabilities are included in accrued expenses in the consolidated balance sheet. 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) Reduction in Value of Assets

During the year ended December 31, 2013, the Company recorded $419.4 million in expense related to reduction in value of assets. The components of reduction in value of assets are as follows (in thousands):

	2013
Reduction in value of long-lived assets and related other assets	$	293,986
Reduction in value of goodwill		91,016
Retirements of long-lived assets		20,054
Reduction in value of assets related to Venezuela exit activities		14,324
Total reduction in value of assets	$	419,380

Reduction in Value of Long-Lived Assets

2013

During the fourth quarter of 2013, the Company recorded $294.0 million in expense in connection with reduction in value of its long-lived assets and related other assets. The reduction in value of assets expense was comprised

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of $221.2 million related to certain marine vessels and equipment and related write-off of other assets of $31.9 million included in the Subsea and Technical Solutions segment, $11.4 million related to equipment in the coiled tubing division within the Production Services segment and $11.2 million related to mechanical drilling rigs included in the Onshore Completion and Workover Services segment. In addition, the Company recorded an $18.3 million expense primarily related to reduction in carrying values of the intangible assets in the subsea construction division included in the Subsea and Technical Solutions segment.

The reduction in value of assets in our Subsea and Technical Solutions segment was primarily driven by the decline in demand for services in our subsea construction and marine technical services businesses. During the fourth quarter of 2013, the demand for these services continued to decline and the forecast for these markets did not indicate a timely recovery sufficient to support the carrying values of these assets. The reduction in value of assets in our Onshore Completion and Workover Services segment related to the reduction in carrying values of our mechanical drilling rigs, primarily driven by the recent shift in customer demand away from mechanically powered rigs to electrically powered drilling rigs. The reduction in value of assets in our Production Services segment related to our coiled tubing business in Mexico and was primarily driven by the decrease in demand for our services during 2013 coupled with a decrease in our forecast for future activities in that region.

2011

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 operations. On March 30, 2012, the Company sold the 18 liftboats and related assets that had comprised its Marine segment.

Reduction in Value of Goodwill

2013

The Company performed its annual test for goodwill impairment as of December 31, 2013, which indicated that the carrying value of the Subsea and Technical Solutions segment exceeded its fair value, indicating that goodwill was potentially impaired. As such, the Company performed 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 Subsea and Technical Solutions 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 Subsea and Technical Solutions segment was less than its carrying value and fully wrote-off the goodwill balance of $91.0 million, which is included in the reduction in value of assets in the consolidated statement of operations. The reduction in value of goodwill in our Subsea and Technical Solutions segment was primarily driven by the decline in demand for services in our subsea construction and marine technical services divisions. During the fourth quarter of 2013, the demand for these services continued to decline and the forecast for these markets did not indicate a timely recovery sufficient to support the carrying values of the goodwill.

As of December 31, 2013, the fair values of the Drilling Products and Services and Production Services segments were substantially in excess of their carrying values. The fair value of the Onshore Completion and Workover Services segment exceeded its carrying value by approximately 6%. A significant amount of judgment was involved in performing these evaluations since the results are based on estimated future events.

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2012

No impairment loss was recognized during the year ended December 31, 2012, 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 Products and 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.

2011

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 operations.

Retirements of Long-Lived Assets

During 2013, the Company recorded $20.1 million for retirement and abandonment of inoperable and/or functionally obsolete long-lived assets. The total amount recorded includes $12.1 million for Subsea and Technical Solutions segment, $5.8 million for Onshore Completion and Workover Services segment and $2.2 million for Production Services segment.

Reduction in Value of Assets Related to Venezuela Exit Activities

In November 2013, the government of Venezuela seized two of the Company’s hydraulic snubbing units from its facility in Anaco, Venezuela. The Company attempted to reach an agreement with its customer, Petroleos de Venezuela, S.A., for the payments owed to the Company and for the return of its equipment, but was unsuccessful. As a result, the Company recorded a $14.3 million reduction in value of net assets, primarily related to accounts receivable, prepaid expenses and property, plant and equipment. During the years ended December 31, 2013, 2012 and 2011, the Company generated $9.5 million, $20.5 million and $13.1 million, respectively in revenue from its operations in Venezuela.

(5) 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. The operations and loss on the sale of this disposal group have been reported within loss from discontinued operations in the consolidated statements of operations 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

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long-term financing (see note 9). 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 operations for all periods presented.

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

	2012			2011
Revenues	$	16,231		$	105,834
Loss from discontinued operations, net of tax benefit of $1,771 and $9,083 for the years ended December 31, 2012 and 2011, respectively		(6,478	)		(22,968	)
Loss (gain) on disposition, net of tax (benefit) expense of ($2,391) and $2,425 for the years ended December 31, 2012 and 2011, respectively		(10,729	)		6,133
Loss from discontinued operations, net of tax	$	(17,207	)	$	(16,835	)

(6) Property, Plant and Equipment

A summary of property, plant and equipment as of December 31, 2013 and 2012 (in thousands) is as follows:

	2013			2012
Buildings, improvements and leasehold improvements	$	284,273		$	230,457
Marine vessels and equipment		137,955			199,819
Machinery and equipment		3,864,599			3,500,112
Automobiles, trucks, tractors and trailers		64,102			60,805
Furniture and fixtures		72,563			59,124
Construction-in-progress		211,017			410,425
Land		56,786			59,824
Oil and gas producing assets		137,910			77,285
Total		4,829,205			4,597,851
Accumulated depreciation and depletion		(1,827,011	)		(1,342,631	)
Property, plant and equipment, net	$	3,002,194		$	3,255,220

In connection with the review for impairment of long-lived assets, during the year ended December 31, 2013, the Company recorded approximately $221.2 million related to reduction in carrying values of certain of the marine vessels and equipment included in the Subsea and Technical Solutions segment, $11.4 million related to equipment in our coiled tubing division included in the Production Services segment and $11.2 million related to reduction in carrying values of mechanical drilling rigs included in the Onshore Completion and Workover Services segment (see note 4).

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The Company had approximately $75.0 million and $63.5 million of leasehold improvements as of December 31, 2013 and 2012, 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 $593.0 million, $480.0 million, and $224.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, which includes amounts recorded within loss from discontinued operations on the consolidated statements of operations.

