10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 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

2

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.

3

PART I

Item 1. Business

General

We believe we are a leading provider of specialized oilfield services and equipment. On February 7, 2012, we acquired Complete Production Services, Inc. (Complete), which significantly added to our geographic footprint in the U.S. land market area. We now offer a wider variety of products and services throughout the life cycle of an oil and gas well. The acquisition of Complete greatly expanded our ability to offer more products and services related to the completion of a well prior to full production commencing, as well as 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;

4

• 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.

5

• 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

6

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.

7

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.

8

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.

9

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;

10

• 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.

11

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.

12

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

13

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

14

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

15

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.

16

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.

17

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.

18

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.

19

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

20

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

21

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

22

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.

23

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.

24

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.

25

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.

26

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

27

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

28

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,

29

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.

30

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.

31

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.

32

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.

42

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

Cash Equivalents

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

Accounts Receivable and Allowances

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

Inventory

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

Property, Plant and Equipment

Property, plant and equipment are stated at cost, except for assets 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.

43

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.

44

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

45

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.

46

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.

47

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.

48

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.

49

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.

50

(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.

51

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

52

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

53

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.

54

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

55

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).

56

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.

57

(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.

58

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.

59

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.

60

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.

61

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.

62

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,

63

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

64

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	)

65

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

66

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	)

67

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.

68

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

69

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		—

70

	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.

71

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.

72

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.

73

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

74

(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.

75

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

76

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		—		—

77

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.

78

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

79

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.

80

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.

81

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.

82

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

83

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.

84

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

90

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

EX-10.5

Exhibit 10.5

AMENDED AND RESTATED

SUPERIOR ENERGY SERVICES, INC.

NONQUALIFIED DEFERRED COMPENSATION PLAN

January 1, 2014

Table of Contents

		Page
ARTICLE I PURPOSE AND EFFECTIVE DATE			1
ARTICLE II DEFINITIONS			1
2.01	Administrative Committee		1
2.02	Base Salary		1
2.03	Base Salary Deferral		1
2.04	Beneficiary		1
2.05	Board		1
2.06	Bonus Compensation		1
2.07	Business Combination		2
2.08	CEO		2
2.09	Change of Control		2
2.10	Change of Control Participant		3
2.11	Claimant		3
2.12	Code		3
2.13	Common Stock		3
2.14	Company		3
2.15	Compensation Committee		4
2.16	Deferral Account		4
2.17	Deferral Period		4
2.18	Deferred Amount		4
2.19	Deferred RSUs		4
2.20	Designee		4
2.21	Disabled		4
2.22	Eligible Cash Compensation		4
2.23	ERISA		4
2.24	Form of Payment		4
2.25	401(k) Plan		4
2.26	Hardship Withdrawal		5
2.27	Hypothetical Investment Benchmark		5
2.28	Incumbent Board		5
2.29	Key Employee		5
2.30	Participant		5
2.31	Participation Agreement		5
2.32	Plan Year		5
2.33	Post Transaction Corporation		5
2.34	Restricted Stock Units or RSUs		5
2.35	Retirement		5
2.36	Separation from Service		6
2.37	Superior		6
2.38	Unforeseeable Emergency		6
2.39	Valuation Date		6
2.40	Years of Service		6

i

ARTICLE III PARTICIPATION AND PARTICIPANT ELECTIONS		7
3.01	Participation	7
3.02	Deferral of Eligible Cash Compensation	7
3.03	Deferral of Restricted Stock Units	7
3.04	Election Timing and Effective Dates.	7
3.05	Contents of Participation Agreement	8
3.06	Modification or Revocation of Election by Participant	8
3.07	Vesting	9
ARTICLE IV MAINTENANCE, CREDITING, AND INVESTMENT OF ACCOUNTS		9
4.01	Maintenance of Deferral Accounts	9
4.02	Crediting of Deferral Accounts	9
4.03	Statement of Accounts	10
4.04	Credit of Dividend Equivalents on Deferred RSUs	10
4.05	Withholding of Taxes	10
ARTICLE V DISTRIBUTION OF BENEFITS		10
5.01	Time and Form of Payment	10
5.02	Specified Payment Dates and In-Service Distributions; Effect of Separation from Service	11
5.03	Death or Disability	13
5.04	Hardship Withdrawals	13
5.05	Acceleration of Payment	13
5.06	Delay of Payment	15
ARTICLE VI BENEFICIARY DESIGNATION		16
6.01	Beneficiary Designation	16
6.02	No Beneficiary Designation	16
ARTICLE VII ADMINISTRATION		16
7.01	Administrative Committee Duties	16
7.02	Claims Procedure.	17
ARTICLE VIII AMENDMENT AND TERMINATION OF PLAN		18
8.01	Amendment	18
8.02	Company’s Right to Terminate	18
ARTICLE IX MISCELLANEOUS		19
9.01	Unfunded Plan	19
9.02	Nonassignability	20
9.03	Validity and Severability; Code Section 409A	20
9.04	Governing Law	20
9.05	Employment Status	20
9.06	Underlying Plans and Programs	20

ii

ARTICLE I

PURPOSE AND EFFECTIVE DATE

The purpose of the Superior Energy Nonqualified Deferred Compensation Plan (“Plan”) is to aid Superior Energy Services, Inc. (“Superior”) and its wholly-owned subsidiaries in retaining and attracting executive employees by providing them with tax deferred savings opportunities. The Plan provides a select group of management and highly compensated employees (within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of the Employee Retirement Income Security Act of 1974, as amended (ERISA)) with the opportunity to elect to defer receipt of specified portions of compensation, and to have these deferred amounts treated as if invested in specified hypothetical investment benchmarks. The Plan is intended to comply with Code Section 409A. The Plan was originally adopted effective September 1, 2004, first amended and restated effective January 1, 2008, and amended on January 1, 2009. This amended and restated version of the Plan is effective January 1, 2014.

ARTICLE II

DEFINITIONS

For the purposes of this Plan, the following words and phrases shall have the meanings indicated, unless the context clearly indicates otherwise:

2.01 Administrative Committee. “Administrative Committee” means the committee appointed by the Compensation Committee or by any person(s) to whom the Compensation Committee has delegated the power of appointment. As of the effective date of the Plan, the persons listed on Appendix B are members of the Administrative Committee.

2.02 Base Salary. “Base Salary” means the base rate of cash compensation paid by the Company to or for the benefit of a Participant for services rendered or labor performed while a Participant, before any reduction for withholdings or amounts deferred under the Plan or any other salary reduction program.

2.03 Base Salary Deferral. “Base Salary Deferral” means the amount of a Participant’s Base Salary that the Participant elects to have withheld on a pre-tax basis from his Base Salary and credited to his Deferral Account pursuant to, and subject to the limitations of, Article III.

2.04 Beneficiary. “Beneficiary” means the person, persons, or entity designated by the Participant to receive any benefits payable under the Plan pursuant to Article VI.

2.05 Board. “Board” means the Board of Directors of Superior.

2.06 Bonus Compensation. “Bonus Compensation” means: (i) the annual cash bonus earned each year by a Participant and paid in the following year in a lump sum or installments (including but not limited to Annual Incentive Plan bonuses); and (ii) the cash portion of any Performance Share Unit (“PSU”) awards paid by Superior after any withholdings or salary reductions, but before reduction for amounts deferred under the Plan.

1

2.07 Business Combination. “Business Combination” has the meaning set forth in Section 2.09(c).

2.08 CEO. “CEO” means the Chief Executive Officer of Superior.

2.09 Change of Control. “Change of Control” means:

(a) the acquisition by any person of beneficial ownership of 50% or more of the outstanding shares of the Common Stock or 50% or more of the combined voting power of Superior’s then-outstanding securities entitled to vote generally in the election of directors; provided, however, that for purposes of this subsection (a), the following acquisitions shall not constitute a Change of Control:

(1) any acquisition (other than a Business Combination (as defined below) that constitutes a Change of Control under subsection (c) hereof) of Common Stock directly from Superior,

(2) any acquisition of Common Stock by Superior,

(3) any acquisition of Common Stock by any employee benefit plan (or related trust) sponsored or maintained by Superior or any corporation controlled by the Company, or

(4) any acquisition of Common Stock by any corporation or other entity pursuant to a Business Combination that does not constitute a Change of Control under subsection (c) hereof; or

(b) individuals who, as of January 1, 2014, constituted the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to such date whose election, or nomination for election by Superior’s stockholders, was approved by a vote of at least two-thirds of the directors then comprising the Incumbent Board shall be considered a member of the Incumbent Board, unless such individual’s initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a person other than the Incumbent Board; or

(c) consummation of a reorganization, share exchange, merger, or consolidation (including any such transaction involving any direct or indirect subsidiary of Superior) or sale or other disposition of all or substantially all of the assets of Superior (a “Business Combination”); provided, however, that in no such case shall any such transaction constitute a Change of Control if immediately following such Business Combination:

(1) the individuals and entities who were the beneficial owners of Superior’s outstanding Common Stock and Superior’s voting securities entitled to vote generally in the election of directors immediately prior to such Business Combination have direct or indirect beneficial ownership, respectively, of more

2

than 50% of the then-outstanding shares of common stock, and more than 50% of the combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors of the surviving or successor corporation, or, if applicable, the ultimate parent company thereof (the “Post-Transaction Corporation”), and

(2) except to the extent that such ownership existed prior to the Business Combination, no person (excluding the Post-Transaction Corporation and any employee benefit plan or related trust of either Superior, the Post-Transaction Corporation, or any subsidiary of either corporation) beneficially owns, directly or indirectly, 25% or more of the then-outstanding shares of common stock of the corporation resulting from such Business Combination or 25% or more of the combined voting power of the then-outstanding voting securities of such corporation, and

(3) at least a majority of the members of the board of directors of the Post-Transaction Corporation were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board providing for such Business Combination; or

(d) approval by the stockholders of Superior of a complete liquidation or dissolution of Superior.

For purposes of this definition of “Change of Control,” the term “person” shall mean a natural person or entity, and shall also mean the group or syndicate created when two or more persons act as a syndicate or other group (including, without limitation, a partnership or limited partnership) for the purpose of acquiring, holding, or disposing of a security, except that “person” shall not include an underwriter temporarily holding a security pursuant to an offering of the security.

Notwithstanding any other provision of this definition of Change of Control, no payment shall be made from this Plan as a result of a Change of Control unless such event qualifies as a Change of Control under Code Section 409A.

2.10 Change of Control Participant. “Change of Control Participant” has the meaning set forth in Section 8.02(a).

2.11 Claimant. “Claimant” has the meaning set forth in Section 7.02(a).

2.12 Code. “Code” means the Internal Revenue Code of 1986, as amended. References to any provision of the Code or regulation (including a proposed regulation) thereunder shall include any successor provisions or regulations.

2.13 Common Stock. “Common Stock” means the common stock of Superior, $0.001 par value per share.

2.14 Company. “Company” means Superior and all entities with whom Superior would be considered a single employer under Section 414(b) of the Code (employees of a

3

controlled group of corporations), and all entities with whom Superior would be considered a single employer under Section 414(c) of the Code (employees of partnerships, proprietorships, etc., under common control).

2.15 Compensation Committee. “Compensation Committee” means the Compensation Committee of the Board.

2.16 Deferral Account. “Deferral Account” means the account maintained on the books of the Company for each Participant pursuant to Article IV.

2.17 Deferral Period. “Deferral Period” has the meaning set forth in Section 3.05.

2.18 Deferred Amount. “Deferred Amount” has the meaning set forth in Section 3.02.

2.19 Deferred RSUs. RSUs that are deferred pursuant to this Plan, in accordance with Sections 3.03 through 3.05.

2.20 Designee. “Designee” means any individual(s) to whom the Board, Compensation Committee, or Administrative Committee has delegated the authority to take action under the Plan. Wherever Board, Compensation Committee, or Administrative Committee is referenced in the Plan, such reference shall be deemed to also refer to such entity’s Designee.

2.21 Disabled. A Participant shall be considered Disabled if the Participant:

(a) is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, or

(b) is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, receiving income replacement benefits for a period of not less than three months under an accident and health plan covering employees of the Participant’s employer.

2.22 Eligible Cash Compensation. “Eligible Cash Compensation” means any Base Salary and Bonus Compensation otherwise earned with respect to a Plan Year. Eligible Cash Compensation does not include expense reimbursements, any form of noncash compensation, stock-based plans, or benefits.

2.23 ERISA. “ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

2.24 Form of Payment. “Form of Payment” means payment in a lump sum or annual installments (not to exceed 15).

2.25 401(k) Plan. “401(k) Plan” means the Superior Energy 401(k) Plan, as amended.

4

2.26 Hardship Withdrawal. “Hardship Withdrawal” means the early payment of all or part of the balance in a Deferral Account(s) in the event of an Unforeseeable Emergency.

2.27 Hypothetical Investment Benchmark. “Hypothetical Investment Benchmark” means the phantom investment benchmarks that are used to measure the return credited to a Participant’s Deferral Account. The Hypothetical Investment Benchmarks are specified by the Administrative Committee and may change from time to time.

2.28 Incumbent Board. “Incumbent Board” has the meaning set forth in Section 2.09(b).

2.29 Key Employee. “Key Employee” shall mean a Participant who is a key employee of the Company under Code Section 416(i) and/or Treasury Regulations Section 1.409A-1(i) because of final and binding action taken by the Board or the Compensation Committee, or by operation of such Code section or regulation. The definition set forth in Section 416(i) of the Code is adjusted by the Secretary of the Treasury for cost-of-living changes, but as of January 1, 2014, a Key Employee under Code Section 416(i) is:

(a) an officer of the Company having annual compensation from the Company of greater than $170,000 (no more than 50 employees of the Company are required to be treated as officers);

(b) an owner of 1% or more of the Company having annual compensation from the Company greater than $150,000; or

(c) an owner of 5% or more of the Company.

2.30 Participant. “Participant” means any individual who is eligible to participate in this Plan under Section 3.01 and who elects to participate by filing a Participation Agreement as provided in Article III.

2.31 Participation Agreement. “Participation Agreement” means the form completed by a Participant in accordance with Article III.

2.32 Plan Year. “Plan Year” means a twelve-month period beginning January 1 and ending the following December 31.

2.33 Post Transaction Corporation. “Post-Transaction Corporation” has the meaning set forth in Section 2.09(c).

2.34 Restricted Stock Units or RSUs. “Restricted Stock Units” or “RSUs” means any grant of restricted stock units from the Company to the Participant under a stockholder approved equity incentive plan of the Company.

2.35 Retirement. “Retirement” means Separation from Service of a Participant from the Company after attaining age 65, or after age 55 with at least five years of service (in accordance with the method of determining years of service adopted by the Company). For deferrals of compensation earned in Plan Years on and after January 1, 2014, “Retirement”

5

means Separation from Service of a Participant from the Company at a time when such Participant’s age plus Years of Service equals at least 60, with any partial years of age being rounded up to the next whole year. Effective November 1, 2013, Participants may elect to apply the definition in the previous sentence to Plan deferrals for Plan Years prior to January 1, 2014, subject to restrictions in the Plan regarding changes to the time and form of payment, including Sections 3.06 and 5.02.

2.36 Separation from Service. “Separation from Service” means “separation from service” with the Company as defined in Treasury Regulation Section 1.409A-1(h). A Participant shall not be considered to have incurred a Separation from Service until the Participant has ceased to provide any services for Superior, its subsidiaries, and any other entity that would be treated as a member of a controlled group that includes Superior under Code Section 414(b) or (c) (as modified by substituting 50% ownership for 80% for all purposes thereof), without any expectation of the Participant being retained to provide future services as an employee or independent contractor.

2.37 Superior. “Superior” means Superior Energy Services, Inc. and its successors and assigns, including but not limited to any corporation or entity with or into which such company may merge or consolidate.

2.38 Unforeseeable Emergency. “Unforeseeable Emergency” means a severe financial hardship of the Participant or Beneficiary resulting from an illness or accident of the Participant or Beneficiary, the Participant’s or Beneficiary’s spouse, or the Participant’s or Beneficiary’s dependent (as defined in Code Section 152(a)); loss of the Participant’s or Beneficiary’s property due to casualty (including the need to rebuild a home following damage to a home not otherwise covered by insurance, for example, not as a result of a natural disaster); or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant or Beneficiary. In addition, the need to pay for medical expenses, including non-refundable deductibles, as well as for the costs of prescription drug medication, may constitute an Unforeseeable Emergency. Finally, the need to pay for the funeral expenses of a spouse or a dependent (as defined in Code Section 152(a)) may also constitute an Unforeseeable Emergency. An Unforeseeable Emergency must satisfy the requirements of Treasury Regulation Section 1.409A-3(i)(3) in order for a payment to be made. Whether a Participant is faced with an “Unforeseeable Emergency” permitting distribution under this Plan is to be determined by the Administrative Committee based on the relevant facts and circumstances of each case and in accordance with Code Section 409A.

2.39 Valuation Date. “Valuation Date” means the last calendar date when the New York Stock Exchange was open, or such other date as the Administrative Committee in its sole discretion may determine.

2.40 Years of Service. “Years of Service” means Years of Service as determined for vesting purposes under the 401(k) Plan.

6

ARTICLE III

PARTICIPATION AND PARTICIPANT ELECTIONS

3.01 Participation. Participation in the Plan shall be limited to executives who (a) are included on a list of eligible employees that the CEO or the Administrative Committee shall establish and revise from time to time and (b) elect to participate in this Plan by filing a Participation Agreement with the Administrative Committee or its Designee.

3.02 Deferral of Eligible Cash Compensation. Subject to the other terms and conditions of this Plan, a Participant may elect to defer a portion of his or her Eligible Cash Compensation for a given Plan Year or performance period (the “Deferred Amount”).

3.03 Deferral of Restricted Stock Units.

(a) Subject to the terms and conditions of this Plan, a Participant may elect to defer, on a grant-by-grant basis, the receipt of all or a portion of the shares of Common Stock that he or she is entitled to receive upon the vesting of RSUs (and any related amounts credited to the Participant’s Dividend Equivalent Account under Section 4.04). Such deferral election must be made during the applicable Section 3.04 enrollment period for the Plan Year in which the RSUs are granted.

(b) A Participant’s Deferred RSUs shall be accounted for separately from his or her Deferred Amounts, and shall generally be subject to all of the provisions of this Plan except Sections 4.01 and 4.02.

3.04 Election Timing and Effective Dates.

(a) A Participation Agreement must be filed prior to the December 31st immediately preceding the Plan Year for which it is effective or by such earlier deadline as the Administrative Committee may prescribe.

(b) Notwithstanding Section 3.04(a), a Participant who is newly eligible for the Plan (as determined in accordance with Treas. Reg. Section 1.409A-2(a)(7)) and who does not participate in any other account balance type nonqualified plan of the Company (as determined by Treas. Reg. Section 1.409A-1(c)) may file a Participation Agreement effective for the remainder of the initial Plan Year of participation and applicable to compensation earned in the remainder of such Plan Year, but only if such election is made not more than 30 days after the Participant becomes eligible for the Plan. In the case of Bonus Compensation, an election by such newly eligible Participant shall only apply to the portion of the Bonus Compensation that is no greater than the total amount of Bonus Compensation for the calendar year multiplied by the ratio of the number of days remaining in the calendar year after the election over 365, unless such bonus meets the requirements of Section 3.04(c).

(c) Elections to defer Bonus Compensation typically must be made in the year prior to the year during which the services are performed that result in the bonus. However, the Administrative Committee may allow Participants whose Bonus Compensation is “performance based” compensation (as defined in Treas. Reg. Section

7

1.409A-1(e)) to execute a Participation Agreement applicable to such qualifying Bonus Compensation by the deadline established by the Retirement Committee, which shall be no later than 6 months prior to the end of the service period during which the Bonus Compensation is earned (e.g. June 30 for qualifying calendar year bonuses). As noted in the applicable regulations, to be considered “performance based,” the Bonus Compensation must be based on a service period of at least 12 months and awarded based on written performance criteria that are established within the first 90 days of the service period, among other requirements.

3.05 Contents of Participation Agreement. The Administrative Committee shall have the discretion to specify the contents of Participation Agreements. Subject to Article V, each Participation Agreement shall set forth: (a) the Deferred Amount, expressed as either a dollar amount or a percentage of the Base Salary and Bonus Compensation for such Plan Year or performance period; provided that a Participant shall be able to defer up to 75% of Base Salary and 100% of Bonus Compensation; (b) whether the Participant is electing to defer a portion or all of the RSUs that may be awarded to the Participant for that Plan Year and, if so, what portion of those RSUs will be deferred; (c) the period after which payment of the Deferred Amount and the issuance of the Common Stock underlying the Deferred RSUs, if applicable, are to be made or begin to be made (the “Deferral Period”); and (d) the form in which payments of the Deferred Amount and the issuance of Common Stock underlying any Deferred RSUs are to be made, which may be a lump sum at the end of the Deferral Period or in substantially equal annual installments over 2 to 15 years following the end of the Deferral Period.

The Deferral Period may be expressed as ending on a specified date, upon the occurrence of an event (such as a Participant’s Separation from Service), or in accordance with such other terms and options that may be set forth in the Participation Agreement. The Deferral Period cannot end later than the year in which the Participant attains age 65 (unless the Participant remains employed by the Company when he/she attains age 65, in which case the Deferral Period will end no later than the Participant’s Separation from Service with the Company).

3.06 Modification or Revocation of Election by Participant.

(a) A Participant may not change the amount of his Base Salary Deferrals during a Plan Year. However, a Participant may discontinue a Base Salary Deferral election if he experiences an Unforeseeable Emergency, or if such discontinuance is required in order to enable the Participant to take a hardship withdrawal from the 401(k) Plan or another similar plan sponsored by the Company, in accordance with Treas. Reg. Section 1.401(k)-1(d)(3), on such forms and subject to such limitations and restrictions as the Administrative Committee may prescribe. If approved by the Administrative Committee, revocation shall take effect as of the first payroll period next following its approval. If a Participant discontinues a Base Salary Deferral election during a Plan Year, he or she will not be permitted to elect to make Base Salary Deferrals again until the later of 6 months from the date of discontinuance or the commencement of the following Plan Year.

(b) A Participant may make an election to change the time or form of his or her payment from the Plan as set forth in an existing Participation Agreement, but in

8

accordance with Treas. Reg. Section 1.409A-2(b), such a change must include the lengthening of the Deferral Period by no less than five years from the original payment date under the Participation Agreement (as in effect before such amendment). In addition, such amended Participation Agreement must be filed with the Administrative Committee or its Designee at least 12 months prior to the date of the first scheduled payment under the Participation Agreement (as in effect before such amendment), and will not be effective for 12 months. Under no circumstances may a Participant’s Participation Agreement be retroactively entered into, modified, or revoked.

(c) Special rules apply to Participant elections to adopt a revised definition of Retirement. See Section 5.02.

3.07 Vesting. Subject to Section 9.01, each Participant shall be 100% vested in his or her Deferral Account(s) at all times. RSUs are subject to the vesting and other provisions of the applicable governing documents.

ARTICLE IV

MAINTENANCE, CREDITING, AND INVESTMENT OF ACCOUNTS

4.01 Maintenance of Deferral Accounts.

(a) The Deferred Amount of a Participant with respect to each Plan Year of participation in the Plan shall be credited by the Administrative Committee to the Participant’s Deferral Account as and when such Deferred Amount would otherwise have been paid to the Participant.

(b) Separate Deferral Accounts shall be maintained for each Participant. More than one Deferral Account may be maintained for a Participant as necessary to reflect (a) various Hypothetical Investment Benchmarks and/or (b) separate Participation Agreements specifying different Deferral Periods, deferral sources, and/or forms of payment. A Participant’s Deferral Account(s) shall be utilized solely as a device for the measurement and determination of the amounts to be paid to the Participant pursuant to this Plan, and shall not constitute or be treated as a trust fund of any kind.

4.02 Crediting of Deferral Accounts.

(a) Each Participant shall be entitled to direct the manner in which his or her Deferral Accounts will be deemed to be invested by selecting among the Hypothetical Investment Benchmarks specified in Appendix A hereto, as amended by the Administrative Committee from time to time, and in accordance with such rules, regulations and procedures as the Administrative Committee may establish from time to time. Notwithstanding anything to the contrary herein, earnings and losses based on a Participant’s investment elections shall begin to accrue as of the date such Participant’s Deferred Amounts are credited to his or her Deferral Accounts.

(b) The Administrative Committee shall determine the balance of each Deferral Account, as of each Valuation Date, by adjusting the balance of such Deferral Account as of the immediately preceding Valuation Date to reflect changes in the value

9

of the deemed investments thereof, credits and debits pursuant to Section 4.01(a) and Section 4.02(a) and distributions pursuant to Article V with respect to such Deferral Account since the preceding Valuation Date.

4.03 Statement of Accounts. The Administrative Committee shall submit to each Participant quarterly statements of his or her Deferral Account(s) in such form as the Administrative Committee deems desirable, setting forth the balance to the credit of such Participant in his or her Deferral Account(s) as of the end of the most recently completed quarter.

4.04 Credit of Dividend Equivalents on Deferred RSUs. For any RSUs a Participant elects to defer, the Administrative Committee shall establish and maintain a “Dividend Equivalent Account” as required under Section 8.3 of the Superior Energy Services, Inc. 2013 Stock Incentive Plan or the equivalent section of any successor plan. All amounts in a Participant’s Dividend Equivalent Account shall be distributed to the Participant in tandem with the related shares of Common Stock underlying the RSUs.

4.05 Withholding of Taxes. To the extent that the Company is required to withhold any taxes or other amounts from the Deferred Amount pursuant to any state, federal or local law, such amounts shall be taken out of other compensation eligible to be paid to the Participant that is not deferred under this Plan, unless otherwise specified by the Administrative Committee pursuant to Section 5.05(c) or (f). Although the Plan is designed to enable Participants to defer income taxes on Deferred Amounts and Deferred RSUs, employment taxes (i.e. FICA taxes) are generally due at the time the applicable compensation becomes vested, regardless of whether an amount is deferred pursuant to this Plan, although exceptions may allow employment taxes to be withheld and paid within the same calendar year that the amount in question becomes vested.

ARTICLE V

DISTRIBUTION OF BENEFITS

5.01 Time and Form of Payment.

(a) Unless otherwise stated in this Article V, at the end of the Deferral Period for each Deferral Account that holds Deferred Amounts, the Company shall pay to the Participant the balance of such Deferral Account at the time or times elected by the Participant in the applicable Participation Agreement; provided that if the Participant has elected to receive payments from a Deferral Account in a lump sum, the Company shall pay the balance in such Deferral Account (determined as of the most recent Valuation Date preceding or coinciding with the payment date) in a lump sum in cash as soon as practicable after the end of the Deferral Period (no later than 90 days after the Deferral Period). If the Participant has elected to receive payments from a Deferral Account in installments, the Company shall make annual cash payments from such Deferral Account, each of which shall consist of an amount equal to (i) the balance of such Deferral Account as of the most recent Valuation Date preceding or coinciding with the payment date times (ii) a fraction, the numerator of which is one and the denominator of which is the number of remaining installments (including the installment being paid). The first such installment shall be paid in January of the year specified in the Participation Agreement (for specified date payments), in January of the year following

10

Separation from Service (for payments triggered by a Separation from Service) or as otherwise specified in the Participation Agreement upon reaching the end of the Deferral Period. Each subsequent installment shall be paid in January of the following years and shall be deemed to be made on a pro rata basis from each of the different deemed investments of the Deferral Account (if there is more than one such deemed investment). The Participant’s Separation from Service may impact the time and form of his payment, as set forth in Section 5.02. If a Participant is subject to the 6-month delay set forth in Section 5.02, then the first installment shall be paid on the later of January of the year following Separation from Service or the first day of the seventh month after the Separation from Service, and all future payments (if any) shall be made in January of each following year.

(b) If a Participant elects to defer an annual grant of RSUs, the shares of Common Stock underlying such grant (and any related amounts credited to the Participant’s Dividend Equivalent Account under Section 4.4) shall be distributed at the time or times elected by the Participant in the applicable Participation Agreement, provided that (i) if the Participant has a Separation from Service prior to the time or times elected by the Participant, the shares of Common Stock shall be distributed in accordance with Section 5.02, and (ii) if the Participant dies or becomes Disabled prior to such date, the shares of Common Stock shall be distributed in accordance with Section 5.03.

5.02 Specified Payment Dates and In-Service Distributions; Effect of Separation from Service.

(a) Subject to the other provisions of this Article V, if a Participant has elected to defer compensation under the Plan for a stated number of years, the Deferred Account balance of the Participant (determined, with respect to Deferred Amounts, as of the most recent Valuation Date preceding such Deferral Period), and any shares of Common Stock associated with Deferred RSUs, shall be distributed in installments or a lump sum in accordance with the Plan and as elected in the Participation Agreement. Notwithstanding the previous sentence, if a Participant has a Separation from Service before the payment date specified in his or her Participation Agreement, the entirety of his or her account balance shall be distributed to him or her as soon as administratively feasible following the Separation from Service in a lump sum payment (in cash or shares of Common Stock, as applicable), unless such termination qualifies as a Retirement, in which case the distribution shall commence as soon as administratively feasible (no later than 90 days after such Separation from Service), but shall be in the form of payment designated by the Participant in the applicable Participation Agreement.

(b) If a Participant has commenced receiving installment payments prior to his Separation from Service, the remaining installments shall be paid to the Participant in a lump sum as soon as administratively feasible following the Separation from Service (no later than 90 days after such termination), unless the Separation from Service constitutes a Retirement, in which case the remaining installments shall be paid pursuant to the elected payment schedule.

11

(c) Special Rules for Elections to apply the January 1, 2014 Revised Retirement Definition: If a Participant entered into a Participation Agreement at a time when Retirement was defined as age 65 or age 55 with 5 Years of Service (“Prior Retirement Definition”), such Participant shall have the option to elect to apply the current definition of Retirement (i.e. total age plus Years of Service equal 60) (the “Retirement Definition Election”) to the amounts covered by such Participation Agreement, with the following conditions being applicable to a Retirement Definition Election:

(1) the Retirement Definition Election will not be effective for 12 months and shall not affect payments scheduled to be made or commence within 12 months of the election;

(2) the commencement of such Deferred Amount shall be delayed: (i) for in-service distributions, by 5 years from the earlier of the Participant’s Separation from Service or the Specified Date elected on the Participant’s original Participation Agreement; and (ii) for distributions scheduled to start on Separation from Service, by 5 years from the Participant’s Separation from Service (this subsection (c)(2) shall not apply, however, if at the time of the Separation of Service the Participant does not meet the current definition of Retirement, in which case there would not be a 5-year delay of the Participant’s lump sum distribution as a result of the Participant electing to change the definition of Retirement); and

(3) the Administrative Committee may restrict Retirement Definition Election changes under this Section 5.02(c), including the ability to impose a requirement that such elections be made on or before any date specified by such committee, and to restrict Participants to a one-time option to change their Retirement Definition Election.

For example, if prior to January 1, 2014, a Participant elected payment of his benefit in 5 installments beginning at Separation from Service, and the Participant terminates on July 1, 2015, at age 52 with 10 Years of Service, under the Prior Retirement Definition, the Participant would not be Retirement eligible because he would not be at least age 65 (or age 55 with 5 Years of Service), and would therefore receive his benefit in a lump sum. Under this restated Plan document, the Participant may elect, at any time 12 months or more prior to termination (by June 30, 2014 in this case, or such earlier date that may be specified by the Administrative Committee), to apply the new definition of Retirement to some or all of his Deferred Amounts. If such Retirement Definition Election is timely made under the above facts, the Participant would be Retirement eligible at Separation from Service and would receive the above distribution in installments rather than a lump sum. However, in compliance with IRS regulations regarding changes to deferral elections, the installments would not commence until January of 2021 (January of the year that is 5 years after Retirement). (Further examples of the application of these special rules for Retirement Definition Elections and the resulting payments are included in separate participant communications regarding such elections, which communications shall be considered part of this Plan.)

12

(d) Lump sum payments (in cash or shares of Common Stock, as applicable) under this Section 5.02 shall be made no later than 90 days after the Separation of Service. Notwithstanding anything else in this Section 5.02, a Participant who is a Key Employee shall not receive a distribution from his Deferral Account(s) or distribution of shares of Common Stock associated with Deferred RSUs on account of his or her Separation from Service until the first day of the seventh month following such Separation from Service, unless such balance is distributable pursuant to another provision of the Plan (e.g. due to death or Disability).

5.03 Death or Disability. Notwithstanding the provisions of Section 5.01 and 5.02 hereof and any Participation Agreement, if a Participant dies or becomes Disabled (whether before or after Separation from Service) prior to receiving full payment of his or her Deferral Account(s), or Deferred RSUs, the Company shall pay the remaining balance of his or her Deferral Account or Deferred RSUs (determined, with respect to Deferred Amounts, as of the most recent Valuation Date preceding or coinciding with such event) to the Participant or, if the Participant is deceased, in accordance with Article VI, in a lump sum (in cash or shares of Common Stock, as applicable) soon as practicable following the occurrence of such event (no later than 90 days after the event occurs).

5.04 Hardship Withdrawals. Notwithstanding the provisions of Section 5.01 and any Participation Agreement, a Participant shall be entitled to early payment of all or part of the balance in his or her Deferral Account(s), or Deferred RSUs, in the event of an Unforeseeable Emergency, in accordance with this Section 5.04. A distribution pursuant to this Section 5.04 may only be made to the extent reasonably needed to satisfy the Unforeseeable Emergency need, and may not be made if such need is or may be relieved (a) through reimbursement or compensation by insurance or otherwise, (b) by liquidation of the Participant’s assets to the extent such liquidation would not itself cause severe financial hardship, or (c) by cessation of deferrals under the Plan. An application for an early payment under this Section 5.04 shall be made to the Administrative Committee in such form and in accordance with such procedures as the Administrative Committee shall determine from time to time. The determination of whether and in what amount and form a distribution will be permitted pursuant to this Section 5.04 shall be made by the Administrative Committee.

5.05 Acceleration of Payment. A Participant shall have no right to compel any accelerated payment of amounts due to a Participant. The Company may accelerate the payment of some or all of the amounts due to a Participant in a given year only in accordance with this Section and Section 409A of the Code.

