spn-20141231 10K FY_Taxonomy2013

    

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, 2014

 

Or

 

 

 

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

 

For the Transition Period from ________ to _______

 

Commission File No. 001-34037

 

 

 

SUPERIOR ENERGY SERVICES, INC.

(Exact name of registrant as specified in its charter)

 

 

 

 

Delaware

 

75-2379388

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

1001 Louisiana Street, Suite 2900

 

 

Houston, TX

 

77002

Address of principal executive offices)

 

(Zip Code)

 

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

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

 

Title of each class:

 

Name of each exchange on which registered:

Common Stock, $.001 Par Value

 

New York Stock Exchange

 

Securities registered pursuant to Section 12(g) of the Act:

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes   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, 2014, the aggregate market value of the registrant’s voting stock held by non-affiliates of the registrant was $5.41 billionAs of February 17, 2015, there were 149,785,368 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, 2014

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

14

 

Item 2

Properties

14

 

Item 3

Legal Proceedings

14

 

Item 4

Mine Safety Disclosures

14

 

 

 

 

PART II

 

 

 

 

 

 

 

Item 5

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

15

 

Item  6

Selected Financial Data

17

 

Item 7

Management’s Discussion and Analysis of Financial Condition and Results of Operations

18

 

Item 7A

Quantitative and Qualitative Disclosures about Market Risk

26

 

Item 8

Financial Statements and Supplementary Data

28

 

Item  9

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

63

 

Item 9A

Controls and Procedures

63

 

Item 9B

Other Information

64

 

 

 

 

PART III

 

 

 

 

 

 

 

Item 10

Directors, Executive Officers and Corporate Governance

65

 

Item 11

Executive Compensation

65

 

Item 12

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

65

 

Item 13

Certain Relationships and Related Transactions, and Director Independence

65

 

Item 14

Principal Accounting Fees and Services

65

 

 

 

 

PART IV

 

 

 

 

 

 

 

Item 15

Exhibits, Financial Statement Schedules

65

 

 

 

2

 


 

 

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; the impact that unfavorable or unusual weather conditions could have on our operations; and the risks inherent in long-term fixed-price contracts. 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.

 

 

3

 


 

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 oil and natural gas 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 (formerly, Subsea and Technical Solutions).  Given our history of growth and long-term strategy of expanding geographically, 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 11 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.  For information about our recent acquisitions, refer to note 4 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 and specialized pressure-control tools used for pressure control and intervention operations.

 

§

Intervention services – Includes services to enhance, maintain and extend oil and gas production during the life of the well, including coiled tubing, cased hole and mechanical wireline, hydraulic workover and snubbing, production testing and optimization, and remedial pumping services (cementing and stimulation services).

 

§

Specialized pressure-control tools – Includes surface and downhole products used to manage and control pressure throughout the life of an oil and gas well, including installing blowout preventers, choke manifolds, fracturing flow back trees, and downhole valves for drilling, workover, and well intervention operations.

 

4

 


 

·

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 include pressure control services, completion tools and services, end-of-life services, and marine technical services. 

 

§

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

 

§

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

 

§

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.

 

§

Marine technical services – Provides technical solutions for oil and gas offshore and marine applications including subsea and offshore  marine engineering and design, harsh environment engineering, well containment systems and project management services.

 

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 2014. However, EOG Resources, Inc. (EOG Resources) accounted for approximately 10% and 13% of our revenues in 2013 and 2012, respectively, primarily within the Onshore Completion and Workover segment.  Our inability to continue to perform services for 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. 

 

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).  Nonetheless, our indemnification arrangements may not protect us in every case.

 

5

 


 

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;

 

·

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 for 2015.

 

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, 2014, we had approximately 14,300 employees.  Approximately 7% 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.

 

6

 


 

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/.

 

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 investor relations page 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

 

David D. Dunlap, age 53, has served as our Chief Executive Officer since April 2010 and our President since February 2011.  Prior to joining us, he was employed by BJ Services Company as its Executive Vice President and Chief Operating Officer since 2007.  Mr. Dunlap joined BJ Services in 1984 and held numerous positions during his tenure, including President of the International Division, Vice President for the Coastal Division of North America and U.S. Sales and Marketing Manager.

 

Robert S. Taylor, age 60, has served as our Chief Financial Officer since January 1996, as one of our Executive Vice Presidents since September 2004, and as our Treasurer since July 1999.  He also served as one of our Vice Presidents from July 1999 to September 2004.

 

A. Patrick Bernard, age 57, has served as a Senior Executive Vice President since July 2006 and as one of our Executive Vice Presidents since September 2004.  He served as one of our Vice Presidents from June 2003 until September 2004.  From July 1999 until June 2003, Mr. Bernard served as the Chief Financial Officer of a wholly-owned subsidiary and its predecessor company.

 

Brian K. Moore, age 58, was appointed Senior Executive Vice President of North America Services on February 7, 2012.  From March 2007 until the effectiveness of the acquisition of the Complete Production Services, Inc. (Complete) in 2012, Mr. Moore was President and Chief Operating Officer of CompleteMr. Moore joined a predecessor company of Complete as President and Chief Executive Officer in April 2004.

   

Westervelt T. Ballard, Jr., age 43, was appointed Executive Vice President of International Services on February 7, 2012.  Mr. Ballard previously served as Vice President of Corporate Development since joining us in June 2007.  Prior to joining us, Mr. Ballard spent six years working in private equity.

 

L. Guy Cook, III, age 46, has served as one of our Executive Vice Presidents since September 2004.  He has also served as an Executive Vice President of a wholly-owned subsidiary, and previously as a Vice President of a wholly-owned subsidiary and its predecessor company since August 2000. 

 

William B. Masters, age 57, has served as our General Counsel and one of our Executive Vice Presidents since March 2008. He was previously a partner in the law firm Jones Walker LLP for more than 20 years.

 

Danny R. Young, age 59, has served as one of our Executive Vice Presidents since September 2004.  Mr. Young has also served as an Executive Vice President of a wholly-owned subsidiary.  From January 2002 to May 2005, he served as Vice President of Health, Safety and Environment and Corporate Services of a wholly-owned subsidiary.

 

7

 


 

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 gas prices and capital expenditures by oil and natural gas companies.

 

Our business depends on the level of oil and gas exploration, development and production activity by oil and gas companies worldwide.  The level of exploration, development and production activity is directly affected by trends in oil and gas prices, which historically have been volatile and difficult to predict.  Oil and 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 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. Any of these factors could significantly affect the demand for oil and natural gas and could have a material effect on our results of operations.

 

The availability of quality drilling prospects, exploration success, relative production costs, expectations about future oil and gas demand, 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.  Worldwide military, political and economic events have in the past contributed to oil and gas price volatility and are likely to do so in the future.  Any prolonged reduction of oil and gas prices, as well as anticipated declines, could also result in lower levels of exploration, development, and production activity. The demand for our services may be affected by numerous factors, including the following:

 

·

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

·

demand for energy, which is affected by worldwide economic activity, population growth and market expectations regarding future trends;

·

the ability of the Organization of Petroleum Exporting Countries (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;

·

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

8

 


 

·

technological advances affecting energy exploration, production and consumption.

Any extended period of low oil and gas prices could depress the level of oil and gas exploration and production activity in our markets, and thus reduce the demand for our products and services.  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.

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

Our operations are subject to hazards inherent in the oil and gas industry that may lead to property damage, personal injury, death or the discharge of hazardous materials into the environment. Many of these events are outside of our control. Typically, we provide products and services at a well site where our personnel and equipment are located together with personnel and equipment of our customer and other service providers. From time to time, personnel are injured or equipment or property is damaged or destroyed as a result of accidents, failed equipment, faulty products or services, failure of safety measures, uncontained formation pressures or other dangers inherent in oil and gas exploration, development and production. Any of these events can be the result of human error 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 environments. From time to time, customers and third parties may seek to hold us accountable for damages and costs incurred as a result of an accident, including pollution, 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. 

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.

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

Our business is directly affected by changes in capital expenditures by our customers, and reductions in their capital spending will generally reduce demand for our services and products.  The steep decline in oil prices in late 2014 has caused several of our customers to announce capital spending or production cuts or to delay their planning regarding future spending or production.  The rate of economic growth in the U.S. and worldwide has not reached the levels experienced since before the 2008 economic downturn.  Prolonged periods of little or no economic growth will likely decrease demand for oil and gas and increase pricing pressure for our services and products.  In addition, if a significant number of our customers experience a prolonged business decline or disruptions, we may incur increased exposure to credit risk and bad debts.

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

Our hydraulic fracturing services are subject to a range of applicable federal, state and local laws.  Our hydraulic fracturing services are designed and operated to minimize the risk, if any, of subsurface migration of hydraulic fracturing fluids and spillage or mishandling of hydraulic fracturing fluids.  However, a proven case of subsurface migration of hydraulic fracturing fluids or a case of spillage or mishandling of hydraulic fracturing fluids during these activities could potentially subject us to civil or criminal liability and the

9

 


 

possibility of substantial remediation costs, depending on the circumstances of the underground migration, spillage, or mishandling, the nature and scope of the underground migration, spillage, or mishandling, and the applicable laws and regulations.

The practice of hydraulically fracturing formations to stimulate the production of natural gas and oil remains under increased scrutiny from federal, 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. For example, the U.S. Department of Interior has issued proposed regulations that would apply to hydraulic fracturing wells subject to federal oil and gas leases that would impose requirements to disclose chemicals used in the fracturing process as well as certain prior approvals to conduct hydraulic fracturing.  In addition, a few states and municipalities have banned fracturing operations in their jurisdictions, and others are contemplating similar actions. Moreover, certain other states have adopted laws and regulations requiring additional disclosure regarding chemicals used in the fracturing process, and other states are evaluating the adoption of legislation or regulations governing hydraulic fracturing. Possible 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 affect our operations. The adoption of any future federal, state or local laws or regulations could adversely affect our hydraulic fracturing business.

Adverse and unusual weather conditions may affect our operations.

Our operations may be materially affected by severe weather conditions in areas where we operate.  Severe weather, such as hurricanes, high winds and seas, blizzards and extreme temperatures may cause evacuation of personnel, curtailment of services and suspension of operations, inability to deliver materials to jobsites in accordance with contract schedules, loss of or damage to equipment and facilities and reduced productivity.  In addition, variations from normal weather patterns can have a significant impact on demand for oil and gas, thereby reducing demand for our services and equipment.

Any capital financing that may be necessary may not be available at economic rates 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. Prevailing market conditions could be adversely affected by the ongoing disruptions in domestic or overseas sovereign or corporate debt markets, low oil 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.  Over the past several years, 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 2014, 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;

10

 


 

·

deprivation of contract rights;

·

increased operating costs;

·

inability to collect receivables;

·

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

·

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

·

confiscatory taxation or other adverse tax policies;

·

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 imposition of unanticipated or increased environmental and safety regulations or other forms of public or governmental regulation that increase our operating expenses; 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, Colombia, Indonesia, Kazakhstan, Nigeria, Mexico 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 its core business. 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 operators, partners or agents.  In certain instances, these local operators, partners or agents may have interests that are not always aligned with ours.  Reliance on local operators, 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 partners or agents even though these 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.

11

 


 

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

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 tax rate could be impacted. The final determination of our income tax liabilities involves the interpretation of local tax laws, tax treaties and related authorities in each taxing jurisdiction, as well as the significant use of estimates and assumptions regarding future operations and results and the timing of income and expenses. We may be audited and receive tax assessments from taxing authorities that may result in assessment of additional taxes that are ultimately resolved with the authorities or through the courts. We believe these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. Resolution of any tax matter involves uncertainties and there are no assurances that the outcomes will be favorable.

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

Our business is significantly affected by a wide range of laws and regulations in the areas in which we operate, and increasingly rigorous environmental laws and regulations governing air emissions, water discharges and waste management.  Generally, these laws have in recent years 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.

We incur, and expect to continue to incur, capital and operating costs to comply with these laws and regulations. The technical requirements of these laws and regulations are becoming increasingly complex and expensive to implement. For instance, a variety of regulatory developments, proposals or requirements have been introduced by various domestic, foreign or international regulatory bodies that are focused on restricting the emission of carbon dioxide, methane and other greenhouse gases, which could impose restrictions in greenhouse gas emissions. These proposals include, among others, various “cap and trade,” carbon tax and sequestration initiatives.  Recently, the U.S. Environmental Protection Agency (EPA) has issued rules regulating greenhouse emissions by oil and gas operators.  At this stage, we cannot predict the impact of the EPA’s recent rulemaking on our 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.

Further, environmental laws may provide for “strict liability” for remediation costs, damages to natural resources or threats to public health and safety. Strict liability can render a party liable for damages without regard to negligence or fault on the part of the party. Some environmental laws provide for joint and several strict liability for remediation of spills and releases of hazardous substances.  For example, our well service and fluids businesses routinely involve the handling of significant amounts of waste materials, some of which are classified as hazardous substances. We also store, transport and use radioactive and explosive materials in certain of our operations. In addition, many of our current and former facilities are, or have been, used for industrial purposes. Accordingly, we could become subject to material liabilities relating to the containment and disposal of hazardous substances, oilfield waste and other waste materials, the use of radioactive materials, the use of underground injection wells, and to claims alleging personal injury or property damage as the result of exposures to, or releases of, hazardous substances. In addition, stricter enforcement of existing laws and regulations, new 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.

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

12

 


 

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 resulting results of operations or financial condition.

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

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

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

We cannot be certain that our infrastructure and workforce will be adequate to support our operations as we expand.  Future growth also could impose significant additional demands on our resources, resulting in additional responsibilities of our senior management, including the need to recruit and integrate new senior level managers, executives and operating personnel.  We cannot be certain that we will be able to recruit and retain such additional personnel.  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.

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 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.

13

 


 

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

Some of our decommissioning business may be conducted under fixed-price or “turnkey” contracts. Under fixed-price contracts, we agree to perform a defined scope of work or deliver a product for a fixed price. Prices for these contracts are established based largely upon estimates and assumptions relating to project scope and specifications, personnel and material needs.  These estimates and assumptions may prove inaccurate or conditions may change due to factors out of our control resulting in cost overruns.  We may be required to absorb these cost overruns, which could have a material adverse effect on our business, financial condition and results of operations.

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

From time to time, we may engage in projects that include the acquisition of oil and gas properties. Acquisitions of these properties require an assessment of a number of factors beyond our control, including estimates of recoverable reserves, future oil and gas prices, operating costs and potential environmental and plugging and abandonment liabilities. These assessments are complex and inherently speculative, and, with respect to estimates of oil and gas reserves, require significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. In addition, since these properties are typically mature and could be in shallow water, our facilities and operations may be more susceptible to hurricane damage, equipment failure or mechanical problems. In connection with these assessments, we perform due diligence reviews that we believe are generally consistent with industry practices. However, our reviews may not reveal all existing or potential risks or liabilities. In addition, our reviews may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We may not always discover structural, subsurface, environmental or other problems that may exist or arise.

Actual future production, cash flows, development expenditures, operating and abandonment expenses and quantities of recoverable oil and gas reserves may vary substantially from those estimated by us and any significant variance in these assumptions could materially affect the estimated quantity and value of our proved reserves. Therefore, the risk exists we may overestimate the value of economically recoverable reserves 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.

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.

 

14

 


 

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

 

 

 

2013

 

 

 

 

 

 

 

 

 

 

First Quarter

$

27.36

 

$

21.10

 

$

 -

 

Second Quarter

 

29.22

 

 

22.89

 

 

 -

 

Third Quarter

 

28.13

 

 

24.43

 

 

 -

 

Fourth Quarter

 

28.32

 

 

24.28

 

 

0.08

 

 

 

 

 

 

 

 

 

 

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

 

As of February 17, 2015, there were 149,785,368 shares of our common stock outstanding, which were held by 132 record holders.

 

Dividend Information

 

On January 15, 2015, our board of directors declared a regular quarterly dividend of $0.08 per share, which was paid on February 20, 2015, to our stockholders of record at the close of business on January 30, 2015.  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, future prospects 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, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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, 2014

 

1,834,906 

 

$

30.89 

 

1,834,400 

 

$

147,075,668 

November 1 - 30, 2014

 

1,704,648 

 

$

24.43 

 

1,704,400 

 

$

105,432,489 

December 1 - 31, 2014

 

854,300 

 

$

18.69 

 

854,300 

 

$

500,000,000 

Total

 

4,393,854 

 

$

26.01 

 

4,393,100 

 

$

500,000,000 

 

 

 

 

 

 

 

 

 

 

 

 

15

 


 

(1) Through our stock incentive plans, 754 shares were delivered to us by our employees to satisfy their tax withholding requirements upon vesting of restricted stock.