(7) Inventory and Other Current Assets

Inventory and other current assets includes approximately $162.9 million and $136.5 million of inventory as of December 31, 2013 and 2012, respectively. The Company’s inventory balance as of December 31, 2013 consisted of approximately $65.6 million of finished goods, $20.1 million of work-in-process, $20.8 million of raw materials and $56.4 million of supplies and consumables. 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.

Inventory and other current assets also includes approximately $63.2 million and $18.5 million of costs incurred and estimated earnings in excess of billings on uncompleted contracts as of December 31, 2013 and 2012, respectively. The Company follows the percentage-of-completion method of accounting for applicable contracts.

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 8). The Company is accounting for the shares of SandRidge stock 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 stockholders’ 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 1.4 million shares as of December 31, 2013 and 2012 was approximately $8.8 million and $9.2 million, respectively. During the year ended December 31, 2013, the Company recorded an unrealized loss on these securities of approximately $0.4 million, of which approximately $0.3 million was reported within accumulated other comprehensive loss, net of tax benefit of approximately $0.1 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 years ended December 31, 2013 or 2012.

(8) Equity-Method Investments

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 7). The Company recorded a gain in the second quarter of 2012 of approximately $17.9 million as a result of this transaction.

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(9) Debt

The Company’s long-term debt as of December 31, 2013 and 2012 consisted of the following (in thousands):

	2013		2012
Term loan – interest payable monthly at floating rate and principal payable quarterly, due December 2017	$	365,000	$	385,000
Senior Notes – interest payable semiannually at 6 7/8%, due June 2014		—		150,000
Discount on 6 7/8% Senior Notes		—		(500	)
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
Other		1,535		—
		1,666,535		1,834,500
Less current portion		20,000		20,000
Long-term debt	$	1,646,535	$	1,814,500

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. In May 2013, the Company redeemed the remaining $150 million aggregate principal amount of its 6 7/8% unsecured senior notes due 2014 at 100% of face value using proceeds from the revolving portion of its credit facility. The redemption resulted in a loss on early extinguishment of debt of approximately $0.9 million related to the writeoff of unamortized debt acquisition costs and note discount.

Credit Facility

The Company has a $1.0 billion bank credit facility, comprised of a $600 million revolving credit facility and a $400 million term loan. As of December 31, 2013, $365 million was outstanding under the 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. As of December 31, 2013, the Company had no amounts outstanding under the revolving portion of its credit facility. The Company had approximately $46.8 million of letters of credit outstanding, which reduce the Company’s borrowing availability under this portion of the credit facility.

Any amounts outstanding on the revolving portion of the credit facility and the term loan are due on February 7, 2017. 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.

Senior Unsecured Notes

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 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.

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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 operations.

Annual maturities of long-term debt for each of the five fiscal years following December 31, 2013 and thereafter are as follows (in thousands):

2014	$	20,000
2015		20,602
2016		20,637
2017		305,296
2018		—
Thereafter		1,300,000
Total	$	1,666,535

(10) 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 stock 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. Under the terms of the 2013 Stock Incentive Plan, approximately 8.0 million shares of the Company’s common stock have been reserved for issuance to employees and non-employee directors. As of December 31, 2013, approximately 7.9 million shares of the Company’s common stock were available for future grants under the plan.

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 2013, the Company granted 406,185 non-qualified stock options under these same terms.

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.

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The following table presents the fair value of stock option grants made during the years ended December 31, 2013, 2012 and 2011, 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,
	2013 Actual			2012 Actual			2011 Actual
Weighted average fair value of grants	$	8.98		$	21.76		$	13.54
Black-Scholes-Merton Assumptions:
Risk free interest rate		0.63	%		0.41	%		0.85	%
Expected life (years)		4			2			5
Volatility		48.41	%		55.27	%		56.31	%
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.

The Company’s compensation expense related to stock options for the years ended December 31, 2013, 2012 and 2011 was approximately $3.6 million, $4.8 million and $3.3 million, respectively, which is reflected in general and administrative expenses in the consolidated statements of operations. The Company has reported tax benefits of approximately $0.7 million, $0.6 million, $7.4 million from the exercise of stock options for the years ended December 31, 2013, 2012 and 2011, respectively, as financing cash flows in the consolidated statement of cash flows.

The following table summarizes stock option activity for the year ended December 31, 2013:

	Number of Options			Weighted Average Option Price		Weighted Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (in thousands)
Outstanding as of December 31, 2012		4,923,102		$	20.52		5.3	$	16,334
Granted		406,185		$	23.03
Exercised		(470,712	)	$	13.31
Forfeited		(1,199	)	$	20.01
Outstanding as of December 31, 2013		4,857,376		$	21.43		4.8	$	29,990
Exercisable as of December 31, 2013		4,320,878		$	21.06		4.3	$	28,536
Options expected to vest as of December 31, 2013		536,498		$	24.33		8.8	$	1,454

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, 2013 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, 2013. 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 (the difference between the stock price upon exercise and the stock option price) during the years ended December 31, 2013, 2012 and 2011 was approximately $5.1 million, $40.4 million and $23.4 million, respectively. The Company received approximately $6.3 million, $14.8 million and $10.3 million during the years ended December 31, 2013, 2012 and 2011, respectively, from employee stock option exercises.

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The following table summarizes non-vested stock option activity for the year ended December 31, 2013:

	Number of Options			Weighted Average Grant Date Fair Value
Non-vested as of December 31, 2012		409,189		$	12.71
Granted		406,185		$	8.98
Vested		(278,876	)	$	12.13
Forfeited		—			—
Non-vested as of December 31, 2013		536,498		$	10.19

As of December 31, 2013, there was approximately $4.1 million of unrecognized compensation expense related to non-vested stock options outstanding. The Company expects to recognize approximately $2.8 million, $1.2 million and $0.1 million of compensation expense during the years 2014, 2015 and 2016, respectively, for these outstanding non-vested stock options.

Restricted Stock

During the year ended December 31, 2013, the Company granted 1,388,835 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, 2013, 2012 and 2011. The Company’s compensation expense related to restricted stock for years ended December 31, 2013, 2012 and 2011 was approximately $21.5 million, $17.0 million and $6.0 million, respectively, which is reflected in general and administrative expenses in the consolidated statements of operations.

