spn-20151231 10K FY_Taxonomy2015

0000886835-16-000032.txt : 20160225 0000886835-16-000032.hdr.sgml : 20160225 20160225092148 ACCESSION NUMBER: 0000886835-16-000032 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 132 CONFORMED PERIOD OF REPORT: 20151231 FILED AS OF DATE: 20160225 DATE AS OF CHANGE: 20160225 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SUPERIOR ENERGY SERVICES INC CENTRAL INDEX KEY: 0000886835 STANDARD INDUSTRIAL CLASSIFICATION: OIL, GAS FIELD SERVICES, NBC [1389] IRS NUMBER: 752379388 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-34037 FILM NUMBER: 161454142 BUSINESS ADDRESS: STREET 1: 1001 LOUISIANA STREET, SUITE 2900 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: (713) 654-2200 MAIL ADDRESS: STREET 1: 1001 LOUISIANA STREET, SUITE 2900 CITY: HOUSTON STATE: TX ZIP: 77002 FORMER COMPANY: FORMER CONFORMED NAME: SMALLS OILFIELD SERVICES CORP DATE OF NAME CHANGE: 19930328 10-K 1 spn-20151231x10k.htm 10-K spn-20151231 10K FY_Taxonomy2015

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)


☒	Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the fiscal year ended December 31, 2015


☐	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 ☒ 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 ☒

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 ☒ 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 ☒ 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 ☒		Accelerated filer ☐
Non-accelerated filer ☐	(do not check if 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 ☒

As of June 30, 2015, the aggregate market value of the registrant’s voting stock held by non-affiliates of the registrant was $3.19 billion. As of February 16, 2016, there were 151,397,654 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, 2015

TABLE OF CONTENTS


			Page
PART I

	Item 1	Business	4
		Executive Officers of Registrant	7
	Item 1A	Risk Factors	8
	Item 1B	Unresolved Staff Comments	15
	Item 2	Properties	15
	Item 3	Legal Proceedings	15
	Item 4	Mine Safety Disclosures	15

PART II

	Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	16
	Item 6	Selected Financial Data	18
	Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
	Item 7A	Quantitative and Qualitative Disclosures about Market Risk	27
	Item 8	Financial Statements and Supplementary Data	28
	Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	60
	Item 9A	Controls and Procedures	60
	Item 9B	Other Information	62

PART III

	Item 10	Directors, Executive Officers and Corporate Governance	62
	Item 11	Executive Compensation	62
	Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	62
	Item 13	Certain Relationships and Related Transactions, and Director Independence	62
	Item 14	Principal Accounting Fees and Services	62

PART IV

	Item 15	Exhibits, Financial Statement Schedules	62

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FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K and other documents filed by us with the Securities and Exchange Commission (SEC) contain, and future oral or written statements or press releases by us and our management may 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” and “estimates,” variations of such words and similar expressions identify forward-looking statements, although not all forward-looking statements contain these identifying words. All statements other than statements of historical fact included in this Annual Report on Form 10-K or such other materials regarding our financial position, financial performance, liquidity, strategic alternatives, market outlook, future capital needs, capital allocation plans, 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 prevailing circumstances on the date such statements are made. Such forward-looking statements, and the assumptions on which they are based, are inherently speculative and are subject to a number of risks and uncertainties that could cause our actual results to differ materially from such statements. Such uncertainties include, but are not limited to: the cyclicality and volatility of the oil and gas industry, including changes in prevailing levels of exploration, production and development activity; changes in prevailing oil and gas prices or expectations about future prices; operating hazards, including the significant possibility of accidents resulting in personal injury or death, property damage or environmental damage for which we may have limited or no insurance coverage or indemnification rights; the effect of regulatory programs and environmental matters on our operations or prospects, 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 the uncertainty of macroeconomic and business conditions worldwide; changes in competitive and technological factors affecting our operations; the potential shortage of skilled workers; risks inherent in acquiring businesses; risks associated with business growth outpacing the capabilities of our infrastructure and workforce; political, economic and other risks and uncertainties associated with our international operations; our continued access to credit markets on favorable terms; and the impact that unfavorable or unusual weather conditions could have on our operations. 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 such statements are made, including for example the market prices of oil and gas and regulations affecting oil and gas operations, which we cannot control or anticipate. Further, we may make changes to our business strategies and plans (including our capital spending and capital allocation plans) at any time and without notice, based on any changes in the above-listed factors, our assumptions or otherwise, any of which could or will affect our results. For all these reasons, actual events and results may differ materially from those anticipated, estimated, projected or implied by us in our forward-looking statements. We undertake no obligation to update any of our forward-looking statements for any reason and, notwithstanding any changes in our assumptions, changes in our business plans, our actual experience, or other changes. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof.

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PART I

Item 1. Business

General

We provide a wide variety of services and products to the energy industry related to the exploration, development and production of oil and natural gas. We serve major, national and independent crude oil and natural gas exploration and production companies throughout the world. Our operations are managed and organized by business units, which offer products and services within the various phases of a well’s economic life cycle. We report our operating results in four business segments: Drilling Products and Services; Onshore Completion and Workover Services; Production Services; and Technical Solutions. Given our history of growth and long-term strategy of geographic expansion, we also 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 operating segment and 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 9 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Products and Services

We offer a wide variety of specialized oilfield services and equipment generally categorized by their typical use during the economic life of a well. A description of the products and services offered by each of 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 and maintenance 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.

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).

Technical Solutions – Includes products and services that generally address customer-specific needs with their applications, which typically require specialized engineering, manufacturing or project planning expertise. Most operations requiring our technical solutions are generally in offshore environments during the completion, production and decommissioning phase of an oil and gas well. These products and services primarily include pressure control services, completion tools and services and end-of-life services.

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

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

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

The Technical Solutions segment also includes revenues from oil and gas production related to our 51% ownership interest in the Bullwinkle platform and related assets.

Customers

Our customers are the major and independent oil and gas companies that are active in the geographic areas in which we operate. There were no customers that exceeded 10% of our total revenues in 2015 and 2014. However, EOG Resources, Inc. (EOG Resources) accounted for 10% of our revenues in 2013, primarily within the Onshore Completion and Workover Services segment. Our inability to continue to perform services for a number of our large existing customers, if not offset by sales to new or other existing customers, could have a material adverse effect on our business and operations.

Competition

We provide products and services worldwide in highly competitive markets, with competitors comprised of both small and large companies. 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 and services.

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 sold by us, 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 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 $350 million per occurrence, including sudden and accidental pollution incidents. All of the insurance policies purchased by us contain specific terms, conditions, limitations and exclusions and are subject to either deductibles or self-insured retention amounts for which we are responsible. There can be no assurance that the nature and amount of insurance we maintain will be sufficient to fully protect us against all liabilities related to our business.

Government Regulation

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

worker safety standards;

the protection of the environment;

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the handling and transportation of hazardous materials; and

the mobilization of our equipment to, and operations conducted at, our 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 in the future.

Raw Materials

We purchase various raw materials and component parts in connection with delivering our products and services. These materials are generally, but not always, available from multiple sources and may be subject to price volatility. While we generally do not experience significant long-term shortages of these materials, we have from time to time experienced temporary shortages of particular raw materials. We are always seeking ways to ensure the availability of resources, as well as manage costs of raw materials.

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, 2015, we had approximately 8,300 employees. Approximately 9% of our employees are subject to union contracts, all of which are in international locations. We believe that we have good relationships with our employees.

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.

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/.

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We have a Code of Conduct (Our Shared Core Values at Work), which applies to all of our directors, officers and employees. This Code of Conduct is publicly available on the Corporate Governance page in the About Us section of our website at http://www.superiorenergy.com. Any waivers granted to directors or executive officers and any material amendment to our Code of Conduct will be posted promptly on our website and/or disclosed in a current report on Form 8-K.

Investors should be aware that while we do, at various times, communicate with securities analysts, it is against our policy to disclose to them selectively any material non-public information or other confidential information. Accordingly, investors should not assume that we agree with any statement or report issued by an analyst with respect to our past or projected performance. To the extent that reports issued by securities analysts contain any projections, forecasts or opinions, such reports are not our responsibility.

Executive Officers of Registrant

The following table indicates the names and ages of the executive officers, including all offices and positions held by each in the past five years:

Name and Age

Offices Held and Term of Office

David D. Dunlap

(Age 54)

President and Chief Executive Officer, since February 2011

Chief Executive Officer, since April 2010

Executive Vice President and Chief Operating Officer of BJ Services Company, 2007 to April 2010

Robert S. Taylor

(Age 61)

Executive Vice President, Treasurer and Chief Financial Officer, since September 2004

A. Patrick Bernard

(Age 58)

Senior Executive Vice President, since July 2006

Brian K. Moore

(Age 59)

Senior Executive Vice President of North America Services, since February 2012

President and Chief Operating Officer of Complete Production Services, Inc. (Complete), 2007 to February 2012

Westervelt T. Ballard, Jr.

(Age 44)

Executive Vice President of International Services, since February 2012

Vice President of Corporate Development, 2007 to February 2012

William B. Masters

(Age 58)

Executive Vice President and General Counsel, since March 2008

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Item 1A. Risk Factors

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

The following discussion of “risk factors” identifies the most significant risks or uncertainties that could (i) materially and adversely affect our business, financial condition, results of operations, liquidity or prospects, as well as the market value of our securities, or (ii) cause our actual results to differ materially from our anticipated results or other expectations. 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 natural gas prices and capital expenditures by oil and gas companies.

Our business depends on the level of oil and natural 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 natural gas prices, which historically have been volatile and difficult to predict. Oil and natural gas prices are subject to large fluctuations in response to relatively minor changes in supply and demand, economic growth trends, 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 also be an impediment to economic growth and can therefore negatively impact spending by our customers. Our customers may 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. Crude oil prices declined significantly in the second half of 2014 and have been negatively affected by a combination of factors, including increased production, the decision by the Organization of Petroleum Exporting Countries (OPEC) to keep production levels unchanged and a strengthening in the U.S. dollar relative to most other currencies. Any of these factors could significantly affect the demand for oil and natural gas, which could affect the level of capital spending by our customers and in turn could have a material effect on our results of operations. Further, downward pressure on commodity prices continued throughout 2015 and could continue for the foreseeable future. As a result of the continued decrease in commodity prices, many of our customers have announced reduced capital spending budgets for 2016, and we expect that further reductions in commodity prices or prices remaining at current levels for a prolonged period of time may result in further capital budget reductions in the future.

The availability of quality drilling prospects, exploration success, relative production costs, expectations about future oil and natural gas demand and prices, the stage of reservoir development, the availability of financing, and political and regulatory environments are also expected to affect levels of exploration, development, and production activity, which would impact the demand for our services. Any prolonged reduction of oil and natural 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, population growth and market expectations regarding future trends;

the ability of OPEC and other key oil-producing countries 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, terrorism 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;

oil refining capacity and shifts in end-customer preferences toward fuel efficiency;

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

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

the extent to which taxes, tax credits, environmental regulations, auctions of mineral rights, drilling permits, drilling concessions, drilling moratoriums or other governmental regulations, actions or policies affect the production, cost of production, price or availability of petroleum products and alternative energy sources; and

technological advances affecting energy exploration, production and consumption.

The oil and gas industry has historically experienced periodic downturns, which have been characterized by significantly reduced demand for oilfield services and downward pressure on the prices we charge. Moreover, weakness in the oil and gas industry may adversely impact the financial position of our customers, which in turn could cause them to fail to pay amounts owed to us in a timely manner or at all. Any of these events could have a material adverse effect on our business, results of operations, financial condition and prospects.

We have outstanding debt obligations that could limit our ability to fund future growth and operations and increase our exposure to risk during adverse economic conditions.

As of December 31, 2015, we had $1.6 billion in outstanding debt obligations. Many factors, including factors beyond our control, may affect our ability to make payments on our outstanding indebtedness. These factors include those discussed elsewhere in these Risk Factors and those listed in the “Forward-Looking Statements” section included in this Annual Report on Form 10-K.

Our existing debt and associated commitments could have important adverse consequences. For example, these commitments could:

make it more difficult for us to satisfy our contractual obligations;

increase our vulnerability to general adverse economic and industry conditions;

limit our ability to pay dividends, fund future working capital, capital expenditures, acquisitions or other corporate requirements;

limit our flexibility in planning for, or reacting to, changes in our business and our industry;

place us at a disadvantage compared to our competitors that have less debt or less restrictive covenants in such debt; and

limit our ability to refinance our debt in the future or borrow additional funds.

There are operating hazards inherent in the oil and 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 natural gas exploration, development and production. Any of these events can be the result of human error or purely accidental, and it may be difficult or impossible to definitively determine the ultimate cause of the event or whose personnel or equipment contributed thereto. 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 locations. 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, even under circumstances where we believe we did not cause or contribute to the accident. 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 or losses 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.

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We may not be fully indemnified against losses incurred due to catastrophic events.

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 we cannot prove that we are entitled to be indemnified or if the customer is bankrupt or insolvent, does not maintain adequate insurance or otherwise does not possess sufficient resources to indemnify us. In addition, our indemnification rights may be held unenforceable in some jurisdictions.

Our customers’ changing views on risk allocation could cause us to accept greater risk to win new business or could result in us losing business if we are not prepared to take such risks. To the extent that we accept such additional risk, and seek to insure against it, our insurance premiums could rise.

From time to time, we are subject to various claims, litigation and other proceedings that could ultimately be resolved against us, requiring material future cash payments or charges, which could impair our financial condition or results of operations.

The size, nature and complexity of our business make us susceptible to various claims, both in litigation and binding arbitration proceedings. We may in the future become subject to various claims, which, if not resolved within amounts we have accrued, could have a material adverse effect on our financial position, results of operations or cash flows. Similarly, any claims, even if fully indemnified or insured, could negatively impact our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future.

The credit risks of our customer base could result in losses.

Many of our customers are oil and gas companies that are facing liquidity constraints in light of the current commodity price environment. These customers may impact our overall exposure to credit risk as they may be similarly affected by prolonged changes in economic and industry conditions. If a significant number of our customers experience a prolonged business decline or disruptions, we may incur increased exposure to credit risk and bad debts.

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

Our customers rely on hydraulic fracturing in conducting exploration and production operations. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies. However, the practice of hydraulically fracturing formations to stimulate the production of natural gas and oil remains under increased scrutiny from federal, state and local 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. Federal agencies, including the Environmental Protection Agency (EPA) and Bureau of Land Management (BLM), have asserted regulatory authority over certain aspects of hydraulic fracturing within their specific jurisdiction. For example, the EPA has issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act, and has enacted, and recently proposed additional New Source Performance Standards for certain aspects of the hydraulic fracturing process. The U.S. Department of Interior has issued regulations that impose requirements on hydraulic fracturing operations within federal and tribal lands, including the requirement to disclose chemicals used in the fracturing process as well as certain prior approvals to conduct hydraulic fracturing. Implementation of this rule is subject to ongoing litigation. And from time to time, Congress has considered legislative measures to regulate hydraulic fracturing, including the imposition of chemical disclosure and permitting requirements.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of, or prohibiting the performance of, drilling activities in general or hydraulic fracturing activities in particular.

The adoption of additional legislation or regulation could impose further requirements or limitations, such as restrictions on the use of certain chemicals or prohibitions on hydraulic fracturing in certain areas, which could impact our and our customers operations, and demand for our services.

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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 natural gas, thereby reducing demand for our services and equipment.

Necessary capital financing may not be available at economic rates or at all.

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 capital markets on terms we believe to be reasonable. Our credit agreement was amended in February 2016 resulting in a decrease in the borrowing capacity from $1.0 billion to $470.3 million. Any further reduction of our borrowing capacity could adversely impact our ability to fund, among other things, capital expenditures and general working capital needs. In addition, prevailing market conditions could be adversely affected by the ongoing disruptions in domestic or overseas sovereign or corporate debt markets, low commodity prices or other factors impacting our business, contractions or limited growth in the economy or other similar adverse economic developments in the U.S. or abroad. Instability in the global financial markets has from time to time resulted in periodic volatility in the capital markets. This volatility could limit our access to the credit markets, leading to higher borrowing costs or, in some cases, the inability to obtain financing on terms that are acceptable to us, or at all. Any such failure to obtain additional financing could jeopardize our ability to repay, refinance or reduce our debt obligations, or to meet our other financial commitments.

Our inability 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. In the past, the demand for skilled personnel has been high and the supply limited. We have experienced increases in labor costs in recent years and may continue to do so in the future.

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

In 2015, we conducted business in more than 70 countries, and we intend to expand our international operations.

Our foreign operations are subject to varying degrees of regulation in each of the foreign jurisdictions in which we provide services. Local laws and regulations, and their interpretation and enforcement, differ significantly among those jurisdictions, and can change significantly over time. Future regulatory, judicial and legislative changes or interpretations may have a material adverse effect on our ability to deliver services within various foreign jurisdictions.

In addition to these international regulatory risks, our international operations are subject to a number of other 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 and longer receipt of payment cycles;

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

import-export quotas or restrictions, including tariffs and the risk of fines or penalties assessed for violations;

confiscatory taxation or other adverse tax policies;

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currency exchange controls;

currency exchange rate fluctuations, devaluations and conversion restrictions;

potential submission of disputes to the jurisdiction of a foreign court or arbitration panel;

pandemics or epidemics that disrupt our ability to transport personnel or equipment;

embargoes or other restrictive governmental actions that could limit our ability to operate in foreign countries;

additional U.S. and other regulation of non-domestic operations, including regulation under the Foreign Corrupt Practices Act (the FCPA) as well as other anti-corruption laws;

restrictions on the repatriation of funds;

limitations in the availability, amount or terms of insurance coverage;

the risk that our international customers may have reduced access to credit because of higher interest rates, reduced bank lending or a deterioration in our customers’ or their lenders’ financial condition;

the burden of complying with multiple and potentially conflicting laws and regulations;

the imposition of unanticipated or increased environmental and safety regulations or other forms of public or governmental regulation that increase our operating expenses;

complications associated with installing, operating and repairing equipment in remote locations;

the geographic, time zone, language and cultural differences among personnel in different areas of the world; and

challenges in staffing and managing foreign operations.

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, Angola, Colombia, Indonesia, Nigeria and Azerbaijan.

Laws, regulations or practices in foreign countries could materially restrict our operations or expose us to additional risks.

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 or prevailing laws may (i) require us to meet local content or hiring requirements or other local standards, (ii) restrict with whom we can contract or (iii) otherwise limit the scope of operations that we can legally or practically conduct. Our inability or failure to meet these requirements, standards or restrictions may adversely impact our 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 us to provide services outside our core businesses. Providing services on an integrated or turnkey basis generally requires us to assume additional risks.

Moreover, in order to effectively compete in certain foreign jurisdictions, it is frequently necessary or required to establish joint ventures or strategic alliances with local contractors, partners or agents. In certain instances, these local contractors, partners or agents may have interests that are not always aligned with ours. Reliance on local contractors, partners or agents could expose us to the risk of being unable to control the scope or quality of our overseas services or products, or being held liable under the FCPA, or other anti-corruption laws for actions taken by our strategic or local contractors, partners or agents even though these contractors, partners or agents may not themselves be subject to the FCPA or other applicable anti-corruption laws. Any determination that we have violated the FCPA or other anti-corruption laws could have a material adverse effect on our business, results of operations, reputation or prospects.

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

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We are subject to the jurisdiction of a significant number of domestic and foreign taxing authorities. Changes in tax laws or tax rates, the resolution of tax assessments or audits by various tax authorities could impact our operating results. In addition, we may periodically restructure our legal entity organization. If taxing authorities were to disagree with our tax positions in connection with any such restructurings, our effective income 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, and worker health and safety 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 environmental and worker health and safety laws and regulations in the areas in which we operate, including increasingly rigorous environmental laws and regulations governing air emissions, water discharges and waste management. Generally, these laws and regulations have become more stringent and have sought to impose greater liability on a larger number of potentially responsible parties. The Macondo well explosion in 2010 resulted in additional regulation of our offshore operations, and similar onshore or offshore accidents in the future could result in additional increases in regulation. Failure to comply with these laws and regulations may result in a variety of administrative, civil and criminal enforcement measures, including assessment of monetary penalties, imposition of remedial requirements and issuance of injunctions as to future compliance.

Environmental laws and regulations may provide for “strict liability” for remediation costs, damages to natural resources or threats to public health and safety as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior owners or operators or other third parties. 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 domestic or foreign 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.

In addition, we and our customers may need to apply for or amend facility permits or licenses from time to time with respect to storm water or wastewater discharges, waste handling, or air emissions relating to manufacturing activities or equipment operations, which subjects us and our customers to new or revised permitting conditions that may be onerous or costly to comply with.

Climate change legislation or regulations restricting emissions of greenhouse gases (GHGs) could result in increased operating costs and reduced demand for the oil and natural gas our customers produce.

In response to findings that greenhouse gas emissions present an endangerment to public health and the environment, the EPA has moved forward with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the Clean Air Act (CAA). EPA rules regulate GHG emissions by, for example, requiring a reduction in emissions from certain large stationary sources, and imposing new and proposed limits on emissions of methane and volatile organic compounds from certain oil and natural gas operations and equipment. The EPA also requires the annual reporting of GHG emissions from certain oil and gas facilities. Congress has considered, and several states have adopted rules that seek to control or reduce emissions of GHGs from a wide range of sources. In addition, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas emissions.

At this stage, we cannot predict the impact of these or other initiatives on our or our customers operations, nor can we predict whether, or which of, other currently pending greenhouse gas emission proposals will be adopted, or what other actions may be taken by domestic, foreign or international regulatory bodies. 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.

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If we are not able to design, develop, and produce commercially competitive products and to implement commercially competitive services in a timely manner in response to changes in the market, customer requirements, competitive pressures, and technology trends, our business and results of operations could be materially and adversely affected.

The market for oilfield services in which we operate is highly competitive and includes numerous small companies capable of competing effectively in our markets on a local basis, as well as several large companies that possess substantially greater financial resources than we do. Contracts are traditionally awarded on the basis of competitive bids or direct negotiations with customers.

The market for our services and products is characterized by continual technological developments to provide better and more reliable performance and services. If we are not able to design, develop, and produce commercially competitive products and to implement commercially competitive services in a timely manner in response to changes in the market, customer requirements, competitive pressures, and technology trends, our business and consolidated results of operations could be materially and adversely affected. Likewise, if our proprietary technologies, equipment, facilities, or work processes become obsolete, we may no longer be competitive, and our business and results of operations could be materially and adversely affected. In addition, we may be disadvantaged competitively and financially by a significant movement of exploration and production operations to areas of the world in which we are not currently active.

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 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, extortion or kidnapping, 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, and many experts believe that a confluence of worldwide factors could result in a prolonged period of economic uncertainty and slow growth in the future. In addition, any of 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 our 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 entry into new markets, 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 timely and efficiently integrate the operations of the acquired business, the performance of the underlying product and service portfolio, and 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. In addition, the financing of any future acquisition completed by us could adversely impact our capital structure or increase our leverage. 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. Except as required by law or applicable securities exchange listing standards, we do not expect to ask our shareholders to vote on any proposed acquisition or divestiture. Moreover, we generally do not announce our acquisitions or divestitures until we have entered into a preliminary or definitive agreement.

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

Like most companies, we rely on information technology networks and systems, including the Internet, to process, transmit and store electronic information, to manage or support a variety of our business operations, and to maintain various records, which may include information regarding our customers, employees or other third parties. We make significant efforts to maintain the security and integrity of these types of information and systems (and maintain contingency plans in the event of security breaches or system disruptions). We cannot provide assurance that our security efforts and measures will prevent unauthorized access to our systems, loss or destruction of

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data, account takeovers, or other forms of cyber-attacks or similar events, whether caused by mechanical failures, human error, fraud, malice, sabotage or otherwise. The frequency, scope and sophistication of cyber-attacks continue to grow, which increases the possibility that our security measures will be unable to prevent our systems’ improper functioning or the improper disclosure of proprietary information. Any failure of our information or communications systems, whether caused by attacks, mechanical failures, natural disasters or otherwise, could interrupt our operations, damage our reputation, or subject us to claims, any of which could materially adversely affect us.

We depend on particular suppliers and are vulnerable to product shortages and price increases.

Some of the materials that we use are obtained from a limited group of suppliers. Our reliance on these suppliers involves several risks, including price increases, inferior quality and a potential inability to obtain an adequate supply in a timely manner. We do not have long-term contracts with most of these sources, and the partial or complete loss of certain of these sources could have a negative impact on our results of operations and could damage our customer relationships. Further, a significant increase in the price of one or more of these materials could have a negative impact on our results of operations.

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

Actual future production, cash flows, development expenditures, operating and abandonment expenses and quantities of recoverable oil and natural 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 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, this could have an adverse effect on our financial condition, results of operations and cash flows.

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

We cannot be certain that our infrastructure and workforce will be adequate to support our operations as we expand in the future. 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. Moreover, we may need to expend significant time and money in the future to integrate and unify our systems and infrastructure. 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.

The price of our common stock may be volatile.

Some of the factors that could affect the price of our common stock are quarterly increases or decreases in revenue or earnings, changes in revenue or earnings estimates by the investment community and speculation in the press or investment community about our financial condition or results of operations. General market conditions and U.S. or international economic factors and political events unrelated to our performance may also affect our stock price. For these reasons, investors should not rely on recent trends in the price of our common stock to predict the future price of our common stock or our financial results.

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

From time to time, we are involved in various legal actions incidental to our business. The outcome of these proceedings is not predictable. However, based on current circumstances, we do not believe that the ultimate resolution of these proceedings, after considering available defenses and any insurance coverage or indemnification rights, will have a material adverse effect on our financial position, results of operations or cash flows.

Item 4. Mine Safety Disclosures

Not Applicable.

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PART II

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

Common Stock and Dividend 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.



		Common Stock Prices				Dividends Declared Per Common Share
		High			Low
2014
	First Quarter	$	30.94	$	22.85	$	-
	Second Quarter		36.96		29.62		0.08
	Third Quarter		37.05		32.40		0.08
	Fourth Quarter		33.24		16.70		0.08

2015
	First Quarter	$	22.98	$	16.89	$	0.08
	Second Quarter		26.95		20.31		0.08
	Third Quarter		21.10		12.35		0.08
	Fourth Quarter		17.19		12.35		0.08

As of February 16, 2016, there were 151,397,654 shares of our common stock outstanding, which were held by 133 record holders.

Dividend Information

On January 15, 2016, our board of directors declared a regular quarterly dividend of $0.08 per share, which was paid on February 23, 2016, to our stockholders of record at the close of business on February 1, 2016. The declaration and payment of any future dividends is at the discretion of our board of directors and will depend on our financial results, cash requirements, compliance with debt covenants and other factors deemed relevant by our board of directors.

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, which will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.

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, 2015:



Period	(a) Total Number of Shares Purchased (1)	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)	(d) Approximate Dollar Value of Shares that May Yet be Purchased Under the Plan or Programs (2)
October 1 - 31, 2015	1,608	$	15.46	-	$	500,000,000
November 1 - 30, 2015	601	$	17.89	-	$	500,000,000
December 1 - 31, 2015	37,414	$	13.53	-	$	500,000,000
Total	39,623	$	13.67	-	$	500,000,000

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(1) Through our stock incentive plans, 39,623 shares were delivered to us by our employees to satisfy their tax withholding requirements upon vesting of long-term incentive awards.

(2) On December 11, 2014, we announced that our Board of Directors authorized a share repurchase program of up to $500 million of our common stock, which will expire on December 31, 2016. As of December 31, 2015, $500 million remained authorized under the stock repurchase program.

Performance Graph

The following performance graph and related information shall not be deemed “soliciting 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 yearly percentage change in cumulative total stockholder return on our common stock for five years ended December 31, 2015 with the cumulative 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, 2011 at closing prices on December 31, 2010.

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.



	2011		2012		2013		2014		2015
Superior Energy Services, Inc.	$	81	$	59	$	76	$	59	$	40
S&P 500 Stock Index	$	102	$	118	$	156	$	177	$	180
Peer Group	$	103	$	95	$	126	$	98	$	68

NOTES:

The lines represent monthly index levels derived from compounded daily returns that reflect the reinvestment of all dividends.

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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 securities was set to $100.00 on December 31, 2010.

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

The following discussion should be read in conjunction with our consolidated financial statements and the notes thereto, which are in this Annual Report on Form 10-K.



	2015		2014		2013		2012		2011

	(in thousands, except per share data)

Revenues	$	2,774,565	$	4,556,622	$	4,350,057	$	4,293,276	$	1,766,287
Income (loss) from operations		(1,952,989)		546,604		214,170		710,373		298,809
Net income (loss) from continuing operations		(1,807,763)		280,790		45,485		383,917		159,491
Loss from discontinued operations, net of tax		(46,955)		(22,973)		(156,903)		(17,982)		(16,937)
Net income (loss)		(1,854,718)		257,817		(111,418)		365,935		142,554
Net income (loss) from continuing operations per share:
Basic		(12.02)		1.81		0.29		2.57		2.00
Diluted		(12.02)		1.79		0.28		2.54		1.97
Net loss from discontinued operations per share:
Basic		(0.31)		(0.15)		(0.99)		(0.12)		(0.21)
Diluted		(0.31)		(0.14)		(0.97)		(0.12)		(0.21)
Net income (loss) per share:
Basic		(12.33)		1.66		(0.70)		2.45		1.79
Diluted		(12.33)		1.65		(0.69)		2.42		1.76
Cash dividends declared per share		0.32		0.24		0.08		-		-
Total assets		4,914,244		7,317,782		7,366,943		7,723,885		4,016,735
Long-term debt, net		1,588,263		1,600,373		1,610,956		1,769,619		1,653,677
Decommissioning liabilities, less current portion		98,890		88,000		56,197		93,053		108,220
Stockholders' equity		2,210,812		4,079,738		4,131,444		4,231,079		1,453,599

For 2015, net loss from continuing operations includes $1,738.9 million of reduction in value of assets.

For 2013, net income from continuing operations includes $300.1 million of reduction in value of assets.

For 2012, net income from continuing operations includes operating results from our acquisition of Complete in February 2012.

In 2015, we adopted Accounting Standards Update (ASU) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. This guidance requires that debt on the balance sheet be presented net of unamortized debt issuance costs. This guidance is required to be applied retrospectively to all prior periods. As a result, as of December 31, 2014, 2013, 2012 and 2011, total assets and long-term debt, net presented in the table above have been adjusted for $27.5 million, $35.6 million, $44.9 million and $31.4 million, respectively, to reflect the reclassification of the debt issuance costs.

In addition, in 2015, we adopted ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes. This guidance requires the classification of all deferred tax assets and liabilities as non-current on the balance sheet instead of separating deferred taxes into current and non-current amounts. We adopted this guidance as of December 31, 2015 and applied the change retrospectively to prior periods. As a result, as of December 31, 2014, 2013 and 2012, total assets presented in the table above have been adjusted for $32.1 million, $8.8 million and $34.1 million, respectively, to reflect the reclassification of the current deferred tax assets to non-current deferred tax liabilities.

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

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

Executive Summary

We experienced a decline in revenue and incurred losses from operations during 2015, as compared to 2014, resulting from decreased oil and gas prices and the corresponding negative impact on oil field activity levels and pricing for our products and services. To a large degree, our business depends upon the spending levels of oil and gas companies for exploration, development and production activities, which are sensitive to changes in crude oil and natural gas prices. The significant decline in oil and gas prices during 2015 resulted in our customers curtailing their operations, reducing their capital expenditures, requesting pricing concessions and /or other arrangements designed to reduce their drilling, completion and operating costs.

We generated $2,774.6 million of revenue during 2015, a 39% decrease from $4,556.6 million of revenue generated in 2014. We reported a loss from operations of $1,953.0 million in 2015, compared to operating income of $546.6 million in 2014. This decrease was due to a decline in activity and pricing in most of our product and service lines. We also implemented several company-wide cost reduction initiatives. As a result, we recorded $1,785.7 million in reduction in value of assets and other charges during 2015. These charges were recorded primarily as a result of the downturn in the energy market and consisted of $1,326.7 million of goodwill impairment, $412.2 million impairment of long-lived assets and $46.8 million of expenses for severance costs and facility closures.

Deteriorating oil and natural gas prices made 2015 an extremely demanding year due to reductions in activity and significant pricing pressure. As a result, we took steps to reduce our cost structure, consolidate product service lines and reorganize businesses. Since the end of 2014, we reduced our workforce by over 40% to help mitigate the current market conditions. During 2015, we also reduced our general and administrative expenses by 18% as compared to 2014 levels.

The ultimate impact on us of the current industry downturn will depend upon its length and several other factors, many of which remain beyond our control. We will continue refining our business and adjusting our cost structure to respond to market conditions. Additionally, we believe we have positioned businesses with competitive advantages to respond quickly when the market ultimately recovers. We have made a concerted effort to preserve cash and generate positive free cash flows by reducing capital expenditures and operating costs, which we will continue to do throughout 2016. In February 2016, we also extended the term of our credit facility for an additional two years so we have no current debt maturities until 2019 as part of our objective to continue to manage our balance sheet and provide liquidity in the current tough industry environment.