(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.  This $500 million share repurchase program replaced the previous $400 million share repurchase program approved by our Board of Directors in October 2013.  As of December 31, 2014, $500 million remained authorized under our new stock repurchase program.    The old share repurchase plan was set to expire in December 2015 and had $89.5 million of remaining authorization for shares repurchases as of December 5, 2014.  From October 1, 2014 through December 5, 2014, we repurchased 4,393,100 shares of our common stock for $114.3 million under the old share 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, 2014 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, 2010 at closing prices on December 31, 2009.

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Years Ended December 31,

 

 

2010

 

2011

 

2012

 

2013

 

2014

Superior Energy Services, Inc.

 

$

144 

 

$

117 

 

$

85 

 

$

110 

 

$

84 

S&P 500 Stock Index

 

$

115 

 

$

117 

 

$

136 

 

$

179 

 

$

204 

Peer Group

 

$

145 

 

$

149 

 

$

139 

 

$

183 

 

$

142 

 

16

 


 

NOTES:

·

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

·

The indexes are reweighted daily, using the market capitalization on the previous trading day.

·

If the monthly interval, based on the fiscal year-end, is not a trading day, the preceding trading day is used.

·

The index level for all securities was set to $100.00 on December 31, 2009.

 

Our Self-Determined Peer Group consists of 16 companies whose average stockholder return levels comprise part of the performance criteria established by the Compensation Committee of our Board of Directors under our long-term incentive compensation program:  Baker Hughes, Incorporated, Basic Energy Services, Inc., Cameron International Corporation, FMC Technologies, Inc., Halliburton Company, Helix Energy Solutions Group, Inc., Helmerich & Payne Inc., Key Energy Services, Inc., Nabors Industries Ltd., National Oilwell Varco, Inc., Oceaneering International, Inc., Oil States International, Inc., Patterson-UTI Energy Inc., RPC, Inc., Schlumberger N.V. and Weatherford International, Ltd. 

 

Item 6. Selected Financial Data

We present below our selected consolidated financial data for the periods indicated.  We derived the historical data from our audited consolidated financial statements.

 

The data presented below should be read together with, and are qualified in their entirety by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in Part II, Item 7 of this Annual Report on Form 10-K and our consolidated financial statements included in Part II, Item 8 in this Annual Report on Form 10-K.  The financial data is in thousands, except per share amounts.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Years Ended December 31,

 

 

2014

 

2013

 

2012

 

2011

 

2010

Revenues

 

$

4,556,622 

 

$

4,350,057 

 

$

4,293,276 

 

$

1,766,287 

 

$

1,280,008 

Income from operations

 

 

546,604 

 

 

214,170 

 

 

710,373 

 

 

298,809 

 

 

145,633 

Net income from continuing operations

 

 

280,790 

 

 

45,485 

 

 

383,917 

 

 

159,491 

 

 

71,706 

Income (loss) from discontinued operations,
    net of tax

 

 

(22,973)

 

 

(156,903)

 

 

(17,982)

 

 

(16,937)

 

 

10,111 

Net income (loss)

 

 

257,817 

 

 

(111,418)

 

 

365,935 

 

 

142,554 

 

 

81,817 

Net income from continuing
    operations per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    Basic

 

 

1.81 

 

 

0.29 

 

 

2.57 

 

 

2.00 

 

 

0.91 

    Diluted

 

 

1.79 

 

 

0.28 

 

 

2.54 

 

 

1.97 

 

 

0.90 

Net income (loss) from discontinued
    operations per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    Basic

 

 

(0.15)

 

 

(0.99)

 

 

(0.12)

 

 

(0.21)

 

 

0.13 

    Diluted

 

 

(0.14)

 

 

(0.97)

 

 

(0.12)

 

 

(0.21)

 

 

0.13 

Net income (loss) per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    Basic

 

 

1.66 

 

 

(0.70)

 

 

2.45 

 

 

1.79 

 

 

1.04 

    Diluted

 

 

1.65 

 

 

(0.69)

 

 

2.42 

 

 

1.76 

 

 

1.03 

Cash dividends declared per share

 

 

0.24 

 

 

0.08 

 

 

 -

 

 

 -

 

 

 -

Total assets

 

 

7,377,389 

 

 

7,411,307 

 

 

7,802,886 

 

 

4,048,145 

 

 

2,907,533 

Long-term debt, net

 

 

1,627,842 

 

 

1,646,535 

 

 

1,814,500 

 

 

1,685,087 

 

 

681,635 

Decommissioning liabilities, less current portion

 

 

88,000 

 

 

56,197 

 

 

93,053 

 

 

108,220 

 

 

100,787 

Stockholders' equity

 

 

4,079,738 

 

 

4,131,444 

 

 

4,231,079 

 

 

1,453,599 

 

 

1,280,551 

 

 

 

 

 

 

 

 

17

 


 

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 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 oil and natural gas 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 (formerly, Subsea and Technical Solutions).  Given our history of growth and long-term strategy of expanding geographically, we also provide supplemental segment revenue information in three geographic areas:  U.S. land; Gulf of Mexico; and International.

 

Overall, 2014 was a very successful year for our Company.  We experienced strong operational performance and focused our efforts on maintaining capital and cost discipline.  Oil markets remained relatively well-balanced during much of 2014 as increasing global production capacity almost matched increasing demand.  However, late in 2014, oil prices declined dramatically to their lowest levels since 2009. 

 

As we enter a challenging 2015, the reduction in commodity prices, which have resulted principally from the higher marketed supply of oil, raises short-term uncertainty regarding the spending activity levels of our customers.  In this uncertain environment, our focus will be on rationalizing costs during the course of the downturn in demand for our products and services.

 

Overview of our business segments

 

The Drilling Products and Services segment is capital intensive with higher operating margins relative to our other segments as a result of relatively low operating expenses.  The largest fixed cost is depreciation as there is little labor associated with our drilling products and services businesses.  The financial performance is primarily a function of changes in volume rather than pricing.  In 2014, 35% of segment revenue was derived from U.S. land market areas (up from 34% in 2013),  while 41% of segment revenue was from the Gulf of Mexico market area (up from 38% in 2013) and 24% of segment revenue was from international market areas (down from 28% in 2013). Premium drill pipe accounted for more than 50% of this segment’s revenue in 2014, while bottom hole assemblies and accommodations each accounted for more than 20% of this segment’s revenue in 2014.

 

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 areasDemand 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 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 45% of this segment’s revenue in 2014.  Fluid management represented more than 25% of this segment’s revenue in 2014, while well service rigs accounted for more than 15% of this segment’s revenue in 2014.

 

The Production Services segment consists of intervention services primarily used to maintain and extend oil and gas production during the life of a producing well, and specialized pressure-control tools used to manage and control pressure throughout the life of a well.  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 2014, 64% of segment revenue was derived from the U.S. land market area (up from 61% in 2013), while 10% of segment revenue was from the Gulf of Mexico market area (down from 15% in 2013) and 26% of this segment’s revenue was from international market areas (up from 24% in 2013). Coiled tubing is the largest service offering in this segment, accounting for more than 25% of segment revenue in 2014. 

 

18

 


 

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, the production and sale of oil and gas, and marine technical services. 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 2014, revenue derived from the U.S. land market area was 19% of segment revenue (up from 16% in 2013), while 57% of segment revenue was from the Gulf of Mexico market area (down from 65% in 2013) and 24% of segment revenue was from international market areas (up from 19% in 2013). Well control and associated services represent the largest service offering in this segment, accounting for more than 30% of this segment’s revenue in 2014.

 

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:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

%
Change

 

2013

 

%
Change

 

2012

Worldwide Rig Count (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. (land and offshore)

 

 

1,862 

 

6% 

 

 

1,761 

 

-8%

 

 

1,919 

International (2)

 

 

1,337 

 

3% 

 

 

1,296 

 

5% 

 

 

1,234 

Commodity Prices (average)

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil (West Texas Intermediate)

 

$

93.17 

 

-5%

 

$

97.98 

 

4% 

 

$

94.22 

Natural Gas (Henry Hub)

 

$

4.37 

 

17% 

 

$

3.73 

 

36% 

 

$

2.75 

 

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

 

(2) Excludes Canadian Rig Count.

 

The following table compares our revenues generated from major geographic regions for the years ended December 31, 2014 and 2013 (in thousands).  We attribute revenue to countries based on the location where services are performed or the destination of the rental or sale of products. 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenue

 

 

2014

 

%

 

2013

 

%

 

Change

U.S. Land

 

$

3,021,830 

 

66% 

 

$

2,847,427 

 

65% 

 

$

174,403 

Gulf of Mexico

 

 

827,099 

 

18% 

 

 

827,398 

 

19% 

 

 

(299)

International

 

 

707,693 

 

16% 

 

 

675,232 

 

16% 

 

 

32,461 

Total

 

$

4,556,622 

 

100% 

 

$

4,350,057 

 

100% 

 

$

206,565 

 

In 2014, our U.S. land revenue increased 6% to $3,021.8 million as a result of the improved general market conditions in the U.S land market area, including increased activity and resulting higher pricing and utilization.  U.S. land market area revenue from our Technical Solutions segment increased 39%, primarily due to an increase in demand for completion tools and products. Drilling Products and Services segment’s revenue derived from the U.S. land market area increased 12%, primarily due to increases in revenue from rentals of accommodations, bottom hole assemblies and premium drill pipe.  Onshore Completion and Workover Services segment revenue increased by 8% due to higher demand for pressure pumping services and fluid management.  The increases were partially offset by a 2% decrease in Production Services segment revenue from the U.S. land market area, primarily as a result of the decline in market demand for coiled tubing, remedial pumping services and hydraulic workover and snubbing activity. 

 

In 2014, our Gulf of Mexico revenue remained flat at $827.1 millionThe Drilling Products and Services segment, which has significant deepwater Gulf of Mexico exposure, experienced a 20% increase in revenue, primarily due to an increase in revenue from rentals of premium drill pipe and accommodations.  The Technical Solutions segment revenue from the Gulf of Mexico increased 2%.  The increases were partially offset by a 33% decrease in Production Services segment revenue from the Gulf of Mexico, primarily due to decreased activity for pressure control, hydraulic workover and snubbing and wireline services.

 

19

 


 

In 2014, our international revenue increased 5% to $707.7 million primarily as a result of increase in demand for well control work and completion tools and products in our Technical Solutions segment.  The Drilling Products and Services segment experienced a  5%  decline in revenue from international market areas due to decreases in rentals of accommodations and premium drill pipe. Production Services segment revenue from international market areas remained flat.

 

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

 

For the year ended December 31, 2014, our revenue was $4,556.6 million and our net income from continuing operations was $280.8 million, or $1.79 diluted earnings per share from continuing operations.    For the year ended December 31, 2013, our revenue was $4,350.1 million and our net income from continuing operations was $45.5 million, or $0.28 diluted earnings per share from continuing operations.  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.       

 

The following table compares our operating results for the years ended December 31, 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

 

$

923,849 

 

$

838,514 

 

$

85,335 

 

$

290,341 

 

31% 

 

$

276,131 

 

33% 

 

$

14,210 

Onshore Completion and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Workover Services

 

 

1,727,904 

 

 

1,596,704 

 

 

131,200 

 

 

1,201,497 

 

70% 

 

 

1,083,494 

 

68% 

 

 

118,003 

Production Services

 

 

1,356,057 

 

 

1,445,555 

 

 

(89,498)

 

 

945,201 

 

70% 

 

 

1,011,933 

 

70% 

 

 

(66,732)

Technical Solutions

 

 

548,812 

 

 

469,284 

 

 

79,528 

 

 

297,794 

 

54% 

 

 

262,032 

 

56% 

 

 

35,762 

Total

 

$

4,556,622 

 

$

4,350,057 

 

$

206,565 

 

$

2,734,833 

 

60% 

 

$

2,633,590 

 

61% 

 

$

101,243 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 $923.8 million for the year ended December 31, 2014, a 10% increase from 2013Cost of services and rentals decreased to 31% of segment revenue in 2014, as compared to 33% in 2013, primarily due to an increase in revenues from a more favorable product mix.  Revenue from our Gulf of Mexico market increased 20% due to increases in rentals of premium drill pipe and accommodationsRevenue generated in 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 $1,727.9 million for the year ended December 31, 2014, an 8% increase from 2013. Cost of services and rentals 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 $1,356.1 million for the year ended December 31, 2014, a 6% decline from 2013.  Cost of services and rentals 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 $548.8 million for the year ended December 31, 2014, a 17% increase from 2013.  Cost of services and rentals decreased to 54% of segment revenue in 2014, as compared to 56% in 2013, primarily due to a more favorable product mixRevenue 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.

20

 


 

 

Depreciation, Depletion, Amortization and Accretion

 

Depreciation, depletion, amortization and accretion increased to $650.8 million for the year ended December 31, 2014 from $604.4 million in 2013.  Depreciation and amortization expense increased for our Drilling Products and Services segment by $18.5 million, or 11%; for our Onshore Completion and Workover Services segment by $18.0 million, or 8%, and for our Technical Solutions segment by $23.2 million, or 56%, primarily due to capital expenditures.  Depreciation and amortization expense for our Production Services segment decreased by $13.3 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 for the year ended December 31, 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 the year ended December 31, 2013, we recorded $300.1 million of reduction in value of assets.  The reduction in value of assets expense 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 9 to our consolidated financial statements for further discussion of the reduction in value of assets.

 

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 that the U.S.  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 10 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  $23.0 million for the year ended December 31, 2014, as compared to $156.9 million in 2013

 

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

 

For the year ended December 31, 2013, our revenue was $4,350.1 million and our net income from continuing operations was $45.5 million, or $0.28 diluted earnings per share from continuing operations.  Included in the results for 2013 were pre-tax charges for $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.  For the year ended December 31, 2012, our revenue was $4,293.3 million and our net income from continuing operations was $383.9 million, or $2.54 diluted earnings per share from continuing operations. Included in the results for 2012 were $32.9 million of acquisition related costs, $2.3 million of loss on early extinguishment of debt, and $17.9 million of gain on the sale of our equity-method investment.       

 

The following table compares our operating results for the years ended December 31, 2013 and 2012 (in thousands).  Cost of services and rentals excludes depreciation, depletion, amortization and accretion for each of our business segments. 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenue

 

Cost of Services and Rentals

 

 

2013

 

2012

 

Change

 

2013

 

%

 

2012

 

%

 

Change

Drilling Products and Services

 

$

838,514 

 

$

775,066 

 

$

63,448 

 

$

276,131 

 

33% 

 

$

255,853 

 

33% 

 

$

20,278 

Onshore Completion and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Workover Services

 

 

1,596,704 

 

 

1,593,977 

 

 

2,727 

 

 

1,083,494 

 

68% 

 

 

1,039,732 

 

65% 

 

 

43,762 

Production Services

 

 

1,445,555 

 

 

1,510,990 

 

 

(65,435)

 

 

1,011,933 

 

70% 

 

 

929,552 

 

62% 

 

 

82,381 

Technical Solutions

 

 

469,284 

 

 

413,243 

 

 

56,041 

 

 

262,032 

 

56% 

 

 

244,283 

 

59% 

 

 

17,749 

Total

 

$

4,350,057 

 

$

4,293,276 

 

$

56,781 

 

$

2,633,590 

 

61% 

 

$

2,469,420 

 

58% 

 

$

164,170 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

21

 


 

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 $838.5 million for the year ended December 31, 2013, an 8% increase from 2012Cost of services and rentals remained at 33% of segment revenue in 2013.  Revenue from our Gulf of Mexico market increased 30% due to increases in most of our product lines within this segment, particularly due to increases in rentals of premium drill pipe.  Revenue generated from our international market areas increased 23%, primarily due to increase in rentals of bottom hole assemblies and premium drill pipe.  Revenue generated from our U.S. land market area decreased 16%, primarily due to decreases in rentals of premium drill pipe and accommodations.    