A summary of the status of restricted stock for the year ended December 31, 2013 is presented in the table below:

	Number of Shares			Weighted Average Grant Date Fair Value
Non-vested as of December 31, 2012		1,296,893		$	27.89
Granted		1,388,835		$	23.14
Vested		(405,109	)	$	23.80
Forfeited		(260,643	)	$	25.23
Non-vested as of December 31, 2013		2,019,976		$	24.71

The weighted average grant-date fair value per share of restricted stock granted during the years ended December 31, 2013, 2012 and 2011 was $23.14, $22.87 and $28.84, respectively. The total fair value of restricted stock vested during the years ended December 31, 2013, 2012 and 2011 was $9.6 million, $13.0 million and $10.3 million, respectively. As of December 31, 2013, there was approximately $29.9 million of unrecognized compensation expense related to non-vested restricted stock. The Company expects to recognize approximately $18.4 million, $11.1 million, $0.4 million during the years 2014, 2015 and 2016, respectively, for non-vested restricted stock. There was no tax benefit to the Company from the vesting of restricted stock for the year ended December 31, 2013.

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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. Each RSU granted prior to 2013 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. Beginning with the June 7, 2013 RSU grant of 67,266 units, the RSUs will vest and pay out in shares of the Company’s common stock in the year following the grant date on the date of the Company’s annual meeting. As of December 31, 2013, there were 324,481 RSUs outstanding. The Company’s expense related to RSUs for the years ended December 31, 2013, 2012 and 2011 was approximately $1.0 million, $2.4 million and $1.2 million, respectively, which is reflected in general and administrative expenses in the consolidated statements of operations.

A summary of the activity of restricted stock units for the year ended December 31, 2013 is presented in the table below:

	Number of Restricted Stock Units		Weighted Average Grant Date Fair Value
Outstanding as of December 31, 2012		257,215	$	26.23
Granted		67,266	$	26.76
Outstanding as of December 31, 2013		324,481	$	26.34

The weighted average grant-date fair value per share of restricted stock units granted during the years ended December 31, 2012 and 2011 was $21.48 and $35.10, respectively. Effective in 2014, grants to employees will be in restricted stock units instead of restricted stock as in prior years.

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 of the Board of Directors. As of December 31, 2013, there were 308,467 PSUs outstanding (70,752, 119,010 and 118,705 related to performance 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, 2013, 2012 and 2011 was approximately $10.0 million, $11.9 million and $3.2 million, respectively, which is reflected in general and administrative expenses in the consolidated statements of operations. The Company has recorded both current and long-term liabilities for this liability-based compensation award. During the year ended December 31, 2013, the Company paid approximately $9.7 million in cash to its employees to settle PSUs for the three year performance period ended December 31, 2012. 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.

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Employee Stock Purchase Plan

The Company had 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 could purchase shares of the Company’s common stock at a discount. Shares were purchased under this plan through June 30, 2013. The Company received approximately $1.9 million, $2.9 million and $2.2 million related to shares issued under this plan for years ended December 31, 2013, 2012 and 2011, respectively. For the years ended December 31, 2013, 2012 and 2011, the Company recorded compensation expense of approximately $0.3 million, $0.5 million and $0.4 million, respectively, which is reflected in general and administrative expenses in the consolidated statements of operations. Additionally, the Company issued approximately 87,000 shares, 147,000 shares and 75,700 shares in the years ended December 31, 2013, 2012 and 2011, respectively, related to this stock purchase plan.

On June 6, 2013, the stockholders of the Company approved the 2013 Employee Stock Purchase Plan. This plan went into effect on July 1, 2013 and replaced the prior plan. Under this plan 3,000,000 shares of the Company’s common stock are reserved for issuance. Eligible employees are allowed to purchase shares of the Company’s common stock at a discount during six-month offering periods beginning on January 1 and July 1 of each year and ending on June 30 and December 31 of each year, respectively. Shares were purchased under this plan for the time period ending December 31, 2013. The Company received approximately $2.2 million in connection with the issuance of its shares of common stock issued pursuant to this plan for the year ended December 31, 2013. For the year ended December 31, 2013, the Company recorded compensation expense of approximately $0.6 million and issued approximately 98,000 shares of its common stock related to this 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, the Company provided a discretionary match, not to exceed 5% of an employee’s salary. The Company made contributions of approximately $16.0 million, $8.4 million and $7.4 million in the years ended December 31, 2013, 2012 and 2011, 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 15). As of December 31, 2013 and 2012, the liability of the Company to the participants was approximately $15.0 million and $13.5 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, 2013 and 2012, the Company had approximately $1.9 million and $0.1 million in accounts payable in anticipation of pending payments. For the years ended December 31, 2013, 2012 and 2011, the Company recorded compensation income (expense) of approximately ($2.5) million, ($1.6) million and $0.1 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,

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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, 2013 and 2012, the deferred compensation plan asset was approximately $13.7 million and $11.3 million, respectively, and is recorded in intangible and other long-term assets, net. For the years ended December 31, 2013, 2012 and 2011, the Company recorded other income (expense) of $2.4 million, $0.7 million and ($0.2) million, respectively, related to the net 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 2013, 2012 and 2011, the participants in the plan received contributions ranging from 5% to 35% of salary and annual cash bonus, which totaled approximately $1.2 million, $1.8 million and $1.0 million, respectively. The Company may also make discretionary contributions to a participant’s account. The Company recorded compensation expense of approximately $1.2 million, $2.4 million and $1.8 million in general and administrative expenses for the years ended December 31, 2013, 2012 and 2011, respectively, inclusive of discretionary contributions. During the years ended December 31, 2013, 2012 and 2011, the Company paid approximately $3.0 million, $6.7 million and $5.5 million, respectively, to select participants in the SERP.

(11) Income Taxes

The components of income (loss) from continuing operations before income taxes for the years ended December 31, 2013, 2012 and 2011 are as follows (in thousands):

	2013			2012		2011
Domestic	$	116,966		$	559,536	$	244,401
Foreign		(188,551	)		48,626		792
	$	(71,585	)	$	608,162	$	245,193

The components of income tax expense (benefit) for the years ended December 31, 2013, 2012 and 2011 are as follows (in thousands):

	2013			2012		2011
Current:
Federal	$	(11,269	)	$	116,774	$	14,227
State		9,480			14,025		785
Foreign		27,877			33,280		19,716
		26,088			164,079		34,728
Deferred:
Federal		7,851			59,442		51,828
State		993			1,117		1,121
Foreign		4,901			382		(1,873	)
		13,745			60,941		51,076
	$	39,833		$	225,020	$	85,804

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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, 2013, 2012 and 2011 as follows (in thousands):