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. In 2015, 28% of segment revenue was derived from U.S. land market areas (down from 35% in 2014), while 43% of segment revenue was from the Gulf of Mexico market area (up from 40% in 2014) and 29% of segment revenue was from international market areas (up from 25% in 2014). Premium drill pipe accounted for more than 60% of this segment’s revenue in 2015, while bottom hole assemblies and accommodations each accounted for approximately 20% of this segment’s revenue in 2015.

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. All of this segment’s revenue is derived in the U.S. land market areas. Demand for these services in the U.S. land market can change quickly and is highly dependent on the number of oil and natural gas wells drilled and completed. Given the cyclical nature of these drilling and completion activities in the U.S. land market, 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 reduce cyclical margin volatility, we contract our pressure pumping horsepower that is used for horizontal well fracturing when possible. Additionally, the volumes of produced water that we

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permanently dispose of for our customers generate stable revenue streams as they are primarily a by-product of ongoing oil and gas production from both newly completed and mature wells.

Pressure pumping is the largest service offering in this segment, representing more than 40% of this segment’s revenue in 2015. Fluid management represented more than 30% of this segment’s revenue in 2015, while well service rigs accounted for more than 15% of this segment’s revenue in 2015.

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. These services are labor intensive and margins fluctuate based on how much capital our customers allocate towards enhancing existing oil and gas production from mature wells.

In 2015, 50% of segment revenue was derived from the U.S. land market area (down from 64% in 2014), while 10% of segment revenue was from the Gulf of Mexico market area (unchanged from 2014) and 40% of this segment’s revenue was from international market areas (up from 26% in 2014). Hydraulic workover and snubbing is the largest service offering in this segment, accounting for more than 25% of this segment’s revenue in 2015. Coiled tubing represented more than 20% of this segment’s revenue in 2015, while electric line accounted for more than 15% of this segment’s revenue in 2015.

The Technical Solutions segment consists of products and services that address customer-specific needs and include offerings such as pressure control services, completion tools and services, end-of-life services, production handling arrangements, and the production and sale of oil and gas. 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.

In 2015, revenue derived from the U.S. land market area was 12% of segment revenue (down from 20% in 2014), while 65% of segment revenue was from the Gulf of Mexico market area (up from 57% in 2014) and 23% of segment revenue was from international market areas (unchanged from 2014). Completion tools and products represent the largest service offering in this segment, accounting for more than 35% of this segment’s revenue in 2015.

Market drivers and conditions

The oil and gas industry is highly cyclical and seasonal. Activity levels are driven by traditional energy industry activity indicators, which include current and expected commodity prices, drilling rig counts, well counts, well completions and workover activity, geologic characteristics of producing wells which determine the number and intensity of services required per well, oil and gas production levels, and our customers’ spending levels allocated towards drilling and production work.

Historical market indicators are listed below:



	2015		% Change	2014		% Change	2013
Worldwide Rig Count (1)
U.S. (land and offshore)		977	-48%		1,862	6%		1,761
International (2)		1,167	-13%		1,337	3%		1,296
Commodity Prices (average)
Crude Oil (West Texas Intermediate)	$	48.66	-48%	$	93.17	-5%	$	97.98
Natural Gas (Henry Hub)	$	2.62	-40%	$	4.37	17%	$	3.73

(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.

We attribute revenue to countries based on the location where services are performed or the destination of the rental or sale of products. The following table compares our revenues generated from major geographic regions (in thousands).



	Revenue
	2015		%	2014		%	Change
U.S. Land	$	1,536,893	55%	$	3,021,830	66%	$	(1,484,937)
Gulf of Mexico		648,178	23%		827,099	18%		(178,921)
International		589,494	21%		707,693	16%		(118,199)
Total	$	2,774,565	100%	$	4,556,622	100%	$	(1,782,057)

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In 2015, our U.S. land, Gulf of Mexico and international revenues decreased 49%, 22% and 17%, respectively. Revenue for all major product and service lines across all of our segments in these geographical locations were negatively impacted by the continued decline in oil and gas prices, which led to lower levels of activity and pricing pressure for our services.

Comparison of the Results of Operations for the Years Ended December 31, 2015 and 2014

For 2015, our revenue was $2,774.6 million, resulting in a loss from continuing operations of $1,807.8 million, or $12.02 loss per share. Net loss was $1,854.7 million, or $12.33 loss per share. Included in the results for 2015 were pre-tax charges of $1,738.9 million related to the reduction in value of assets and $46.8 million expense for severance and facility closures. For December 2014, our revenue was $4,556.6 million, resulting in income from continuing operations of $280.8 million, or $1.79 per diluted share. Net income was $257.8 million, or $1.65 per diluted share.

The following table compares our operating results for 2015 and 2014 (in thousands). Cost of services and rentals excludes depreciation, depletion, amortization and accretion for each of our business segments.



	Revenue						Cost of Services and Rentals
	2015		2014		Change		2015		%	2014		%	Change
Drilling Products and Services	$	583,139	$	904,358	$	(321,219)	$	196,921	34%	$	282,023	31%	$	(85,102)
Onshore Completion and
Workover Services		934,274		1,732,833		(798,559)		773,119	83%		1,205,443	70%		(432,324)
Production Services		759,606		1,350,956		(591,350)		594,286	78%		941,030	70%		(346,744)
Technical Solutions		497,546		568,475		(70,929)		301,486	61%		306,337	54%		(4,851)
Total	$	2,774,565	$	4,556,622	$	(1,782,057)	$	1,865,812	67%	$	2,734,833	60%	$	(869,021)

The following provides a discussion of our results on a segment basis:

Drilling Products and Services Segment

Revenue for our Drilling Products and Services segment was $583.1 million for 2015, a 36% decrease from 2014. Cost of services and rentals as a percentage of revenue increased to 34% of segment revenue in 2015, as compared to 31% in 2014. Revenue from our Gulf of Mexico market area decreased 30%, revenue generated in our U.S. land market area decreased 49% and revenue from our international market areas decreased 24%. Revenues for all major product and service lines of the segment were impacted by the decline in oil and gas prices which led to lower levels of activity in the oil and gas industry and pricing pressure for our services. In addition, the decrease in income from operations for this segment was impacted by a $40.2 million reduction in value of assets and a $1.1 million expense for severance.

Onshore Completion and Workover Services Segment

Revenue for our Onshore Completion and Workover Services segment was $934.3 million for 2015, a 46% decrease from 2014. Cost of services and rentals as a percentage of revenue increased to 83% of segment revenue in 2015, as compared to 70% in 2014. All product and service lines in this segment were impacted negatively by reduced customer spending and activity as well as pricing pressure in North America during 2015. In addition, the loss from operations for 2015 was impacted by a $740.0 million reduction in value of goodwill, a $43.3 million reduction in value of long-lived assets and a $22.5 million expense for severance and facility closures.

Production Services Segment

Revenue for our Production Services segment was $759.6 million for 2015, a 44% decline from 2014. Cost of services and rentals as a percentage of revenue increased to 78% of segment revenue in 2015, as compared to 70% in 2014. Revenue derived from the Gulf of Mexico market area decreased 46%, revenue from the U.S. land market area decreased 56% and revenue from international market areas decreased 13%. The Production Services segment’s revenue was lower in all product and service lines primarily due to lower levels of activity and pricing pressure for our services. In addition, the loss from operations for 2015 for this segment was impacted by a $586.7 million reduction in value of goodwill, a $149.2 million reduction in value of long-lived assets, a $15.2 million expense relating to the retirements of long-lived assets, a $39.4 million loss on sale of a business and a $16.3 million expense for severance and facility closures.

Technical Solutions Segment

Revenue for our Technical Solutions segment was $497.6 million for 2015, a 12% decrease from 2014. Cost of services and rentals as percentage of revenue increased to 61% of segment revenue in 2015, as compared to 54% in 2014. Revenue derived from the Gulf of Mexico market area decreased 1%, revenue from the U.S. land market area decreased 45% and revenue from international market areas decreased 13%. The Technical Solutions segment’s revenue was lower in all product and service lines primarily due to lower levels of

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activity and pricing pressure for our services. In addition, the loss from operations for 2015 for this segment was impacted by a $124.9 million reduction in value of long-lived assets and a $6.9 million expense for severance and facility closures.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion decreased to $612.1 million during 2015 from $650.8 million in 2014. Depreciation and amortization expense decreased for our Production Services segment by $34.4 million, or 21%; for our Onshore Completion and Workover Services segment by $7.8 million, or 3%, and for our Technical Solutions segment by $3.9 million, or 6%, as a result of certain assets being fully depreciated and reductions in value of long-lived assets recorded during 2015. Depreciation and amortization expense for our Drilling Products and Services segment increased by $7.4 million, or 4%, primarily due to capital expenditures.

General and Administrative Expenses

General and administrative expenses decreased to $510.7 million during 2015 from $624.4 million in 2014. The decrease is primarily attributable to lower levels of employee and infrastructure-related expenses as a result of our cost reduction programs.

Reduction in Value of Assets

During 2015, we recorded $1,738.9 million reduction in value of assets. The reduction in value of assets included $740.0 and $586.7 million related to the Onshore Completion and Workover Services and the Production Services segments’ goodwill impairment, respectively. In addition, the reduction in value of assets included $412.2 million related to the reduction in long-lived assets across all of our operating segments. See note 3 to our consolidated financial statements for further discussion of the reduction in value of assets.

Income Taxes

Our effective income tax rate for 2015 was a 12.2% tax benefit compared to a 36.5% tax expense for 2014. The decrease in the effective income tax rate was primarily due to the reduction in value of goodwill which is non-deductible for income tax purposes. See note 8 to our consolidated financial statements.

Discontinued Operations

Discontinued operations include operating results for both our subsea construction business and our conventional decommissioning business. Losses from discontinued operations, net of tax, were $47.0 million during 2015, as compared to $23.0 million during 2014. The increase in the loss from discontinued operations is primarily due to the $34.6 million reduction in value of the marine vessels and equipment recorded during 2015.

Comparison of the Results of Operations for the Years Ended December 31, 2014 and 2013

For 2014, our revenue was $4,556.6 million, resulting in income from continuing operations of $280.8 million, or $1.79 per diluted share. Net income was $257.8 million, or $1.65 per diluted share. For 2013, our revenue was $4,350.1 million, resulting in income from continuing operations of $45.5 million, or $0.28 per diluted share. Included in the results for 2013 were pre-tax charges of $300.1 million related to the reduction in value of assets and $5.6 million primarily related to cost savings initiatives in certain of our U.S. land market areas. Net loss was $111.4 million, or $0.69 loss per share.

The following table compares our operating results for 2014 and 2013 (in thousands). Cost of services and rentals excludes depreciation, depletion, amortization and accretion for each of our business segments.



	Revenue						Cost of Services and Rentals
	2014		2013		Change		2014		%	2013		%	Change
Drilling Products and Services	$	904,358	$	820,538	$	83,820	$	282,023	31%	$	268,127	33%	$	13,896
Onshore Completion and
Workover Services		1,732,833		1,607,268		125,565		1,205,443	70%		1,091,956	68%		113,487
Production Services		1,350,956		1,434,990		(84,034)		941,030	70%		1,002,628	70%		(61,598)
Technical Solutions		568,475		487,261		81,214		306,337	54%		270,879	56%		35,458
Total	$	4,556,622	$	4,350,057	$	206,565	$	2,734,833	60%	$	2,633,590	61%	$	101,243

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The following provides a discussion of our results on a segment basis:

Drilling Products and Services Segment

Revenue for our Drilling Products and Services segment was $904.3 million for 2014, a 10% increase from 2013. Cost of services and rentals as a percentage of revenue decreased to 31% of segment revenue in 2014, as compared to 33% in 2013, primarily due to an increase in revenues with a more favorable product mix. Revenue from our Gulf of Mexico market area increased 20% due to increases in rentals of premium drill pipe and accommodations. Revenue generated from our U.S. land market area increased 12%, primarily due to increases in revenue from rentals of accommodations and bottom hole assemblies. These increases were partially offset by a 5% decrease in revenue generated from our international market areas, which was due to a decrease in rentals of accommodations and bottom hole assemblies.

Onshore Completion and Workover Services Segment

Revenue for our Onshore Completion and Workover Services segment was $1,732.8 million for 2014, an 8% increase from 2013. Cost of services and rentals as a percentage of revenue increased to 70% of segment revenue in 2014, as compared to 68% in 2013. The increase is primarily due to higher levels of repair and maintenance expense for pressure pumping services. The increase in revenue was driven by higher demand for pressure pumping services and fluid management.

Production Services Segment

Revenue for our Production Services segment was $1,351.0 million for 2014, a 6% decline from 2013. Cost of services and rentals as a percentage of revenue remained at 70% of segment revenue. Revenue derived from the Gulf of Mexico market area decreased 33% due to decreased activity for pressure control, hydraulic workover and snubbing and wireline services. Revenue from the U.S. land market area decreased 2% as we experienced declines in coiled tubing, remedial pumping, and hydraulic workover and snubbing activity. Revenue from international market areas remained flat for 2014 as compared to 2013.

Technical Solutions Segment

Revenue for our Technical Solutions segment was $568.5 million for 2014, a 17% increase from 2013. Cost of services and rentals as a percentage of revenue decreased to 54% of segment revenue in 2014, as compared to 56% in 2013, primarily due to a more favorable product mix. Revenue in our international market areas increased 48% primarily as a result of an increase in demand for well control work and completion tools and products. Revenue in our Gulf of Mexico market area increased 2%, primarily due to increases in our oil and gas activities. Revenue in our U.S. land market area increased 39% primarily due to an increase in demand for completion tools and products and well control work.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $650.8 million during 2014 from $604.4 million in 2013. Depreciation and amortization expense increased for our Drilling Products and Services segment by $18.3 million, or 11%; for our Onshore Completion and Workover Services segment by $17.3 million, or 8%, and for our Technical Solutions segment by $23.7 million, or 56%, primarily due to capital expenditures. Depreciation and amortization expense for our Production Services segment decreased by $12.9 million, or 7%, as a result of certain assets being fully depreciated.

General and Administrative Expenses

General and administrative expenses increased to $624.4 million during 2014 from $597.8 million in 2013. General and administrative expenses increased year over year primarily due to an increase in employee-related expenses and expanding infrastructure to support growth in both U.S. and international markets.

Reduction in Value of Assets

During 2013, we recorded $300.1 million of reduction in value of assets. The reduction in value of assets included $180.3 million related to long-lived assets and certain other assets in our 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 Technical Solutions segment, $14.5 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 3 to our consolidated financial statements for further discussion of the reduction in value of assets.

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Income Taxes

The decrease in the effective tax rate during 2014 relative to 2013 was primarily due to an increase in operating income from continuing operations in jurisdictions with tax rates lower than the United States. The 2013 rate was above normal 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. The absence of asset value reductions in 2014 caused the effective tax rate to normalize during the year. See note 8 to our consolidated financial statements.

Discontinued Operations

Liquidity and Capital Resources

During 2015, we generated net cash from operating activities of $632.6 million as compared to $1,033.0 million in 2014. Our primary liquidity needs are for working capital and to fund debt service, dividend payments and capital expenditures. 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 $564.0 million as of December 31, 2015 as compared to $393.0 million as of December 31, 2014. As of December 31, 2015, $140.1 million of our cash balance was held outside the United States. Cash balances held in foreign jurisdictions could be repatriated to the United States; however, they would be subject to federal income taxes, less applicable foreign tax credits. We have not provided U.S. income tax expense on earnings of our foreign subsidiaries because we expect to reinvest the undistributed earnings indefinitely.

We spent $358.2 million of cash on capital expenditures during 2015. Approximately $129.5 million was used to expand and maintain our Drilling Products and Services segment’s equipment inventory, and approximately $103.0 million, $72.0 million and $53.7 million was spent to expand and maintain the asset bases of our Onshore Completion and Workover Services, Production Services and Technical Solutions segments, respectively. In addition to normal course of business capital expenditures, during 2015, we spent $46.4 million to purchase two leased vessels. In addition, the purchase price for one of the vessels included the extinguishment of the related capital lease obligation of $20.9 million.

During 2015, we generated $274.4 million of free cash flow. During 2016, we intend to significantly reduce our capital expenditures with the objective to at least break even on a free cash flow basis. We define free cash flow as operating cash flows less capital expenditures.

At December 31, 2015, we had a credit facility that was comprised of a $600.0 million revolving line of credit and a $325.0 million term loan. In February 2016, we amended and extended our credit facility. The amended agreement results in a $470.3 million revolving credit facility which matures in 2019 and no longer has a term loan component. As of February 22, 2016, we had $325.0 million of borrowings and $42.2 million of letters of credit outstanding under the amended credit facility. Borrowings under the credit facility bear interest at LIBOR plus margins that depend on our credit rating. Indebtedness under the credit facility is secured by substantially all of our assets, including the pledge of the stock of our principal domestic subsidiaries. The credit facility contains customary events of default and requires that we satisfy various financial covenants. It also limits our ability to pay dividends or make other distributions, make acquisitions, create liens or incur additional indebtedness. At December 31, 2015, 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 1st and November 1st 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, 2015, 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 15th and December 15th 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, 2015, we were in compliance with all such covenants.

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The following table summarizes our contractual cash obligations and commercial commitments as of December 31, 2015 (in thousands):


Contractual Obligations	Total		< 1 Year		1 - 3 Years		3 - 5 Years		More Than 5 Years
Long-term debt, including estimated interest payments	$	2,116,004	$	99,898	$	202,220	$	956,886	$	857,000
Decommissioning liabilities, undiscounted		200,712		20,270		18,694		2,427		159,321
Operating leases		152,711		45,694		55,666		26,177		25,174
Other long-term liabilities		184,634		-		92,964		24,938		66,732
Total	$	2,654,061	$	165,862	$	369,544	$	1,010,428	$	1,108,227

The table above reflects only contractual obligations as of December 31, 2015 and excludes, among other things, (i) commitments made thereafter, (ii) options to purchase assets, (iii) contingent liabilities, (iv) capital expenditures that we plan, but are not committed, to make and (v) open purchase orders. The table reflects changes in the timing of debt and estimated interest payments pursuant to the amended credit facility dated February 22, 2016.

Critical Accounting Policies and Estimates

The accounting policies described below are considered critical in obtaining an understanding of our consolidated financial statements because their application requires significant estimates and judgments by management in preparing our consolidated financial statements. Management’s estimates and judgments are inherently uncertain and may differ significantly from actual results achieved. Management considers an accounting estimate to be critical if the following conditions apply:

the estimate requires significant assumptions; and

changes in estimate could have a material effect on our consolidated results of operations or financial condition; or

if different estimates that could have been selected had been used, there could be a material effect on our consolidated results of operations or financial condition.

It is management’s view that the current assumptions and other considerations used to estimate amounts reflected in our consolidated financial statements are appropriate. However, actual results can differ significantly from those estimates under different assumptions and conditions. The sections below contain information about our most critical accounting estimates.

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. 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 2015, we recorded $412.2 million in expense in connection with the reduction in value of our long-lived assets across all of our operating segments. See note 3 to our consolidated financial statements for further information about these impairments.

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 or when changes in circumstances indicate that the carrying value may not be recoverable. Our annual testing of goodwill is based on carrying value and our estimate of fair value as of October 1. 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 unit exceeds the carrying amount, no impairment loss is recognized. If the estimated fair value of the reporting unit is below the carrying value, then a second step must be performed to determine the goodwill impairment, if any. In this second step, the estimated fair value is used as the purchase price in a hypothetical acquisition of the reporting unit. The hypothetical purchase price is allocated to the reporting unit’s assets and liabilities, with the residual amount representing an implied fair value of the goodwill. The carrying amount of the goodwill is then compared to the implied fair value of the goodwill for each reporting unit and is written down to the implied fair value amount, if lower. We use all available

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information to estimate fair values of the reporting units, including discounted cash flows. We engage third-party appraisal firms to assist in fair value determination of property, plant and equipment, intangible assets and any other significant assets or liabilities when appropriate. 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. During 2015, we recorded a reduction in value of goodwill of $1,326.7 million, of which $740.0 million related to impairment of the goodwill in our Onshore Completion and Workover Services segment and $586.7 million related to the impairment of goodwill in our Production Services segment. See note 3 to our consolidated financial statements for further information about these impairments.

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

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

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

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 an oil and gas property as well as the related well abandonment and decommissioning liability. Wild Well follows the successful efforts method of accounting for its investment in the oil and gas property. 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 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 property.

Our oil and gas property is assessed for impairment in value 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.

Off-Balance Sheet Arrangements

As of December 31, 2015, we had no off-balance sheet arrangements.

Hedging Activities

We have three 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.

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Recently Adopted and Issued Accounting Guidance

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

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 operations in the United Kingdom and Europe, is the U.S. dollar, but a portion of the revenues from our foreign operations is paid in foreign currencies. The effects of foreign currency fluctuations are partly mitigated because local expenses of such foreign operations are also generally denominated in the same currency. We continually monitor the currency exchange risks associated with all contracts not denominated in the U.S. dollar.

Assets and liabilities of certain subsidiaries in 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, 2015, we had no outstanding foreign currency forward contracts.

Interest Rate Risk

As of December 31, 2015, our debt was comprised of the following (in thousands):



	Fixed Rate Debt		Variable Rate Debt
Term loan due 2017	$	-	$	325,000
6 3/8 % Senior Notes due 2019		500,000		-
7 1/8% Senior Notes due 2021		500,000		300,000
Other		13,046		-
Total Debt	$	1,013,046	$	625,000

Variable debt of $300 million represents the portion of the $800 million aggregate principal amount of our 7 1/8% senior notes subject to the fixed-to-variable interest rate swap agreements. Based on the amount of this debt outstanding as of December 31, 2015, a 10% increase in the variable interest rate would increase our interest expense for the year ended December 31, 2015 by $2.3 million, while a 10% decrease would decrease our interest expense by $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. For additional information on the impact of changes in commodities prices on our business and prospects, see Item 1A to this Annual Report.

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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, 2015 and 2014, 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, 2015. In connection with our audits of the consolidated financial statements, we also have audited 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, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, Superior Energy Services, Inc. has changed its method of accounting for debt issuance costs and method of accounting for deferred income taxes as of December 31, 2015. Additionally, as discussed in Note 1 to the consolidated financial statements, Superior Energy Services, Inc. has changed its method for accounting for discontinued operations as of January 1, 2015.

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, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 25, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

KPMG LLP

Houston, Texas

February 25, 2016

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2015 and 2014
(in thousands, except share data)
	2015		2014
ASSETS
Current assets:
Cash and cash equivalents	$	564,017	$	393,046
Accounts receivable, net of allowance for doubtful accounts of $28,242 and
$22,076 as of December 31, 2015 and December 31, 2014, respectively		428,514		926,768
Prepaid expenses		42,298		74,750
Inventory and other current assets		165,062		185,429
Assets held for sale		95,234		116,680
Total current assets		1,295,125		1,696,673
Property, plant and equipment, net of accumulated depreciation and depletion		2,123,291		2,733,839
Goodwill		1,140,101		2,468,409
Notes receivable		52,382		25,970
Intangible and other long-term assets, net of accumulated amortization		303,345		392,891
Total assets	$	4,914,244	$	7,317,782
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	114,475	$	225,306
Accrued expenses		271,246		363,747
Income taxes payable		9,185		40,213
Current maturities of long-term debt		29,957		20,941
Current portion of decommissioning liabilities		19,052		-
Liabilities held for sale		4,661		61,840
Total current liabilities		448,576		712,047
Deferred income taxes		383,069		670,858
Decommissioning liabilities		98,890		88,000
Long-term debt, net		1,588,263		1,600,373
Other long-term liabilities		184,634		166,766
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 and Outstanding-150,861,500 as of December 31, 2015 Authorized-250,000,000, Issued-149,648,826, Outstanding-149,708,825 as of December 31, 2014		151		150
Additional paid in capital		2,664,517		2,620,328
Accumulated other comprehensive loss, net		(45,694)		(36,280)
Retained earnings (deficit)		(408,162)		1,495,540
Total stockholders’ equity		2,210,812		4,079,738
Total liabilities and stockholders’ equity	$	4,914,244	$	7,317,782

See accompanying notes to consolidated financial statements.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
Years Ended December 31, 2015, 2014, and 2013
(in thousands, except per share data)

	2015		2014		2013
Revenues:
Services	$	2,104,942	$	3,466,279	$	3,371,847
Rentals		669,623		1,090,343		978,210
Total revenues		2,774,565		4,556,622		4,350,057
Costs and expenses:
Cost of services (exclusive of items shown separately below)		1,575,653		2,308,270		2,244,881
Cost of rentals (exclusive of items shown separately below)		290,159		426,563		388,709
Depreciation, depletion, amortization and accretion		612,147		650,814		604,441
General and administrative expenses		510,708		624,371		597,778
Reduction in value of assets		1,738,887		-		300,078
Income (loss) from operations		(1,952,989)		546,604		214,170
Other expense:
Interest expense, net		(97,318)		(96,734)		(107,902)
Other expense		(9,476)		(7,681)		(5,511)
Income (loss) from continuing operations before income taxes		(2,059,783)		442,189		100,757
Income taxes		(252,020)		161,399		55,272
Net income (loss) from continuing operations		(1,807,763)		280,790		45,485
Loss from discontinued operations, net of income tax		(46,955)		(22,973)		(156,903)
Net income (loss)	$	(1,854,718)	$	257,817	$	(111,418)
Earnings (loss) per share information:
Basic:
Continuing operations	$	(12.02)	$	1.81	$	0.29
Discontinued operations		(0.31)		(0.15)		(0.99)
Basic earnings (loss) per share	$	(12.33)	$	1.66	$	(0.70)
Diluted:
Continuing operations	$	(12.02)	$	1.79	$	0.28
Discontinued operations		(0.31)		(0.14)		(0.97)
Diluted earnings (loss) per share	$	(12.33)	$	1.65	$	(0.69)
Cash dividends declared per share	$	0.32	$	0.24	$	0.08
Weighted average common shares used in computing
earnings (loss) per share:
Basic		150,461		155,154		159,206
Incremental common shares from stock based compensation		-		1,572		1,574
Diluted		150,461		156,726		160,780


SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Comprehensive Income (Loss)
Years Ended December 31, 2015, 2014, and 2013
(in thousands)

	2015		2014		2013
Net income (loss)	$	(1,854,718)	$	257,817	$	(111,418)
Unrealized net gain on available-for-sale securities, net of tax		-		-		(256)
Reclassification adjustment of unrealized net loss on available-for-sale securities, net of tax		-		1,153		-
Change in cumulative translation adjustment, net of tax		(9,414)		(19,933)		2,073
Comprehensive income (loss)	$	(1,864,132)	$	239,037	$	(109,601)

See accompanying notes to consolidated financial statements.



SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders’ Equity
Years Ended December 31, 2015, 2014, and 2013
(in thousands, except share data)

						Accumulated
				Additional		other
	Common	Common		paid-in		comprehensive		Retained
	stock shares	stock		capital		loss, net		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 available-for-sale securities	-		-		-		(256)		-		(256)
Cash dividends declared ($0.08 per share)	-		-		-		-		(12,759)		(12,759)
Stock-based compensation expense, net of forfeitures	1,154,032		1		26,071		-		-		26,072
Exercise of stock options	470,712		-		6,263		-		-		6,263
Shares withheld and retired	(119,070)		-		(2,811)		-		-		(2,811)
Tax benefit from stock-based compensation	-		-		(1,185)		-		-		(1,185)
Shares issued under Employee Stock Purchase Plan	185,407		-		5,013		-		-		5,013
Vesting of restricted stock assumed with acquisition of Complete	210,951		-		-		-		-		-
Shares repurchased and retired	(426,883)		-		(10,627)		-		-		(10,627)
Balances, December 31, 2013	158,976,784	$	159	$	2,873,579	$	(17,500)	$	1,275,206	$	4,131,444
Net income	-		-		-		-		257,817		257,817
Foreign currency translation adjustment	-		-		-		(19,933)		-		(19,933)
Reclassification adjustment of unrealized net loss on available-for-sale securities, net of tax	-		-		-		1,153		-		1,153
Cash dividends declared ($0.24 per share)	-		-		-		-		(37,483)		(37,483)
Stock-based compensation expense, net of forfeitures	(152,447)		-		30,982		-		-		30,982
Exercise of stock options	880,687		1		10,560		-		-		10,561
Restricted stock units vested	95,914		-		-		-		-		-
Shares withheld and retired	(267,340)		-		(7,315)		-		-		(7,315)
Tax benefit from stock-based compensation	-		-		6,160		-		-		6,160
Shares issued under Employee Stock Purchase Plan	246,480		-		6,096		-		-		6,096
Vesting of restricted stock assumed with acquisition of Complete	114,839		-		-		-		-		-
Shares repurchased and retired	(10,246,091)		(10)		(299,734)		-		-		(299,744)
Balances, December 31, 2014	149,648,826	$	150	$	2,620,328	$	(36,280)	$	1,495,540	$	4,079,738

See accompanying notes to consolidated financial statements.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders’ Equity (continued)
Years Ended December 31, 2015, 2014, and 2013
(in thousands, except share data)


						Accumulated
	Common			Additional		other
	stock	Common		paid-in		comprehensive		Retained
	shares	stock		capital		loss, net		earnings		Total
Balances, December 31, 2014	149,648,826	$	150	$	2,620,328	$	(36,280)	$	1,495,540		$ 4,079,738
Net loss	-		-		-		-		(1,854,718)		(1,854,718)
Foreign currency translation adjustment	-		-		-		(9,414)		-		(9,414)
Cash dividends declared ($0.32 per share)	-		-		-		-		(48,984)		(48,984)
Stock-based compensation expense, net of forfeitures	-		-		32,661		-		-		32,661
Restricted stock forfeited	(48,374)		-		-		-		-		-
Exercise of stock options	506,029		1		8,819		-		-		8,820
Restricted stock units vested	460,400		-		-		-		-		-
Shares withheld and retired	(323,537)		-		(5,696)		-		-		(5,696)
Tax benefit from stock-based compensation	-		-		(2,174)		-		-		(2,174)
Shares issued under Employee Stock Purchase Plan	332,534		-		5,568		-		-		5,568
Shares issued to pay performance share units	224,303		-		5,011		-		-		5,011
Vesting of restricted stock assumed with acquisition of Complete	61,319		-		-		-		-		-
Balances, December 31, 2015	150,861,500	$	151	$	2,664,517	$	(45,694)	$	(408,162)	$	2,210,812

See accompanying notes to consolidated financial statements.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years Ended December 31, 2015, 2014, and 2013
(in thousands)
	2015		2014		2013
Cash flows from operating activities:
Net income (loss)	$	(1,854,718)	$	257,817	$	(111,418)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		612,147		652,143		625,928
Deferred income taxes		(288,671)		(49,567)		14,435
Reduction in value of assets		1,738,887		-		419,380
Stock based compensation expense		46,485		42,748		35,832
Amortization of debt issuance costs		7,643		8,110		8,919
Gains on sales of assets and businesses		(14,803)		(12,777)		(657)
Other reconciling items, net		49,042		(6,803)		(899)
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		501,269		(9,487)		85,423
Inventory and other current assets		33,282		53,594		(70,995)
Accounts payable		(105,801)		36,450		(32,304)
Accrued expenses		(116,573)		16,411		25,154
Income taxes		(30,891)		46,134		(162,148)
Other, net		55,314		(1,762)		56,158
Net cash provided by operating activities		632,612		1,033,011		892,808
Cash flows from investing activities:
Payments for capital expenditures		(358,226)		(616,102)		(608,960)
Purchase of leased vessels		(46,442)		-		-
Cash proceeds from sales of assets and businesses		14,110		147,305		6,292
Sale of available-for-sale securities		-		10,622		-
Acquisitions of businesses, net of cash acquired		-		(24,327)		(23,797)
Cash proceeds from insurance settlement		-		-		22,650
Other		2,290		7,767		(1,753)
Net cash used in investing activities		(388,268)		(474,735)		(605,568)
Cash flows from financing activities:
Proceeds from revolving line of credit		7,475		14,736		581,771
Payments on revolving line of credit		(7,475)		(14,736)		(581,771)
Payment to extinguish capital lease obligation		(20,933)		-		-
Proceeds from issuance of long-term debt		14,733		2,602		-
Principal payments on long-term debt		(21,038)		(21,564)		(170,000)
Share repurchases		-		(299,734)		(10,627)
Cash dividends		(48,139)		(49,756)		-
Proceeds from exercise of stock options		8,820		10,560		6,264
Other		(2,302)		724		(6,840)
Net cash used in financing activities		(68,859)		(357,168)		(181,203)
Effect of exchange rate changes on cash		(4,514)		(4,109)		(1,189)
Net increase in cash and cash equivalents		170,971		196,999		104,848
Cash and cash equivalents at beginning of period		393,046		196,047		91,199
Cash and cash equivalents at end of period	$	564,017	$	393,046	$	196,047

See accompanying notes to consolidated financial statements.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Years Ended December 31, 2015, 2014 and 2013

(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 2015 presentation.