(a) Domestic Relations Orders. The Administrative Committee may, in its sole and absolute discretion, accelerate the time or schedule of a payment under the Plan to an individual other than the Participant as may be necessary to fulfill a domestic relations order (as defined in Section 414(p)(1)(B) of the Code).

(b) Conflicts of Interest. The Administrative Committee may, in its sole and absolute discretion, provide for the acceleration of the time or schedule of a payment under the Plan to the extent necessary for any federal officer or employee in the executive branch to comply with an ethics agreement with the federal government. Additionally,

13

the Committee may, in its sole discretion, provide for the acceleration of the time or schedule of a payment under the Plan to the extent reasonably necessary to avoid the violation of an applicable federal, state, local, or foreign ethics law or conflicts of interest law (including where such payment is reasonably necessary to permit the Participant to participate in activities in the normal course of his or her position in which the Participant would otherwise not be able to participate under an applicable rule).

(c) Employment Taxes. The Administrative Committee may, in its sole and absolute discretion, provide for the acceleration of the time or schedule of a payment under the Plan to pay the federal Insurance Contributions Act (FICA) tax imposed under Sections 3101, 3121(a), and 3121(v)(2) of the Code, on compensation deferred under the Plan (the FICA amount). Additionally, the Administrative Committee may, in its sole discretion, provide for the acceleration of the time or schedule of a payment, to pay the income tax at source on wages imposed under Section 3401 of the Code or the corresponding withholding provisions of applicable state, local, or foreign tax laws as a result of the payment of the FICA amount, and to pay the additional income tax at source on wages attributable to the pyramiding Section 3401 of the Code wages and taxes. However, the total payment under this acceleration provision must not exceed the aggregate of the FICA amount, and the income tax withholding related to such FICA amount.

(d) Limited Cash-Outs. The Administrative Committee may, in its sole discretion, require a mandatory lump sum payment of amounts deferred under the Plan that do not exceed the applicable dollar amount under Section 402(g)(1)(B) of the Code, provided that the payment results in the termination and liquidation of the entirety of the Participant’s interest under the Plan, including all agreements, methods, programs, or other arrangements with respect to which deferrals of compensation are treated as having been deferred under a single plan under Section 409A of the Code.

(e) Payment Upon Income Inclusion Under Section 409A. The Administrative Committee may, in its sole discretion, provide for the acceleration of the time or schedule of a payment under the Plan if at any time the Plan fails to meet the requirements of Section 409A of the Code. The payment may not exceed the amount required to be included in income as a result of the failure to comply with the requirements of Section 409A of the Code.

(f) Payment of State, Local, or Foreign Taxes. The Administrative Committee may, in its sole discretion, provide for the acceleration of the time or schedule of a payment under the Plan to reflect payment of state, local, or foreign tax obligations arising from participation in the Plan that apply to an amount deferred under the Plan before the amount is paid or made available to the participant (the state, local, or foreign tax amount). Such payment may not exceed the amount of such taxes due as a result of participation in the Plan. The payment may be made in the form of withholding pursuant to provisions of applicable state, local, or foreign law or by payment directly to the Participant. Additionally, the Administrative Committee may, in its sole discretion, provide for the acceleration of the time or schedule of a payment under the Plan to pay the income tax at source on wages imposed under Section 3401 of the Code as a result of

14

such payment and to pay the additional income tax at source on wages imposed under Section 3401 of the Code attributable to such additional wages and taxes. However, the total payment under this acceleration provision must not exceed the aggregate of the state, local, and foreign tax amount, and the income tax withholding related to such state, local, and foreign tax amount.

(g) Bona Fide Disputes as to a Right to a Payment. The Compensation Committee may, in its sole discretion, provide for the acceleration of the time or schedule of a payment under the Plan where such payments occur as part of a settlement between the Participant and the Company of an arm’s length, bona fide dispute as to the Participant’s right to the deferred amount, if done in accordance with Treasury Regulation Section 1.409A-3(j)(4)(xiv).

(h) Plan Terminations and Liquidations. The Compensation Committee may, in its sole discretion, provide for the acceleration of the time or schedule of a payment under the Plan as provided in Section 8.02.

(i) Other Events and Conditions. A payment may be accelerated upon such other events and conditions as the Internal Revenue Service may prescribe in generally applicable guidance published in the Internal Revenue Bulletin.

5.06 Delay of Payment. The Company may delay a payment otherwise due hereunder to a date after the designated payment date under any of the following circumstances:

(a) Delay Due to Financial Considerations. Any payment required to be made on a date set forth under the terms of this Plan may be delayed if payment on the originally scheduled date would jeopardize the ability of the Company to continue as a going concern (in such case, payment will be made during the first taxable year after such payment no longer would have such effect).

(b) Legal Compliance. If the Company reasonably anticipates that the making of the payment will violate applicable law, provided that the payment shall be made at the earliest date at which the Company reasonably anticipates that the making of the payment will not cause such violation. (The making of a payment that would cause inclusion in gross income or the application of any penalty provision or other provision of the Code is not treated as a violation of applicable law.)

(c) Compensation Deduction. If the Company reasonably anticipates that its deduction with respect to a payment under the Plan would be limited by the application of Code Section 162(m) (in such case, payment will be made at either the earliest date at which the Company reasonably anticipates that the deduction of the payment will not be so limited or the calendar year in which the Participant experiences a Separation from Service).

(d) Other Events and Conditions. Payment may also be delayed upon such other events and conditions as the Commissioner of Internal Revenue may prescribe in generally applicable guidance published in the Internal Revenue Bulletin.

15

ARTICLE VI

BENEFICIARY DESIGNATION

6.01 Beneficiary Designation. Each Participant shall have the right, at any time, to designate any person, persons or entity as his Beneficiary or Beneficiaries. A Beneficiary designation shall be made, and may be amended, by the Participant by filing a written designation with the Administrative Committee, on such form and in accordance with such procedures as the Administrative Committee shall establish from time to time.

6.02 No Beneficiary Designation. If a Participant fails to designate a Beneficiary as provided above, or if all designated Beneficiaries predecease the Participant, then the Participant shall be deemed to have designated the surviving spouse of the Participant as the designated Beneficiary. If the Participant dies without a designated Beneficiary (or spouse as the deemed designated Beneficiary), then the Participant’s Beneficiary shall be deemed to be the Participant’s estate.

ARTICLE VII

ADMINISTRATION

7.01 Administrative Committee Duties. The Plan shall be administered by the Administrative Committee. A majority of the members of the Administrative Committee shall constitute a quorum. All resolutions or other action taken by the Administrative Committee shall be by a vote of a majority of its members present at any meeting or, without a meeting, by an instrument in writing signed by all its members. Members of the Administrative Committee may participate in a meeting of such committee by means of a conference telephone or similar communications equipment that enables all persons participating in the meeting to hear each other, and such participation in a meeting shall constitute presence in person at the meeting and waiver of notice of such meeting.

The Administrative Committee shall be responsible for the administration of this Plan and shall have all powers necessary to administer this Plan, including discretionary authority to determine eligibility for benefits and to decide claims under the terms of this Plan, except to the extent that any such powers are vested in any other person. The Administrative Committee may from time to time establish rules for the administration of this Plan, and it shall have the exclusive right to interpret this Plan and to decide any matters arising in connection with the administration and operation of this Plan. All rules, interpretations and decisions of the Administrative Committee shall be conclusive and binding on the Company, Participants and Beneficiaries.

The Administrative Committee’s responsibilities shall include, but shall not be limited to, determining in the first instance issues related to eligibility, Hypothetical Investment Benchmarks, distribution of Deferred Amounts, determination of account balances, crediting of hypothetical earnings and debiting of hypothetical losses and of distributions, in-service withdrawals, deferral elections and any other duties concerning the day-to-day operation of this Plan. The Administrative Committee may designate one of its members as a chairperson and may retain and supervise outside providers, third party administrators, record keepers and professionals (including in-house professionals) to perform any or all of the duties delegated to it hereunder.

16

Neither a member of the Board nor any member of the Administrative Committee shall be liable for any act or action hereunder, whether of omission or commission, by any other member or employee or by any agent to whom duties in connection with the administration of this Plan have been delegated or for anything done or omitted to be done in connection with this Plan. The Administrative Committee shall keep records of all of its proceedings and shall keep records of all payments made to Participants or Beneficiaries and payments made for expenses or otherwise.

Any member of the Administrative Committee who is due a benefit under the Plan shall recuse himself or herself from any Administrative Committee deliberations that concern such member’s benefits, including deliberations concerning such member’s eligibility for a benefit or his or her level of benefits. The previous sentence shall not apply to deliberations that apply to Participants generally rather than the particular member at issue.

Any expense incurred by the Company or the Administrative Committee relative to the administration of this Plan shall be paid by the Company and/or may be deducted from the Deferral Accounts of the Participants, as determined by the Administrative Committee.

7.02 Claims Procedure.

(a) Any Participant or Beneficiary (a “Claimant”) who believes that he or she is entitled to a benefit under the Plan which he or she has not received may submit a claim to the Administrative Committee. Claims for benefits under this Plan shall be made in writing, signed by the Claimant or his or her authorized representative, and must specify the basis of the Claimant’s complaint and the facts upon which he or she relies in making such claim. A claim shall be deemed filed when received by the Administrative Committee.

(b) In the event a claim for benefits is wholly or partially denied by the Committee, the Administrative Committee shall notify the Claimant in writing of the denial of the claim within a reasonable period of time, but not later than ninety (90) days after receipt of the claim, unless special circumstances require an extension of time for processing, in which case the ninety (90) day period may be extended to 180 days. The Administrative Committee shall notify the Claimant in writing of any such extension. A notice of denial shall be written in a manner reasonably calculated to be understood by the Claimant, and shall contain (i) the specific reason or reasons for denial of the claim; (ii) a specific reference to the pertinent Plan provisions upon which the denial is based; (iii) a description of any additional material or information necessary for the Claimant to perfect the claim, together with an explanation of why such material or information is necessary; and (iv) an explanation of the Plan’s review procedure.

(c) Within sixty (60) days of the receipt by the Claimant of the written notice of denial of the claim, the Claimant may appeal by filing with the Committee a written request for a full and fair review of the denial of the Claimant’s claim for benefits.

17

Appeal requests under this Plan shall be made in writing, signed by the Claimant or his or her authorized representative, and must specify the basis of the Claimant’s complaint and the facts upon which he or she relies in making such appeal. An appeal request shall be deemed filed when received by the Administrative Committee.

(d) The Administrative Committee shall render a decision on the claim appeal promptly, but not later than sixty (60) days after the receipt of the Claimant’s request for review, unless special circumstances (such as the need to hold a hearing, if necessary), require an extension of time for processing, in which case the sixty (60) day period may be extended to one hundred twenty (120) days. The Administrative Committee shall notify the Claimant in writing of any such extension. The decision upon review shall be written in a manner reasonably calculated to be understood by the Claimant, and shall contain (i) the specific reason or reasons for denial of the claim; (ii) a specific reference to the pertinent Plan provisions upon which the denial is based; (iii) a statement that the Claimant shall be provided, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the claim for benefits; and (iv) a statement of the Claimant’s right to bring an action under Section 502(a) of ERISA, if the adverse benefit determination is sustained on appeal.

(e) No lawsuit by a Claimant may be filed prior to exhausting the Plan’s administrative appeal process. Any lawsuit must be filed no later than the earlier of one year after the Claimant’s claim for benefit was denied or the date the cause of action first arose.

ARTICLE VIII

AMENDMENT AND TERMINATION OF PLAN

8.01 Amendment. The Compensation Committee of the Board, or any person(s) to whom such committee has delegated the right to amend the Plan, may at any time amend this Plan in whole or in part, provided, however, that no amendment shall be effective to decrease the balance in any Deferral Account as accrued at the time of such amendment. The Administrative Committee shall have authority to approve administrative and technical amendments that do not materially increase the cost of the Plan. All participating Companies delegate the power of Amendment to the Compensation Committee of the Board (or its designee). The Company may amend the Plan in any other manner that does not cause adverse consequences under such Code Section or other guidance from the Treasury Department or IRS, provided that no amendments shall divest otherwise vested rights of Participants, or their Beneficiaries.

8.02 Company’s Right to Terminate . The Compensation Committee may terminate the Plan (or, where allowed by Section 409A of the Code, a portion of the Plan) and accelerate any payments due (or that may become due) under the Plan under the following circumstances:

(a) Section 409A Change of Control. The Plan termination occurs pursuant to an irrevocable action of the Compensation Committee that is taken within the thirty (30) days preceding or the twelve (12) months following a Section 409A Change of Control, and all other plans sponsored by the Company that are required to be aggregated with this Plan under Section 409A of the Code are also terminated with respect to each

18

Participant therein who was employed by the Company that underwent the Section 409A Change of Control (“Change of Control Participant”). In the event of such a termination, the Accounts, together with amounts due to each Change of Control Participant under all aggregated plans, shall be paid at the time and pursuant to the schedule specified by the Compensation Committee, so long as all payments are required to be made no later than twelve (12) months after the date that the Compensation Committee or its Designee irrevocably approves the termination.

(b) Company’s Discretion. In the discretion of the Compensation Committee, provided that: (i) all arrangements sponsored by the Company that would be aggregated with the Agreement under Treasury Regulation Section 1.409A-1(c) if the same employee participated in all of the arrangements are terminated; (ii) no payments other than payments that would be payable under the terms of the arrangements if the termination had not occurred are made within 12 months of the termination of the arrangements; (iii) all payments are made within 24 months of the termination of the arrangements; and (iv) the Company does not adopt a new arrangement that under Treasury Regulation Section 1.409A-1(c) that would be aggregated with the Agreement if the same service provider participated in both arrangements, at any time within three years following the date of termination of the Agreement.

(c) Dissolution or Bankruptcy Court Order. Within 12 months of a corporate dissolution of the Company taxed under Section 331 of the Code, or with the approval of a bankruptcy court pursuant to 11 U.S.C. Section 503(b)(1)(A), provided that the amounts deferred under the Plan are included in the Participant’s gross income in the latest of (i) the calendar year in which the termination occurs, (ii) the calendar year in which the amount is no longer subject to a substantial risk of forfeiture or (iii) the first calendar year in which the payment is administratively practicable.

(d) Other. Due to such other events and conditions as the Commissioner of the IRS may prescribe in generally applicable guidance published in the Internal Revenue Bulletin.

ARTICLE IX

MISCELLANEOUS

9.01 Unfunded Plan. This Plan is intended to be an unfunded plan maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees, within the meaning of Sections 201, 301 and 401 of ERISA. All payments pursuant to the Plan shall be made from the general funds of the Company and no special or separate fund shall be established or other segregation of assets made to assure payment. No Participant or other person shall have under any circumstances any interest in any particular property or assets of the Company as a result of participating in the Plan. Notwithstanding the foregoing, the Company may (but shall not be obligated to) create one or more grantor trusts, the assets of which are subject to the claims of the Company’s creditors, to assist it in accumulating funds to pay its obligations under the Plan. Participants shall have no right to compel the investment of any amounts deposited in any such trust(s).

19

9.02 Nonassignability. Except as specifically set forth in the Plan with respect to the designation of Beneficiaries, neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate or convey in advance of actual receipt the amounts, if any, payable hereunder, or any part thereof, which are, and all rights to which are, expressly declared to be unassignable and non-transferable. No part of the amounts payable shall, prior to actual payment, be subject to seizure or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person, nor be transferable by operation of law in the event of a Participant’s or any other person’s bankruptcy or insolvency.

9.03 Validity and Severability; Code Section 409A. The invalidity or unenforceability of any provision of this Plan shall not affect the validity or enforceability of any other provision of this Plan, which shall remain in full force and effect, and any prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction. If any provision of the Plan is capable of being interpreted in more than one manner, to the extent feasible, the provision shall be interpreted in a manner that does not result in an excise tax under Code Section 409A.

9.04 Governing Law. The validity, interpretation, construction and performance of this Plan shall in all respects be governed by the laws of the State of Louisiana, without reference to principles of conflict of law, except to the extent preempted by federal law.

9.05 Employment Status. This Plan does not constitute a contract of employment or impose on the Participant or the Company any obligation for the Participant to remain an employee of the Company or change the status of the Participant’s employment or the policies of the Company and its affiliates regarding Separation from Service.

9.06 Underlying Plans and Programs. Nothing in this Plan shall prevent the Company from modifying, amending or terminating the compensation or the plans and programs pursuant to which cash awards are earned and which are deferred under this Plan.

IN WITNESS HEREOF, this Plan, as amended and restated, is hereby executed on the 30^th day of December, 2013, effective January 1, 2014, unless otherwise stated.

WITNESSES	SUPERIOR ENERGY SERVICES, INC.
/s/ Julie Castex	By:	/s/ Danny R. Young
/s/ Alan P. Bernard	Title:	Executive Vice President

20

APPENDIX A

INVESTMENT BENCHMARKS

Model Portfolio – Conservative

Model Portfolio – Moderate/Conservative

Model Portfolio – Moderate

Model Portfolio – Moderate/Aggressive

Model Portfolio – Aggressive

Nationwide VIT Money Market V

PIMCO VIT Total Return Admin

PIMCO VIT Real Return Admin

MFS VIT Value Svc

Dreyfus Stock Index Initial

American Funds IS Growth 2

JPMorgan IT Mid Cap Value 1

Morgan Stanley UIF Mid Cap Growth I

Royce Capital Small Cap

Vanguard VIF Small Company Growth Inv

American Funds IS International 2

MFS VIT II International Value Svc

Invesco VIF Global Real Estate I

A-1

APPENDIX B

ADMINISTRATIVE COMMITTEE

The members of the Plan’s Administrative Committee are as follows:

Donna Cummins

Colleen Hayman

Jennifer Phan

Wayne Robertson

Tom White

Danny Young

B-1

EX-10.8

Exhibit 10.8

AMENDMENT NO. 2

TO THE

SUPERIOR ENERGY SERVICES, INC.

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

WHEREAS, Superior Energy Services, Inc. (“Superior”) adopted the Superior Energy Services, Inc. Supplemental Executive Retirement Plan (the “Plan”), effective January 1, 2008;

WHEREAS, Section 9.01 of the Plan states that the Compensation Committee of Superior’s Board of Directors (“Compensation Committee”) may amend the Plan;

WHEREAS, at its meeting on March 3, 2010, the Compensation Committee approved an amendment to the Plan eliminating the requirement that the Compensation Committee annually approve the interest rate applied to Plan accounts, and the Compensation Committee authorized any executive officer of Superior to execute such amendment;

WHEREAS, at its meeting on May 21, 2010, the Compensation Committee declared a discretionary contribution to the Plan account for Mr. Kenneth L. Blanchard, and pursuant to Section 4.02 of the Plan, such declaration is part of the Plan document and shall be memorialized on Appendix C to the Plan;

WHEREAS, at its meeting on December 10, 2010, the Board of Directors of Superior adopted resolutions delegating to the SERP Administrative Committee the authority to adopt administrative and technical amendments to the Plan that do not materially increase the cost of the Plan; and

WHEREAS, the SERP Administrative Committee wishes to revise timing for the determination of the SERP earnings rate that applies for a given Plan Year;

NOW THEREFORE, the Plan is amended as follows, as of the dates set forth below:

I.

Section 5.02 of the Plan, Earnings Allocations, is amended and restated effective March 3, 2010, as follows:

5.02 Earnings Allocation. At the end of each Plan Year, each Participant’s Accounts will be adjusted to reflect earnings on the average daily balance of the Accounts during the Plan Year at a rate established on an annual basis by the Administrative Committee in accordance with this Section 5.02. The earnings rate established by the Administrative Committee shall be commensurate with Superior’s after-tax, long-term borrowing rate and may be applied retroactively or prospectively (e.g. made applicable to the prior, current, or subsequent Plan Year). Earnings shall be credited only on Accounts that are on the books of the Company at the end of the Plan Year. However, Accounts or portions of Accounts

1

that are distributed during a Plan Year will be credited with earnings from the beginning of the Plan Year through the day immediately preceding the distribution, at the earnings rate applicable to the preceding Plan Year. Effective January 1, 2011, if the earnings rate for the Plan Year during which a distribution is made has been set by the Administrative Committee, then such rate shall apply to determine the earnings credited on the portion that is distributed; otherwise, if the earnings rate for such Plan Year has not yet been established, then the earnings rate applicable to the previous Plan Year shall apply to determine the earnings on the portion that is distributed.

II.

Appendix C to the Plan, Discretionary Contributions, is amended effective May 21, 2010 to memorialize changes to the Plan made by the Compensation Committee, by adding a new paragraph to read as follows:

President & COO Contribution. In addition to the amounts credited to his Account in accordance with Section 4.01 of the Plan, Kenneth L. Blanchard shall receive a fully vested contribution in the amount of $4,675,000, on the earliest of: (i) the date of Mr. Blanchard’s voluntary resignation as President and Chief Operating Officer of the Company in December 2010; (ii) his becoming disabled; or (iii) his death. Such contribution shall be governed by the terms of the Plan, including but not limited to the time and manner of payment provisions of Section 7.02 of the Plan.

IN WITNESS WHEREOF, this Amendment No. Two to the Plan is executed on the     day of                     , 2011.

WITNESSES:	SUPERIOR ENERGY SERVICES, INC.
	By:
	Name:
	Title:

2

EX-10.19

Exhibit 10.19

Form for 2014 Awards

RESTRICTED STOCK AGREEMENT

This RESTRICTED STOCK AGREEMENT (this “Agreement”), executed by the parties on the dates indicated on the signature page, is by and between Superior Energy Services, Inc. (“Superior”) and <<Participant Name>> (the “Award Recipient”).

WHEREAS, Superior maintains the 2013 Stock Incentive Plan (the “Plan”), under which the Compensation Committee of the Board of Directors of Superior (the “Committee”) may, directly or indirectly, among other things, grant restricted shares of Superior’s common stock, $.001 par value per share (the “Common Stock”), to key employees of Superior or its subsidiaries (collectively, the “Company”); and

WHEREAS, pursuant to the Plan the Committee has awarded to the Award Recipient restricted shares of Common Stock on the terms and conditions specified below;

NOW, THEREFORE, the parties agree as follows:

1.

AWARD OF SHARES

On January 15, 2014 (the “Date of Grant”), and upon the terms and conditions of the Plan and this Agreement, and in consideration of services rendered, Superior awarded to the Award Recipient <<Awards Granted>> restricted shares of Common Stock (the “Restricted Stock”), that vest, subject to Sections 2, 3 and 4 hereof, in annual installments (disregarding any fractional share) as follows:

Scheduled Vesting Date	Amount of Restricted Stock To Vest
January 15, 2015	33%
January 15, 2016	33%
January 15, 2017	Remaining balance

2.

AWARD RESTRICTIONS ON

RESTRICTED STOCK

2.1 In addition to the conditions and restrictions provided in the Plan, neither the shares of Restricted Stock nor the right to vote the Restricted Stock, to receive accrued dividends and other distributions thereon or to enjoy any other rights or interests thereunder or hereunder may be sold, assigned, donated, transferred, exchanged, pledged, hypothecated or otherwise encumbered prior to vesting. All dividends and other distributions relating to the Restricted Stock will accrue when declared and be paid to the Award Recipient only upon the vesting of the related Restricted Stock. Except as otherwise provided in this Section 2.1, the Award Recipient shall be entitled to all rights of a shareholder of Superior with respect to the Restricted Stock, including the right to vote the shares.

2.2 If the shares of Restricted Stock have not already vested in accordance with Section 1 above, the shares of Restricted Stock shall vest and all restrictions set forth in Section 2.1 shall lapse on the earlier of: (a) the date on which the employment of the Award Recipient terminates as a result of any of the events specified in Sections 3(a) or (b) below, (b) if permitted by the Committee in accordance with Section 3 below, retirement or termination by the Company, or (c) the occurrence of a Change of Control (as defined in the Plan).

3.

TERMINATION OF EMPLOYMENT

If the Award Recipient’s employment terminates as the result of (a) death or (b) disability (within the meaning of Section 22(e)(3) of the Internal Revenue Code of 1986, as amended (the “Code”)), all unvested shares of Restricted Stock granted hereunder shall immediately vest. Unless the Committee determines otherwise in the case of retirement of the Award Recipient or termination by the Company of the Award Recipient’s employment, termination of employment for any other reason, except termination upon a Change of Control (as defined in the Plan), shall automatically result in the termination and forfeiture of all unvested Restricted Stock and any accrued dividends or other distributions related to such shares.

4.

FORFEITURE OF AWARD

4.1 If the Award Recipient engages in grossly negligent conduct or intentional misconduct that either (i) requires the Company’s financial statements to be restated at any time beginning on the Date of Grant and ending on the third anniversary of the end of the final vesting date set forth in Section 1 or (ii) results in an increase of the value of the Restricted Stock upon vesting, then the Committee, after considering the costs and benefits to the Company of doing so, may seek recovery for the benefit of the Company of the difference between the shares of Common Stock received upon vesting during the three-year period following such conduct and the shares of Common Stock that would have been received based on the restated financial statements or absent the increase described in part (ii) above (the “Excess Shares”). All determinations regarding the amount of the Excess Shares shall be made solely by the Committee in good faith.

4.2 The shares of Restricted Stock granted hereunder are also subject to any clawback policies the Company may adopt in order to conform to the requirements of Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act and any resulting rules issued by the SEC or national securities exchanges thereunder.

4.3 If the Committee determines that the Award Recipient owes any amount to the Company under Sections 4.1 or 4.2 above, the Award Recipient shall return to the Company the Excess Shares (or the shares recoverable under Section 4.2) acquired by the Award Recipient pursuant to this Agreement (or other securities into which such shares have been converted or exchanged) or, if no longer held by the Award Recipient, the Award Recipient shall pay to the Company, without interest, all cash, securities or other assets received by the Award Recipient upon the sale or transfer of such shares. The Award Recipient acknowledges that the Company may, to the fullest extent permitted by applicable law, deduct such amount owed from any

2

amounts the Company owes the Award Recipient from time to time for any reason (including without limitation amounts owed to the Award Recipient as salary, wages, reimbursements or other compensation, fringe benefits, retirement benefits or vacation pay). Whether or not the Company elects to make any such set-off in whole or in part, if the Company does not recover by means of set-off the full amount the Award Recipient owes it, the Award Recipient hereby agrees to pay immediately the unpaid balance to the Company.

5.

ESCROW

5.1 The shares of Restricted Stock will generally be represented in book or electronic entry rather than a physical certificate, and Superior shall take steps necessary to restrict transfer of the Restricted Stock as it deems necessary or advisable until the lapse of restrictions under the terms hereof. In the event a stock certificates evidencing the Restricted Stock is issued, the certificate shall be retained by Superior until the lapse of restrictions under the terms hereof, and Superior shall place a legend, in the form specified in the Plan, on such stock certificate restricting the transferability of the shares of Restricted Stock.

5.2 Upon the lapse of the restrictions on shares of Restricted Stock, Superior will credit the Award Recipient’s brokerage account with the vested shares of Restricted Stock and any accrued dividends and distributions related to such shares of Restricted Stock. If the Award Recipient has not established a brokerage account, the shares and any accrued dividends and distributions due will be held by Superior’s transfer agent until such time as the Award Recipient opens such an account.

6.

WITHHOLDING TAXES; SECTION 409A

6.1 At the time that all or any portion of the Restricted Stock vests, the Award Recipient must deliver to Superior the amount of income tax withholding required by law. In accordance with and subject to the terms of the Plan, the Award Recipient may satisfy the tax withholding obligation in whole or in part by delivering currently owned shares of Common Stock or by electing to have Superior withhold from the shares the Award Recipient otherwise would receive hereunder shares of Common Stock having a value equal to the minimum amount required to be withheld (as determined under the Plan).

6.2 It is intended that the payments and benefits provided under this Agreement will comply with the requirements of Section 409A of the Internal Revenue Code and any related implementing regulations or guidance (“Section 409A”) or an exemption therefrom. This Agreement shall be interpreted, construed, administered, and governed in a manner that effects such intent. No acceleration of the vesting and payment of any accrued dividends and distributions shall be permitted unless permitted under Section 409A.

7.

ADDITIONAL CONDITIONS

Anything in this Agreement to the contrary notwithstanding, if at any time Superior further determines, in its sole discretion, that the listing, registration or qualification (or any

3

updating of any such document) of the shares of Common Stock issuable pursuant hereto is necessary on any securities exchange or under any federal or state securities or blue sky law, or that the consent or approval of any governmental regulatory body is necessary or desirable as a condition of, or in connection with the issuance of shares of Common Stock pursuant thereto, or the removal of any restrictions imposed on such shares, such shares of Common Stock shall not be issued, in whole or in part, or the restrictions thereon removed, unless such listing, registration, qualification, consent or approval shall have been effected or obtained free of any conditions not acceptable to Superior. Superior agrees to use commercially reasonable efforts to issue all shares of Common Stock issuable hereunder on the terms provided herein.

8.

NO CONTRACT OF EMPLOYMENT INTENDED

Nothing in this Agreement shall confer upon the Award Recipient any right to continue in the employment of the Company, or to interfere in any way with the right of the Company to terminate the Award Recipient’s employment relationship with the Company at any time.

9.

BINDING EFFECT

This Agreement may not be transferred, assigned pledged or hypothecated in any manner or law or otherwise, other than by will or by the laws of descent and distribution, and shall not be subject to execution, attachment or similar process. This Agreement shall inure to the benefit of and be binding upon the parties hereto and their respective heirs, executors, administrators, legal representatives and permitted successors. Without limiting the generality of the foregoing, whenever the term “Award Recipient” is used in any provision of this Agreement under circumstances where the provision appropriately applies to the heirs, executors, administrators or legal representatives to whom this award may be transferred by will or by the laws of descent and distribution, the term “Award Recipient” shall be deemed to include such person or persons.

10.

INCONSISTENT PROVISIONS

The shares of Restricted Stock granted hereby are subject to the terms, conditions, restrictions and other provisions of the Plan as fully as if all such provisions were set forth in their entirety in this Agreement. If any provision of this Agreement conflicts with a provision of the Plan, the Plan provision shall control. The Award Recipient acknowledges that a copy of the Plan and a prospectus summarizing the Plan was distributed or made available to the Award Recipient and that the Award Recipient was advised to review such materials prior to entering into this Agreement. The Award Recipient waives the right to claim that the provisions of the Plan are not binding upon the Award Recipient and the Award Recipient’s heirs, executors, administrators, legal representatives and successors.

11.

GOVERNING LAW

This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware. For purposes of litigating any dispute that arises directly or indirectly from

4

the relationship of the parties evidenced by the grant of the Restricted Stock or this Agreement, the parties hereby submit to and consent to the exclusive jurisdiction of the courts of Harris County, Texas, or the federal courts for the United States for the Southern District of Texas, and no other courts, where this grant is made and/or to be performed.

12.

SEVERABILITY

If any term or provision of this Agreement, or the application thereof to any person or circumstance, shall at any time or to any extent be invalid, illegal or unenforceable in any respect as written, the Award Recipient and Superior intend for any court construing this Agreement to modify or limit such provision so as to render it valid and enforceable to the fullest extent allowed by law. Any such provision that is not susceptible of such reformation shall be ignored so as to not affect any other term or provision hereof, and the remainder of this Agreement, or the application of such term or provision to persons or circumstances other than those as to which it is held invalid, illegal or unenforceable, shall not be affected thereby and each term and provision of this Agreement shall be valid and enforced to the fullest extent permitted by law.

13.

ENTIRE AGREEMENT; MODIFICATION; WAIVER

The Plan and this Agreement contain the entire agreement between the parties with respect to the subject matter contained herein and may not be modified, except as provided in the Plan, as it may be amended from time to time in the manner provided therein, or in this Agreement, as it may be amended from time to time by a written document signed by each of the parties hereto. Any oral or written agreements, representations, warranties, written inducements, or other communications with respect to the subject matter contained herein made prior to the execution of the Agreement shall be void and ineffective for all purposes. The Award Recipient acknowledges that a waiver by Superior of a breach of any provision of this Agreement shall not operate or be construed as a waiver of any other provision of this Agreement, or of any subsequent breach by the Award Recipient or any other Plan participant.

14.

ELECTRONIC DELIVERY; ACCEPTANCE OF AGREEMENT

14.1 Superior may, in its sole discretion, deliver any documents related to the Award Recipient’s current or future participation in the Plan by electronic means or request the Award Recipient’s consent to participate in the Plan by electronic means. By accepting the terms of this Agreement, the Award Recipient hereby consents to receive such documents by electronic delivery and agree to participate in the Plan through an on-line or electronic system established and maintained by Superior or a third party designated by Superior.

14.2 The Award Recipient must expressly accept the terms and conditions of this Agreement by electronically accepting this Agreement in a timely manner. If the Award Recipient does not accept the terms of this Agreement, this award of Restricted Stock is subject to cancellation.

* * * * * * * * * * * * *

5

By clicking the “Accept” button, the Award Recipient represents that he or she is familiar with the terms and provisions of the Plan, and hereby accepts this Agreement subject to all of the terms and provisions thereof. The Award Recipient has reviewed the Plan and this Agreement in their entirety and fully understands all provisions of this Agreement. The Award Recipient agrees to accept as binding, conclusive and final all decisions or interpretations of the Committee upon any questions arising under the Plan or this Agreement.

PLEASE PRINT AND KEEP A COPY FOR YOUR RECORDS

6

EX-10.20

Exhibit 10.20

Form for 2014 Awards

RESTRICTED STOCK UNIT AGREEMENT

This RESTRICTED STOCK UNIT AGREEMENT (this “Agreement”) is by and between Superior Energy Services, Inc. (“Superior”) and <<Participant Name>> (the “Award Recipient”).

WHEREAS, Superior maintains the 2013 Stock Incentive Plan (the “Plan”), under which the Compensation Committee of the Board of Directors of Superior (the “Committee”) may, directly or indirectly, among other things, grant restricted stock units payable in shares of Superior’s common stock, $.001 par value per share (the “Common Stock”), to key employees of Superior or its subsidiaries (collectively, the “Company”); and

WHEREAS, pursuant to the Plan the Committee has awarded to the Award Recipient restricted stock units on the terms and conditions specified below;

NOW, THEREFORE, the parties agree as follows:

1.