	2013			2012			2011
Computed expected tax expense	$	(25,055	)	$	212,857		$	85,818
Increase (decrease) resulting from
State and foreign income taxes		6,310			15,046			(2,106	)
Reduction in value of assets		74,658			—			—
Other		(16,080	)		(2,883	)		2,092
Income tax	$	39,833		$	225,020		$	85,804

The tax effects of temporary differences that give rise to significant components of deferred income tax assets and liabilities as of December 31, 2013 and 2012 are as follows (in thousands):

	2013		2012
Deferred tax assets:
Allowance for doubtful accounts	$	8,482	$	9,701
Operating loss and tax credit carryforwards		32,543		18,020
Compensation and employee benefits		50,136		49,136
Decommissioning liabilities		22,124		28,246
Other		51,161		47,353
		164,446		152,456
Valuation allowance		—		—
Net deferred tax assets		164,446		152,456
Deferred tax liabilities:
Property, plant and equipment		671,172		650,778
Notes receivable		5,429		14,085
Goodwill and other intangible assets		136,940		145,296
Deferred revenue on long-term contracts		21,354		4,329
Other		56,846		48,992
Deferred tax liabilities		891,741		863,480
Net deferred tax liability	$	727,295	$	711,024

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, 2013 and 2012 as follows (in thousands):

	2013			2012
Deferred tax assets:
Current deferred income taxes	$	8,785		$	34,120
Deferred tax liabilities:
Non-current deferred income taxes		(736,080	)		(745,144	)
Net deferred tax liability	$	(727,295	)	$	(711,024	)

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As of December 31, 2013, the Company had approximately $1.5 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, 2013, the Company also has various state net operating loss carryforwards with expiration dates from 2014 to 2026. A deferred tax asset of $10.8 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, 2013, the undistributed earnings of the Company’s foreign subsidiaries were approximately $56 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 unrecognized tax benefits of approximately $29.9 million, $26.4 million and $21.7 million as of December 31, 2013, 2012 and 2011, respectively all of which would impact the Company’s effective tax rate if recognized.

The activity in unrecognized tax benefits as of December 31, 2013, 2012 and 2011 is as follows (in thousands):

	2013			2012			2011
Unrecognized tax benefits, December 31, 2012, 2011 and 2010, respectively	$	26,399		$	21,692		$	24,760
Additions based on tax positions related to current year		—			—			—
Additions based on tax positions related to prior years		5,065			6,873			871
Reductions based on tax positions related to prior years		(1,565	)		(2,166	)		(3,939	)
Unrecognized tax benefits, December 31, 2013, 2012 and 2011, respectively	$	29,899		$	26,399		$	21,692

(12) Segment Information

Business Segments

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 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

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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, 2013, 2012 and 2011 is shown in the following tables (in thousands):

Year Ended December 31, 2013

	Drilling Products and Services		Onshore Completion and Workover Services		Production Services		Subsea and Technical Solutions			Unallocated			Consolidated Total
Revenues	$	838,514	$	1,596,704	$	1,445,555	$	731,051		$	—		$	4,611,824
Cost of services
(exclusive of items shown separately below)		276,131		1,083,494		1,011,933		530,292			—			2,901,850
Depreciation, depletion, amortization and accretion		169,296		215,506		178,442		62,684						625,928
General and administrative expenses		145,585		153,825		190,614		143,853			—			633,877
Reduction in value of assets		2,292		16,975		28,568		371,545			—			419,380
Income (loss) from operations		245,210		126,904		35,998		(377,323	)		—			30,789
Interest expense		—		—		—		—			(106,954	)		(106,954	)
Interest income		—		—		—		2,585			393			2,978
Other income		—		—		—		—			2,486			2,486
Loss on early extinguishment of debt		—		—		—		—			(884	)		(884	)
Income (loss) from continuing operations before income taxes	$	245,210	$	126,904	$	35,998	$	(374,738	)	$	(104,959	)	$	(71,585	)

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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		—		—		—		—		(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

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		—		—			—		—		(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 $4.5 million of acquisition related expenses recorded in the year ended December 31, 2011.

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Identifiable Assets

	Drilling Products and Services		Onshore Completion and Workover Services		Production Services		Subsea and Technical Solutions		Marine		Unallocated		Consolidated Total
December 31, 2013	$	1,245,501	$	2,973,916	$	2,176,785	$	1,015,105	$	—	$	—	$	7,411,307
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

Capital Expenditures

	Drilling Products and Services		Onshore Completion and Workover Services		Production Services		Subsea and Technical Solutions		Marine		Consolidated Total
December 31, 2013	$	269,152	$	99,517	$	107,412	$	144,388	$	—	$	620,469
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

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:

	Revenues						Long-Lived Assets
	2013		2012		2011		2013		2012
United States	$	3,760,276	$	3,769,528	$	1,438,138	$	2,476,792	$	2,684,932
Other Countries		851,548		798,540		526,194		525,402		570,288
Total	$	4,611,824	$	4,568,068	$	1,964,332	$	3,002,194	$	3,255,220

(13) Guarantee

In accordance with authoritative guidance related to guarantees, the Company has assigned an estimated value of $2.6 million as of December 31, 2013 and 2012, 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. As of December 31, 2013, 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 $109.1 million, net of the contractual right to receive payments from third parties, which is approximately $24.6 million, as of December 31, 2013. The total maximum potential obligation will decrease over time as the underlying obligations are fulfilled.

(14) 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

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asset value under the capital lease was approximately $37.6 million at inception and accumulated depreciation through December 31, 2013 and 2012 was approximately $16.4 million and $12.2 million, respectively. As of December 31, 2013 and 2012, the Company had approximately $21.4 million and $25.6 million, respectively, included in other long-term liabilities, and approximately $4.2 million and $3.9 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 $4.2 million, $4.6 million, $5.0 million, $5.4 million and $5.9 million for the years ending December 31, 2014, 2015, 2016, 2017 and 2018, respectively, exclusive of interest at an annual rate of 8.5%. For the years ended December 31, 2013, 2012 and 2011, the Company recorded interest expense of approximately $2.4 million, $2.7 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 $28.7 million, $26.3 million and $18.3 million in the years ended December 31, 2013, 2012 and 2011, respectively. Future minimum lease payments under non-cancelable leases for the five years ending December 31, 2014 through 2018 and thereafter are as follows: $72.3 million, $51.5 million, $36.7 million, $27.1 million, $18.7 million and $26.0 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.