Business

The Company provides a wide variety of services and products to the energy industry related to the exploration, development and production of oil and natural gas. The Company serves major, national and independent oil and natural gas companies throughout the world. The Company’s operations are managed and organized by business units, which offer products and services within the various phases of a well’s economic life cycle. The Company reports its operating results in four business segments: Drilling Products and Services; Onshore Completion and Workover Services; Production Services; and Technical Solutions. Given the Company’s history of growth and long-term strategy of expanding geographically, the Company also provides supplemental segment revenue information in three geographic areas: U.S. land; Gulf of Mexico; and International.

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. land and Gulf of Mexico areas 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. There were no customers that exceeded 10% of total revenue in 2015 and 2014. In 2013 EOG Resources, Inc. accounted for 10% of total revenue, primarily within the Onshore Completion and Workover Services segment.

In addition to trade receivables, other financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and derivative instruments used in hedging activities. The 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.

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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. The components of inventory balances are as follows (in thousands):



	December 31,
	2015		2014
Finished goods	$	71,951	$	72,788
Raw materials		23,418		29,718
Work-in-process		18,203		20,317
Supplies and consumables		35,189		42,739
Total	$	148,761	$	165,562

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 and oil and natural gas properties, depreciation is computed using the straight line method over the estimated useful lives of the related assets as follows:

Buildings and improvements	5	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	10	years
Furniture and fixtures	2	to	10	years

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.

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. 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 3 for a discussion of the reduction in value of long-lived assets recorded during 2015 and 2013.

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Goodwill

The following table summarizes the activity for the Company’s goodwill (in thousands):



			Onshore
	Drilling		Completion
	Products		and Workover		Production
	and Services		Services		Services		Total
Balance, December 31, 2013	$	144,872	$	1,419,550	$	893,687	$	2,458,109
Acquisition activities		-		-		13,909		13,909
Foreign currency translation adjustment		(2,033)		-		(1,576)		(3,609)
Balance, December 31, 2014		142,839		1,419,550		906,020		2,468,409
Acquisition activities		-		-		1,170		1,170
Reduction in value of assets		-		(740,000)		(586,701)		(1,326,701)
Foreign currency translation adjustment		(1,557)		-		(1,220)		(2,777)
Other		-		44,000		(44,000)		-
Balance, December 31, 2015	$	141,282	$	723,550	$	275,269	$	1,140,101

Goodwill is tested for impairment annually as of October 1st 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. There is no outstanding goodwill balance associated with the Company’s Technical Solutions segment. 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. If the fair value of the reporting unit exceeds the carrying amount, no impairment loss is recognized. If the estimated fair value of the reporting unit is below the carrying value, then a second step must be performed to determine the goodwill impairment, if any. In this second step, the estimated fair value is used as the purchase price in a hypothetical acquisition of the reporting unit. The hypothetical purchase price is allocated to the reporting unit’s assets and liabilities, with the residual amount representing an implied fair value of the goodwill. The carrying amount of the goodwill is then compared to the implied fair value of the goodwill for each reporting unit and is written down to the implied fair value, if lower. The Company uses all available information to estimate fair value of the reporting units, including discounted cash flows. The Company engages third-party appraisal firms to assist in fair value determination of property, plant and equipment, intangible assets and any other significant assets or liabilities when appropriate. A significant amount of judgment was involved in performing these evaluations since the results are based on estimated future events. See note 3 for a discussion of the reduction in value of goodwill recorded during 2015 and 2013. As of December 31, 2015 and 2014, the Company’s accumulated reduction in value of goodwill was $1,417.7 million and $91.0 million, respectively.

Notes Receivable

The Company’s wholly owned subsidiary, 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 2015, the Company revised its estimates relating to the timing of decommissioning work on its Bullwinkle assets, due to the changes in the economics of the estimated oil and gas reserves, resulting in a 10 year acceleration of the platform decommissioning to an estimated date of 2028. This change in estimate resulted in an increase of the present value of the note receivable. The Company recorded interest income related to notes receivable of $1.7 million, $1.6 million and $2.6 million during 2015, 2014 and 2013, respectively.

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Intangible and Other Long-Term Assets

Intangible assets consist of the following (in thousands):



			December 31,
			2015						2014
	Estimated		Gross		Accumulated		Net		Gross		Accumulated		Net
	Useful Lives		Amount		Amortization		Balance		Amount		Amortization		Balance
Customer relationships	17	years	$	257,364	$	(65,209)	$	192,155	$	339,695	$	(64,954)	$	274,741
Tradenames	10	years		36,119		(15,371)		20,748		41,265		(13,151)		28,114
Non-compete agreements	3	years		3,242		(2,940)		302		4,487		(3,281)		1,206
Total			$	296,725	$	(83,520)	$	213,205	$	385,447	$	(81,386)	$	304,061

Amortization expense was $23.0 million, $25.9 million and $26.2 million during 2015, 2014 and 2013, respectively. Based on the carrying values of intangible assets as of December 31, 2015, amortization expense is estimated to be as follows: $19.2 million for 2016, $18.6 million for 2017, $18.5 million for 2018, $18.3 million for 2019 and $18.0 million for 2020.

During 2015, the Company recorded $68.9 million of expense related to the reduction in carrying values of intangibles primarily in the Production Services segment (see note 3).

As of December 31, 2015 and 2014, intangible and other long-term assets, net included $58.4 million of escrowed cash, primarily related to the future decommissioning obligations of the Bullwinkle platform.

Decommissioning Liabilities

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 platform and equipment, and site restoration. 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.

During 2015, the Company revised its estimates relating to the timing and the cost estimates of decommissioning work on its Bullwinkle assets due to changes in the economics of the oil and gas property, including a 10 year acceleration of the platform decommissioning to an estimated date of 2028. This change in estimate resulted in an increase in the present value of decommissioning liabilities. Further, as of December 31, 2015, the Company anticipated that it would be able to decommission several depleted wells that are part of the Bullwinkle assets based on the revised estimates. As a result, the decommissioning liabilities associated with those wells were classified as current liabilities on the consolidated balance sheet.

The following table summarizes the activity for the Company’s decommissioning liabilities (in thousands):



	December 31,
	2015		2014
Decommissioning liabilities, December 31, 2014 and 2013, respectively	$	88,000	$	83,519
Revisions in estimated timing and cash flows		24,660		(276)
Accretion		5,016		4,470
Liability acquisitions and dispositions		266		866
Liabilities settled		-		(579)
Total decommissioning liabilities, December 31, 2015 and 2014, respectively	$	117,942	$	88,000

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 recognizes oil and gas revenue from its interests in producing wells as oil and natural gas is sold. Taxes collected from customers and remitted to governmental authorities are reported on a net basis in the Company’s financial statements.

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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. 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 and conversion of restricted stock units.

During 2015, the Company incurred a loss from continuing operations; therefore the impact of any incremental shares would be anti-dilutive. Stock options for 1,100,000 shares of the Company’s common stock were excluded in the computation of diluted earnings per share for 2014 and 2013, as the effect would have been anti-dilutive.

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair value hierarchy are 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 $1,508.0 million and $1,624.3 million as of December 31, 2015 and 2014, 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 other income (expense) in the consolidated statements of operations in the period in which the currency exchange rates change. During 2015, 2014 and 2013, the Company recorded $9.6 million, $7.3 million and $7.1 million of foreign currency losses, respectively.

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Stock-Based Compensation

The Company records compensation costs relating to share-based payment transactions and includes such costs in general and administrative expenses in the consolidated statements 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 between fixed and variable interest, 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 62% and 61% of its long-term debt as of December 31, 2015 and 2014, respectively. The Company had notional amounts of $300 million 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, 2015 and 2014.

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 Guidance

In November 2015, the Financial Accounting Standards Board (FASB) issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes, which amends existing guidance on income taxes to require the classification of all deferred tax assets and liabilities as non-current on the balance sheet. The new standard is effective for the Company on January 1, 2017, with early adoption permitted, and the guidance may be applied either prospectively or retrospectively. The Company adopted this standard as of December 31, 2015 and applied the change retrospectively to prior periods, resulting in a $32.1 million reduction in total current assets and corresponding decrease in non-current deferred income tax liabilities.

In April 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs, which changes the presentation of debt issuance costs. This guidance requires that debt on the balance sheet be presented net of unamortized debt issuance costs. Amortization of such costs is reported as interest expense, which is consistent with the Company’s current policy. This change conforms the presentation of debt issuance costs with that of debt discounts. The ASU is effective for annual reporting periods (including interim reporting periods within those periods) beginning after December 15, 2015; early adoption is permitted. The guidance is required to be applied retrospectively to all prior periods. The Company adopted this standard as of December 31, 2015. The effect of the adoption of ASU 2015-03 on the Company’s consolidated balance sheet is a reduction of total assets and long-term debt of $27.5 million as of December 31, 2014.

In April 2014, the FASB issued ASU No. 2014-08, Presentation of Financial Statements and Property, Plant and Equipment, which changes the definition of discontinued operations. The guidance permits only those disposed components (or components held-for-sale) representing a strategic shift that have (or will have) a major effect on operations and financial results to be reported in discontinued operations. The new standard is effective prospectively for disposals (or classifications as held-for-sale) occurring after December 31, 2014. The Company has adopted the accounting guidance as of January 1, 2015.

Recently Issued Accounting Guidance

In July 2015, the FASB issued ASU No. 2015-11, Inventory – Simplifying the Measurement of Inventory, which applies to inventory measured using first-in, first-out or average cost. The guidance in this update states that inventory within its scope shall be measured at the lower of cost or net realizable value, and when the net realizable value of inventory is lower than its cost, the difference shall be recognized as a loss in earnings. The new standard is effective for the Company beginning on January 1, 2017 and should be applied on a prospective basis. The Company is evaluating the effect that ASU 2015-11 will have on its consolidated financial statements and related disclosures.

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In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which will replace most existing revenue recognition guidance in GAAP. The guidance in this update requires an entity to recognize the amount of revenue that it expects to be entitled for the transfer of promised goods or services to customers. The new standard is effective for the Company on January 1, 2018. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09 will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the accounting guidance on its ongoing financial reporting.

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.

(2) Supplemental Cash Flow Information

The following table includes the Company’s supplemental cash flow information (in thousands):



	Years Ended December 31,
	2015		2014		2013
Cash paid for interest	$	93,946	$	102,880	$	97,129

Cash paid for income taxes, net of refunds	$	40,074	$	127,132	$	164,158

Details of business acquisitions:
Fair value of assets	$	-	$	29,468	$	34,964
Fair value of liabilities		-		(5,125)		(10,942)
Common stock issued		-		-		-
Cash paid		-		24,343		24,022
Less cash acquired		-		(16)		(225)
Net cash paid for acquisitions	$	-	$	24,327	$	23,797

Non-cash investing activity:
Capital expenditures included in accounts payable,
accrued expenses and other long term liabilities	$	28,704	$	49,118	$	70,463

Non-cash financing activity:
Cash dividends declared	$	-	$	-	$	12,759

(3) Reduction in Value of Assets and Other Charges

During 2015 and 2013, the Company recorded $1,738.9 million and $300.1 million in expense related to reduction in value of assets, respectively. The components of reduction in value of assets are as follows (in thousands):



	Years Ended December 31,
	2015		2013
Reduction in value of goodwill	$	1,326,701	$	91,016
Reduction in value of long-lived assets		330,194		180,320
Retirements of long-lived assets		42,545		14,418
Reduction in value of assets related to sale of a business		39,447		-
Reduction in value of assets related to Venezuela exit activities		-		14,324
Total reduction in value of assets	$	1,738,887	$	300,078

Reduction in Value of Goodwill

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Completion and Workover Services segment’s goodwill. In addition, the Company determined that the implied fair value of its goodwill for the Production Services segment was less than its carrying value and recorded a $586.7 million impairment of the Production Services segment’s goodwill. The reduction in value of goodwill in the Production Services segment was primarily driven by the continued decline in demand for coiled tubing services. The reduction in value of goodwill in the Onshore Completion and Workover Services and Production Services segments was primarily driven by further deterioration of market conditions during the year and the Company’s forecast did not indicate a timely recovery sufficient to support the carrying values of the goodwill.

During 2013, the Company recorded $91.0 million reduction in value of goodwill relating to its Technical Solutions segment. The Company performed its annual test for goodwill, which indicated that the carrying value of the Technical Solutions segment exceeded its fair value, indicating that goodwill was potentially impaired. The Company determined that the implied fair value of the goodwill for the Technical Solutions segment was less than its carrying value and fully wrote-off the goodwill balance of $91.0 million. The reduction in value of goodwill in the Technical Solutions segment was primarily driven by the decline in demand for services in the subsea construction and marine technical services divisions. During 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 value of the goodwill.

Reduction in Value of Long-Lived Assets

During 2015, the Company recorded $330.2 million in connection with the reduction in value of its long-lived assets. The reduction in value of assets was comprised of $89.7 million related to equipment and $59.5 million related to intangibles in the coiled tubing business and pressure control tools businesses within the Production Services segment. The reduction in value of assets in the Production Services segment was primarily driven by the decline in demand for coiled tubing services. The demand for these services continued to decline and the Company’s forecast did not indicate a timely recovery sufficient to support the carrying values of these assets.

The reduction in value of assets also included $68.9 million related to the reduction in carrying values of the marine vessels and equipment included in the marine technical services division in the Technical Solutions segment. The reduction in value of assets in the Technical Solutions segment was primarily as a result of the termination of the contract with a certain marine technical services division’s customer. Further, the reduction in value of assets also included $56.0 million related to impairment of the Gulf of Mexico oil and gas property which is included in the Technical Solutions segment.

In addition, the reduction in value of assets included a $40.2 million, primarily related to reduction in carrying values of certain domestic and international accommodation units and premium drill pipe included in the Drilling Products and Services segment and $15.9 million related to mechanical drilling rigs included in the Onshore Completion and Workover Services segment. The reduction in value of assets in the Drilling Products and Services segment was primarily driven by the decrease in demand for the rental of accommodation units, changes in the regulatory requirements and a decrease in the Company’s forecast for future rentals of these units. The reduction in value of assets in the Onshore Completion and Workover Services segment related to the reduction in carrying values of the mechanical drilling rigs, primarily as a result of the decreased demand for certain mechanical drilling rigs driven by the downturn in the oil and gas market.

During 2013, the Company recorded $180.3 million in connection with reduction in value of its long-lived assets and related other assets. The reduction in value of assets was comprised of $122.8 million related to certain marine equipment and related write-off of other assets of $31.9 million included in the 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 a $3.0 million related to reduction in carrying values of the intangible assets in the coiled tubing business in the Production Services segment.

The reduction in value of assets in the Technical Solutions segment was primarily driven by the decline in demand for services in the Company’s marine technical services business. During 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 the Onshore Completion and Workover Services segment related to the reduction in carrying values of the mechanical drilling rigs, primarily driven by the shift in customer demand away from mechanically powered rigs to electrically powered drilling rigs. The reduction in value of assets in the Production Services segment related to the coiled tubing business in Mexico and was primarily driven by the decrease in demand for the Company’s services during 2013 coupled with a decrease in the forecast for future activities in that region.

Retirements of Long-Lived Assets

During 2015, the Company recorded $42.5 million for retirement and abandonment of inoperable and/or functionally obsolete long-lived assets that would require a significant cost to refurbish. The total amount recorded includes $27.3 million for the Onshore Completion and Workover Services segment and $15.2 million for the Production Services segment.

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During 2013, the Company recorded $14.4 million for retirement and abandonment of inoperable and/or functionally obsolete long-lived assets. The total amount recorded includes $6.4 million for 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 Sale of Coiled Tubing Business in Mexico

During 2015, the Company sold its Mexico based coiled tubing business and related assets. The Company received proceeds in the form of cash and a note receivable. The Company recorded a full valuation allowance on the note receivable in the amount of $16.8 million because its collectability was not reasonably assured. In connection with the sale, the Company recorded a $39.4 million reduction in value of assets, primarily related to property, plant and equipment and intangible assets.

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. 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 2013, the Company generated $9.5 million, in revenue from its operations in Venezuela.

Other Charges

During 2015, in connection with the reorganization of several of its businesses, the Company recorded $46.8 million relating to reduction in force expense and reorganization costs. The Company’s reorganization plan resulted in the consolidation of certain of its product lines and rationalization of the related facilities and offices. Included in the total reorganization costs is $20.2 million relating to the impairment of certain real estate operating leases included in the Onshore Completion and Workover Services segment. As of December 31, 2015, the accrued lease termination liability balances were $7.2 million and $11.1 million, included in accrued expenses and other long-term liabilities, respectively, on the consolidated balance sheet.

(4) Discontinued Operations

Discontinued operations results include operating results for both of the Company’s subsea construction and conventional decommissioning businesses. Unfavorable oil and gas market conditions that have negatively impacted the demand for the assets included in these businesses. Therefore, the remaining assets of these businesses were not disposed of during the initial one-year period. As of December 31, 2015, these assets were being actively marketed and the Company’s management is committed to selling the remaining assets. Both the subsea construction business and conventional decommissioning business were included in the Technical Solutions segment. As of December 31, 2015, the assets and liabilities of these businesses were classified as held for sale. The results of operations of these businesses for 2015, 2014 and 2013 are reported as discontinued operations in the consolidated statements of operations.

The following table summarizes the components of loss from discontinued operations, net of tax (in thousands):



	Years Ended December 31,
	2015		2014		2013
Revenues	$	18,723	$	145,463	$	261,767

Loss from discontinued operations, net of tax benefit of $5,626, $19,330 and $15,439 for 2015, 2014 and 2013, respectively	$	(46,955)	$	(22,973)	$	(156,903)

During 2015, loss from discontinued operations included $25.8 million and $8.8 million for the reduction in value of marine vessels in the subsea construction and conventional decommissioning businesses, respectively.

During 2014, loss from discontinued operations included an $18.8 million gain related to the sale of marine vessels and equipment in the subsea construction business.

During 2013, loss from discontinued operations included $119.3 million related to the reduction in value of assets. The reduction in value of assets included a $98.3 million charge primarily relating to certain marine vessels included in the subsea construction business; a $15.4 million expense relating to reduction in carrying values of the intangible assets in the subsea construction business; and a $5.6 million expense relating to the retirement of long-lived assets in the conventional decommissioning business.

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The following summarizes the assets and liabilities related to the businesses reported as discontinued operations (in thousands):



	December 31,
	2015		2014
Accounts receivable, net	$	1,234	$	16,701
Prepaid expenses		330		2,463
Inventory and other current assets		1,036		5,576
Current assets	$	2,600	$	24,740
Property, plant and equipment, net		92,634		91,171
Intangible and other long-term assets, net		-		769
Long-term assets	$	92,634	$	91,940
Accounts payable		1,007		20,530
Accrued expenses		3,654		24,496
Current liabilities	$	4,661	$	45,026
Other long-term liabilities	$	-	$	16,814

During 2015, the Company spent $46.4 million to purchase two leased vessels in its subsea construction business. In addition, the purchase price for one of the vessels included the extinguishment of the related capital lease obligation of $20.9 million. The purchases were made to eliminate ongoing lease payments and facilitate the disposition of the vessels.

(5) Property, Plant and Equipment

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



	December 31,
	2015		2014
Buildings, improvements and leasehold improvements	$	318,906	$	328,651
Marine vessels and equipment		87		55,494
Machinery and equipment		3,770,959		4,126,570
Automobiles, trucks, tractors and trailers		45,013		66,032
Furniture and fixtures		67,483		75,631
Construction-in-progress		74,683		102,895
Land		58,731		58,814
Oil and gas producing assets		66,285		189,294
Total		4,402,147		5,003,381
Accumulated depreciation and depletion		(2,278,856)		(2,269,542)
Property, plant and equipment, net	$	2,123,291	$	2,733,839

The Company had $84.9 million and $93.3 million of leasehold improvements as of December 31, 2015 and 2014, 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 $584.1 million, $620.6 million, and $572.9 million during 2015, 2014 and 2013, respectively. During 2015, the Company recorded $343.3 million related to reduction in value of property, plant and equipment (see note 3).

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(6) Debt

The Company’s outstanding debt is as follows (in thousands):



	December 31,
	2015				2014
	Long-term		Current		Long-term		Current
Term loan due February 2017	$	305,000	$	20,000	$	325,000	$	20,000
Senior Notes due May 2019		500,000		-		500,000		-
Senior Notes due December 2021		800,000		-		800,000		-
Other		3,089		9,957		2,842		941
Total debt, gross		1,608,089		29,957		1,627,842		20,941
Unamortized debt issuance costs		(19,826)		-		(27,469)		-
Total debt	$	1,588,263	$	29,957	$	1,600,373	$	20,941

Debt maturities presented as of December 31, 2015 are as follows (in thousands):



2016	$	29,957
2017		306,705
2018		1,384
2019		500,000
2020		-
Thereafter		800,000
Total	$	1,638,046

Credit Facility

At December 31, 2015, the Company had a credit facility that was comprised of a $600.0 million revolving line of credit and a $325.0 million term loan. In February 2016, the Company amended and extended the credit facility. The amended agreement results in a $470.3 million revolving credit facility which matures in 2019 and no longer has a term loan component. As of February 22, 2016, the Company had $325.0 million of borrowings and $42.2 million of letters of credit outstanding under the amended credit facility. Borrowings under the credit facility bear interest at LIBOR plus margins that depend on our credit rating. Indebtedness under the credit facility is secured by substantially all of the Company’s assets, including the pledge of the stock of its principal domestic subsidiaries. The credit facility contains customary events of default and requires that the Company satisfies various financial covenants.

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.

(7) Stock-Based and Long-Term Compensation

Under our 2013 Stock Incentive Plan, the Company may grant non-qualified stock options, restricted stock, restricted stock units and other types of equity based awards. The Compensation Committee determines the recipients of the equity awards, the type of awards made and the required performance measures. During 2015, the plan was amended to increase the number of shares of common stock authorized for issuance under the plan from 8,000,000 to 14,850,000 shares. As of December 31, 2015, 8,700,000 shares of the Company’s common stock were available for future grants under the plan.

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Total stock-based compensation expense and the associated tax benefits are as follows (in thousands):



Compensation Expense	Years Ended December 31,
	2015		2014		2013
Stock options	$	3,663	$	3,900	$	3,586
Restricted stock		9,219		15,800		21,460
Restricted stock units		19,699		11,282		-
Performance share units		10,733		10,688		10,014
Strategic performance share units		2,258		2,404		-
Total	$	45,572	$	44,074	$	35,060

Tax Benefit	Years Ended December 31,
	2015		2014		2013
Stock options	$	1,355	$	1,443	$	1,327
Restricted stock		3,411		5,846		7,940
Restricted stock units		7,289		4,174		-
Total	$	12,055	$	11,463	$	9,267

Total stock-based compensation expense is reflected in general and administrative expenses in the consolidated statements of operations.

Stock Options

Stock options are granted with an exercise price equal to the market price of our ordinary shares at the date of grant. The stock options generally vest in equal installments over three years and expire in ten years from the grant date. Non-vested stock options are generally forfeited upon termination of employment.

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 volatility and the expected life of the stock options. 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 dividend yield is based on our historical dividend payouts.

The weighted average fair values of stock options granted and the assumptions used in estimating those fair values are as follows:



	Years Ended December 31,
	2015		2014		2013
Weighted average fair value of grants	$	6.25	$	6.95	$	8.98

Black-Scholes-Merton Assumptions:
Risk free interest rate		1.33%		1.42%		0.63%
Expected life (years)		5		4		4
Volatility		47.07%		34.50%		48.41%
Dividend yield		1.30		1.23		-

The following table summarizes stock option activity for 2015:



	Number of Options	Weighted Average Option Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding as of December 31, 2014	4,484,505	$	23.76	5.1	$	4,095
Granted	612,665	$	17.27
Exercised	(506,029)	$	17.43
Outstanding as of December 31, 2015	4,591,141	$	23.60	5.3	$	256
Exercisable as of December 31, 2015	3,488,262	$	24.48	4.3	$	256
Options expected to vest as of December 31, 2015	1,102,879	$	20.81	8.5	$	-

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The total intrinsic value of stock options exercised during 2015, 2014 and 2013 was $2.3 million, $17.1 million and $5.1 million, respectively. The Company received $8.8 million, $10.6 million and $6.3 million during 2015, 2014 and 2013, respectively, from employee stock option exercises. The Company has reported tax benefits of $0.9 million, $5.6 million and $0.7 million from the exercise of stock options for 2015, 2014 and 2013, respectively.

The following table summarizes non-vested stock option activity for 2015:



	Number of Options	Weighted Average Grant Date Fair Value
Non-vested as of December 31, 2014	824,488	$	7.83
Granted	612,665	$	17.27
Vested	(334,274)	$	25.01
Non-vested as of December 31, 2015	1,102,879	$	20.81

As of December 31, 2015, the unrecognized compensation expense related to non-vested stock options was $3.9 million. The Company expects to recognize $2.6 million and $1.3 million of compensation expense during the years 2016 and 2017, respectively.

Restricted Stock

Shares of restricted stock generally vest in equal annual installments over three years. Non-vested shares are generally forfeited upon termination of employment. Holders of the 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.

The following table summarizes restricted stock activity for 2015:



	Number of Shares	Weighted Average Grant Date Fair Value
Non-vested as of December 31, 2014	1,022,280	$	24.08
Vested	(678,880)	$	17.88
Forfeited	(50,463)	$	23.26
Non-vested as of December 31, 2015	292,937	$	23.13

No restricted stock was granted during 2015 and 2014. The weighted average grant-date fair value per share of restricted stock granted during 2013 was $23.14. The total fair value of restricted stock vested during 2015, 2014 and 2013 was $12.1 million, $23.0 million and $9.6 million, respectively. As of December 31, 2015, there was $0.4 million of unrecognized compensation expense related to non-vested restricted stock, which is expected to be recognized during 2016.

Restricted Stock Units

Beginning in 2014, restricted stock unit awards (RSUs) were granted to eligible employees. Prior to 2014, only non-employee directors were granted RSU awards. RSUs granted to employees vest in equal annual installments over three years. On the vesting date, each RSU is converted to one share of the Company’s common stock having an aggregate value determined by the Company’s closing stock price on the vesting date. Holders of RSUs are not entitled to any rights of a stockholder, such as the right to vote shares, but will accrue dividends that are paid out upon vesting.

Each non-employee director is issued annually a number of 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 or her 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. 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.

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The following table summarizes RSU activity for 2015:



	Number of Restricted Stock Units	Weighted Average Grant Date Fair Value
Non-vested as of December 31, 2014	1,416,477	$	26.40
Granted	2,162,146	$	17.74
Vested	(460,400)	$	18.51
Forfeited	(330,334)	$	20.16
Non-vested as of December 31, 2015	2,787,889	$	20.41

As of December 31, 2015, there was $30.0 million of unrecognized compensation expense related to unvested RSUs. The Company expects to recognize $19.3 million, $10.3 million, and $0.4 million for 2016, 2017, and 2018, respectively.

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, 2015, there were 370,822 PSUs outstanding (112,922, 123,079 and 134,821 related to performance periods ending December 31, 2015, 2016 and 2017, respectively). The Company has recorded both current and long-term liabilities for this liability-based compensation award.

Effective February 2014, the Company granted strategic performance share units (SPSUs) to the executive officers of the Company. The number of target SPSUs was established at the beginning of a two-calendar year performance period. The final value of SPSUs earned will be based upon the level of the Company’s free cash flow achieved for 2015 and 2014. The earned SPSUs will vest provided the participant remains actively employed by the Company through January 2, 2016.

Employee Stock Purchase Plan

In 2013, the stockholders of the Company approved the 2013 Employee Stock Purchase Plan (ESPP). This plan went into effect on July 1, 2013 and replaced the prior plan. Under this plan 3,000,000 shares of common stock were 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.

The following table summarizes ESPP activity (in thousands except shares):



	Years Ended December 31,
	2015		2014		2013
	2013 Plan		2013 Plan		2013 and 2007 Plans
Cash received for shares issued	$	4,803	$	4,870	$	4,124
Compensation expense	$	835	$	1,078	$	947
Shares issued		332,467		246,480		185,407

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. The Company provides a nondiscretionary match of 100% of an employee’s contributions to the plan, up to 4% of the employee’s salary. The Company made contributions of $13.9 million, $16.7 million and $16.0 million during 2015, 2014 and 2013, respectively.

Non-Qualified Deferred Compensation Plans

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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. 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) in the consolidated statements of operations.

The following table summarizes deferred compensation balances (in thousands):



		December 31,
	Balance sheet location	2015		2014
Deferred compensation assets	Intangible and other long-term assets, net	$	11,548	$	12,982
Deferred compensation liabilities, short-term	Accounts payable	$	721	$	2,291
Deferred compensation liabilities, long-term	Other long-term liabilities	$	17,367	$	14,720

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. The participants in the plan receive contributions ranging from 5% to 35% of salary and annual cash bonus, which totaled $1.2 million during 2015, 2014 and 2013. The Company recorded compensation expense of $2.1 million, $1.6 million and $1.2 million in general and administrative expenses during 2015, 2014 and 2013. The Company may also make discretionary contributions to a participant’s account. During 2015, 2014 and 2013, the Company paid $3.7 million, $3.0 million and $3.0 million, respectively, to select participants in the SERP.

(8) Income Taxes

The components of income (loss) from continuing operations before income taxes are as follows (in thousands):



	Years Ended December 31,
	2015		2014		2013
Domestic	$	(2,069,019)	$	372,672	$	165,463
Foreign		9,236		69,517		(64,706)
	$	(2,059,783)	$	442,189	$	100,757

The components of income tax expense (benefit) are as follows (in thousands):



	Years Ended December 31,
	2015		2014		2013
Current:
Federal	$	(952)	$	150,997	$	19,897
State		2,818		11,339		10,816
Foreign		19,227		36,287		25,613
		21,093		198,623		56,326
Deferred:
Federal		(249,193)		(33,172)		(6,341)
State		(10,034)		648		386
Foreign		(13,886)		(4,700)		4,901
		(273,113)		(37,224)		(1,054)
	$	(252,020)	$	161,399	$	55,272

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Income tax expense differs from the amounts computed by applying the U.S. Federal income tax rate of 35% to income (loss) before income taxes as follows (in thousands):



	Years Ended December 31,
	2015		2014		2013
Computed expected tax expense	$	(720,923)	$	154,766	$	35,265
Increase (decrease) resulting from
State and foreign income taxes		(6,353)		8,467		(852)
Reduction in value of assets		464,395		-		34,874
Other		10,861		(1,834)		(14,015)
Income tax	$	(252,020)	$	161,399	$	55,272

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



	December 31,
	2015		2014
Deferred tax assets:
Allowance for doubtful accounts	$	8,275	$	3,942
Operating loss and tax credit carryforwards		92,798		21,928
Compensation and employee benefits		59,310		57,045
Decommissioning liabilities		30,400		21,029
Other		57,768		50,641
		248,551		154,585
Valuation allowance		(5,395)		-
Net deferred tax assets		243,156		154,585
Deferred tax liabilities:
Property, plant and equipment		469,728		648,054
Notes receivable		14,796		5,718
Goodwill and other intangible assets		119,661		138,017
Other		22,040		33,654
Deferred tax liabilities		626,225		825,443
Net deferred tax liability	$	383,069	$	670,858

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 has been recognized on a portion of the state net operating loss carryforward deferred tax asset. After considering all available evidence at December 31, 2015, the Company determined that it was more likely than not that a portion of the carryforward would not be realized. Accordingly, the Company increased deferred income tax expense by the amount of the valuation allowance.

As of December 31, 2015, the Company had $102.1 million in U.S. net operating loss carryforwards, which are available to reduce future or prior taxable income. The expiration dates for utilization of the loss carryforwards are 2020 through 2035. 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, 2015, the Company also had various state net operating loss carryforwards with expiration dates from 2016 to 2030. A net deferred tax asset of $25.2 million reflects the expected future tax benefit for the state loss carryforwards. As of December 31, 2015, the Company also had a U.S. foreign tax credit carryforward of $31.8 million.

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, 2015, the undistributed earnings of the Company’s foreign subsidiaries were $52.0 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 2010.

The Company had unrecognized tax benefits of $29.7 million, $30.3 million and $29.9 million as of December 31, 2015, 2014 and 2013, respectively all of which would impact the Company’s effective tax rate if recognized.

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The activity in unrecognized tax benefits is as follows (in thousands):



	Years Ended December 31,
	2015		2014		2013
Unrecognized tax benefits, December 31, 2014, 2013 and 2012, respectively	$	30,344	$	29,899	$	26,399
Additions based on tax positions related to current year		-		-		-
Additions based on tax positions related to prior years		6,752		7,860		5,065
Reductions based on tax positions related to prior years		(7,381)		(7,415)		(1,565)
Unrecognized tax benefits, December 31, 2015, 2014 and 2013, respectively	$	29,715	$	30,344	$	29,899

(9) 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 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. The Technical Solutions segment provides services typically requiring specialized engineering, manufacturing or project planning, including 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.