AWARD OF RESTRICTED STOCK UNITS

1.1 On January 15, 2014 (the “Date of Grant”), and upon the terms and conditions of the Plan and this Agreement, and in consideration of services rendered, Superior awarded to the Award Recipient <<Awards Granted>> restricted stock units (the “RSUs”), that vest, subject to Sections 2 and 4 hereof, in annual installments (disregarding any fractional share) as follows:

Scheduled Vesting Date	Amount of RSUs To Vest
January 15, 2015	33%
January 15, 2016	33%
January 15, 2017	Remaining balance

2.

TERMS OF

RESTRICTED STOCK UNITS

2.1 Each RSU represents the right to receive from Superior, upon vesting, one share of Common Stock, free of any restrictions, and all Related Credits credited to the Award Recipient’s Dividend Equivalent Account (as such terms are defined in Section 3.1) with respect to such RSU.

2.2 Neither the RSUs nor the right to receive dividend equivalents thereon may be sold, assigned, donated, transferred, exchanged, pledged, hypothecated or otherwise encumbered. The Award Recipient shall have no rights, including but not limited to, voting and dividend rights, in the shares of Common Stock underlying the RSUs unless and until such shares are issued to the Award Recipient, or as otherwise provided in this Agreement.

2.3 If the RSUs have not already vested in accordance with Section 1 above, the RSUs shall vest on the earlier of: (a) the date on which the employment of the Award Recipient terminates as the result of death or disability (within the meaning of Section 22(e)(3) of the Internal Revenue Code of 1986, as amended (the “Code”)), (b) if permitted by the Committee and subject to any additional restrictions the Committee may impose, retirement or termination by the Company, or (c) the occurrence of a Change of Control (as defined in the Plan). Unless the Committee determines otherwise in the case of retirement of the Award Recipient or termination by the Company of the Award Recipient’s employment, termination of employment for any other reason, except termination upon a Change of Control, shall automatically result in the termination and forfeiture of all unvested RSUs.

3.

DIVIDEND EQUIVALENTS; ISSUANCE OF SHARES UPON VESTING

3.1 From and after the Date of Grant of an RSU until the issuance of the share of Common Stock payable in respect of such RSU, the Award Recipient shall be credited, as of the payment date therefor, with (a) the amount of any cash dividends and (b) the amount equal to the Fair Market Value of any shares of Common Stock, securities, or other property distributed or distributable in respect of one share of Common Stock to which the Award Recipient would have been entitled had the Award Recipient been a record holder of one share of Common Stock for each RSU at all times from the Date of Grant of such RSU to such issuance date (collectively, the “Related Credits”). All such Related Credits shall be made notionally to a dividend equivalent account (a “Dividend Equivalent Account”) established for the Award Recipient with respect to all RSUs granted on the same date. All such Related Credits shall vest or be forfeited at the same time and on the same terms as the RSUs to which they relate.

3.2 As soon as practicable after the vesting of the RSUs, but no later than 30 days from such date, Superior will credit the Award Recipient’s brokerage account with the shares of Common Stock and the cash value of any Related Credits applicable to such RSUs. If the RSUs have vested in connection with a Change of Control under Section 2.3, and the event constituting the Change of Control does not qualify as a change in the ownership of the Company, a change in the effective control of the Company or a change in the ownership of a substantial portion of the assets of the Company under Section 409A of the Internal Revenue Code and any related implementing regulations or guidance (“Section 409A”), then settlement of the RSUs and distribution of the shares of Common Stock or other property and any Related Credits shall be delayed until the applicable vesting date set forth in Section 1 or such earlier time as settlement would be permissible under Section 409A. If the Award Recipient has not established a brokerage account, the shares and any cash payment due will be held by Superior’s transfer agent until such time as the Award Recipient opens an account.

3.3 Upon issuance of such shares of Common Stock, the Award Recipient is free to hold or dispose of such shares, subject to applicable securities laws and any internal Company policy then in effect and applicable to the Award Recipient, such as Superior’s Insider Trading Policy and Executive Stock Ownership Guidelines.

2

4.

FORFEITURE OF AWARD

4.1 If the Award Recipient engages in grossly negligent conduct or intentional misconduct that either (i) requires the Company’s financial statements to be restated at any time beginning on the Date of Grant and ending on the third anniversary of the end of the final vesting date set forth in Section 1 or (ii) results in an increase of the value of the RSUs upon vesting, then the Committee, after considering the costs and benefits to the Company of doing so, may seek recovery for the benefit of the Company of the difference between the shares of Common Stock received upon vesting during the three-year period following such conduct and the shares of Common Stock that would have been received based on the restated financial statements or absent the increase described in part (ii) above (the “Excess Shares”). All determinations regarding the amount of the Excess Shares shall be made solely by the Committee in good faith.

4.2 The RSUs granted hereunder are also subject to any clawback policies the Company may adopt in order to conform to the requirements of Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act and any resulting rules issued by the SEC or national securities exchanges thereunder.

4.3 If the Committee determines that the Award Recipient owes any amount to the Company under Sections 4.1 or 4.2 above, the Award Recipient shall return to the Company the Excess Shares (or the shares recoverable under Section 4.2) acquired by the Award Recipient pursuant to this Agreement (or other securities into which such shares have been converted or exchanged) or, if no longer held by the Award Recipient, the Award Recipient shall pay to the Company, without interest, all cash, securities or other assets received by the Award Recipient upon the sale or transfer of such shares. The Award Recipient acknowledges that the Company may, to the fullest extent permitted by applicable law, deduct such amount owed from any amounts the Company owes the Award Recipient from time to time for any reason (including without limitation amounts owed to the Award Recipient as salary, wages, reimbursements or other compensation, fringe benefits, retirement benefits or vacation pay). Whether or not the Company elects to make any such set-off in whole or in part, if the Company does not recover by means of set-off the full amount the Award Recipient owes it, the Award Recipient hereby agrees to pay immediately the unpaid balance to the Company.

5.

WITHHOLDING TAXES; SECTION 409A

5.1 At the time that all or any portion of the RSUs vest, the Award Recipient must deliver to Superior the amount of income tax withholding required by law. In accordance with and subject to the terms of the Plan, the Award Recipient may satisfy the tax withholding obligation in whole or in part by delivering currently owned shares of Common Stock or by electing to have Superior withhold from the shares the Award Recipient otherwise would receive upon vesting of the RSUs shares of Common Stock having a Fair Market Value equal to the minimum amount required to be withheld (as determined under the Plan).

5.2 It is intended that the payments and benefits provided under this Agreement will comply with the requirements of Section 409A or an exemption therefrom. This Agreement shall be interpreted, construed, administered, and governed in a manner that effects such intent. No acceleration of the settlement of RSUs shall be permitted unless permitted under Section 409A.

3

6.

ADDITIONAL CONDITIONS

Anything in this Agreement to the contrary notwithstanding, if at any time Superior further determines, in its sole discretion, that the listing, registration or qualification (or any updating of any such document) of the shares of Common Stock issuable pursuant hereto is necessary on any securities exchange or under any federal or state securities or blue sky law, or that the consent or approval of any governmental regulatory body is necessary or desirable as a condition of, or in connection with the issuance of shares of Common Stock pursuant hereto, such shares of Common Stock shall not be issued, in whole or in part, or the restrictions thereon removed, unless such listing, registration, qualification, consent or approval shall have been effected or obtained free of any conditions not acceptable to Superior. Superior agrees to use commercially reasonable efforts to issue all shares of Common Stock issuable hereunder on the terms provided herein.

7.

NO CONTRACT OF EMPLOYMENT INTENDED

Nothing in this Agreement shall confer upon the Award Recipient any right to continue in the employment of the Company, or to interfere in any way with the right of the Company to terminate the Award Recipient’s employment relationship with the Company at any time.

8.

BINDING EFFECT

This Agreement may not be transferred, assigned pledged or hypothecated in any manner or law or otherwise, other than by will or by the laws of descent and distribution, and shall not be subject to execution, attachment or similar process. This Agreement shall inure to the benefit of and be binding upon the parties hereto and their respective heirs, executors, administrators, legal representatives and permitted successors. Without limiting the generality of the foregoing, whenever the term “Award Recipient” is used in any provision of this Agreement under circumstances where the provision appropriately applies to the heirs, executors, administrators or legal representatives to whom this award may be transferred by will or by the laws of descent and distribution, the term “Award Recipient” shall be deemed to include such person or persons.

9.

INCONSISTENT PROVISIONS

The RSUs granted hereby are subject to the terms, conditions, restrictions and other provisions of the Plan as fully as if all such provisions were set forth in their entirety in this Agreement. If any provision of this Agreement conflicts with a provision of the Plan, the Plan provision shall control. The Award Recipient acknowledges that a copy of the Plan and a prospectus summarizing the Plan was distributed or made available to the Award Recipient and that the Award Recipient was advised to review such materials prior to entering into this Agreement. The Award Recipient waives the right to claim that the provisions of the Plan are not binding upon the Award Recipient and the Award Recipient’s heirs, executors, administrators, legal representatives and successors.

4

10.

GOVERNING LAW

This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware. For purposes of litigating any dispute that arises directly or indirectly from the relationship of the parties evidenced by the grant of RSUs or this Agreement, the parties hereby submit to and consent to the exclusive jurisdiction of the courts of Harris County, Texas, or the federal courts for the United States for the Southern District of Texas, and no other courts, where this grant is made and/or to be performed.

11.

SEVERABILITY

If any term or provision of this Agreement, or the application thereof to any person or circumstance, shall at any time or to any extent be invalid, illegal or unenforceable in any respect as written, the Award Recipient and Superior intend for any court construing this Agreement to modify or limit such provision so as to render it valid and enforceable to the fullest extent allowed by law. Any such provision that is not susceptible of such reformation shall be ignored so as to not affect any other term or provision hereof, and the remainder of this Agreement, or the application of such term or provision to persons or circumstances other than those as to which it is held invalid, illegal or unenforceable, shall not be affected thereby and each term and provision of this Agreement shall be valid and enforced to the fullest extent permitted by law.

12.

ENTIRE AGREEMENT; MODIFICATION; WAIVER

The Plan and this Agreement contain the entire agreement between the parties with respect to the subject matter contained herein and may not be modified, except as provided in the Plan, as it may be amended from time to time in the manner provided therein, or in this Agreement, as it may be amended from time to time by a written document signed by each of the parties hereto. Any oral or written agreements, representations, warranties, written inducements, or other communications with respect to the subject matter contained herein made prior to the execution of the Agreement shall be void and ineffective for all purposes. The Award Recipient acknowledges that a waiver by Superior of breach of any provision of this Agreement shall not operate or be construed as a waiver of any other provision of this Agreement, or of any subsequent breach by the Award Recipient or any other Plan participant.

13.

ELECTRONIC DELIVERY; ACCEPTANCE OF AGREEMENT

13.1 Superior may, in its sole discretion, deliver any documents related to the Award Recipient’s current or future participation in the Plan by electronic means or request the Award Recipient’s consent to participate in the Plan by electronic means. By accepting the terms of this Agreement, the Award Recipient hereby consents to receive such documents by electronic delivery and agrees to participate in the Plan through an on-line or electronic system established and maintained by Superior or a third party designated by Superior.

5

13.2 The Award Recipient must expressly accept the terms and conditions of this Agreement by electronically accepting this Agreement in a timely manner. If the Award Recipient does not accept the terms of this Agreement, this award of RSUs is subject to cancellation.

* * * * * * * * * * * * *

By clicking the “Accept” button, the Award Recipient represents that he or she is familiar with the terms and provisions of the Plan, and hereby accepts this Agreement subject to all of the terms and provisions thereof. The Award Recipient has reviewed the Plan and this Agreement in their entirety and fully understands all provisions of this Agreement. The Award Recipient agrees to accept as binding, conclusive and final all decisions or interpretations of the Committee upon any questions arising under the Plan or this Agreement.

PLEASE PRINT AND KEEP A COPY FOR YOUR RECORDS

6

EX-10.21

Exhibit 10.21

Form for 2014 Awards

STOCK OPTION AGREEMENT

THIS AGREEMENT is by and between Superior Energy Services, Inc. (“Superior”), and <<Participant Name>> (“Optionee”).

WHEREAS Optionee is a key employee of Superior or one of its subsidiaries (collectively, the “Company”) and Superior considers it desirable and in its best interest that Optionee be given an inducement to acquire a proprietary interest in the Company and an added incentive to advance the interests of the Company by possessing an option to purchase shares of the common stock of Superior, $.001 par value per share (the “Common Stock”), in accordance with the 2013 Stock Incentive Plan (the “Plan”).

NOW, THEREFORE, in consideration of the premises, it is agreed by and between the parties as follows:

1.

GRANT OF OPTION

On <<Grant Date>> (the “Date of Grant”), Superior granted to Optionee the right, privilege and option to purchase <<Awards Granted>> shares of Common Stock (the “Option”) at an exercise price of $             per share (the “Exercise Price”). The Option shall be exercisable at the time specified in Section 2 below. The Option is a non-qualified stock option and shall not be treated as an incentive stock option under Section 422 of the Internal Revenue Code of 1986, as amended (the “Code”).

2.

TIME OF EXERCISE

2.1 Subject to the provisions of the Plan and the other provisions of this Agreement, the Option shall vest in annual installments (disregarding any fractional shares) as follows:

Scheduled Vesting Date	Amount of Shares To Vest
January 15, 2015	33%
January 15, 2016	33%
January 15, 2017	Remaining balance

The Option shall expire and may not be exercised later than the tenth anniversary of the Date of Grant.

2.2 Except as otherwise provided herein, upon the termination of Optionee’s employment with the Company, any portion of the Option that has not yet become exercisable shall terminate immediately. If (a) Optionee’s employment by the Company is terminated because of death or disability (within the meaning of Section 22(e)(3) of the Code), or (b) if there has been a Change of Control (as defined in the Plan), then any portion of the Option that has not yet vested shall become immediately exercisable on the date of such termination of employment or Change of Control. If Optionee’s employment by the Company is terminated because of (a)

Optionee’s retirement on or after reaching age 55 with five years of service, or (b) the Company’s termination of Optionee’s employment without Cause (as defined below), then, if approved by the Compensation Committee of the Board of Directors of Superior, any portion of the Option that has not yet vested shall become immediately exercisable on the date of such termination of employment.

2.3 If Optionee’s employment by the Company is terminated for Cause, the Option shall terminate in full immediately, whether or not exercisable at the time of termination of employment. “Cause” for termination of employment shall be deemed to exist upon either (a) a final determination is made in accordance with the terms of Optionee’s employment agreement, if any, with the Company that Optionee’s employment has been terminated for “cause” within the meaning of the employment agreement or (b), if Optionee is not subject to an employment agreement: (i) failure to abide by the Company’s rules and regulations governing the transaction of its business, including without limitation, its Code of Business Ethics and Conduct; (ii) inattention to duties, or the commission of acts within employment with the Company amounting to negligence or misconduct; (iii) misappropriation of funds or property of the Company or committing any fraud against the Company or against any other person or entity in the course of employment with the Company; (iv) misappropriation of any corporate opportunity, or otherwise obtaining personal profit from any transaction which is adverse to the interests of the Company or to the benefits of which the Company is entitled; or (v) the commission of a felony or other crime involving moral turpitude.

2.4 Except as provided in Sections 2.5 and 2.6, if Optionee’s employment with the Company is terminated, the Option must be exercised, to the extent exercisable at the time of termination of employment, within 30 days of the date on which Optionee ceases to be an employee, but in no event later than the tenth anniversary of the Date of Grant.

2.5 If Optionee’s employment by the Company is terminated because of (a) death, (b) disability (within the meaning of Section 22(e)(3) of the Code) or (c) retirement on or after reaching age 55 with five years of service, the Option must be exercised, to the extent exercisable at the time of termination of employment, on or before the tenth anniversary of the Date of Grant. In the event of Optionee’s death, the Option may, to the extent exercisable at the time of death, be exercised by his estate, or by the person to whom such right devolves from him by reason of his death. If Optionee’s employment is terminated by the Company other than for Cause, then the Option must be exercised, to the extent exercisable at the time of termination of employment, within five years following the date of termination of employment, but in no event later than the tenth anniversary of the Date of Grant.

2.6 If there has been a Change of Control (as defined in the Plan) of Superior, (a) if the Option remains outstanding after the Change of Control, either as a right to purchase Common Stock or as a right to purchase that number and class of shares of stock or other securities or property (including without limitation, cash) to which Optionee would have been entitled if, immediately prior to the Change of Control, Optionee had been the record owner of the number of shares of Common Stock then covered by the Option and (b) if Optionee’s employment is terminated by the Company other than for Cause within a one-year period following the Change of Control, then the Option must be exercised within five years following the date of termination of employment, but in no event later than the tenth anniversary of the Date of Grant.

2

3.

FORFEITURE OF OPTION GAIN

3.1 If the Optionee engages in grossly negligent conduct or intentional misconduct that either (i) requires the Company’s financial statements to be restated at any time beginning on the Date of Grant and ending on the third anniversary of the end of the final vesting date set forth in Section 1 or (ii) results in an increase of the value of the Options upon exercise, then the Committee, after considering the costs and benefits to the Company of doing so, may seek recovery for the benefit of the Company of the difference between the shares of Common Stock received upon exercise of the Options during the three-year period following such conduct and the shares of Common Stock that would have been received based on the restated financial statements or absent the increase described in part (ii) above (the “Excess Shares”). All determinations regarding the amount of the Excess Shares shall be made solely by the Committee in good faith.

3.2 The Options granted hereunder are also subject to any clawback policies the Company may adopt in order to conform to the requirements of Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act and any resulting rules issued by the SEC or national securities exchanges thereunder.

3.3 If the Committee determines that Optionee owes any amount to the Company under Sections 3.1 or 3.2 above, Optionee shall return to the Company the Excess Shares (or the shares recoverable under Section 3.2) acquired by Optionee pursuant to this Agreement (or other securities into which such shares have been converted or exchanged) or, if no longer held by Optionee, Optionee shall pay to the Company, without interest, all cash, securities or other assets received by Optionee upon the sale or transfer of such shares. Optionee acknowledges that the Company may, to the fullest extent permitted by applicable law, deduct such amount owed from any amounts the Company owes Optionee from time to time for any reason (including without limitation amounts owed to Optionee as salary, wages, reimbursements or other compensation, fringe benefits, retirement benefits or vacation pay). Whether or not the Company elects to make any such set-off in whole or in part, if the Company does not recover by means of set-off the full amount Optionee owes it, Optionee hereby agrees to pay immediately the unpaid balance to the Company.

4.

METHOD OF EXERCISE OF OPTION

Optionee may exercise all or a portion of the Option by contacting Merrill Lynch, the Company’s third party administrator, or any successor administrator, in accordance with the procedures established by Superior. Optionee shall specify the number of shares to be purchased and must pay the total Exercise Price of the shares, which may be accomplished in any manner set forth in the Plan or approved by Superior. Once Superior or its delegee has received the Exercise Price for the shares, the appropriate officer of Superior shall cause the transfer of title of the shares purchased to Optionee on Superior’s stock records and cause such shares to be issued in Optionee’s name or to an account in Optionee’s name with his brokerage firm. Optionee shall not have any rights as a stockholder until such shares are issued to him.

3

5.

NO CONTRACT OF EMPLOYMENT INTENDED

Nothing in this Agreement shall confer upon Optionee any right to continue in the employ of the Company, or to interfere in any way with the right of the Company to terminate Optionee’s employment relationship with the Company at any time.

6.

NON-TRANSFERABILITY, BINDING EFFECT AND SUCCESSORS

6.1 The Option may not be transferred, assigned, pledged or hypothecated in any manner, by operation of law or otherwise, other than by will or by the laws of descent and distribution, and shall not be subject to execution, attachment or similar process. This Agreement shall inure to the benefit of and be binding upon the parties hereto and their respective heirs, executors and administrators and permitted successors.

6.2 If in connection with a Change of Control, the Option is assumed by a successor to the Company, then, as used herein, “Company” shall include any successor to the Company’s business and assets that assumes and agrees to perform this Agreement.

7.

INCONSISTENT PROVISIONS

The Option is subject to the provisions of the Plan as in effect on the date hereof and as it may be amended. In the event any provision of this Agreement conflicts with such a provision of the Plan, the Plan provision shall control.

8.

GOVERNING LAW

This Agreement shall be governed and construed in accordance with the laws of the State of Delaware. For purposes of litigating any dispute that arises directly or indirectly from the relationship of the parties evidenced by the grant of the Options or this Agreement, the parties hereby submit to and consent to the exclusive jurisdiction of the courts of Harris County, Texas, or the federal courts for the United States for the Southern District of Texas, and no other courts, where this grant is made and/or to be performed.

9.

ENTIRE AGREEMENT; MODIFICATION; WAIVER

The Plan and this Agreement contain the entire agreement between the parties with respect to the subject matter contained herein and may not be modified, except as provided in the Plan, as it may be amended from time to time in the manner provided therein, or in this Agreement, as it may be amended from time to time by a written document signed by each of the parties hereto. Any oral or written agreements, representations, warranties, written inducements,

4

or other communications with respect to the subject matter contained herein made prior to the execution of the Agreement shall be void and ineffective for all purposes. Optionee acknowledges that a waiver by Superior of a breach of any provision of this Agreement shall not operate or be construed as a waiver of any other provision of this Agreement, or of any subsequent breach by the Optionee or any other Plan participant.

10.

ELECTRONIC DELIVERY; ACCEPTANCE OF AGREEMENT

10.1 Superior may, in its sole discretion, deliver any documents related to Optionee’s current or future participation in the Plan by electronic means or request your consent to participate in the Plan by electronic means. By accepting the terms of this Agreement, Optionee hereby consents to receive such documents by electronic delivery and agrees to participate in the Plan through an on-line or electronic system established and maintained by Superior or a third party designated by Superior.

10.2 Optionee must expressly accept the terms and conditions of this Agreement by electronically accepting this Agreement in a timely manner. If Optionee does not accept the terms of this Agreement, this Option is subject to cancellation.

* * * * * * * * * * * * *

By clicking the “Accept” button, Optionee represents that he or she is familiar with the terms and provisions of the Plan, and hereby accepts this Agreement subject to all of the terms and provisions thereof. Optionee has reviewed the Plan and this Agreement in their entirety and fully understands all provisions of this Agreement. Optionee agrees to accept as binding, conclusive and final all decisions or interpretations of the Compensation Committee of Superior’s Board of Directors upon any questions arising under the Plan or this Agreement.

PLEASE PRINT AND KEEP A COPY FOR YOUR RECORDS

5

EX-10.22

Exhibit 10.22

Form for 2014 Awards

PERFORMANCE SHARE UNIT AWARD AGREEMENT

This PERFORMANCE SHARE UNIT AWARD AGREEMENT (this “Agreement”) is by and between Superior Energy Services, Inc. (“Superior”) and <<Participant Name>> (the “Participant”).

WHEREAS, Superior has adopted the 2013 Stock Incentive Plan (the “Plan”), under which the Compensation Committee (the “Committee”) of the Board of Directors of Superior, or its delegee, may, among other things, grant awards of performance share units payable in cash, or a combination of cash and shares of Superior common stock, $.001 par value per share (the “Common Stock”), to officers and key employees of Superior or its subsidiaries (collectively, the “Company”); and

WHEREAS, the Committee believes that entering into this Agreement with the Participant is consistent with the purpose for which the Plan was adopted.

NOW, THEREFORE, Superior and the Participant hereby agree as follows:

Section 1. The Plan. The Plan, a copy of which has been made available to the Participant, is incorporated by reference and made a part of this Agreement as if fully set forth herein. This Agreement uses a number of defined terms that are defined in the Plan or in the body of this Agreement. These defined terms are capitalized wherever they are used.

Section 2. Award.

(a) On <<Grant Date>>, Superior granted to the Participant an Other Stock Based Award consisting of <<Awards Granted>> performance share units (the “Units”), subject to the terms and conditions of this Agreement.

(b) Depending on the Company’s achievement of the performance goals specified in Section 2(c) during the period beginning January 1, 2014 and ending December 31, 2016 (the “Performance Period”), the Participant shall be entitled to a payment equal to the value of the Units determined pursuant to Section 2(d) if, except as otherwise provided in Section 3, he remains actively employed with the Company on January 2, 2017.

(c) The amount paid with respect to the Units shall be based upon the Company’s achievement of the following performance criteria as determined by the Committee: (i) return on invested capital relative to the return on invested capital of the Company’s “Peer Group” listed on Schedule A attached hereto (“Relative ROIC”); and (ii) the Company’s total shareholder return relative to the total shareholder return of the Company’s “Peer Group” listed on Schedule A attached hereto (“Relative TSR”) in accordance with the following matrix:

Relative ROIC

Performance Level Compared to Peer Group		Performance Percentage(%)
	Below 25th Percentile		0	%
Threshold	25th Percentile		25	%
Target	50th Percentile		50	%
Maximum	75th Percentile or above		100	%

Relative TSR

Performance Level Compared to Peer Group		Performance Percentage(%)
	Below 25th Percentile		0	%
Threshold	25th Percentile		25	%
Target	50th Percentile		50	%
Maximum	75th Percentile or above		100	%

The Committee shall adjust the performance criteria to recognize special or non-recurring situations or circumstances with respect to the Company or any other company in the peer group for any year during the Performance Period arising from the acquisition or disposition of assets, costs associated with exit or disposal activities or material impairments that are reported on a Form 8-K filed with the Securities and Exchange Commission.

(d) The amount payable to the Participant pursuant to this Agreement shall be an amount equal to the number of Units awarded to the Participant multiplied by the product of (i) $100 and (ii) the sum of the Performance Percentages set forth above for the level of achievement of each of the performance criteria set forth in Section 2(c). By way of example, if the Company reached the 25^th percentile in Relative ROIC and the 50^th percentile in Relative TSR, the sum of the Performance Percentages would be 75% and the amount payable with respect to each Unit would be $75. If Relative ROIC reached the 75^th percentile but Relative TSR was below the 25^th percentile, the sum of the Performance Percentages would be 100% and the amount payable with respect to each Unit would be $100. Performance results between the threshold, target and maximum levels will be calculated on a pro rata basis. The maximum payout for each Unit is $200.

(e) Except as provided in Section 3(b), payment of amounts due under the Units shall be made on March 31, 2017. Any amount paid in respect of the Units shall be payable in such combination of cash and Common Stock (with the Common Stock valued at its Fair Market Value) as determined by the Committee in its sole discretion; provided, however, that no more than fifty percent (50%) of the payment may be made in Common Stock. Prior to any payments under this Agreement, the Committee shall certify in writing, by resolution or otherwise, the amount to be paid in respect of the Units as a result of the achievement of Relative ROIC and Relative TSR. The Committee retains discretion to decrease the amount payable to the Participant if it deems appropriate, but shall not increase the amount payable to the Participant to an amount that is higher than the amount payable under the formula described herein.

2

Section 3. Early Termination; Change of Control.

(a) In the event of the Participant’s termination of employment prior to the end of the Performance Period due to (i) any reason other than voluntary termination by the Participant (other than as permitted under Section 3(a)(iv)) or cause as determined by the Committee in its sole discretion, (ii) death, (iii) disability (within the meaning of Section 22(e)(3) of the Internal Revenue Code of 1986, as amended (the “Code”)), or (iv) Retirement (as hereinafter defined), the Participant shall forfeit as of the date of termination a number of Units determined by multiplying the number of Units by a fraction, the numerator of which is the number of full months following the date of termination, death, disability or Retirement to the end of the Performance Period and the denominator of which is thirty six (36). The Committee shall determine the number of Units forfeited and the amount to be paid to the Participant or his beneficiary in accordance with Section 2(e) based on the performance criteria for the entire Performance Period. As used herein, “Retirement” is defined as the voluntary termination of employment at or after age 55 with at least five years of service.

(b) In the event of a Change of Control, the Participant shall be deemed to have achieved the maximum level for Relative ROIC and Relative TSR in accordance with the terms of the Plan. Payment shall be made to the Participant as soon as administratively practical following the Change of Control, but in no event later than 2.5 months following the end of the year in the such Change of Control occurs. Notwithstanding the foregoing, if the Change of Control does not qualify as a “change in control event” under Section 409A of the Code, and any regulations or guidance promulgated thereunder, then payment shall be made at the time specified in Section 2(e).

Section 4. Forfeiture of Award.

(a) If the Participant engages in grossly negligent conduct or intentional misconduct that either (i) requires the Company’s financial statements to be restated at any time beginning on the Date of Grant and ending on the third anniversary of the end of the Performance Period or (ii) results in an increase of the value of the Participant’s Units, then the Committee, after considering the costs and benefits to the Company of doing so, may seek recovery for the benefit of the Company of the after-tax portion of the difference between the value of the Units received by the Participant during the three-year period following such conduct and the value of the Units that would have been received based on the restated financial statements or absent the increase described in part (ii) above (the “Excess Unit Value”). All determination regarding the value of the Units shall be made solely by the Committee in good faith.

(b) The Units granted hereunder are also subject to any clawback policies the Company may adopt in order to conform to the requirements of Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act and any resulting rules issued by the SEC or national securities exchanges thereunder.

(c) If the Committee determines that the Participant owes any amount to the Company under Sections 4(a) or 4(b) above, the Participant shall pay to the Company, without interest, the Excess Unit Value (or the amount recoverable under Section 4(b)). The Participant acknowledges that the Company may, to the fullest extent permitted by applicable law, deduct the amount owed from any amounts the Company owes the Participant from time to time for any

3

reason (including without limitation amounts owed to the Participant as salary, wages, reimbursements or other compensation, fringe benefits, retirement benefits or vacation pay). Whether or not the Company elects to make any such set-off in whole or in part, if the Company does not recover by means of set-off the full amount the Participant owes it, the Participant hereby agrees to pay immediately the unpaid balance to the Company.

Section 5. Miscellaneous.

(a) The Participant understands and acknowledges that he is one of a limited number of employees of the Company who have been selected to receive grants of Units and that the grant is considered confidential information. The Participant hereby covenants and agrees not to disclose the award of Units pursuant to this Agreement to any other person except (i) the Participant’s immediate family and legal or financial advisors who agree to maintain the confidentiality of this Agreement, (ii) as required in connection with the administration of this Agreement and the Plan as it relates to this award or under applicable law, and (iii) to the extent the terms of this Agreement have been publicly disclosed by the Company.

(b) The Company shall be entitled to require a cash payment by or on behalf of the Participant and/or to deduct from other compensation payable to the Participant any sums required by federal, state or local tax law to be withheld with respect to the award or payments in respect of any Units or the issuance of Common Stock. Alternatively, the Participant may irrevocably elect, in such manner and at such time or times prior to any applicable tax date, as may be permitted by the Committee, to have the Company withhold and reacquire Units or Common Stock to satisfy any withholding obligations of the Company. Any election to have Units or Common Stock so held back and reacquired shall be subject to the Committee’s approval.

(c) The authority to manage and control the operation and administration of this Agreement shall be vested in the Committee, and the Committee shall have all powers with respect to this Agreement as it has with respect to the Plan. Any interpretation of this Agreement by the Committee and any decision made by it with respect to this Agreement shall be final and binding on all persons.

(d) Notwithstanding anything in this Agreement to the contrary, the terms of this Agreement shall be subject to the terms of the Plan, and this Agreement is subject to all interpretations, amendments, rules and regulations promulgated by the Committee from time to time pursuant to the Plan.

(e) This Agreement shall be construed and interpreted to comply with Section 409A of the Internal Revenue Code of 1986, as amended. Superior reserves the right to amend this Agreement to the extent it reasonably determines is necessary in order to preserve the intended tax consequences of the Units in light of Section 409A and any regulations or other guidance promulgated thereunder. Neither the Company nor the members of the Committee shall be liable for any determination or action taken or made with respect to this Agreement or the Units granted thereunder.

(f) Each notice relating to this Agreement shall be in writing and delivered in person or by mail to Superior at its office, 1001 Louisiana Street, Suite 2900, Houston, TX 77002, to the

4

attention of the Secretary or at such other address as Superior may specify in writing to the Participant by a notice delivered in accordance with this Section 5(f). All notices to the Participant shall be delivered to the Participant’s address on file with the Company or at such other address as the Participant may specify in writing to the Secretary by a notice delivered in accordance with this Section 5(f) and Section 5(m).

(g) Neither this Agreement nor the rights of Participant hereunder shall be transferable by the Participant during his life other than by will or pursuant to applicable laws of descent and distribution. No rights or privileges of the Participant in connection herewith shall be transferred, assigned, pledged or hypothecated by Participant or by any other person in any way, whether by operation of law, or otherwise, and shall not be subject to execution, attachment, garnishment or similar process. In the event of any such occurrence, this Agreement shall automatically be terminated and shall thereafter be null and void.

(h) Nothing in this Agreement shall confer upon the Participant any right to continue in the employment of the Company, or to interfere in any way with the right of the Company to terminate the Participant’s employment relationship with the Company at any time.

(i) This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware. For purposes of litigating any dispute that arises directly or indirectly from the relationship of the parties evidenced by the grant of the Units or this Agreement, the parties hereby submit to and consent to the exclusive jurisdiction of the courts of Harris County, Texas, or the federal courts for the United States for the Southern District of Texas, and no other courts, where this grant is made and/or to be performed.

(j) If any term or provision of this Agreement, shall at any time or to any extent be invalid, illegal or unenforceable in any respect as written, the Participant and Superior intend for any court construing this Agreement to modify or limit such provision so as to render it valid and enforceable to the fullest extent allowed by law. Any such provision that is not susceptible of such reformation shall be ignored so as to not affect any other term or provision hereof, and the remainder of this Agreement, or the application of such term or provision to persons or circumstances other than those as to which it is held invalid, illegal or unenforceable, shall not be affected thereby and each term and provision of this Agreement shall be valid and enforced to the fullest extent permitted by law.

(k) The Plan and this Agreement contain the entire agreement between the parties with respect to the subject matter contained herein and may not be modified, except as provided herein or in the Plan or as it may be amended from time to time by a written document signed by each of the parties hereto, including by electronic means as provided in Section 5(m). Any oral or written agreements, representations, warranties, written inducements, or other communications with respect to the subject matter contained herein made prior to the execution of the Agreement shall be void and ineffective for all purposes.