 

Onshore Completion and Workover Services Segment

 

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

 

Production Services Segment

 

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

 

Technical Solutions Segment

 

Revenue for our Technical Solutions segment was $469.3 million for the year ended December 31, 2013, a 14% increase from 2012.  Cost of services and rentals decreased to 56% of segment revenue in 2013, as compared to 59% in 2012.  Revenue in our Gulf of Mexico market area increased 34%, primarily due to increases in well control work and sand control and stimulation services.  Revenue in our international market areas decreased 24%, primarily as a result of a decrease in well control work.  Revenue in our U.S. land market area increased 9%, primarily as a result of increased demand for environmental services.

 

Depreciation, Depletion, Amortization and Accretion

 

Depreciation, depletion, amortization and accretion increased to $604.4 million for the year ended December 31, 2013 from $488.1 million in 2012.  Depreciation and amortization expense increased for our Drilling Products and Services segment by $18.6 million, or 12%, due to capital expenditures.  Depreciation and amortization expense for our Onshore Completion and Workover Services segment increased by $43.7 million, or 25%, some of which was attributable to the fact that the product offerings comprising this segment were acquired in the February 2012 acquisition of Complete and the remainder is attributable to capital expenditures.  Depreciation and amortization expense for our Production Services segment increased by $42.5 million, or 31%, partly because a portion of the product offerings comprising this segment were acquired in the Complete acquisition and the remainder is attributable to other acquisitions and capital expenditures.  Depreciation, depletion, amortization and accretion expense for our Technical Solutions segment increased by $11.6 million, or 39%, primarily due to capital expenditures. 

 

General and Administrative Expenses

 

General and administrative expenses decreased to $597.8 million for the year ended December 31, 2013 from $625.4 million in 2012.    General and administrative expenses declined year over year primarily due to nonrecurring acquisition-related expenses and other expenses incurred during 2012

 

Reduction in Value of Assets

 

During the year ended December 31, 2013, we recorded $300.1 million of reduction in value of assets.  The reduction in value of assets expense 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

22

 


 

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 9 to our consolidated financial statements for further discussion of the reduction in value of assets.

 

Income Taxes

 

The increase in the effective tax rate during 2013 was primarily due to the asset value reductions recorded during the fourth quarter of 2013, which were attributable to foreign jurisdictions with low or zero statutory income tax rates.  See note 10 to our consolidated financial statements.

 

Discontinued Operations

 

Loss from discontinued operations, net of tax, was $156.9 million for the year ended December 31, 2013 and included operating results for both our subsea construction business and conventional decommissioning business.  Loss from discontinued operations, net of tax, was $18.0 million for the year ended December 31, 2012 and included operating results for both our subsea construction business and conventional decommissioning business and the derrick barge and liftboats that were sold in 2012.

 

Liquidity and Capital Resources

 

In the year ended December 31, 2014, we generated net cash from operating activities of $1,033.0 million as compared to $892.8 million in 2013Our primary liquidity needs are for working capital and to fund capital expenditures, debt service, dividend payments, share repurchases and acquisitions.  Our primary sources of liquidity are cash flows from operations and available borrowings under the revolving portion of our credit facility.  We had cash and cash equivalents of $393.0 million as of December 31, 2014 as compared to $196.0 million as of December 31, 2013.   As of December 31, 2014, approximately $172.5 million of our cash balance was held in foreign jurisdictions.  Cash balances held in foreign jurisdictions could be repatriated to the U.S.; however, they would be subject to U.S. federal income taxes, less applicable foreign tax credits.  Our current plans do not demonstrate a need to repatriate these balances to fund our domestic cash requirements.  We have not provided U.S. income tax expense on earnings of our foreign subsidiaries because we expect to reinvest the undistributed earnings indefinitely.  In October 2014, we acquired all of the equity interests in a company in India using approximately $22.0 million of cash which was held outside of the U.S.

 

We spent $616.1 million of cash on capital expenditures during the year ended December 31, 2014.  Approximately $276.6 million was used to expand and maintain our Drilling Products and Services segment’s equipment inventory, and approximately $152.7 million, $88.9 million and $97.9 million was spent to expand and maintain the asset bases of our Onshore Completion and Workover Services, Production Services and Technical Solutions segments, respectively.  

 

During 2015, we currently believe that we will reduce our capital expenditures by at least 35% from 2014.    We intend to limit our 2015 capital expenditures so that we continue to generate net cash from operating activities after considering our capital expenditures.

 

We have a $1.0 billion bank credit facility which is comprised of a $600 million revolving credit facility and a $400 million term loan.  The principal balance of the term loan is payable in installments of $5.0 million on the last day of each fiscal quarter.  As of December 31, 2014, we had $345 million outstanding under the term loan. As of December 31, 2014, we had no amounts outstanding under the revolving portion of our credit facility and $44.2 million of letters of credit outstanding, which reduce our borrowing capacity under this portion of the credit facility.  As of February 17, 2015, we had no amounts outstanding under the revolving portion of our credit facility, and $44.1 million of letters of credit outstanding.  Any amounts outstanding on the bank revolving credit facility and the term loan are due on February 7, 2017.  Borrowings under the credit facility bear interest at LIBOR plus margins that depend on our credit rating. The credit facility contains customary events of default and requires that we satisfy various financial covenants.  As of December 31, 2014, 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, 2014, 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, 2014, we were in compliance with all such covenants.

 

During 2014, credit ratings for our outstanding debt were raised to investment grade with the ratings of Baa3 with Moody’s Investors Service and BBB- with Standard and Poor’s.

 

23

 


 

The following table summarizes our contractual cash obligations and commercial commitments as of December 31, 2014 (in thousands):    

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Contractual Obligations

 

Total

 

< 1 Year

 

1 - 3 Years

 

3 - 5 Years

 

More Than 5 Years

Long-term debt, including estimated interest
    payments

 

$

2,222,808 

 

$

125,184 

 

$

521,124 

 

$

662,500 

 

$

914,000 

Decommissioning liabilities, undiscounted

 

 

220,422 

 

 

 -

 

 

35,697 

 

 

4,186 

 

 

180,539 

Operating leases

 

 

203,650 

 

 

64,675 

 

 

72,768 

 

 

37,515 

 

 

28,692 

Other long-term liabilities

 

 

166,766 

 

 

 -

 

 

74,020 

 

 

29,042 

 

 

63,704 

Total

 

$

2,813,646 

 

$

189,859 

 

$

703,609 

 

$

733,243 

 

$

1,186,935 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The table above reflects only contractual obligations as of December 31, 2014 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.

 

We continue to focus on operational efficiency and returning cash to stockholders.  During 2014, we repurchased $299.9 million of our common stock.  As of December 31, 2014, $500 million was available under our existing share repurchase program. During 2014, we paid $49.8 million of dividends to stockholders.  In February 2015, we paid a quarterly dividend of $12.0 million to stockholders of record as of January 30, 2015.

   

Critical Accounting Policies and Estimates

 

Our discussion and analysis of our financial condition and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.  The preparation of these financial statements requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes.  Note 1 of our consolidated financial statements, which is included in Part II, Item 8 of this Annual Report on Form 10-K, contains a description of the significant accounting policies used in the preparation of our financial statements.  We evaluate our estimates on an ongoing basis, including those related to business combinations, long-lived assets, goodwill, income taxes, allowance for doubtful accounts, revenue recognition, long-term contract accounting, self-insurance, and oil and gas properties.  We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances.  Actual amounts could differ significantly from these estimates under different assumptions and conditions.

 

We define a critical accounting policy or estimate as one that is both important to our financial condition and results of operations and requires us to make difficult, subjective or complex judgments or estimates about matters that are uncertain.  We believe that the following are the critical accounting policies and estimates used in the preparation of our consolidated financial statements.  In addition, there are other items within our consolidated financial statements that require estimates but are not deemed critical as defined in this paragraph.

 

Business Combinations -  Purchase Price Allocation. We allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. We use all available information to estimate fair values, including quoted market prices, the carrying value of acquired assets, and widely accepted valuation techniques such as discounted cash flows. We engage third-party appraisal firms to assist in fair value determination of property, plant and equipment, inventories, identifiable intangible assets, and any other significant assets or liabilities when appropriate. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can materially impact our results of operations.

 

Long-Lived Assets.  We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such asset may not be recoverable.  We record impairment losses on long-lived assets used in operations when the fair value of those assets is less than their respective carrying amount.  Fair value is measured, in part, by the estimated cash flows to be generated by those assets.   Our cash flow estimates are based upon, among other things, historical results adjusted to reflect our best estimate of future market rates, utilization levels and operating performance.  Our estimates of cash flows may differ from actual cash flows due to, among other things, changes in economic conditions or changes in an asset’s operating performance.  Assets are generally grouped by subsidiary or division for the impairment testing, which represent the lowest level of identifiable cash flows.  We have long-lived assets, such as facilities, utilized by multiple operating divisions that do not have identifiable cash flows.  Impairment testing for these long-lived assets is based on the consolidated entity.  Assets to be disposed of are reported at the lower of the carrying amount or fair value less estimated costs to sell.  Our estimate of fair value represents our best estimate based on industry trends and reference to market transactions and is subject to variability.  The oil and gas industry is cyclical and our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows, can have a significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges.

 

24

 


 

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 recoverableDuring the third quarter of 2014, we changed the annual goodwill impairment testing date from December 31 to October 1. We consider this accounting change preferable because it allows us additional time to complete the annual goodwill impairment test. This change does not accelerate, delay, avoid, or cause an impairment charge, nor does this change result in adjustments to previously issued financial statements. 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 units exceeds the carrying amount, no impairment loss is recognized.  Our estimates of the fair value of these reporting units represent our best estimates based on industry trends and reference to market transactions.  A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. 

 

Based on the most recent goodwill impairment test at October 1, 2014, the fair values of the Drilling Products and Services and Onshore Completion and Workover Services segments were substantially in excess of their carrying values.  The fair value of the Production Services segment exceeded its carrying value by approximately 9%.  Therefore, no goodwill impairment was recorded.  As a result of our 2013 impairment of the goodwill of the Technical Solutions segment, this segment had no goodwill as of October 1, 2014.  A significant amount of judgment was involved in performing these evaluations since the results are based on estimated future events. 

 

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

 

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

 

Revenue Recognition.  Our products and services are generally sold based upon purchase orders or contracts with customers that include fixed or determinable prices.  We recognize revenue when services or equipment are provided and collectability is reasonably assured.  We contract for services either on a day rate or turnkey basis, with a majority of our projects conducted on a day rate basis.  We rent products on a day rate basis, and revenue from the sale of equipment is recognized when the title to the equipment has transferred to the customer. 

 

Long-Term Contract Accounting for Revenue and Profit (Loss) Recognition.  A portion of our revenue is derived from long-term contracts.  For contracts that meet the criteria under the authoritative guidance related to construction-type and production-type contracts, we recognize revenues on the percentage-of-completion method, primarily based on costs incurred to date compared with total estimated contract costs.  It is possible there will be future and currently unforeseeable significant adjustments to our estimated contract revenues, costs and profitability for contracts currently in process.  These adjustments could, depending on the magnitude of the adjustments, materially, positively or negatively, affect our operating results in a reporting period.  To the extent that an adjustment in the estimated total contract cost impacts estimated profit of the contract, the cumulative change to revenue and profitability is reflected in the period in which this adjustment in estimate is identified.  The accuracy of the revenue and estimated earnings we report for fixed-price contracts is dependent upon the judgments we make in estimating our contract performance and contract revenue and costs.

 

Self-Insurance.  We self-insure, through deductibles and retentions, up to certain levels for losses under our insurance programsAs 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.  

 

25

 


 

Oil and Gas Properties. Our subsidiary, Wild Well Control Inc. (Wild Well) has oil and gas properties as well as the related well abandonment and decommissioning liabilities.  Wild Well follows the successful efforts method of accounting for its investment in oil and gas properties.  Under the successful efforts method, the costs of successful exploratory wells and leases containing productive reserves are capitalized.  Costs incurred to drill and equip developmental wells, including unsuccessful developmental wells, are capitalized.  Other costs such as geological and geophysical costs and the drilling costs of unsuccessful exploratory wells are expensed.  All capitalized costs are accumulated and recorded separately for each field and allocated to leasehold costs and well costs.  Leasehold and well costs are depleted on a units-of-production basis based on the estimated remaining equivalent oil and gas reserves of the field. 

 

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

 

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

 

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.

 

Recently Issued Accounting Pronouncements

 

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

 

 

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risks associated with foreign currency fluctuations and changes in interest rates.  A discussion of our market risk exposure in financial instruments follows.

 

Foreign Currency Exchange 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, 2014, we had no outstanding foreign currency forward contracts.

 

26

 


 

Interest Rate Risk

 

As of December 31, 2014, our debt was comprised of the following (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed
Rate Debt

 

Variable
Rate Debt

Term loan due 2017

 

$

 -

 

$

345,000 

6 3/8 % Senior Notes due 2019

 

 

500,000 

 

 

 -

7 1/8% Senior Notes due 2021

 

 

500,000 

 

 

300,000 

Other

 

 

3,783 

 

 

 -

Total Debt

 

$

1,003,783 

 

$

645,000 

 

 

 

 

 

 

 

 

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, 2014, a 10% increase in the variable interest rate would increase our interest expense for the year ended December 31, 2014 by approximately $2.1 million, while a 10% decrease would decrease our interest expense by approximately $2.1 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.    

 

 

27

 


 

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, 2014 and 2013, 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, 2014.  In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule II, Valuation and Qualifying Accounts.  These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Superior Energy Services, Inc. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.  Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Superior Energy Services, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2015 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

 

KPMG LLP

 

 

Houston,  Texas

February 26, 2015

 

 

28

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2014 and 2013

(in thousands, except share data)

 

 

2014

 

2013

ASSETS

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

Cash and cash equivalents

 

$

393,046 

 

$

196,047 

Accounts receivable, net of allowance for doubtful accounts of $22,076 and

 

 

 

 

 

 

$31,030 as of December 31, 2014 and 2013, respectively

 

 

926,768 

 

 

937,195 

Income taxes receivable

 

 

 -

 

 

5,532 

Deferred income taxes

 

 

32,138 

 

 

8,785 

Prepaid expenses

 

 

74,750 

 

 

70,421 

Inventory and other current assets

 

 

185,429 

 

 

258,449 

Assets held for sale

 

 

116,680 

 

 

 -

Total current assets

 

 

1,728,811 

 

 

1,476,429 

Property, plant and equipment, net of accumulated depreciation and depletion

 

 

2,733,839 

 

 

3,002,194 

Goodwill

 

 

2,468,409 

 

 

2,458,109 

Notes receivable

 

 

25,970 

 

 

23,708 

Intangible and other long-term assets, net of accumulated amortization

 

 

420,360 

 

 

450,867 

Total assets

 

$

7,377,389 

 

$

7,411,307 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

Accounts payable

 

$

225,306 

 

$

216,029 

Accrued expenses

 

 

363,747 

 

 

376,049 

Income taxes payable

 

 

40,213 

 

 

 -

Current maturities of long-term debt

 

 

20,941 

 

 

20,000 

Current portion of decommissioning liabilities

 

 

 -

 

 

27,322 

Liabilities held for sale

 

 

61,840 

 

 

 -

Total current liabilities

 

 

712,047 

 

 

639,400 

Deferred income taxes

 

 

702,996 

 

 

736,080 

Decommissioning liabilities

 

 

88,000 

 

 

56,197 

Long-term debt, net

 

 

1,627,842 

 

 

1,646,535 

Other long-term liabilities

 

 

166,766 

 

 

201,651 

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-149,648,826, Outstanding-149,708,825 as of December 31, 2014
Authorized-250,000,000, Issued-158,976,784, Outstanding-159,158,022 as of December 31, 2013

 

 

150 

 

 

159 

Additional paid in capital

 

 

2,620,328 

 

 

2,873,579 

Accumulated other comprehensive loss, net

 

 

(36,280)

 

 

(17,500)

Retained earnings

 

 

1,495,540 

 

 

1,275,206 

Total stockholders’ equity

 

 

4,079,738 

 

 

4,131,444 

Total liabilities and stockholders’ equity

 

$

7,377,389 

 

$

7,411,307 

 

 

 

 

 

 

 

See accompanying notes to consolidated financial statements.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