For 2015, 2014 and 2013, operating results for the Company’s subsea construction and conventional decommissioning businesses are reported in discontinued operations (see note 4). Previously those operating results were reported within the Technical Solutions segment.

The Company evaluates the performance of its reportable segments based on income or loss from operations. The segment measure is calculated as follows: segment revenues less segment operating expenses, depreciation, depletion, amortization and accretion expense, reduction in value of assets and allocated general and administrative expenses. General and administrative expenses are allocated to the segments based primarily on specific identification and, to the extent that such identification is not practical, other methods which the Company believes to be a reasonable reflection of the utilization of services provided. The Company believes this segment measure is useful in evaluating the performance of its reportable segments because it highlights operating trends and aids analytical comparisons.

Summarized financial information for the Company’s segments is as follows (in thousands):



2015

			Onshore
	Drilling		Completion
	Products and		and Workover		Production		Technical				Consolidated
	Services		Services		Services		Solutions		Unallocated		Total
Revenues	$	583,139	$	934,274	$	759,606	$	497,546	$	-	$	2,774,565
Cost of services and rentals
(exclusive of items shown separately below)		196,921		773,119		594,286		301,486		-		1,865,812
Depreciation, depletion, amortization and accretion		194,061		225,667		130,267		62,152		-		612,147
General and administrative expenses		127,525		121,289		139,304		122,590		-		510,708
Reduction in value of assets		40,237		783,229		790,517		124,904		-		1,738,887
Income (loss) from operations		24,395		(969,030)		(894,768)		(113,586)		-		(1,952,989)
Interest expense, net		-		-		(2,013)		1,707		(97,012)		(97,318)
Other expense		-		-		-		-		(9,476)		(9,476)
Income (loss) from continuing operations before income taxes	$	24,395	$	(969,030)	$	(896,781)	$	(111,879)	$	(106,488)	$	(2,059,783)

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2014

			Onshore
	Drilling		Completion
	Products and		and Workover		Production		Technical				Consolidated
	Services		Services		Services		Solutions		Unallocated		Total
Revenues	$	904,358	$	1,732,833	$	1,350,956	$	568,475	$	-	$	4,556,622
Cost of services and rentals
(exclusive of items shown separately below)		282,023		1,205,443		941,030		306,337		-		2,734,833
Depreciation, depletion, amortization and accretion		186,642		233,430		164,672		66,070		-		650,814
General and administrative expenses		149,967		159,687		187,526		127,191		-		624,371
Income from operations		285,726		134,273		57,728		68,877		-		546,604
Interest expense, net		-		-		-		1,577		(98,311)		(96,734)
Other expense		-		-		-		-		(7,681)		(7,681)
Income (loss) from continuing operations before income taxes	$	285,726	$	134,273	$	57,728	$	70,454	$	(105,992)	$	442,189



2013

			Onshore
	Drilling		Completion
	Products and		and Workover		Production		Technical				Consolidated
	Services		Services		Services		Solutions		Unallocated		Total
Revenues	$	820,538	$	1,607,268	$	1,434,990	$	487,261	$	-	$	4,350,057
Cost of services and rentals
(exclusive of items shown separately below)		268,127		1,091,956		1,002,628		270,879		-		2,633,590
Depreciation, depletion, amortization and accretion		168,391		216,152		177,532		42,366		-		604,441
General and administrative expenses		136,244		158,448		190,647		112,439		-		597,778
Reduction in value of assets		2,292		16,975		28,568		252,243		-		300,078
Income (loss) from operations		245,484		123,737		35,615		(190,666)		-		214,170
Interest expense, net		-		-		-		1,323		(109,225)		(107,902)
Other income (expense)		-		-		-		836		(6,347)		(5,511)
Income (loss) from continuing operations before income taxes	$	245,484	$	123,737	$	35,615	$	(188,507)	$	(115,572)	$	100,757



Identifiable Assets
			Onshore
	Drilling		Completion
	Products and		and Workover		Production		Technical				Consolidated
	Services		Services		Services		Solutions		Unallocated		Total
December 31, 2015	$	1,223,191	$	1,929,185	$	967,719	$	794,149	$	-	$	4,914,244
December 31, 2014	$	1,284,842	$	2,993,824	$	2,098,592	$	940,524	$	-	$	7,317,782
December 31, 2013	$	1,237,842	$	2,961,390	$	2,158,653	$	1,009,058	$	-	$	7,366,943

As of December 31, 2015 and 2014, the Technical Solutions segment included $95.2 million and $116.7 million, respectively, of identifiable assets of the subsea construction and conventional decommissioning businesses that were classified as assets held for sale on the consolidated balance sheets.

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Capital Expenditures
			Onshore
	Drilling		Completion
	Products and		and Workover		Production		Technical		Consolidated
	Services		Services		Services		Solutions		Total
December 31, 2015	$	129,504	$	103,001	$	72,048	$	53,673	$	358,226
December 31, 2014	$	274,752	$	152,742	$	88,870	$	99,738	$	616,102
December 31, 2013	$	246,479	$	101,854	$	122,946	$	137,681	$	608,960

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 rented. 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. As of December 31, 2015 and 2014, the assets of the subsea construction and conventional decommissioning businesses were classified as assets held for sale on the consolidated balance sheets. 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
	Years Ended December 31,
	2015		2014		2013
United States	$	2,185,071	$	3,848,929	$	3,674,825
Other Countries		589,494		707,693		675,232
Total	$	2,774,565	$	4,556,622	$	4,350,057

Long-Lived Assets
			December 31,
			2015		2014
United States			$	1,799,418	$	2,416,306
Other Countries				323,873		317,533
Total, net			$	2,123,291	$	2,733,839

(10) Commitments and Contingencies

The Company leases many of its office, service and assembly facilities under operating leases. In addition, the Company also leases certain assets used in providing services under operating leases. The leases expire at various dates over an extended period of time. Total rent expense was $29.6 million, $26.2 million and $25.6 million during 2015, 2014 and 2013, respectively. Future minimum lease payments under non-cancelable leases for the five years ending December 31, 2016 through 2020 and thereafter are as follows: $45.7 million, $32.4 million, $23.3 million, $16.1 million, $10.0 million and $25.2 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. However, based on current circumstances, the Company does not believe that the ultimate resolution of these proceedings, after considering available defenses and any insurance coverage or indemnification rights, will have a material adverse effect on its financial position, results of operations or cash flows.

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(11) Fair Value Measurements

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



			Fair Value Measurements at Reporting Date Using
	December 31, 2015		Level 1		Level 2		Level 3
Intangible and other long-term assets, net
Non-qualified deferred compensation assets	$	11,548	$	368	$	11,180		-
Interest rate swaps	$	6,905		-	$	6,905		-
Accounts payable
Non-qualified deferred compensation liabilities	$	721		-	$	721		-
Other long-term liabilities
Non-qualified deferred compensation liabilities	$	17,367		-	$	17,367		-

	December 31, 2014		Level 1		Level 2		Level 3
Intangible and other long-term assets, net
Non-qualified deferred compensation assets	$	12,982	$	1,481	$	11,501		-
Interest rate swaps	$	4,183		-	$	4,183		-
Accounts payable
Non-qualified deferred compensation liabilities	$	2,291		-	$	2,291		-
Other long-term liabilities
Non-qualified deferred compensation liabilities	$	14,720		-	$	14,720		-

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 7). 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.

The Company has three 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 12).

The following table reflects the fair value measurements used in testing the impairment of long-lived assets and goodwill (in thousands):



	Years Ended December 31,
	2015				2013
	Impairment		Fair Value		Impairment		Fair Value
Property, plant and equipment, net	$	177,442	$	179,612	$	243,781	$	328,876
Goodwill	$	1,326,701	$	998,288	$	91,016	$	-
Intangible assets	$	68,890	$	6,345	$	18,296	$	4,355

Fair value is measured as of the impairment date using Level 3 inputs. See note 3 for discussion of reduction in value of assets recorded during 2015 and 2013.

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(12) Derivative Financial Instruments

From time to time, the Company may enter into interest rate swaps in an attempt to achieve a more balanced debt portfolio between fixed and variable debt. 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 $6.9 million and $4.2 million within intangible and other long term assets in the consolidated balance sheets as of December 31, 2015 and 2014, respectively, relating to these swaps.

The changes in fair value of the interest rate swaps are included in the adjustments to reconcile net income/loss to net cash provided by operating activities in the consolidated statements of cash flows. The location and effect of the derivative instrument on the consolidated statements of operations presented on a pre-tax basis is as follows (in thousands):




		Years Ended December 31,
Effect of derivative instrument	Location of (gain) loss recognized	2015		2014		2013
Interest rate swap	Interest expense, net	$	(1,932)	$	(11,054)	$	13,079
Hedged item - debt	Interest expense, net		(790)		7,208		(12,303)
		$	(2,722)	$	(3,846)	$	776

During 2015, 2014 and 2013, $2.7 million of interest income, $3.8 million of interest income and $0.8 million of interest expense, 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.

(13) Related Party Transactions

During 2014 and 2013, the Company purchased services, products and equipment, as well as leased certain facilities, from companies affiliated with a former officer, who retired during the first quarter of 2015, of one of its subsidiaries. During 2014 and 2013, these transactions totaled $221.1 million and $164.8 million, respectively. During 2014, $92.1 million was purchased from ORTEQ Energy Services, a heavy equipment construction company which also manufactures pressure pumping equipment, $0.7 million was purchased from Ortowski Construction, primarily related to the manufacture of pressure pumping units, $21.6 million was paid to Resource Transport, LLC, related to the transportation of sand used in pressure pumping equipment, $79.3 million was purchased from Texas Specialty Sands, LLC primarily for the purchase of sand used for pressure pumping activities, $25.5 million was purchased from ProFuel, LLC, primarily related to the purchase of diesel used to operate equipment and trucks and $1.9 million was related to facilities leased from Timber Creek Real Estate Partners. During 2013, $52.8 million was purchased from ORTEQ Energy Services, $14.0 million was paid to Resource Transport, LLC, $69.1 million was purchased from Texas Specialty Sands, LLC, $26.9 million was purchased from ProFuel, LLC, and $2.0 million was related to facilities leased from Timber Creek Real Estate Partners.

As of December 31, 2014, the Company’s trade accounts payable includes amounts due to these companies totaling $26.8 million, of which $10.1 million was due ORTEQ Energy Services, $1.7 million was due Resource Transport, $14.0 million was due Texas Specialty Sands, and $1.0 million was due ProFuel, LLC. No amounts were due Ortowski Construction and Timber Creek Real Estate Partners.

The Company’s President and Chief Executive Officer serves as an independent director of the board of Linn Energy, LLC (Linn), an independent oil and gas development company. The Company recorded revenues from Linn of $7.2 million, $19.7 million and $26.9 million during 2015, 2014 and 2013, respectively. The Company had trade receivables from Linn of $2.0 million and $1.6 million as of December 31, 2015 and 2014, respectively.

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(14) Interim Financial Information (Unaudited)

The following is a summary of consolidated interim financial information (in thousands):



	2015
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Revenues	$	917,235	$	710,784	$	601,396	$	545,150
Less:
Cost of services and rentals		582,246		465,533		420,485		397,548
Depreciation, depletion, amortization and accretion		162,220		158,352		146,757		144,818
Gross profit		172,769		86,899		34,154		2,784
Reduction in value of assets		-		807,637		755,632		175,618
Net loss from continuing operations		(1,497)		(775,132)		(816,587)		(214,547)
Loss from discontinued operations, net of tax		(9,640)		(9,857)		(4,610)		(22,848)
Net loss		(11,137)		(784,989)		(821,197)		(237,395)
Loss per share from continuing operations:
Basic and diluted	$	(0.02)	$	(5.15)	$	(5.42)	$	(1.43)
Loss per share from discontinued operations:
Basic and diluted	$	(0.06)	$	(0.07)	$	(0.03)	$	(0.15)

	2014
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Revenues	$	1,061,418	$	1,107,552	$	1,209,026	$	1,178,626
Less:
Cost of services and rentals		651,605		650,293		721,692		711,243
Depreciation, depletion, amortization and accretion		162,318		160,965		170,154		157,377
Gross profit		247,495		296,294		317,180		310,006
Net income from continuing operations		42,626		79,057		85,743		73,364
Loss from discontinued operations, net of tax		(5,954)		(3,895)		(5,886)		(7,238)
Net income		36,672		75,162		79,857		66,126
Earnings per share from continuing operations:
Basic	$	0.27	$	0.51	$	0.55	$	0.49
Diluted		0.27		0.50		0.55		0.48
Loss per share from discontinued operations:
Basic and diluted	$	(0.04)	$	(0.03)	$	(0.03)	$	(0.05)

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

The Company’s December 31, 2015 and 2014 estimates of proved reserves are based on reserve reports prepared by Ryder Scott Company, L.P., independent petroleum engineers. The Company’s December 31, 2013 estimates of proved reserves are based on reserve reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers. Users of this information should be aware that the process of estimating quantities of “proved”, “proved developed” and “proved undeveloped” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may also change substantially over time as a result of multiple factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves are estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion.

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Oil and Natural Gas Reserves

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



	Crude Oil	Natural Gas
	(Mbbls)	(Mmcf)
Proved-developed and undeveloped reserves:
December 31, 2012	8,207	11,284
Revisions	(3,203)	(4,036)
Production	(411)	(296)
December 31, 2013	4,593	6,952
Revisions	(438)	1,431
Production	(738)	(1,247)
December 31, 2014	3,417	7,136
Revisions	(381)	(245)
Production	(633)	(1,517)
December 31, 2015	2,403	5,374

Proved-developed reserves:
December 31, 2013	2,397	2,100
December 31, 2014	3,184	6,945
December 31, 2015	2,202	5,216
Proved-undeveloped reserves:
December 31, 2013	2,196	4,852
December 31, 2014	233	191
December 31, 2015	201	158

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 (in thousands):



	Years Ended December 31,
	2015		2014		2013
Acquisition of properties - proved	$	-	$	-	$	-
Acquisition of properties - unproved		-		-		-
Exploratory costs		-		-		-
Development costs		20,636		52,719		51,527
Total costs incurred	$	20,636	$	52,719	$	51,527

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



	December 31,
	2015		2014
Proved oil and gas properties	$	66,285	$	189,294
Accumulated depreciation, depletion and amortization		-		(55,864)
Capitalized costs, net	$	66,285	$	133,430

Productive Wells Summary

The following table presents the Company’s ownership of productive oil wells as of December 31, 2015. 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 a working interest and “net” refers to the sum of fractional interests owned in gross wells.



	Productive Wells
	Gross	Net
Oil	11.00	5.61

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Acreage

The following table sets forth information as of December 31, 2015 relating to acreage held by the Company. Developed acreage is assigned to productive wells.



	Gross	Net
	Acreage	Acreage
Developed	23,040	11,750
Undeveloped	-	-
Total	23,040	11,750

Drilling Activity

The following table shows the Company’s drilling activity. 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.



	Years Ended December 31,
	2015		2014
	Gross	Net	Gross	Net
Exploratory Wells
Productive	-	-	-	-
Non-productive	-	-	-	-
Total	-	-	-	-

Development Wells
Productive	1.00	0.51	2.00	1.02
Non-productive	1.00	0.51	1.00	0.51
Total	2.00	1.02	3.00	1.53

Results of Operations

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



	Years Ended December 31,
	2015		2014		2013
Revenues
Sales	$	30,245	$	77,845	$	47,050
Production costs		15,466		13,529		9,876
Exploration expenses		-		-		-
Depreciation, depletion and amortization		37,623		38,768		12,032
Reduction in value of assets		56,000		-		-
		(78,844)		25,548		25,142
Income tax expenses		(28,778)		9,325		8,800
Results of operations from producing activities (excluding corporate overhead)	$	(50,066)	$	16,223	$	16,342

The Company’s oil and gas operations are in the Gulf of Mexico. The Company’s average sales price was $47.17 per barrel of oil and $2.82 per mcf of gas during 2015, $92.86 per barrel of oil and $4.95 per mcf of gas during 2014 and $101.85 per barrel of oil and $3.98 per mcf of gas during 2013. Average production costs were $10.38, $7.29 and $10.70 per barrel of oil equivalent during 2015, 2014 and 2013, respectively.

Standardized Measure of Discounted Future Net Cash Flows Relating to Reserves

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

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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 is as follows (in thousands):



	Years Ended December 31,
	2015		2014		2013
Future cash inflows	$	127,048	$	336,944	$	496,704
Future production costs		(43,010)		(71,209)		(82,487)
Future development and abandonment costs		(84,090)		(111,374)		(156,340)
Future income tax expenses		1,353		(60,345)		(89,507)
Future net cash flows		1,301		94,016		168,370
10% annual discount for estimated timing of cash flows		(19,762)		(17,034)		10,641
Standardized measure of discounted future net cash flows	$	21,063	$	111,050	$	157,729

For 2015 and 2014, the 10% annual discount for the estimated timing of cash flows resulted in a negative discount as a result of significant decreases in future cash inflows due to decreases in oil and gas prices along with lower reserve estimates.

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves is as follows (in thousands):


	Years Ended December 31,
	2015		2014		2013
Beginning of the period	$	111,050	$	157,729	$	303,430
Net change in sales and transfer prices and in production (lifting) costs related to future production		(143,808)		(57,568)		(13,278)
Changes in estimated future development costs		3,787		(5,512)		(48,594)
Sales and transfers of oil and gas produced during the period		(14,779)		(64,316)		(45,866)
Net change due to extensions, discoveries, and improved recovery		6,737		-		75,304
Net changes due to revisions in quantity estimates		(36,397)		(8,396)		(228,620)
Previously estimated development costs incurred during the period		20,636		40,962		10,136
Accretion of discount		17,606		24,251		46,711
Other-unspecified		1,895		4,125		(24,169)
Net change in income taxes		54,336		19,775		82,675
Aggregate change in the standardized measure of discounted future net cash flows for the year		(89,987)		(46,679)		(145,701)
End of the period	$	21,063	$	111,050	$	157,729

The December 31, 2015 amount was estimated by Ryder Scott Company, L.P. using a twelve month average WTI price of $50.28 per barrel (bbl), and a Henry Hub gas price of $2.66 per million British Thermal Units, and price differentials.

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The December 31, 2014 amount was estimated by Ryder Scott Company, L.P. using a twelve month average WTI price of $94.99 per barrel (bbl), and a Henry Hub gas price of $4.35 per million British Thermal Units, and price differentials.

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.

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

None.

Item 9A. Controls and Procedures

Our management has established and maintains a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is appropriately recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission (SEC). In addition, the disclosure controls and procedures ensure that information required to be disclosed, accumulated and communicated to management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), allow timely decisions regarding required disclosure. An evaluation was carried out, under the supervision and with the participation of our management, including our CEO and CFO, regarding the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-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 CEO and CFO have concluded that our disclosure controls and procedures as of December 31, 2015 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 herein by reference.

There has been no change in our internal control over financial reporting during the three months ended December 31, 2015, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over our financial reporting, and for performing an assessment of the effectiveness of internal control over our financial reporting as of December 31, 2015. 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 CEO and CFO, performed an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2015 based upon criteria in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, our management determined that as of December 31, 2015, our internal control over financial reporting was effective based on those criteria.

Our internal control over financial reporting as of December 31, 2015 has been audited by KPMG, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Superior Energy Services, Inc.:

We have audited Superior Energy Services, Inc.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) 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, 2015, based on criteria established in Internal Control – Integrated Framework (2013) 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, 2015 and 2014, 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, 2015, and our report dated February 25, 2016 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Houston, Texas

February 25, 2016

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Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information relating to our executive officers is included in “Executive Officers of Registrants” in Part I of this Annual Report on Form 10-K, and is incorporated herein by reference. Information relating to Our Shared Core Values at Work (Code of 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.

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, 2015 and 2014

Consolidated Statements of Operations for the years ended December 31, 2015, 2014 and 2013

Consolidated Statements of Comprehensive Income/Loss for the years ended December 31, 2015, 2014 and 2013

Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2015, 2014 and 2013

Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013

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, 2015, 2014 and 2013

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

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Exhibit No.	Description
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 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)), as further amended by Supplemental Indenture dated August 29, 2014, 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 4.1 to Superior Energy Services, Inc.’s Current Report on Form 8-K filed September 2, 2014 (File No. 001-34037)), as further amended by Supplemental Indenture dated August 3, 2015, 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 4.1 to Superior Energy Services, Inc.’s Quarterly Report on Form 10-Q filed August 4, 2015 (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)), as further amended by Supplemental Indenture dated August 29, 2014, 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 4.1 to Superior Energy Services, Inc.’s Current Report on Form 8-K filed September 2, 2014 (File No. 001-34037)), as further amended by Supplemental Indenture dated August 3, 2015, 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 4.1 to Superior Energy Services, Inc.’s Quarterly Report on Form 10-Q filed August 4, 2015 (File No. 001-34037)).
10.1^	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)).
10.2^	Superior Energy Services, Inc. Amended and Restated Nonqualified Deferred Compensation Plan (incorporated herein by reference to Exhibit 10.5 to Superior Energy Services, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 001-34037)).

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10.3^	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)).
10.4^	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)).
10.5^	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, effective as of January 1, 2009 (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, 2010 (File No. 001-34037)), as further amended by Amendment No. 2 to the Superior Energy Services, Inc. Supplemental Executive Retirement Plan, effective as of March 3, 2010 (incorporated herein by reference to Exhibit 10.8 to Superior Energy Services, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 001-34037)).
10.6^	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)).
10.7^	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)).
10.8^	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)).
10.9^	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)).
10.10^	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)).
10.11^	Superior Energy Services, Inc. Amended and Restated 2013 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 28, 2015 (File No. 001-34037)).
10.12^	Form of Restricted Stock Agreement under the Superior Energy Services, Inc. 2013 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.19 to Superior Energy Services, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 001-34037)).
10.13^*	Form of Restricted Stock Unit Agreement under the Superior Energy Services, Inc. Amended and Restated 2013 Stock Incentive Plan.
10.14^*	Form of Stock Option Agreement under the Superior Energy Services, Inc. Amended and Restated 2013 Stock Incentive Plan.
10.15^	Form of Performance Share Unit Agreement under the Superior Energy Services, Inc. 2013 Stock Incentive Plan (for awards made prior to 2015) (incorporated herein by reference to Exhibit 10.22 to Superior Energy Services, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 001-34037)).
10.16^*	Form of Performance Share Unit Agreement under the Superior Energy Services, Inc. 2013 Stock Incentive Plan (for awards made in 2015 and after).

Table of Contents

10.17^	Form of Strategic Performance Award Agreement under the Superior Energy Services, Inc. 2013 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.23 to Superior Energy Services, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 001-34037)).
10.18^*	Form of Notice of Grant of Restricted Stock Units for Non-Management Directors under the Superior Energy Services, Inc. Amended and Restated 2013 Stock Incentive Plan.
10.19^	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)), as amended by 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))
10.29^	Superior Energy Services, Inc. Directors Deferred Compensation Plan, as amended and restated December 8, 2014 (incorporated herein by reference to Exhibit 10.29 to Superior Energy Services, Inc.’s Annual Report on Form 10-K filed February 26, 2015 (File No. 001-34037)).
10.30^	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)).
10.31^	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)).
10.32^	Superior Energy Services, Inc. Amended and Restated Legacy CPX 2008 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)).
10.33	Fourth Amended and Restated Credit Agreement, dated February 22, 2016, 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 22, 2016 (File No. 001-34037)).
14.1	Our Shared Core Values at Work (Code of Conduct) (incorporated herein by reference to Exhibit 14.1 to Superior Energy Services, Inc.’s Annual Report on Form 10-K filed February 26, 2015 (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 Ryder Scott Company, L.P.
23.3*	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, 2015 on Certain Properties owned by Superior Energy Services, Inc.

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99.2	Appraisal Report as of December 31, 2014 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 26, 2015 ((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

Table of Contents

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 25, 2016
	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 Officer	February 25, 2016
David D. Dunlap	(Principal Executive Officer)


/s/ Robert S. Taylor	Executive Vice President, Treasurer and	February 25, 2016
Robert S. Taylor	Chief Financial Officer
	(Principal Financial and Accounting Officer)


/s/ Terence E. Hall	Chairman of the Board	February 25, 2016
Terence E. Hall


/s/ Harold J. Bouillion	Director	February 25, 2016
Harold J. Bouillion


/s/ James M. Funk	Director	February 25, 2016
James M. Funk


/s/ Peter D. Kinnear	Director	February 25, 2016
Peter D. Kinnear


/s/ Janiece M. Longoria	Director	February 25, 2016
Janiece M. Longoria


/s/ Michael M. McShane	Director	February 25, 2016
Michael M. McShane


/s/ W. Matt Ralls	Director	February 25, 2016
W. Matt Ralls


/s/ Justin L. Sullivan	Director	February 25, 2016
Justin L. Sullivan

Table of Contents

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Schedule II Valuation and Qualifying Accounts

Years Ended December 31, 2015, 2014 and 2013

(in thousands)



	Balance at the		Charged to
	beginning of		costs and				Discontinued		Balance at the
Description	the year		expenses		Deductions		operations		end of the year
2015: Allowance for doubtful accounts	$	22,076	$	14,341	$	4,795	$	3,380	$	28,242
2014: Allowance for doubtful accounts	$	31,030	$	6,299	$	10,639	$	4,614	$	22,076
2013: Allowance for doubtful accounts	$	28,715	$	7,587	$	7,763	$	(2,491)	$	31,030

EX-10.13 2 spn-20151231ex10135bc55.htm EX-10.13 Exhibit 1013

EXHIBIT 10.13

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 Amended and Restated 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:

AWARD OF RESTRICTED STOCK UNITS

1.1 On <<Grant Date>> (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 <<Number Of 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
1st anniversary of the Date of Grant		33%
2nd anniversary of the Date of Grant		33%
3rd anniversary of the Date of Grant		Remaining balance

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 Related Credits 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.

EXHIBIT 10.13

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.

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.

EXHIBIT 10.13

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.

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

EXHIBIT 10.13

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 there from. 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.

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 here to 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 here to, such shares of Common Stock shall not be issued, in whole or in part, or the restrictions there on 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.

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.

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.

EXHIBIT 10.13

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.

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 there of 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

EXHIBIT 10.13

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.

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.

<<Electronic Signature>>

<<Acceptance Date>>

PLEASE PRINT AND KEEP A COPY FOR YOUR RECORDS

EX-10.14 3 spn-20151231ex101420edd.htm EX-10.14 Exhibit 1014

EXHIBIT 10.14

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 Amended and Restated 2013 Stock Incentive Plan (the “Plan”).

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

Grant of Option

On <<Grant Date>> (the “Date of Grant”), Superior granted to Optionee the right, privilege and option to purchase <<Number Of Awards Granted>> shares of Common Stock (the “Option”) at an exercise price of <<Grant Price>> 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”).

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
1st anniversary of the Date of Grant		33%
2nd anniversary of the Date of Grant		33%
3rd anniversary of the Date of Grant		Remaining balance

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

EXHIBIT 10.14

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 policy titled “Our Shared Core Values at Work” (Code of 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

EXHIBIT 10.14

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.

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.

EXHIBIT 10.14

Method of Exercise of Option

Optionee may exercise all or a portion of the Option by contacting Fidelity Investments, 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.

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.

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.

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.

EXHIBIT 10.14

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.

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. 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 the Optionee’s 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

EXHIBIT 10.14

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.

<<Electronic Signature>>

<<Acceptance Date>>

PLEASE PRINT AND KEEP A COPY FOR YOUR RECORDS

EX-10.16 4 spn-20151231ex1016bd77b.htm EX-10.16 Exhibit 1016

EXHIBIT 10.16

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 Amended and Restated 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>> (the “Date of Grant”), 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, 20__ and ending December 31, 20__ (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 through the end of the Performance Period.

(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: return on assets relative to the return on assets of the Company’s “Peer Group” listed on Schedule A attached hereto (“Relative ROA”); and 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 ROA
		Performance
Performance Level Compared to Peer Group		Percentage(%)

	Below 25th Percentile		0	%
Threshold	25th Percentile		25	%
Target	50th Percentile		50	%
Maximum	75th Percentile or above		100	%


	Relative TSR
		Performance
Performance Level Compared to Peer Group		Percentage(%)

	Below 25th Percentile		0	%
Threshold	25th Percentile		25	%
Target	50th Percentile		50	%
Maximum	75th Percentile or above		100	%

(i)Return on assets with respect to the Company or any other company in the peer group shall be calculated as (A) the sum of the Company’s income from continuing operations before income taxes and depreciation, depletion, amortization and accretion, divided by (B) the sum of the Company’s total assets plus accumulated depreciation and depletion, less goodwill and other intangible assets, investment in unconsolidated companies and non-interest bearing current liabilities.

(ii)Total shareholder return as applied to the Company or any company in the peer group means stock price appreciation from the beginning to the end of the Performance Period, including monthly reinvestment of dividends and distributions paid during the Performance Period.

(iii)The Committee shall adjust the performance criteria in Section 2(c)(i) with respect to the Company or any other company in the peer group for any year during the Performance Period, to recognize (A) the effect of accounting changes in accordance with generally accepted accounting principles, (B) the impact of changes to international, federal and state tax laws, and (C) unusual or non-recurring transactions or events during the 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 or other periodic report 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 25th percentile in Relative ROA and the 50th 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 ROA reached the 75th percentile but Relative TSR

was below the 25th 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 <<Payment Date>>. 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 ROA 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.

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 ROA 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 which the 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 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 attention of the Human Resources Department 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).

(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.

(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.

<<Electronic Signature>>

<<Acceptance Date>>

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 ROA 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-10.18 5 spn-20151231ex101853610.htm EX-10.18 Exhibit 1018

EXHIBIT 10.18

SUPERIOR ENERGY SERVICES, INC.

NOTICE OF GRANT OF

RESTRICTED STOCK UNITS

UNDER THE

2013 STOCK INCENTIVE PLAN

Pursuant to the terms of the Superior Energy Services, Inc. Amended and Restated 2013 Stock Incentive Plan (the “Plan”), <<Director Name>> (the “Director”), being a non-management member of the Board of Directors (the “Board”) of Superior Energy Services, Inc. (the “Company”), was granted restricted stock units (“RSUs”) as hereinafter set forth. The RSUs were granted as a matter of separate inducement in connection with his service as a director of the Company, and not in lieu of any fee or other compensation for service as a director. This Notice is subject to the provisions of the Plan, and all terms not otherwise defined herein shall have the meanings set forth in the Plan.


	Grant Date:	<<Date of Grant>>
	Number of RSUs Granted:	<<Units Granted>>
	Scheduled Vesting Date:	The date of the Company’s 20__ annual meeting of stockholders

1.The following terms and conditions shall apply to the RSUs.

1.1 Each RSU represents the right to automatically receive from the Company, on the Scheduled Vesting Date, one share (a “Share”) of Common Stock, free of any restrictions, and all cash, securities and property credited to or deposited in the Director’s Dividend Equivalent Account (as defined in Section 1.2) with respect to such RSU, except as otherwise set forth herein.

1.2 From and after the Grant Date of an RSU until the issuance of the Shares payable in respect of such RSU, the Director 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, securities, or other property distributed or distributable in respect of one share of Common Stock to which the Director would have been entitled had the Director been a record holder of one share of Common Stock for each RSU at all times from the Grant Date 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 Director with respect to all RSUs granted on the same date.

1.3 (a) Except as otherwise set forth in this Section 1.3, the Director’s termination of service on the Board prior to vesting of the RSUs shall have no effect on the outstanding RSUs and Related Credits.

(b) If the Director voluntarily resigns from the Board prior to the vesting of the RSUs, then all unvested RSUs and Related Credits shall immediately be forfeited on the date the Director ceases to serve on the Board.

(c) If the Director’s service on the Board terminates by reason of the Director’s death or disability (as defined herein), all unvested RSUs and Related Credits shall vest as of the date the Director ceases to serve on the Board, provided such cessation of service also constitutes a “separation from service” in accordance with Section 409A of the Internal Revenue Code and any related implementing regulations or guidance (“Section 409A”).

(d) For purposes of this Section 1.3, a “disability” shall have occurred if the Director is (i) 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 (ii) 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 3 months under an accident and health plan covering employees of the Director’s employer.

1.4 Upon a Change of Control, all outstanding RSUs shall become fully vested; provided, however, that if the event constituting the Change of Control of the Company 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, then settlement of the RSUs and distribution of the Shares shall be delayed until the Scheduled Vesting Date or such earlier time as settlement would be permissible under Section 409A.

2.The terms of this Notice shall bind and inure to the benefit of the Director, the Company and the successors and assigns of the Company and, to the extent provided in the Plan and in this Notice, the legal representatives of the Director.

3.This Notice may at any time be amended by the Committee provided that no amendment to this Notice that materially impairs the benefits provided to the Director hereunder may be made without the Director’s consent.