(l) Superior’s obligation under the Plan and this Agreement is an unsecured and unfunded promise to pay benefits that may be earned in the future. Superior shall have no obligation to set aside, earmark or invest any fund or money with which to pay its obligations under this Agreement. The Participant or any successor in interest shall be and remain a general creditor of Superior in the same manner as any other creditor having a general claim for matured and unpaid compensation.

5

(m) Superior may, in its sole discretion, deliver any documents related to the Participant’s current or future participation in the Plan by electronic means or request the Participant’s consent to participate in the Plan by electronic means. By accepting the terms of this Agreement, the Participant hereby consents to receive such documents by electronic delivery and agrees to participate in the Plan through an on-line or electronic system established and maintained by Superior or a third party designated by Superior.

(n) The Participant must expressly accept the terms and conditions of this Agreement by electronically accepting this Agreement in a timely manner. If the Participant does not accept the terms of this Agreement, this award of Units is subject to cancellation.

(o) The Participant acknowledges that a waiver by Superior of a breach of any provision of this Agreement shall not operate or be construed as a waiver of any other provision of this Agreement, or of any subsequent breach by the Participant or any other Plan participant.

* * * * * * * * * * * * *

By clicking the “Accept” button, the Participant represents that he or she is familiar with the terms and provisions of the Plan, and hereby accepts this Agreement subject to all of the terms and provisions thereof. The Participant has reviewed the Plan and this Agreement in their entirety and fully understands all provisions of this Agreement. The Participant agrees to accept as binding, conclusive and final all decisions or interpretations of the Committee upon any questions arising under the Plan or this Agreement.

6

Schedule A

PEER GROUP COMPANIES

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 Limited

Weatherford International, Ltd.

If any peer group company’s Relative ROIC or Relative TSR shall cease to be publicly available (due to a business combination, receivership, bankruptcy or other event) or if any such company is no longer publicly held, the Committee shall exclude that company from the peer group and, in its sole discretion, substitute another comparable company.

PLEASE PRINT AND KEEP A COPY FOR YOUR RECORDS

A-1

EX-10.23

Exhibit 10.23

Draft Dated February 10, 2014

Form for 2014 Awards

Strategic Grant to Executive Team

STRATEGIC PERFORMANCE AWARD AGREEMENT

This STRATEGIC PERFORMANCE AWARD AGREEMENT (this “Agreement”) is by and between Superior Energy Services, Inc. (“Superior”) and <<Participant Name>> (the “Participant”).

WHEREAS, Superior has adopted the 2013 Stock Incentive Plan (the “Plan”), under which the Compensation Committee (the “Committee”) of the Board of Directors of Superior may, among other things, grant performance awards in the form of phantom shares of Superior common stock, $.001 par value per share (the “Common Stock”), to officers and key employees of Superior or its subsidiaries (collectively, the “Company”); and

WHEREAS, the Committee believes that entering into this Agreement with the Participant is consistent with the purpose for which the Plan was adopted.

NOW, THEREFORE, Superior and the Participant hereby agree as follows:

Section 1. The Plan. The Plan, a copy of which has been made available to the Participant, is incorporated by reference and made a part of this Agreement as if fully set forth herein. This Agreement uses a number of defined terms that are defined in the Plan or in the body of this Agreement. These defined terms are capitalized wherever they are used.

Section 2. Award.

(a) The Committee has agreed to award the Participant an Other Stock Based Award consisting of performance shares (the “Performance Shares”) with an aggregate grant date value of $        (the “Aggregate Grant Value”), which Performance Shares will be awarded through two separate grants under the following schedule, provided the Participant is an employee of the Company on the applicable grant date (each, a “Grant Date”):

(i) Effective February 12, 2014 (the “2014 Grant Date”), the Participant will receive a target award of Performance Shares determined by dividing 50% of the Aggregate Grant Value by the Fair Market Value of a share of Common Stock on the 2014 Grant Date, and rounding up to the nearest whole number (such Performance Shares referred to herein as the “2014 Target Award”).

(ii) Effective March 1, 2015 (the “2015 Grant Date”), the Participant will receive a target award of Performance Shares determined by dividing 50% of the Aggregate Grant Value by the Fair Market Value of a share of Common Stock on the 2015 Grant Date, and rounding up to the nearest whole number (such Performance Shares referred to herein as the “2015 Target Award”).

(b) Each Performance Share represents the right to receive a share of Common Stock on the Payment Date (as defined in Section 4), and all Related Credits credited to the Participant’s Dividend Equivalent Account (as such terms are defined in Section 2(c)) with respect to such Performance Share, subject to the terms and conditions set forth in this Agreement and the Plan. Notwithstanding anything to the contrary in this Agreement, the Participant has the right to earn and vest in up to 150% of the number of Performance Shares represented by each of the 2014 Target Award and the 2015 Target Award, based on the Company’s level of achievement of the applicable performance goals described in Section 3 and the Appendices hereto, as certified by the Committee, and satisfaction of the service requirements set forth herein.

(c) The Performance Shares are not actual shares of Common Stock and do not entitle the Participant to any incidents of ownership (including, without limitation, dividend and voting rights) in any shares of Common Stock until such shares of Common Stock are issued. From and after the applicable Grant Date of Performance Shares until the issuance of the shares of Common Stock payable in respect of any Vested Performance Shares (as defined below), the Participant shall be credited, as of the payment date therefor, with (a) the amount of any cash dividends and (b) the amount equal to the Fair Market Value of any shares of Common Stock, securities, or other property distributed or distributable in respect of one share of Common Stock to which the Participant would have been entitled had the Participant been a record holder of one share of Common Stock for each Vested Performance Share at all times from the applicable Grant Date of such Performance Share to such issuance date (collectively, the “Related Credits”). All such Related Credits shall be made notionally to a dividend equivalent account (a “Dividend Equivalent Account”) established for the Participant with respect to all Performance Shares granted on the same Grant Date. All such Related Credits shall vest or be forfeited at the same time and on the same terms as the Performance Shares to which they relate.

Section 3. Performance Goals; Vesting.

(a) The number of Performance Shares earned will be based upon the level of the Company’s free cash flow (“Free Cash Flow”) achieved for each performance period (each, a “Performance Period”) relative to the goals established by the Committee. The performance goals and payout matrix applicable to the 2014 Target Award are set forth on Appendix A hereto, and the performance goals and payout matrix applicable to the 2015 Target Award will be set forth on Appendix B hereto, which will be approved by the Committee in its sole discretion and incorporated into this Agreement prior to the 2015 Grant Date.

(b) With respect to the Performance Shares granted in 2014, within 90 days following the end of fiscal year 2014, the Committee will certify in writing, by resolution or otherwise, the level of Free Cash Flow for 2014 and the resulting Performance Shares earned, if any, in respect of the 2014 Target Award (between 0% and 150%) in accordance with Appendix A. These earned Performance Awards will vest and payout pursuant to Section 4 if, except as otherwise provided in Section 5, the Participant remains actively employed with the Company through January 2, 2016.

(c) With respect to the Performance Shares granted in 2015, within 90 days following the end of fiscal year 2015, the Committee will certify in writing, by resolution or otherwise, the

2

level of Free Cash Flow for 2015 and the resulting Performance Shares earned, if any, in respect of the 2015 Target Award (between 0% and 150%) in accordance with Appendix B. These earned Performance Awards will vest and payout pursuant to Section 4 if, except as otherwise provided in Section 5, the Participant remains actively employed with the Company through January 2, 2016.

(d) The earned and vested Performance Shares under Sections 3(b) and (c) above are referred to herein as the “Vested Performance Shares.” Any Performance Shares that are not earned and vested shall, with no further action, be forfeited and cease to be outstanding.

(e) For purposes of this Agreement, Free Cash Flow for each of the fiscal years ended December 31, 2014 and December 31, 2015 shall mean net cash provided by operating activities less payments for capital expenditures, each as set forth in Superior’s Consolidated Statement of Cash Flows included in Superior’s Form 10-K filed with the Securities and Exchange Commission (the “Commission”) for each of the fiscal years ended December 31, 2014 and December 31, 2015, respectively, and as adjusted as provided herein. The Committee shall adjust Free Cash Flow to recognize, when applicable, (1) the effect of accounting changes in accordance with generally accepted accounting principles, (ii) the impact of changes to international, federal and state tax laws, and (iii) unusual or non-recurring transactions or events affecting the Company during either Performance Period, including those arising from the acquisition or disposition of assets, impairments or costs associated with exit or disposal activities or material impairments that are reported on a Form 8-K filed with the Commission.

Section 4. Payout of Performance Shares. Except as provided in Section 5(b), payout of the Vested Performance Shares shall be made effective on the later of (i) March 1, 2016, or (ii) the date in 2016 that the Committee makes the certification required by Section 3(c) (each, a “Payment Date”). No later than 10 days following the applicable Payment Date, Superior will credit the Participant’s brokerage account with the shares of Common Stock and the cash value of any Related Credits applicable to such Vested Performance Shares, less any applicable tax withholding. The Committee retains discretion to decrease the amount payable to the Participant if it deems appropriate, but shall not increase the amount payable to the Participant to an amount that is higher than the amount payable under the formulas described herein.

Section 5. Early Termination; Change of Control.

(a) In the event of the Participant’s termination of employment prior to January 2, 2016 due to (i) any reason other than voluntary termination by the Participant (other than as permitted under Section 5(a)(iv)) or cause as determined by the Committee in its sole discretion, (ii) death, (iii) disability (within the meaning of Section 22(e)(3) of the Internal Revenue Code of 1986, as amended (the “Code”)), or (iv) Retirement (as hereinafter defined), the Participant shall forfeit as of the date of termination a number of Performance Shares determined by multiplying each of the 2014 Target Award and the 2015 Target Award, but only if the Participant received the grant, by a fraction, the numerator of which is the number of full months in the Performance Period following the date of termination, death, disability or Retirement to the end of the applicable Performance Period and the denominator of which is twelve (12). The Committee shall determine the number of Performance Shares forfeited from each of the 2014 Target Award and the 2015 Target Award, as applicable, and the amount to be paid to the Participant or his

3

beneficiary shall be determined by the Committee in accordance with Section 3 based on the achievement of the performance criteria for each Performance Period. Any such amounts will be paid in accordance with Section 4. As used herein, “Retirement” is defined as the voluntary termination of employment at or after age 55 with at least five years of service.

(b) In the event of a Change of Control occurring after the grant date of an award granted under Section 2(a) but prior to the end of the Performance Period applicable to that award, the Company shall be deemed to have achieved the maximum level of Free Cash Flow in accordance with Sections 3(b) and 3(c) and the Participant shall vest in 150% of the applicable target award. In the event of a Change of Control occurring after the end of the Performance Period for an award granted under Section 2(a) but prior to payout of the award, the Participant shall vest in the number of Performance Shares determined based on actual achievement of the performance criteria for that Performance Period in accordance with Section 3(b) and 3(c). Payout of the Vested Performance Shares following a Change of Control shall be made to the Participant as soon as administratively practical following the Change of Control, but in no event later than 2.5 months following the end of the year in the such Change of Control occurs. Notwithstanding the foregoing, if the Change of Control does not qualify as a “change in control event” under Section 409A of the Code, and any regulations or guidance promulgated thereunder, then payment shall be made at the time specified in Section 4.

Section 6. Forfeiture of Award.

(a) If the Participant engages in grossly negligent conduct or intentional misconduct that either (i) requires the Company’s financial statements to be restated at any time beginning on the 2014 Grant Date and ending on the third anniversary of the end of the 2015 Performance Period or (ii) results in an increase of the value of the Participant’s Performance Shares, then the Committee, after considering the costs and benefits to the Company of doing so, may seek recovery for the benefit of the Company of the shares of Common Stock received upon payout of the Vested Performance Shares received by the Participant during the three-year period following such conduct and the shares of Common Stock that would have been received based on the restated financial statements or absent the increase described in part (ii) above (the “Excess Shares”). All determination regarding the value of the Performance Shares shall be made solely by the Committee in good faith.

(b) The Performance Shares granted hereunder are also subject to any clawback policies the Company may adopt in order to conform to the requirements of Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act and any resulting rules issued by the SEC or national securities exchanges thereunder.

(c) If the Committee determines that the Participant owes any amount to the Company under Sections 6(a) or 6(b) above, the Participant shall return to the Company the Excess Shares (or the shares recoverable under Section 6(b)) acquired by the Participant pursuant to this Agreement (or other securities into which such shares have been converted or exchanged) or, if no longer held by the Participant, the Participant shall pay to the Company, without interest, all cash, securities or other assets received by the Participant upon the sale or transfer of such shares. The Participant acknowledges that the Company may, to the fullest extent permitted by applicable law, deduct the amount owed from any amounts the Company owes the Participant

4

from time to time for any reason (including without limitation amounts owed to the Participant as salary, wages, reimbursements or other compensation, fringe benefits, retirement benefits or vacation pay). Whether or not the Company elects to make any such set-off in whole or in part, if the Company does not recover by means of set-off the full amount the Participant owes it, the Participant hereby agrees to pay immediately the unpaid balance to the Company.

Section 7. Miscellaneous.

(a) The Participant understands and acknowledges that he is one of a limited number of employees of the Company who have been selected to receive grants of Performance Shares and that the grant is considered confidential information. The Participant hereby covenants and agrees not to disclose the award of Performance Shares pursuant to this Agreement to any other person except (i) the Participant’s immediate family and legal or financial advisors who agree to maintain the confidentiality of this Agreement, (ii) as required in connection with the administration of this Agreement and the Plan as it relates to this award or under applicable law, and (iii) to the extent the terms of this Agreement have been publicly disclosed by the Company.

(b) At the time of payout of the Vested Performance Shares, the Participant must deliver to Superior any sums required by federal, state or local tax law to be withheld with respect to the award or payments in respect of any Performance Shares. In accordance with and subject to the terms of the Plan, the Participant may satisfy the tax withholding obligation in whole or in part by delivering currently owned shares of Common Stock or by electing to have Superior withhold from the shares the Participant otherwise would receive upon vesting and payout of the Performance Shares the shares of Common Stock having a Fair Market Value equal to the minimum amount required to be withheld (as determined under the Plan).

(c) The authority to manage and control the operation and administration of this Agreement shall be vested in the Committee, and the Committee shall have all powers with respect to this Agreement as it has with respect to the Plan. Any interpretation of this Agreement by the Committee and any decision made by it with respect to this Agreement shall be final and binding on all persons.

(d) Notwithstanding anything in this Agreement to the contrary, the terms of this Agreement shall be subject to the terms of the Plan, and this Agreement is subject to all interpretations, amendments, rules and regulations promulgated by the Committee from time to time pursuant to the Plan.

(e) This Agreement shall be construed and interpreted to comply with Section 409A of the Code. Superior reserves the right to amend this Agreement to the extent it reasonably determines is necessary in order to preserve the intended tax consequences of the Performance Shares in light of Section 409A of the Code and any regulations or other guidance promulgated thereunder. Neither the Company nor the members of the Committee shall be liable for any determination or action taken or made with respect to this Agreement or the Performance Shares granted hereunder.

(f) Each notice relating to this Agreement shall be in writing and delivered in person or by mail to Superior at its office, 1001 Louisiana Street, Suite 2900, Houston, TX 77002, to the

5

attention of the Secretary or at such other address as Superior may specify in writing to the Participant by a notice delivered in accordance with this Section 7(f). All notices to the Participant shall be delivered to the Participant’s address on file with the Company or at such other address as the Participant may specify in writing to the Secretary by a notice delivered in accordance with this Section 7(f) and Section 7(m).

(g) Neither this Agreement nor the rights of Participant hereunder shall be transferable by the Participant during his life other than by will or pursuant to applicable laws of descent and distribution. No rights or privileges of the Participant in connection herewith shall be transferred, assigned, pledged or hypothecated by Participant or by any other person in any way, whether by operation of law, or otherwise, and shall not be subject to execution, attachment, garnishment or similar process. In the event of any such occurrence, this Agreement shall automatically be terminated and shall thereafter be null and void.

(h) Nothing in this Agreement shall confer upon the Participant any right to continue in the employment of the Company, or to interfere in any way with the right of the Company to terminate the Participant’s employment relationship with the Company at any time.

(i) This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware. For purposes of litigating any dispute that arises directly or indirectly from the relationship of the parties evidenced by the grant of the Performance Shares or this Agreement, the parties hereby submit to and consent to the exclusive jurisdiction of the courts of Harris County, Texas, or the federal courts for the United States for the Southern District of Texas, and no other courts, where this grant is made and/or to be performed.

(j) If any term or provision of this Agreement, shall at any time or to any extent be invalid, illegal or unenforceable in any respect as written, the Participant and Superior intend for any court construing this Agreement to modify or limit such provision so as to render it valid and enforceable to the fullest extent allowed by law. Any such provision that is not susceptible of such reformation shall be ignored so as to not affect any other term or provision hereof, and the remainder of this Agreement, or the application of such term or provision to persons or circumstances other than those as to which it is held invalid, illegal or unenforceable, shall not be affected thereby and each term and provision of this Agreement shall be valid and enforced to the fullest extent permitted by law.

(k) The Plan and this Agreement contain the entire agreement between the parties with respect to the subject matter contained herein and may not be modified, except as provided herein or in the Plan or as it may be amended from time to time by a written document signed by each of the parties hereto, including by electronic means as provided in Section 7(m). The Participant specifically acknowledges the Committee unilateral authority to amend this agreement to include Appendix B as set forth in Section 3(a). Any oral or written agreements, representations, warranties, written inducements, or other communications with respect to the subject matter contained herein made prior to the execution of the Agreement shall be void and ineffective for all purposes.

(l) Superior’s obligation under the Plan and this Agreement is an unsecured and unfunded promise to pay benefits that may be earned in the future. Superior shall have no

6

obligation to set aside, earmark or invest any fund or money with which to pay its obligations under this Agreement. The Participant or any successor in interest shall be and remain a general creditor of Superior in the same manner as any other creditor having a general claim for matured and unpaid compensation.

(m) Superior may, in its sole discretion, deliver any documents related to the Participant’s current or future participation in the Plan by electronic means or request the Participant’s consent to participate in the Plan by electronic means. By accepting the terms of this Agreement, the Participant hereby consents to receive such documents by electronic delivery and agrees to participate in the Plan through an on-line or electronic system established and maintained by Superior or a third party designated by Superior.

(n) The Participant must expressly accept the terms and conditions of this Agreement by electronically accepting this Agreement in a timely manner. If the Participant does not accept the terms of this Agreement, this award of Performance Shares is subject to cancellation.

(o) The Participant acknowledges that a waiver by Superior of a breach of any provision of this Agreement shall not operate or be construed as a waiver of any other provision of this Agreement, or of any subsequent breach by the Participant or any other Plan participant.

* * * * * * * * * * * * *

By clicking the “Accept” button, the Participant represents that he or she is familiar with the terms and provisions of the Plan, and hereby accepts this Agreement subject to all of the terms and provisions thereof. The Participant has reviewed the Plan and this Agreement in their entirety and fully understands all provisions of this Agreement. The Participant agrees to accept as binding, conclusive and final all decisions or interpretations of the Committee upon any questions arising under the Plan or this Agreement.

PLEASE PRINT AND KEEP A COPY FOR YOUR RECORDS

7

Appendix A

to Strategic Performance Award Agreement

Performance Goals and Payout Matrix for 2014 Target Award

2014 Target Award:	Performance Shares
2014 Performance Period:	January 1, 2014 – December 31, 2014
Performance Goal:	Increase in Free Cash Flow above $175 million

		Percentage (%) of 2014 Target Award Earned
2014 Free Cash Flow
	Below $180 million		0	%
Threshold	$180 million		50	%
Target	$225 million		100	%
Maximum	$270 million or above		150	%

Performance results between the threshold, target and maximum levels will be calculated on a pro rata basis.

8

Appendix B

to Strategic Performance Award Agreement

Performance Goals and Payout Matrix for 2015 Target Award

[To be approved by the Compensation Committee of Superior Energy Services, Inc. and made a part hereof on or before March 1, 2015.]

2015 Target Award:	Performance Shares
2015 Performance Period:	January 1, 2015 – December 31, 2015
Performance Goal:	Increase in Free Cash Flow above $            million

		Percentage (%) of 2015 Target Award Earned
2015 Free Cash Flow
	Below $         million		0	%
Threshold	$         million		50	%
Target	$         million		100	%
Maximum	$         million or above		150	%

Performance results between the threshold, target and maximum levels will be calculated on a pro rata basis.

9

EX-10.38

Exhibit 10.38

FIRST AMENDMENT

TO

THIRD AMENDED AND RESTATED

CREDIT AGREEMENT

Dated as of November 20, 2013

Among

SUPERIOR ENERGY SERVICES, INC.,

as Parent,

SESI, L.L.C.,

as the Borrower,

JPMORGAN CHASE BANK, N.A.

as Administrative Agent

and

the Lenders Party Hereto

FIRST AMENDMENT TO THIRD AMENDED AND RESTATED

CREDIT AGREEMENT

THIS FIRST AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT (this “First Amendment”) dated as of November 20, 2013 is among Superior Energy Services, Inc., a corporation duly formed and existing under the laws of the State of Delaware (the “Parent”), SESI, L.L.C., a limited liability company duly formed and existing under the laws of the State of Delaware (the “Borrower”), each of the undersigned guarantors (the “Guarantors”, and together with the Parent and the Borrower, the “Obligors”), each of the Lenders, the Issuing Lenders and the Swingline Lender (collectively, the “Lenders”), and JPMORGAN CHASE BANK, N.A., as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”).

R E C I T A L S

A. The Borrower, the Parent, the Administrative Agent and the Lenders are parties to that certain Third Amended and Restated Credit Agreement dated as of February 7, 2012 (the “Credit Agreement”), pursuant to which the Lenders have made certain credit available to and on behalf of the Borrower.

B. The Borrower has requested and the Administrative Agent and the Lenders have agreed to make certain changes to the Credit Agreement.

C. NOW, THEREFORE, to induce the Administrative Agent and the Lenders party hereto to enter into this First Amendment and in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1. Defined Terms. Each capitalized term used herein but not otherwise defined herein has the meaning given such term in the Credit Agreement, as amended by this First Amendment. Unless otherwise indicated, all section references in this First Amendment refer to sections of the Credit Agreement.

Section 2. Amendments to Credit Agreement.

2.1 Amendments to Section 1.1.

(a) The following definitions are hereby added where alphabetically appropriate:

“Amendment Effective Date” has the meaning assigned to such term in the First Amendment.

“Corporate Rating” means the long-term senior unsecured publicly held debt rating of the Parent or the Borrower (as is the applicable Person then receiving the primary rating) from each of S&P and Moody’s.

“Investment Grade Rating” means a Corporate Rating equal to or higher than Baa3 (or the equivalent) by Moody’s and BBB- (or the equivalent) by S&P.

“First Amendment” means that certain First Amendment to Third Amended and Restated Credit Agreement, dated as of November 20, 2013, among the Loan Parties, the Administrative Agent and the Lenders.

“Moody’s” means Moody’s Investors Service, Inc. or its successor.

“Rating Upgrade Date” is defined in Section 2.18(d).

“S&P” means Standard & Poor’s Ratings Group, Inc. or its successor.

(b) The following defined terms are hereby amended to read:

“Agreement” means this Third Amended and Restated Credit Agreement, as amended by the First Amendment and as the same may be further amended or supplemented from time to time.

“Rate Management Obligations” means any and all obligations of the Borrower or any Subsidiaries, whether absolute or contingent and howsoever and whensoever created, arising, evidenced or acquired (including all renewals, extensions and modifications thereof and substitutions therefor), under (a) any and all Rate Management Transactions with any Lender or affiliate thereof, and (b) any and all cancellations, buy backs, reversals, terminations or assignments of any Rate Management Transactions with any Lender or affiliate thereof.

“Rate Management Transaction” means any transaction (including an agreement with respect thereto) now existing or hereafter entered into by the Borrower or any Subsidiaries which is a rate swap, basis swap, forward rate transaction, commodity swap, commodity option, equity or equity index swap, equity or equity index option, bond option, interest rate option, foreign exchange transaction, cap transaction, floor transaction, collar transaction, forward transaction, currency swap transaction, cross-currency rate swap transaction, currency option or any other similar transaction (including any option with respect to any of these transactions) or any combination thereof, whether linked to one or more interest rates, foreign currencies, commodity prices, equity prices or other financial measures.

2.2 Amendment to Section 2.18. Section 2.18 is hereby amended to insert the following Section 2.18(d) which reads as follows:

(d) On the first day (such day being the “Rating Upgrade Date”) on which (i) the Corporate Rating shall be an Investment Grade Rating, (ii) each Rate Management Transaction other than those listed on Schedule 1 attached hereto is unsecured or secured by a Lien permitted by Section 6.14(a)(x) and (iii) no Default or Event of Default has occurred and is continuing under this Agreement:

(A) the Parent and the Borrower shall not be subject to the terms, agreements and covenants contained in Section 2.18(a), Section 2.18(b), Section 6.21 or Section 7.11;

2

(B) the Liens created under all Collateral Documents shall be released and discharged and the obligations of the Parent, the Borrower or any other Loan Party thereunder terminated; and

(C) upon its receipt of written notice from the Borrower of the occurrence of the Rating Upgrade Date, the Administrative Agent will promptly return all Collateral in its possession to the Borrower. The Lenders, the Issuing Lenders and the Swingline Lender hereby authorize and direct the Administrative Agent to return any such Collateral and to execute and deliver any releases, terminations or other instruments reasonably requested by the Borrower to effect or evidence the foregoing releases on or after the Rating Upgrade Date. For the avoidance of doubt, such terms, agreements, covenants and Liens shall not be reinstated if the Corporate Rating is no longer an Investment Grade Rating at any time after the Rating Upgrade Date.

2.3 Amendment to Section 6.1. Section 6.1 is hereby amended to insert the following Section 6.1(c) which reads as follows:

(c) The Parent will give the Administrative Agent and the Lenders prompt written notice of any change in the Corporate Rating from either S&P or Moody’s.

2.4 Amendment to Section 6.11(a). Sections 6.11(a) is hereby amended by deleting the phrase “Rate Management Obligations” in the second line thereof and replacing it with the phrase “Rate Management Transactions”.

2.5 Amendment to Section 6.11(a)(vi). Sections 6.11(a)(vi) is hereby amended by deleting the phrase “Rate Management Obligations” starting in the first line thereof and replacing it with the phrase “Rate Management Transactions”.

2.6 Amendment to Section 6.11(a)(vii). Sections 6.11(a)(vii) is hereby amended by deleting the phrase “Rate Management Obligations” starting in the first line thereof and replacing it with the phrase “Rate Management Transactions”.

2.7 Amendment to Section 6.14(a)(x). Sections 6.14(a)(x) is hereby amended by deleting the phrase “Rate Management Obligations” starting in the first line thereof and replacing it with the phrase “Rate Management Transactions”.

2.8 Amendment to SCHEDULE 2 (PRICING SCHEDULE). Effective as of the Rating Upgrade Date, Schedule 2 (Pricing Schedule) to the Credit Agreement shall be deemed amended by deleting such schedule in its entirety and replacing it with Schedule 2 to this First Amendment.

3

Section 3. Conditions Precedent. This First Amendment shall not become effective until the date on which each of the following conditions is satisfied (or waived in accordance with Section 9.12 of the Credit Agreement) (such date, the “Amendment Effective Date”):

3.1 The Administrative Agent shall have received from the Obligors and the Lenders, counterparts (in such number as may be requested by the Administrative Agent) of this First Amendment signed on behalf of such Person.

3.2 The Administrative Agent and the Lenders shall have received all fees and amounts due and payable on or prior to the Amendment Effective Date, including, to the extent invoiced, reimbursement or payment of all documented out-of-pocket expenses required to be reimbursed or paid by the Borrower under the Credit Agreement.

3.3 No Default or Event of Default shall have occurred and be continuing as of the date hereof, after giving effect to the terms of this First Amendment.

The Administrative Agent is hereby authorized and directed to declare this First Amendment to be effective when it has received documents confirming or certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forth in this Section 3 or the waiver of such conditions as permitted hereby. Such declaration shall be final, conclusive and binding upon all parties to the Credit Agreement for all purposes. If the Rating Upgrade Date does not occur by October 31, 2014, the Loan Documents shall be modified in a customary manner so that no Guarantor is guaranteeing any obligations in respect of any Rate Management Transaction in a manner that does not comply with applicable law.

Section 4. Miscellaneous.

4.1 Confirmation. The provisions of the Credit Agreement, as amended by this First Amendment, shall remain in full force and effect following the effectiveness of this First Amendment.

4.2 Ratification and Affirmation; Representations and Warranties. Each Obligor hereby i) acknowledges the terms of this First Amendment; ii) ratifies and affirms its obligations under, and acknowledges, renews and extends its continued liability under, each Loan Document to which it is a party and agrees that each Loan Document to which it is a party remains in full force and effect, except as expressly amended hereby, notwithstanding the amendments contained herein; and iii) represents and warrants to the Lenders that as of the date hereof, after giving effect to the terms of this First Amendment: (i) all of the representations and warranties contained in each Loan Document to which it is a party are true and correct in all material respects, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct as of such specified earlier date and (ii) no Default or Event of Default has occurred and is continuing.

4.3 No Waiver; Loan Document. The execution, delivery and effectiveness of this First Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of any Lender or the Administrative Agent under any of the Loan Documents, nor constitute a waiver of any provision of any of the Loan Documents. On and after the Amendment Effective Date, this First Amendment shall for all purposes constitute a Loan Document.

4

4.4 Counterparts. This First Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this First Amendment by facsimile or electronic transmission in portable document format (.pdf) shall be effective as delivery of a manually executed counterpart hereof.

4.5 NO ORAL AGREEMENT. THIS FIRST AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS EXECUTED IN CONNECTION HEREWITH AND THEREWITH REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR UNWRITTEN ORAL AGREEMENTS OF THE PARTIES. AS OF THE DATE OF THIS FIRST AMENDMENT, THERE ARE NO ORAL AGREEMENTS BETWEEN THE PARTIES.

4.6 GOVERNING LAW. THIS FIRST AMENDMENT (INCLUDING, BUT NOT LIMITED TO, THE VALIDITY AND ENFORCEABILITY HEREOF) SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

[SIGNATURES BEGIN NEXT PAGE]

5

IN WITNESS WHEREOF, the parties hereto have caused this First Amendment to be duly executed as of the date first written above.

BORROWER:	SESI, L.L.C.
	By:	/s/ Robert S. Taylor
		Name:	Robert S. Taylor
		Title:	Executive Vice President, Chief
			Financial Officer and Treasurer
PARENT:	SUPERIOR ENERGY SERVICES, INC.
	By:	/s/ Robert S. Taylor
		Name:	Robert S. Taylor
		Title:	Executive Vice President and Chief
			Financial Officer

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-1

GUARANTORS:	ADVANCED OIL WELL SERVICES, INC.
	BLOWOUT TOOLS, INC.
	CONCENTRIC PIPE AND TOOL RENTALS, L.L.C.
	CONNECTION TECHNOLOGY, L.L.C.
	CSI TECHNOLOGIES, LLC
	DRILLING LOGISTICS, L.L.C.
	FASTORQ, L.L.C.
	INTERNATIONAL SNUBBING SERVICES, L.L.C.
	NON-MAGNETIC RENTAL TOOLS, L.L.C.
	PRODUCTION MANAGEMENT
	INDUSTRIES, L.L.C.
	SEMO, L.L.C.
	SEMSE, L.L.C.
	STABIL DRILL SPECIALTIES, L.L.C.
	SUB-SURFACE TOOLS, L.L.C.
	SUPERIOR HOLDING, INC.
	SUPERIOR ENERGY SERVICES COLOMBIA, LLC
	SUPERIOR INSPECTION SERVICES, L.L.C.
	WARRIOR ENERGY SERVICES CORPORATION
	WILD WELL CONTROL, INC.
	WORKSTRINGS INTERNATIONAL, L.L.C.
	1105 PETERS ROAD, L.L.C.
	By: /s/ Robert S. Taylor
	Name: Robert S. Taylor
	Title: Vice President
	A&W WATER SERVICE, INC.
	AWS, INC.
	HAMM & PHILLIPS SERVICE COMPANY, INC.
	INTEGRATED PRODUCTION SERVICES, INC.
	LEED TOOL CORPORATION
	MONUMENT WELL SERVICE CO.
	PUMPCO ENERGY SERVICES, INC.
	RISING STAR SERVICES, L.P.
	SUPERIOR ENERGY SERVICES-NORTH AMERICA
	SERVICES, INC. (F/K/A SPN FAIRWAY ACQUISITION, INC.)
	TEXAS CES, INC.
	By: /s/ Robert S. Taylor
	Name: Robert S. Taylor
	Title: Vice President

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-2

GUARANTORS (CONT’D):	H. B. RENTALS, L.C.
	By: /s/ Robert S. Taylor
	Name: Robert S. Taylor
	Title: Director and Treasurer
	SUPERIOR ENERGY SERVICES, INC.
	By: /s/ Robert S. Taylor
	Name: Robert S. Taylor
	Title: Executive Vice President, Chief Financial Officer, Treasurer
	SUPERIOR ENERGY SERVICES, L.L.C.
	By: /s/ Robert S. Taylor
	Name: Robert S. Taylor
	Title: Executive Vice President, Chief Financial Officer, Treasurer

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-3

ADMINISTRATIVE AGENT, ISSUING LENDER AND LENDER:	JPMORGAN CHASE BANK, N.A.
	By:	/s/ Thomas Okamoto
		Name: Thomas Okamoto
		Title: Authorized Officer

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-4

LENDER:	BANK OF AMERICA, N.A.
	By:	/s/ Gary L. Mingle
		Name: Gary L. Mingle
		Title: Senior Vice-President

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-5

ISSUING LENDER, SWING LINE LENDER AND LENDER:	WELLS FARGO BANK, N.A.
	By:	/s/ Philip C. Lauinger III
		Name: Philip C. Lauinger III
		Title: Managing Director

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-6

LENDER:	CAPITAL ONE, NATIONAL ASSOCIATION
	By:	/s/ Mark Preston
		Name: Mark Preston
		Title: Senior Vice President

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-7

LENDER:	ROYAL BANK OF CANADA
	By:	/s/ Jay T. Sartain
		Name: Jay T. Sartain
		Title: Authorized Signatory

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-8

LENDER:	THE BANK OF NOVA SCOTIA
	By:	/s/ J. Frazell
		Name: J. Frazell
		Title: Director

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-9

LENDER:	CITIBANK, N.A.
	By:	/s/ John F. Miller
		Name: John F. Miller
		Title: Attorney-in-fact

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-10

LENDER:	COMERICA BANK, NA
	By:	/s/ Gary Culbertson
		Name: Gary Culbertson
		Title: Vice President

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-11

LENDER:	HSBC BANK USA, N.A.
	By:	/s/ Ryan Smith
		Name: Ryan Smith
		Title: Vice President

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-12

LENDER:	CANADIAN IMPERIAL BANK OF COMMERCE
	By:	/s/ Trudy Nelson
		Name: Trudy Nelson
		Title: Authorized Signatory
	By:	/s/ Richard Antl
		Name: Richard Antl
		Title: Authorized Signatory

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-13

LENDER:	REGIONS BANK
	By:	/s/ Scott Sarrat
		Name: Scott Sarrat
		Title: Senior Vice President

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-14

LENDER:	WHITNEY NATIONAL BANK
	By:	/s/ Hollie L. Ericksen
		Name: Hollie L. Ericksen
		Title: Senior Vice President

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-15

LENDER:	PNC BANK, NATIONAL ASSOCIATION
	By:	/s/ John Berry
		Name: John Berry
		Title: Vice President

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-16

LENDER:	COMPASS BANK
	By:	/s/ Eric Appel
		Name: Eric Appel
		Title: Senior Vice President

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-17

LENDER:	STANDARD CHARTER BANK
	By:	/s/ James P. Hughes
		Name: James P. Hughes A2386
		Title: Director
	By:	/s/ Andrew Y. NG
		Name: Andrew Y. NG
		Title: Director
		Standard Chartered Bank NY

SIGNATURE PAGE TO FIRST AMENDMENT TO

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

S-18

SCHEDULE 1

HEDGE SCHEDULE

1. Interest Rate Swap Transaction

Counterparty: The Bank of Nova Scotia

Notional Amount: USD 100,000,000.00

Fixed Rate: 7.125%

Floating Rate: 3-month LIBOR Plus 4.8600%

Effective Date: April 4, 2012

Termination Date: December 15, 2021

2. Interest Rate Swap Transaction

Counterparty: Wells Fargo Bank, N.A.