29

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Operations

Years Ended December 31, 2014, 2013 and 2012

(in thousands, except per share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

Revenues:

 

 

 

 

 

 

 

 

 

Services

 

$

3,466,279 

 

$

3,371,847 

 

$

3,315,072 

Rentals

 

 

1,090,343 

 

 

978,210 

 

 

978,204 

Total revenues

 

 

4,556,622 

 

 

4,350,057 

 

 

4,293,276 

Costs and expenses:

 

 

 

 

 

 

 

 

 

Cost of services (exclusive of items shown separately below)

 

 

2,308,270 

 

 

2,244,881 

 

 

2,100,168 

Cost of rentals (exclusive of items shown separately below)

 

 

426,563 

 

 

388,709 

 

 

369,252 

Depreciation, depletion, amortization and accretion

 

 

650,814 

 

 

604,441 

 

 

488,061 

General and administrative expenses

 

 

624,371 

 

 

597,778 

 

 

625,422 

Reduction in value of assets

 

 

 -

 

 

300,078 

 

 

 -

Income from operations

 

 

546,604 

 

 

214,170 

 

 

710,373 

Other income (expense):

 

 

 

 

 

 

 

 

 

Interest expense, net

 

 

(96,734)

 

 

(107,902)

 

 

(116,479)

Other expense

 

 

(7,681)

 

 

(4,627)

 

 

(2,317)

Loss on early extinguishment of debt

 

 

 -

 

 

(884)

 

 

(2,294)

Gain on sale of equity-method investment

 

 

 -

 

 

 -

 

 

17,880 

Income from continuing operations before income taxes

 

 

442,189 

 

 

100,757 

 

 

607,163 

Income taxes

 

 

161,399 

 

 

55,272 

 

 

223,246 

Net income from continuing operations

 

 

280,790 

 

 

45,485 

 

 

383,917 

Loss from discontinued operations, net of income tax

 

 

(22,973)

 

 

(156,903)

 

 

(17,982)

Net income (loss)

 

$

257,817 

 

$

(111,418)

 

$

365,935 

Earnings (loss) per share information:

 

 

 

 

 

 

 

 

 

Basic:

 

 

 

 

 

 

 

 

 

Continuing operations

 

$

1.81 

 

$

0.29 

 

$

2.57 

Discontinued operations

 

 

(0.15)

 

 

(0.99)

 

 

(0.12)

Basic earnings (loss) per share

 

$

1.66 

 

$

(0.70)

 

$

2.45 

Diluted:

 

 

 

 

 

 

 

 

 

Continuing operations

 

$

1.79 

 

$

0.28 

 

$

2.54 

Discontinued operations

 

 

(0.14)

 

 

(0.97)

 

 

(0.12)

Diluted earnings (loss) per share

 

$

1.65 

 

$

(0.69)

 

$

2.42 

Cash dividends declared per share

 

$

0.24 

 

$

0.08 

 

$

 -

Weighted average common shares used in computing

 

 

 

 

 

 

 

 

 

earnings (loss) per share:

 

 

 

 

 

 

 

 

 

Basic

 

 

155,154 

 

 

159,206 

 

 

149,288 

Incremental common shares from stock based compensation

 

 

1,572 

 

 

1,574 

 

 

1,818 

Diluted

 

 

156,726 

 

 

160,780 

 

 

151,106 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income (Loss)

Years Ended December 31, 2014, 2013 and 2012

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

Net income (loss)

 

$

257,817 

 

$

(111,418)

 

$

365,935 

Unrealized net loss on available-for-sale securities, net of tax

 

 

 -

 

 

(256)

 

 

(897)

Reclassification adjustment of unrealized net loss on available-for-sale securities, net of tax

 

 

1,153 

 

 

 -

 

 

 -

Change in cumulative translation adjustment, net of tax

 

 

(19,933)

 

 

2,073 

 

 

8,516 

Comprehensive income (loss)

 

$

239,037 

 

$

(109,601)

 

$

373,554 

 

 

 

 

 

 

 

 

 

 

See accompanying notes to consolidated financial statements.

 

 

 

30

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Changes in Stockholders’ Equity

Years Ended December 31, 2014, 2013, and 2012

(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, 2011

 

80,425,443 

 

$

80 

 

$

447,007 

 

$

(26,936)

 

$

1,033,448 

 

$

1,453,599 

Net income

 

 -

 

 

 -

 

 

 -

 

 

 -

 

 

365,935 

 

 

365,935 

Foreign currency translation adjustment

 

 -

 

 

 -

 

 

 -

 

 

8,516 

 

 

 -

 

 

8,516 

Unrealized net loss on available-for-sale securities

 

 -

 

 

 -

 

 

 -

 

 

(897)

 

 

 -

 

 

(897)

Stock-based compensation expense, net of forfeitures

 

295,366 

 

 

 -

 

 

23,737 

 

 

 -

 

 

 -

 

 

23,737 

Exercise of stock options

 

1,962,248 

 

 

 

 

14,775 

 

 

 -

 

 

 -

 

 

14,777 

Shares withheld and retired

 

(135,128)

 

 

 -

 

 

(3,424)

 

 

 -

 

 

 -

 

 

(3,424)

Tax benefit from stock-based compensation

 

 -

 

 

 -

 

 

(675)

 

 

 -

 

 

 -

 

 

(675)

Shares issued under Employee Stock Purchase Plan

 

147,026 

 

 

 -

 

 

3,360 

 

 

 -

 

 

 -

 

 

3,360 

Shares issued to pay performance share units

 

43,259 

 

 

 -

 

 

1,140 

 

 

 -

 

 

 -

 

 

1,140 

Vesting of restricted stock assumed with acquisition
    of Complete Production Services, Inc.

 

64,356 

 

 

 -

 

 

 -

 

 

 -

 

 

 -

 

 

 -

Shares issued in connection with acquisition of
     Complete Production Services, Inc.

 

74,699,065 

 

 

76 

 

 

2,361,391 

 

 

 -

 

 

 -

 

 

2,361,467 

Fair value of options exchanged in connection with
    acquisition of Complete Production Services, Inc.

 

 -

 

 

 -

 

 

3,932 

 

 

 -

 

 

 -

 

 

3,932 

Share issuance cost

 

 -

 

 

 -

 

 

(388)

 

 

 -

 

 

 -

 

 

(388)

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 

 

 

 

 

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 Production Services, Inc.

 

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 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying notes to consolidated financial statements.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

31

 


 

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Changes in Stockholders’ Equity (continued)

Years Ended December 31, 2014, 2013, and 2012

(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, 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 ($0.08 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 

 

 

 

 

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 Production Services, Inc.

 

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.

 

 

 

 

 

 

 

 

 

 

 

 

 

32

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

Years Ended December 31, 2014, 2013 and 2012

(in thousands)

 

 

 

2014

 

2013

 

2012

Cash flows from operating activities:

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

257,817 

 

$

(111,418)

 

$

365,935 

Adjustments to reconcile net income (loss) to net cash provided by operating
  activities:

 

 

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

 

 

652,143 

 

 

625,928 

 

 

510,526 

Loss on early extinguishment of debt

 

 

 -

 

 

884 

 

 

3,460 

Deferred income taxes

 

 

(49,567)

 

 

14,435 

 

 

11,218 

Reduction in value of assets

 

 

 -

 

 

419,380 

 

 

 -

Stock based compensation expense

 

 

42,748 

 

 

35,832 

 

 

36,570 

Amortization of debt issuance costs

 

 

8,110 

 

 

8,919 

 

 

9,856 

(Gains) losses on sales of assets and businesses

 

 

(12,777)

 

 

(657)

 

 

5,763 

Other reconciling items, net

 

 

(6,803)

 

 

(1,783)

 

 

(12,377)

Changes in operating assets and liabilities, net of acquisitions:

 

 

 

 

 

 

 

 

 

Accounts receivable

 

 

(9,487)

 

 

85,423 

 

 

(42,946)

Inventory and other current assets

 

 

53,594 

 

 

(70,995)

 

 

62,720 

Accounts payable

 

 

36,450 

 

 

(32,304)

 

 

(30,977)

Accrued expenses

 

 

16,411 

 

 

25,154 

 

 

(26,107)

Income taxes

 

 

46,134 

 

 

(162,148)

 

 

152,093 

Other, net

 

 

(1,762)

 

 

56,158 

 

 

(10,691)

Net cash provided by operating activities

 

 

1,033,011 

 

 

892,808 

 

 

1,035,043 

Cash flows from investing activities:

 

 

 

 

 

 

 

 

 

Payments for capital expenditures

 

 

(616,102)

 

 

(608,960)

 

 

(1,141,922)

Sale of available-for-sale securities

 

 

10,622 

 

 

 -

 

 

41,874 

Change in restricted cash held for acquisition of business

 

 

 -

 

 

 -

 

 

785,280 

Acquisitions of businesses, net of cash acquired

 

 

(24,327)

 

 

(23,797)

 

 

(1,091,161)

Cash proceeds from sale of equity method investment

 

 

 -

 

 

 -

 

 

34,087 

Cash proceeds from sales of assets and businesses

 

 

147,305 

 

 

6,292 

 

 

193,166 

Cash proceeds from insurance settlement

 

 

 -

 

 

22,650 

 

 

 -

Other

 

 

7,767 

 

 

(1,753)

 

 

21,558 

         Net cash used in investing activities

 

 

(474,735)

 

 

(605,568)

 

 

(1,157,118)

Cash flows from financing activities:

 

 

 

 

 

 

 

 

 

Proceeds from revolving line of credit

 

 

14,736 

 

 

581,771 

 

 

696,439 

Payments on revolving line of credit

 

 

(14,736)

 

 

(581,771)

 

 

(771,439)

Proceeds from issuance of long-term debt

 

 

2,602 

 

 

 -

 

 

400,000 

Principal payments on long-term debt

 

 

(21,564)

 

 

(170,000)

 

 

(177,546)

Payment of debt acquisition costs

 

 

 -

 

 

 -

 

 

(25,274)

Share repurchases

 

 

(299,734)

 

 

(10,627)

 

 

 -

Cash dividends

 

 

(49,756)

 

 

 -

 

 

 -

Proceeds from exercise of stock options

 

 

10,560 

 

 

6,264 

 

 

14,777 

Other

 

 

724 

 

 

(6,840)

 

 

(5,973)

         Net cash provided by (used in) financing activities

 

 

(357,168)

 

 

(181,203)

 

 

130,984 

         Effect of exchange rate changes on cash

 

 

(4,109)

 

 

(1,189)

 

 

2,016 

         Net increase in cash and cash equivalents

 

 

196,999 

 

 

104,848 

 

 

10,925 

Cash and cash equivalents at beginning of period

 

 

196,047 

 

 

91,199 

 

 

80,274 

Cash and cash equivalents at end of period

 

$

393,046 

 

$

196,047 

 

$

91,199 

 

 

 

 

 

 

 

 

 

 

See accompanying notes to consolidated financial statements.

33

 


 

 

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Years Ended December 31, 2014, 2013 and 2012

 (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 2014 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 (formerly, Subsea 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 2014. In 2013 and 2012, EOG Resources, Inc. accounted for approximately 10% and 13%, respectively, of total revenue, primarily within the Onshore Completion and Workover segment.

 

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.

34

 


 

 

Accounts Receivable and Allowances

 

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

 

Inventory

 

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

 

Property, Plant and Equipment

 

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

 

Capitalized Interest

 

The Company capitalizes interest on the cost of major capital projects during the active construction period.  Capitalized interest is added to the cost of the underlying assets and is amortized over the useful lives of the assets.  The Company capitalized $1.0 million, $2.4 million and $7.7 million of interest expense in the years ended December 31, 2014, 2013 and 2012, respectively, for various capital projects.

 

Reduction in Value of Long-Lived Assets

 

Long-lived assets, such as property, plant and equipment and purchased intangibles subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable.  Recoverability of assets to be held and used is assessed by a comparison of the carrying amount of such assets to their fair value calculated, in part, by the estimated undiscounted future cash flows expected to be generated by the assets.  Cash flow estimates are based upon, among other things, historical results adjusted to reflect the best estimate of future market rates, utilization levels, and operating performance.  Estimates of cash flows may differ from actual cash flows due to, among other things, changes in economic conditions or changes in an asset’s operating performance.  The Company’s assets are grouped by subsidiary or division for the impairment testing, which represent the lowest level of identifiable cash flows.  The Company has long-lived assets, such as facilities, utilized by multiple operating divisions that do not have identifiable cash flows.  Impairment testing for these long-lived assets is based on the consolidated entity.  If the asset grouping’s fair value is less than the carrying amount of those items, impairment losses are recorded in the amount by which the carrying amount of such assets exceeds the fair value.  Assets to be disposed of are reported at the lower of the carrying amount or fair value less estimated costs to sell.  The net carrying value of assets not fully recoverable is reduced to fair value.  The estimate of fair value represents the Company’s best estimate based on industry trends and reference to market transactions and is subject to variability.  The oil and gas industry is cyclical and estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows, can have a significant impact on the carrying values of these assets and, in periods of prolonged down cycles, may result in impairment charges.  See note 9 for a discussion of reduction in values of long-lived assets recorded during 2013.

35

 


 

 

Goodwill

 

The following table summarizes the activity for the Company’s goodwill for the years ended December 31, 2014 and 2013 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Onshore

 

 

 

 

 

 

 

 

 

 

Drilling

 

Completion

 

 

 

 

 

 

 

 

 

 

Products

 

and Workover

 

Production

 

Technical

 

 

 

 

and Services

 

Services

 

Services

 

Solutions

 

Total

Balance, December 31, 2012

$

144,947 

 

$

1,418,050 

 

$

878,052 

 

$

91,016 

 

$

2,532,065 

Acquisition activities

 

 -

 

 

1,500 

 

 

15,099 

 

 

 -

 

 

16,599 

Disposition activities

 

(756)

 

 

 -

 

 

 -

 

 

 -

 

 

(756)

Reduction in value of assets

 

 -

 

 

 -

 

 

 -

 

 

(91,016)

 

 

(91,016)

Foreign currency translation adjustment

 

681 

 

 

 -

 

 

536 

 

 

 -

 

 

1,217 

Balance, December 31, 2013

 

144,872 

 

 

1,419,550 

 

 

893,687 

 

 

 -

 

 

2,458,109 

Acquisition activities

 

 -

 

 

 -

 

 

13,909 

 

 

 -

 

 

13,909 

Disposition activities

 

 -

 

 

 -

 

 

 -

 

 

 -

 

 

 -

Foreign currency translation adjustment

 

(2,033)

 

 

 -

 

 

(1,576)

 

 

 -

 

 

(3,609)

Balance, December 31, 2014

$

142,839 

 

$

1,419,550 

 

$

906,020 

 

$

 -

 

$

2,468,409 

 

Goodwill is tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value.  During the third quarter of 2014, the Company changed its annual goodwill impairment testing date from December 31 to October 1. Management considers this accounting change preferable because it allows the Company additional time to complete the annual goodwill test. This change does not accelerate, delay, avoid, or cause an impairment charge, nor does this change result in adjustments to previously issued financial statements. In order to estimate the fair value of the reporting units (which is consistent with the reported business segments), the Company used a weighting of the discounted cash flow method and the public company guideline method of determining fair value of each reporting unit. The Company weighted the discounted cash flow method 80% and the public company guideline method 20% due to differences between the Company’s reporting units and the peer companies’ size, profitability and diversity of operations.  In order to validate the reasonableness of the estimated fair values obtained for the reporting units, a reconciliation of fair value to market capitalization was performed for each unit on a standalone basis.  A control premium, derived from market transaction data, was used in this reconciliation to ensure that fair values were reasonably stated in conjunction with the Company’s capitalization.  These fair value estimates were then compared to the carrying value of the reporting units.  No impairment loss was recognized during the year ended December 31, 2014, as the fair value of each of the reporting units exceeded its carrying amount. Based on the most recent goodwill impairment test, the fair values of the Drilling Products and Services and Onshore Completion and Workover Services segments were substantially in excess of their carrying values.  The fair value of the Production Services segment exceeded its carrying value by approximately 9%.  A significant amount of judgment was involved in performing these evaluations since the results are based on estimated future events. 

 

See note 9 for a discussion of reduction in value of goodwill recorded during 2013.  As of December 31, 2014, the Company’s accumulated reduction in value of goodwill was $91.0 million.