4.It is intended that the payments and benefits provided under this Notice will comply with the requirements of Section 409A or an exemption therefrom. This Notice 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.


	SUPERIOR ENERGY SERVICES, INC.

	By:
		David D. Dunlap
		President and Chief Executive Officer

EX-21.1 6 spn-20151231xex211.htm EX-21.1 Exhibit 211

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	ORGANIZATION
1105 Peters Road, L.L.C	Louisiana
Alliance Energy Service Co. LLC	Colorado
Balance Point Group B.V.	Netherlands
Complete Energy Services, Inc.	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
Ingenieria y Technologia de Servicios S.A.S.	Colombia
Integrated Production Services, Inc.	Delaware
International Snubbing Services, L.L.C.	Louisiana
Monument Well Service Co.	Delaware
Pumpco Energy Services, Inc.	Delaware
SES Canada, ULC	Canada
SESI, L.L.C.	Delaware
Stabil Drill Specialties, L.L.C.	Louisiana
Sub-Surface Tools, L.L.C.	Louisiana
Superior Energy International, C.V.	Netherlands
Superior Energy Services (UK) Limited	United Kingdom
Superior Energy Services - Servicos de Petroleo do Brasil,	Brazil
Superior Energy Services Group B.V.	Netherlands
Superior Energy Services S.A.	Argentina
Superior Energy Services, L.L.C.	Louisiana
Superior Energy Services - North America Services, Inc.	Delaware
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	United Kingdom
Workstrings International, L.L.C	Louisiana

EX-23.1 7 spn-20151231xex231.htm EX-23.1 Exhibit 231

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, 333-116078, 333-136809, 333-161212, 333-174972, 333-177679, 333-189130, 333-204563) on Form S-8 of Superior Energy Services, Inc. and subsidiaries of our reports dated February 25, 2016, with respect to the consolidated balance sheets of Superior Energy Services, Inc. and subsidiaries as of December 31, 2015 and 2014, 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, 2015, and related financial statement schedule, and the effectiveness of internal control over financial reporting as of December 31, 2015, which reports appear in the December 31, 2015 annual report on Form 10-K of Superior Energy Services, Inc.

Our report refers to a change in the method of accounting for debt issuance costs, accounting for deferred income taxes and accounting for discontinued operations.

KPMG, LLP

Houston, Texas

February 25, 2016

EX-23.2 8 spn-20151231ex2321dc5ef.htm EX-23.2 Exhibit 232

EXHIBIT 23.2

TBPE REGISTERED ENGINEERING FIRM F-1580FAX (713) 651-0849

1100 LOUISIANA SUITE 4600HOUSTON, TEXAS 77002-5294TELEPHONE (713) 651-9191

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, 2015, and to the incorporation of our report of estimates of reserves and present value of future net reserves as of December 31, 2015 and December 31, 2014 (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 (No. 333-125316, 333-116078, 333-136809, 333-161212, 333-174972, 333-177679, 333-189130, 333-204563)

/s/ Ryder Scott Company, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

February 23, 2016

SUITE 600, 1015 4TH STREET, S.W.CALGARY, ALBERTA T2R 1J4TEL (403) 262-2799FAX (403) 262-2790

621 17TH STREET, SUITE 1550DENVER, COLORADO 80293-1501TEL (303) 623-9147FAX (303) 623-4258

EX-23.3 9 spn-20151231ex233415bcc.htm EX-23.3 Exhibit 233

EXHIBIT 23.3

020401SecondPagePortrait2

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, 2015, and to the incorporation of our report of estimates of reserves and present value of future net reserves as of December 31, 2012 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, 333-136809, 333-161212, 333-174972, 333-177679, 333-189130, 333-204563).

NETHERLAND, SEWELL & ASSOCIATES, INC.

By: /s/ Danny D. Simmons, P.E.

Danny D. Simmons, P.E.

President and Chief Operating Officer

Houston, Texas

February 24, 2016

EX-31.1 10 spn-20151231xex311.htm EX-31.1 Exhibit 311

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 25, 2016
			/s/ David. D. Dunlap
			David D. Dunlap
			President and Chief Executive Officer
			Superior Energy Services, Inc.

EX-31.2 11 spn-20151231xex312.htm EX-31.2 Exhibit 312

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.;

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 25, 2016
			/s/ Robert S. Taylor
			Robert S. Taylor
			Executive Vice President, Treasurer and Chief Financial Officer
			Superior Energy Services, Inc.

EX-32.1 12 spn-20151231xex321.htm EX-32.1 Exhibit 321

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, 2015 (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 25, 2016
			/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 13 spn-20151231xex322.htm EX-32.2 Exhibit 322

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:

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 25, 2016
			/s/ Robert S. Taylor
			Robert S. Taylor
			Executive Vice President, Treasurer and Chief Financial Officer
			Superior Energy Services, Inc.

EX-99.1 14 spn-20151231ex99108d28b.htm EX-99.1 Exhibit 991

EXHIBIT 99.1


	January 15, 2016

Ms. Yelena Shugol,

Director, Financial Reporting

Superior Energy Services

1001 Louisiana Street, Suite 2900

Houston, Texas 77002

Dear Ms. Shugol,

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of Superior Energy Services (Superior) as of December 31, 2015. The subject properties are located in the federal waters offshore Louisiana in the Green Canyon Block 65 Field, also called Bullwinkle. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 14, 2016 and presented herein, was prepared for public disclosure by Superior in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of Superior as of December 31, 2015.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2015, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

Superior Energy Services

As of December 31, 2015


	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Remaining Reserves
Oil/Condensate – MBBL		1,621.7		370.5		193.7		2,185.9
Plant Products – MBBL		154.6		55.5		7.4		217.5
Gas – MMCF		3,839.0		1,377.0		158.0		5,374.0

Income Data (M$)
Future Gross Revenue	$	93,704.7	$	23,222.3	$	10,121.3	$	127,048.3
Deductions		104,714.5		13,493.5		8,892.0		127,100.0
Future Net Income (FNI)	$	(11,009.8)	$	9,728.8	$	1,229.3	$	(51.7)

Discounted FNI @ 10%	$	26,580.4	$	5,044.3	$	113.6	$	31,738.3

Please note that a large abandonment cost of 74,400 M$ net to Superior is scheduled to occur one year following the economic life of the properties, currently in the year 2026. This large abandonment cost, which is applied to the Proved Producing reserves category, causes the undiscounted future net income to have a negative value for the Proved Producing and Total Proved reserves categories. Without considering abandonment costs, the undiscounted future net income would be positive and much larger than the discounted value for all reserves categories.

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBBL). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package AriesTM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes, although there are no such taxes on these properties since they are located in federal waters. The deductions incorporate the normal direct costs of operating the wells, recompletion costs, development costs, gas transportation costs and abandonment costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 87.6 percent and gas reserves account for the remaining 12.4 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.


	Discounted Future Net Income (M$)
	As of December 31, 2015
Discount Rate		Total
Percent		Proved

4.00		$18,169.3
6.37		$24,984.2
9.00		$30,232.4
11.00		$33,024.5

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe categories.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas consumed in operations as 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.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Superior’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

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.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as

changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Superior’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Superior owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 57.5 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. The performance method used was decline curve analysis which utilized extrapolations of historical production and pressure data available through September 2015 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Fieldwood Energy LLC (Fieldwood), the operator of the field, or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 42.5 percent of the proved producing reserves were estimated by the volumetric method, analogy, or a combination of methods. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

Approximately 67.7 percent of the proved developed non-producing and undeveloped reserves included herein were estimated by the volumetric method. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Fieldwood or which we have obtained from public data sources that were available through September 2015. The data utilized from the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof. The remaining 32.3 percent of the non-producing and undeveloped reserves included herein were estimated by performance methods.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Superior has informed us that they have furnished or authorized Fieldwood, the operator of the working interest properties and partner in the three overriding royalty properties which are operated by Walter Oil & Gas Corp, to furnish us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Superior with respect to property interests owned, abandonment costs and insurance costs. We have relied on Fieldwood for production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, recompletion and development costs, development plans, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Superior and Fieldwood. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Fieldwood. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Fieldwood furnished us with the above mentioned average prices in effect on December 31, 2015. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Fieldwood. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Fieldwood to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.


Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
	Oil/Condensate	WTI Cushing	$50.28/Bbl	$49.21/Bbl
United States	NGLs	Mount Belvieu – Propane	$19.90/Bbl	$16.90/Bbl
	Gas	Henry Hub	$2.66/MMBTU	$2.94/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by Fieldwood and are based on the operating expense reports of Fieldwood and include only those costs directly applicable to the leases or wells. The operating costs include COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements and a gas transportation fee. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Fieldwood. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Fieldwood and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by Superior were accepted without independent verification.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Fieldwood’s plans to develop these reserves as of December 31, 2015. The implementation of Fieldwood’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Fieldwood’s management. As the result of our inquiries during the course of preparing this report, Superior has informed us that the development activities included herein have been subjected to and received the internal approvals required by Superior’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Superior. Superior has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, Superior has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2015, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Fieldwood/Superior were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Superior. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Superior Energy Services.

Superior Energy Services makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Superior Energy Services has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-4 and Form S-8 of Superior Energy Services, of the references to our name as well as to the references to our third party report for Superior Energy Services, which appears in the December 31, 2015 annual report on Form 10-K of Superior Energy Services. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Superior Energy Services.

We have provided Superior Energy Services with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings

made by Superior Energy Services and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.


	Very truly yours,

	RYDER SCOTT COMPANY, L.P.
	TBPE Firm Registration No. F-1580

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. W. Frank Jeanes was the primary technical person responsible for overseeing the estimate of the reserves, future production and income presented herein.

Mr. Jeanes, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2007, is a Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide, with primary emphasis on the Gulf Coast area of the U.S. Before joining Ryder Scott, Mr. Jeanes served in a number of engineering positions with Texaco Inc., Houston Pipe Line Company, North Central Oil Corp. and spent over 20 years as an independent consulting engineer on numerous client engagements. For more information regarding Mr. Jeanes’ geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

Mr. Jeanes earned a Bachelor of Science degree in Petroleum Engineering from The University of Texas in 1971, and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Jeanes fulfills. As part of his 2015 continuing education hours, Mr. Jeanes attended an internally presented fourteen and one-half hours of formalized training, seven hours at the annual Ryder Scott Reserves Conference consisting of six hours of presentations on the subject of reserves reporting standards and evaluation methods and one hour of professional ethics, seven hours of technical sessions and one hour of ethics training at the 2015 SPEE Annual Conference as well as various professional society meetings and presentations totaling four hours covering such topics as oil prices, sub-surface rights and trespass, geologic concepts, and ethics for engineers.

Based on his educational background, professional training and more than 44 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Jeanes has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

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. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

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).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(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 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

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 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

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion 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.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

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.

(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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

<div> <div style="margin-left:0pt;margin-right:0pt;">     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 2015 presentation.   </div> </div>

<div> <div style="margin-left:0pt;margin-right:0pt;"> Recently Adopted Accounting Guidance   In November 2015, the Financial Accounting Standards Board (FASB) issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes, which amends existing guidance on income taxes to require the classification of all deferred tax assets and liabilities as non-current on the balance sheet.  The new standard is effective for the Company on January 1, 2017, with early adoption permitted, and the guidance may be applied either prospectively or retrospectively.  The Company adopted this standard as of December 31, 2015 and applied the change retrospectively to prior periods, resulting in a $32.1 million reduction in total current assets and corresponding decrease in non-current deferred income tax liabilities.       In April 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs, which changes the presentation of debt issuance costs. This guidance requires that debt on the balance sheet be presented net of unamortized debt issuance costs.  Amortization of such costs is reported as interest expense, which is consistent with the Company’s current policy. This change conforms the presentation of debt issuance costs with that of debt discounts. The ASU is effective for annual reporting periods (including interim reporting periods within those periods) beginning after December 15, 2015; early adoption is permitted. The guidance is required to be applied retrospectively to all prior periods. The Company adopted this standard as of December 31, 2015. The effect of the adoption of ASU 2015-03 on the Company’s consolidated balance sheet is a reduction of total assets and long-term debt of $27.5 million as of December 31, 2014.   In April 2014, the FASB issued ASU No. 2014-08, Presentation of Financial Statements and Property, Plant and Equipment, which changes the definition of discontinued operations.  The guidance permits only those disposed components (or components held-for-sale) representing a strategic shift that have (or will have) a major effect on operations and financial results to be reported in discontinued operations.  The new standard is effective prospectively for disposals (or classifications as held-for-sale) occurring after December 31, 2014.  The Company has adopted the accounting guidance as of January 1, 2015.   Recently Issued Accounting Guidance   In July 2015, the FASB issued ASU No. 2015-11, Inventory – Simplifying the Measurement of Inventory, which applies to inventory measured using first-in, first-out or average cost. The guidance in this update states that inventory within its scope shall be measured at the lower of cost or net realizable value, and when the net realizable value of inventory is lower than its cost, the difference shall be recognized as a loss in earnings. The new standard is effective for the Company beginning on January 1, 2017 and should be applied on a prospective basis. The Company is evaluating the effect that ASU 2015-11 will have on its consolidated financial statements and related disclosures.   In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which will replace most existing revenue recognition guidance in GAAP.  The guidance in this update requires an entity to recognize the amount of revenue that it expects to be entitled for the transfer of promised goods or services to customers. The new standard is effective for the Company on January 1, 2018. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09 will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the accounting guidance on its ongoing financial reporting. </div> </div>

<div> <div style="margin-left:0pt;margin-right:0pt;">   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 recognizes oil and gas revenue from its interests in producing wells as oil and natural gas is sold.  Taxes collected from customers and remitted to governmental authorities are reported on a net basis in the Company’s financial statements. </div> </div>

Document And Entity Information - USD ($) $ in Millions	12 Months Ended
Document And Entity Information - USD ($) $ in Millions	Dec. 31, 2015	Feb. 16, 2016	Jun. 30, 2015
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, 2015
Amendment Flag	false
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		151,397,654
Entity Public Float			$ 3,190
Entity Well-known Seasoned Issuer	Yes
Trading Symbol	spn
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No

XML 26 R2.htm IDEA: XBRL DOCUMENT

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 564,017	$ 393,046
Accounts receivable, net of allowance for doubtful accounts of $28,242 and $22,076 at December 31, 2015 and December 31, 2014, respectively	428,514	926,768
Prepaid expenses	42,298	74,750
Inventory and other current assets	165,062	185,429
Assets held for sale	95,234	116,680
Total current assets	1,295,125	1,696,673
Property, plant and equipment, net	2,123,291	2,733,839
Goodwill	1,140,101	2,468,409
Notes receivable	52,382	25,970
Intangible and other long-term assets, net	303,345	392,891
Total assets	4,914,244	7,317,782
Current liabilities:
Accounts payable	114,475	225,306
Accrued expenses	271,246	363,747
Income taxes payable	9,185	40,213
Current maturities of long-term debt	29,957	20,941
Current portion of decommissioning liabilities	19,052
Liabilities Held-for-sale	4,661	61,840
Total current liabilities	448,576	712,047
Deferred income taxes	383,069	670,858
Decommissioning liabilities	98,890	88,000
Long-term debt, net	1,588,263	1,600,373
Other long-term liabilities	$ 184,634	$ 166,766
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 and Outstanding- 150,861,500as of December 31, 2015 Authorized - 250,000,000, Issued - 149,648,826, Outstanding - 149,708,825 at December 31, 2014	$ 151	$ 150
Additional paid in capital	2,664,517	2,620,328
Accumulated other comprehensive loss, net	(45,694)	(36,280)
Retained earnings	(408,162)	1,495,540
Total stockholders' equity	2,210,812	4,079,738
Total liabilities and stockholders' equity	$ 4,914,244	$ 7,317,782

XML 27 R3.htm IDEA: XBRL DOCUMENT

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Consolidated Balance Sheets [Abstract]
Allowance for doubtful accounts	$ 28,242	$ 22,076
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	150,861,500	149,648,826
Common stock, shares outstanding	150,861,500	149,708,825

XML 28 R4.htm IDEA: XBRL DOCUMENT

Condensed Consolidated Statements Of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Consolidated Statements of Operations [Abstract]
Services	$ 2,104,942	$ 3,466,279	$ 3,371,847
Rentals	669,623	1,090,343	978,210
Total, Revenues	2,774,565	4,556,622	4,350,057
Costs and expenses:
Cost of Services (exclusive of items shown separately below)	1,575,653	2,308,270	2,244,881
Cost of Rentals (exclusive of items shown separately below)	290,159	426,563	388,709
Cost of goods and services	1,865,812	2,734,833	2,633,590
Depreciation, depletion, amortization and accretion	612,147	650,814	604,441
General and administrative expenses	510,708	624,371	597,778
Reduction in value of assets	1,738,887		300,078
Income from operations	(1,952,989)	546,604	214,170
Other income (expense):
Interest expense, net	97,318	96,734	107,902
Other Expense	(9,476)	(7,681)	(5,511)
Income from continuing operations before income taxes	(2,059,783)	442,189	100,757
Income taxes	(252,020)	161,399	55,272
Net income from continuing operations	(1,807,763)	280,790	45,485
Loss from discontinued operations, net of tax	(46,955)	(22,973)	(156,903)
Net income (loss)	$ (1,854,718)	$ 257,817	$ (111,418)
Earnings per share information:
Continuing operations, basic	$ (12.02)	$ 1.81	$ 0.29
Discontinued operations, basic	(0.31)	(0.15)	(0.99)
Basic earnings (loss) per share	(12.33)	1.66	(0.70)
Continuing operations, diluted	(12.02)	1.79	0.28
Discontinued operations, diluted	(0.31)	(0.14)	(0.97)
Diluted earnings per share	(12.33)	1.65	(0.69)
Cash dividends declared per share	$ 0.32	$ 0.24	$ 0.08
Weighted average common shares used in computing earnings per share:
Basic	150,461	155,154	159,206
Incremental common shares from stock based compensation		1,572	1,574
Diluted	150,461	156,726	160,780

XML 29 R5.htm IDEA: XBRL DOCUMENT

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Consolidated Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (1,854,718)	$ 257,817	$ (111,418)
Unrealized net gain (loss) on investment securities, net of tax			(256)
Reclassification adjustment, net of tax		1,153
Change in cumulative translation adjustment, net of tax	(9,414)	(19,933)	2,073
Comprehensive income (loss)	$ (1,864,132)	$ 239,037	$ (109,601)

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

XML 30 R6.htm IDEA: XBRL DOCUMENT

Consolidated Statements Of Changes In Stockholders' Equity - USD ($) $ in Thousands	Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]	Total
Beginning balance, value at Dec. 31, 2012	$ 158	$ 2,850,855	$ (19,317)	$ 1,399,383	$ 4,231,079
Beginning balance, shares at Dec. 31, 2012	157,501,635
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Net income (loss)				(111,418)	(111,418)
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Unrealized net gain (loss) on investment securities			(256)		(256)
Unrealized net gain (loss) on investment securities, net of tax			(256)		(256)
Foreign currency translation adjustment			2,073		2,073
Stock Withheld and Retired Value		(2,811)			(2,811)
Stock Withheld and Retired Shares	(119,070)
Stock Repurchased and Retired During Period, Shares	(426,883)
Stock Repurchased and Retired During Period, Value		(10,627)			(10,627)
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)
Tax benefit (expense) from stock-based compensation		(1,185)			(1,185)
Cash dividends declared				(12,759)	(12,759)
Stock Issued During Period, Shares, Share-based Compensation	1,154,032
Stock-based compensation expense, net of forfeitures	$ 1	26,071			26,072
Shares issued under Employee Stock Purchase Plan, value		5,013			$ 5,013
Shares issued under Employee Stock Purchase Plan, shares	185,407				185,407
Exercise of stock options, shares	426,883
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
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Net income (loss)				257,817	257,817
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Reclassification Adjustment of unrealized net loss on available-for-sale securities, Net of Tax			(1,153)		(1,153)
Foreign currency translation adjustment			(19,933)		(19,933)
Stock Withheld and Retired Value		(7,315)			(7,315)
Stock Withheld and Retired Shares	(267,340)
Stock Repurchased and Retired During Period, Shares	(10,246,091)
Stock Repurchased and Retired During Period, Value	$ (10)	(299,734)			(299,744)
Incremental common shares from restricted stock units	95,914
Vesting of restricted stock assumed with acquisition	114,839
Exercise of stock options, value	$ 1	10,560			10,561
Exercise of stock options, shares	(880,687)
Tax benefit (expense) from stock-based compensation		6,160			6,160
Cash dividends declared				(37,483)	(37,483)
Stock Issued During Period, Shares, Share-based Compensation	(152,447)
Stock-based compensation expense, net of forfeitures		30,982			30,982
Shares issued under Employee Stock Purchase Plan, value		6,096			$ 6,096
Shares issued under Employee Stock Purchase Plan, shares					246,480
Exercise of stock options, shares	10,246,091
Ending balance, value at Dec. 31, 2014	$ 150	2,620,328	(36,280)	1,495,540	$ 4,079,738
Ending balance, shares at Dec. 31, 2014	149,648,826
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Net income (loss)				(1,854,718)	(1,854,718)
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Foreign currency translation adjustment			(9,414)		(9,414)
Stock Withheld and Retired Value		(5,696)			(5,696)
Stock Withheld and Retired Shares	(323,537)
Stock Repurchased and Retired During Period, Shares	(506,029)
Incremental common shares from restricted stock units	460,400
Restricted stock grant and expense, net of forefeitures, shares	(48,374)
Vesting of restricted stock assumed with acquisition	61,319
Exercise of stock options, value	$ 1	8,819			$ 8,820
Exercise of stock options, shares					506,029
Tax benefit (expense) from stock-based compensation		(2,174)			$ (2,174)
Cash dividends declared				(48,984)	(48,984)
Stock-based compensation expense, net of forfeitures		32,661			32,661
Shares issued to pay performance share unit, value		5,011			5,011
Shares issued to pay performance share unit, shares	224,303
Shares issued under Employee Stock Purchase Plan, value		5,568			$ 5,568
Shares issued under Employee Stock Purchase Plan, shares	332,534				332,467
Exercise of stock options, shares	506,029
Ending balance, value at Dec. 31, 2015	$ 151	$ 2,664,517	$ (45,694)	$ (408,162)	$ 2,210,812
Ending balance, shares at Dec. 31, 2015	150,861,500

XML 31 R7.htm IDEA: XBRL DOCUMENT

Consolidated Statements of Changes in Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Stockholders' Equity [Abstract]
Cash dividends declared per share	$ 0.32	$ 0.24	$ 0.08

XML 32 R8.htm IDEA: XBRL DOCUMENT

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss)	$ (1,854,718)	$ 257,817	$ (111,418)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	612,147	652,143	625,928
Deferred income taxes	(288,671)	(49,567)	14,435
Reduction in value of assets including discontinued operations	1,738,887		419,380
Stock based and performance share unit compensation expense	46,485	42,748	35,832
Amortization of debt acquisition costs and note discount	7,643	8,110	8,919
(Gains) losses on sales of assets and businesses	(14,803)	(12,777)	(657)
Other reconciling items, net	49,042	(6,803)	(899)
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable	501,269	(9,487)	85,423
Inventory and other current assets	33,282	53,594	(70,995)
Accounts payable	(105,801)	36,450	(32,304)
Accrued expenses	(116,573)	16,411	25,154
Income taxes	(30,891)	46,134	(162,148)
Other, net	55,314	(1,762)	56,158
Net Cash Provided by (Used in) Operating Activities, Total	632,612	1,033,011	892,808
Cash flows from investing activities:
Payments for capital expenditures	(358,226)	(616,102)	(608,960)
Purchase of leased vessels	46,442
Proceeds from Sale of Available-for-sale Securities, Equity		10,622
Acquisitions of businesses, net of cash acquired		(24,327)	(23,797)
Cash Proceeds From Sales of Assets And Businesses	14,110	147,305	6,292
Proceeds from Insurance Settlement, Investing Activities			22,650
Other	2,290	7,767	(1,753)
Net Cash Provided by (Used in) Investing Activities, Total	(388,268)	(474,735)	(605,568)
Cash flows from financing activities:
Repayments of Long-term Lines of Credit	(7,475)	(14,736)	(581,771)
Proceeds from Long-term Lines of Credit	7,475	14,736	581,771
Payment to extinguish capital lease obligation	20,933
Proceeds from issuance of long-term debt	14,733	2,602
Principal payments of long-term debt	(21,038)	(21,564)	(170,000)
Share repurchases		(299,734)	(10,627)
Cash dividends	(48,139)	(49,756)
Proceeds from exercise of stock options	8,820	10,560	6,264
Proceeds from issuance of stock through employee benefit plans	4,803	4,870	4,124
Other	(2,302)	724	(6,840)
Net Cash Provided by (Used in) Financing Activities, Total	(68,859)	(357,168)	(181,203)
Effect of exchange rate changes on cash	(4,514)	(4,109)	(1,189)
Net increase in cash and cash equivalents	170,971	196,999	104,848
Cash and cash equivalents at beginning of period	393,046	196,047	91,199
Cash and cash equivalents at end of period	$ 564,017	$ 393,046	$ 196,047

XML 33 R9.htm IDEA: XBRL DOCUMENT

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2015

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 (in thousands):



	Years Ended December 31,
	2015		2014		2013
Cash paid for interest	$	93,946	$	102,880	$	97,129

Cash paid for income taxes, net of refunds	$	40,074	$	127,132	$	164,158

Details of business acquisitions:
Fair value of assets	$	-	$	29,468	$	34,964
Fair value of liabilities		-		(5,125)		(10,942)
Common stock issued		-		-		-
Cash paid		-		24,343		24,022
Less cash acquired		-		(16)		(225)
Net cash paid for acquisitions	$	-	$	24,327	$	23,797

Non-cash investing activity:
Capital expenditures included in accounts payable,
accrued expenses and other long term liabilities	$	28,704	$	49,118	$	70,463

Non-cash financing activity:
Cash dividends declared	$	-	$	-	$	12,759

XML 34 R10.htm IDEA: XBRL DOCUMENT

Reduction in Value of Assets

12 Months Ended

Dec. 31, 2015

Reduction In Value Of Assets [Abstract]

Reduction In Value Of Assets

(3) Reduction in Value of Assets and Other Charges



	Years Ended December 31,
	2015		2013
Reduction in value of goodwill	$	1,326,701	$	91,016
Reduction in value of long-lived assets		330,194		180,320
Retirements of long-lived assets		42,545		14,418
Reduction in value of assets related to sale of a business		39,447		-
Reduction in value of assets related to Venezuela exit activities		-		14,324
Total reduction in value of assets	$	1,738,887	$	300,078

Reduction in Value of Goodwill

During 2015, the Company recorded $1,326.7 million reduction in value of goodwill relating to its Onshore Completion and Workover Services and Production Services segments. The Company determined that the implied fair value of its goodwill for the Onshore Completion and Workover Services segment was less than its carrying value and recorded a $740.0 million impairment of the Onshore Completion and Workover Services segment’s goodwill. In addition, the Company determined that the implied fair value of its goodwill for the Production Services segment was less than its carrying value and recorded a $586.7 million impairment of the Production Services segment’s goodwill. The reduction in value of goodwill in the Production Services segment was primarily driven by the continued decline in demand for coiled tubing services. The reduction in value of goodwill in the Onshore Completion and Workover Services and Production Services segments was primarily driven by further deterioration of market conditions during the year and the Company’s forecast did not indicate a timely recovery sufficient to support the carrying values of the goodwill.

Reduction in Value of Long-Lived Assets

Retirements of Long-Lived Assets

Reduction in Value of Assets Related to Sale of Coiled Tubing Business in Mexico

Reduction in Value of Assets Related to Venezuela Exit Activities

Other Charges

XML 35 R11.htm IDEA: XBRL DOCUMENT

Discontinued Operations

12 Months Ended

Dec. 31, 2015

Discontinued Operations [Abstract]

Discontinued Operations

(4) Discontinued Operations

The following table summarizes the components of loss from discontinued operations, net of tax (in thousands):



	Years Ended December 31,
	2015		2014		2013
Revenues	$	18,723	$	145,463	$	261,767

Loss from discontinued operations, net of tax benefit of $5,626, $19,330 and $15,439 for 2015, 2014 and 2013, respectively	$	(46,955)	$	(22,973)	$	(156,903)

During 2014, loss from discontinued operations included an $18.8 million gain related to the sale of marine vessels and equipment in the subsea construction business.

The following summarizes the assets and liabilities related to the businesses reported as discontinued operations (in thousands):



	December 31,
	2015		2014
Accounts receivable, net	$	1,234	$	16,701
Prepaid expenses		330		2,463
Inventory and other current assets		1,036		5,576
Current assets	$	2,600	$	24,740
Property, plant and equipment, net		92,634		91,171
Intangible and other long-term assets, net		-		769
Long-term assets	$	92,634	$	91,940
Accounts payable		1,007		20,530
Accrued expenses		3,654		24,496
Current liabilities	$	4,661	$	45,026
Other long-term liabilities	$	-	$	16,814

- Definition

The entire disclosure related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=51716988&loc=SL51721533-107759

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721665-107760

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5C
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721675-107760

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 360
-SubTopic 10
-Section 50
-Paragraph 3A
-URI http://asc.fasb.org/extlink&oid=51719941&loc=SL51724579-110230

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721663-107760

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 360
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=51719941&loc=d3e2941-110230

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=51717284&loc=d3e1361-107760

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5B
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721673-107760

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 3A
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721659-107760

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5A
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721671-107760

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5D
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721677-107760

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=51717284&loc=d3e1474-107760

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721683-107760

+ Details

XML 36 R12.htm IDEA: XBRL DOCUMENT

Property, Plant And Equipment

12 Months Ended

Dec. 31, 2015

Property, Plant And Equipment [Abstract]

Property, Plant And Equipment

(5) Property, Plant and Equipment

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



	December 31,
	2015		2014
Buildings, improvements and leasehold improvements	$	318,906	$	328,651
Marine vessels and equipment		87		55,494
Machinery and equipment		3,770,959		4,126,570
Automobiles, trucks, tractors and trailers		45,013		66,032
Furniture and fixtures		67,483		75,631
Construction-in-progress		74,683		102,895
Land		58,731		58,814
Oil and gas producing assets		66,285		189,294
Total		4,402,147		5,003,381
Accumulated depreciation and depletion		(2,278,856)		(2,269,542)
Property, plant and equipment, net	$	2,123,291	$	2,733,839

XML 37 R13.htm IDEA: XBRL DOCUMENT

Debt

12 Months Ended

Dec. 31, 2015

Debt [Abstract]

Debt

(6) Debt

The Company’s outstanding debt is as follows (in thousands):



	December 31,
	2015				2014
	Long-term		Current		Long-term		Current
Term loan due February 2017	$	305,000	$	20,000	$	325,000	$	20,000
Senior Notes due May 2019		500,000		-		500,000		-
Senior Notes due December 2021		800,000		-		800,000		-
Other		3,089		9,957		2,842		941
Total debt, gross		1,608,089		29,957		1,627,842		20,941
Unamortized debt issuance costs		(19,826)		-		(27,469)		-
Total debt	$	1,588,263	$	29,957	$	1,600,373	$	20,941

Debt maturities presented as of December 31, 2015 are as follows (in thousands):



2016	$	29,957
2017		306,705
2018		1,384
2019		500,000
2020		-
Thereafter		800,000
Total	$	1,638,046

Credit Facility

Senior Unsecured Notes

XML 38 R14.htm IDEA: XBRL DOCUMENT

Stock-Based Compensation And Retirement Plans

12 Months Ended

Dec. 31, 2015

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

Stock-Based and Long-Term Compensation

(7) Stock-Based and Long-Term Compensation

Total stock-based compensation expense and the associated tax benefits are as follows (in thousands):



Compensation Expense	Years Ended December 31,
	2015		2014		2013
Stock options	$	3,663	$	3,900	$	3,586
Restricted stock		9,219		15,800		21,460
Restricted stock units		19,699		11,282		-
Performance share units		10,733		10,688		10,014
Strategic performance share units		2,258		2,404		-
Total	$	45,572	$	44,074	$	35,060

Tax Benefit	Years Ended December 31,
	2015		2014		2013
Stock options	$	1,355	$	1,443	$	1,327
Restricted stock		3,411		5,846		7,940
Restricted stock units		7,289		4,174		-
Total	$	12,055	$	11,463	$	9,267

Total stock-based compensation expense is reflected in general and administrative expenses in the consolidated statements of operations.