Notional Amount: USD 100,000,000.00

Fixed Rate: 7.125%

Floating Rate: 3-month LIBOR Plus 4.8225%

Effective Date: June 11, 2013

Termination Date: December 15, 2021

3. Interest Rate Swap Transaction

Counterparty: Wells Fargo Bank, N.A.

Notional Amount: USD 100,000,000.00

Fixed Rate: 7.125%

Floating Rate: 3-month LIBOR Plus 4.4000%

Effective Date: July 15, 2013

Termination Date: December 15, 2021

SCHEDULE 1

PAGE-1

SCHEDULE 2

PRICING SCHEDULE

The following is the Pricing Schedule:

Corporate Rating (S&P/Moody’s)	Applicable Margin for Eurodollar Loans			Applicable Margin for Floating Rate Loans			Commitment Fee Rate			Letter of Credit Fee Rate
Category 1 > BBB+/Baa1		1.25	%		0.25	%		0.20	%		1.25	%
Category 2 BBB/Baa2		1.50	%		0.50	%		0.25	%		1.50	%
Category 3 BBB-/Baa3		1.75	%		0.75	%		0.30	%		1.75	%
Category 4 BB+/Ba1		2.00	%		1.00	%		0.375	%		2.00	%
Category 5 > BB/Ba2		2.25	%		1.25	%		0.375	%		2.25	%

The Pricing Schedule on any day will be based on the highest Corporate Rating. If S&P or Moody’s does not have a Corporate Rating in effect, then such rating agency not having a Corporate Rating in effect shall be deemed to have established a Corporate Rating in Category 5. If the Corporate Ratings established or deemed to have been established fall within different Categories, the Pricing Schedule shall be based on the higher of the Corporate Ratings, unless one of the Corporate Ratings is two or more Categories lower than the other, in which case the Pricing Schedule shall be determined by reference to the Category next below that of the higher of the Corporate Ratings. Each change in the Pricing Schedule (other than as a result of a change in the rating system of such rating agency) shall be effective as of the date on which a Corporate Rating change is first publically announced by the applicable rating agency, and such change shall apply during the period commencing on the effective date of such change and end on the date immediately preceding the effective date of the next such change.

SCHEDULE 2

PAGE-1

EX-21.1

EXHIBIT 21.1

SUPERIOR ENERGY SERVICES, INC.

List of Subsidiaries

Pursuant to Item 601(b)(21)(ii) of Regulation S-K, the names of other subsidiaries of Superior Energy Services, Inc. are omitted because, considered in the aggregate, they would not constitute a significant subsidiary as of the end of the year covered by this report.

SUBSIDIARY NAME	STATE OF JURISDICTION OF INCORPORATION OR ORGANIZATION
1105 Peters Road, L.L.C.	Louisiana
A&W Water Service, Inc.	Colorado
AWS, Inc.	Delaware
Balance Point Group, B.V.	Netherlands
BTI Services, Inc.	Texas
Complete Energy, LLC	Delaware
Concentric Pipe and Tool Rentals, L.L.C.	Louisiana
CSI Technologies, L.L.C.	Texas
H.B. Rentals, L.C.	Louisiana
Hallin Marine Singapore Pte Ltd.	Singapore
Hamm & Phillips Service Company, Inc	Delaware
NAS Fluids Division Management Co.	Delaware
Integrated Production Services, Inc.	Delaware
International Snubbing Services, L.L.C.	Louisiana
IPS Optimization ULC	Canada
Ingenieria y Tecnologia de Servicios SAS	Colombia
Leed Tool Corporation	Colorado
Monument Well Service Co.	Delaware
Northern Plains Trucking, LLC	Colorado
Oil Tool Rentals Co.	Delaware
Pumpco Energy Services, Inc.	Delaware
Rising Star Services, LP	Texas
Roustabout Specialties, Inc.	Colorado
Servicios Petrotec, S.A. de C.V.	Mexico
Superior Energy Services Group B.V.	Netherlands
SES Canada, ULC	Canada
SESI, L.L.C.	Delaware
Shale Tank Truck, LLC	Texas
Superior Energy Services - North America Services, Inc.	Delaware
Stabil Drill Specialties, L.L.C.	Louisiana
Stride Well Service Company, Inc.	Delaware
Sub-Surface Tools, L.L.C.	Louisiana
Superior Energy Services (International Holdings) Limited	Singapore
Superior Energy International, C.V.	Netherlands
Superior Energy Services (UK) Limited	United Kingdom
Superior Energy Services Cayman, Limited	Cayman Islands
Superior Energy Services do Brasil	Brazil
Superior Energy Services Gibraltar Ltd	Girbraltar
Superior Energy Services, L.L.C.	Louisiana
Superior Energy Services S. A.	Argentina
Superior-Wild Well Energy Services Limited	United Kingdom
Texas CES, Inc.	Texas
Warrior Energy Services Corporation	Delaware
Wild Well Control, Inc.	Texas
Workstrings International Limited	Scotland
Workstrings International, L.L.C.	Louisiana

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Superior Energy Services, Inc:

We consent to the incorporation by reference in the registration statements (No. 333-125316, No. 333-116078, No. 333-101211, No. 333-60860, No. 333-33758, No. 333-43421, No. 333-12175, No. 333-136809, No. 333-146237, No. 333-144394, No. 333-161212, No. 333-174972, No. 333-177679, and 333-189130) on Form S-8 and Form S-4 of Superior Energy Services, Inc. of our reports dated February 27, 2014, with respect to 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 related financial statement schedule, and the effectiveness of internal control over financial reporting as of December 31, 2013, which reports appear in the December 31, 2013 annual report on Form 10-K of Superior Energy Services, Inc.

KPMG, LLP

New Orleans, Louisiana

February 27, 2014

EX-23.2

Exhibit 23.2

February 26, 2014

Mr. Ross Burkenstock

Superior Energy Services, Inc.

601 Poydras Street, Suite 2400

New Orleans, Louisiana 70130

Dear Mr. Burkenstock:

In accordance with your request, we have enclosed our Consent of Independent Petroleum Engineers and Geologists for the Form 10-K Registration Statement to be filed by Superior Energy Services, Inc. with the U.S. Securities and Exchange Commission.

Our Consent is based on our review of the draft provided to us on February 26, 2014, and is conditioned upon there being no further changes made that relate to us in the Form 10-K. In the event your subsequent filings include further changes relating to our reserves estimates or our firm, we would like to review such changes and provide a new Consent letter.

Please send us a copy of the final Form 10-K when filed with the U.S. Securities and Exchange Commission. Please let us know if we can be of further assistance.

Sincerely,

/s/ Danny D. Simmons

Danny D. Simmons, P.E.

President and Chief Operating Officer

RBT:SKB

Enclosure

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

4500 THANKSGIVING TOWER • 1601 ELM STREET • DALLAS, TEXAS 75201-4754 • PH: 214-969-5401 • FAX: 214-969-5411	nsai@nsai-petro.com
1221 LAMAR STREET, SUITE 1200 • HOUSTON, TEXAS 77010-3072 • PH: 713-654-4950 • FAX: 713-654-4951	netherlandsewell.com

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

As independent petroleum engineers, we hereby consent to the use of our name included or incorporated by reference in this Annual Report on Form 10-K of Superior Energy Services, Inc., for the year ended December 31, 2013, and to the incorporation of our report of estimates of reserve and present value of future net reserves as of December 31, 2011 and 2013 (our Reports) into this Annual Report on Form 10-K. In addition, we hereby consent to the use of our name included or incorporated by reference and to the incorporation of our Reports in Superior Energy Services, Inc.’s Registration Statements on Form S-8 (Registration Nos. 333-125316, 333-116078, 333-101211, 333-60860, 333-33758, 333-43421, 333-12175, 333-136809, 333-146237, 333-144394, 333-161212,

333-174972, 333-177679, and 333-189130).

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ Danny D. Simmons
	Danny D. Simmons, P.E.
	President and Chief Operating Officer

Houston, Texas

February 27, 2014

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

EX-31.1

EXHIBIT 31.1

CERTIFICATION PURSUANT TO

RULES 13a-14(a) AND 15d-14(a) UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, David D. Dunlap, President and Chief Executive Officer of Superior Energy Services, Inc., certify that:

1. I have reviewed this annual report on Form 10-K of Superior Energy Services, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 27, 2014

/s/ David. D. Dunlap

David D. Dunlap

President and Chief Executive Officer

Superior Energy Services, Inc.

EX-31.2

EXHIBIT 31.2

CERTIFICATION PURSUANT TO

RULES 13a-14(a) AND 15d-14(a) UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Robert S. Taylor, Executive Vice President, Treasurer and Chief Financial Officer of Superior Energy Services, Inc., certify that:

1. I have reviewed this annual report on Form 10-K of Superior Energy Services, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 27, 2014

/s/ Robert S. Taylor

Robert S. Taylor

Executive Vice President, Treasurer and Chief

Financial Officer

Superior Energy Services, Inc.

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

SECTION 1350 OF TITLE 18 OF THE U.S. CODE

I, David D. Dunlap, President and Chief Executive Officer of Superior Energy Services, Inc. (the “Company”), certify, pursuant to Section 1350 of Title 18 of the U.S. Code, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that:

1. the annual report on Form 10-K of the Company for the year ended December 31, 2013 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

This certificate is being furnished solely for purposes of Section 906 and is not being filed as part of the Report or as a separate disclosure document.

Date: February 27, 2014

/s/ David D. Dunlap

David D. Dunlap

President and Chief Executive Officer

Superior Energy Services, Inc.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

SECTION 1350 OF TITLE 18 OF THE U.S. CODE

I, Robert S. Taylor, Executive Vice President, Treasurer and Chief Financial Officer of Superior Energy Services, Inc. (the “Company”), certify, pursuant to Section 1350 of Title 18 of the U.S. Code, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that:

1. the annual report on Form 10-K of the Company for the year ended December 31, 2013 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

This certificate is being furnished solely for purposes of Section 906 and is not being filed as part of the Report or as a separate disclosure document.

Date: February 27, 2014

/s/ Robert S. Taylor

Robert S. Taylor

Executive Vice President, Treasurer and Chief

Financial Officer

Superior Energy Services, Inc.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.1

Exhibit 99.1

CHAIRMAN & CEO C.H. (SCOTT) REES III PRESIDENT & COO DANNY D. SIMMONS EXECUTIVE VP G. LANCE BINDER EXECUTIVE COMMITTEE P. SCOTT FROST - DALLAS J. CARTER HENSON, JR. - HOUSTON DAN PAUL SMITH - DALLAS JOSEPH J. SPELLMAN - DALLAS THOMAS J. TELLA II - DALLAS

February 19, 2014

Mr. Ross Burkenstock

Superior Energy Services, Inc.

601 Poydras Street, Suite 2400

New Orleans, Louisiana 70130

Dear Mr. Burkenstock:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2013, to the Superior Energy Services, Inc. (Superior) interest in certain oil and gas properties located in the Green Canyon 65 Unit, federal waters in the Gulf of Mexico, as listed in the accompanying tabulations. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Superior. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, except that per-well overhead expenses are excluded for operated properties and future income taxes are excluded for all properties. Definitions are presented immediately following this letter.

We estimate the net reserves and future net revenue to the Superior interest in these properties, as of December 31, 2013, to be:

	Net Reserves						Future Net Revenue (M$)
	Oil		NGL		Gas				Present Worth
Category	(MBBL)		(MBBL)		(MMCF)		Total		at 10%
Proved Developed Producing(1)		1,725.8		17.4		1,485.2		050,443.2		087,259.6
Proved Developed Non-Producing		0,646.6		07.2		0,615.2		057,766.1		038,597.0
Proved Undeveloped		2,139.4		56.8		4,851.8		149,667.6		116,658.0
Total Proved		4,511.8		81.4		6,952.3		257,877.0		242,514.5

Totals may not add because of rounding.

⁽¹⁾  Future net revenue is after deducting estimated abandonment costs.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved reserves. As requested, probable and possible reserves that exist for these properties have not been included. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

This report includes summary projections of reserves and revenue by reserves category. Also included for each reserves category are one-line summaries of reserves, economics, and basic data by lease.

Gross revenue shown in this report is Superior’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Superior’s share of capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been

4500 THANKSGIVING TOWER Ÿ 1601 ELM STREET Ÿ DALLAS, TEXAS 75201-4754 Ÿ PH: 214-969-5401 Ÿ FAX: 214-969-5411	nsai@nsai-petro.com
1221 LAMAR STREET, SUITE 1200 Ÿ HOUSTON, TEXAS 77010-3072 Ÿ PH: 713-654-4950 Ÿ FAX: 713-654-4951	netherlandsewell.com

discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2013. For oil and NGL volumes, the average West Texas Intermediate posted price of $93.42 per barrel is adjusted for quality, transportation fees, and a regional price differential. For gas volumes, the average Henry Hub spot price of $3.670 per MMBTU is adjusted for energy content, transportation fees, and a regional price differential. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $100.76 per barrel of oil, $22.32 per barrel of NGL, and $3.905 per MCF of gas.

Operating costs used in this report are based on operating expense records of SandRidge Energy, Inc. (SandRidge), the operator of these properties. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into per-well costs and per-unit-of-production costs. Since all properties are nonoperated, headquarters general and administrative overhead expenses of Superior are not included. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Sandridge and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Superior’s estimates of the costs to abandon the wells, platforms, and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Superior interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Superior receiving its net revenue interest share of estimated future gross production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be commercially recoverable; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil

and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Superior, Sandridge, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

	Sincerely,
	NETHERLAND, SEWELL & ASSOCIATES, INC.
	Texas Registered Engineering Firm F-2699
	/s/ C.H. (Scott) Rees III
	By:
	C.H. (Scott) Rees III, P.E.
	Chairman and Chief Executive Officer
/s/ Richard B. Talley, Jr.	/s/ Edward C. Roy III
By:	By:
Richard B. Talley, Jr., P.E. 102425	Edward C. Roy III, P.G. 2364
Vice President	Vice President
Date Signed: February 19, 2014	Date Signed: February 19, 2014
RBT:SKB

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

Definitions - Page 1 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

Definitions - Page 2 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

Definitions - Page 3 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous

Definitions - Page 4 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:

a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a. Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.

d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

Definitions - Page 5 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

• The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

• The company’s historical record at completing development of comparable long-term projects;

• The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

• The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

• The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 6 of 6

	SUMMARY PROJECTION OF RESERVES AND REVENUE
	AS OF DECEMBER 31, 2013	SUMMARY - CERTAIN PROPERTIES
SUPERIOR ENERGY SERVICES, INC. INTEREST		LOCATED IN GREEN CANYON 65 UNIT
	TOTAL PROVED RESERVES	IN THE GULF OF MEXICO

PERIOD	GROSS RESERVES						NET RESERVES						AVERAGE PRICES						GROSS REVENUE
ENDING	OIL		NGL		GAS		OIL		NGL		GAS		OIL		NGL		GAS		OIL		NGL		GAS		TOTAL
M-D-Y	MBBL		MBBL		MMCF		MBBL		MBBL		MMCF		$/BBL		$/BBL		$/MCF		M$		M$		M$		M$
12-31-2014		2,845.2		0.0		4,104.4		1,016.1		13.4		1,148.3		100.76		22.32		3.905		102,385.0		300.0		4,484.2		110,632.5
12-31-2015		2,829.8		0.0		7,128.7		1,051.6		25.2		2,155.3		100.76		22.32		3.905		105,964.1		563.1		8,416.6		117,629.5
12-31-2016		2,049.3		0.0		4,863.5		738.6		16.9		1,448.1		100.76		22.32		3.905		74,424.9		378.3		5,654.9		82,541.1
12-31-2017		1,497.0		0.0		3,028.8		521.5		10.3		875.9		100.76		22.32		3.905		52,547.2		228.8		3,420.3		57,812.0
12-31-2018		1,070.7		0.0		1,491.3		355.7		4.6		396.2		100.76		22.32		3.905		35,841.7		103.5		1,547.1		38,745.9
12-31-2019		801.5		0.0		1,064.3		255.9		3.2		272.5		100.76		22.32		3.905		25,787.2		71.2		1,063.9		27,895.1
12-31-2020		641.8		0.0		824.9		201.6		2.4		207.0		100.76		22.32		3.905		20,311.6		54.1		808.3		21,797.5
12-31-2021		507.5		0.0		638.7		161.2		1.9		160.5		100.76		22.32		3.905		16,241.5		41.9		626.9		17,341.8
12-31-2022		324.9		0.0		618.2		145.0		2.3		199.8		100.76		22.32		3.905		14,608.6		52.2		780.1		15,440.8
12-31-2023		144.5		0.0		274.5		64.5		1.0		88.7		100.76		22.32		3.905		6,497.8		23.2		346.4		6,867.4
12-31-2024		0.0		0.0		0.0		0.0		0.0		0.0		0.00		0.00		0.000		0.0		0.0		0.0		0.0
12-31-2025		0.0		0.0		0.0		0.0		0.0		0.0		0.00		0.00		0.000		0.0		0.0		0.0		0.0
12-31-2026		0.0		0.0		0.0		0.0		0.0		0.0		0.00		0.00		0.000		0.0		0.0		0.0		0.0
SUBTOTAL		12,712.3		0.0		24,037.3		4,511.8		81.4		6,952.3		100.76		22.32		3.905		454,609.6		1,816.3		27,148.6		496,703.6
REMAINING		0.0		0.0		0.0		0.0		0.0		0.0		0.00		0.00		0.000		0.0		0.0		0.0		0.0
TOTAL		12,712.3		0.0		24,037.3		4,511.8		81.4		6,952.3		100.76		22.32		3.905		454,609.6		1,816.3		27,148.6		496,703.6
CUM PROD		72,525.6				93,744.7
ULTIMATE		85,238.0				117,782.0

					NET DEDUCTIONS AND EXPENDITURES										FUTURE NET REVENUE
PERIOD	NUMBER OF				TAXES				CAPITAL		ABANDONMENT		OPERATING		UNDISCOUNTED		DISCOUNTED AT 10.000%				PRESENT WORTH PROFILE
ENDING	ACTIVE COMPLETIONS				PRODUCTION		AD VALOREM		COST		COST		EXPENSE		PERIOD		PERIOD		CUM		DISC RATE		CUM PW
M-D-Y	GROSS		NET		M$		M$		M$		M$		M$		M$		M$		M$		%		M$
12-31-2014		14		6.1		0.0		0.0		46,724.5		0.0		12,261.8		51,646.3		48,130.6		48,130.6		8.000		248,513.3
12-31-2015		15		6.8		0.0		0.0		2,191.1		0.0		12,931.4		102,507.0		89,127.6		137,258.2		12.000		236,025.3
12-31-2016		15		6.9		0.0		0.0		13,056.0		0.0		10,711.9		58,773.1		46,226.5		183,484.7		15.000		225,898.8
12-31-2017		14		6.4		0.0		0.0		0.0		0.0		9,064.8		48,747.3		35,072.8		218,557.5		20.000		209,159.8
12-31-2018		12		5.5		0.0		0.0		0.0		0.0		7,686.7		31,059.2		20,283.7		238,841.2		25.000		193,547.6
12-31-2019		10		4.6		0.0		0.0		0.0		0.0		6,847.8		21,047.3		12,503.8		251,345.0		30.000		179,451.8
12-31-2020		10		4.5		0.0		0.0		0.0		0.0		6,313.8		15,483.7		8,355.2		259,700.2		35.000		166,898.0
12-31-2021		10		4.4		0.0		0.0		2,040.0		0.0		6,003.1		9,298.7		4,609.4		264,309.5		40.000		155,769.1
12-31-2022		5		2.8		0.0		0.0		0.0		0.0		5,691.4		9,749.4		4,379.7		268,689.2		45.000		145,903.3
12-31-2023		4		1.8		0.0		0.0		0.0		0.0		4,974.0		1,893.4		782.8		269,472.0		50.000		137,136.0
12-31-2024		0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		269,472.0
12-31-2025		0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		269,472.0
12-31-2026		0		0.0		0.0		0.0		0.0		92,328.4		0.0		-92,328.4		-26,957.5		242,514.5
SUBTOTAL						0.0		0.0		64,011.5		92,328.4		82,486.7		257,877.0		242,514.5		242,514.5
REMAINING						0.0		0.0		0.0		0.0		0.0		0.0		0.0		242,514.5
TOTAL OF 13.0 YRS						0.0		0.0		64,011.5		92,328.4		82,486.7		257,877.0		242,514.5		242,514.5

BASED ON SEC PRICE AND COST PARAMETERS

All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.

Page 1

	SUMMARY PROJECTION OF RESERVES AND REVENUE
	AS OF DECEMBER 31, 2013	SUMMARY - CERTAIN PROPERTIES
SUPERIOR ENERGY SERVICES, INC. INTEREST		LOCATED IN GREEN CANYON 65 UNIT
	PROVED DEVELOPED PRODUCING RESERVES	IN THE GULF OF MEXICO

PERIOD	GROSS RESERVES						NET RESERVES						AVERAGE PRICES						GROSS REVENUE
ENDING	OIL		NGL		GAS		OIL		NGL		GAS		OIL		NGL		GAS		OIL		NGL		GAS		TOTAL
M-D-Y	MBBL		MBBL		MMCF		MBBL		MBBL		MMCF		$/BBL		$/BBL		$/MCF		M$		M$		M$		M$
12-31-2014		1,491.1		0.0		1,678.4		411.8		4.3		364.4		100.76		22.32		3.905		41,497.3		95.2		1,423.0		46,478.9
12-31-2015		1,214.6		0.0		1,357.5		330.9		3.4		290.5		100.76		22.32		3.905		33,337.2		75.9		1,134.3		37,233.0
12-31-2016		1,001.0		0.0		1,114.0		270.8		2.8		236.5		100.76		22.32		3.905		27,288.3		61.8		923.6		30,356.7
12-31-2017		829.9		0.0		920.8		223.8		2.3		194.7		100.76		22.32		3.905		22,550.4		50.9		760.3		24,977.3
12-31-2018		690.5		0.0		764.6		186.1		1.9		161.3		100.76		22.32		3.905		18,747.8		42.2		630.1		20,673.6
12-31-2019		522.9		0.0		542.0		131.6		1.2		103.7		100.76		22.32		3.905		13,260.2		27.1		405.0		14,665.0
12-31-2020		432.2		0.0		443.8		108.1		1.0		83.9		100.76		22.32		3.905		10,889.1		21.9		327.4		11,862.0
12-31-2021		286.9		0.0		297.4		62.7		0.6		50.2		100.76		22.32		3.905		6,318.7		13.1		196.2		6,959.5
12-31-2022		0.0		0.0		0.0		0.0		0.0		0.0		0.00		0.00		0.000		0.0		0.0		0.0		0.0
12-31-2023		0.0		0.0		0.0		0.0		0.0		0.0		0.00		0.00		0.000		0.0		0.0		0.0		0.0
12-31-2024		0.0		0.0		0.0		0.0		0.0		0.0		0.00		0.00		0.000		0.0		0.0		0.0		0.0
12-31-2025		0.0		0.0		0.0		0.0		0.0		0.0		0.00		0.00		0.000		0.0		0.0		0.0		0.0
12-31-2026		0.0		0.0		0.0		0.0		0.0		0.0		0.00		0.00		0.000		0.0		0.0		0.0		0.0
SUBTOTAL		6,469.2		0.0		7,118.5		1,725.8		17.4		1,485.2		100.76		22.32		3.905		173,889.0		388.0		5,799.8		193,206.0
REMAINING		0.0		0.0		0.0		0.0		0.0		0.0		0.00		0.00		0.000		0.0		0.0		0.0		0.0
TOTAL		6,469.2		0.0		7,118.5		1,725.8		17.4		1,485.2		100.76		22.32		3.905		173,889.0		388.0		5,799.8		193,206.0
CUM PROD		59,954.7				77,718.2
ULTIMATE		66,423.8				84,836.7

					NET DEDUCTIONS AND EXPENDITURES										FUTURE NET REVENUE
PERIOD	NUMBER OF				TAXES				CAPITAL		ABANDONMENT		OPERATING		UNDISCOUNTED		DISCOUNTED AT 10.000%				PRESENT WORTH PROFILE
ENDING	ACTIVE COMPLETIONS				PRODUCTION		AD VALOREM		COST		COST		EXPENSE		PERIOD		PERIOD		CUM		DISC RATE		CUM PW
M-D-Y	GROSS		NET		M$		M$		M$		M$		M$		M$		M$		M$		%		M$
12-31-2014		12		4.7		0.0		0.0		0.0		0.0		7,899.6		38,579.3		36,873.7		36,873.7		8.000		84,788.1
12-31-2015		10		4.0		0.0		0.0		0.0		0.0		7,221.6		30,011.4		26,073.1		62,946.8		12.000		88,499.0
12-31-2016		9		3.7		0.0		0.0		0.0		0.0		6,771.0		23,585.6		18,627.4		81,574.2		15.000		88,765.9
12-31-2017		9		3.8		0.0		0.0		0.0		0.0		6,473.8		18,503.5		13,285.5		94,859.8		20.000		86,728.6
12-31-2018		9		3.9		0.0		0.0		0.0		0.0		6,236.0		14,437.6		9,424.4		104,284.2		25.000		83,257.1
12-31-2019		7		3.2		0.0		0.0		0.0		0.0		5,740.0		8,925.0		5,307.6		109,591.8		30.000		79,342.6
12-31-2020		7		3.1		0.0		0.0		0.0		0.0		5,420.3		6,441.7		3,475.8		113,067.6		35.000		75,442.2
12-31-2021		6		2.6		0.0		0.0		0.0		0.0		4,672.0		2,287.6		1,149.5		114,217.1		40.000		71,754.5
12-31-2022		0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		114,217.1		45.000		68,353.6
12-31-2023		0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		114,217.1		50.000		65,254.0
12-31-2024		0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		114,217.1
12-31-2025		0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		114,217.1
12-31-2026		0		0.0		0.0		0.0		0.0		92,328.4		0.0		-92,328.4		-26,957.5		87,259.6
SUBTOTAL						0.0		0.0		0.0		92,328.4		50,434.3		50,443.2		87,259.6		87,259.6
REMAINING						0.0		0.0		0.0		0.0		0.0		0.0		0.0		87,259.6
TOTAL OF 13.0 YRS						0.0		0.0		0.0		92,328.4		50,434.3		50,443.2		87,259.6		87,259.6

BASED ON SEC PRICE AND COST PARAMETERS

All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.

Page 2

	SUMMARY PROJECTION OF RESERVES AND REVENUE
	AS OF DECEMBER 31, 2013	SUMMARY - CERTAIN PROPERTIES
SUPERIOR ENERGY SERVICES, INC. INTEREST		LOCATED IN GREEN CANYON 65 UNIT
	PROVED DEVELOPED NON-PRODUCING RESERVES	IN THE GULF OF MEXICO

PERIOD	GROSS RESERVES						NET RESERVES						AVERAGE PRICES						GROSS REVENUE
ENDING	OIL		NGL		GAS		OIL		NGL		GAS		OIL		NGL		GAS		OIL		NGL		GAS		TOTAL
M-D-Y	MBBL		MBBL		MMCF		MBBL		MBBL		MMCF		$/BBL		$/BBL		$/MCF		M$		M$		M$		M$
12-31-2014		45.3		0.0		45.0		20.2		0.2		14.5		100.76		22.32		3.905		2,035.8		3.8		56.8		2,096.3
12-31-2015		309.3		0.0		351.6		138.0		1.3		113.6		100.76		22.32		3.905		13,908.2		29.7		443.6		14,381.5
12-31-2016		245.0		0.0		273.8		109.3		1.0		88.5		100.76		22.32		3.905		11,015.7		23.1		345.4		11,384.2
12-31-2017		168.6		0.0		188.2		75.2		0.7		60.8		100.76		22.32		3.905		7,581.4		15.9		237.5		7,834.7
12-31-2018		107.9		0.0		121.3		48.2		0.5		39.2		100.76		22.32		3.905		4,853.0		10.2		153.0		5,016.3
12-31-2019		75.0		0.0		84.1		33.5		0.3		27.2		100.76		22.32		3.905		3,373.1		7.1		106.1		3,486.4
12-31-2020		56.0		0.0		62.2		25.0		0.2		20.1		100.76		22.32		3.905		2,517.2		5.3		78.5		2,601.0
12-31-2021		103.8		0.0		107.8		46.3		0.4		34.8		100.76		22.32		3.905		4,666.3		9.1		136.0		4,811.4
12-31-2022		235.1		0.0		445.9		104.9		1.7		144.1		100.76		22.32		3.905		10,569.5		37.6		562.7		11,169.8
12-31-2023		103.1		0.0		224.1		46.0		0.8		72.4		100.76		22.32		3.905		4,633.7		18.9		282.7		4,935.4
SUBTOTAL		1,449.0		0.0		1,903.9		646.6		7.2		615.2		100.76		22.32		3.905		65,153.9		160.7		2,402.4		67,717.0
REMAINING		0.0		0.0		0.0		0.0		0.0		0.0		0.00		0.00		0.000		0.0		0.0		0.0		0.0
TOTAL		1,449.0		0.0		1,903.9		646.6		7.2		615.2		100.76		22.32		3.905		65,153.9		160.7		2,402.4		67,717.0
CUM PROD		1.5				1.4
ULTIMATE		1,450.5				1,905.3

					NET DEDUCTIONS AND EXPENDITURES										FUTURE NET REVENUE
PERIOD	NUMBER OF				TAXES				CAPITAL		ABANDONMENT		OPERATING		UNDISCOUNTED		DISCOUNTED AT 10.000%				PRESENT WORTH PROFILE
ENDING	ACTIVE COMPLETIONS				PRODUCTION		AD VALOREM		COST		COST		EXPENSE		PERIOD		PERIOD		CUM		DISC RATE		CUM PW
M-D-Y	GROSS		NET		M$		M$		M$		M$		M$		M$		M$		M$		%		M$
12-31-2014		0		0.0		0.0		0.0		0.0		0.0		127.0		1,969.3		1,855.6		1,855.6		8.000		41,490.5
12-31-2015		2		0.8		0.0		0.0		2,191.1		0.0		1,052.9		11,137.6		9,637.2		11,492.9		12.000		36,034.8
12-31-2016		2		1.0		0.0		0.0		0.0		0.0		900.4		10,483.8		8,289.5		19,782.3		15.000		32,709.0
12-31-2017		2		1.0		0.0		0.0		0.0		0.0		670.3		7,164.5		5,149.3		24,931.6		20.000		28,244.1
12-31-2018		1		0.7		0.0		0.0		0.0		0.0		432.2		4,584.1		2,998.7		27,930.3		25.000		24,772.1
12-31-2019		1		0.5		0.0		0.0		0.0		0.0		305.7		3,180.7		1,888.3		29,818.6		30.000		22,011.3
12-31-2020		1		0.5		0.0		0.0		0.0		0.0		248.7		2,352.3		1,269.5		31,088.0		35.000		19,772.5
12-31-2021		2		0.9		0.0		0.0		2,040.0		0.0		448.5		2,322.8		1,152.2		32,240.3		40.000		17,925.6
12-31-2022		3		1.7		0.0		0.0		0.0		0.0		1,011.3		10,158.5		4,558.1		36,798.3		45.000		16,378.9
12-31-2023		2		1.2		0.0		0.0		0.0		0.0		522.9		4,412.5		1,798.6		38,597.0		50.000		15,066.4
SUBTOTAL						0.0		0.0		4,231.1		0.0		5,719.8		57,766.1		38,597.0		38,597.0
REMAINING						0.0		0.0		0.0		0.0		0.0		0.0		0.0		38,597.0
TOTAL OF 10.0 YRS						0.0		0.0		4,231.1		0.0		5,719.8		57,766.1		38,597.0		38,597.0

BASED ON SEC PRICE AND COST PARAMETERS

All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.