 

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

 

Notes Receivable

 

The Company’s wholly owned subsidiary, Wild Well Control, Inc. (Wild Well) has decommissioning obligations related to its ownership of the Bullwinkle platform. Notes receivable consist of a commitment from the seller of the platform towards its eventual abandonment.  Pursuant to an agreement with the seller, the Company will invoice the seller an agreed upon amount at the completion of certain decommissioning activities.  The gross amount of this obligation totaled $115.0 million and is recorded at present value using an effective interest rate of 6.58%.  The related discount is amortized to interest income based on the expected timing of the platform’s removal.  The Company recorded interest income related to notes receivable of $1.6 million, $2.6 million and $2.8 million for the years ended December 31, 2014, 2013 and 2012, respectively.

 

36

 


 

Intangible and Other Long-Term Assets

 

Intangible and other long-term assets consist of the following as of December 31, 2014 and 2013 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2014

 

December 31, 2013

 

 

Gross

 

Accumulated

 

Net

 

Gross

 

Accumulated

 

Net

 

 

Amount

 

Amortization

 

Balance

 

Amount

 

Amortization

 

Balance

Customer relationships

 

$

339,695 

 

$

(64,954)

 

$

274,741 

 

$

335,590 

 

$

(44,117)

 

$

291,473 

Tradenames

 

 

41,265 

 

 

(13,151)

 

 

28,114 

 

 

45,025 

 

 

(9,175)

 

 

35,850 

Non-compete agreements

 

 

4,487 

 

 

(3,281)

 

 

1,206 

 

 

4,256 

 

 

(2,163)

 

 

2,093 

Debt issuance costs

 

 

63,829 

 

 

(36,360)

 

 

27,469 

 

 

63,829 

 

 

(28,250)

 

 

35,579 

Deferred compensation
    plan assets

 

 

12,982 

 

 

 -

 

 

12,982 

 

 

13,731 

 

 

 -

 

 

13,731 

Escrowed cash

 

 

58,421 

 

 

 -

 

 

58,421 

 

 

58,406 

 

 

 -

 

 

58,406 

Other

 

 

18,356 

 

 

(929)

 

 

17,427 

 

 

14,597 

 

 

(862)

 

 

13,735 

Total

 

$

539,035 

 

$

(118,675)

 

$

420,360 

 

$

535,434 

 

$

(84,567)

 

$

450,867 

 

Customer relationships, tradenames, and non-compete agreements are amortized using the straight line method over the life of the related asset with weighted average useful lives of 17 years, 10 years, and 3 years, respectively.  Amortization expense (exclusive of debt issuance costs) was $25.9 million, $26.2 million and $22.6 million for the years ended December 31, 2014, 2013 and 2012, respectively.  Estimated annual amortization of intangible assets (exclusive of debt acquisition costs) will be approximately $25.6 million for 2015, $24.8 million for 2016, $24.0 million for 2017, $23.9 million for 2018 and $23.7 million for 2019, excluding the effects of any acquisitions or dispositions subsequent to December 31, 2014. 

 

Debt issuance costs are amortized using the effective interest method over the life of the related debt agreements with a weighted average useful life of 7 years.  Amortization of debt issuance costs is recorded in interest expense, net of amounts capitalized within the consolidated statements of operations.

 

In accordance with the asset purchase agreement between Wild Well and the seller to acquire the Bullwinkle platform and its related assets and to assume the related decommissioning obligations, Wild Well obtained a $50.0 million performance bond and funded $50.0 million into an escrow account.  Included in intangible and other long-term assets, net is escrowed cash related to the Bullwinkle platform of $50.4 million as of December 31, 2014 and 2013.  

 

Decommissioning Liabilities

 

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

 

The Company’s decommissioning liabilities associated with the Bullwinkle platform and its related assets consist of costs related to the plugging of wells, the removal of the related facilities and equipment, and site restoration.  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 2013, as a result of an increase in third party drilling activity in the vicinity of the Bullwinkle platform, the Company believed new economic opportunities existed for additional production handling agreements with those third party production companies utilizing the Bullwinkle platform.  As a result, the Company revised its estimates relating to the timing of decommissioning work on its Bullwinkle assets, including a 10 year postponement of the platform decommissioning to an estimated date of 2038.  This change in estimate resulted in a reduction in the present value of decommissioning liabilities.  Further, as of December 31, 2013, the Company anticipated that it would be able to decommission several depleted wells that are part of the Bullwinkle assets based on the estimates received from engineers regarding platform availability during 2014.  As a result, as of December 31, 2013, the decommissioning liabilities associated with those wells were classified as current liabilities on the consolidated balance sheet.  Based on revised estimates received during 2014, the Company did not anticipate decommissioning any of the wells during the next twelve months.  As a result, all of the decommissioning liabilities were classified as long-term liabilities on the consolidated balance sheet as of December 31, 2014. 

 

37

 


 

The following table summarizes the activity for the Company’s decommissioning liabilities for the years ended December 31, 2014 and 2013 (in thousands): 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

Decommissioning liabilities, December 31, 2013 and 2012, respectively

 

$

83,519 

 

$

93,053 

Liabilities acquired and incurred

 

 

866 

 

 

445 

Liabilities settled

 

 

(579)

 

 

(87)

Accretion

 

 

4,470 

 

 

5,320 

Revisions in estimated timing and cash flows

 

 

(276)

 

 

(15,212)

Total decommissioning liabilities, December 31, 2014 and 2013, respectively

 

$

88,000 

 

$

83,519 

 

 

 

 

 

 

 

 

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 accounts for the revenue and related costs on large-scale platform decommissioning contracts on the percentage-of-completion method utilizing costs incurred as a percentage of total estimated costs.  The Company recognizes oil and gas revenue from its interests in producing wells as oil and natural gas is sold.

 

Taxes Collected from Customers

 

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

 

Income Taxes

 

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

 

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

 

Earnings per Share

 

Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of shares of common stock outstanding during the period.   Diluted earnings per share is computed in the same manner as basic earnings per share except that the denominator is increased to include the number of additional shares of common stock that could have been outstanding assuming the exercise of stock options and conversion of restricted stock units.

 

Stock options for approximately 1,100,000 shares, 1,100,000 shares and 2,100,000 shares of the Company’s common stock were excluded in the computation of diluted earnings per share for the years ended December 31, 2014, 2013 and 2012, respectively, as the effect would have been anti-dilutive. 

 

Cash Dividends

 

In December 2013, the Company’s Board of Directors approved initiating a quarterly dividend program and declared an initial quarterly dividend of $0.08 per share on its outstanding common stock.  The dividend payable of $12.8 million was included in accrued expenses in the consolidated balance sheet as of December 31, 2013.  The initial dividend was paid on February 19, 2014 to all stockholders of record as of January 30, 2014.  During 2014, $49.8 million of dividends was paid to stockholders.

 

38

 


 

Discontinued Operations

 

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

 

Fair Value Measurements

 

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

 

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

 

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

 

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

 

Financial Instruments

 

The fair value of the Company’s financial instruments of cash equivalents, accounts receivable, accounts payable, accrued expenses and borrowings under its credit facility approximates their carrying amounts due to their short maturity or market interest rates.  The fair value of the Company’s debt was $1,624.3 million and $1,789.0 million as of December 31, 2014 and 2013, 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.  For the years ended December 31, 2014, 2013 and 2012, the Company recorded $7.3 million, $7.1 million and $2.9 million of foreign currency losses, respectively.

 

Stock-Based Compensation

 

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

39

 


 

 

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 approximately 61% and 60% of its long-term debt as of December 31, 2014 and 2013, 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, 2014 and 2013.

 

Self-Insurance Reserves

 

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

 

Recently Issued Accounting Pronouncements

 

In May 2014, the Financial Accounting Standards Board 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, 2017. 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.

 

In April 2014, the Financial Accounting Standards Board 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) that occur after December 31, 2014.  The Company has adopted the accounting guidance as of January 1, 2015. 

 

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.

40

 


 

 

(2) Supplemental Cash Flow Information

The following table includes the Company’s supplemental cash flow information for the years ended December 31, 2014, 2013 and 2012 (in thousands): 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

Cash paid for interest, net of amounts capitalized

 

$

102,880 

 

$

97,129 

 

$

109,112 

 

 

 

 

 

 

 

 

 

 

Cash paid for income taxes, net of refunds

 

$

127,132 

 

$

164,158 

 

$

42,261 

 

 

 

 

 

 

 

 

 

 

Details of business acquisitions:

 

 

 

 

 

 

 

 

 

 Fair value of assets

 

$

29,468 

 

$

34,964 

 

$

4,364,872 

 Fair value of liabilities

 

 

(5,125)

 

 

(10,942)

 

 

(695,243)

 Common stock issued

 

 

 -

 

 

 -

 

 

(2,361,466)

 Cash paid

 

 

24,343 

 

 

24,022 

 

 

1,308,163 

 Less cash acquired

 

 

(16)

 

 

(225)

 

 

(217,002)

   Net cash paid for acquisitions

 

$

24,327 

 

$

23,797 

 

$

1,091,161 

 

 

 

 

 

 

 

 

 

 

Non-cash investing activity:

 

 

 

 

 

 

 

 

 

Capital expenditures included in accounts payable,

 

 

 

 

 

 

 

 

 

 accrued expenses and other long term liabilities

 

$

49,118 

 

$

70,463 

 

$

61,035 

 

 

 

 

 

 

 

 

 

 

Non-cash financing activity:

 

 

 

 

 

 

 

 

 

Cash dividends declared

 

$

 -

 

$

12,759 

 

$

 -

 

 

 

 

 

 

 

 

 

 

 

 

 

(3) Discontinued Operations

 

2014

 

During 2014, the Company conducted a strategic review and analysis of its subsea construction business. As of December 31, 2014, the Company has sold $131.1 million of the assets related to this business and is committed to sell the remaining assets and exit the subsea construction business. The disposition of the remaining assets is expected to be completed by the end of the first half of 2015.

 

During 2014, the Company also made a decision to discontinue its conventional decommissioning business. As of December 31, 2014, the Company was committed to sell the assets of and exit the conventional decommissioning business. The disposition of assets is expected to be completed by the end of the first half of 2015.

Both the subsea construction business and conventional decommissioning business were included in the Technical Solutions segment, formerly referred to as the Subsea and Technical Solutions segment. As of December 31, 2014, the assets and liabilities of these businesses were classified as held for sale. For the years ended December 31, 2014, 2013 and 2012, the results of operations of these businesses 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 for the years ended December 31, 2014, 2013 and 2012 (in thousands): 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

Revenues

 

$

145,463 

 

$

261,767 

 

$

274,792 

 

 

 

 

 

 

 

 

 

 

Loss from discontinued operations, net of tax (benefit) expense of ($19,330),
    ($15,439) and $1,774, for the years ended December 31, 2014, 2013 and
    2012, respectively

 

$

(22,973)

 

$

(156,903)

 

$

(775)

 

 

 

 

 

 

 

 

 

 

 

For the year ended December 31, 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.

 

For the year ended December 31, 2013, loss from discontinued operations included a  $119.3 million expense related to the reduction in value of assets.  The expense relating to the reduction in value of assets was comprised of a  $98.3 million expense primarily relating to

41

 


 

certain marine vessels included in our 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 our conventional decommissioning business.

 

The following summarizes the assets and liabilities related to the businesses reported as discontinued operations as of December 31, 2014 and 2013 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

Accounts receivable, net

 

$

16,701 

 

$

26,858 

Prepaid expenses

 

 

2,463 

 

 

8,164 

Inventory and other current assets

 

 

5,576 

 

 

63,618 

Current assets

 

$

24,740 

 

$

98,640 

Property, plant and equipment, net

 

 

91,171 

 

 

217,089 

Intangible and other long-term assets, net

 

 

769 

 

 

4,854 

Long-term assets

 

$

91,940 

 

$

221,943 

Accounts payable

 

 

20,530 

 

 

13,449 

Accrued expenses

 

 

24,496 

 

 

52,133 

Current liabilities

 

$

45,026 

 

$

65,582 

Other long-term liabilities

 

$

16,814 

 

$

21,801 

 

Assets and liabilities held for sale include a capital lease for a dynamically positioned subsea vessel.  Such amounts are recorded at the present value of the lease payments.  The vessel’s gross asset value under the capital lease was $37.6 million at inception and accumulated depreciation through December 31, 2014 and 2013 was $17.4 million and $16.4 million, respectively.  As of December 31, 2014, $16.8 million of other long-term liabilities and $4.6 million of accounts payable related to this capital lease are included in the liabilities held for sale.  As of December 31, 2013, $21.4 million of other long-term liabilities and $4.2 million of accounts payable related to this capital lease are included in the liabilities held for sale.  In February 2015, the Company purchased this leased vessel for $45.2 million.  The purchase was made to facilitate the disposition of the vessel during the first half of 2015.    

 

2012

 

During 2012, the Company sold one of its derrick barges and received proceeds of $44.5 million, inclusive of selling costs. The Company recorded a pre-tax loss of $3.1 million, inclusive of $9.7 million of goodwill, during the year ended December 31, 2012 in connection with this sale. The operations and loss on the sale of this disposal group have been reported within loss from discontinued operations in the consolidated statement of operations for the year ended December 31, 2012.

 

During 2012, the Company sold 18 liftboats and related assets comprising its former Marine business. The Company received cash proceeds of $138.6 million, inclusive of working capital and selling costs. In connection with the sale, the Company repaid $12.5 million in U.S. Government guaranteed long-term financing. Additionally, the Company paid $4.0 million of make-whole premiums and wrote off $0.7 million of unamortized loan costs as a result of this repayment. The Company’s pre-tax loss on the disposal of this business recorded during 2012 was $10.0 million.

 

The following table summarizes the components of loss from discontinued operations, net of tax related to the dispositions of derrick barges and liftboats for the year ended December 31, 2012 (in thousands):

 

 

 

 

 

 

 

2012

Revenues

 

$

16,231 

 

 

 

 

Loss from discontinued operations, net of tax benefit of $620

 

$

(17,207)

 

 

 

 

 

(4) Acquisitions

 

2014

 

In October 2014, the Company acquired all of the equity interests in a company that provides well testing and slickline services in India.  The purchase price of the acquisition was approximately $22.0 million.  Goodwill of $13.9 million was recognized as a result of this acquisition and was calculated as the excess of the consideration paid over the net assets recognized and represents estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. None of the goodwill related to this acquisition will be deductible for tax purposes. All of the goodwill was assigned to the Production Services segment.

42

 


 

 

2013

 

In March 2013, the Company acquired all of the equity interests in a company that provides cementing services in Colombia.  The Company paid approximately $20.4 million at closing and repaid $3.0 million of the acquired company’s debt. In 2014, the Company paid $2.4 million as a result of a post-closing process to reconcile the net working capital of the acquired company and settlement of certain liabilities. Goodwill of $15.1 million was recognized as a result of this acquisition and was calculated as the excess of the consideration paid over the net assets recognized and represents estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. None of the goodwill related to this acquisition will be deductible for tax purposes. All of the goodwill was assigned to the Production Services segment.

 

2012

 

In February 2012, the Company acquired Complete in a cash and stock merger transaction valued at approximately $2,914.8 million.  Complete focused on providing specialized completion and production services and products that help oil and gas companies develop hydrocarbon reserves, reduce costs and enhance production.  Complete’s operations were located throughout the U.S. and Mexico. The acquisition of Complete substantially expanded the size and scope of the Company’s services. 

 

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

In August 2012, the Company acquired all of the equity interests in a company that provides mechanical wireline, electric line and well testing services to oil and gas companies in Argentina.  The Company paid approximately $37.6 million in cash related to this acquisition, including approximately $6.5 million of contingent consideration which was paid during 2013 based upon achievement of certain performance metrics.  Goodwill of $22.6 million was recognized as a result of this acquisition and was calculated as the excess of the consideration paid over the net assets recognized and represents estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized.  None of the goodwill related to this acquisition will be deductible for tax purposes.  The goodwill has been allocated to the Onshore Completion and Workover Services, the Production Services, and the Technical Solutions segments based on each segment’s relative fair value.