Stock Options

The weighted average fair values of stock options granted and the assumptions used in estimating those fair values are as follows:



	Years Ended December 31,
	2015		2014		2013
Weighted average fair value of grants	$	6.25	$	6.95	$	8.98

Black-Scholes-Merton Assumptions:
Risk free interest rate		1.33%		1.42%		0.63%
Expected life (years)		5		4		4
Volatility		47.07%		34.50%		48.41%
Dividend yield		1.30		1.23		-

The following table summarizes stock option activity for 2015:



	Number of Options	Weighted Average Option Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding as of December 31, 2014	4,484,505	$	23.76	5.1	$	4,095
Granted	612,665	$	17.27
Exercised	(506,029)	$	17.43
Outstanding as of December 31, 2015	4,591,141	$	23.60	5.3	$	256
Exercisable as of December 31, 2015	3,488,262	$	24.48	4.3	$	256
Options expected to vest as of December 31, 2015	1,102,879	$	20.81	8.5	$	-

The following table summarizes non-vested stock option activity for 2015:



	Number of Options	Weighted Average Grant Date Fair Value
Non-vested as of December 31, 2014	824,488	$	7.83
Granted	612,665	$	17.27
Vested	(334,274)	$	25.01
Non-vested as of December 31, 2015	1,102,879	$	20.81

Restricted Stock

The following table summarizes restricted stock activity for 2015:



	Number of Shares	Weighted Average Grant Date Fair Value
Non-vested as of December 31, 2014	1,022,280	$	24.08
Vested	(678,880)	$	17.88
Forfeited	(50,463)	$	23.26
Non-vested as of December 31, 2015	292,937	$	23.13

Restricted Stock Units

The following table summarizes RSU activity for 2015:



	Number of Restricted Stock Units	Weighted Average Grant Date Fair Value
Non-vested as of December 31, 2014	1,416,477	$	26.40
Granted	2,162,146	$	17.74
Vested	(460,400)	$	18.51
Forfeited	(330,334)	$	20.16
Non-vested as of December 31, 2015	2,787,889	$	20.41

Performance Share Units

Employee Stock Purchase Plan

The following table summarizes ESPP activity (in thousands except shares):



	Years Ended December 31,
	2015		2014		2013
	2013 Plan		2013 Plan		2013 and 2007 Plans
Cash received for shares issued	$	4,803	$	4,870	$	4,124
Compensation expense	$	835	$	1,078	$	947
Shares issued		332,467		246,480		185,407

401(k)/Profit Sharing Plan

Non-Qualified Deferred Compensation Plans

The Company has a non-qualified deferred compensation plan which allows senior management 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. 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) in the consolidated statements of operations.

The following table summarizes deferred compensation balances (in thousands):



		December 31,
	Balance sheet location	2015		2014
Deferred compensation assets	Intangible and other long-term assets, net	$	11,548	$	12,982
Deferred compensation liabilities, short-term	Accounts payable	$	721	$	2,291
Deferred compensation liabilities, long-term	Other long-term liabilities	$	17,367	$	14,720

Supplemental Executive Retirement Plan

XML 39 R15.htm IDEA: XBRL DOCUMENT

Income Taxes

12 Months Ended

Dec. 31, 2015

Income Taxes [Abstract]

Income Taxes

(8) Income Taxes

The components of income (loss) from continuing operations before income taxes are as follows (in thousands):



	Years Ended December 31,
	2015		2014		2013
Domestic	$	(2,069,019)	$	372,672	$	165,463
Foreign		9,236		69,517		(64,706)
	$	(2,059,783)	$	442,189	$	100,757

The components of income tax expense (benefit) are as follows (in thousands):



	Years Ended December 31,
	2015		2014		2013
Current:
Federal	$	(952)	$	150,997	$	19,897
State		2,818		11,339		10,816
Foreign		19,227		36,287		25,613
		21,093		198,623		56,326
Deferred:
Federal		(249,193)		(33,172)		(6,341)
State		(10,034)		648		386
Foreign		(13,886)		(4,700)		4,901
		(273,113)		(37,224)		(1,054)
	$	(252,020)	$	161,399	$	55,272

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 as follows (in thousands):



	Years Ended December 31,
	2015		2014		2013
Computed expected tax expense	$	(720,923)	$	154,766	$	35,265
Increase (decrease) resulting from
State and foreign income taxes		(6,353)		8,467		(852)
Reduction in value of assets		464,395		-		34,874
Other		10,861		(1,834)		(14,015)
Income tax	$	(252,020)	$	161,399	$	55,272

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



	December 31,
	2015		2014
Deferred tax assets:
Allowance for doubtful accounts	$	8,275	$	3,942
Operating loss and tax credit carryforwards		92,798		21,928
Compensation and employee benefits		59,310		57,045
Decommissioning liabilities		30,400		21,029
Other		57,768		50,641
		248,551		154,585
Valuation allowance		(5,395)		-
Net deferred tax assets		243,156		154,585
Deferred tax liabilities:
Property, plant and equipment		469,728		648,054
Notes receivable		14,796		5,718
Goodwill and other intangible assets		119,661		138,017
Other		22,040		33,654
Deferred tax liabilities		626,225		825,443
Net deferred tax liability	$	383,069	$	670,858

The activity in unrecognized tax benefits is as follows (in thousands):



	Years Ended December 31,
	2015		2014		2013
Unrecognized tax benefits, December 31, 2014, 2013 and 2012, respectively	$	30,344	$	29,899	$	26,399
Additions based on tax positions related to current year		-		-		-
Additions based on tax positions related to prior years		6,752		7,860		5,065
Reductions based on tax positions related to prior years		(7,381)		(7,415)		(1,565)
Unrecognized tax benefits, December 31, 2015, 2014 and 2013, respectively	$	29,715	$	30,344	$	29,899

XML 40 R16.htm IDEA: XBRL DOCUMENT

Segment Information

12 Months Ended

Dec. 31, 2015

Segment Information [Abstract]

Segment Information

(9) Segment Information

Business Segments

Summarized financial information for the Company’s segments is as follows (in thousands):



2015

			Onshore
	Drilling		Completion
	Products and		and Workover		Production		Technical				Consolidated
	Services		Services		Services		Solutions		Unallocated		Total
Revenues	$	583,139	$	934,274	$	759,606	$	497,546	$	-	$	2,774,565
Cost of services and rentals
(exclusive of items shown separately below)		196,921		773,119		594,286		301,486		-		1,865,812
Depreciation, depletion, amortization and accretion		194,061		225,667		130,267		62,152		-		612,147
General and administrative expenses		127,525		121,289		139,304		122,590		-		510,708
Reduction in value of assets		40,237		783,229		790,517		124,904		-		1,738,887
Income (loss) from operations		24,395		(969,030)		(894,768)		(113,586)		-		(1,952,989)
Interest expense, net		-		-		(2,013)		1,707		(97,012)		(97,318)
Other expense		-		-		-		-		(9,476)		(9,476)
Income (loss) from continuing operations before income taxes	$	24,395	$	(969,030)	$	(896,781)	$	(111,879)	$	(106,488)	$	(2,059,783)



2014

			Onshore
	Drilling		Completion
	Products and		and Workover		Production		Technical				Consolidated
	Services		Services		Services		Solutions		Unallocated		Total
Revenues	$	904,358	$	1,732,833	$	1,350,956	$	568,475	$	-	$	4,556,622
Cost of services and rentals
(exclusive of items shown separately below)		282,023		1,205,443		941,030		306,337		-		2,734,833
Depreciation, depletion, amortization and accretion		186,642		233,430		164,672		66,070		-		650,814
General and administrative expenses		149,967		159,687		187,526		127,191		-		624,371
Income from operations		285,726		134,273		57,728		68,877		-		546,604
Interest expense, net		-		-		-		1,577		(98,311)		(96,734)
Other expense		-		-		-		-		(7,681)		(7,681)
Income (loss) from continuing operations before income taxes	$	285,726	$	134,273	$	57,728	$	70,454	$	(105,992)	$	442,189



2013

			Onshore
	Drilling		Completion
	Products and		and Workover		Production		Technical				Consolidated
	Services		Services		Services		Solutions		Unallocated		Total
Revenues	$	820,538	$	1,607,268	$	1,434,990	$	487,261	$	-	$	4,350,057
Cost of services and rentals
(exclusive of items shown separately below)		268,127		1,091,956		1,002,628		270,879		-		2,633,590
Depreciation, depletion, amortization and accretion		168,391		216,152		177,532		42,366		-		604,441
General and administrative expenses		136,244		158,448		190,647		112,439		-		597,778
Reduction in value of assets		2,292		16,975		28,568		252,243		-		300,078
Income (loss) from operations		245,484		123,737		35,615		(190,666)		-		214,170
Interest expense, net		-		-		-		1,323		(109,225)		(107,902)
Other income (expense)		-		-		-		836		(6,347)		(5,511)
Income (loss) from continuing operations before income taxes	$	245,484	$	123,737	$	35,615	$	(188,507)	$	(115,572)	$	100,757



Identifiable Assets
			Onshore
	Drilling		Completion
	Products and		and Workover		Production		Technical				Consolidated
	Services		Services		Services		Solutions		Unallocated		Total
December 31, 2015	$	1,223,191	$	1,929,185	$	967,719	$	794,149	$	-	$	4,914,244
December 31, 2014	$	1,284,842	$	2,993,824	$	2,098,592	$	940,524	$	-	$	7,317,782
December 31, 2013	$	1,237,842	$	2,961,390	$	2,158,653	$	1,009,058	$	-	$	7,366,943



Capital Expenditures
			Onshore
	Drilling		Completion
	Products and		and Workover		Production		Technical		Consolidated
	Services		Services		Services		Solutions		Total
December 31, 2015	$	129,504	$	103,001	$	72,048	$	53,673	$	358,226
December 31, 2014	$	274,752	$	152,742	$	88,870	$	99,738	$	616,102
December 31, 2013	$	246,479	$	101,854	$	122,946	$	137,681	$	608,960

Geographic Segments



Revenues
	Years Ended December 31,
	2015		2014		2013
United States	$	2,185,071	$	3,848,929	$	3,674,825
Other Countries		589,494		707,693		675,232
Total	$	2,774,565	$	4,556,622	$	4,350,057

Long-Lived Assets
			December 31,
			2015		2014
United States			$	1,799,418	$	2,416,306
Other Countries				323,873		317,533
Total, net			$	2,123,291	$	2,733,839

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e9038-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 33
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8971-108599

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Commitments And Contingencies	12 Months Ended
Commitments And Contingencies	Dec. 31, 2015
Commitments And Contingencies [Abstract]
Commitments And Contingencies	(10) Commitments and Contingencies The Company leases many of its office, service and assembly facilities under operating leases. In addition, the Company also leases certain assets used in providing services under operating leases. The leases expire at various dates over an extended period of time. Total rent expense was $29.6 million, $26.2 million and $25.6 million during 2015, 2014 and 2013, respectively. Future minimum lease payments under non-cancelable leases for the five years ending December 31, 2016 through 2020 and thereafter are as follows: $45.7 million, $32.4 million, $23.3 million, $16.1 million, $10.0 million and $25.2 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. However, based on current circumstances, the Company does not believe that the ultimate resolution of these proceedings, after considering available defenses and any insurance coverage or indemnification rights, will have a material adverse effect on its financial position, results of operations or cash flows.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2015

Fair Value Measurements [Abstract]

Fair Value Measurements

(11) Fair Value Measurements

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



			Fair Value Measurements at Reporting Date Using
	December 31, 2015		Level 1		Level 2		Level 3
Intangible and other long-term assets, net
Non-qualified deferred compensation assets	$	11,548	$	368	$	11,180		-
Interest rate swaps	$	6,905		-	$	6,905		-
Accounts payable
Non-qualified deferred compensation liabilities	$	721		-	$	721		-
Other long-term liabilities
Non-qualified deferred compensation liabilities	$	17,367		-	$	17,367		-

	December 31, 2014		Level 1		Level 2		Level 3
Intangible and other long-term assets, net
Non-qualified deferred compensation assets	$	12,982	$	1,481	$	11,501		-
Interest rate swaps	$	4,183		-	$	4,183		-
Accounts payable
Non-qualified deferred compensation liabilities	$	2,291		-	$	2,291		-
Other long-term liabilities
Non-qualified deferred compensation liabilities	$	14,720		-	$	14,720		-

The following table reflects the fair value measurements used in testing the impairment of long-lived assets and goodwill (in thousands):



	Years Ended December 31,
	2015				2013
	Impairment		Fair Value		Impairment		Fair Value
Property, plant and equipment, net	$	177,442	$	179,612	$	243,781	$	328,876
Goodwill	$	1,326,701	$	998,288	$	91,016	$	-
Intangible assets	$	68,890	$	6,345	$	18,296	$	4,355

Fair value is measured as of the impairment date using Level 3 inputs. See note 3 for discussion of reduction in value of assets recorded during 2015 and 2013.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2015

Derivative Financial Instruments [Abstract]

Derivative Financial Instruments

(12) Derivative Financial Instruments




		Years Ended December 31,
Effect of derivative instrument	Location of (gain) loss recognized	2015		2014		2013
Interest rate swap	Interest expense, net	$	(1,932)	$	(11,054)	$	13,079
Hedged item - debt	Interest expense, net		(790)		7,208		(12,303)
		$	(2,722)	$	(3,846)	$	776

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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+ Details

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Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	(13) Related Party Transactions During 2014 and 2013, the Company purchased services, products and equipment, as well as leased certain facilities, from companies affiliated with a former officer, who retired during the first quarter of 2015, of one of its subsidiaries. During 2014 and 2013, these transactions totaled $221.1 million and $164.8 million, respectively. During 2014, $92.1 million was purchased from ORTEQ Energy Services, a heavy equipment construction company which also manufactures pressure pumping equipment, $0.7 million was purchased from Ortowski Construction, primarily related to the manufacture of pressure pumping units, $21.6 million was paid to Resource Transport, LLC, related to the transportation of sand used in pressure pumping equipment, $79.3 million was purchased from Texas Specialty Sands, LLC primarily for the purchase of sand used for pressure pumping activities, $25.5 million was purchased from ProFuel, LLC, primarily related to the purchase of diesel used to operate equipment and trucks and $1.9 million was related to facilities leased from Timber Creek Real Estate Partners. During 2013, $52.8 million was purchased from ORTEQ Energy Services, $14.0 million was paid to Resource Transport, LLC, $69.1 million was purchased from Texas Specialty Sands, LLC, $26.9 million was purchased from ProFuel, LLC, and $2.0 million was related to facilities leased from Timber Creek Real Estate Partners. As of December 31, 2014, the Company’s trade accounts payable includes amounts due to these companies totaling $26.8 million, of which $10.1 million was due ORTEQ Energy Services, $1.7 million was due Resource Transport, $14.0 million was due Texas Specialty Sands, and $1.0 million was due ProFuel, LLC. No amounts were due Ortowski Construction and Timber Creek Real Estate Partners. The Company’s President and Chief Executive Officer serves as an independent director of the board of Linn Energy, LLC (Linn), an independent oil and gas development company. The Company recorded revenues from Linn of $7.2 million, $19.7 million and $26.9 million during 2015, 2014 and 2013, respectively. The Company had trade receivables from Linn of $2.0 million and $1.6 million as of December 31, 2015 and 2014, respectively.

- Definition

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References + Details

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Interim Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2015

Interim Financial Information (Unaudited) [Abstract]

Interim Financial Information (Unaudited)

(14) Interim Financial Information (Unaudited)

The following is a summary of consolidated interim financial information (in thousands):



	2015
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Revenues	$	917,235	$	710,784	$	601,396	$	545,150
Less:
Cost of services and rentals		582,246		465,533		420,485		397,548
Depreciation, depletion, amortization and accretion		162,220		158,352		146,757		144,818
Gross profit		172,769		86,899		34,154		2,784
Reduction in value of assets		-		807,637		755,632		175,618
Net loss from continuing operations		(1,497)		(775,132)		(816,587)		(214,547)
Loss from discontinued operations, net of tax		(9,640)		(9,857)		(4,610)		(22,848)
Net loss		(11,137)		(784,989)		(821,197)		(237,395)
Loss per share from continuing operations:
Basic and diluted	$	(0.02)	$	(5.15)	$	(5.42)	$	(1.43)
Loss per share from discontinued operations:
Basic and diluted	$	(0.06)	$	(0.07)	$	(0.03)	$	(0.15)

	2014
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Revenues	$	1,061,418	$	1,107,552	$	1,209,026	$	1,178,626
Less:
Cost of services and rentals		651,605		650,293		721,692		711,243
Depreciation, depletion, amortization and accretion		162,318		160,965		170,154		157,377
Gross profit		247,495		296,294		317,180		310,006
Net income from continuing operations		42,626		79,057		85,743		73,364
Loss from discontinued operations, net of tax		(5,954)		(3,895)		(5,886)		(7,238)
Net income		36,672		75,162		79,857		66,126
Earnings per share from continuing operations:
Basic	$	0.27	$	0.51	$	0.55	$	0.49
Diluted		0.27		0.50		0.55		0.48
Loss per share from discontinued operations:
Basic and diluted	$	(0.04)	$	(0.03)	$	(0.03)	$	(0.05)

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Supplementary Oil And Natural Gas Disclosures (Unaudited)

12 Months Ended

Dec. 31, 2015

Supplementary Oil And Natural Gas Disclosures [Abstract]

Supplementary Oil And Natural Gas Disclosures (Unaudited)

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

Oil and Natural Gas Reserves

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



	Crude Oil	Natural Gas
	(Mbbls)	(Mmcf)
Proved-developed and undeveloped reserves:
December 31, 2012	8,207	11,284
Revisions	(3,203)	(4,036)
Production	(411)	(296)
December 31, 2013	4,593	6,952
Revisions	(438)	1,431
Production	(738)	(1,247)
December 31, 2014	3,417	7,136
Revisions	(381)	(245)
Production	(633)	(1,517)
December 31, 2015	2,403	5,374

Proved-developed reserves:
December 31, 2013	2,397	2,100
December 31, 2014	3,184	6,945
December 31, 2015	2,202	5,216
Proved-undeveloped reserves:
December 31, 2013	2,196	4,852
December 31, 2014	233	191
December 31, 2015	201	158

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 (in thousands):



	Years Ended December 31,
	2015		2014		2013
Acquisition of properties - proved	$	-	$	-	$	-
Acquisition of properties - unproved		-		-		-
Exploratory costs		-		-		-
Development costs		20,636		52,719		51,527
Total costs incurred	$	20,636	$	52,719	$	51,527

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



	December 31,
	2015		2014
Proved oil and gas properties	$	66,285	$	189,294
Accumulated depreciation, depletion and amortization		-		(55,864)
Capitalized costs, net	$	66,285	$	133,430

Productive Wells Summary



	Productive Wells
	Gross	Net
Oil	11.00	5.61

Acreage

The following table sets forth information as of December 31, 2015 relating to acreage held by the Company. Developed acreage is assigned to productive wells.



	Gross	Net
	Acreage	Acreage
Developed	23,040	11,750
Undeveloped	-	-
Total	23,040	11,750

Drilling Activity



	Years Ended December 31,
	2015		2014
	Gross	Net	Gross	Net
Exploratory Wells
Productive	-	-	-	-
Non-productive	-	-	-	-
Total	-	-	-	-

Development Wells
Productive	1.00	0.51	2.00	1.02
Non-productive	1.00	0.51	1.00	0.51
Total	2.00	1.02	3.00	1.53

Results of Operations

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



	Years Ended December 31,
	2015		2014		2013
Revenues
Sales	$	30,245	$	77,845	$	47,050
Production costs		15,466		13,529		9,876
Exploration expenses		-		-		-
Depreciation, depletion and amortization		37,623		38,768		12,032
Reduction in value of assets		56,000		-		-
		(78,844)		25,548		25,142
Income tax expenses		(28,778)		9,325		8,800
Results of operations from producing activities (excluding corporate overhead)	$	(50,066)	$	16,223	$	16,342

Standardized Measure of Discounted Future Net Cash Flows Relating to Reserves

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



	Years Ended December 31,
	2015		2014		2013
Future cash inflows	$	127,048	$	336,944	$	496,704
Future production costs		(43,010)		(71,209)		(82,487)
Future development and abandonment costs		(84,090)		(111,374)		(156,340)
Future income tax expenses		1,353		(60,345)		(89,507)
Future net cash flows		1,301		94,016		168,370
10% annual discount for estimated timing of cash flows		(19,762)		(17,034)		10,641
Standardized measure of discounted future net cash flows	$	21,063	$	111,050	$	157,729

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves is as follows (in thousands):


	Years Ended December 31,
	2015		2014		2013
Beginning of the period	$	111,050	$	157,729	$	303,430
Net change in sales and transfer prices and in production (lifting) costs related to future production		(143,808)		(57,568)		(13,278)
Changes in estimated future development costs		3,787		(5,512)		(48,594)
Sales and transfers of oil and gas produced during the period		(14,779)		(64,316)		(45,866)
Net change due to extensions, discoveries, and improved recovery		6,737		-		75,304
Net changes due to revisions in quantity estimates		(36,397)		(8,396)		(228,620)
Previously estimated development costs incurred during the period		20,636		40,962		10,136
Accretion of discount		17,606		24,251		46,711
Other-unspecified		1,895		4,125		(24,169)
Net change in income taxes		54,336		19,775		82,675
Aggregate change in the standardized measure of discounted future net cash flows for the year		(89,987)		(46,679)		(145,701)
End of the period	$	21,063	$	111,050	$	157,729

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Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2015

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, 2015, 2014 and 2013

(in thousands)



	Balance at the		Charged to
	beginning of		costs and				Discontinued		Balance at the
Description	the year		expenses		Deductions		operations		end of the year
2015: Allowance for doubtful accounts	$	22,076	$	14,341	$	4,795	$	3,380	$	28,242
2014: Allowance for doubtful accounts	$	31,030	$	6,299	$	10,639	$	4,614	$	22,076
2013: Allowance for doubtful accounts	$	28,715	$	7,587	$	7,763	$	(2,491)	$	31,030

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Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2015

Summary Of Significant Accounting Policies [Abstract]

Basis of Presentation

Business

Use of Estimates

Major Customers and Concentration of Credit Risk

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

Inventory



	December 31,
	2015		2014
Finished goods	$	71,951	$	72,788
Raw materials		23,418		29,718
Work-in-process		18,203		20,317
Supplies and consumables		35,189		42,739
Total	$	148,761	$	165,562

Property, Plant and Equipment

Buildings and improvements	5	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	10	years
Furniture and fixtures	2	to	10	years

Reduction in Value of Long-Lived Assets Text Block

Reduction in Value of Long-Lived Assets

Goodwill

The following table summarizes the activity for the Company’s goodwill (in thousands):



			Onshore
	Drilling		Completion
	Products		and Workover		Production
	and Services		Services		Services		Total
Balance, December 31, 2013	$	144,872	$	1,419,550	$	893,687	$	2,458,109
Acquisition activities		-		-		13,909		13,909
Foreign currency translation adjustment		(2,033)		-		(1,576)		(3,609)
Balance, December 31, 2014		142,839		1,419,550		906,020		2,468,409
Acquisition activities		-		-		1,170		1,170
Reduction in value of assets		-		(740,000)		(586,701)		(1,326,701)
Foreign currency translation adjustment		(1,557)		-		(1,220)		(2,777)
Other		-		44,000		(44,000)		-
Balance, December 31, 2015	$	141,282	$	723,550	$	275,269	$	1,140,101

Notes Receivable

Intangible and Other Long-Term Assets

Intangible assets consist of the following (in thousands):



			December 31,
			2015						2014
	Estimated		Gross		Accumulated		Net		Gross		Accumulated		Net
	Useful Lives		Amount		Amortization		Balance		Amount		Amortization		Balance
Customer relationships	17	years	$	257,364	$	(65,209)	$	192,155	$	339,695	$	(64,954)	$	274,741
Tradenames	10	years		36,119		(15,371)		20,748		41,265		(13,151)		28,114
Non-compete agreements	3	years		3,242		(2,940)		302		4,487		(3,281)		1,206
Total			$	296,725	$	(83,520)	$	213,205	$	385,447	$	(81,386)	$	304,061

During 2015, the Company recorded $68.9 million of expense related to the reduction in carrying values of intangibles primarily in the Production Services segment (see note 3).

Decommissioning Liabilities

The following table summarizes the activity for the Company’s decommissioning liabilities (in thousands):



	December 31,
	2015		2014
Decommissioning liabilities, December 31, 2014 and 2013, respectively	$	88,000	$	83,519
Revisions in estimated timing and cash flows		24,660		(276)
Accretion		5,016		4,470
Liability acquisitions and dispositions		266		866
Liabilities settled		-		(579)
Total decommissioning liabilities, December 31, 2015 and 2014, respectively	$	117,942	$	88,000

Revenue Recognition

Income Taxes

Earnings (Loss) per Share

Earnings per Share

Fair Value Measurements

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

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

Financial Instruments

Foreign Currency

Stock-Based Compensation

Derivative Instruments and Hedging Activities

Self Insurance Reserves

Self-Insurance Reserves

Subsequent Events

Recently Issued Accounting Pronouncements

Recently Adopted Accounting Guidance

Recently Issued Accounting Guidance

XML 49 R25.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

Summary Of Significant Accounting Policies [Abstract]

Schedule of Inventory, Current [Table Text Block]



	December 31,
	2015		2014
Finished goods	$	71,951	$	72,788
Raw materials		23,418		29,718
Work-in-process		18,203		20,317
Supplies and consumables		35,189		42,739
Total	$	148,761	$	165,562

Estimated Useful Lives Of The Related Assets

Buildings and improvements	5	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	10	years
Furniture and fixtures	2	to	10	years

Summary Of Activity Of Goodwill



			Onshore
	Drilling		Completion
	Products		and Workover		Production
	and Services		Services		Services		Total
Balance, December 31, 2013	$	144,872	$	1,419,550	$	893,687	$	2,458,109
Acquisition activities		-		-		13,909		13,909
Foreign currency translation adjustment		(2,033)		-		(1,576)		(3,609)
Balance, December 31, 2014		142,839		1,419,550		906,020		2,468,409
Acquisition activities		-		-		1,170		1,170
Reduction in value of assets		-		(740,000)		(586,701)		(1,326,701)
Foreign currency translation adjustment		(1,557)		-		(1,220)		(2,777)
Other		-		44,000		(44,000)		-
Balance, December 31, 2015	$	141,282	$	723,550	$	275,269	$	1,140,101

Composition Of Intangible And Other Long-term Assets



			December 31,
			2015						2014
	Estimated		Gross		Accumulated		Net		Gross		Accumulated		Net
	Useful Lives		Amount		Amortization		Balance		Amount		Amortization		Balance
Customer relationships	17	years	$	257,364	$	(65,209)	$	192,155	$	339,695	$	(64,954)	$	274,741
Tradenames	10	years		36,119		(15,371)		20,748		41,265		(13,151)		28,114
Non-compete agreements	3	years		3,242		(2,940)		302		4,487		(3,281)		1,206
Total			$	296,725	$	(83,520)	$	213,205	$	385,447	$	(81,386)	$	304,061

Summary Of The Activity For Company's Decommissioning Liabilities



	December 31,
	2015		2014
Decommissioning liabilities, December 31, 2014 and 2013, respectively	$	88,000	$	83,519
Revisions in estimated timing and cash flows		24,660		(276)
Accretion		5,016		4,470
Liability acquisitions and dispositions		266		866
Liabilities settled		-		(579)
Total decommissioning liabilities, December 31, 2015 and 2014, respectively	$	117,942	$	88,000

XML 50 R26.htm IDEA: XBRL DOCUMENT

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2015

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information



	Years Ended December 31,
	2015		2014		2013
Cash paid for interest	$	93,946	$	102,880	$	97,129

Cash paid for income taxes, net of refunds	$	40,074	$	127,132	$	164,158

Details of business acquisitions:
Fair value of assets	$	-	$	29,468	$	34,964
Fair value of liabilities		-		(5,125)		(10,942)
Common stock issued		-		-		-
Cash paid		-		24,343		24,022
Less cash acquired		-		(16)		(225)
Net cash paid for acquisitions	$	-	$	24,327	$	23,797

Non-cash investing activity:
Capital expenditures included in accounts payable,
accrued expenses and other long term liabilities	$	28,704	$	49,118	$	70,463

Non-cash financing activity:
Cash dividends declared	$	-	$	-	$	12,759

XML 51 R27.htm IDEA: XBRL DOCUMENT

Reduction in Value of Assets (Tables)

12 Months Ended

Dec. 31, 2015

Reduction In Value Of Assets [Abstract]

Reduction in Value of Assets [Table Text Block]



	Years Ended December 31,
	2015		2013
Reduction in value of goodwill	$	1,326,701	$	91,016
Reduction in value of long-lived assets		330,194		180,320
Retirements of long-lived assets		42,545		14,418
Reduction in value of assets related to sale of a business		39,447		-
Reduction in value of assets related to Venezuela exit activities		-		14,324
Total reduction in value of assets	$	1,738,887	$	300,078

XML 52 R28.htm IDEA: XBRL DOCUMENT

Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2015

Discontinued Operations [Abstract]

Components Of Income (Loss) From Discontinued Operations



	Years Ended December 31,
	2015		2014		2013
Revenues	$	18,723	$	145,463	$	261,767

Loss from discontinued operations, net of tax benefit of $5,626, $19,330 and $15,439 for 2015, 2014 and 2013, respectively	$	(46,955)	$	(22,973)	$	(156,903)

Assets And Liabilities Of Disposal Groups



	December 31,
	2015		2014
Accounts receivable, net	$	1,234	$	16,701
Prepaid expenses		330		2,463
Inventory and other current assets		1,036		5,576
Current assets	$	2,600	$	24,740
Property, plant and equipment, net		92,634		91,171
Intangible and other long-term assets, net		-		769
Long-term assets	$	92,634	$	91,940
Accounts payable		1,007		20,530
Accrued expenses		3,654		24,496
Current liabilities	$	4,661	$	45,026
Other long-term liabilities	$	-	$	16,814

XML 53 R29.htm IDEA: XBRL DOCUMENT

Property, Plant And Equipment (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant And Equipment [Abstract]

Summary Of Property, Plant And Equipment



	December 31,
	2015		2014
Buildings, improvements and leasehold improvements	$	318,906	$	328,651
Marine vessels and equipment		87		55,494
Machinery and equipment		3,770,959		4,126,570
Automobiles, trucks, tractors and trailers		45,013		66,032
Furniture and fixtures		67,483		75,631
Construction-in-progress		74,683		102,895
Land		58,731		58,814
Oil and gas producing assets		66,285		189,294
Total		4,402,147		5,003,381
Accumulated depreciation and depletion		(2,278,856)		(2,269,542)
Property, plant and equipment, net	$	2,123,291	$	2,733,839

XML 54 R30.htm IDEA: XBRL DOCUMENT

Debt (Tables)

12 Months Ended

Dec. 31, 2015

Debt [Abstract]

Summary Of Long-Term Debt



	December 31,
	2015				2014
	Long-term		Current		Long-term		Current
Term loan due February 2017	$	305,000	$	20,000	$	325,000	$	20,000
Senior Notes due May 2019		500,000		-		500,000		-
Senior Notes due December 2021		800,000		-		800,000		-
Other		3,089		9,957		2,842		941
Total debt, gross		1,608,089		29,957		1,627,842		20,941
Unamortized debt issuance costs		(19,826)		-		(27,469)		-
Total debt	$	1,588,263	$	29,957	$	1,600,373	$	20,941

Schedule Of Maturities Of Long-Term Debt



2016	$	29,957
2017		306,705
2018		1,384
2019		500,000
2020		-
Thereafter		800,000
Total	$	1,638,046

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=34725769&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

+ Details

XML 55 R31.htm IDEA: XBRL DOCUMENT

Stock-Based And Long-Term Compensation (Tables)

12 Months Ended

Dec. 31, 2015

Stock-Based And Long-Term Compensation [Abstract]

Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]



Compensation Expense	Years Ended December 31,
	2015		2014		2013
Stock options	$	3,663	$	3,900	$	3,586
Restricted stock		9,219		15,800		21,460
Restricted stock units		19,699		11,282		-
Performance share units		10,733		10,688		10,014
Strategic performance share units		2,258		2,404		-
Total	$	45,572	$	44,074	$	35,060

Tax Benefit	Years Ended December 31,
	2015		2014		2013
Stock options	$	1,355	$	1,443	$	1,327
Restricted stock		3,411		5,846		7,940
Restricted stock units		7,289		4,174		-
Total	$	12,055	$	11,463	$	9,267

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



	Years Ended December 31,
	2015		2014		2013
Weighted average fair value of grants	$	6.25	$	6.95	$	8.98

Black-Scholes-Merton Assumptions:
Risk free interest rate		1.33%		1.42%		0.63%
Expected life (years)		5		4		4
Volatility		47.07%		34.50%		48.41%
Dividend yield		1.30		1.23		-

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, 2014	4,484,505	$	23.76	5.1	$	4,095
Granted	612,665	$	17.27
Exercised	(506,029)	$	17.43
Outstanding as of December 31, 2015	4,591,141	$	23.60	5.3	$	256
Exercisable as of December 31, 2015	3,488,262	$	24.48	4.3	$	256
Options expected to vest as of December 31, 2015	1,102,879	$	20.81	8.5	$	-

Summary Of Non-Vested Stock Option Activity



	Number of Options	Weighted Average Grant Date Fair Value
Non-vested as of December 31, 2014	824,488	$	7.83
Granted	612,665	$	17.27
Vested	(334,274)	$	25.01
Non-vested as of December 31, 2015	1,102,879	$	20.81