Page 3

	SUMMARY PROJECTION OF RESERVES AND REVENUE
	AS OF DECEMBER 31, 2013	SUMMARY - CERTAIN PROPERTIES
SUPERIOR ENERGY SERVICES, INC. INTEREST		LOCATED IN GREEN CANYON 65 UNIT
	PROVED UNDEVELOPED RESERVES	IN THE GULF OF MEXICO

PERIOD	GROSS RESERVES						NET RESERVES						AVERAGE PRICES						GROSS REVENUE
ENDING	OIL		NGL		GAS		OIL		NGL		GAS		OIL		NGL		GAS		OIL		NGL		GAS		TOTAL
M-D-Y	MBBL		MBBL		MMCF		MBBL		MBBL		MMCF		$/BBL		$/BBL		$/MCF		M$		M$		M$		M$
12-31-2014		1,308.8		0.0		2,381.0		584.1		9.0		769.4		100.76		22.32		3.905		58,851.8		201.0		3,004.5		62,057.3
12-31-2015		1,305.9		0.0		5,419.7		582.8		20.5		1,751.3		100.76		22.32		3.905		58,718.8		457.5		6,838.7		66,015.0
12-31-2016		803.3		0.0		3,475.7		358.5		13.1		1,123.1		100.76		22.32		3.905		36,120.9		293.4		4,385.8		40,800.1
12-31-2017		498.5		0.0		1,919.8		222.5		7.3		620.4		100.76		22.32		3.905		22,415.4		162.1		2,422.5		25,000.0
12-31-2018		272.2		0.0		605.4		121.5		2.3		195.6		100.76		22.32		3.905		12,240.9		51.1		764.0		13,056.0
12-31-2019		203.6		0.0		438.1		90.8		1.7		141.6		100.76		22.32		3.905		9,153.9		37.0		552.8		9,743.7
12-31-2020		153.6		0.0		318.8		68.5		1.2		103.0		100.76		22.32		3.905		6,905.2		26.9		402.3		7,334.5
12-31-2021		116.9		0.0		233.5		52.2		0.9		75.5		100.76		22.32		3.905		5,256.6		19.7		294.7		5,571.0
12-31-2022		89.8		0.0		172.3		40.1		0.7		55.7		100.76		22.32		3.905		4,039.1		14.5		217.4		4,271.0
12-31-2023		41.5		0.0		50.5		18.5		0.2		16.3		100.76		22.32		3.905		1,864.1		4.3		63.7		1,932.0
SUBTOTAL		4,794.1		0.0		15,014.9		2,139.4		56.8		4,851.8		100.76		22.32		3.905		215,566.7		1,267.6		18,946.4		235,780.6
REMAINING		0.0		0.0		0.0		0.0		0.0		0.0		0.00		0.00		0.000		0.0		0.0		0.0		0.0
TOTAL		4,794.1		0.0		15,014.9		2,139.4		56.8		4,851.8		100.76		22.32		3.905		215,566.7		1,267.6		18,946.4		235,780.6
CUM PROD		12,569.5				16,025.1
ULTIMATE		17,363.7				31,040.0

					NET DEDUCTIONS AND EXPENDITURES										FUTURE NET REVENUE
PERIOD	NUMBER OF				TAXES				CAPITAL		ABANDONMENT		OPERATING		UNDISCOUNTED		DISCOUNTED AT 10.000%				PRESENT WORTH PROFILE
ENDING	ACTIVE COMPLETIONS				PRODUCTION		AD VALOREM		COST		COST		EXPENSE		PERIOD		PERIOD		CUM		DISC RATE		CUM PW
M-D-Y	GROSS		NET		M$		M$		M$		M$		M$		M$		M$		M$		%		M$
12-31-2014		2		1.1		0.0		0.0		46,724.5		0.0		4,235.1		11,097.7		9,401.2		9,401.2		8.000		122,234.7
12-31-2015		4		2.0		0.0		0.0		0.0		0.0		4,657.0		61,358.0		53,417.3		62,818.5		12.000		111,491.5
12-31-2016		4		2.3		0.0		0.0		13,056.0		0.0		3,040.5		24,703.6		19,309.6		82,128.1		15.000		104,424.0
12-31-2017		3		1.7		0.0		0.0		0.0		0.0		1,920.7		23,079.3		16,638.0		98,766.1		20.000		94,187.0
12-31-2018		2		1.0		0.0		0.0		0.0		0.0		1,018.5		12,037.5		7,860.7		106,626.8		25.000		85,518.4
12-31-2019		2		1.0		0.0		0.0		0.0		0.0		802.1		8,941.6		5,307.9		111,934.7		30.000		78,097.8
12-31-2020		2		1.0		0.0		0.0		0.0		0.0		644.8		6,689.7		3,609.9		115,544.6		35.000		71,683.2
12-31-2021		2		1.0		0.0		0.0		0.0		0.0		882.6		4,688.4		2,307.6		117,852.2		40.000		66,089.0
12-31-2022		2		1.0		0.0		0.0		0.0		0.0		4,680.1		-409.1		-178.4		117,673.9		45.000		61,170.8
12-31-2023		1		0.6		0.0		0.0		0.0		0.0		4,451.2		-2,519.1		-1,015.9		116,658.0		50.000		56,815.7
SUBTOTAL						0.0		0.0		59,780.5		0.0		26,332.5		149,667.6		116,658.0		116,658.0
REMAINING						0.0		0.0		0.0		0.0		0.0		0.0		0.0		116,658.0
TOTAL OF 10.0 YRS						0.0		0.0		59,780.5		0.0		26,332.5		149,667.6		116,658.0		116,658.0

BASED ON SEC PRICE AND COST PARAMETERS

All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.

Page 4

	RESERVES AND ECONOMICS
	AS OF DECEMBER 31, 2013	SUMMARY - CERTAIN PROPERTIES
SUPERIOR ENERGY SERVICES, INC. INTEREST		LOCATED IN GREEN CANYON 65 UNIT
	PROVED DEVELOPED PRODUCING RESERVES	IN THE GULF OF MEXICO

		GROSS RESERVES						NET RESERVES						GROSS REVENUE						TOTAL		NET CAP		ABDNMNT		OPERATING		NET		CUM P.W.
ACCOUNT		OIL		NGL		GAS		OIL		NGL		GAS		OIL		NGL		GAS		TAXES		COST		COST		EXPENSE		REVENUE		10.000%
NUMBER	LEASE NAME	MBBL		MBBL		MMCF		MBBL		MBBL		MMCF		M$		M$		M$		M$		M$		M$		M$		M$		M$
FEDERAL OFFSHORE
GREEN CANYON 65 FIELD
SEO0233	GC65 A38ST J14		3.6		0.0		3.6		1.6		0.0		1.2		162.5		0.3		4.6		0.0		0.0		0.0		73.2		94.2		92.4
SEO0234	GC65 A59 I3 RA		283.9		0.0		425.8		126.7		1.6		137.6		12,763.7		35.9		537.3		0.0		0.0		0.0		1,526.9		11,810.0		8,605.7
SEO0235	GC65 A60 J1		10.5		0.0		18.9		4.7		0.1		6.1		473.2		1.6		23.9		0.0		0.0		0.0		150.2		348.5		335.1
SEO0238	GC108 A17 J12		1,539.4		0.0		1,539.4		687.0		5.8		497.4		69,217.9		130.0		1,942.5		0.0		0.0		0.0		5,258.9		66,031.4		50,675.1
SEO0236	GC109 A4 I1		4.6		0.0		4.1		2.0		0.0		1.3		204.7		0.3		5.2		0.0		0.0		0.0		131.3		78.9		75.8
SEO0237	GC109 A10 I11		348.4		0.0		313.5		155.5		1.2		101.3		15,664.6		26.5		395.6		0.0		0.0		0.0		1,704.9		14,381.7		11,518.5
SEO0239	GC109 A18ST3J14		301.0		0.0		602.1		134.3		2.3		194.6		13,536.2		50.8		759.7		0.0		0.0		0.0		1,358.4		12,988.4		10,696.0
SEO1375	GC109 A21 J1 4		533.5		0.0		800.3		238.1		3.0		258.6		23,988.9		67.6		1,009.8		0.0		0.0		0.0		2,070.2		22,996.1		19,429.9
SEO0241	GC109 A37 I3		542.3		0.0		596.6		242.0		2.3		192.8		24,386.3		50.4		752.8		0.0		0.0		0.0		2,298.3		22,891.1		17,019.8
SEO0242	GC243 SS2 ASPEN		274.1		0.0		274.1		13.3		0.1		9.6		1,338.0		2.5		37.5		0.0		0.0		0.0		0.0		1,378.1		1,071.1
SEO0243	GC243 SS4 ASPEN		1,750.8		0.0		1,750.8		84.8		0.7		61.4		8,547.2		16.0		239.9		0.0		0.0		0.0		0.0		8,803.1		6,704.8
SEO0244	GC243 SS5 ASPEN		877.1		0.0		789.4		35.8		0.3		23.3		3,605.7		6.1		91.1		0.0		0.0		0.0		0.0		3,702.8		2,834.6
SEO0245	PHA ANGUS FIELD		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		657.5		3,210.8		2,597.7
SEO0246	PHA DROSHKY FIELD		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		657.5		6,278.8		4,989.1
SEO0247	PHA LORIEN FIELD		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		505.2		550.8		468.6
SEO0248	PHA MANATEE FIELD		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0
SEO0249	PHA TROIKA FIELD		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		512.1		756.5		644.5
SEO0250	FIXED EXP PDP		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		33,529.6		-33,529.6		-23,541.5
SEO1484	BULLWINKLE ABDN		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		92,328.4		0.0		-92,328.4		-26,957.5
FIELD TOTAL			6,469.2		0.0		7,118.5		1,725.8		17.4		1,485.2		173,889.0		388.0		5,799.8		0.0		0.0		92,328.4		50,434.3		50,443.2		87,259.6
TOTAL FEDERAL OFFSHORE			6,469.2		0.0		7,118.5		1,725.8		17.4		1,485.2		173,889.0		388.0		5,799.8		0.0		0.0		92,328.4		50,434.3		50,443.2		87,259.6
TOTAL ALL LEASES			6,469.2		0.0		7,118.5		1,725.8		17.4		1,485.2		173,889.0		388.0		5,799.8		0.0		0.0		92,328.4		50,434.3		50,443.2		87,259.6

BASED ON SEC PRICE AND COST PARAMETERS

All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.

Page 5

	BASIC DATA
	AS OF DECEMBER 31, 2013	SUMMARY - CERTAIN PROPERTIES
SUPERIOR ENERGY SERVICES, INC. INTEREST		LOCATED IN GREEN CANYON 65 UNIT
	PROVED DEVELOPED PRODUCING RESERVES	IN THE GULF OF MEXICO

						GROSS ULTIMATE				WORKING				REVENUE				OIL/COND				NGL				GAS
LEASE		COMPLTNS				OIL/COND		GAS		INTEREST				INTEREST				$/BBL				$/BBL				$/MCF				LIFE
NUMBER	LEASE NAME	OIL		GAS		MBBL		MMCF		START		END		START		END		START		END		START		END		START		END		YRS
FEDERAL OFFSHORE
GREEN CANYON 65 FIELD
SR1130019257	GC65 A38ST J14		1		0		2,147.3		2,383.1		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		0.8
SR1130019258	GC65 A59 I3 RA		1		0		4,075.3		5,791.7		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		7.9
SR1130019261	GC65 A60 J1		1		0		212.4		243.6		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		1.4
SR1130019269	GC108 A17 J12		1		0		7,332.7		16,781.9		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		7.4
SR1130019265	GC109 A4 I1		1		0		44.1		29.7		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		1.4
SR1130019267	GC109 A10 I11		1		0		621.4		536.1		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		7.9
SR1130019271	GC109 A18ST3J14		1		0		2,433.1		4,507.7		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		5.1
SR1130019264	GC109 A21 J1 4		1		0		616.7		953.0		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		5.3
SR1130019275	GC109 A37 I3		1		0		2,675.6		2,793.6		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		7.9
SR1130019278	GC243 SS2 ASPEN		1		0		8,032.9		7,540.6		0.000		0.000		4.845		4.845		100.761		100.761		22.322		22.322		3.905		3.905		7.9
SR1130019279	GC243 SS4 ASPEN		1		0		12,843.2		12,921.9		0.000		0.000		4.845		4.845		100.761		100.761		22.322		22.322		3.905		3.905		7.9
SR1130019280	GC243 SS5 ASPEN		1		0		4,344.8		4,388.1		0.000		0.000		4.080		4.080		100.761		100.761		22.322		22.322		3.905		3.905		7.9
SR1130019281	PHA ANGUS FIELD		0		0		2,474.3		4,456.5		51.000		51.000		44.625		44.625		0.000		0.000		0.000		0.000		0.000		0.000		7.9
SR1130019282	PHA DROSHKY FIELD		0		0		13,923.7		14,711.7		51.000		51.000		44.625		44.625		0.000		0.000		0.000		0.000		0.000		0.000		7.9
SR1130019283	PHA LORIEN FIELD		0		0		1,409.0		1,969.9		51.000		51.000		44.625		44.625		0.000		0.000		0.000		0.000		0.000		0.000		6.1
SR1130019284	PHA MANATEE FIELD		0		0		2,018.0		3,200.4		0.000		0.000		0.000		0.000		0.000		0.000		0.000		0.000		0.000		0.000		0.0
SR1130019285	PHA TROIKA FIELD		0		0		1,219.4		1,627.3		51.000		51.000		44.625		44.625		0.000		0.000		0.000		0.000		0.000		0.000		6.2
SR1130019286	FIXED EXP PDP		0		0		0.0		0.0		0.000		0.000		0.000		0.000		0.000		0.000		0.000		0.000		0.000		0.000		7.9
SR1130019289	BULLWINKLE ABDN		0		0		0.0		0.0		0.000		0.000		0.000		0.000		0.000		0.000		0.000		0.000		0.000		0.000		13.0
FIELD TOTAL			12		0		66,423.8		84,836.7
TOTAL FEDERAL OFFSHORE			12		0		66,423.8		84,836.7
TOTAL ALL LEASES			12		0		66,423.8		84,836.7

BASED ON SEC PRICE AND COST PARAMETERS

All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.

Page 6

	RESERVES AND ECONOMICS
	AS OF DECEMBER 31, 2013	SUMMARY - CERTAIN PROPERTIES
SUPERIOR ENERGY SERVICES, INC. INTEREST		LOCATED IN GREEN CANYON 65 UNIT
	PROVED DEVELOPED NON-PRODUCING RESERVES	IN THE GULF OF MEXICO

		GROSS RESERVES						NET RESERVES						GROSS REVENUE						TOTAL		NET CAP		ABDNMNT		OPERATING		NET		CUM P.W.
ACCOUNT		OIL		NGL		GAS		OIL		NGL		GAS		OIL		NGL		GAS		TAXES		COST		COST		EXPENSE		REVENUE		10.000%
NUMBER	LEASE NAME	MBBL		MBBL		MMCF		MBBL		MBBL		MMCF		M$		M$		M$		M$		M$		M$		M$		M$		M$
FEDERAL OFFSHORE
GREEN CANYON 65 FIELD
SEO0871	GC65 A59 I1 RA		218.8		0.0		546.9		97.6		2.1		176.7		9,837.2		46.2		690.2		0.0		2,040.0		0.0		856.8		7,676.8		3,239.5
SEO0874	GC108 A17 J12 IPBP		381.1		0.0		381.1		170.1		1.4		123.2		17,138.0		32.2		480.9		0.0		0.0		0.0		1,182.9		16,468.2		10,941.4
SEO0873	GC109 A3 I3A		127.0		0.0		127.0		56.7		0.5		41.0		5,710.5		10.7		160.3		0.0		2,191.1		0.0		618.4		3,072.0		2,233.1
SEO2114	GC109 A10 I11 EXT		35.9		0.0		32.3		16.0		0.1		10.5		1,615.9		2.7		40.8		0.0		0.0		0.0		281.1		1,378.4		864.6
SEO2113	GC109 A21 J1 4 EXT		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0
SEO1376	GC109 A32ST1 BP2		617.0		0.0		740.4		275.3		2.8		239.2		27,743.2		62.5		934.3		0.0		0.0		0.0		2,447.0		26,293.0		19,914.6
SEO2115	GC109 A37 I3 EXT		69.1		0.0		76.1		30.9		0.3		24.6		3,109.1		6.4		96.0		0.0		0.0		0.0		333.8		2,877.8		1,403.7
FIELD TOTAL			1,449.0		0.0		1,903.9		646.6		7.2		615.2		65,153.9		160.7		2,402.4		0.0		4,231.1		0.0		5,719.8		57,766.1		38,597.0
TOTAL FEDERAL OFFSHORE			1,449.0		0.0		1,903.9		646.6		7.2		615.2		65,153.9		160.7		2,402.4		0.0		4,231.1		0.0		5,719.8		57,766.1		38,597.0
TOTAL ALL LEASES			1,449.0		0.0		1,903.9		646.6		7.2		615.2		65,153.9		160.7		2,402.4		0.0		4,231.1		0.0		5,719.8		57,766.1		38,597.0

BASED ON SEC PRICE AND COST PARAMETERS

All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.

Page 7

	BASIC DATA
	AS OF DECEMBER 31, 2013	SUMMARY - CERTAIN PROPERTIES
SUPERIOR ENERGY SERVICES, INC. INTEREST		LOCATED IN GREEN CANYON 65 UNIT
	PROVED DEVELOPED NON-PRODUCING RESERVES	IN THE GULF OF MEXICO

						GROSS ULTIMATE				WORKING				REVENUE				OIL/COND				NGL				GAS
LEASE		COMPLTNS				OIL/COND		GAS		INTEREST				INTEREST				$/BBL				$/BBL				$/MCF				LIFE
NUMBER	LEASE NAME	OIL		GAS		MBBL		MMCF		START		END		START		END		START		END		START		END		START		END		YRS
FEDERAL OFFSHORE
GREEN CANYON 65 FIELD
SR1130019259	GC65 A59 I1 RA		1		0		218.8		546.9		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		10.0
SR1130019270	GC108 A17 J12 IPBP		0		0		382.0		382.0		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		8.4
SR1130019263	GC109 A3 I3A		1		0		127.0		127.0		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		4.3
OAO1E21HQ3	GC109 A10 I11 EXT		0		0		36.4		32.8		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		10.0
OAO1E25HP3	GC109 A21 J1 4 EXT		0		0		0.0		0.0		51.000		51.000		44.625		44.625		100.761		100.761		0.000		0.000		3.905		3.905		5.3
SR1130019272	GC109 A32ST1 BP2		1		0		617.0		740.4		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		7.9
OAO1E2VIR3	GC109 A37 I3 EXT		0		0		69.3		76.3		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		9.4
FIELD TOTAL			3		0		1,450.5		1,905.3
TOTAL FEDERAL OFFSHORE			3		0		1,450.5		1,905.3
TOTAL ALL LEASES			3		0		1,450.5		1,905.3

BASED ON SEC PRICE AND COST PARAMETERS

All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.

Page 8

	RESERVES AND ECONOMICS
	AS OF DECEMBER 31, 2013	SUMMARY - CERTAIN PROPERTIES
SUPERIOR ENERGY SERVICES, INC. INTEREST		LOCATED IN GREEN CANYON 65 UNIT
	PROVED UNDEVELOPED RESERVES	IN THE GULF OF MEXICO

		GROSS RESERVES						NET RESERVES						GROSS REVENUE						TOTAL		NET CAP		ABDNMNT		OPERATING		NET		CUM P.W.
ACCOUNT		OIL		NGL		GAS		OIL		NGL		GAS		OIL		NGL		GAS		TAXES		COST		COST		EXPENSE		REVENUE		10.000%
NUMBER	LEASE NAME	MBBL		MBBL		MMCF		MBBL		MBBL		MMCF		M$		M$		M$		M$		M$		M$		M$		M$		M$
FEDERAL OFFSHORE
GREEN CANYON 65 FIELD
SEO0872	GC65 A20 J1 2		555.0		0.0		749.3		247.7		2.8		242.1		24,955.4		63.3		945.4		0.0		5,763.0		0.0		1,899.8		18,301.2		16,036.7
SEO1428	GC65 A24 J1/J2		2,254.0		0.0		6,198.5		1,005.8		23.4		2,002.9		101,350.2		523.3		7,821.5		0.0		16,150.0		0.0		7,902.1		85,642.9		64,379.6
SEO1430	GC65 A26 J		670.0		0.0		6,700.0		299.0		25.3		2,165.0		30,126.3		565.6		8,454.3		0.0		18,997.5		0.0		2,822.0		17,326.7		12,132.6
SEO1427	GC65 A44ST H		795.0		0.0		795.0		354.8		3.0		256.9		35,746.9		67.1		1,003.2		0.0		5,814.0		0.0		2,688.5		28,314.6		25,137.7
SEO0240	GC109 A35 J14		520.1		0.0		572.2		232.1		2.2		184.9		23,388.0		48.3		722.0		0.0		13,056.0		0.0		2,196.6		8,905.7		2,734.5
SEO1377	FIXED EXP PUD		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		8,823.6		-8,823.6		-3,763.1
FIELD TOTAL			4,794.1		0.0		15,014.9		2,139.4		56.8		4,851.8		215,566.7		1,267.6		18,946.4		0.0		59,780.5		0.0		26,332.6		149,667.6		116,658.0
TOTAL FEDERAL OFFSHORE			4,794.1		0.0		15,014.9		2,139.4		56.8		4,851.8		215,566.7		1,267.6		18,946.4		0.0		59,780.5		0.0		26,332.6		149,667.6		116,658.0
TOTAL ALL LEASES			4,794.1		0.0		15,014.9		2,139.4		56.8		4,851.8		215,566.7		1,267.6		18,946.4		0.0		59,780.5		0.0		26,332.6		149,667.6		116,658.0

BASED ON SEC PRICE AND COST PARAMETERS

All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.

Page 9

	BASIC DATA
	AS OF DECEMBER 31, 2013	SUMMARY - CERTAIN PROPERTIES
SUPERIOR ENERGY SERVICES, INC. INTEREST		LOCATED IN GREEN CANYON 65 UNIT
	PROVED UNDEVELOPED RESERVES	IN THE GULF OF MEXICO

						GROSS ULTIMATE				WORKING				REVENUE				OIL/COND				NGL				GAS
LEASE		COMPLTNS				OIL/COND		GAS		INTEREST				INTEREST				$/BBL				$/BBL				$/MCF				LIFE
NUMBER	LEASE NAME	OIL		GAS		MBBL		MMCF		START		END		START		END		START		END		START		END		START		END		YRS
FEDERAL OFFSHORE
GREEN CANYON 65 FIELD
SR1130019262	GC65 A20 J1 2		1		0		555.0		749.3		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		2.9
SR1130021163	GC65 A24 J1/J2		1		0		2,254.0		6,198.5		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		9.1
SR1130023000	GC65 A26 J		0		1		670.0		6,700.0		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		3.8
SR1130021162	GC65 A44ST H		0		1		795.0		795.0		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		3.6
SR1130019274	GC109 A35 J14		1		0		13,089.7		16,597.2		51.000		51.000		44.625		44.625		100.761		100.761		22.322		22.322		3.905		3.905		10.0
SR1130019287	FIXED EXP PUD		0		0		0.0		0.0		0.000		0.000		0.000		0.000		0.000		0.000		0.000		0.000		0.000		0.000		10.0
FIELD TOTAL			3		2		17,363.7		31,040.0
TOTAL FEDERAL OFFSHORE			3		2		17,363.7		31,040.0
TOTAL ALL LEASES			3		2		17,363.7		31,040.0

BASED ON SEC PRICE AND COST PARAMETERS

All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.

Page 10

XML

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Results Of Operations For Oil And Gas Producing Activities) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues
Sales	$ 47,050	$ 57,757	$ 54,442
Production costs	9,876	12,332	12,293
Depreciation, depletion and amortization	12,032	9,818	11,928
Income before income taxes	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
Equity Method Investments [Member]
Revenues
Sales			53,181
Production costs			22,034
Depreciation, depletion and amortization			18,449
Income before income taxes			12,698
Income tax expenses			4,533
Results of operations from producing activities (excluding corporate overhead)			$ 8,165

XML

Summary Of Significant Accounting Policies (Summary Of The Activity For Company's Decommissioning Liabilities) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Summary Of Significant Accounting Policies [Abstract]
Decommissioning liabilities, December 31, 2011 and 2010, 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

XML

Summary Of Significant Accounting Policies (Goodwill) (Narrative) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2011
Summary Of Significant Accounting Policies [Abstract]
Percentage of the discounted cash flow method for estimation of fair value of reporting units	80.00%
Percentage of the public company guideline method for estimation of fair value of reporting units	20.00%
Goodwill, Impairment Loss	$ 91,016	$ 10,334

XML

Property, Plant and Equipment (Summary Of Property, Plant And Equipment) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 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
Buildings, Improvements And Leasehold Improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	284,273	230,457
Marine Vessels And Equipment [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	137,955	199,819
Machinery And Equipment [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	3,864,599	3,500,112
Automobiles, trucks, tractors and trailers [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	64,102	60,805
Furniture And Fixtures [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	72,563	59,124
Construction in Progress [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	211,017	410,425
Land [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	56,786	59,824
Oil and Gas Properties [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 137,910	$ 77,285

XML

Summary Of Significant Accounting Policies (Earnings (Loss) Per Share) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Summary Of Significant Accounting Policies [Abstract]
Antidilutive securities excluded from computation of earnings per share, share	2,100,000	540,000

XML

Stock-Based And Long-Term Compensation (Summary Of Stock Option Activity) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Summarization of stock option activity
Number of options outstanding, beginning	4,923,102
Number of options granted	406,185
Number of options exercised	(470,712)
Number of options forfeited	(1,199)
Number of options outstanding, ending	4,857,376	4,923,102
Number of options exercisable	4,320,878
Number of options expected to vest	536,498
Weighted average option price outstanding, beginning	$ 20.52
Weighted average option price granted	$ 23.03
Weighted average option price excercised	$ 13.31
Weighted average option price forfeited	$ 20.01
Weighted average option price outstanding, ending	$ 21.43	$ 20.52
Weighted average option price exercisable		$ 21.06
Weighted average option price expected to vest	$ 24.33
Weighted average remaining contractual term, outstanding	4 years 9 months 18 days	5 years 3 months 18 days
Weighted average remaining contractual term, exercisable	5 years 1 month 6 days
Weighted average remaining contractual term, expected to vest	8 years 4 months 24 days
Aggregate intrinsic value, outstanding	$ 29,990	$ 16,334
Aggregate intrinsic value, exercisable	28,536
Aggregate intrinsic value, expected to vest	$ 1,454

XML

Interim Financial Information (Unaudited) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Selected Quarterly Financial Information [Abstract]
Revenues	$ 1,128,017	$ 1,188,615	$ 1,159,713	$ 1,135,479	$ 1,178,247	$ 1,179,665	$ 1,243,319	$ 966,837	$ 4,611,824	$ 4,568,068	$ 1,964,332
Costs and Expenses [Abstract]
Cost of services, rentals and sales	734,428	748,052	711,883	707,487	722,814	708,608	711,284	546,767	2,901,850	2,689,473	1,046,409
Depreciation, depletion, amortization and accretion	163,301	158,006	154,987	149,634	143,009	128,160	135,516	102,596	625,928	509,281	244,915
Gross Profit	230,288	282,557	292,843	278,358	312,424	342,897	396,519	317,474
Net income from continuing operations	(313,539)	69,835	68,559	63,727	76,275	93,887	142,823	70,157
Income (loss) from discontinued operations, net of tax							$ (970)	$ (16,237)		$ (17,207)	$ (16,835)
Earnings Per Share [Abstract]
Continuing operations, basic	$ (1.97)	$ 0.44	$ 0.43	$ 0.40	$ 0.50	$ 0.60	$ 0.91	$ 0.56	$ (0.70)	$ 2.57	$ 2.00
Continuing operations, diluted	$ (1.97)	$ 0.43	$ 0.43	$ 0.40	$ 0.50	$ 0.59	$ 0.90	$ 0.55	$ (0.70)	$ 2.54	$ 1.97
Discontinued operations, basic							$ (0.01)	$ (0.13)		$ (0.12)	$ (0.21)
Discontinued operations, diluted							$ (0.01)	$ (0.13)		$ (0.12)	$ (0.21)

XML

Summary Of Significant Accounting Policies (Property, Plant And Equipment) (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Mar. 30, 2012 item
Summary Of Significant Accounting Policies [Abstract]
Capitalized interest on the cost of major capital projects	$ 8.7	$ 12.4	$ 7.1
Reduction in the value of property, plant and equipment			$ 35.8
Number of liftboats sold				18

XML

Reduction in Value of Assets (Tables)

12 Months Ended

Dec. 31, 2013

Reduction In Value Of Assets [Abstract]

Reduction in Value of Assets [Table Text Block]

	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

XML

Stock-Based And Long-Term Compensation (Summary Of Stock Options Outstanding) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Summary of stock options outstanding
Weighted average remaining contractual term, outstanding	4 years 9 months 18 days	5 years 3 months 18 days

XML

Debt (Narrative) (Details) (USD $)	1 Months Ended	12 Months Ended		1 Months Ended	12 Months Ended
	May 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Aug. 31, 2012 Unsecured Senior Notes Due 2014 [Member]	Dec. 31, 2012 Unsecured Senior Notes Due 2014 [Member]	Dec. 31, 2013 Unsecured Senior Notes Due 2019 [Member]	Dec. 31, 2012 Unsecured Senior Notes Due 2019 [Member]	Dec. 31, 2013 Unsecured Senior Notes Due 2021 [Member]	Dec. 31, 2012 Unsecured Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Term Loan A, Amount Outstanding		$ 365,000,000
Revolving portion of credit facility, borrowing capacity		600,000,000
Face value of debt extinguished	100			100
Portion of debt extinguished				50
Original face amount of debt instrument				300,000,000
Line of Credit Facility, Current Borrowing Capacity		1,000,000,000
Aggregate principal amount of term loan		400,000,000
Line of Credit Facility, Periodic Payment		5,000,000
Letters of Credit Outstanding, Amount		46,800,000
Senior Notes						500,000,000		800,000,000
Stated interest rate on unsecured senior notes				6.00%			6.375%		7.125%
Repayment Of Us Government Guaranteed Long Term Financing Connected To Disposition			12,500,000
Make Whole Premiums Connected To Dispositions			4,000,000
Written Off Unamortized Loan Costs Connected To Repayments Of Make Whole Premiums			700,000
Gains (Losses) on Extinguishment of Debt		(884,000)	(2,294,000)		2,300,000
Extinguishment of Debt, Amount	$ 150,000,000			$ 150,000,000

XML

Income Taxes (Summary Of Activity In Unrecognized Tax Benefits) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits, beginning balance	$ 26,399	$ 21,692	$ 24,760
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, ending balance	29,899	26,399	21,692
Parent Company [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits, ending balance	$ 29,900	$ 26,400	$ 21,700

XML

Summary Of Significant Accounting Policies (Foreign Currency) (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary Of Significant Accounting Policies [Abstract]
Foreign currency gains	$ (9.4)	$ (2.7)	$ 1.4

XML

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Schedule Of Ownership In Productive Oil And Natural Gas Wells) (Details)	Dec. 31, 2013 item
Company's ownership of productive oil and natural gas wells
Oil, gross	9.00
Oil, net	4.59

XML

Stock-Based And Long-Term Compensation (Narrative) (Details) (USD $)	12 Months Ended									24 Months Ended	12 Months Ended					12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Supplemental Executive Retirement Plan [Member]	Dec. 31, 2012 Supplemental Executive Retirement Plan [Member]	Dec. 31, 2011 Supplemental Executive Retirement Plan [Member]	Dec. 31, 2013 Defined Contribution Pension [Member]	Dec. 31, 2012 Defined Contribution Pension [Member]	Dec. 31, 2011 Defined Contribution Pension [Member]	Dec. 31, 2011 Defined Contribution Pension [Member]	Dec. 31, 2013 Non-Qualified Deferred Compensation Plans [Member]	Dec. 31, 2012 Non-Qualified Deferred Compensation Plans [Member]	Dec. 31, 2011 Non-Qualified Deferred Compensation Plans [Member]	Dec. 31, 2013 2013 Employee Stock Purchase Plan Member	Jun. 30, 2013 2013 Employee Stock Purchase Plan Member	Dec. 31, 2013 Stock Options [Member]	Dec. 31, 2012 Stock Options [Member]	Dec. 31, 2011 Stock Options [Member]	Dec. 31, 2013 Restricted Stock [Member]	Dec. 31, 2012 Restricted Stock [Member]	Dec. 31, 2011 Restricted Stock [Member]	Dec. 31, 2013 Restricted Stock Units (RSUs) [Member]	Dec. 31, 2012 Restricted Stock Units (RSUs) [Member]	Dec. 31, 2011 Restricted Stock Units (RSUs) [Member]	Dec. 31, 2013 Performance Shares [Member]	Dec. 31, 2012 Performance Shares [Member]	Dec. 31, 2011 Performance Shares [Member]	Dec. 31, 2013 Employee Stock Purchase Plan [Member]	Dec. 31, 2012 Employee Stock Purchase Plan [Member]	Dec. 31, 2011 Employee Stock Purchase Plan [Member]	Jun. 30, 2013 Employee Stock Purchase Plan [Member]
Stock Based and Long-Term Compensation (Textual) [Abstract]
Common Stock Reserved for Issuance, Shares Remaining	7,900,000
Maximum employee contribution to be matched by employer								4		5
Stock options granted																406,185
Share-based payment vesting period, years																3 years			3 years
Share-based payment expiration period, years																10 years
Compensation expense				$ 1,200,000	$ 2,400,000	$ 1,800,000								$ 600,000		$ 3,600,000	$ 4,800,000	$ 3,300,000	$ 21,500,000	$ 17,000,000	$ 6,000,000	$ 1,000,000	$ 2,400,000	$ 1,200,000	$ 10,000,000	$ 11,000,000	$ 3,200,000	$ 300,000	$ 500,000	$ 400,000
Intrinsic value of options exercised																5,100,000	40,400,000	23,400,000
Cash received from exercising options																6,300,000	14,800,000	10,300,000
Tax benefit from exercising stock options																700,000	600,000	7,400,000
Unrecognized compensation expense related to non-vested options oustanding																4,100,000			29,900,000
Compensation expense expected to recognize In 2013																2,800,000			18,400,000
Compensation expense expected to recognize in 2014																1,200,000			11,100,000
Compensation expense expected to recognize in 2015																100,000			400,000	400,000
Resticted stock granted																			1,388,835			67,266
Shares outstanding																			2,019,976	1,296,893		324,481	257,215		308,467
Performance period of PSU grant, years																									3 years
Portion of equivalent value in common stock of company after meeting service requirements, at discretion of compensation committee																									50.00%
Issue of common stock to employees																											67,300
Cash paid to settle performance share units																									9,700,000	2,700,000	2,800,000
Performance Share Units Outstanding, in 2013																									70,752
Performance Share Units Outstanding, in 2014																									119,010
Performance Share Units Outstanding, in 2015																									118,705
Shares issued under Employee Stock Purchase Plan, shares														98,000												43,300		87,000	147,000	75,700
Proceed from issue of shares under employee stock purchase plans	4,123,000	2,855,000	2,206,000											2,200,000														1,900,000	2,900,000	2,200,000
Common stock reserved for issuance	8,000,000														3,000,000																1,000,000
Maximum empoyee contribution							75.00%
Company contribution, percent								100.00%
Company discretionary contributions							16,000,000	8,400,000	7,400,000
Maximum portion of base salary to defer under non-qualified deferred compensation plan											75.00%
Maximum portion of bonus to defer under non-qualified deferred compensation plan											100.00%
Non-employee cash deferred to non-qualified compensation plan											100.00%
Maximum of cash portion of PSU compensation to defer under non-qualified deferred compensation plan											100.00%
Non-employee RSU deferred to non-qualified compensation plan											100.00%
Long-term liability											15,000,000	13,500,000
Current liability											1,900,000	100,000
Deferred compensation, compensation expense											2,500,000	1,600,000	(100,000)
Deferred compensation plan assets											13,700,000	11,300,000
Other income (expense)											(2,400,000)	(700,000)	200,000
Employers Contribution to be received by plan participants, Minimum				5.00%
Employers Contribution to be received by plan participants, Maximum				35.00%
Employers contribution				1,200,000	1,800,000	1,000,000
Distribution to select participants				3,000,000	6,700,000	5,500,000
Share-based Compensation Arrangement by Share-based Payment Award, Other Share Increase (Decrease)																				609,743
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value																			$ 23.80
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value																			$ 24.71	$ 27.89		$ 26.34	$ 26.23
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value																			$ 9,600,000	$ 13,000,000	$ 10,300,000