(15) 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, 2013 and 2012 (in thousands):

	December 31, 2013		Fair Value Measurements at Reporting Date Using
			Level 1		Level 2		Level 3
Inventory and other current assets
Available-for-sale securities	$	8,817	$	8,817		—		—
Intangible and other long-term assets, net
Non-qualified deferred compensation assets	$	13,731	$	2,330	$	11,401		—
Interest rate swaps	$	337		—	$	337		—
Accounts payable
Non-qualified deferred compensation liabilities	$	1,944		—	$	1,944		—
Accrued Expenses
Contingent consideration	$	136		—		—	$	136
Other long-term liabilities
Non-qualified deferred compensation liabilities	$	14,986		—	$	14,986		—

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	December 31, 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		—
Accrued expenses
Contingent consideration	$	9,890		—		—	$	9,890
Other long-term liabilities
Non-qualified deferred compensation liabilities	$	13,515		—	$	13,515		—

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 7).

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 10). 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.

In July 2013, June 2013 and April 2012, the Company entered into interest rate swap agreements related to its fixed rate debt maturing in 2021 for notional amounts of $100 million each, 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 floating rates, which are adjusted every 90 days, based on LIBOR plus a fixed margin. The swap agreements, scheduled to terminate on December 15, 2021, are designated as fair value hedges of a portion of the Company’s 7 1/8% senior notes, as the derivative has been tested to be highly effective in offsetting changes in the fair value of the underlying note. As these derivatives are classified as fair value hedges, the changes in the fair value of the derivatives are offset against the changes in the fair value of the underlying note in interest expense, net (see note 16). 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.

During 2013, the Company paid $6.5 million of contingent consideration related to its 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.

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The following table summarizes the activity recorded using fair value of Level 3 liabilities for the years ended December 31, 2013 and 2012 (in thousands):

	2013			2012
Balance as of December 31, 2012 and 2011, respectively	$	9,890		$	—
Additions related to acquisitions		—			10,663
Settlements		(6,500	)		(3,000	)
Losses included in earnings attributable to additional consideration		—			2,227
Reduction in fair value of liability for additional consideration		(3,254	)		—
Balance as of December 31, 2013 and 2012, respectively	$	136		$	9,890

The following tables reflects the fair value measurements used in testing the impairment of long-lived assets and goodwill during the years ended December 31, 2013 and 2011 (in thousands):

			Fair Value Measurements at Reporting Date Using
	December 31, 2013		(Level 1)		(Level 2)		(Level 3)		Total Losses
Property, plant and equipment, net	$	328,876		—		—	$	328,876	$	(243,781	)
Goodwill		—		—		—		—	$	(91,016	)
Intangible assets	$	4,355					$	4,355	$	(18,296	)

	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	)

During the year ended December 31, 2013, the Company recorded $243.8 million in expense related to reduction in carrying values of its property, plant and equipment. The reduction in value of assets expense was comprised of $221.2 million related to certain marine vessels and equipment included in the Subsea and Technical Solutions segment, $11.4 million related to equipment in the coiled tubing division included in the Production Services segment and $11.2 million related to mechanical drilling rigs included in the Onshore Completion and Workover Services segment. In addition, the Company recorded a $91.0 million expense related to reduction in value of goodwill and an $18.3 million expense, primarily, related to reduction in carrying values of the intangible assets in the subsea construction division included in the Subsea and Technical Solutions segment (see note 4).

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. The write offs related to liftboats in 2011 are included in discontinued operations in the consolidated statements of operations.

(16) 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.

The Company has three interest rate swaps for notional amounts of $100 million each related to its 7 1/8% senior notes maturing in December 2021. These transactions are designated as fair value hedges since the swaps hedge against the change in fair value of fixed rate debt resulting from changes in interest rates. The Company recorded a derivative asset of $0.3 million and $1.3 million within intangible and other long term assets in the consolidated balance sheets as of December 31, 2013 and December 31, 2012, respectively, relating to these swaps.

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The Company previously had an interest rate swap for a notional amount of $150 million related to its 6 7/8% senior notes 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 $1.2 million.

The changes in fair value of the interest rate swaps are included in the adjustments to reconcile net income to net cash provided by operating activities in the consolidated statement of cash flows. The location and effect of the derivative instrument on the consolidated statement of operations for the years ended December 31, 2013, 2012 and 2011, presented on a pre-tax basis, is as follows (in thousands):

Effect of derivative instrument	Location of (gain) loss recognized	2013			2012			2011
Interest rate swap	Interest expense, net	$	13,079		$	(3,632	)	$	793
Hedged item - debt	Interest expense, net		(12,303	)		2,346			(2,536	)
		$	776		$	(1,286	)	$	(1,743	)

For the years ended December 31, 2013, 2012 and 2011, approximately $0.8 million of interest expense, and $1.3 million and $1.7 million of interest income, respectively, 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.

(17) Related Party Transactions

Subsequent to the February 2012 acquisition of Complete, the Company purchases services, products and equipment from companies affiliated with an officer of one of its subsidiaries. The Company believes the transactions reflected below with these related parties are on terms and conditions no less favorable to the Company than transactions with unaffiliated parties. For the years ended December 31, 2013 and 2012, these transactions totaled approximately $164.8 million and $240.3 million, respectively. For the year ended December 31, 2013, approximately $52.8 million was purchased from ORTEQ Energy Services, a heavy equipment construction company which also manufactures pressure pumping equipment, approximately $14.0 million was paid to Resource Transport, LLC, related to the transportation of sand used in pressure pumping activities, approximately $69.1 million was purchased from Texas Specialty Sands, LLC primarily for the purchase of sand used for pressure pumping activities, approximately $26.9 million was purchased from ProFuel, LLC, primarily related to the purchase of diesel used to operate equipment and trucks and approximately $2.0 million was related to facilities leased from Timber Creek Real Estate Partners. For the year ended December 31, 2012, approximately $111.6 million was purchased from ORTEQ Energy Services, approximately $4.1 million was purchased from Ortowski Construction, approximately $12.1 million was paid to Resource Transport, approximately $91.9 million was purchased from Texas Specialty Sands, LLC, 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, 2013, the Company’s trade accounts payable includes amounts due to these companies totaling approximately $14.6 million, of which approximately $7.8 million was due ORTEQ Energy Services, approximately $0.9 million was due Resource Transport, LLC, approximately $2.0 million was due Texas Specialty Sands, LLC, approximately $2.6 million was due ProFuel, LLC and approximately $1.3 million was due 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.