Summary Of The Status Of Restricted Stock



	Number of Shares	Weighted Average Grant Date Fair Value
Non-vested as of December 31, 2014	1,022,280	$	24.08
Vested	(678,880)	$	17.88
Forfeited	(50,463)	$	23.26
Non-vested as of December 31, 2015	292,937	$	23.13

Summary Of Restricted Stock Unit Activity



	Number of Restricted Stock Units	Weighted Average Grant Date Fair Value
Non-vested as of December 31, 2014	1,416,477	$	26.40
Granted	2,162,146	$	17.74
Vested	(460,400)	$	18.51
Forfeited	(330,334)	$	20.16
Non-vested as of December 31, 2015	2,787,889	$	20.41

Summary Of Employee Stock Purchase Plan Activity Table Text Block



	Years Ended December 31,
	2015		2014		2013
	2013 Plan		2013 Plan		2013 and 2007 Plans
Cash received for shares issued	$	4,803	$	4,870	$	4,124
Compensation expense	$	835	$	1,078	$	947
Shares issued		332,467		246,480		185,407

Summary of Deferred Compensation Balances Table Text Block



		December 31,
	Balance sheet location	2015		2014
Deferred compensation assets	Intangible and other long-term assets, net	$	11,548	$	12,982
Deferred compensation liabilities, short-term	Accounts payable	$	721	$	2,291
Deferred compensation liabilities, long-term	Other long-term liabilities	$	17,367	$	14,720

XML 56 R32.htm IDEA: XBRL DOCUMENT

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Income Taxes [Abstract]

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



	Years Ended December 31,
	2015		2014		2013
Domestic	$	(2,069,019)	$	372,672	$	165,463
Foreign		9,236		69,517		(64,706)
	$	(2,059,783)	$	442,189	$	100,757

Schedule Of Components Of Income Tax Expense (Benefit)



	Years Ended December 31,
	2015		2014		2013
Current:
Federal	$	(952)	$	150,997	$	19,897
State		2,818		11,339		10,816
Foreign		19,227		36,287		25,613
		21,093		198,623		56,326
Deferred:
Federal		(249,193)		(33,172)		(6,341)
State		(10,034)		648		386
Foreign		(13,886)		(4,700)		4,901
		(273,113)		(37,224)		(1,054)
	$	(252,020)	$	161,399	$	55,272

Schedule Of Effective Income Tax Rate Reconciliation



	Years Ended December 31,
	2015		2014		2013
Computed expected tax expense	$	(720,923)	$	154,766	$	35,265
Increase (decrease) resulting from
State and foreign income taxes		(6,353)		8,467		(852)
Reduction in value of assets		464,395		-		34,874
Other		10,861		(1,834)		(14,015)
Income tax	$	(252,020)	$	161,399	$	55,272

Schedule Of Deferred Tax Assets and Liabilities



	December 31,
	2015		2014
Deferred tax assets:
Allowance for doubtful accounts	$	8,275	$	3,942
Operating loss and tax credit carryforwards		92,798		21,928
Compensation and employee benefits		59,310		57,045
Decommissioning liabilities		30,400		21,029
Other		57,768		50,641
		248,551		154,585
Valuation allowance		(5,395)		-
Net deferred tax assets		243,156		154,585
Deferred tax liabilities:
Property, plant and equipment		469,728		648,054
Notes receivable		14,796		5,718
Goodwill and other intangible assets		119,661		138,017
Other		22,040		33,654
Deferred tax liabilities		626,225		825,443
Net deferred tax liability	$	383,069	$	670,858

Summary Of Activity In Unrecognized Tax Benefits



	Years Ended December 31,
	2015		2014		2013
Unrecognized tax benefits, December 31, 2014, 2013 and 2012, respectively	$	30,344	$	29,899	$	26,399
Additions based on tax positions related to current year		-		-		-
Additions based on tax positions related to prior years		6,752		7,860		5,065
Reductions based on tax positions related to prior years		(7,381)		(7,415)		(1,565)
Unrecognized tax benefits, December 31, 2015, 2014 and 2013, respectively	$	29,715	$	30,344	$	29,899

XML 57 R33.htm IDEA: XBRL DOCUMENT

Segment Information (Tables)

12 Months Ended

Dec. 31, 2015

Segment Information [Abstract]

Schedule Of Segment Reporting Information



2015

			Onshore
	Drilling		Completion
	Products and		and Workover		Production		Technical				Consolidated
	Services		Services		Services		Solutions		Unallocated		Total
Revenues	$	583,139	$	934,274	$	759,606	$	497,546	$	-	$	2,774,565
Cost of services and rentals
(exclusive of items shown separately below)		196,921		773,119		594,286		301,486		-		1,865,812
Depreciation, depletion, amortization and accretion		194,061		225,667		130,267		62,152		-		612,147
General and administrative expenses		127,525		121,289		139,304		122,590		-		510,708
Reduction in value of assets		40,237		783,229		790,517		124,904		-		1,738,887
Income (loss) from operations		24,395		(969,030)		(894,768)		(113,586)		-		(1,952,989)
Interest expense, net		-		-		(2,013)		1,707		(97,012)		(97,318)
Other expense		-		-		-		-		(9,476)		(9,476)
Income (loss) from continuing operations before income taxes	$	24,395	$	(969,030)	$	(896,781)	$	(111,879)	$	(106,488)	$	(2,059,783)



2014

			Onshore
	Drilling		Completion
	Products and		and Workover		Production		Technical				Consolidated
	Services		Services		Services		Solutions		Unallocated		Total
Revenues	$	904,358	$	1,732,833	$	1,350,956	$	568,475	$	-	$	4,556,622
Cost of services and rentals
(exclusive of items shown separately below)		282,023		1,205,443		941,030		306,337		-		2,734,833
Depreciation, depletion, amortization and accretion		186,642		233,430		164,672		66,070		-		650,814
General and administrative expenses		149,967		159,687		187,526		127,191		-		624,371
Income from operations		285,726		134,273		57,728		68,877		-		546,604
Interest expense, net		-		-		-		1,577		(98,311)		(96,734)
Other expense		-		-		-		-		(7,681)		(7,681)
Income (loss) from continuing operations before income taxes	$	285,726	$	134,273	$	57,728	$	70,454	$	(105,992)	$	442,189



2013

			Onshore
	Drilling		Completion
	Products and		and Workover		Production		Technical				Consolidated
	Services		Services		Services		Solutions		Unallocated		Total
Revenues	$	820,538	$	1,607,268	$	1,434,990	$	487,261	$	-	$	4,350,057
Cost of services and rentals
(exclusive of items shown separately below)		268,127		1,091,956		1,002,628		270,879		-		2,633,590
Depreciation, depletion, amortization and accretion		168,391		216,152		177,532		42,366		-		604,441
General and administrative expenses		136,244		158,448		190,647		112,439		-		597,778
Reduction in value of assets		2,292		16,975		28,568		252,243		-		300,078
Income (loss) from operations		245,484		123,737		35,615		(190,666)		-		214,170
Interest expense, net		-		-		-		1,323		(109,225)		(107,902)
Other income (expense)		-		-		-		836		(6,347)		(5,511)
Income (loss) from continuing operations before income taxes	$	245,484	$	123,737	$	35,615	$	(188,507)	$	(115,572)	$	100,757

Schedule Of Identifiable Assets



Identifiable Assets
			Onshore
	Drilling		Completion
	Products and		and Workover		Production		Technical				Consolidated
	Services		Services		Services		Solutions		Unallocated		Total
December 31, 2015	$	1,223,191	$	1,929,185	$	967,719	$	794,149	$	-	$	4,914,244
December 31, 2014	$	1,284,842	$	2,993,824	$	2,098,592	$	940,524	$	-	$	7,317,782
December 31, 2013	$	1,237,842	$	2,961,390	$	2,158,653	$	1,009,058	$	-	$	7,366,943

Schedule of Capital Expenditures Table Text Block



Capital Expenditures
			Onshore
	Drilling		Completion
	Products and		and Workover		Production		Technical		Consolidated
	Services		Services		Services		Solutions		Total
December 31, 2015	$	129,504	$	103,001	$	72,048	$	53,673	$	358,226
December 31, 2014	$	274,752	$	152,742	$	88,870	$	99,738	$	616,102
December 31, 2013	$	246,479	$	101,854	$	122,946	$	137,681	$	608,960

Schedule Of Revenues By Geographic Segment



Revenues
	Years Ended December 31,
	2015		2014		2013
United States	$	2,185,071	$	3,848,929	$	3,674,825
Other Countries		589,494		707,693		675,232
Total	$	2,774,565	$	4,556,622	$	4,350,057

Long-Lived Assets
			December 31,
			2015		2014
United States			$	1,799,418	$	2,416,306
Other Countries				323,873		317,533
Total, net			$	2,123,291	$	2,733,839

XML 58 R34.htm IDEA: XBRL DOCUMENT

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2015

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, 2015		Level 1		Level 2		Level 3
Intangible and other long-term assets, net
Non-qualified deferred compensation assets	$	11,548	$	368	$	11,180		-
Interest rate swaps	$	6,905		-	$	6,905		-
Accounts payable
Non-qualified deferred compensation liabilities	$	721		-	$	721		-
Other long-term liabilities
Non-qualified deferred compensation liabilities	$	17,367		-	$	17,367		-

	December 31, 2014		Level 1		Level 2		Level 3
Intangible and other long-term assets, net
Non-qualified deferred compensation assets	$	12,982	$	1,481	$	11,501		-
Interest rate swaps	$	4,183		-	$	4,183		-
Accounts payable
Non-qualified deferred compensation liabilities	$	2,291		-	$	2,291		-
Other long-term liabilities
Non-qualified deferred compensation liabilities	$	14,720		-	$	14,720		-

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



	Years Ended December 31,
	2015				2013
	Impairment		Fair Value		Impairment		Fair Value
Property, plant and equipment, net	$	177,442	$	179,612	$	243,781	$	328,876
Goodwill	$	1,326,701	$	998,288	$	91,016	$	-
Intangible assets	$	68,890	$	6,345	$	18,296	$	4,355

XML 59 R35.htm IDEA: XBRL DOCUMENT

Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Financial Instruments [Abstract]

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




		Years Ended December 31,
Effect of derivative instrument	Location of (gain) loss recognized	2015		2014		2013
Interest rate swap	Interest expense, net	$	(1,932)	$	(11,054)	$	13,079
Hedged item - debt	Interest expense, net		(790)		7,208		(12,303)
		$	(2,722)	$	(3,846)	$	776

XML 60 R36.htm IDEA: XBRL DOCUMENT

Interim Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

Interim Financial Information (Unaudited) [Abstract]

Schedule Of Interim Financial Information



	2015
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Revenues	$	917,235	$	710,784	$	601,396	$	545,150
Less:
Cost of services and rentals		582,246		465,533		420,485		397,548
Depreciation, depletion, amortization and accretion		162,220		158,352		146,757		144,818
Gross profit		172,769		86,899		34,154		2,784
Reduction in value of assets		-		807,637		755,632		175,618
Net loss from continuing operations		(1,497)		(775,132)		(816,587)		(214,547)
Loss from discontinued operations, net of tax		(9,640)		(9,857)		(4,610)		(22,848)
Net loss		(11,137)		(784,989)		(821,197)		(237,395)
Loss per share from continuing operations:
Basic and diluted	$	(0.02)	$	(5.15)	$	(5.42)	$	(1.43)
Loss per share from discontinued operations:
Basic and diluted	$	(0.06)	$	(0.07)	$	(0.03)	$	(0.15)

	2014
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Revenues	$	1,061,418	$	1,107,552	$	1,209,026	$	1,178,626
Less:
Cost of services and rentals		651,605		650,293		721,692		711,243
Depreciation, depletion, amortization and accretion		162,318		160,965		170,154		157,377
Gross profit		247,495		296,294		317,180		310,006
Net income from continuing operations		42,626		79,057		85,743		73,364
Loss from discontinued operations, net of tax		(5,954)		(3,895)		(5,886)		(7,238)
Net income		36,672		75,162		79,857		66,126
Earnings per share from continuing operations:
Basic	$	0.27	$	0.51	$	0.55	$	0.49
Diluted		0.27		0.50		0.55		0.48
Loss per share from discontinued operations:
Basic and diluted	$	(0.04)	$	(0.03)	$	(0.03)	$	(0.05)

XML 61 R37.htm IDEA: XBRL DOCUMENT

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

12 Months Ended

Dec. 31, 2015

Supplementary Oil And Natural Gas Disclosures [Abstract]

Schedule Of Proved Developed And Undeveloped Oil And Gas Reserves



	Crude Oil	Natural Gas
	(Mbbls)	(Mmcf)
Proved-developed and undeveloped reserves:
December 31, 2012	8,207	11,284
Revisions	(3,203)	(4,036)
Production	(411)	(296)
December 31, 2013	4,593	6,952
Revisions	(438)	1,431
Production	(738)	(1,247)
December 31, 2014	3,417	7,136
Revisions	(381)	(245)
Production	(633)	(1,517)
December 31, 2015	2,403	5,374

Proved-developed reserves:
December 31, 2013	2,397	2,100
December 31, 2014	3,184	6,945
December 31, 2015	2,202	5,216
Proved-undeveloped reserves:
December 31, 2013	2,196	4,852
December 31, 2014	233	191
December 31, 2015	201	158

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



	Years Ended December 31,
	2015		2014		2013
Acquisition of properties - proved	$	-	$	-	$	-
Acquisition of properties - unproved		-		-		-
Exploratory costs		-		-		-
Development costs		20,636		52,719		51,527
Total costs incurred	$	20,636	$	52,719	$	51,527

Capitalized Costs Relating To Oil And Gas Producing Activities



	December 31,
	2015		2014
Proved oil and gas properties	$	66,285	$	189,294
Accumulated depreciation, depletion and amortization		-		(55,864)
Capitalized costs, net	$	66,285	$	133,430

Schedule Of Ownership In Productive Oil And Natural Gas Wells



	Productive Wells
	Gross	Net
Oil	11.00	5.61

Schedule Of Gas And Oil Acreage



	Gross	Net
	Acreage	Acreage
Developed	23,040	11,750
Undeveloped	-	-
Total	23,040	11,750

Schedule Of Drilling Activity



	Years Ended December 31,
	2015		2014
	Gross	Net	Gross	Net
Exploratory Wells
Productive	-	-	-	-
Non-productive	-	-	-	-
Total	-	-	-	-

Development Wells
Productive	1.00	0.51	2.00	1.02
Non-productive	1.00	0.51	1.00	0.51
Total	2.00	1.02	3.00	1.53

Results Of Operations For Oil And Gas Producing Activities



	Years Ended December 31,
	2015		2014		2013
Revenues
Sales	$	30,245	$	77,845	$	47,050
Production costs		15,466		13,529		9,876
Exploration expenses		-		-		-
Depreciation, depletion and amortization		37,623		38,768		12,032
Reduction in value of assets		56,000		-		-
		(78,844)		25,548		25,142
Income tax expenses		(28,778)		9,325		8,800
Results of operations from producing activities (excluding corporate overhead)	$	(50,066)	$	16,223	$	16,342

Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves



	Years Ended December 31,
	2015		2014		2013
Future cash inflows	$	127,048	$	336,944	$	496,704
Future production costs		(43,010)		(71,209)		(82,487)
Future development and abandonment costs		(84,090)		(111,374)		(156,340)
Future income tax expenses		1,353		(60,345)		(89,507)
Future net cash flows		1,301		94,016		168,370
10% annual discount for estimated timing of cash flows		(19,762)		(17,034)		10,641
Standardized measure of discounted future net cash flows	$	21,063	$	111,050	$	157,729

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


	Years Ended December 31,
	2015		2014		2013
Beginning of the period	$	111,050	$	157,729	$	303,430
Net change in sales and transfer prices and in production (lifting) costs related to future production		(143,808)		(57,568)		(13,278)
Changes in estimated future development costs		3,787		(5,512)		(48,594)
Sales and transfers of oil and gas produced during the period		(14,779)		(64,316)		(45,866)
Net change due to extensions, discoveries, and improved recovery		6,737		-		75,304
Net changes due to revisions in quantity estimates		(36,397)		(8,396)		(228,620)
Previously estimated development costs incurred during the period		20,636		40,962		10,136
Accretion of discount		17,606		24,251		46,711
Other-unspecified		1,895		4,125		(24,169)
Net change in income taxes		54,336		19,775		82,675
Aggregate change in the standardized measure of discounted future net cash flows for the year		(89,987)		(46,679)		(145,701)
End of the period	$	21,063	$	111,050	$	157,729

XML 62 R38.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Major Customers And Concentration Of Credit Risk) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Summary Of Significant Accounting Policies [Abstract]
Maximum percentage of revenue for a single major customer	10.00%	10.00%

XML 63 R39.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Cash Equivalents) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015
Summary Of Significant Accounting Policies [Abstract]
Maximum maturity of short-term investments purchased to be cash equivalents	90 days

XML 64 R40.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Inventory) (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Inventory	$ 148,761	$ 165,562
Finished goods	71,951	72,788
Raw materials	23,418	29,718
Work-in-progress	18,203	20,317
Supplies and consumables	$ 35,189	$ 42,739

XML 65 R41.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Estimated Useful Lives Of The Related Assets) (Details)	12 Months Ended
	Dec. 31, 2015
Building and Building Improvements [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, useful life	5 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	25 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	10 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 66 R42.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Goodwill) (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2013	Dec. 31, 2014
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, Impaired, Accumulated Impairment Loss	$ 1,417,700		$ 91,000
Reduction in value of goodwill	$ 1,326,701	$ 91,016

XML 67 R43.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Summary Of Activity Of Goodwill) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Goodwill [Roll Forward]
Beginning Balance	$ 2,468,409	$ 2,458,109
Acquisition activities	1,170	13,909
Reduction in value of assets	(1,326,701)		$ (91,016)
Foreign currency translation adjustments	(2,777)	(3,609)
Ending Balance	1,140,101	2,468,409	2,458,109
Drilling Products And Services [Member]
Goodwill [Roll Forward]
Beginning Balance	142,839	144,872
Foreign currency translation adjustments	(1,557)	(2,033)
Ending Balance	141,282	142,839	144,872
Onshore Completion Services [Member]
Goodwill [Roll Forward]
Beginning Balance	1,419,550	1,419,550
Reduction in value of assets	(740,000)
Additional consideration paid for prior acquisitions	44,000
Ending Balance	723,550	1,419,550	1,419,550
Goodwill, Other Changes	44,000
Production Services [Member]
Goodwill [Roll Forward]
Beginning Balance	906,020	893,687
Acquisition activities	1,170	13,909
Reduction in value of assets	(586,701)
Additional consideration paid for prior acquisitions	(44,000)
Foreign currency translation adjustments	(1,220)	(1,576)
Ending Balance	275,269	$ 906,020	$ 893,687
Goodwill, Other Changes	$ (44,000)

XML 68 R44.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Notes Receivable) (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Notes Receivable [Abstract]
Amount of notes receivable net	$ 115.0
Interest rate percentage to record present value of notes receivable	6.58%
AccelerationOfPlatformDecommissioningDate	10 years
Company recorded interest income	$ 1.7	$ 1.6	$ 2.6

XML 69 R45.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Intangible And Other Long-Term Assets) (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Escrow Deposit Required by Seller of Oil and Gas Properties	$ 58,400			$ 58,400
Reduction in value of assets	175,618	$ 755,632	$ 807,637	1,738,887		$ 300,078
Amortization expense exclusive of debt acquisition costs				23,000	$ 25,900	$ 26,200
Amortization of intangible assets exclusive of debt acquisitions costs for 2015	19,200			19,200
Amortization of intangible assets exclusive of debt acquisitions costs for 2016	18,600			18,600
Amortization of intangible assets exclusive of debt acquisitions costs for 2017	18,500			18,500
Amortization of intangible assets exclusive of debt acquisitions costs for 2018	18,300			18,300
Amortization of intangible assets exclusive of debt acquisitions costs for 2019	$ 18,000			$ 18,000
Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				17 years
Trade Names [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				10 years
Noncompete Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				3 years
Unsecured Senior Notes Due 2021 [Member]
Finite-Lived Intangible Assets [Line Items]
Stated interest rate on unsecured senior notes	7.125%			7.125%

XML 70 R46.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Composition Of Intangible And Other Long-term Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Schedule of Intangible Assets by Major Class [Line Items]
Finite-Lived Intangible Assets, Net, Total	$ 213,205	$ 304,061
Acquired Finite-lived Intangible Asset, Amount	296,725	385,447
Finite-Lived Intangible Assets, Accumulated Amortization	(83,520)	(81,386)
Customer Relationships [Member]
Schedule of Intangible Assets by Major Class [Line Items]
Finite-Lived Intangible Assets, Net, Total	192,155	274,741
Acquired Finite-lived Intangible Asset, Amount	257,364	339,695
Finite-Lived Intangible Assets, Accumulated Amortization	(65,209)	(64,954)
Trade Names [Member]
Schedule of Intangible Assets by Major Class [Line Items]
Finite-Lived Intangible Assets, Net, Total	20,748	28,114
Acquired Finite-lived Intangible Asset, Amount	36,119	41,265
Finite-Lived Intangible Assets, Accumulated Amortization	(15,371)	(13,151)
Noncompete Agreements [Member]
Schedule of Intangible Assets by Major Class [Line Items]
Finite-Lived Intangible Assets, Net, Total	302	1,206
Acquired Finite-lived Intangible Asset, Amount	3,242	4,487
Finite-Lived Intangible Assets, Accumulated Amortization	$ (2,940)	$ (3,281)

XML 71 R47.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Decommissioning Liabilities) (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Asset Retirement Obligation, Liabilities Incurred	$ 266	$ 866

XML 72 R48.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Summary Of The Activity For Company's Decommissioning Liabilities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Decommissioning liabilities, December 31, 2014 and 2013, respectively	$ 88,000	$ 83,519
Liabilities acquired and incurred	266	866
Liabilities settled		(579)
Accretion	5,016	4,470
Revision in estimated liabilities	24,660	(276)
Total decommissioning liabilities, December 31, 2015 and 2014, respectively	$ 88,000	$ 83,519	$ 117,942	$ 88,000
Less: current portion of decommissioning liabilities as of December 31, 2015 and 2014, respectively			19,052
Long-term decommissioning liabilities, December 31, 2015 and 2014, respectively			$ 98,890	$ 88,000

XML 73 R49.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Earnings (Loss) Per Share) (Narrative) (Details)	24 Months Ended
	Dec. 31, 2014 shares
Summary Of Significant Accounting Policies [Abstract]
Antidilutive securities excluded from computation of earnings per share, share	1,100,000

XML 74 R50.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Financial Instruments) (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Fair value of debt	$ 1,508.0	$ 1,624.3

XML 75 R51.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Foreign Currency) (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary Of Significant Accounting Policies [Abstract]
Foreign currency gains	$ (9.6)	$ 7.3	$ 7.1

XML 76 R52.htm IDEA: XBRL DOCUMENT

Summary Of Significant Accounting Policies (Derivative Instruments And Hedging Activities) (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Percentage of fixed rate debt	62.00%	61.00%
Notional amount of interest rate swap	$ 300,000,000
Variable interest rate, Adjustment	90 days

XML 77 R53.htm IDEA: XBRL DOCUMENT

Summary of Significant Accounting Policies (Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Accumulated other comprehensive loss, net	$ (45,694)	$ (36,280)

- Definition

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

+ References + Details

XML 78 R54.htm IDEA: XBRL DOCUMENT

Summary of Significant Accounting Policies (Cash Dividends) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary Of Significant Accounting Policies [Abstract]
Cash dividends declared per share	$ 0.32	$ 0.24	$ 0.08

XML 79 R55.htm IDEA: XBRL DOCUMENT

Summary of Significant Accounting Policies (Recently Adopted Accounting Guidance) (Details) $ in Millions	Dec. 31, 2015 USD ($)
Summary Of Significant Accounting Policies [Abstract]
Change in deferred tax balance due to reclassification	$ 32.1

XML 80 R56.htm IDEA: XBRL DOCUMENT

Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]
Cash paid for interest	$ 93,946	$ 102,880	$ 97,129
Cash paid for income taxes	40,074	127,132	164,158
Details of business acquisitions:
Fair Value of Assets Acquired		29,468	34,964
Fair value of liabilities		(5,125)	(10,942)
Cash paid		24,343	24,022
Less cash acquired		(16)	(225)
Net cash paid for acquisitions		24,327	23,797
Non-cash investing activity:
Capital Expenditures Incurred but Not yet Paid	$ 28,704	$ 49,118	70,463
Non-cash financing activity:
Dividends, Share-based Compensation, Cash			$ 12,759

XML 81 R57.htm IDEA: XBRL DOCUMENT

Reduction in Value of Assets (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Impairment Charges [Line Items]
Revenue Derived from Venezuela					$ 9,500
Reduction in Value of Assets Related to Exit of Venezuela Activities						$ 14,324
Retirments of Long-Lived Assets				$ 42,545		14,418
Reduction in Value of Long-Lived Assets				330,194		180,320
Reduction in value of goodwill				1,326,701		91,016
Reduction in value of assets	$ 175,618	$ 755,632	$ 807,637	1,738,887		300,078
Impairment of Intangible Assets, Finite-lived				68,900
Impairment of Long-Lived Assets Held-for-use				343,300
Allowance for Notes Receivables	16,800			16,800
Restructuring Charges				46,800
Impairment of operating leases				20,200
Restructuring Reserve, Current	7,200			7,200
Restructuring Reserve, Noncurrent	$ 11,100			11,100
Drilling Products And Services [Member]
Asset Impairment Charges [Line Items]
Reduction in value of assets				40,237		2,292
Impairment of Long-Lived Assets Held-for-use				40,200
Technical Solutions [Member]
Asset Impairment Charges [Line Items]
Reduction in value of other assets					31,900
Retirments of Long-Lived Assets					6,400
Reduction in value of assets				124,904		252,243
Impairment of Intangible Assets, Finite-lived					3,000
Impairment of Long-Lived Assets Held-for-use				68,900	122,800
Production Services [Member]
Asset Impairment Charges [Line Items]
Retirments of Long-Lived Assets				15,200	2,200
Reduction in value of goodwill				586,701
Reduction in value of assets				790,517		28,568
Impairment of Intangible Assets, Finite-lived				59,500
Impairment of Long-Lived Assets Held-for-use				89,700	11,400
Onshore Completion Services [Member]
Asset Impairment Charges [Line Items]
Retirments of Long-Lived Assets				27,300	5,800
Reduction in value of goodwill				740,000
Reduction in value of assets				783,229		$ 16,975
Impairment of Long-Lived Assets Held-for-use				$ 15,900	$ 11,200

XML 82 R58.htm IDEA: XBRL DOCUMENT

Reduction in Value of Assets (Components of the Expense) (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2013
Reduction In Value Of Assets [Abstract]
Reduction in value of assets	$ 175,618	$ 755,632	$ 807,637	$ 1,738,887	$ 300,078
Reduction in Value of Assets Related to Exit of Venezuela Activities					14,324
Reduction in Value of Long-Lived Assets				330,194	180,320
Reduction in value of goodwill				1,326,701	91,016
Retirments of Long-Lived Assets				42,545	$ 14,418
Reduction in value of assets related to sale of a business				$ 39,447

XML 83 R59.htm IDEA: XBRL DOCUMENT

Discontinued Operations (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment Included in Discontinued Operations			$ 119,300
Long-term assets	$ 92,634	$ 91,940
Subsea Construction Marine Vessels Member
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment Included in Discontinued Operations	25,800		98,300
Gain on sale of assets, disposal group accounted for as discontinued operations		$ 18,800
Subsea Construction Intangible Assets Member
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment Included in Discontinued Operations			15,400
Conventional Decommissioning Long-lived Assets Member
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment Included in Discontinued Operations	$ 8,800		$ 5,600

XML 84 R60.htm IDEA: XBRL DOCUMENT

Discontinued Operations (Components Of Income (Loss) From Discontinued Operations) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Discontinued Operations [Abstract]
Revenues									$ 18,723	$ 145,463	$ 261,767
Income tax expense (benefit)									(5,626)	(19,330)	(15,439)
Income (Loss) from Discontinued Operations, Net of Tax (benefit) expense	$ (22,848)	$ (4,610)	$ (9,857)	$ (9,640)	$ (7,238)	$ (5,886)	$ (3,895)	$ (5,954)	$ (46,955)	$ (22,973)	$ (156,903)

- Definition

Amount of tax expense (benefit) related to a discontinued operation. Includes, but is not limited to, tax expense (benefit) related to income (loss) from operations during the phase-out period, tax expense (benefit) related to gain (loss) on disposal, tax expense (benefit) related to gain (loss) for reversal of write-down (write-down) to fair value, less cost to sell, and tax expense (benefit) related to adjustments of a prior period gain (loss) on disposal.