XML

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Computed expected tax expense (benefit)	$ (25,055)	$ 212,857	$ 85,818
Increase (decrease) resulting from State and foreign income taxes	6,310	15,046	(2,106)
Increase (decrease) resulting other	(16,080)	(2,883)	2,092
Income tax	39,833	225,020	85,804
Income Tax Reconciliation, Nondeductible Expense, Impairment Losses	$ 74,658

XML

Stock-Based And Long-Term Compensation (Summary Of The Status Of Restricted Stock) (Details) (Restricted Stock [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Restricted Stock [Member]
Summary of restricted stock
Beginning balance	1,296,893
Granted	1,388,835
Shares, vested	(405,109)
Shares, fofeited	(260,643)
Ending balance	2,019,976	1,296,893
Weighted average grant date fair value, beginning balance	$ 27.89
Weighted average grant date fair value, granted	$ 23.14	$ 22.87	$ 28.84
Weighted average grant date fair value, vested	$ 23.80
Weighted average grant date fair value, forfeited	$ 25.23
Weighted average grant date fair value, ending balance	$ 24.71	$ 27.89

XML

Income Taxes (Schedule Of Deferred Tax Assets and Liabilities) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Components of Deferred Tax Assets [Abstract]
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
Deferred tax assets, gross	164,446	152,456
Net deferred tax assets	164,446	152,456
Components of Deferred Tax Liabilities [Abstract]
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

XML

Stock-Based And Long-Term Compensation (Summary Of The Valuation Assumptions Used To Calculate The Fair Value Of Stock Option Grants) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
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)	5 years	5 years	4 years
Volatility	48.41%	55.27%	56.31%

XML

Inventory and Other Current Assets (Details) (USD $) Share data in Millions, unless otherwise specified	0 Months Ended	12 Months Ended
	Apr. 17, 2012	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2012
Inventory and Other Current Assets [Abstract]
Costs and estimated earnings in excess of billings included in other current assets		$ 63,200,000	$ 18,500,000
Supplies and consumables		56,400,000	61,800,000	56,400,000
Raw materials		20,800,000	5,000,000
Work-in-progress		20,100,000	6,000,000
Finished goods		65,600,000	63,700,000
Inventory		162,900,000	136,500,000
Equity Method Investment, Net Sales Proceeds	34,100,000
Available-for-sale Equity Securities, Amortized Cost Basis	51,600,000
Number of shares comprising Available for Sale Securities	7.0	1.4
Available-for-Sale Securities, Share Price	7.33
Percentage of limited partnership interest	10.00%		10.00%
Available-for-sale securities, number of shares sold			5.6
Available-for-sale Securities, Income Tax Expense on Change in Unrealized Holding Gain (Loss)		100,000	500,000
Available-for-sale Securities, Change in Net Unrealized Holding Gain (Loss), Net of Tax		300,000	900,000
Available-for-sale Securities, Change in Net Unrealized Holding Gain (Loss) before Taxes		400,000	1,400,000
Available-for-sale Securities, Gross Realized Gains (Losses), Sale Proceeds			41,900,000
Available-for-sale Securities, Gross Realized Gains			900,000
Available-for-sale Securities, Current		$ 8,800,000	$ 9,200,000

XML

Related Party Transactions

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

Related Party Transactions

(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  $240.3million, 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.

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 millionfor 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. 

XML

Summary Of Significant Accounting Policies (Notes Receivable) (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Notes Receivable [Abstract]
Amount of notes receivable net	$ 115.0
Interest rate percentage to record present value of notes receivable	6.58%
Company recorded interest income	$ 2.6	$ 2.8	$ 4.5

XML

Interim Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Interim Financial Information (Unaudited) [Abstract]

Schedule Of Interim Financial Information

	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)	-	-

XML

Debt (Schedule Of Maturities Of Long-Term Debt) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Debt [Abstract]
2013	$ 20,000
2014	20,602
2015	20,637
2016	305,296
Thereafter	1,300,000
Total	$ 1,666,535

XML

Fair Value Measurements (Narrative) (Details) (USD $) Share data in Millions, unless otherwise specified	0 Months Ended	12 Months Ended
	Apr. 17, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 29, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of limited partnership interest	10.00%		10.00%
Number of shares comprising Available for Sale Securities	7.0	1.4
Interest rate swap agreement for notional amount		$ 300,000,000	$ 100,000,000		$ 150,000,000
Selling of interest rate swap					1,200,000
Fair value of debt		1,789,000,000	1,960,000,000
Impairment of long lived assets		243,781,000
Business combination, total contingent consideration paid		6,500,000	6,000,000
Goodwill, Impairment Loss		91,016,000		10,334,000
Impairment of Long-Lived Assets Held-for-use		243,781,000
Impairment of Intangible Assets, Finite-lived		(18,296,000)
Liftboats [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of long lived assets				46,100,000
Impairment of Long-Lived Assets Held-for-use				46,100,000
Subsea And Technical Solutions [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of long lived assets		221,200,000
Impairment of Long-Lived Assets Held-for-use		221,200,000
Onshore Completion Services [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of long lived assets		11,200,000
Impairment of Long-Lived Assets Held-for-use		11,200,000
Production Services [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of long lived assets		11,400,000
Impairment of Long-Lived Assets Held-for-use		$ 11,400,000

XML

Stock-Based And Long-Term Compensation (Tables)

12 Months Ended

Dec. 31, 2013

Stock-Based And Long-Term Compensation [Abstract]

Summary Of The Valuation Assumptions Used To Calculate The Fair Value Of Stock Option Grants

	Years Ended December 31,
	2013	2012	2011
	Actual	Actual	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	-	-	-

Summary Of Stock Option Activity

	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

Summary Of Non-Vested Stock Option Activity

	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

Summary Of The Status Of Restricted Stock

	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

Summary Of Restricted Stock Activity

	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

XML

Summary Of Significant Accounting Policies (Composition Of Intangible And Other Long-term Assets) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Schedule of Intangible Assets by Major Class [Line Items]
Gross Amount	$ 535,434	$ 563,554
Accumulated Amortization	(84,567)	(53,148)
Net Balance	450,867	510,406
Deferred Compensation Plan Assets [Member]
Schedule of Intangible Assets by Major Class [Line Items]
Gross Amount	13,731	11,343
Accumulated Amortization
Net Balance	13,731	11,343
Escrowed Cash [Member]
Schedule of Intangible Assets by Major Class [Line Items]
Gross Amount	58,406	58,305
Accumulated Amortization
Net Balance	58,406	58,305
Long Term Assets Held as Major Replacement Spares [Member]
Schedule of Intangible Assets by Major Class [Line Items]
Gross Amount	1,000	7,241
Accumulated Amortization
Net Balance	1,000	7,241
Customer Relationships [Member]
Schedule of Intangible Assets by Major Class [Line Items]
Gross Amount	335,590	348,160
Accumulated Amortization	(44,117)	(25,357)
Net Balance	291,473	322,803
Trade Names [Member]
Schedule of Intangible Assets by Major Class [Line Items]
Gross Amount	45,025	53,063
Accumulated Amortization	(9,175)	(7,017)
Net Balance	35,850	46,046
Noncompete Agreements [Member]
Schedule of Intangible Assets by Major Class [Line Items]
Gross Amount	4,256	2,938
Accumulated Amortization	(2,163)	(1,062)
Net Balance	2,093	1,876
Debt Issuance Costs [Member]
Schedule of Intangible Assets by Major Class [Line Items]
Gross Amount	63,829	63,829
Accumulated Amortization	(28,250)	(18,948)
Net Balance	35,579	44,881
Other Intangible Assets [Member]
Schedule of Intangible Assets by Major Class [Line Items]
Gross Amount	13,597	18,675
Accumulated Amortization	(862)	(764)
Net Balance	$ 12,735	$ 17,911

XML

Discontinued Operations (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended	1 Months Ended	12 Months Ended	1 Months Ended	3 Months Ended		6 Months Ended		12 Months Ended
	Dec. 31, 2012	Feb. 29, 2012 Derrick Barge [Member]	Dec. 31, 2012 Derrick Barge [Member]	Mar. 31, 2012 Liftboats [Member] item	Mar. 31, 2012 Liftboats [Member]	Dec. 31, 2011 Liftboats [Member]	Jun. 30, 2012 Liftboats [Member] item	Mar. 31, 2012 Liftboats [Member]	Dec. 31, 2012 Liftboats [Member]	Dec. 31, 2011 Liftboats [Member] item
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds received		$ 44.5		$ 138.6						$ 22.3
Pre-tax gain loss after sale			3.1		10.0	46.1		56.1		8.6
Goodwill			9.7
Quantity of liftboats sold				18			18			7
Repayment Of Us Government Guaranteed Long Term Financing Connected To Disposition	12.5								12.5
Make Whole Premiums Connected To Dispositions	4.0								4.0
Written Off Unamortized Loan Costs Connected To Repayments Of Make Whole Premiums	0.7								0.7
Loss on sale of assets, disposal group accounted for as discontinued operations					3.6
Costs Related To Disposition					$ 6.4

XML

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Schedule Of Drilling Activity) (Details)	12 Months Ended
	Dec. 31, 2013 item	Dec. 31, 2012 item
Exploratory Wells Drilled
Exploratory wells productive, gross	0	0
Exploratory wells non-productive, gross	0	0
Exploratory wells productive and non-productive, gross	0	0
Exploratory wells productive, net	0	0
Exploratory wells non-productive, net	0	0
Exploratory wells productive and non-productive, net	0
Development Wells Drilled
Total Development Wells Net	1.53
Non-Productive Development Wells Net	0.51
Productive Development Wells Net	1.02
Total Development Wells Gross	3.00
Non-Productive Development Wells Gross	1.00
Productive Development Wells Gross	2.00
Development wells productive, gross		0
Development wells non-productive, gross		0
Development wells productive and non-productive, gross		0
Development wells productive, net		0
Development wells non-productive, net		0
Development wells productive and non-productive, net		0

XML

Supplemental Cash Flow Information (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, net of amounts capitalized	$ 97,129	$ 109,112	$ 39,539
Cash paid for income taxes	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
Non-cash investing activity:
Capital expenditures included in accounts payable	70,463	61,035	23,053
Additional consideration payable on acquisitions	136	9,890
Non-cash financing activity:
Dividends, Share-based Compensation, Cash	$ 12,759

XML

Summary Of Significant Accounting Policies (Estimated Useful Lives Of The Related Assets) (Details)	12 Months Ended
	Dec. 31, 2013
Building and Building Improvements [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, useful life	3 years
Building and Building Improvements [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, useful life	40 years
Marine Vessels And Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, useful life	5 years
Marine Vessels And Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, useful life	25 years
Machinery And Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, useful life	2 years
Machinery And Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, useful life	20 years
Automobiles, Trucks, Tractors And Trailers [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, useful life	3 years
Automobiles, Trucks, Tractors And Trailers [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, useful life	5 years
Furniture And Fixtures [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, useful life	2 years
Furniture And Fixtures [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, useful life	10 years

XML

Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Summary Of Significant Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

(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.

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.

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.

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

	Drilling	Subsea and	Onshore		Subsea and
	Products and	Well	Completion	Production	Technical
	Services	Enhancement	Services	Services	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 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	Accumulated	Net	Gross	Accumulated	Net
	Amount	Amortization	Balance	Amount	Amortization	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. 

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.

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.

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 compensation, the Company records compensation costs relating to share-based payment transactions and includes such costs in general and administrative expenses in the consolidated statement of 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.

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.

XML

Acquisitions (Narrative) (Details) (USD $) Share data in Millions, except Per Share data, unless otherwise specified	12 Months Ended			12 Months Ended		0 Months Ended	2 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Feb. 07, 2012	Dec. 31, 2013 Other Acquisitions [Member]	Dec. 31, 2012 Other Acquisitions [Member]	Feb. 07, 2012 Complete Production Services, Inc. [Member]	Feb. 29, 2012 Complete Production Services, Inc. [Member]	Sep. 30, 2012 Complete Production Services, Inc. [Member]	Dec. 31, 2012 Complete Production Services, Inc. [Member]
Business Acquisition [Line Items]
Business combination, total contingent consideration paid	$ 6,500,000	$ 6,000,000		$ 6,500,000
Business acquisition, contingent consideration paid, post 141R acquisition		3,000,000
Business acquisition, pre-414R contingent consideration paid		3,000,000
Business Acquisition, Contingent Consideration, Potential Cash Payment	100,000	10,000,000
Cash paid to acquire equity interest						2,914,800,000
Complete stockholders received of a share of the company's common stock						0.945
Business acquisition cost of acquired entity cash paid per share						$ 7.00
Approximately cash paid				20,400,000	37,600,000	553,300,000
Business acquisition Equity consideration paid number of shares						74.7
Approximately cash acquisition						2,308,200,000
Closing price of our common stock on the merger date						$ 30.90
Company will repay of complete debt				3,000,000
Estimated Fair Value of Option Issued for Due to Conversion						1.1999
Business Acquisition, Purchase Price Allocation, Goodwill Amount			1,922,689,000		22,600,000
Goodwill recognized from this acquisition				15,100,000					1,922,700,000
Goodwill acquired			1,922,689,000		22,600,000
Additional consideration payment after the settlement of certain liabilities and administrative formalities				3,600,000
Non-recurring Expenses							48,400,000	81,600,000
Maximum additional consideration for acquisitions payable through 2012	$ 100,000	$ 10,000,000
Business Acquisition, Percentage of Voting Interests Acquired				100.00%	100.00%

XML

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Supplementary Oil And Natural Gas Disclosures [Abstract]

Schedule Of Proved Developed And Undeveloped Oil And Gas Reserves

			Company's Share of
	Consolidated		Equity-Method Investments
	Crude Oil	Natural Gas	Crude Oil	Natural Gas
	(Mbbls)	(Mmcf)	(Mbbls)	(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	-	-

Cost Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities

	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

Capitalized Costs Relating To Oil And Gas Producing Activities

	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

Schedule Of Ownership In Productive Oil And Natural Gas Wells

	Productive Wells
	Gross	Net
Oil	9.00	4.59

Schedule Of Gas And Oil Acreage

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

Schedule Of Drilling Activity

	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	-	-

Results Of Operations For Oil And Gas Producing Activities

Consolidated Entities	Years Ended December 31,
	2013	2012	2011
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

Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves

	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

Summary Of Changes In Standardized Measure Of Discounted Future Net Cash Flows Applicable To Proved Oil And Natural Gas Reserves

	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

XML

Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Summary Of Significant Accounting Policies [Abstract]

Basis of Presentation

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.

Use of Estimates

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.

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

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.

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

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

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 and Other Current Assets

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

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.

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

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.

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

	Drilling	Subsea and	Onshore		Subsea and
	Products and	Well	Completion	Production	Technical
	Services	Enhancement	Services	Services	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

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 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

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	Accumulated	Net	Gross	Accumulated	Net
	Amount	Amortization	Balance	Amount	Amortization	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

Decommissioning Liabilities

The Company records estimated future decommissioning liabilities in accordance with the authoritative guidance related to asset retirement obligations (decommissioning liabilities), which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, with a corresponding increase in the carrying amount of the related long-lived asset.  Subsequent to initial measurement, the decommissioning liability is required to be accreted each period to present value. 

The Company’s decommissioning liabilities associated with the Bullwinkle platform and its related assets consist of costs related to the plugging of wells, the removal of the related facilities and equipment, and site restoration.  Whenever practical, the Company utilizes its own equipment and labor services to perform well abandonment and decommissioning work.  When the Company performs these services, all recorded intercompany revenues and related costs of services are eliminated in the consolidated financial statements.  The recorded decommissioning liability associated with a specific property is fully extinguished when the property is abandoned.  The recorded liability is first reduced by all cash expenses incurred to abandon and decommission the property.  If the recorded liability exceeds (or is less than) the Company’s total costs, then the difference is reported as income (or loss) within revenue during the period in which the work is performed. 

The Company reviews the adequacy of its decommissioning liabilities whenever indicators suggest that the estimated cash flows needed to satisfy the liability have changed materially.  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

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.

Taxes Collected from Customers

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

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 (Loss) per Share

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

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.

Fair Value Measurements

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

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

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

Stock-Based Compensation

In accordance with authoritative guidance related to stock compensation, the Company records compensation costs relating to share-based payment transactions and includes such costs in general and administrative expenses in the consolidated statement of 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.

Derivative Instruments and Hedging Activities

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

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

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

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.

XML

Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2012

Valuation and Qualifying Accounts [Abstract]

Schedule II Valuation and Qualifying Accounts

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Schedule II Valuation and Qualifying Accounts

Years Ended December 31, 2013, 2012 and 2011

(in thousands)

	Balance at the	Charged to		Balance
	beginning of	costs and		at the end
Description	the year	expenses	Deductions	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

XML

Fair Value Measurements (Fair Value Measurements Used in Testing) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite Lived Intangible Assets Fair Value Used In Testing for Impairment	$ 4,355
Property, Plant and Equipment Fair Value Measurment Used in Testing Impairment of Long-Lived Assets	328,876	134,000
Goodwill, Impairment Loss	91,016	10,334
Impairment of Intangible Assets, Finite-lived	(18,296)
Impairment of Long-Lived Assets Held-for-use	243,781
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite Lived Intangible Assets Fair Value Used In Testing for Impairment	4,355
Property, Plant and Equipment Fair Value Measurment Used in Testing Impairment of Long-Lived Assets	328,876	134,000
Impairment of Long-Lived Assets to be Disposed of		$ (35,762)

XML

Summary Of Significant Accounting Policies (Financial Instruments) (Narrative) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Summary Of Significant Accounting Policies [Abstract]
Fair value of debt	$ 1,789.0	$ 1,960.0

XML

Summary Of Significant Accounting Policies (Major Customers And Concentration Of Credit Risk) (Narrative) (Details)	12 Months Ended		24 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary Of Significant Accounting Policies [Abstract]
Maximum percentage of revenue for a single major customer	10.00%	13.00%	10.00%

XML

Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Summary Of Significant Accounting Policies [Abstract]

Estimated Useful Lives Of The Related Assets

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

Summary Of Activity Of Goodwill

	Drilling	Subsea and	Onshore		Subsea and
	Products and	Well	Completion	Production	Technical
	Services	Enhancement	Services	Services	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

Composition Of Intangible And Other Long-term Assets

	December 31, 2013			December 31, 2012
	Gross	Accumulated	Net	Gross	Accumulated	Net
	Amount	Amortization	Balance	Amount	Amortization	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

Summary Of The Activity For Company's Decommissioning Liabilities

	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

XML

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2013

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

	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	$                -	$               -

XML

Consolidated Statements Of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:
Net income	$ (111,418)	$ 365,935	$ 142,554
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	625,928	510,526	257,313
Writeoff of debt acquisition costs and note discount	(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 loss from 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 sale of business		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 (Used in) Operating Activities, Total	892,808	1,035,043	492,804
Cash flows from investing activities:
Payments for capital expenditures	(608,960)	(1,141,922)	(484,648)
Proceeds from Sale of Available-for-sale Securities, Equity		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
Proceeds from Sale of Equity Method Investments		34,087
Proceeds from Insurance Settlement, Investing Activities	22,650
Purchase of short-term investments, net.			(223,491)
Proceeds from sale of short-term investments			223,630
Other	4,539	31,630	(721)
Net Cash Provided by (Used in) Investing Activities, Total	(605,568)	(1,157,118)	(1,249,909)
Cash flows from financing activities:
Repayments of Long-term Lines of Credit	(581,771)	(771,439)	(424,913)
Proceeds from Long-term Lines of Credit	581,771	696,439	324,913
Proceeds from issuance of long-term debt	1,535	400,000	1,300,000
Principal payments of 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
Payments for Repurchase of Common Stock	(10,627)
Other	(13,187)	(10,383)	(9,662)
Net Cash Provided by (Used in) Financing Activities, Total	(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

XML

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2013

Acquisitions [Abstract]

Consideration Paid And The Provisional Fair Value Of The Assets Acquired And Liabilities

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

Supplemental Pro Forma 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

XML

Income Taxes (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2013
U.S. Federal income tax rate	35.00%	35.00%	35.00%
net operating loss carryforwards				$ 1,500,000
Expiration dates for utilization of loss carryforwards	2020 through 2026
Annual limitation on utilization of net operating loss carryforwards				500,000
Deferred tax assets, various state				10,800,000
Undistributed earnings of foreign subsidiaries				56,000,000
Unrecorded tax benefits	26,399,000	21,692,000	24,760,000	29,899,000
Parent Company [Member]
Unrecorded tax benefits	$ 26,400,000	$ 21,700,000		$ 29,900,000

XML

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Summary Of Changes In Standardized Measure Of Discounted Future Net Cash Flows Applicable To Proved Oil And Natural Gas Reserves) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Beginning of the period	$ 303,430	$ 237,749	$ 169,492
Net change in sales and transfer prices and in production (lifting) costs related to future production	(13,278)	(17,734)	62,881
Changes in estimated future development costs	(48,594)	(5,569)	8,297
Sales and transfers of oil and gas produced during the period	(45,866)	(45,425)	(54,057)
Net change due to extensions, discoveries, and improved recovery	75,304	206,313
Net changes due to revisions in quantity estimates	(228,620)	(63,192)	57,189
Previously estimated development costs incurred during period	10,136	4,748	17,980
Accretion of discount	46,711	37,252	26,625
Other-unspecified	(24,169)	(21,799)	(12,650)
Net change in income taxes	82,675	(28,913)	(38,008)
Aggregate change in the standardized measure of discounted future net cash flows for the year	(145,701)	65,681	68,257
End of the period	157,729	303,430	237,749
Equity Method Investments [Member]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Beginning of the period			102,476
Net change in sales and transfer prices and in production (lifting) costs related to future production			27,944
Changes in estimated future development costs			(8,862)
Sales and transfers of oil and gas produced during the period			(44,268)
Net changes due to purchases and sales of minerals in place			51,781
Net changes due to revisions in quantity estimates			22,005
Previously estimated development costs incurred during period			13,840
Exchange transaction			(23,356)
Accretion of discount			11,179
Other-unspecified			(2,065)
Net change in income taxes			(17,942)
Aggregate change in the standardized measure of discounted future net cash flows for the year			30,256
End of the period			$ 132,732

XML

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Measurements [Abstract]

Summary Of Financial Assets And Liabilities Measured At Fair Value On Recurring Basis

		Fair Value Measurements at Reporting Date Using
	December 31, 2013	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	-
	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	-

Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Valuation Techniques [Table Text Block]

		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)

XML

Summary Of Significant Accounting Policies (Decommissioning Liabilities) (Narrative) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Summary Of Significant Accounting Policies [Abstract]
Period of postponement of platform decomissioning	10 years
Asset Retirement Obligation, Liabilities Incurred	$ 445	$ 4,620

XML

Equity-Method Investments (Narrative) (Details) (USD $) In Thousands, unless otherwise specified	0 Months Ended	12 Months Ended		1 Months Ended	12 Months Ended
	Apr. 17, 2012	Dec. 31, 2012	Dec. 31, 2011	Mar. 31, 2011 Dynamic Offshore [Member]	Dec. 31, 2012 Dynamic Offshore [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of limited partnership interest	10.00%	10.00%		10.00%
Earnings (losses) from equity-method investments, net		$ (287)	$ 16,394
Gain loss from Equity method investment		$ 17,880			$ 17,900

XML

Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 196,047	$ 91,199
Accounts receivable, net of allowance for doubtful accounts of $28,715 and $17,484 at December 31, 2012 and December 31, 2011, respectively	937,195	1,027,218
Deferred income taxes	8,785	34,120
Prepaid expenses	70,421	93,190
Income tax receivable	5,532
Inventory and other current assets	258,449	214,630
Total current assets	1,476,429	1,460,357
Property, plant and equipment, net	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	450,867	510,406
Total assets	7,411,307	7,802,886
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 - 157,501,635, Outstanding - 157,933,224 at December 31, 2012 Authorized - 125,000,000, Issued and Outstanding, 82,425,443 at December 31, 2011	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

XML

Summary Of Significant Accounting Policies (Cash Equivalents) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2013
Summary Of Significant Accounting Policies [Abstract]
Maximum maturity of short-term investments purchased to be cash equivalents	90 days

XML

Commitments And Contingencies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jan. 26, 2010
Commitments and Contingencies (Textual) [Abstract]
Period for Lease Renewal	2 years
Interest of Subsidiary in Lease Assets Owned Entity	5.00%
Vessel's gross asset value under the capital lease at inception				$ 37.6
Vessel's gross asset value under the capital lease at depreciation	16.4	12.2
Other long-term liabilities	21.4	25.6
Accounts Payable Related to Obligations Under Capital Lease	4.2	3.9
2013	4.2
2014	4.6
2015	5.0
2016	5.4
2017	5.9
Capital Leases of Lessee Variable Rate of Interest	8.50%
Interest Expense	2.4	2.7	3.0
Rent expense	28.7	26.3	18.3
2013	72.3
2014	51.5
2015	36.7
2016	27.1
2017	18.7
Thereafter	$ 26.0

XML

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]
Future cash inflows	$ 496,704	$ 891,215	$ 701,170
Future production costs	(82,487)	(141,980)	(126,627)
Future development and abandonment costs	(156,340)	(91,632)	(58,388)
Future income tax expenses	(89,507)	(229,808)	(185,816)
Future net cash flows	168,370	427,795	330,339
10% annual discount for estimated timing of cash flows	10,641	124,365	92,590
Standardized measure of discounted future net cash flows	157,729	303,430	237,749
Equity Method Investments [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]
Future cash inflows			414,246
Future production costs			(100,848)
Future development and abandonment costs			(67,760)
Future income tax expenses			(73,202)
Future net cash flows			172,436
10% annual discount for estimated timing of cash flows			39,704
Standardized measure of discounted future net cash flows			$ 132,732

XML

Consolidated Statements Of Changes In Stockholders' Equity (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2013
Statement of Stockholders' Equity [Abstract]
Common Stock, Dividends, Per Share, Declared	$ 0.08

XML

Segment Information (Schedule of Capital Expenditures, by Segment) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Capital Expenditures	$ 620,469	$ 1,169,105	$ 507,701
Drilling Products And Services [Member]
Segment Reporting Information [Line Items]
Capital Expenditures	269,152	246,389	219,121
Onshore Completion Services [Member]
Segment Reporting Information [Line Items]
Capital Expenditures	99,517	308,317
Production Services [Member]
Segment Reporting Information [Line Items]
Capital Expenditures	107,412	334,670	173,562
Subsea And Technical Solutions [Member]
Segment Reporting Information [Line Items]
Capital Expenditures	144,388	279,729	112,504
Marine [Member]
Segment Reporting Information [Line Items]
Capital Expenditures			$ 2,514

XML

Summary of Significant Accounting Policies (Accumulated Other Comprehensive Loss) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Summary Of Significant Accounting Policies [Abstract]
Accumulated other comprehensive loss, net	$ (17,500)	$ (19,317)

XML

Fair Value Measurements (Level 3 Liabilities) (Details) (Level 3 [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Reduction in Value of Level 3 Liability	$ (3,254,000)	$ 0
Losses recorded_Level 3 liabilities	0	2,227,000
Settlements _Level 3 Liabilities	(6,500,000)	(3,000,000)
Additions related to acquisitions_Level 3 Liabilities	0	10,663,000
Liabilities, Fair Value Disclosure	$ 136,000	$ 9,890,000	$ 0

XML

Property, Plant And Equipment (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant And Equipment [Abstract]

Summary Of Property, Plant And Equipment

	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

XML

Reduction in Value of Assets (Narrative) (Details) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Impairment Charges [Line Items]
Revenue Derived from Venezuela		$ 9,500,000	$ 20,500,000	$ 13,100,000
Reduction in Value of Assets Related to Exit of Venezuela Activities		14,324,000
Retirments of Long-Lived Assets		20,054,000
Reduction in Value of Long-Lived Assets and Related Assets		293,986,000
Goodwill, Impairment Loss		91,016,000		10,334,000
Asset Impairment Charges	419,380,000	419,380,000
Impairment of Intangible Assets, Finite-lived		(18,296,000)
Impairment of Long-Lived Assets Held-for-use		243,781,000
Subsea And Technical Solutions [Member]
Asset Impairment Charges [Line Items]
Reduction in value of other assets		31,900,000
Retirments of Long-Lived Assets		12,100,000
Goodwill, Impairment Loss		91,016,000
Asset Impairment Charges		371,545,000
Impairment of Intangible Assets, Finite-lived		18,300,000
Impairment of Long-Lived Assets Held-for-use		221,200,000
Production Services [Member]
Asset Impairment Charges [Line Items]
Retirments of Long-Lived Assets		2,200,000
Goodwill, Impairment Loss
Asset Impairment Charges		28,568,000
Impairment of Long-Lived Assets Held-for-use		11,400,000
Onshore Completion Services [Member]
Asset Impairment Charges [Line Items]
Retirments of Long-Lived Assets		5,800,000
Goodwill, Impairment Loss
Asset Impairment Charges		16,975,000
Impairment of Long-Lived Assets Held-for-use		11,200,000
Marine [Member]
Asset Impairment Charges [Line Items]
Goodwill, Impairment Loss				10,300,000
Impairment of Long-Lived Assets to be Disposed of				$ 35,800,000

XML

Commitments And Contingencies

12 Months Ended

Dec. 31, 2013

Commitments And Contingencies [Abstract]

Commitments And Contingencies

(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 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 ofDecember 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.

XML

Debt (Tables)

12 Months Ended

Dec. 31, 2013

Debt [Abstract]

Summary Of Long-Term Debt

	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

Schedule Of Maturities Of Long-Term Debt

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

XML

Fair Value Measurements (Summary Of Financial Assets And Liabilities Measured At Fair Value On Recurring Basis) (Details) (Fair Value, Measurements, Recurring [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities, Fair Value Disclosure	$ 8,817	$ 9,224
Contingent consideration	136	9,890
Non-Qualified Deferred Compensation Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Accounts payable	1,944
Intangible and other long-term assets	13,731	11,343
Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Intangible and other long-term assets	337	1,286
Non Qualified Deferred Compensation Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other long-term liabilities	14,986	13,515
Accounts payable		125
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities, Fair Value Disclosure	8,817	9,224
Contingent consideration
Level 1 [Member] | Non-Qualified Deferred Compensation Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Accounts payable
Intangible and other long-term assets	2,330	825
Level 1 [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Intangible and other long-term assets
Level 1 [Member] | Non Qualified Deferred Compensation Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other long-term liabilities
Accounts payable
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities, Fair Value Disclosure
Contingent consideration
Level 2 [Member] | Non-Qualified Deferred Compensation Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Accounts payable	1,944
Intangible and other long-term assets	11,401	10,518
Level 2 [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Intangible and other long-term assets	337	1,286
Level 2 [Member] | Non Qualified Deferred Compensation Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other long-term liabilities	14,986	13,515
Accounts payable		125
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities, Fair Value Disclosure
Contingent consideration	136	9,890
Level 3 [Member] | Non-Qualified Deferred Compensation Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Accounts payable
Intangible and other long-term assets
Level 3 [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Intangible and other long-term assets
Level 3 [Member] | Non Qualified Deferred Compensation Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other long-term liabilities
Accounts payable

XML

Derivative Financial Instruments

12 Months Ended

Dec. 31, 2013

Derivative Financial Instruments [Abstract]

Derivative Financial Instruments

(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. 

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. 