 

(5) Property, Plant and Equipment

A summary of property, plant and equipment as of December 31, 2014 and 2013 is as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

Buildings, improvements and leasehold improvements

 

$

328,651 

 

$

284,273 

Marine vessels and equipment

 

 

55,494 

 

 

137,955 

Machinery and equipment

 

 

4,126,570 

 

 

3,864,599 

Automobiles, trucks, tractors and trailers

 

 

66,032 

 

 

64,102 

Furniture and fixtures

 

 

75,631 

 

 

72,563 

Construction-in-progress

 

 

102,895 

 

 

211,017 

Land

 

 

58,814 

 

 

56,786 

Oil and gas producing assets

 

 

189,294 

 

 

137,910 

Total

 

 

5,003,381 

 

 

4,829,205 

Accumulated depreciation and depletion

 

 

(2,269,542)

 

 

(1,827,011)

Property, plant and equipment, net

 

$

2,733,839 

 

$

3,002,194 

 

The Company had $93.3 million and $75.0 million of leasehold improvements as of December 31, 2014 and 2013, 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 $620.6 million, $572.9 million, and $460.2 million for the years ended December 31, 2014, 2013 and 2012, respectively.

 

43

 


 

(6) Inventory and Other Current Assets

Inventory and other current assets includes $165.6 million and $162.9 million of inventory as of December 31, 2014 and 2013, respectively.  The components of inventory balances as of December 31, 2014 and 2013 are as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

Finished goods

 

$

72,788 

 

$

65,621 

Raw materials

 

 

29,718 

 

 

20,764 

Work-in-process

 

 

20,317 

 

 

20,064 

Supplies and consumables

 

 

42,739 

 

 

56,470 

Total

 

$

165,562 

 

$

162,919 

 

 

 

 

 

 

 

 

As of December 31, 2013, inventory and other current assets included $63.2 million of costs incurred and estimated earnings in excess of billings on uncompleted contracts.  The Company follows the percentage-of-completion method of accounting for applicable contracts.

   

As of December 31, 2013, inventory and other current assets also included $8.8 million of available-for-sale securities recorded at fair value. These available-for-sale securities consisted of approximately 1.4 million shares of SandRidge Energy, Inc. (SandRidge) common stock held by the Company.  During 2014, the Company sold all of its remaining shares of SandRidge common stock for $10.6 million. In connection with the sale, the Company reversed $1.2 million of previously recorded unrealized losses, of which $1.8 million was reclassified out of accumulated other comprehensive loss, net of tax benefit of $0.6 million.

During the year ended December 31, 2013, the Company recorded an unrealized loss on these securities of $0.4 million, of which $0.3 million was reported within accumulated other comprehensive loss, net of tax benefit of $0.1 million.  During the year ended December 31, 2012, the Company recorded an unrealized loss on these securities of $1.4 million, of which $0.9 million was reported within accumulated other comprehensive loss, net of tax benefit of $0.5 million.  During 2012, the Company sold approximately 5.6 million shares of SandRidge stock for $41.9 million, resulting in a realized gain of $0.9 million. 

(7) Debt 

The Company’s long-term debt as of December 31, 2014 and 2013 consisted of the following (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

Term loan - interest payable monthly at floating rate and
    principal payable quarterly, due February 2017

 

$

345,000 

 

$

365,000 

Senior Notes - interest payable semiannually at 6 3/8%,
   due May 2019

 

 

500,000 

 

 

500,000 

Senior Notes - interest payable semiannually at 7 1/8%,
    due December 2021

 

 

800,000 

 

 

800,000 

Other

 

 

3,783 

 

 

1,535 

 

 

 

1,648,783 

 

 

1,666,535 

Less current portion

 

 

20,941 

 

 

20,000 

Long-term debt

 

$

1,627,842 

 

$

1,646,535 

 

Annual maturities of long-term debt for each of the five fiscal years following December 31, 2014 and thereafter are as follows (in thousands):

 

 

 

 

 

 

2015

$

20,941 

2016

 

21,134 

2017

 

306,085 

2018

 

623 

2019

 

500,000 

Thereafter

 

800,000 

   Total

$

1,648,783 

 

Credit Facility

 

The Company has a $1.0 billion bank credit facility, comprised of a $600 million revolving credit facility and a $400 million term loan.  As of December 31, 2014, $345 million was outstanding under the term loan.  The principal balance of the term loan is payable in installments of $5.0 million on the last day of each fiscal quarter, which began on June 30, 2012.  As of December 31, 2014, the Company

44

 


 

had no amounts outstanding under the revolving portion of its credit facility.  The Company had $44.2 million of letters of credit outstanding, which reduce the Company’s borrowing availability under this portion of the credit facility.     

 

Any amounts outstanding on the revolving portion of the credit facility and the term loan are due on February 7, 2017.  Amounts borrowed under the credit facility bear interest at LIBOR plus margins that depend on the Company’s credit rating

 

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. 

 

During 2012, the Company redeemed $150 million, or 50%, of the principal amount of its $300 million 6 7/8% unsecured senior notes due 2014 at 100% of face value.  This redemption resulted in a loss on early extinguishment of debt of $2.3 million related to the write off of debt acquisition costs and notes discount.  During 2013, the Company redeemed the remaining $150 million aggregate principal amount of its 6 7/8% unsecured senior notes due 2014 at 100% of face value using proceeds from the revolving portion of its credit facility.  The redemption resulted in a loss on early extinguishment of debt of $0.9 million related to the writeoff of unamortized debt acquisition costs and note discount.

 

 

(8) Stock-Based and Long-Term Compensation

The Company maintains various stock incentive plans that provide long-term incentives to the Company’s key employees, including officers and directors (Eligible Participants).  Under the stock incentive plan, the Company may grant incentive stock options, non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, other stock-based awards or any combination thereof to Eligible Participants. The Compensation Committee of the Company’s Board of Directors establishes the terms and conditions of any awards granted under the plans, provided that the exercise price of any stock options granted may not be less than the fair value of the common stock on the date of the grant.  Under the terms of the 2013 Stock Incentive Plan, approximately 8,000,000 shares of the Company’s common stock have been reserved for issuance to employees and non-employee directors.  As of December 31, 2014, approximately 5,400,000 shares of the Company’s common stock were available for future grants under the 2013 plan.

 

Total stock-based compensation expense and the associated tax benefits for the years ended December 31, 2014, 2013 and 2012 are as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Compensation Expense

 

 

 

 

2014

 

2013

 

2012

Stock options

 

$

3,900 

 

$

3,586 

 

$

4,829 

Restricted stock

 

 

15,800 

 

 

21,460 

 

 

16,981 

Restricted stock units

 

 

11,282 

 

 

 -

 

 

2,360 

Performance share units

 

 

10,688 

 

 

10,014 

 

 

11,894 

Strategic performance share units

 

 

2,404 

 

 

 -

 

 

 -

Total

 

$

44,074 

 

$

35,060 

 

$

36,064 

 

 

 

 

 

 

 

 

 

 

Tax Benefit

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

Stock options

 

$

1,443 

 

$

1,327 

 

$

1,787 

Restricted stock

 

 

5,846 

 

 

7,940 

 

 

6,283 

Restricted stock units

 

 

4,174 

 

 

 -

 

 

873 

Total

 

$

11,463 

 

$

9,267 

 

$

8,943 

 

Stock Options

 

The Company has granted non-qualified stock options under its stock incentive plans.  The stock options generally vest in equal installments over three years and expire in ten years.  Non-vested stock options are generally forfeitable upon termination of employment. 

 

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

45

 


 

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 history of dividend payouts.

 

The following table presents the fair value of stock option grants made during the years ended December 31, 2014, 2013 and 2012, as well as the options assumed and converted in the Complete acquisition, and the related assumptions used to calculate the fair value:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

Weighted average fair value of grants

 

$

6.95 

 

$

8.98 

 

$

21.76 

 

 

 

 

 

 

 

 

 

 

Black-Scholes-Merton Assumptions:

 

 

 

 

 

 

 

 

 

 Risk free interest rate

 

 

1.42% 

 

 

0.63% 

 

 

0.41% 

 Expected life (years)

 

 

 

 

 

 

 Volatility

 

 

34.50% 

 

 

48.41% 

 

 

55.27% 

 Dividend yield

 

 

1.23 

 

 

 -

 

 

 -

 

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

 

The Company has reported tax benefits of $5.6 million, $0.7 million, $0.6 million from the exercise of stock options for the years ended December 31, 2014, 2013 and 2012, respectively, as financing cash flows in the consolidated statement of cash flows.

The following table summarizes stock option activity for the year ended December 31, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Number of Options

 

Weighted Average Option Price

 

Weighted Average Remaining Contractual Term (in years)

 

Aggregate Intrinsic Value
(in thousands)

Outstanding as of December 31, 2013

 

4,857,376 

 

$

21.43 

 

4.8 

 

$

29,990 

Granted

 

567,084 

 

$

26.01 

 

 

 

 

 

Exercised

 

(880,687)

 

$

11.99 

 

 

 

 

 

Forfeited

 

(41,166)

 

$

25.39 

 

 

 

 

 

Expired

 

(18,102)

 

$

35.77 

 

 

 

 

 

Outstanding as of December 31, 2014

 

4,484,505 

 

$

23.76 

 

5.1 

 

$

4,095 

Exercisable as of December 31, 2014

 

3,660,017 

 

$

23.45 

 

4.3 

 

$

4,095 

Options expected to vest as of December 31, 2014

 

824,488 

 

$

25.14 

 

8.7 

 

$

 -

 

The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between the Company’s closing stock price on December 31, 2014 and the stock option price, multiplied by the number of “in-the-money” stock options) that would have been received by the stock option holders if all the options had been exercised on December 31, 2014.  The Company expects all of its remaining non-vested options to vest as they are primarily held by its officers and senior managers.

 

The total intrinsic value of stock options exercised (the difference between the stock price upon exercise and the stock option price) during the years ended December 31, 2014, 2013 and 2012 was $17.1 million, $5.1 million and $40.4 million, respectively.  The Company received $10.6 million, $6.3 million and $14.8 million during the years ended December 31, 2014, 2013 and 2012, respectively, from employee stock option exercises. 

 

46

 


 

The following table summarizes non-vested stock option activity for the year ended December 31, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Number of Options

 

Weighted Average Grant Date Fair Value

Non-vested as of December 31, 2013

 

 

536,498 

 

$

10.19 

Granted

 

 

567,084 

 

$

6.95 

Vested

 

 

(237,928)

 

$

13.39 

Forfeited

 

 

(41,166)

 

$

8.16 

Non-vested as of December 31, 2014

 

 

824,488 

 

$

7.83 

 

As of December 31, 2014, there was $4.2 million of unrecognized compensation expense related to non-vested stock options outstanding.  The Company expects to recognize approximately $2.4 million, $1.3 million and $0.5 million of compensation expense during the years 2015, 2016 and 2017, respectively, for these outstanding non-vested stock options.

Restricted Stock

 

Shares of restricted stock generally vest in equal annual installments over three years.  On February 7, 2012, the Company also assumed and converted 609,743 shares of restricted stock related to the Complete acquisition. Non-vested shares are generally forfeited upon termination of employment.  With the exception of the non-vested shares of restricted stock assumed and converted as a result of the Complete acquisition, holders of shares of restricted stock are entitled to all rights of a stockholder of the Company with respect to the restricted stock, including the right to vote the shares and receive any dividends or other distributions.  Compensation expense associated with restricted stock is measured based on the grant date fair value of our common stock.

 

A summary of the status of restricted stock for the year ended December 31, 2014 is presented in the table below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Number of Shares

 

Weighted Average Grant Date Fair Value

Non-vested as of December 31, 2013

 

 

2,020,448 

 

$

24.71 

Vested

 

 

(842,257)

 

$

27.27 

Forfeited

 

 

(155,911)

 

$

24.29 

Non-vested as of December 31, 2014

 

 

1,022,280 

 

$

24.08 

 

The weighted average grant-date fair value per share of restricted stock granted during the years ended December 31, 2013 and 2012 was $23.14 and $22.87, respectively.  No restricted stock was granted during the year ended December 31, 2014. The total fair value of restricted stock vested during the years ended December 31, 2014, 2013 and 2012 was $23.0 million, $9.6 million and $13.0 million, respectively.  As of December 31, 2014, there was approximately $10.4 million of unrecognized compensation expense related to non-vested restricted stock.  The Company expects to recognize approximately $10.0 million and $0.4 million during the years 2015 and 2016, respectively, for non-vested restricted stock. 

 

Restricted Stock Units

 

Beginning in 2014, Restricted Stock Units (RSUs) were granted to eligible employees. Prior to 2014, RSUs were only granted to non-employee directors. 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 stockholders, such as the right to vote share, but will accrue dividend equivalents 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 previous annual meeting.  Each RSU granted prior to 2013 represents the right to receive from the Company, within 30 days of the date the director ceases to serve on the Board, one share of the Company’s common stock.  Beginning with the RSU grants in 2013, 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.

 

47

 


 

A summary of the activity of restricted stock units for the year ended December 31, 2014 is presented in the table below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Number of Restricted Stock Units

 

Weighted Average Grant Date Fair Value

Outstanding as of December 31, 2013

 

 

324,481 

 

$

26.34 

Granted

 

 

1,352,184 

 

$

26.45 

Vested

 

 

(95,914)

 

$

30.65 

Forfeited

 

 

(164,274)

 

$

26.36 

Outstanding as of December 31, 2014

 

 

1,416,477 

 

$

26.40 

 

As of December 31, 2014, there was approximately $21.2 million of unrecognized compensation expense related to unvested RSUs.  The Company expects to recognize approximately $10.6 million, $10.0 million, and $0.6 million for the years ended 2015, 2016, and 2017, 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, 2014, there were 360,329 PSUs outstanding (115,788,  115,376 and 129,165 related to performance periods ending December 31, 2014, 2015 and 2016, respectively).  The Company has recorded both current and long-term liabilities for this liability-based compensation award.

 

In February 2014, the Company granted strategic performance share units (SPSUs) to certain executive officers of the Company.  The executives received a grant of SPSUs in February 2014 and will receive another grant in 2015, each with a specified target grant date value and each subject to a one-year performance period.  The SPSUs will be paid out in an equivalent number of the Company’s common stock with the number SPSUs earned based upon the level of the Company’s free cash flow achieved for each of the fiscal years ended December 31, 2014 and December 31, 2015, respectively. The earned SPSUs will vest in 2016 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. Shares were purchased under this plan for the time period ending December 31, 2014.

The following table summarizes ESPP activity for the years ended December 31, 2014, 2013 and 2012 (in thousands except shares):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

 

 

2013 Plan

 

2013 and 2007 Plans

 

2007 Plan

Cash received for shares issued

 

$

4,870 

 

$

4,124 

 

$

2,855 

Compensation expense

 

$

1,078 

 

$

947 

 

$

504 

Shares issued

 

 

246,480 

 

 

185,407 

 

 

147,026 

 

401(k)/Profit Sharing Plan

 

The Company maintains a defined contribution profit sharing plan for employees who have satisfied minimum service requirements.  Employees may contribute up to 75% of their eligible earnings to the plan subject to the contribution limitations imposed by the Internal Revenue Service.  In 2012, the Company adopted a “safe harbor” match for its 401(k) plan, which includes a nondiscretionary match of 100% of an employee’s contributions to the plan, up to 4% of the employee’s salary.  The Company made contributions of $16.7 million, $16.0 million and $8.4 million in the years ended December 31, 2014, 2013 and 2012, respectively.

 

48

 


 

Non-Qualified Deferred Compensation Plans

 

The Company has a non-qualified deferred compensation plan which allows certain highly compensated employees to defer up to 75% of their base salary, up to 100% of their bonus, and up to 100% of the cash portion of their PSU compensation to the plan.   The Company also has a non-qualified deferred compensation plan for its non-employee directors which allows each director to defer up to 100% of their cash compensation paid by the Company to the plan.  Additionally, participating directors may defer up to 100% of the shares of common stock they are entitled to receive in connection with the payout of RSUs. Payments are made to participants based on their annual enrollment elections and plan balances.  Participants earn a return on their deferred compensation that is based on hypothetical investments in certain mutual funds. Changes in market value of these hypothetical participant investments are reflected as an adjustment to the deferred compensation liability of the Company with an offset to compensation expense (see note 13).  As of December 31, 2014 and 2013, the liability of the Company to the participants was $14.7 million and $15.0 million, respectively, which reflects the accumulated participant deferrals and earnings (losses) as of that date.  These amounts are recorded in other long-term liabilities.  Additionally, as of December 31, 2014 and 2013, the Company had $2.3 million and $1.9 million in accounts payable in anticipation of pending payments.  For the years ended December 31, 2014, 2013 and 2012, the Company recorded compensation expense of $0.9 million, $2.5 million and $1.6 million, respectively, related to the earnings and losses of the deferred compensation plan liability. The Company makes contributions that approximate the participant deferrals into various investments, principally life insurance that is invested in mutual funds similar to the participants’ hypothetical investment elections.  Changes in market value of the investments and life insurance are reflected as adjustments to the deferred compensation plan asset with an offset to other income (expense).  As of December 31, 2014 and 2013, the deferred compensation plan asset was $13.0 million and $13.7 million, respectively, and is recorded in intangible and other long-term assets, net.  For the years ended December 31, 2014, 2013 and 2012, the Company recorded other income of $1.2 million, $2.4 million and $0.7 million, respectively, related to the net earnings and losses of the deferred compensation plan assets.