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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 $26.9 million and $21.1 million for the years ended December 31, 2013 and 2012, respectively. The Company had trade receivables from Linn of approximately $2.9 million and $3.3 million as of December 31, 2013 and 2012, respectively.

(18) Interim Financial Information (Unaudited)

The following is a summary of consolidated interim financial information for the two years ended December 31, 2013 and 2012 (in thousands):

	Three Months Ended
	March 31			June 30			Sept. 30		Dec. 31
2013
Revenues	$	1,135,479		$	1,159,713		$	1,188,615	$	1,128,017
Less:
Cost of services, rentals and sales		707,487			711,883			748,052		734,428
Depreciation, depletion, amortization and accretion		149,634			154,987			158,006		163,301
Gross profit		278,358			292,843			282,557		230,288
Reduction in value of assets		—			—			—		419,380
Net income (loss) from operations		63,727			68,559			69,835		(313,539	)
Earnings (loss) per share from operations:
Basic	$	0.40		$	0.43		$	0.44	$	(1.97	)
Diluted		0.40			0.43			0.43		(1.97	)
	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
Loss per share from discontinued operations:
Basic	$	(0.13	)	$	(0.01	)	$	—	$	—
Diluted		(0.13	)		(0.01	)		—		—

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

In 2010, Wild Well acquired 100% ownership of the 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 operated these assets. Prior to April 2012, the Company had an interest in oil and gas operations through its equity-method investment in Dynamic Offshore (see note 8). For the year ended December 31, 2012, oil and gas-producing activities were not considered significant and are presented for comparative purposes only.

The Company’s December 31, 2013, 2012 and 2011 estimates of proved reserves are based on reserve reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers. Users of this information should be aware that the process of estimating quantities of “proved”, “proved developed” and “proved undeveloped” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may also change substantially over time as a result of multiple factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves are estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion.

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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, 2010		5,982			5,301			3,395			20,111
Purchase of reserves in place		—			—			958			8,045
Revisions		887			1,338			412			(547	)
Sales of reserves in-place		—			—			(1,159	)		(8,467	)
Production		(439	)		(371	)		(399	)		(906	)
December 31, 2011		6,430			6,268			3,207			18,236
Revisions		2,234			5,357			—			—
Change in ownership percentage		—			—			(3,207	)		(18,236	)
Production		(457	)		(341	)		—			—
December 31, 2012		8,207			11,284			—			—
Revisions		(3,203	)		(4,036	)		—			—
Production		(411	)		(296	)		—			—
December 31, 2013		4,593			6,952			—			—
Proved-developed reserves:
December 31, 2011		3,495			3,229			2,606			14,695
December 31, 2012		5,076			5,085			—			—
December 31, 2013		2,397			2,100			—			—
Proved-undeveloped reserves:
December 31, 2011		2,935			3,039			602			3,542
December 31, 2012		3,131			6,199			—			—
December 31, 2013		2,196			4,852			—			—

During the year ended December 31, 2013, the Company incurred a downward revision to its proved oil and natural gas reserves due to its drilling results during the year and resulting year-end production rates.

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, 2013, 2012 and 2011 (in thousands).

	Consolidated						Company’s Share of Equity-Method  Investments
	Years Ended December 31,						Year Ended
	2013		2012		2011		2011
Acquisition of properties - proved	$	—	$	—	$	—	$	32,586
Acquisition of properties - unproved		—		—		—		—
Exploratory costs		—		—		—		—
Development costs		51,527		34,685		10,560		18,367
Total costs incurred	$	51,527	$	34,685	$	10,560	$	50,953

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

	As of December 31,
	2013			2012
Proved oil and gas properties	$	136,350		$	77,285
Accumulated depreciation, depletion and amortization		(21,158	)		(13,620	)
Capitalized costs, net	$	115,192		$	63,665

Productive Wells Summary

The following table presents the Company’s ownership of productive oil wells as of December 31, 2013. Productive wells consist of producing wells and wells capable of production. In the table, “gross” refers to the total wells in which the Company owns an interest and “net” refers to the sum of fractional interests owned in gross wells.

	Productive Wells
	Gross		Net
Oil		9.00		4.59

Acreage

The following table sets forth information as of December 31, 2013 relating to acreage held by the Company. Developed acreage is assigned to productive wells.

	Gross Acreage		Net Acreage
Developed		17,280		8,813
Undeveloped		—		—
Total		17,280		8,813

Drilling Activity

The following table shows the Company’s drilling activity for the years ended December 31, 2013 and 2012. The Company did not engage in any drilling activity related to its ownership of the Bullwinkle platform and its related assets during the year ended December 31, 2011. In the table, “gross” refers to the total wells in which the Company has a working interest and “net” refers to the gross wells multiplied by the Company’s working interest in these wells. Well activity refers to the number of wells completed during a fiscal year, regardless of when drilling first commenced.

	2013				2012
	Gross		Net		Gross		Net
Exploratory Wells
Productive		—		—		—		—
Non-productive		—		—		—		—
Total		—		—		—		—
Development Wells
Productive		2.00		1.02		—		—
Non-productive		1.00		0.51		—		—
Total		3.00		1.53		—		—

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Results of Operations

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

	Years Ended December 31,
	2013		2012		2011
Consolidated Entities
Revenues
Sales	$	47,050	$	57,757	$	54,442
Production costs		9,876		12,332		12,293
Exploration expenses		—		—		—
Depreciation, depletion and amortization		12,032		9,818		11,928
		25,142		35,607		30,221
Income tax expenses		8,800		13,175		10,789
Results of operations from producing activities (excluding corporate overhead)	$	16,342	$	22,432	$	19,432
Company’s share of equity-method investments
					Year Ended 2011
Revenues
Sales					$	53,181
Production costs						22,034
Exploration expenses						—
Depreciation, depletion and amortization						18,449
						12,698
Income tax expenses						4,533
Results of operations from producing activities (excluding corporate overhead)					$	8,165

The Company’s oil and gas operations are in the Gulf of Mexico. The Company’s average sales price was $101.85 per barrel of oil and $3.98 per mcf of gas in 2013, $100.70 per barrel of oil and $2.45 per mcf of gas in 2012 and $108.79 per barrel of oil and $3.45 per mcf of gas in 2011. Average production costs were $10.70, $10.71 and $12.51 per barrel of oil equivalent in years ended December 31, 2013, 2012 and 2011, 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. Average production costs were $26.30 per barrel of oil equivalent in 2011.