+ References + Details

- Definition

Amount after tax of income (loss) from a discontinued operation including the portion attributable to the noncontrolling interest. Includes, but is not limited to, the income (loss) from operations during the phase-out period, gain (loss) on disposal, gain (loss) for reversal of write-down (write-down) to fair value, less cost to sell, and adjustments to a prior period gain (loss) on disposal.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 225
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04.12)
-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5C
-Subparagraph (b)(2)
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721675-107760

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 225
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03.14)
-URI http://asc.fasb.org/extlink&oid=26872669&loc=d3e20235-122688

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 45
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=51716988&loc=d3e1012-107759

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 45
-Paragraph 3B
-URI http://asc.fasb.org/extlink&oid=51716988&loc=SL51721525-107759

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 45
-Paragraph 3A
-URI http://asc.fasb.org/extlink&oid=51716988&loc=SL51721523-107759

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 45
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=51716988&loc=d3e957-107759

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=51717284&loc=d3e1361-107760

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph 13
-Article 7

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 03
-Paragraph 15
-Article 5

+ Details

XML 85 R61.htm IDEA: XBRL DOCUMENT

Discontinued Operations (Assets And Liabilities of Disposal Groups) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Disposal Group, Including Discontinued Operation, Classified Balance Sheet Disclosures [Abstract]
Accounts receivable, net	$ 1,234	$ 16,701
Prepaid expenses	330	2,463
Disposal group inventory and other current assets	1,036	5,576
Assets of Disposal Group, Including Discontinued Operation, Current	2,600	24,740
Disposal group property, plant and equipment, net	92,634	91,171
Intangible and other long-term assets, net		769
Long-term assets	92,634	91,940
Accounts payable	1,007	20,530
Accrued expenses	3,654	24,496
Current liabilities	$ 4,661	45,026
Other long-term liabilities		$ 16,814

XML 86 R62.htm IDEA: XBRL DOCUMENT

Property, Plant and Equipment alt (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant And Equipment [Abstract]
Impairment of long lived assets	$ 343.3
Leasehold Improvements, Gross	84.9	$ 93.3
Depreciation	$ 584.1	$ 620.6	$ 572.9

XML 87 R63.htm IDEA: XBRL DOCUMENT

Property, Plant and Equipment (Summary Of Property, Plant And Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 4,402,147	$ 5,003,381
Accumulated depreciation and depletion	(2,278,856)	(2,269,542)
Property, plant and equipment, net	2,123,291	2,733,839
Buildings, Improvements And Leasehold Improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	318,906	328,651
Marine Vessels And Equipment [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	87	55,494
Machinery And Equipment [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	3,770,959	4,126,570
Automobiles, trucks, tractors and trailers [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	45,013	66,032
Furniture And Fixtures [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	67,483	75,631
Construction in Progress [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	74,683	102,895
Land [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	58,731	58,814
Oil and Gas Properties [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 66,285	$ 189,294

XML 88 R64.htm IDEA: XBRL DOCUMENT

Debt (Narrative) (Details) $ in Millions	12 Months Ended
Debt (Narrative) (Details) $ in Millions	Dec. 31, 2015 USD ($)
Debt Instrument [Line Items]
Term Loan A, Amount Outstanding	$ 325.0
Revolving portion of credit facility, borrowing capacity	600.0
Revolving portion of credit facility, amount outstanding	325.0
Line of Credit Facility, Current Borrowing Capacity	470.3
Letters of Credit Outstanding, Amount	42.2
Unsecured Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 500.0
Stated interest rate on unsecured senior notes	6.375%
Unsecured Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 800.0
Stated interest rate on unsecured senior notes	7.125%

XML 89 R65.htm IDEA: XBRL DOCUMENT

Debt (Summary Of Long-Term Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Current	$ 29,957	$ 20,941
Long-term debt, gross	1,608,089	1,627,842
Long-term Debt, Excluding Current Maturities, Total	1,588,263	1,600,373
Accumulated Amortization, Deferred Finance Costs	(19,826)	(27,469)
Other long term debt instrument [member]
Debt Instrument [Line Items]
Current	9,957	941
Long-term debt, gross	3,089	2,842
Term Loan, Interest Payable Monthly At Floating Rate And Principal Payable Quarterly, Due December 2017 [Member]
Debt Instrument [Line Items]
Current	20,000	20,000
Long-term debt, gross	305,000	325,000
Senior Notes, Interest Payable Semiannually At 6 3/8%, Due May 2019 [Member]
Debt Instrument [Line Items]
Long-term debt, gross	500,000	500,000
Senior Notes, Interest Payable Semiannually At 7 1/8%, Due December 2021 [Member]
Debt Instrument [Line Items]
Long-term debt, gross	$ 800,000	$ 800,000

XML 90 R66.htm IDEA: XBRL DOCUMENT

Debt (Schedule Of Maturities Of Long-Term Debt) (Details) $ in Thousands	Dec. 31, 2015 USD ($)
Debt [Abstract]
2016	$ 29,957
2017	306,705
2018	1,384
2019	500,000
Thereafter	800,000
Total	$ 1,638,046

XML 91 R67.htm IDEA: XBRL DOCUMENT

Stock-Based And Long-Term Compensation (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jul. 01, 2013
Stock Based and Long-Term Compensation (Textual) [Abstract]
Common Stock Reserved for Issuance, Shares Remaining	8,700,000
Compensation expense	$ 45,572	$ 44,074	$ 35,060
Tax benefit from exercising stock options	900	$ 5,600	$ 700
Compensation expense expected to recognize in 2015	19,300
Compensation expense expected to recognize in 2016	10,300
Compensation expense expected to recognize in 2017	$ 400
Shares issued under Employee Stock Purchase Plan, shares	332,467	246,480	185,407
Proceed from issue of shares under employee stock purchase plans	$ 4,803	$ 4,870	$ 4,124
Common stock reserved for issuance	14,850,000	8,000,000
Long-term liability	$ 17,367	$ 14,720
Current liability	721	2,291
Deferred compensation, compensation expense	2,100	1,600	1,200
Deferred compensation plan assets	11,548	12,982
Other income (expense)	$ (9,476)	(7,681)	(5,511)
Employee Stock Option [Member]
Stock Based and Long-Term Compensation (Textual) [Abstract]
Share-based payment vesting period, years	3 years
Share-based payment expiration period, years	10 years
Compensation expense	$ 3,663	3,900	3,586
Intrinsic value of options exercised	2,300	17,100	5,100
Cash received from exercising options	8,800	10,600	6,300
Unrecognized compensation expense related to non-vested options oustanding	3,900
Compensation expense expected to recognize in 2015	2,600
Compensation expense expected to recognize in 2016	$ 1,300
Restricted Stock [Member]
Stock Based and Long-Term Compensation (Textual) [Abstract]
Share-based payment vesting period, years	3 years
Compensation expense	$ 9,219	$ 15,800	21,460
Unrecognized compensation expense related to non-vested options oustanding	$ 400
Shares outstanding	292,937	1,022,280
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 17.88
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 23.13	$ 24.08
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 12,100	$ 23,000	9,600
Restricted Stock Units (RSUs) [Member]
Stock Based and Long-Term Compensation (Textual) [Abstract]
Compensation expense	19,699	$ 11,282
Unrecognized compensation expense related to non-vested options oustanding	$ 30,000
Resticted stock granted	2,162,146
Shares outstanding	2,787,889	1,416,477
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 18.51
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 20.41	$ 26.40
Performance Shares [Member]
Stock Based and Long-Term Compensation (Textual) [Abstract]
Compensation expense	$ 10,733	$ 10,688	10,014
Shares outstanding	370,822
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%
Performance Share Units Outstanding, in 2014	112,922
Performance Share Units Outstanding, in 2015	123,079
Performance Share Units Outstanding, in 2016	134,821
Strategic Performance Shares [Member]
Stock Based and Long-Term Compensation (Textual) [Abstract]
Compensation expense	$ 2,258	2,404
2013 Employee Stock Purchase Plan Member
Stock Based and Long-Term Compensation (Textual) [Abstract]
Compensation expense	$ 835	1,078	947
Common stock reserved for issuance				3,000,000
Supplemental Executive Retirement Plan [Member]
Stock Based and Long-Term Compensation (Textual) [Abstract]
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
Distribution to select participants	$ 3,700	3,000	3,000
Other Pension Plan [Member]
Stock Based and Long-Term Compensation (Textual) [Abstract]
Maximum employee contribution to be matched by employer	4.00%
Maximum empoyee contribution	75.00%
Company contribution, percent	100.00%
Company discretionary contributions	$ 13,900	$ 16,700	$ 16,000
Non-Qualified Deferred Compensation Plans [Member]
Stock Based and Long-Term Compensation (Textual) [Abstract]
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%

XML 92 R68.htm IDEA: XBRL DOCUMENT

Stock-Based And Long-Term Compensation (Summary Of The Valuation Assumptions Used To Calculate The Fair Value Of Stock Option Grants) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted average fair value of grants	$ 6.25	$ 6.95	$ 8.98
Black-Scholes-Merton Assumptions:
Risk free interest rate	1.33%	1.42%	0.63%
Expected life (years)	5 years	4 years	4 years
Volatility	47.07%	34.50%	48.41%
Dividend yield	1.30%	1.23%

XML 93 R69.htm IDEA: XBRL DOCUMENT

Stock-Based And Long-Term Compensation (Summary Of Stock Option Activity) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Summarization of stock option activity
Number of options outstanding, beginning	4,484,505
Number of options granted	612,665
Number of options exercised	(506,029)
Number of options outstanding, ending	4,591,141	4,484,505
Number of options exercisable	3,488,262
Number of options expected to vest	1,102,879
Weighted average option price outstanding, beginning	$ 23.76
Weighted average option price granted	17.27
Weighted average option price excercised	17.43
Weighted average option price outstanding, ending	23.60	$ 23.76
Weighted average option price exercisable		$ 24.48
Weighted average option price expected to vest	$ 20.81
Weighted average remaining contractual term, outstanding	5 years 3 months 18 days	5 years 1 month 6 days
Weighted average remaining contractual term, exercisable	4 years 3 months 18 days
Weighted average remaining contractual term, expected to vest	8 years 6 months
Aggregate intrinsic value, outstanding	$ 256	$ 4,095
Aggregate intrinsic value, exercisable	$ 256

XML 94 R70.htm IDEA: XBRL DOCUMENT

Stock-Based And Long-Term Compensation (Summary Of Non-Vested Stock Option Activity) (Details)	12 Months Ended
	Dec. 31, 2015 $ / shares shares
Summarizes Non-vested Stock Option [Abstract]
Number of Option, Beginning Balance \| shares	824,488
Number of Option, Granted \| shares	612,665
Number of Option, Vested \| shares	(334,274)
Number of Option, Ending Balance \| shares	1,102,879
Weighted Average Grant Date Fair Value, Beginning Balance \| $ / shares	$ 7.83
Weighted Average Grant Date Fair Value, Granted \| $ / shares	17.27
Weighted Average Grant Date Fair Value, Vested \| $ / shares	25.01
Weighted Average Grant Date Fair Value, Ending Balance \| $ / shares	$ 20.81

XML 95 R71.htm IDEA: XBRL DOCUMENT

Stock-Based And Long-Term Compensation (Summary Of The Status Of Restricted Stock) (Details) - Restricted Stock [Member] - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Summary of restricted stock
Beginning balance	1,022,280
Shares, vested	(678,880)
Shares, fofeited	(50,463)
Ending balance	292,937	1,022,280
Weighted average grant date fair value, beginning balance	$ 24.08
Weighted average grant date fair value, granted		$ 23.14
Weighted average grant date fair value, vested	17.88
Weighted average grant date fair value, forfeited	23.26
Weighted average grant date fair value, ending balance	$ 23.13	$ 24.08

XML 96 R72.htm IDEA: XBRL DOCUMENT

Stock-Based And Long-Term Compensation (Summary Of The Activity Of Restricted Stock Units) (Details) - Restricted Stock Units (RSUs) [Member]	12 Months Ended
	Dec. 31, 2015 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Beginning balance \| shares	1,416,477
Granted \| shares	2,162,146
Shares, vested \| shares	(460,400)
Shares, fofeited \| shares	(330,334)
Ending balance \| shares	2,787,889
Weighted average grant date fair value, beginning balance \| $ / shares	$ 26.40
Weighted average grant date fair value, granted \| $ / shares	17.74
Weighted average grant date fair value, vested \| $ / shares	18.51
Weighted average grant date fair value, forfeited \| $ / shares	20.16
Weighted average grant date fair value, ending balance \| $ / shares	$ 20.41

XML 97 R73.htm IDEA: XBRL DOCUMENT

Stock-Based And Long-Term Compensation (Summary Of Compensation Expense and Tax Benefits) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Compensation expense	$ 45,572	$ 44,074	$ 35,060
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	12,055	11,463	9,267
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Compensation expense	3,663	3,900	3,586
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	1,355	1,443	1,327
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Compensation expense	9,219	15,800	21,460
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	3,411	5,846	7,940
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Compensation expense	19,699	11,282
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	7,289	4,174
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Compensation expense	10,733	10,688	10,014
2013 Employee Stock Purchase Plan Member
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Compensation expense	$ 835	$ 1,078	$ 947

XML 98 R74.htm IDEA: XBRL DOCUMENT

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	36 Months Ended
Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Abstract]
U.S. Federal income tax rate	35.00%
net operating loss carryforwards	$ 102,100
Annual limitation on utilization of net operating loss carryforwards	500
Deferred tax assets, various state	25,200
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	31,800
Undistributed earnings of foreign subsidiaries	52,000
Unrecorded tax benefits	$ 29,715	$ 30,344	$ 29,899	$ 26,399

XML 99 R75.htm IDEA: XBRL DOCUMENT

Income Taxes (Schedule Of Components Of Income And Loss From Continuing Operations Before Income Taxes) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest [Abstract]
Domestic	$ (2,069,019)	$ 372,672	$ 165,463
Foreign	9,236	69,517	(64,706)
Income from continuing operations before income taxes	$ (2,059,783)	$ 442,189	$ 100,757

XML 100 R76.htm IDEA: XBRL DOCUMENT

Income Taxes (Schedule Of Components Of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current, federal	$ (952)	$ 150,997	$ 19,897
Current, state	2,818	11,339	10,816
Current, foreign	19,227	36,287	25,613
Current, total	21,093	198,623	56,326
Deferred, federal	(249,193)	(33,172)	(6,341)
Deferred, state	(10,034)	648	386
Deferred, foreign	(13,886)	(4,700)	4,901
Deferred income taxes	(273,113)	(37,224)	(1,054)
Income Tax Expense (Benefit), Total	$ (252,020)	$ 161,399	$ 55,272

XML 101 R77.htm IDEA: XBRL DOCUMENT

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Computed expected tax expense (benefit)	$ (720,923)	$ 154,766	$ 35,265
Increase (decrease) resulting from State and foreign income taxes	(6,353)	8,467	(852)
Increase (decrease) resulting other	10,861	(1,834)	(14,015)
Income Tax Expense (Benefit), Total	(252,020)	$ 161,399	55,272
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount	$ 464,395		$ 34,874

XML 102 R78.htm IDEA: XBRL DOCUMENT

Income Taxes (Schedule Of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Components of Deferred Tax Assets [Abstract]
Allowance for doubtful accounts	$ 8,275	$ 3,942
Operating loss and tax credit carryforwards	92,798	21,928
Compensation and employee benefits	59,310	57,045
Decommissioning liabilities	30,400	21,029
Other	57,768	50,641
Deferred tax assets, gross	248,551	154,585
Valuation allowance	(5,395)
Net deferred tax assets	243,156	154,585
Components of Deferred Tax Liabilities [Abstract]
Property, plant and equipment	469,728	648,054
Notes receivable	14,796	5,718
Goodwill and other intangible assets	119,661	138,017
Other	22,040	33,654
Deferred tax liabilities	626,225	825,443
Net deferred tax liability	$ (383,069)	$ (670,858)

XML 103 R79.htm IDEA: XBRL DOCUMENT

Income Taxes (Net Deferred Tax Liabilities Classified In The Consolidated Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred Tax Liabilities, Net, Classification [Abstract]
Noncurrent deferred income taxes	$ (383,069)	$ (670,858)
Net deferred tax liability	$ (383,069)	$ (670,858)

XML 104 R80.htm IDEA: XBRL DOCUMENT

Income Taxes (Summary Of Activity In Unrecognized Tax Benefits) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits, December 31, 2014, 2013 and 2012, respectively	$ 30,344	$ 29,899	$ 26,399
Additions based on tax positions related to prior years	6,752	7,860	5,065
Reductions based on tax positions related to prior years	(7,381)	(7,415)	(1,565)
Unrecognized tax benefits, December 31, 2015, 2014 and 2013, respectively	$ 29,715	$ 30,344	$ 29,899

XML 105 R81.htm IDEA: XBRL DOCUMENT

Segment Information (Schedule Of Segment Reporting Information) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Revenues	$ 545,150	$ 601,396	$ 710,784	$ 917,235	$ 1,178,626	$ 1,209,026	$ 1,107,552	$ 1,061,418	$ 2,774,565	$ 4,556,622	$ 4,350,057
Cost of goods and services	397,548	420,485	465,533	582,246	711,243	721,692	650,293	651,605	1,865,812	2,734,833	2,633,590
Depreciation, depletion, amortization and accretion	144,818	146,757	158,352	$ 162,220	157,377	$ 170,154	$ 160,965	$ 162,318	612,147	650,814	604,441
General and administrative expenses									510,708	624,371	597,778
Reduction in the value of assets	175,618	$ 755,632	$ 807,637						1,738,887		300,078
Income from operations									(1,952,989)	546,604	214,170
Interest expense, net									97,318	96,734	107,902
Other Expense									(9,476)	(7,681)	(5,511)
Income (loss) from continuing operations before income taxes									(2,059,783)	442,189	100,757
Identifiable Assets	4,914,244				7,317,782				4,914,244	7,317,782	7,366,943
Capital Expenditures									358,226	616,102	608,960
Drilling Products And Services [Member]
Segment Reporting Information [Line Items]
Revenues									583,139	904,358	820,538
Cost of goods and services									196,921	282,023	268,127
Depreciation, depletion, amortization and accretion									194,061	186,642	168,391
General and administrative expenses									127,525	149,967	136,244
Reduction in the value of assets									40,237		2,292
Income from operations									24,395	285,726	245,484
Income (loss) from continuing operations before income taxes									24,395	285,726	245,484
Identifiable Assets	1,223,191				1,284,842				1,223,191	1,284,842	1,237,842
Capital Expenditures									129,504	274,752	246,479
Onshore Completion Services [Member]
Segment Reporting Information [Line Items]
Revenues									934,274	1,732,833	1,607,268
Cost of goods and services									773,119	1,205,443	1,091,956
Depreciation, depletion, amortization and accretion									225,667	233,430	216,152
General and administrative expenses									121,289	159,687	158,448
Reduction in the value of assets									783,229		16,975
Income from operations									(969,030)	134,273	123,737
Income (loss) from continuing operations before income taxes									(969,030)	134,273	123,737
Identifiable Assets	1,929,185				2,993,824				1,929,185	2,993,824	2,961,390
Capital Expenditures									103,001	152,742	101,854
Production Services [Member]
Segment Reporting Information [Line Items]
Revenues									759,606	1,350,956	1,434,990
Cost of goods and services									594,286	941,030	1,002,628
Depreciation, depletion, amortization and accretion									130,267	164,672	177,532
General and administrative expenses									139,304	187,526	190,647
Reduction in the value of assets									790,517		28,568
Income from operations									(894,768)	57,728	35,615
Interest expense, net									2,013
Income (loss) from continuing operations before income taxes									(896,781)	57,728	35,615
Identifiable Assets	967,719				2,098,592				967,719	2,098,592	2,158,653
Capital Expenditures									72,048	88,870	122,946
Technical Solutions [Member]
Segment Reporting Information [Line Items]
Revenues									497,546	568,475	487,261
Cost of goods and services									301,486	306,337	270,879
Depreciation, depletion, amortization and accretion									62,152	66,070	42,366
General and administrative expenses									122,590	127,191	112,439
Reduction in the value of assets									124,904		252,243
Income from operations									(113,586)	68,877	(190,666)
Interest expense, net									(1,707)	(1,577)	(1,323)
Other Expense											836
Income (loss) from continuing operations before income taxes									(111,879)	70,454	(188,507)
Identifiable Assets	$ 794,149				$ 940,524				794,149	940,524	1,009,058
Capital Expenditures									53,673	99,738	137,681
Unallocated [Member]
Segment Reporting Information [Line Items]
Interest expense, net									97,012	98,311	109,225
Other Expense									(9,476)	(7,681)	(6,347)
Income (loss) from continuing operations before income taxes									$ (106,488)	$ (105,992)	$ (115,572)

XML 106 R82.htm IDEA: XBRL DOCUMENT

Segment Information (Schedule Of Identifiable Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Assets	$ 4,914,244	$ 7,317,782	$ 7,366,943
Drilling Products And Services [Member]
Segment Reporting Information [Line Items]
Assets	1,223,191	1,284,842	1,237,842
Onshore Completion Services [Member]
Segment Reporting Information [Line Items]
Assets	1,929,185	2,993,824	2,961,390
Production Services [Member]
Segment Reporting Information [Line Items]
Assets	967,719	2,098,592	2,158,653
Technical Solutions [Member]
Segment Reporting Information [Line Items]
Assets	$ 794,149	$ 940,524	$ 1,009,058

XML 107 R83.htm IDEA: XBRL DOCUMENT

Segment Information (Schedule Of Revenues By Geographic Segment) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Revenues	$ 545,150	$ 601,396	$ 710,784	$ 917,235	$ 1,178,626	$ 1,209,026	$ 1,107,552	$ 1,061,418	$ 2,774,565	$ 4,556,622	$ 4,350,057
Total, Revenues	545,150	$ 601,396	$ 710,784	$ 917,235	1,178,626	$ 1,209,026	$ 1,107,552	$ 1,061,418	2,774,565	4,556,622	4,350,057
Property, plant and equipment, net	2,123,291				2,733,839				2,123,291	2,733,839
UNITED STATES
Segment Reporting Information [Line Items]
Revenues									2,185,071	3,848,929	3,674,825
Total, Revenues									2,185,071	3,848,929	3,674,825
Long-lived assets	1,799,418				2,416,306				1,799,418	2,416,306
Other Countries Member
Segment Reporting Information [Line Items]
Revenues									589,494	707,693	675,232
Total, Revenues									589,494	707,693	$ 675,232
Long-lived assets	$ 323,873				$ 317,533				$ 323,873	$ 317,533

XML 108 R84.htm IDEA: XBRL DOCUMENT

Segment Information (Schedule of Capital Expenditures, by Segment) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Capital Expenditures	$ 358,226	$ 616,102	$ 608,960
Drilling Products And Services [Member]
Segment Reporting Information [Line Items]
Capital Expenditures	129,504	274,752	246,479
Onshore Completion Services [Member]
Segment Reporting Information [Line Items]
Capital Expenditures	103,001	152,742	101,854
Production Services [Member]
Segment Reporting Information [Line Items]
Capital Expenditures	72,048	88,870	122,946
Technical Solutions [Member]
Segment Reporting Information [Line Items]
Capital Expenditures	$ 53,673	$ 99,738	$ 137,681

XML 109 R85.htm IDEA: XBRL DOCUMENT

Commitments And Contingencies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies (Textual) [Abstract]
Rent expense	$ 29.6	$ 26.2	$ 25.6
2016	45.7
2017	32.4
2018	23.3
2019	16.1
2020	10.0
Thereafter	$ 25.2

XML 110 R86.htm IDEA: XBRL DOCUMENT

Fair Value Measurements (Narrative) (Details) - USD ($)	12 Months Ended
Fair Value Measurements (Narrative) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2013	Dec. 31, 2014
Fair Value Measurements [Abstract]
Interest rate swap agreement for notional amount	$ 300,000,000
Fair value of debt	1,508,000,000		$ 1,624,300,000
Impairment of long lived assets	343,300,000
Reduction in value of goodwill	1,326,701,000	$ 91,016,000
Impairment of Long-Lived Assets Held-for-use	343,300,000
Impairment of Intangible Assets, Finite-lived	$ 68,900,000

XML 111 R87.htm IDEA: XBRL DOCUMENT

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	Dec. 31, 2015	Dec. 31, 2014
Non-Qualified Deferred Compensation Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Accounts payable	$ 721
Intangible and other long-term assets	11,548	$ 12,982
Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Intangible and other long-term assets	6,905	4,183
Non Qualified Deferred Compensation Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other long-term liabilities	$ 17,367	14,720
Accounts payable		2,291
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	$ 368	$ 1,481
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] \| Non-Qualified Deferred Compensation Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Accounts payable	$ 721
Intangible and other long-term assets	11,180	$ 11,501
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	6,905	4,183
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	$ 17,367	14,720
Accounts payable		$ 2,291
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 112 R88.htm IDEA: XBRL DOCUMENT

Fair Value Measurements (Fair Value Measurements Used in Testing) (Details) - USD ($) $ in Thousands			12 Months Ended
	Dec. 31, 2015	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite Lived Intangible Assets Fair Value Used In Testing for Impairment	$ 68,890
Goodwill Fair Value Measurement Used in Testing for Impairment	1,326,701
Property, Plant and Equipment Fair Value Measurment Used in Testing Impairment of Long-Lived Assets	177,442
Reduction in value of goodwill			$ 1,326,701	$ 91,016
Impairment of Intangible Assets, Finite-lived			68,900
Impairment of Long-Lived Assets Held-for-use			$ 343,300
Level 1 [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	6,345
Goodwill Fair Value Measurement Used in Testing for Impairment	998,288
Property, Plant and Equipment Fair Value Measurment Used in Testing Impairment of Long-Lived Assets	$ 179,612
Level 2 [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		$ 18,296
Goodwill Fair Value Measurement Used in Testing for Impairment		91,016
Property, Plant and Equipment Fair Value Measurment Used in Testing Impairment of Long-Lived Assets		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

XML 113 R89.htm IDEA: XBRL DOCUMENT

Derivative Financial Instruments (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Financial Instruments [Abstract]
Derivative asset	$ 6,900,000	$ 4,200,000
Interest income (expense) related to the ineffectiveness associated with the fair value hedge	(2,700,000)	$ 3,800,000	$ 800,000
Interest rate swap agreement for notional amount	$ 300,000,000

XML 114 R90.htm IDEA: XBRL DOCUMENT

Derivative Financial Instruments (Location And Effect Of The Derivative Instrument On The Statements Of Operations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, (Gain) Loss [Line Items]
Amount of (gain) loss recognized	$ (2,722)	$ (3,846)	$ 776
Hedged Item Debt [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Amount of (gain) loss recognized	(790)	7,208	(12,303)
Interest Rate Swap [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Amount of (gain) loss recognized	$ (1,932)	$ (11,054)	$ 13,079

XML 115 R91.htm IDEA: XBRL DOCUMENT

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Purchase of services		$ 221.1	$ 164.8
Trade Accounts Payable		26.8
Ortowski Construction [Member]
Related Party Transaction [Line Items]
Purchase of services		0.7
Trade Accounts Payable		0.0
ORTEQ Energy Services [Member]
Related Party Transaction [Line Items]
Purchase of services		92.1	52.8
Trade Accounts Payable		10.1
Resource Transport [Member]
Related Party Transaction [Line Items]
Purchase of services		21.6	14.0
Trade Accounts Payable		1.7
Texas Specialty Sands [Member]
Related Party Transaction [Line Items]
Purchase of services		79.3	69.1
Trade Accounts Payable		14.0
ProFuel LLC [Member]
Related Party Transaction [Line Items]
Purchase of services		25.5	26.9
Trade Accounts Payable		1.0
TIMBER CREEK REAL ESTATE PARTNERS [Member]
Related Party Transaction [Line Items]
Purchase of services		1.9	2.0
LINNENERGY[MEMBER]
Related Party Transaction [Line Items]
Revenue from Related Parties	$ 7.2	19.7	$ 26.9
Accounts Receivable, Related Parties, Current	$ 2.0	$ 1.6

XML 116 R92.htm IDEA: XBRL DOCUMENT

Interim Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Selected Quarterly Financial Information [Abstract]
Revenues	$ 545,150	$ 601,396	$ 710,784	$ 917,235	$ 1,178,626	$ 1,209,026	$ 1,107,552	$ 1,061,418	$ 2,774,565	$ 4,556,622	$ 4,350,057
Costs and Expenses [Abstract]
Cost of services and rentals	397,548	420,485	465,533	582,246	711,243	721,692	650,293	651,605	1,865,812	2,734,833	2,633,590
Depreciation, depletion, amortization and accretion	144,818	146,757	158,352	162,220	157,377	170,154	160,965	162,318	612,147	650,814	604,441
Gross Profit	2,784	34,154	86,899	172,769	310,006	317,180	296,294	247,495
Reduction in value of assets	175,618	755,632	807,637						1,738,887		300,078
Net income (loss) from continuing operations	(214,547)	(816,587)	(775,132)	(1,497)	73,364	85,743	79,057	42,626	(1,807,763)	280,790	45,485
Loss from discontinued operations, net of tax	(22,848)	(4,610)	(9,857)	(9,640)	(7,238)	(5,886)	(3,895)	(5,954)	(46,955)	(22,973)	(156,903)
Net Income (Loss)	$ (237,395)	$ (821,197)	$ (784,989)	$ (11,137)	$ 66,126	$ 79,857	$ 75,162	$ 36,672	$ (1,854,718)	$ 257,817	$ (111,418)
Earnings Per Share [Abstract]
Continuing operations, basic	$ (1.43)	$ (5.42)	$ (5.15)	$ (0.02)	$ 0.49	$ 0.55	$ 0.51	$ 0.27	$ (12.02)	$ 1.81	$ 0.29
Continuing operations, diluted					0.48	0.55	0.50	0.27	(12.02)	1.79	0.28
Discontinued operations, basic	$ (0.15)	$ (0.03)	$ (0.07)	$ (0.06)	$ (0.05)	$ (0.03)	$ (0.03)	$ (0.04)	(0.31)	(0.15)	(0.99)
Discontinued operations, diluted									$ (0.31)	$ (0.14)	$ (0.97)

XML 117 R93.htm IDEA: XBRL DOCUMENT

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015 $ / Mcf	Dec. 31, 2015 $ / Boe	Dec. 31, 2015 $ / bbl	Dec. 31, 2015 $ / BTU	Dec. 31, 2014 $ / Mcf	Dec. 31, 2014 $ / Boe	Dec. 31, 2014 $ / bbl	Dec. 31, 2014 $ / BTU	Dec. 31, 2014	Dec. 31, 2013 $ / Mcf	Dec. 31, 2013 $ / Boe	Dec. 31, 2013 $ / bbl	Dec. 31, 2013 $ / BTU
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Average sales prices	2.82	47.17			4.95	92.86				3.98	101.85
Average production costs \| $ / Boe		10.38				7.29					10.70
Percentage of annual discount rate for future cash flows									10.00%
Supplementary Oil and Natural Gas Disclosures (Textual) [Abstract]
Twelve month average price on the basis of which oil price is estimated \| $ / bbl			50.28				94.99					93.42
Twelve month average price on the basis of which gas price is estimated \| $ / BTU				2.66				4,350,000.00					3.67

XML 118 R94.htm IDEA: XBRL DOCUMENT

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Schedule Of Proved Developed And Undeveloped Oil And Gas Reserves) (Details) MMcf in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2015 MBbls MMcf	Dec. 31, 2014 MBbls MMcf	Dec. 31, 2013 MBbls MMcf
Oil [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Beginning balance \| MBbls	3,417	4,593	8,207
Revisions \| MBbls	(381)	(438)	(3,203)
Production \| MBbls	(633)	(738)	(411)
Ending balance \| MBbls	2,403	3,417	4,593
Proved-developed reserves:
Proved Developed Reserves (Volume) \| MBbls	2,202	3,184	2,397
Proved-undeveloped reserves:
Proved Undeveloped Reserve (Volume) \| MBbls	201	233	2,196
Natural Gas [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Beginning balance \| MMcf	7,136	6,952	11,284
Revisions \| MMcf	(245)	1,431	(4,036)
Production \| MMcf	(1,517)	(1,247)	(296)
Ending balance \| MMcf	5,374	7,136	6,952
Proved-developed reserves:
Proved Developed Reserves (Volume) \| MMcf	5,216	6,945	2,100
Proved-undeveloped reserves:
Proved Undeveloped Reserve (Volume) \| MMcf	158	191	4,852

XML 119 R95.htm IDEA: XBRL DOCUMENT

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Cost Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Abstract]
Development costs	$ 20,636	$ 52,719	$ 51,527
Total costs incurred	$ 20,636	$ 52,719	$ 51,527

XML 120 R96.htm IDEA: XBRL DOCUMENT

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Capitalized Costs Relating To Oil And Gas Producing Activities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Capitalized Costs, Oil and Gas Producing Activities, Net [Abstract]
Proved oil and gas properties	$ 66,285	$ 189,294
Accumulated depreciation, depletion and amortization		(55,864)
Capitalized costs, net	$ 66,285	$ 133,430

XML 121 R97.htm IDEA: XBRL DOCUMENT

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Schedule Of Ownership In Productive Oil And Natural Gas Wells) (Details)	Dec. 31, 2015 item
Company's ownership of productive oil and natural gas wells
Oil, gross	11.00
Oil, net	5.61

XML 122 R98.htm IDEA: XBRL DOCUMENT

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Schedule Of Gas And Oil Acreage) (Details)	Dec. 31, 2015 a
Information relating to acreage held by the Company
Developed, gross acreage	23,040
Undeveloped, gross acreage	0
Total developed and undeveloped gross acreage	23,040
Developed, net acreage	11,750
Undeveloped, net acreage	0
Total developed and undeveloped net Acreage	11,750

XML 123 R99.htm IDEA: XBRL DOCUMENT

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Schedule Of Drilling Activity) (Details) - item	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
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	1.02	1.53
Non-Productive Development Wells Net	0.51	0.51
Productive Development Wells Net	0.51	1.02
Total Development Wells Gross	2.00	3.00
Non-Productive Development Wells Gross	1.00	1.00
Productive Development Wells Gross	1.00	2.00

XML 124 R100.htm IDEA: XBRL DOCUMENT

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Results Of Operations For Oil And Gas Producing Activities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues
Sales	$ 30,245	$ 77,845	$ 47,050
Production costs	15,466	13,529	9,876
Depreciation, depletion and amortization	37,623	38,768	12,032
Reduction in value of assets	56,000
Income before income taxes	(78,844)	25,548	25,142
Income tax expenses	(28,778)	9,325	8,800
Results of operations from producing activities (excluding corporate overhead)	$ (50,066)	$ 16,223	$ 16,342

XML 125 R101.htm IDEA: XBRL DOCUMENT

Supplementary Oil And Natural Gas Disclosures (Unaudited) (Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]
Standardized measure of discounted future net cash flows	$ 21,063	$ 111,050	$ 157,729	$ 303,430
Future net cash flows	1,301	94,016	168,370
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Cash Inflows	127,048	336,944	496,704
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Production Costs	43,010	71,209	82,487
Future Net Cash Flows Relating to Prived Oil and Gas Reserves Future Develpment And Abandonment Costs	84,090	111,374	156,340
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Income Tax Expense	(1,353)	60,345	89,507
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, 10 Percent Annual Discount for Estimated Timing of Cash Flows	$ (19,762)	$ (17,034)	$ 10,641

XML 126 R102.htm IDEA: XBRL DOCUMENT

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	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Beginning of the period	$ 111,050	$ 157,729	$ 303,430
Net change in sales and transfer prices and in production (lifting) costs related to future production	(143,808)	(57,568)	(13,278)
Changes in estimated future development costs	3,787	(5,512)	(48,594)
Sales and transfers of oil and gas produced during the period	(14,779)	(64,316)	(45,866)
Net change due to extensions, discoveries, and improved recovery	6,737		75,304
Net changes due to revisions in quantity estimates	(36,397)	(8,396)	(228,620)
Previously estimated development costs incurred during period	20,636	40,962	10,136
Accretion of discount	17,606	24,251	46,711
Other-unspecified	1,895	4,125	(24,169)
Net change in income taxes	54,336	19,775	82,675
Aggregate change in the standardized measure of discounted future net cash flows for the year	(89,987)	(46,679)	(145,701)
End of the period	$ 21,063	$ 111,050	$ 157,729

XML 127 R103.htm IDEA: XBRL DOCUMENT

Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Movement in Valuation Allowances and Reserves [Roll Forward]
Valuation Allowances and Reserves, Balance, Beginning Balance	$ 22,076	$ 31,030	$ 28,715
Valuation Allowances and Reserves, Charged to Cost and Expense	14,341	6,299	7,587
Valuation Allowances and Reserves, Deductions	4,795	10,639	7,763
Valuation Allowances and Reserves, Reclassifications to Assets Held for Sale	3,380	4,614	(2,491)
Valuation Allowances and Reserves, Balance, Ending Balance	$ 28,242	$ 22,076	$ 31,030

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