 

Supplemental Executive Retirement Plan

 

The Company has a supplemental executive retirement plan (SERP).  The SERP provides retirement benefits to the Company’s executive officers and certain other designated key employees. The SERP is an unfunded, non-qualified defined contribution retirement plan, and all contributions under the plan are unfunded credits to a notional account maintained for each participant. Under the SERP, the Company will generally make annual contributions to a retirement account based on age and years of service.  During 2014, 2013 and 2012, the participants in the plan received contributions ranging from 5% to 35% of salary and annual cash bonus, which totaled $1.2 million, $1.2 million and $1.8 million, respectively.  The Company may also make discretionary contributions to a participant’s account.  The Company recorded compensation expense of $1.6 million, $1.2 million and $2.4 million in general and administrative expenses for the years ended December 31, 2014, 2013 and 2012, respectively, inclusive of discretionary contributions.  During the years ended December 31, 2014, 2013 and 2012, the Company paid $3.0 million, $3.0 million and $6.7 million, respectively, to select participants in the SERP. 

 

(9) Reduction in Value of Assets

 

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

 

 

 

 

 

 

 

 

 

 

 

2013

 Reduction in value of long-lived assets and related other assets

 

$

180,320 

 Reduction in value of goodwill

 

 

91,016 

 Retirements of long-lived assets

 

 

14,418 

 Reduction in value of assets related to Venezuela exit activities

 

 

14,324 

   Total reduction in value of assets

 

$

300,078 

 

Reduction in Value of Long-Lived Assets

 

During the fourth quarter of 2013, the Company recorded $180.3 million in expense in connection with reduction in value of its long-lived assets and related other assets.  The reduction in value of assets expense was comprised of $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 an $3.0 million expense 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 the fourth quarter of 2013, the demand for these services continued to decline and the forecast for these markets did not indicate a timely recovery sufficient to support the carrying values of these assets.  The reduction in value of assets in the Onshore Completion and Workover Services segment related to the reduction in carrying values of

49

 


 

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.

 

Reduction in Value of Goodwill

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

 

Retirements of Long-Lived Assets

 

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 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 the years ended December 31, 2013 and 2012, the Company generated $9.5 million and $20.5 million, respectively, in revenue from its operations in Venezuela.

 

(10) Income Taxes

 

The components of income (loss) from continuing operations before income taxes for the years ended December 31, 2014, 2013 and 2012 are as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

Domestic

 

$

372,672 

 

$

165,463 

 

$

554,675 

Foreign

 

 

69,517 

 

 

(64,706)

 

 

52,488 

 

 

$

442,189 

 

$

100,757 

 

$

607,163 

 

The components of income tax expense (benefit) for the years ended December 31, 2014, 2013 and 2012 are as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

Current:

 

 

 

 

 

 

 

 

 

 Federal

 

$

150,997 

 

$

19,897 

 

$

119,797 

 State

 

 

11,339 

 

 

10,816 

 

 

14,155 

 Foreign

 

 

36,287 

 

 

25,613 

 

 

33,279 

 

 

 

198,623 

 

 

56,326 

 

 

167,231 

Deferred:

 

 

 

 

 

 

 

 

 

 Federal

 

 

(33,172)

 

 

(6,341)

 

 

54,718 

 State

 

 

648 

 

 

386 

 

 

915 

 Foreign

 

 

(4,700)

 

 

4,901 

 

 

382 

 

 

 

(37,224)

 

 

(1,054)

 

 

56,015 

 

 

$

161,399 

 

$

55,272 

 

$

223,246 

 

50

 


 

Income tax expense differs from the amounts computed by applying the U.S. Federal income tax rate of 35% to income (loss) before income taxes for the years ended December 31, 2014, 2013 and 2012 as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

Computed expected tax expense

 

$

154,766 

 

$

35,265 

 

$

212,581 

Increase (decrease) resulting from

 

 

 

 

 

 

 

 

 

State and foreign income taxes

 

 

8,467 

 

 

(852)

 

 

15,176 

Reduction in value of assets

 

 

 -

 

 

34,874 

 

 

 -

Other

 

 

(1,834)

 

 

(14,015)

 

 

(4,511)

Income tax

 

$

161,399 

 

$

55,272 

 

$

223,246 

 

The tax effects of temporary differences that give rise to significant components of deferred income tax assets and liabilities as of December 31, 2014 and 2013 are as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

Deferred tax assets:

 

 

 

 

 

 

Allowance for doubtful accounts

 

$

3,942 

 

$

8,482 

Operating loss and tax credit carryforwards

 

 

21,928 

 

 

32,543 

Compensation and employee benefits

 

 

57,045 

 

 

50,136 

Decommissioning liabilities

 

 

21,029 

 

 

22,124 

Other

 

 

50,641 

 

 

51,161 

 

 

 

154,585 

 

 

164,446 

Valuation allowance

 

 

 -

 

 

 -

Net deferred tax assets

 

 

154,585 

 

 

164,446 

Deferred tax liabilities:

 

 

 

 

 

 

Property, plant and equipment

 

 

648,054 

 

 

671,172 

Notes receivable

 

 

5,718 

 

 

5,429 

Goodwill and other intangible assets

 

 

138,017 

 

 

136,940 

Deferred revenue on long-term contracts

 

 

1,470 

 

 

21,354 

Other

 

 

32,184 

 

 

56,846 

Deferred tax liabilities

 

 

825,443 

 

 

891,741 

Net deferred tax liability

 

$

670,858 

 

$

727,295 

 

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

 

Net deferred tax liabilities were classified in the consolidated balance sheet as of December 31, 2014 and 2013 as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

Deferred tax assets:

 

 

 

 

 

 

Current deferred income taxes

 

$

32,138 

 

$

8,785 

Deferred tax liabilities:

 

 

 

 

 

 

  Non-current deferred income taxes

 

 

(702,996)

 

 

(736,080)

Net deferred tax liability

 

$

(670,858)

 

$

(727,295)

 

As of December 31, 2014, the Company had approximately $1.3 million in net operating loss carryforwards, which are available to reduce future taxable income.  The expiration dates for utilization of the loss carryforwards are 2020 through 2026.  Utilization of $0.5 million of the net operating loss carryforwards will be subject to the annual limitations due to the ownership change limitations provided by the Internal Revenue Code of 1986, as amended.  As of December 31, 2014, the Company also has various state net operating loss carryforwards with expiration dates from 2016 to 2029.  A deferred tax asset of $9.9 million reflects the expected future tax benefit for the state loss carryforwards. 

 

The Company has not provided U.S. income tax expense on earnings of its foreign subsidiaries, since the Company has reinvested or expects to reinvest outside the U.S. the undistributed earnings indefinitely.  As of December 31, 2014, the undistributed earnings of the Company’s foreign subsidiaries were approximately $61.0 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.

 

51

 


 

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 $30.3 million, $29.9 million and $26.4 million as of December 31, 2014, 2013 and 2012, respectively all of which would impact the Company’s effective tax rate if recognized. 

The activity in unrecognized tax benefits as of December 31, 2014, 2013 and 2012 is as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

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

 

$

29,899 

 

$

26,399 

 

$

21,692 

Additions based on tax positions related to current year

 

 

 -

 

 

 -

 

 

 -

Additions based on tax positions related to prior years

 

 

7,860 

 

 

5,065 

 

 

6,873 

Reductions based on tax positions related to prior years

 

 

(7,415)

 

 

(1,565)

 

 

(2,166)

Unrecognized tax benefits,
    December 31, 2014, 2013 and 2012, respectively

 

$

30,344 

 

$

29,899 

 

$

26,399 

 

 

 

 

 (11) Segment Information

 

Business Segments

 

The Drilling Products and Services segment rents and sells bottom hole assemblies, premium drill pipe, tubulars and specialized equipment for use with onshore and offshore oil and gas well drilling, completion, production and workover activities.  It also provides on-site accommodations and bolting and machining services.  The Onshore Completion and Workover Services segment provides pressure pumping services used to complete and stimulate production in new oil and gas wells, fluid handling services and well servicing rigs that provide a variety of well completion, workover and maintenance services.  The Production Services segment provides intervention services such as coiled tubing, cased hole and mechanical wireline, hydraulic workover and snubbing, production testing and optimization, and remedial pumping services. It also provides specialized pressure control tools used to manage and control pressure throughout the life of a well.  The Technical Solutions segment provides services typically requiring specialized engineering, manufacturing or project planning, including well control services, well containment systems, stimulation and sand control services and well plug and abandonment services. It also includes production handling arrangements and the production and sale of oil and gas. 

 

For the years ended December 31, 2014, 2013 and 2012, operating results for the Company’s subsea construction and conventional decommissioning businesses are reported in discontinued operations (see note 3).  Previously those operating results were reported within the Technical Solutions segment, which was previously named the Subsea and 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 expense 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.

 

52

 


 

Summarized financial information for the Company’s segments for the years ended December 31, 2014, 2013 and 2012 is shown in the following tables (in thousands): 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Onshore

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Drilling

 

Completion

 

 

 

 

 

 

 

 

 

 

 

 

 

Products and

 

and Workover

 

Production

 

Technical

 

 

 

 

Consolidated

 

 

Services

 

Services

 

Services

 

Solutions

 

Unallocated

 

Total

Revenues

 

$

923,849 

 

$

1,727,904 

 

$

1,356,057 

 

$

548,812 

 

$

 -

 

$

4,556,622 

Cost of services and rentals

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(exclusive of items shown separately below)

 

 

290,341 

 

 

1,201,497 

 

 

945,201 

 

 

297,794 

 

 

 -

 

 

2,734,833 

Depreciation, depletion, amortization
    and accretion

 

 

187,825 

 

 

233,479 

 

 

165,144 

 

 

64,366 

 

 

 -

 

 

650,814 

General and administrative expenses

 

 

155,606 

 

 

159,325 

 

 

190,172 

 

 

119,268 

 

 

 -

 

 

624,371 

Income from operations

 

 

290,077 

 

 

133,603 

 

 

55,540 

 

 

67,384 

 

 

 -

 

 

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

 

$

290,077 

 

$

133,603 

 

$

55,540 

 

$

68,961 

 

$

(105,992)

 

$

442,189 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Onshore

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Drilling

 

Completion

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Products and

 

and Workover

 

Production

 

Technical

 

 

 

 

Consolidated

 

 

Services

 

Services

 

Services

 

Solutions

 

Unallocated

 

Total

Revenues

 

$

838,514 

 

$

1,596,704 

 

$

1,445,555 

 

$

469,284 

 

$

 -

 

$

4,350,057 

Cost of services and rentals

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(exclusive of items shown separately below)

 

 

276,131 

 

 

1,083,494 

 

 

1,011,933 

 

 

262,032 

 

 

 -

 

 

2,633,590 

Depreciation, depletion, amortization
    and accretion

 

 

169,296 

 

 

215,506 

 

 

178,442 

 

 

41,197 

 

 

 -

 

 

604,441 

General and administrative expenses

 

 

142,850 

 

 

156,405 

 

 

190,931 

 

 

107,592 

 

 

 -

 

 

597,778 

Reduction in value of assets

 

 

2,292 

 

 

16,975 

 

 

28,568 

 

 

252,243 

 

 

 -

 

 

300,078 

Income (loss) from operations

 

 

247,945 

 

 

124,324 

 

 

35,681 

 

 

(193,780)

 

 

 -

 

 

214,170 

Interest expense, net

 

 

 -

 

 

 -

 

 

 -

 

 

1,323 

 

 

(109,225)

 

 

(107,902)

Other income (expense)

 

 

 -

 

 

 -

 

 

 -

 

 

836 

 

 

(5,463)

 

 

(4,627)

Loss on early extinguishment of debt

 

 

 -

 

 

 -

 

 

 -

 

 

 -

 

 

(884)

 

 

(884)

Income (loss) from continuing operations
    before income taxes

 

$

247,945 

 

$

124,324 

 

$

35,681 

 

$

(191,621)

 

$

(115,572)

 

$

100,757 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

53

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Onshore

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Drilling

 

Completion

 

 

 

 

 

 

 

 

 

 

 

 

 

Products and

 

and Workover

 

Production

 

Technical

 

 

 

 

Consolidated

 

 

Services

 

Services

 

Services

 

Solutions

 

Unallocated

 

Total

Revenues

 

$

775,066 

 

$

1,593,977 

 

$

1,510,990 

 

$

413,243 

 

$

 -

 

$

4,293,276 

Cost of services and rentals

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(exclusive of items shown separately below)

 

 

255,853 

 

 

1,039,732 

 

 

929,552 

 

 

244,283 

 

 

 -

 

 

2,469,420 

Depreciation, depletion, amortization
    and accretion

 

 

150,687 

 

 

171,853 

 

 

135,910 

 

 

29,611 

 

 

 -

 

 

488,061 

General and administrative expenses

 

 

130,954 

 

 

185,548 

 

 

210,411 

 

 

98,509 

 

 

 -

 

 

625,422 

Income from operations

 

 

237,572 

 

 

196,844 

 

 

235,117 

 

 

40,840 

 

 

 -

 

 

710,373 

Interest expense, net

 

 

 -

 

 

 -

 

 

 -

 

 

849 

 

 

(117,328)

 

 

(116,479)

Other expense

 

 

 -

 

 

 -

 

 

 -

 

 

(212)

 

 

(2,105)

 

 

(2,317)

Loss on early extinguishment of debt

 

 

 -

 

 

 -

 

 

 -

 

 

 -

 

 

(2,294)

 

 

(2,294)

Gain on sale of equity-method investment

 

 

 

 

 

 

 

 

 

 

 

 

 

 

17,880 

 

 

17,880 

Income (loss) from continuing operations
    before income taxes

 

$

237,572 

 

$

196,844 

 

$

235,117 

 

$

41,477 

 

$

(103,847)

 

$

607,163 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Identifiable Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Onshore

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Drilling

 

Completion

 

 

 

 

 

 

 

 

 

 

 

 

 

Products and

 

and Workover

 

Production

 

Technical

 

 

 

 

Consolidated

 

 

Services

 

Services

 

Services

 

Solutions

 

Unallocated

 

Total

December 31, 2014

 

$

1,304,110 

 

$

3,010,295 

 

$

2,116,171 

 

$

946,813 

 

$

 -

 

$

7,377,389 

December 31, 2013

 

$

1,245,501 

 

$

2,973,916 

 

$

2,176,785 

 

$

1,015,105 

 

$

 -

 

$

7,411,307 

December 31, 2012

 

$

1,086,804 

 

$

3,223,984 

 

$

2,185,779 

 

$

1,295,134 

 

$

11,185 

 

$

7,802,886 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital Expenditures

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Onshore

 

 

 

 

 

 

 

 

 

 

 

Drilling

 

Completion

 

 

 

 

 

 

 

 

 

 

 

Products and

 

and Workover

 

Production

 

Technical

 

Consolidated

 

 

Services

 

Services

 

Services

 

Solutions

 

Total

December 31, 2014

 

$

254,500 

 

$

160,888 

 

$

95,796 

 

$

95,037 

 

$

606,221 

December 31, 2013

 

$

269,152 

 

$

99,517 

 

$

107,412 

 

$

144,388 

 

$

620,469 

December 31, 2012

 

$

246,389 

 

$

308,317 

 

$

334,670 

 

$

279,729 

 

$

1,169,105 

 

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, 2014, the assets of the subsea construction and conventional decommissioning businesses were classified as assets held for sale on the consolidated balance sheet.  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): 

54

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

Years Ended December 31,

 

 

2014

 

2013

 

2012

United States

 

$

3,848,929 

 

$

3,674,825 

 

$

3,680,817 

Other Countries

 

 

707,693 

 

 

675,232 

 

 

612,459 

Total

 

$

4,556,622 

 

$

4,350,057 

 

$

4,293,276 

 

 

 

 

 

 

 

 

 

 

Long-Lived Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31,

 

 

 

 

 

2014

 

2013

United States

 

 

 

 

$

2,416,306 

 

$

2,476,792 

Other Countries

 

 

 

 

 

317,533 

 

 

525,402 

Total, net

 

 

 

 

$

2,733,839 

 

$

3,002,194 

 

 

 

 

 

 

 

 

 

 

 

 (12) 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 $26.2 million, $25.6 million and $23.1 million in the years ended December 31, 2014, 2013 and 2012, respectively.  Future minimum lease payments under non-cancelable leases for the five years ending December 31, 2015 through 2019 and thereafter are as follows:  $64.7 million, $42.4 million, $30.3 million, $23.8 million, $13.8 million and $28.7 million, respectively.