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.

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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 as of December 31, 2013, 2012 and 2011 is as follows (in thousands):

	Consolidated									Company’s Share of Equity-Method  Investments
	2013			2012			2011			2011
Future cash inflows	$	496,704		$	891,215		$	701,170		$	414,246
Future production costs		(82,487	)		(141,980	)		(126,627	)		(100,848	)
Future development and abandonment costs		(156,340	)		(91,632	)		(58,388	)		(67,760	)
Future income tax expenses		(89,507	)		(229,808	)		(185,816	)		(73,202	)
Future net cash flows		168,370			427,795			330,339			172,436
10% annual discount for estimated timing of cash flows		10,641			124,365			92,590			39,704
Standardized measure of discounted future net cash flows	$	157,729		$	303,430		$	237,749		$	132,732

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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, 2013, 2012 and 2011 is as follows (in thousands):

	Consolidated									Company’s Share of Equity-Method  Investments
	2013			2012			2011			2011
Beginning of the period	$	303,430		$	237,749		$	169,492		$	102,476
Net change in sales and transfer prices and in production (lifting) costs related to future production		(13,278	)		(17,734	)		62,881			27,944
Changes in estimated future development costs		(48,594	)		(5,569	)		8,297			(8,862	)
Sales and transfers of oil and gas produced during the period		(45,866	)		(45,425	)		(54,057	)		(44,268	)
Net change due to extensions, discoveries, and improved recovery		75,304			206,313			—			—
Net changes due to purchases and sales of minerals in place		—			—			—			51,781
Net changes due to revisions in quantity estimates		(228,620	)		(63,192	)		57,189			22,005
Previously estimated development costs incurred during the period		10,136			4,748			17,980			13,840
Exchange transaction		—			—			—			(23,356	)
Accretion of discount		46,711			37,252			26,625			11,179
Other-unspecified		(24,169	)		(21,799	)		(12,650	)		(2,065	)
Net change in income taxes		82,675			(28,913	)		(38,008	)		(17,942	)
Aggregate change in the standardized measure of discounted future net cash flows for the year		(145,701	)		65,681			68,257			30,256
End of the period	$	157,729		$	303,430		$	237,749		$	132,732

The December 31, 2013 amount was estimated by Netherland, Sewell & Associates, Inc. using a twelve month average WTI price of $93.42 per barrel (bbl), and a Henry Hub gas price of $3.670 per million British Thermal Units, and price differentials.

The December 31, 2012 amount was estimated by Netherland, Sewell & Associates, Inc. using a twelve month average WTI price of $91.21 per barrel (bbl), and a Henry Hub gas price of $2.757 per million British Thermal Units, and price differentials.

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

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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, regarding 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, 2013 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, 2013, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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, 2013. 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, 2013 based upon criteria in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, our management determined that as of December 31, 2013, our internal control over financial reporting was effective based on those criteria.

Our internal control over financial reporting as of December 31, 2013 has been audited by KPMG, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

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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, 2013, based on criteria established in Internal Control – Integrated Framework (1992) 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, 2013, based on criteria established in Internal Control – Integrated Framework (1992) 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, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2013, and our report dated February 27, 2014 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

New Orleans, Louisiana

February 27, 2014

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Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information relating to our executive officers is included in “Executive Officers of Registrants” in Part I of this Annual Report on Form 10-K, 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 on Form 10-K, 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.

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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, 2013 and 2012

Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011

Consolidated Statements of Comprehensive Income/Loss for the years ended December 31, 2013, 2012 and 2011

Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2013, 2012 and 2011

Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011

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, 2013, 2012 and 2011

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 Current Report on Form 8-K filed October 12, 2011 (File No. 001-34037)).
3.1	Restated Certificate of Incorporation of Superior Energy Services, Inc. (incorporated herein by reference to Exhibit 3.1 to Superior Energy Services, Inc.’s Quarterly Report on Form 10-Q filed August 7, 2013 (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 Current Report on Form 8-K filed March 12, 2012 (File No. 001-34037)).
4.1	Specimen Stock Certificate (incorporated herein by reference to Post-Effective Amendment No. 1 to Superior Energy Services, Inc.’s Form S-4 on Form SB-2 filed January 9, 1997 (Registration Statement No. 33-94454)).
4.2	Indenture, dated April 27, 2011, among SESI, L.L.C., 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 Current Report on Form 8-K filed April 27, 2011 (File No. 001-34037)), as amended by Supplemental Indenture, dated February 29, 2012, by and among SESI, L.L.C., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as

85

Exhibit No.	Description
	trustee (incorporated by reference to Exhibit 4.2 to Superior Energy Services, Inc.’s Current Report on Form 8-K filed March 1, 2012 (File No. 001-34037)), as further amended by Supplemental Indenture dated May 7, 2012, by and among SESI, L.L.C. the guarantors party thereto 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 Current Report on Form 8-K filed May 8, 2012 (File No. 001-34037)).
4.3	Indenture, dated December 6, 2011, among SESI, L.L.C., 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 Current Report on Form 8-K filed December 12, 2011 (File No. 001-34037)), as amended by Supplemental Indenture, dated February 29, 2012, by and among SESI, L.L.C., the guarantors party thereto 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 Current Report on Form 8-K filed March 1, 2012 (File No. 001-34037)), as further amended by Supplemental Indenture dated May 7, 2012, by and among SESI, L.L.C. the guarantors party thereto 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 Current Report on Form 8-K filed May 8, 2012 (File No. 001-34037)).
10.1^	Amended and Restated Superior Energy Services, Inc. 1995 Stock Incentive Plan (incorporated herein by reference to Exhibit A to Superior Energy Services, Inc.’s Definitive Proxy Statement filed June 26, 1997 (File No. 000-20310)).
10.2^	Superior Energy Services, Inc. 2013 Employee Stock Purchase Plan (incorporated herein by reference to Appendix B to Superior Energy Services, Inc.’s Definitive Proxy Statement filed April 29, 2013 (File No. 001-34037)).
10.3^	Superior Energy Services, Inc. 1999 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.2 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 Amendment No. 2 to the 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 Current Report on Form 8-K filed December 20, 2004 (File No. 333-22603)).
10.4^	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 Amendment No. 1 to the 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 Current Report on Form 8-K filed December 20, 2004 (File No. 333-22603)).
10.5^*	Superior Energy Services, Inc. Amended and Restated Nonqualified Deferred Compensation Plan.
10.6^	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)).
10.7^	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)).
10.8^*	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