XML

Discontinued Operations (Components Of Income (Loss) From Discontinued Operations) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		12 Months Ended
	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2012	Dec. 31, 2011
Discontinued Operations [Abstract]
Revenues			$ 16,231	$ 105,834
Income (loss) from discontinued operations before income tax			(6,478)	(22,968)
Income tax expense (benefit)			1,771	9,083
Gain (loss) on disposition, net of tax			(10,729)	6,133
Income (loss) from discontinued operations, net of tax	(970)	(16,237)	(17,207)	(16,835)
Gain (loss) on disposition, tax			$ (2,391)	$ 2,425

XML

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Capitalized Costs Relating To Oil And Gas Producing Activities) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Capitalized Costs, Oil and Gas Producing Activities, Net [Abstract]
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

XML

Consolidated Statements Of Comprehensive Income (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Consolidated Statement of Comprehensive Income [Abstract]
Net income	$ (111,418)	$ 365,935	$ 142,554
Unrealized net gain (loss) on investment securities, net of tax	(256)	(897)
Change in cumulative translation adjustment	2,073	8,516	(1,236)
Comprehensive income	$ (109,601)	$ 373,554	$ 141,318

XML

Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Consolidated Balance Sheets [Abstract]
Allowance for doubtful accounts	$ 31,030	$ 28,715
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	0	0
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	250,000,000	250,000,000
Common stock, shares issued	158,976,784	157,501,635
Common stock, shares outstanding	159,158,022	157,933,224

XML

Debt

12 Months Ended

Dec. 31, 2013

Debt [Abstract]

Debt

(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 1st and November 1st 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 15th and December 15th of each year through the maturity date of December 15, 2021. 

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

XML

Related Party Transactions (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2012
Schedule of Equity Method Investments [Line Items]
Purchase of services	$ 164.8	$ 240.3
Trade Accounts Payable	14.6	23.2
Ortowski Construction [Member]
Schedule of Equity Method Investments [Line Items]
Purchase of services		4.1
Trade Accounts Payable		0
ORTEQ Energy Services [Member]
Schedule of Equity Method Investments [Line Items]
Purchase of services	52.8	111.6
Trade Accounts Payable	7.8	13.4
Resource Transport [Member]
Schedule of Equity Method Investments [Line Items]
Purchase of services	14.0	12.1
Trade Accounts Payable	0.9	1.3
Texas Specialty Sands [Member]
Schedule of Equity Method Investments [Line Items]
Purchase of services	69.1	91.9
Trade Accounts Payable	2.0	6.9	6.0
ProFuel LLC [Member]
Schedule of Equity Method Investments [Line Items]
Purchase of services	26.9	18.9
Trade Accounts Payable	2.6	1.6
TIMBER CREEK REAL ESTATE PARTNERS [Member]
Schedule of Equity Method Investments [Line Items]
Purchase of services	2.0	1.7
Trade Accounts Payable	1.3
LINNENERGY[MEMBER]
Schedule of Equity Method Investments [Line Items]
Revenue from Related Parties	26.9	21.1
Accounts Receivable, Related Parties, Current	$ 2.9	$ 3.3

XML

Segment Information (Schedule Of Revenues By Geographic Segment) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Information [Abstract]
United States, Revenue									$ 3,760,276	$ 3,769,528	$ 1,438,138
Other Countries, Revenue									851,548	798,540	526,194
Total, Revenues	1,128,017	1,188,615	1,159,713	1,135,479	1,178,247	1,179,665	1,243,319	966,837	4,611,824	4,568,068	1,964,332
United States, Long-lived assets	2,476,792				2,684,932				2,476,792	2,684,932
Other Countries, Long-lived assets	525,402				570,288				525,402	570,288
Property, plant and equipment, net	$ 3,002,194				$ 3,255,220				$ 3,002,194	$ 3,255,220

XML

Segment Information (Schedule Of Segment Reporting Information) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Revenues	$ 1,128,017	$ 1,188,615	$ 1,159,713	$ 1,135,479	$ 1,178,247	$ 1,179,665	$ 1,243,319	$ 966,837	$ 4,611,824	$ 4,568,068	$ 1,964,332
Cost of services (exclusive of items shown separately below)	734,428	748,052	711,883	707,487	722,814	708,608	711,284	546,767	2,901,850	2,689,473	1,046,409
Depreciation, depletion, amortization and accretion	163,301	158,006	154,987	149,634	143,009	128,160	135,516	102,596	625,928	509,281	244,915
General and administrative expenses									633,877	662,792	376,619
Reduction in the value of assets	419,380								419,380
Income from operations									30,789	706,522	296,389
Interest expense, net									(106,954)	(117,682)	(72,994)
Interest income									2,978	3,170	6,226
Other income									2,486	853	(822)
Earnings (losses) from equity-method investments, net										(287)	16,394
Gain loss from Equity method investment										17,880
Gains (Losses) on Extinguishment of Debt									(884)	(2,294)
Income (loss) from continuing operations before income taxes									(71,585)	608,162	245,193
Identifiable Assets	7,411,307				7,802,886				7,411,307	7,802,886	4,048,145
Capital Expenditures									620,469	1,169,105	507,701
Drilling Products And Services [Member]
Segment Reporting Information [Line Items]
Revenues									838,514	775,066	611,101
Cost of services (exclusive of items shown separately below)									276,131	255,853	220,647
Depreciation, depletion, amortization and accretion									169,296	150,687	130,809
General and administrative expenses									145,585	131,798	122,201
Reduction in the value of assets									2,292
Income from operations									245,210	236,728	137,444
Income (loss) from continuing operations before income taxes									245,210	236,728	137,444
Identifiable Assets	1,245,501				1,086,804				1,245,501	1,086,804	947,679
Capital Expenditures									269,152	246,389	219,121
Onshore Completion Services [Member]
Segment Reporting Information [Line Items]
Revenues									1,596,704	1,593,977
Cost of services (exclusive of items shown separately below)									1,083,494	1,039,732
Depreciation, depletion, amortization and accretion									215,506	171,852
General and administrative expenses									153,825	185,917	3,226
Reduction in the value of assets									16,975
Income from operations									126,904	196,476	(3,226)
Income (loss) from continuing operations before income taxes									126,904	196,476	(3,226)
Identifiable Assets	2,973,916				3,223,984				2,973,916	3,223,984	560,246
Capital Expenditures									99,517	308,317
Production Services [Member]
Segment Reporting Information [Line Items]
Revenues									1,445,555	1,510,990	788,568
Cost of services (exclusive of items shown separately below)									1,011,933	929,552	443,381
Depreciation, depletion, amortization and accretion									178,442	135,910	66,825
General and administrative expenses									190,614	211,293	135,180
Reduction in the value of assets									28,568
Income from operations									35,998	234,235	143,182
Income (loss) from continuing operations before income taxes									35,998	234,235	143,182
Identifiable Assets	2,176,785				2,185,779				2,176,785	2,185,779	1,140,724
Capital Expenditures									107,412	334,670	173,562
Subsea And Technical Solutions [Member]
Segment Reporting Information [Line Items]
Revenues									731,051	688,035	564,663
Cost of services (exclusive of items shown separately below)									530,292	464,336	382,381
Depreciation, depletion, amortization and accretion									62,684	50,832	47,281
General and administrative expenses									143,853	133,784	116,012
Reduction in the value of assets									371,545
Income from operations									(377,323)	39,083	18,989
Interest income									2,585	2,816	4,542
Other income											105
Income (loss) from continuing operations before income taxes									(374,738)	41,899	23,636
Identifiable Assets	1,015,105				1,295,134				1,015,105	1,295,134	1,162,580
Capital Expenditures									144,388	279,729	112,504
Unallocated [Member]
Segment Reporting Information [Line Items]
Interest expense, net									(106,954)	(117,682)	(72,994)
Interest income									393	354	1,684
Other income									2,486	853	(927)
Earnings (losses) from equity-method investments, net										(287)	16,394
Gain loss from Equity method investment										17,880
Gains (Losses) on Extinguishment of Debt									(884)	(2,294)
Income (loss) from continuing operations before income taxes									(104,959)	(101,176)	(55,843)
Identifiable Assets					$ 11,185					$ 11,185	$ 72,472

XML

Document And Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Feb. 17, 2014	Jun. 28, 2013
Document And Entity Information [Abstract]
Entity Registrant Name	Superior Energy Services Inc
Entity Central Index Key	0000886835
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		158,613,126
Entity Public Float			$ 4.07
Entity Well-known Seasoned Issuer	Yes
Trading Symbol	spn
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No

XML

Stock-Based Compensation And Retirement Plans

12 Months Ended

Dec. 31, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based and Long-Term Compensation

(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.  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	2012	2011
	Actual	Actual	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. 

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, $0.4million 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.

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 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.

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 $1.9million, $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 and75,700 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, 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, $2.4million 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. 

XML

Stock-Based And Long-Term Compensation (Summary Of Non-Vested Stock Option Activity) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Summarizes Non-vested Stock Option [Abstract]
Number of Option, Beginning Balance	409,189
Number of Option, Granted	406,185
Number of Option, Vested	(278,876)
Number of Option, Ending Balance	536,498
Weighted Average Grant Date Fair Value, Beginning Balance	$ 12.71
Weighted Average Grant Date Fair Value, Granted	$ 8.98
Weighted Average Grant Date Fair Value, Vested	$ 12.13
Weighted Average Grant Date Fair Value, Ending Balance	$ 10.19

XML

Segment Information (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Segment Information [Abstract]
Acquisition costs allocated to two reporting segments	$ 4.5

XML

Condensed Consolidated Statements Of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Consolidated Statements of Operations [Abstract]
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
Asset Impairment Charges	419,380
Income from operations	30,789	706,522	296,389
Other income (expense):
Interest expense, net	(106,954)	(117,682)	(72,994)
Interest expense, net	106,954	117,682	72,994
Interest income	2,978	3,170	6,226
Other income (expense)	2,486	853	(822)
Gain (loss) on early estinguishment of debt	(884)	(2,294)
Earnings (losses) from equity-method investments, net		(287)	16,394
Gain on sale of equity-method investments		17,880
Income 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
Income (loss) from discontinued operations, net of tax		(17,207)	(16,835)
Net income	$ (111,418)	$ 365,935	$ 142,554
Earnings per share information:
Continuing operations, basic	$ (0.70)	$ 2.57	$ 2.00
Discontinued operations		$ (0.12)	$ (0.21)
Basic earnings per share	$ (0.70)	$ 2.45	$ 1.79
Continuing operations, diluted	$ (0.70)	$ 2.54	$ 1.97
Discontinued operations		$ (0.12)	$ (0.21)
Diluted earnings per share	$ (0.70)	$ 2.42	$ 1.76
Weighted average common shares used in computing earnings per share:
Basic	159,206	149,288	79,654
Incremental common shares from stock based compensation		1,081	1,271
Incremental common shares from restricted stock units		737	170
Diluted	159,206	151,106	81,095

XML

Reduction in Value of Assets

12 Months Ended

Dec. 31, 2013

Reduction In Value Of Assets [Abstract]

Reduction In Value Of Assets

(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 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. 

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.

XML

Acquisitions

12 Months Ended

Dec. 31, 2013

Acquisitions [Abstract]

Acquisitions

(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.  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 approximately $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 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.

XML

Fair Value Measurements

12 Months Ended

Dec. 31, 2013

Fair Value Measurements [Abstract]

Fair Value Measurements

(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):

		Fair Value Measurements at Reporting Date Using
	December 31, 2013	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	-
	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. 

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. 

XML

Income Taxes

12 Months Ended

Dec. 31, 2013

Income Taxes [Abstract]

Income Taxes

(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

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)

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, 2013, 2012 and 2011, 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

XML

Income Taxes (Schedule Of Components Of Income And Loss From Continuing Operations Before Income Taxes) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest [Abstract]
Domestic	$ 116,966	$ 559,536	$ 244,401
Foreign	(188,551)	48,626	792
Income from continuing operations before income taxes	$ (71,585)	$ 608,162	$ 245,193

XML

Inventory and Other Current Assets

12 Months Ended

Dec. 31, 2013

Inventory and Other Current Assets [Abstract]

Inventory and Other Current Assets

(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 $56.4million 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 $41.9million, resulting in a realized gain of approximately $0.9 million. 

The fair value of the 1.4 million sharesas 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. 

XML

Summary of Significant Accounting Policies (Cash Dividends) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Summary Of Significant Accounting Policies [Abstract]
Dividends Payable	$ 12,800
Common Stock, Dividends, Per Share, Declared	$ 0.08

XML

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Schedule Of Gas And Oil Acreage) (Details)	Dec. 31, 2013 acre
Information relating to acreage held by the Company
Developed, gross acreage	17,280
Undeveloped, gross acreage	0
Total developed and undeveloped gross acreage	17,280
Developed, net acreage	8,813
Undeveloped, net acreage	0
Total developed and undeveloped net Acreage	8,813

XML

Discontinued Operations

12 Months Ended

Dec. 31, 2013

Discontinued Operations [Abstract]

Discontinued Operations

(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 sold18 liftboats and related assets comprising its former Marine segment. The Company received cash proceeds of approximately $138.6 million, inclusive of working capital and selling costs.  In connection with the sale, the Company repaid approximately $12.5 million in U.S. Government guaranteed long-term financing (see note 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)

XML

Property, Plant And Equipment

12 Months Ended

Dec. 31, 2013

Property, Plant And Equipment [Abstract]

Property, Plant And Equipment

(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).

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.

XML

Equity-Method Investments

12 Months Ended

Dec. 31, 2013

Equity-Method Investments [Abstract]

Equity-Method Investments

(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 Resourcesand DBHto 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. 

XML

Acquisitions (Supplemental Pro Forma Results) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Actual Results [Member]
Revenue	$ 2,225,013
Net income from continuing operations	140,806
Basic earnings per share	$ 1.61
Diluted earnings per share	$ 1.59
Pro Forma [Member]
Revenue	4,858,464	4,214,617
Net income from continuing operations	$ 428,276	$ 390,209
Basic earnings per share	$ 2.70	$ 2.53
Diluted earnings per share	$ 2.70	$ 2.49

XML

Income Taxes (Schedule Of Components Of Income Tax Expense (Benefit) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current Income Tax Expense (Benefit) [Abstract]
Current, federal	$ (11,269)	$ 116,774	$ 14,227
Current, state	9,480	14,025	785
Current, foreign	27,877	33,280	19,716
Current, total	26,088	164,079	34,728
Deferred Income Tax Expense (Benefit) [Abstract]
Deferred, federal	7,851	59,442	51,828
Deferred, state	993	1,117	1,121
Deferred, foreign	4,901	382	(1,873)
Deferred income taxes	13,745	60,941	51,076
Income tax	$ 39,833	$ 225,020	$ 85,804

XML

Reduction in Value of Assets (Components of the Expense) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2011
Reduction In Value Of Assets [Abstract]
Asset Impairment Charges	$ 419,380	$ 419,380
Reduction in Value of Assets Related to Exit of Venezuela Activities		14,324
Reduction in Value of Long-Lived Assets and Related Assets		293,986
Goodwill, Impairment Loss		91,016	10,334
Retirments of Long-Lived Assets		$ 20,054

XML

Derivative Financial Instruments (Location And Effect Of The Derivative Instrument On The Statements Of Operations) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, (Gain) Loss [Line Items]
Amount of (gain) loss recognized	$ 776	$ (1,286)	$ (1,743)
Hedged Item Debt [Member] | Interest Expense, Net [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Amount of (gain) loss recognized	(12,303)	2,346	(2,536)
Interest Rate Swap [Member] | Interest Expense, Net [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Amount of (gain) loss recognized	$ 13,079	$ (3,632)	$ 793

XML

Acquisitions (Consideration Paid And The Provisional Fair Value Of The Assets Acquired And Liabilities) (Details) (USD $) In Thousands, unless otherwise specified	Feb. 07, 2012
Acquisitions [Abstract]
Current assets	$ 738,456
Property, plant and equipment	1,221,808
Goodwill	1,922,689
Intangible and other long-term assets	372,713
Current liabilities	231,951
Deferred income taxes	403,403
Other long-term liabilities	29,519
Net assets acquired	$ 3,590,793

XML

Segment Information (Schedule Of Identifiable Assets) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Assets	$ 7,411,307	$ 7,802,886	$ 4,048,145
Drilling Products And Services [Member]
Segment Reporting Information [Line Items]
Assets	1,245,501	1,086,804	947,679
Onshore Completion Services [Member]
Segment Reporting Information [Line Items]
Assets	2,973,916	3,223,984	560,246
Production Services [Member]
Segment Reporting Information [Line Items]
Assets	2,176,785	2,185,779	1,140,724
Subsea And Technical Solutions [Member]
Segment Reporting Information [Line Items]
Assets	1,015,105	1,295,134	1,162,580
Unallocated [Member]
Segment Reporting Information [Line Items]
Assets		11,185	72,472
Marine [Member]
Segment Reporting Information [Line Items]
Assets			$ 164,444

XML

Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2013

Discontinued Operations [Abstract]

Components Of Income (Loss) From Discontinued Operations

	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)

XML

Summary Of Significant Accounting Policies (Intangible And Other Long-Term Assets) (Narrative) (Details) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Finite-Lived Intangible Assets [Line Items]
Escrow Deposit Required by Seller of Oil and Gas Properties	$ 50,000,000	$ 50,000,000
Performance Bond Required by Seller	50,000,000	50,000,000
Escrow Deposit	50,400,000	50,400,000	50,300,000
Asset Impairment Charges	419,380,000	419,380,000
Amortization expense exclusive of debt acquisition costs		27,600,000	24,000,000	3,400,000
Amortization of intangible assets exclusive of debt acquisitions costs for 2013	26,300,000	26,300,000
Amortization of intangible assets exclusive of debt acquisitions costs for 2014	25,500,000	25,500,000
Amortization of intangible assets exclusive of debt acquisitions costs for 2015	24,500,000	24,500,000
Amortization of intangible assets exclusive of debt acquisitions costs for 2016	23,800,000	23,800,000
Amortization of intangible assets exclusive of debt acquisitions costs for 2017	23,800,000	23,800,000
Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life		13 years
Trade Names [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life		17 years
Asset Impairment Charges		$ 18,300,000
Noncompete Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life		3 years
Debt Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life		9 years
Unsecured Senior Notes Due 2021 [Member]
Finite-Lived Intangible Assets [Line Items]
Stated interest rate on unsecured senior notes			7.125%

XML

Guarantee

12 Months Ended

Dec. 31, 2013

Guarantee [Abstract]

Guarantee

(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.

XML

Valuation and Qualifying Accounts (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Movement in Valuation Allowances and Reserves [Roll Forward]
Valuation Allowances and Reserves, Balance, Beginning Balance	$ 28,715	$ 17,484	$ 22,618
Valuation Allowances and Reserves, Charged to Cost and Expense	10,078	13,539	3,689
Valuation Allowances and Reserves, Deductions	7,763	2,308	8,823
Valuation Allowances and Reserves, Balance, Ending Balance	$ 31,030	$ 28,715	$ 17,484

XML

Interim Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2013

Interim Financial Information (Unaudited) [Abstract]

Interim Financial Information (Unaudited)

(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)	-	-

XML

Guarantee (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Guarantee [Abstract]
Decommissioning performance guarantees, estimated value	$ 2.6
Maximum potential obligation under Decommissioning performance guarantees	109.1
Contractual right to receive payments from third parties	$ 24.6

XML

Summary Of Significant Accounting Policies (Summary Of Activity Of Goodwill) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Goodwill [Roll Forward]
Beginning Balance	$ 2,532,065	$ 581,379
Acquisition activities	16,599	1,955,647
Disposition activities		(9,741)
Reduction in value of assets	(91,016)		(10,334)
Additional consideration paid for prior acquisitions	756	3,000
Foreign currency translation adjustments	1,217	1,780
Ending Balance	2,458,109	2,532,065	581,379
Goodwill, Other Changes	756	3,000
Drilling Products And Services [Member]
Goodwill [Roll Forward]
Beginning Balance	144,947	140,428
Additional consideration paid for prior acquisitions	756	3,000
Foreign currency translation adjustments	681	1,519
Ending Balance	144,872	144,947
Goodwill, Other Changes	756	3,000
Onshore Completion Services [Member]
Goodwill [Roll Forward]
Beginning Balance	1,418,050
Acquisition activities	1,500	1,193,486
Disposition activities
Reduction in value of assets
Allocation of goodwill to new segments		(224,564)
Additional consideration paid for prior acquisitions
Foreign currency translation adjustments
Ending Balance	1,419,550	1,418,050
Goodwill, Other Changes
Production Services [Member]
Goodwill [Roll Forward]
Beginning Balance	878,052
Acquisition activities	15,099	738,709
Disposition activities
Reduction in value of assets
Allocation of goodwill to new segments		(138,994)
Additional consideration paid for prior acquisitions
Foreign currency translation adjustments	536	349
Ending Balance	893,687	878,052
Goodwill, Other Changes
Subsea And Technical Solutions [Member]
Goodwill [Roll Forward]
Beginning Balance	91,016
Acquisition activities
Disposition activities
Reduction in value of assets	(91,016)
Allocation of goodwill to new segments		(91,016)
Additional consideration paid for prior acquisitions
Foreign currency translation adjustments
Ending Balance		91,016
Goodwill, Other Changes
Subsea and Well Enhancement [Member]
Goodwill [Roll Forward]
Beginning Balance		440,951
Acquisition activities		23,452
Disposition activities		(9,741)
Allocation of goodwill to new segments		454,574
Foreign currency translation adjustments		(88)
Marine [Member]
Goodwill [Roll Forward]
Reduction in value of assets			$ (10,300)

XML

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Narrative) (Details)	12 Months Ended								12 Months Ended
	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2011	Jan. 31, 2010 Shell Offshore Inc [Member]	Jan. 31, 2010 Dynamic Offshore [Member]	Dec. 31, 2011 Equity Method Investments [Member]	Dec. 31, 2011 Equity Method Investments [Member]
Supplementary Oil And Natural Gas Disclosures [Line Items]
Average sales prices	101.85	3.98	2.45	100.70	3.45	108.79			113.28	4.40
Average production costs	10.70	10.70	10.71	10.71	12.51	12.51			26.30	26.30
Percentage of annual discount rate for future cash flows			10.00%	10.00%
Supplementary Oil and Natural Gas Disclosures (Textual) [Abstract]
Percentage of ownership acquired by Wild Well in Shell Offshore Inc.'s Gulf of Mexico Bullwinkle platform							100.00%
Conveyance of undivided interest in assets and related well plugging and abandonment obligations								49.00%
Twelve month average price on the basis of which oil price is estimated	93.42	93.42	91.21	91.21	96.19	96.19
Twelve month average price on the basis of which gas price is estimated	3.67	3.67	2.757	2.757	4,118,000	4,118,000

XML

Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Financial Instruments [Abstract]

Location And Effect Of The Derivative Instrument On The Statements Of Operations

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)

XML

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Cost Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Costs incurred associated with finding, acquiring and developing the Company's proved oil and natural gas reserves
Development costs	$ 51,527	$ 34,685	$ 10,560
Total costs incurred	51,527	34,685	10,560
Equity Method Investments [Member]
Costs incurred associated with finding, acquiring and developing the Company's proved oil and natural gas reserves
Acquisition of properties - proved			32,586
Development costs			18,367
Total costs incurred			$ 50,953

XML

Consolidated Statements Of Changes In Stockholders' Equity (USD $) In Thousands, except Share data, unless otherwise specified	Preferred Stock [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]	Total
Beginning balance, value at Dec. 31, 2010		$ 79	$ 415,278	$ (25,700)	$ 890,894	$ 1,280,551
Beginning balance, shares at Dec. 31, 2010		78,951,053
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Net income					142,554	142,554
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Foreign currency translation				(1,236)		(1,236)
Stock Withheld and Retired Value			(3,039)			(3,039)
Stock Withheld and Retired Shares		86,503
Grant of restricted stock units			1,140			1,140
Restricted stock grant and expense, net of forefeitures, value			5,996			5,996
Restricted stock grant and expense, net of forefeitures, shares		541,425
Exercise of stock options, value		1	10,262			10,263
Exercise of stock options, shares		876,435
Tax benefit (expense) from exercise of stock options			9,004			9,004
Stock options compensation expense			3,348			3,348
Shares issued to pay performance share unit, value			2,759			2,759
Shares issued to pay performance share unit, shares		67,288
Shares issued under Employee Stock Purchase Plan, value			2,594			2,594
Shares issued under Employee Stock Purchase Plan, shares		75,745
Share issuance cost			(335)			(335)
Ending balance, value at Dec. 31, 2011		80	447,007	(26,936)	1,033,448	1,453,599
Ending balance, shares at Dec. 31, 2011		80,425,443
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Net income					365,935	365,935
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Unrealized net gain (loss) on investment securities				(897)		(897)
Foreign currency translation				8,516		8,516
Stock Withheld and Retired Value			3,424			3,424
Stock Withheld and Retired Shares		135,128
Grant of restricted stock units			1,927			1,927
Restricted stock grant and expense, net of forefeitures, value			16,981			16,981
Restricted stock grant and expense, net of forefeitures, shares		295,366
Vesting of restricted stock assumed with acquisition		64,356
Exercise of stock options, value		2	14,775			14,777
Exercise of stock options, shares		1,962,248
Tax benefit (expense) from exercise of stock options			(675)			(675)
Stock options compensation expense			4,829			4,829
Shares issued to pay performance share unit, value			1,140			1,140
Shares issued to pay performance share unit, shares		43,259
Shares issued under Employee Stock Purchase Plan, value			3,360			3,360
Shares issued under Employee Stock Purchase Plan, shares		147,026
Stock issued under acquisition, value		76	2,361,391			2,361,467
Stock issued under acquisition, shares		74,699,065
Fair value of options exchanged in with acquisition			3,932			3,932
Share issuance cost			(388)			(388)
Ending balance, value at Dec. 31, 2012		158	2,850,855	(19,317)	1,399,383	4,231,079
Ending balance, shares at Dec. 31, 2012		157,501,635
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Net income					(111,418)	(111,418)
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Unrealized net gain (loss) on investment securities				(256)		(256)
Foreign currency translation				2,073		2,073
Stock Withheld and Retired Value			2,811			2,811
Stock Withheld and Retired Shares		119,070
Grant of restricted stock units			1,026			1,026
Restricted stock grant and expense, net of forefeitures, value		1	21,459			21,460
Restricted stock grant and expense, net of forefeitures, shares		1,154,032
Vesting of restricted stock assumed with acquisition		210,951
Exercise of stock options, value			6,263			6,263
Exercise of stock options, shares		470,712				470,712
Tax benefit (expense) from exercise of stock options			(1,185)			(1,185)
Stock options compensation expense			3,586			3,586
Shares issued under Employee Stock Purchase Plan, value			5,013			5,013
Shares issued under Employee Stock Purchase Plan, shares		185,407
Shares withheld and retired, value			(10,627)			(10,627)
Exercise of stock options, shares		(426,883)
Dividends, Common Stock, Cash					(12,759)	(12,759)
Ending balance, value at Dec. 31, 2013		$ 159	$ 2,873,579	$ (17,500)	$ 1,275,206	$ 4,131,444
Ending balance, shares at Dec. 31, 2013		158,976,784

XML

Income Taxes (Net Deferred Tax Liabilities Classified In The Consolidated Balance Sheet) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Deferred Tax Liabilities, Net, Classification [Abstract]
Deferred Tax Assets, Net, Current	$ 8,785	$ 34,120
Noncurrent deferred income taxes	(736,080)	(745,144)
Net deferred tax liability	$ (727,295)	$ (711,024)

XML

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2013

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

(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	$                -	$               -

XML

Summary Of Significant Accounting Policies (Derivative Instruments And Hedging Activities) (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Feb. 29, 2012
Summary Of Significant Accounting Policies [Abstract]
Percentage of fixed rate debt	60.00%	74.00%
Notional amount of interest rate swap	$ 300.0	$ 100.0	$ 150.0
Variable interest rate, Adjustment	90 days

XML

Stock-Based And Long-Term Compensation (Summary Of The Activity Of Restricted Stock Units) (Details) (Restricted Stock Units (RSUs) [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Beginning balance	257,215
Granted	67,266
Ending balance	324,481	257,215
Weighted average grant date fair value, beginning balance	$ 26.23
Weighted average grant date fair value, granted	$ 26.76	$ 21.48	$ 35.10
Weighted average grant date fair value, ending balance	$ 26.34	$ 26.23

XML

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Schedule Of Proved Developed And Undeveloped Oil And Gas Reserves) (Details)	12 Months Ended
	Dec. 31, 2013 MBbls	Dec. 31, 2012 MBbls	Dec. 31, 2011 MBbls
Oil [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Beginning balance	8,207,000	6,430,000	5,982,000
Revisions	(3,203,000)	2,234,000	887,000
Production	(411,000)	(457,000)	(439,000)
Ending balance	4,593,000	8,207,000	6,430,000
Proved-developed reserves:
Proved Developed Reserves (Volume)	2,397,000	5,076,000	3,495,000
Proved-undeveloped reserves:
Proved Undeveloped Reserve (Volume)	2,196,000	3,131,000	2,935,000
Natural Gas [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Beginning balance	11,284,000	6,268,000	5,301,000
Revisions	(4,036,000)	5,357,000	1,338,000
Production	(296,000)	(341,000)	(371,000)
Ending balance	6,952,000	11,284,000	6,268,000
Proved-developed reserves:
Proved Developed Reserves (Volume)	2,100,000	5,085,000	3,229,000
Proved-undeveloped reserves:
Proved Undeveloped Reserve (Volume)	4,852,000	6,199,000	3,039,000
Equity Method Investments [Member] | Oil [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Beginning balance		3,207,000	3,395,000
Purchase of reserves in place			958,000
Revisions			412,000
Change in ownership percentage		(3,207,000)
Production			(399,000)
Sale of reserves in-place			(1,159,000)
Ending balance			3,207,000
Proved-developed reserves:
Proved Developed Reserves (Volume)			2,606,000
Proved-undeveloped reserves:
Proved Undeveloped Reserve (Volume)			602,000
Equity Method Investments [Member] | Natural Gas [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Beginning balance		18,236,000	20,111,000
Purchase of reserves in place			8,045,000
Revisions			(547,000)
Change in ownership percentage		(18,236,000)
Production			(906,000)
Sale of reserves in-place			(8,467,000)
Ending balance			18,236,000
Proved-developed reserves:
Proved Developed Reserves (Volume)			14,695,000
Proved-undeveloped reserves:
Proved Undeveloped Reserve (Volume)			3,542,000

XML

Property, Plant and Equipment alt (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Line Items]
Impairment of long lived assets	$ 243,781,000
Leasehold Improvements, Gross	75,000,000	63,500,000
Depreciation	593,000,000	480,000,000	224,600,000
Liftboats [Member]
Property, Plant and Equipment [Line Items]
Impairment of long lived assets			46,100,000
Subsea And Technical Solutions [Member]
Property, Plant and Equipment [Line Items]
Impairment of long lived assets	221,200,000
Onshore Completion Services [Member]
Property, Plant and Equipment [Line Items]
Impairment of long lived assets	11,200,000
Production Services [Member]
Property, Plant and Equipment [Line Items]
Impairment of long lived assets	$ 11,400,000

XML

Supplementary Oil And Natural Gas Disclosures (Unaudited)

12 Months Ended

Dec. 31, 2013

Supplementary Oil And Natural Gas Disclosures [Abstract]

Supplementary Oil And Natural Gas Disclosures (Unaudited)

(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.

Oil and Natural Gas Reserves

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

			Company's Share of
	Consolidated		Equity-Method Investments
	Crude Oil	Natural Gas	Crude Oil	Natural Gas
	(Mbbls)	(Mmcf)	(Mbbls)	(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

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	Net
	Acreage	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	-	-

Results of Operations

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

Consolidated Entities	Years Ended December 31,
	2013	2012	2011
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.

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

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.

XML

Debt (Summary Of Long-Term Debt) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Long-term debt	$ 1,666,535	$ 1,834,500
Less current portion	20,000	20,000
Long-term debt, noncurrent	1,646,535	1,814,500
Other long term debt instrument [member]
Debt Instrument [Line Items]
Long-term debt	1,535
Term Loan, Interest Payable Monthly At Floating Rate And Principal Payable Quarterly, Due December 2017 [Member]
Debt Instrument [Line Items]
Long-term debt	365,000	385,000
Senior Notes, Interest Payable Semiannually At 6 7/8%, Due June 2014 [Member]
Debt Instrument [Line Items]
Long-term debt		150,000
Discount On 6 7/8% Senior Notes [Member]
Debt Instrument [Line Items]
Long-term debt		(500)
Senior Notes, Interest Payable Semiannually At 6 3/8%, Due May 2019 [Member]
Debt Instrument [Line Items]
Long-term debt	500,000	500,000
Senior Notes, Interest Payable Semiannually At 7 1/8%, Due December 2021 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 800,000	$ 800,000

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Taxes [Abstract]

Schedule Of Components Of Income And Loss From Continuing Operations Before Income Taxes

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

Schedule Of Components Of Income Tax Expense (Benefit)

	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

Schedule Of Effective Income Tax Rate Reconciliation

	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

Schedule Of Deferred Tax Assets and Liabilities

	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

Net Deferred Tax Liabilities Classified In The Consolidated Balance Sheet

	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)

Summary Of Activity In Unrecognized Tax Benefits

	2013	2012	2011
Unrecognized tax benefits,
December 31, 2013, 2012 and 2011, 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

XML

Segment Information

12 Months Ended

Dec. 31, 2013

Segment Information [Abstract]

Segment Information

(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 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
		Onshore
	Drilling	Completion		Subsea and
	Products and	and Workover	Production	Technical		Consolidated
	Services	Services	Services	Solutions	Unallocated	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)

Year Ended December 31, 2012
		Onshore
	Drilling	Completion		Subsea and
	Products and	and Workover	Production	Technical		Consolidated
	Services	Services	Services	Solutions	Unallocated	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
		Onshore
	Drilling	Completion		Subsea and		Consolidated
	Products and	and Workover	Production	Technical
	Services	Services *	Services *	Solutions	Unallocated	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. 

Identifiable Assets
		Onshore
	Drilling	Completion		Subsea and
	Products and	and Workover	Production	Technical			Consolidated
	Services	Services	Services	Solutions	Marine	Unallocated	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
		Onshore
	Drilling	Completion		Subsea and
	Products and	and Workover	Production	Technical		Consolidated
	Services	Services	Services	Solutions	Marine	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

XML

Derivative Financial Instruments (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 29, 2012
Derivatives, Fair Value [Line Items]
Derivative asset	$ 0.3	$ 1.3
Selling of interest rate swap				1.2
Interest income (expense) related to the ineffectiveness associated with the fair value hedge	(0.8)	1.3	1.7
Interest rate swap agreement for notional amount	300.0	100.0		150.0
Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Selling of interest rate swap				$ 1.2