86

Exhibit No.	Description
	Exhibit 10.21 to Superior Energy Services, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 001-34037)), as further amended by Amendment No. 2 to the Superior Energy Services, Inc. Supplemental Executive Retirement Plan.
10.9^	Superior Energy Services, Inc. 2009 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Current Report on Form 8-K filed May 27, 2009 (File No. 001-34037)).
10.10^	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 Current Report on Form 8-K filed December 16, 2009 (File No. 001-34037)).
10.11^	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 Current Report on Form 8-K filed December 16, 2009 (File No. 001-34037)).
10.12^	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 Current Report on Form 8-K filed December 16, 2009 (File No. 001-34037)).
10.13^	Superior Energy Services, Inc. 2011 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Current Report on Form 8-K filed May 26, 2011 (File No. 001-34037)).
10.14^	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 Current Report on Form 8-K filed December 14, 2011 (File No. 001-34037)).
10.15^	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 Current Report on Form 8-K filed December 14, 2011 (File No. 001-34037)).
10.16^	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 Current Report on Form 8-K filed December 14, 2011 (File No. 001-34037)).
10.17^	Superior Energy Services, Inc. Annual Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Current Report on Form 8-K filed August 14, 2013 (File No. 001-34037)).
10.18	Superior Energy Services, Inc. 2013 Stock Incentive Plan (incorporated herein by reference to Appendix A to Superior Energy Services, Inc.’s Definitive Proxy Statement filed April 29, 2013 (File No. 001-34037)).
10.19^*	Form of Restricted Stock Agreement under the Superior Energy Services, Inc. 2013 Stock Incentive Plan.
10.20^*	Form of Restricted Stock Unit Agreement under the Superior Energy Services, Inc. 2013 Stock Incentive Plan.
10.21^*	Form of Stock Option Agreement under the Superior Energy Services, Inc. 2013 Stock Incentive Plan.
10.22^*	Form of Performance Share Unit Agreement under the Superior Energy Services, Inc. 2013 Stock Incentive Plan.

87

Exhibit No.	Description
10.23^*	Form of Strategic Performance Award Agreement under the Superior Energy Services, Inc. 2013 Stock Incentive Plan.
10.24^	Form of Notice of Grant of Restricted Stock Units for Non-Management Directors under the Superior Energy Services, Inc. 2013 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.6 to Superior Energy Services, Inc.’s Quarterly Report on Form 10-Q filed November 6, 2013 (File No. 001-34037)).
10.25^	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 Annual Report on Form 10-K filed February 28, 2012 (File No. 001-34037)).
10.26^	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 Annual Report on Form 10-K filed February 28, 2012 (File No. 001-34037)).
10.27^	Complete Production Services, Inc. 2008 Incentive Award Plan (incorporated herein by reference to Exhibit 10.25 to Superior Energy Services, Inc.’s Annual Report on Form 10-K filed February 28, 2012 (File No. 001-34037)).
10.28^	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 Annual Report on Form 10-K filed February 28, 2012 (File No. 001-34037)).
10.29^	Buy-Out Agreement, dated 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 Current Report on Form 8-K filed May 3, 2010 (File No. 001-34037)).
10.30^	Senior Advisor Agreement, dated 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 Current Report on Form 8-K filed May 3, 2010 (File No. 001-34037)).
10.31^	Letter Agreement, dated 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 Current Report on Form 8-K filed December 16, 2010 (File No. 001-34037)).
10.32^	Amended and Restated Complete Production Services, Inc. Executive Agreement, dated December 31, 2008, by and between Complete Production Services, Inc. and Brian K. Moore (incorporated herein by reference to Exhibit 10.34 to Superior Energy Services, Inc.’s Annual Report on Form 10-K filed February 28, 2012 (File No. 001-34037)).
10.33^	Superior Energy Services, Inc. Directors Deferred Compensation Plan (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Current Report on Form 8-K filed February 25, 2011 (File No. 001-34037)).
10.34^	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 Current Report on Form 8-K filed December 18, 2012 (File No. 001-34037)).
10.35^	Superior Energy Services, Inc. Change of Control Severance Plan (incorporated herein by reference to Exhibit 10.2 to Superior Energy Services, Inc.’s Current Report on Form 8-K filed December 18, 2012 (File No. 001-34037)).
10.36^	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 Quarterly Report on Form 10-Q filed November 8, 2012 (File No. 001-34037)).

88

Exhibit No.	Description
10.37	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 Current Report on Form 8-K filed February 8, 2012 (File No. 001-34037)).
10.38*	First Amendment to Third Amended and Restated Credit Agreement, dated November 20, 2013, among SESI, L.L.C., Superior Energy Services, Inc., JPMorgan Chase Bank, N.A. and the lenders party thereto.
14.1	Code of Business Ethics and Conduct (incorporated herein by reference to Exhibit 14.1 to Superior Energy Services, Inc.’s Current Report on Form 8-K filed June 11, 2013 (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.
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, 2013 on Certain Properties owned by Superior Energy Services, Inc.
99.2	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 Annual Report on 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

89

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 27, 2014	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 27, 2014
David D. Dunlap	Officer (Principal Executive Officer)
/s/ Robert S. Taylor	Executive Vice President,	February 27, 2014
Robert S. Taylor	Treasurer and Chief Financial Officer (Principal Financial and Accounting Officer)
/s/ Terence E. Hall	Chairman of the Board	February 27, 2014
Terence E. Hall
/s/ Harold J. Bouillion	Director	February 27, 2014
Harold J. Bouillion
/s/ Enoch L. Dawkins	Director	February 27, 2014
Enoch L. Dawkins
/s/ James M. Funk	Director	February 27, 2014
James M. Funk
	Director	February 27, 2014
Ernest E. Howard, III
/s/ Peter D. Kinnear	Director	February 27, 2014
Peter D. Kinnear
/s/ Michael M. McShane	Director	February 27, 2014
Michael M. McShane
/s/ W. Matt Ralls	Director	February 27, 2014
W. Matt Ralls
/s/ Justin L. Sullivan	Director	February 27, 2014
Justin L. Sullivan

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Schedule II Valuation and Qualifying Accounts

Years Ended December 31, 2013, 2012 and 2011

(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, 2013:
Allowance for doubtful accounts	$	28,715	$	10,078	$	7,763	$	31,030
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

91