 

Due to the nature of the Company’s business, the Company is involved, from time to time, in routine litigation or subject to disputes or claims regarding 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. 

 

55

 


 

(13) Fair Value Measurements

The following tables provide a summary of the financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2014 and 2013 (in thousands): 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value Measurements at Reporting Date Using

 

 

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 

 

 

 -

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2013

 

Level 1

 

Level 2

 

Level 3

Inventory and other current assets

 

 

 

 

 

 

 

 

 

 

 

 

Available-for-sale securities

 

$

8,817 

 

$

8,817 

 

 

 -

 

 

 -

Intangible and other long-term assets, net

 

 

 

 

 

 

 

 

 

 

 

 

Non-qualified deferred compensation assets

 

$

13,731 

 

$

2,330 

 

$

11,401 

 

 

 -

Interest rate swap

 

$

337 

 

 

 -

 

$

337 

 

 

 -

Accounts payable

 

 

 

 

 

 

 

 

 

 

 

 

Non-qualified deferred compensation liabilities

 

$

1,944 

 

 

 -

 

$

1,944 

 

 

 -

Other long-term liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Non-qualified deferred compensation liabilities

 

$

14,986 

 

 

 -

 

$

14,986 

 

 

 -

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2013, available-for-sale securities was comprised of approximately 1.4 million shares of SandRidge common stock.  The securities were reported at fair value based on the closing price of the shares as reported on the New York Stock Exchange (see note 6). 

 

The Company’s non-qualified deferred compensation plans allow officers, certain highly compensated employees and non-employee directors to defer receipt of a portion of their compensation and contribute such amounts to one or more hypothetical investment funds (see note 8).  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 14). 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value Measurements at Reporting Date Using

 

 

 

 

 

December 31,
2013

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

Total
Losses

Property, plant and equipment, net

 

$

328,876 

 

$

 -

 

$

 -

 

$

328,876 

 

$

243,781 

Goodwill

 

 

 -

 

 

 -

 

 

 -

 

 

 -

 

$

91,016 

Intangible assets

 

$

4,355 

 

$

 -

 

$

 -

 

$

4,355 

 

$

18,296 

 

During the year ended December 31, 2013, the Company recorded $243.8 million in expense related to reduction in carrying values of its property, plant and equipment, $98.3 million of which was included in the discontinued operations on the statement of operations. 

56

 


 

During the year ended December 31, 2013, the Company recorded a $91.0 million expense related to reduction in value of goodwill.  In addition, the Company recorded an $18.3 million expense, primarily, related to reduction in carrying values of the intangible assets in the subsea construction division, of which $15.3 million is included in the discontinued operations on the statement of operations.  See note 9 for a discussion of reduction in value of assets expense recorded during 2013.

 

 

(14) 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 $4.2 million and $0.3 million within intangible and other long term assets in the consolidated balance sheets as of December 31, 2014 and 2013, respectively, relating to these swaps

 

The changes in fair value of the interest rate swaps are included in the adjustments to reconcile net income to net cash provided by operating activities in the consolidated statement of cash flows. The location and effect of the derivative instrument on the consolidated statement of operations for the years ended December 31, 2014, 2013 and 2012, presented on a pre-tax basis, is as follows (in thousands):  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Effect of derivative instrument

 

Location of (gain) loss 
recognized

 

 

2014

 

 

2013

 

 

2012

Interest rate swap

 

Interest expense, net

 

 

$

(11,054)

 

 

$

13,079 

 

$

(3,632)

Hedged item - debt

 

Interest expense, net

 

 

 

7,208 

 

 

 

(12,303)

 

 

2,346 

 

 

 

 

 

$

(3,846)

 

 

$

776 

 

$

(1,286)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the years ended December 31, 2014, 2013 and 2012, $3.8 million of interest income, $0.8 million of interest expense and $1.3 million of interest income, respectively, was related to the ineffectiveness associated with these fair value hedges.  Hedge ineffectiveness represents the difference between the changes in fair value of the derivative instruments and the changes in fair value of the fixed rate debt attributable to changes in the benchmark interest rate. 

 

(15) Related Party Transactions

The Company purchases services, products and equipment, as well as leases certain facilities, from companies affiliated with an officer of one of its subsidiaries.  The Company believes the transactions reflected below with these related parties are on terms and conditions no less favorable to the Company than transactions with unaffiliated parties.  For the years ended December 31, 2014, 2013 and 2012, these transactions totaled approximately $221.1 million, $164.8 million and $240.3 million, respectively. For the year ended December 31, 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. For the year ended December 31, 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. For the year ended December 31, 2012, $111.6 million was purchased from ORTEQ Energy Services, $4.1 million was purchased from Ortowski Construction, $12.1 million was paid to Resource Transport, $91.9 million was purchased from Texas Specialty Sands, LLC, $18.9 million was purchased from ProFuel, LLC, and $1.7 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 approximately $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. As of December 31, 2013, the Company’s trade accounts payable includes amounts due to these companies totaling approximately $14.6 million, of which $7.8 million was due ORTEQ Energy Services, $0.9 million was due Resource Transport, LLC, $2.0 million was due Texas Specialty Sands, LLC, $2.6 million was due ProFuel, LLC and $1.3 million was due Timber Creek Real Estate Partners. 

57

 


 

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 with focus areas in the Rockies, Mid-Continent, the Hugoton Basin, California, the Permian Basin, Michigan, Illinois and east Texas.  The Company recorded revenues from Linn of $19.7 million, $26.9 million and $21.1 million for the years ended December 31, 2014, 2013 and 2012, respectively.  The Company had trade receivables from Linn of $1.6 million and $2.9 million as of December 31, 2014 and 2013, respectively. 

 

(16) Interim Financial Information (Unaudited)

The following is a summary of consolidated interim financial information for the two years ended December 31, 2014 and 2013 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

March 31

 

June 30

 

Sept. 30

 

Dec. 31

2014

 

 

 

 

 

 

 

 

 

 

 

 

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 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

 

$

(0.04)

 

$

(0.03)

 

$

(0.03)

 

$

(0.05)

Diluted

 

 

(0.04)

 

 

(0.03)

 

 

(0.04)

 

 

(0.05)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

March 31

 

June 30

 

Sept. 30

 

Dec. 31

2013

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

1,086,872 

 

$

1,091,129 

 

$

1,096,412 

 

$

1,075,644 

Less:

 

 

 

 

 

 

 

 

 

 

 

 

Cost of services and rentals

 

 

651,594 

 

 

646,704 

 

 

671,632 

 

 

663,660 

Depreciation, depletion, amortization
    and accretion

 

 

144,964 

 

 

149,440 

 

 

152,028 

 

 

158,009 

Gross profit

 

 

290,314 

 

 

294,985 

 

 

272,752 

 

 

253,975 

Reduction in value of assets

 

 

 -

 

 

 -

 

 

 -

 

 

300,078 

Net income (loss) from continuing operations

 

 

80,618 

 

 

74,079 

 

 

67,469 

 

 

(176,681)

Income (loss) from discontinued operations,
    net of tax

 

 

(16,891)

 

 

(5,520)

 

 

2,366 

 

 

(136,858)

Net income (loss)

 

 

63,727 

 

 

68,559 

 

 

69,835 

 

 

(313,539)

Earnings (loss) per share from continuing
    operations:

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.51 

 

$

0.46 

 

$

0.42 

 

$

(1.11)

Diluted

 

 

0.51 

 

 

0.46 

 

 

0.42 

 

 

(1.11)

Earnings (loss) per share from discontinued
    operations:

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

(0.11)

 

$

(0.03)

 

$

0.02 

 

$

(0.86)

Diluted

 

 

(0.11)

 

 

(0.03)

 

 

0.01 

 

 

(0.86)

 

 

 

58

 


 

(17) Accelerated Share Repurchase Program

During 2014, the Company entered into an accelerated share repurchase program with a third-party financial institution to purchase $75.0 million aggregate amount of shares of the Company’s outstanding common stock.  The Company paid $75.0 million and received and retired 2,532,540 shares of its outstanding common stock.

 

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

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

 

Oil and Natural Gas Reserves

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil

 

Natural Gas

 

 

(Mbbls)

 

(Mmcf)

Proved-developed and undeveloped reserves:

 

 

 

 

December 31, 2011

 

6,430 

 

6,268 

Revisions

 

2,234 

 

5,357 

Production

 

(457)

 

(341)

December 31, 2012

 

8,207 

 

11,284 

Revisions

 

(3,203)

 

(4,036)

Production

 

(411)

 

(296)

December 31, 2013

 

4,593 

 

6,952 

Revisions

 

(438)

 

1,431 

Production

 

(738)

 

(1,247)

December 31, 2014

 

3,417 

 

7,136 

 

 

 

 

 

Proved-developed reserves:

 

 

 

 

December 31, 2012

 

5,076 

 

5,085 

December 31, 2013

 

2,397 

 

2,100 

December 31, 2014

 

3,184 

 

6,945 

Proved-undeveloped reserves:

 

 

 

 

December 31, 2012

 

3,131 

 

6,199 

December 31, 2013

 

2,196 

 

4,852 

December 31, 2014

 

233 

 

191 

 

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

 

59

 


 

Costs Incurred in Oil and Natural Gas Activities

 

The following table displays certain information regarding the costs incurred associated with finding, acquiring and developing the Company’s proved oil and natural gas reserves for the years ended December 31, 2014, 2013 and 2012 (in thousands):    

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

Acquisition of properties - proved

 

$

 -

 

$

 -

 

$

 -

Acquisition of properties - unproved

 

 

 -

 

 

 -

 

 

 -

Exploratory costs

 

 

 -

 

 

 -

 

 

 -

Development costs

 

 

52,719 

 

 

51,527 

 

 

34,685 

Total costs incurred

 

$

52,719 

 

$

51,527 

 

$

34,685 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31,

 

 

2014

 

2013

Proved oil and gas properties

 

$

189,294 

 

$

136,350 

Accumulated depreciation, depletion and amortization

 

 

(55,864)

 

 

(21,158)

Capitalized costs, net

 

$

133,430 

 

$

115,192 

 

Productive Wells Summary

 

The following table presents the Company’s ownership of productive oil wells as of December 31, 2014.  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

 

10.00 

 

5.10 

 

Acreage

 

The following table sets forth information as of December 31, 2014 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 for the years ended December 31, 2014 and 2013.  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. 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

 

Gross

 

Net

 

Gross

 

Net

Exploratory Wells

 

 

 

 

 

 

 

 

Productive

 

 -

 

 -

 

 -

 

 -

Non-productive

 

 -

 

 -

 

 -

 

 -

Total

 

 -

 

 -

 

 -

 

 -

 

 

 

 

 

 

 

 

 

Development Wells

 

 

 

 

 

 

 

 

Productive

 

2.00 

 

1.02 

 

2.00 

 

1.02 

Non-productive

 

1.00 

 

0.51 

 

1.00 

 

0.51 

Total

 

3.00 

 

1.53 

 

3.00 

 

1.53 

60

 


 

 

Results of Operations

 

The following table sets forth the Company’s results of operations for producing activities for the years ended December 31, 2014, 2013 and 2012 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

Revenues

 

 

 

 

 

 

 

 

 

Sales

 

$

77,845 

 

$

47,050 

 

$

57,757 

Production costs

 

 

13,529 

 

 

9,876 

 

 

12,332 

Exploration expenses

 

 

 -

 

 

 -

 

 

 -

Depreciation, depletion and amortization

 

 

38,768 

 

 

12,032 

 

 

9,818 

 

 

 

25,548 

 

 

25,142 

 

 

35,607 

Income tax expenses

 

 

9,325 

 

 

8,800 

 

 

13,175 

Results of operations from producing activities
    (excluding corporate overhead)

 

$

16,223 

 

$

16,342 

 

$

22,432 

 

 

 

 

 

 

 

 

 

 

The Company’s oil and gas operations are in the Gulf of Mexico. The Company’s average sales price was $92.86 per barrel of oil and $4.95 per mcf of gas in 2014, $101.85 per barrel of oil and $3.98 per mcf of gas in 2013 and $100.70 per barrel of oil and $2.45 per mcf of gas in 2012.  Average production costs were $7.29,  $10.70 and $10.71 per barrel of oil equivalent in years ended December 31, 2014, 2013 and 2012, respectively. 

 

Standardized Measure of Discounted Future Net Cash Flows Relating to Reserves

 

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

 

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

 

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

 

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of December 31, 2014, 2013 and 2012 is as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

Future cash inflows

 

$

336,944 

 

$

496,704 

 

$

891,215 

Future production costs

 

 

(71,209)

 

 

(82,487)

 

 

(141,980)

Future development and abandonment costs

 

 

(111,374)

 

 

(156,340)

 

 

(91,632)

Future income tax expenses

 

 

(60,345)

 

 

(89,507)

 

 

(229,808)

Future net cash flows

 

 

94,016 

 

 

168,370 

 

 

427,795 

10% annual discount for estimated timing of
    cash flows

 

 

(17,034)

 

 

10,641 

 

 

124,365 

Standardized measure of discounted future
    net cash flows

 

$

111,050 

 

$

157,729 

 

$

303,430 

 

For 2014, the 10% annual discount for the estimated timing of cash flows resulted in a negative discount as a result of significant abandonment costs that will occur at the end of the life of the platform. See note 1 (Decommissioning Liabilities). 

 

61

 


 

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the years ended December 31, 2014, 2013 and 2012 is as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

Beginning of the period

 

$

157,729 

 

$

303,430 

 

$

237,749 

Net change in sales and transfer prices and in
    production (lifting) costs related to future production

 

 

(57,568)

 

 

(13,278)

 

 

(17,734)

Changes in estimated future development costs

 

 

(5,512)

 

 

(48,594)

 

 

(5,569)

Sales and transfers of oil and gas produced
    during the period

 

 

(64,316)

 

 

(45,866)

 

 

(45,425)

Net change due to extensions, discoveries,
    and improved recovery

 

 

 -

 

 

75,304 

 

 

206,313 

Net changes due to revisions in quantity
    estimates

 

 

(8,396)

 

 

(228,620)

 

 

(63,192)

Previously estimated development costs
    incurred during the period

 

 

40,962 

 

 

10,136 

 

 

4,748 

Accretion of discount

 

 

24,251 

 

 

46,711 

 

 

37,252 

Other-unspecified

 

 

4,125 

 

 

(24,169)

 

 

(21,799)

Net change in income taxes

 

 

19,775 

 

 

82,675 

 

 

(28,913)

Aggregate change in the standardized measure
    of discounted future net cash flows for the year

 

 

(46,679)

 

 

(145,701)

 

 

65,681 

End of the period

 

$

111,050 

 

$

157,729 

 

$

303,430 

 

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.

 

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

 

62

 


 

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, 2014 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, 2014, 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, 2014.  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, 2014 based upon criteria in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this assessment, our management determined that as of December 31, 2014, our internal control over financial reporting was effective based on those criteria.

 

Our internal control over financial reporting as of December 31, 2014 has been audited by KPMG, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

 

63

 


 

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, 2014, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Superior Energy Services, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting.  Our responsibility is to express an opinion on Superior Energy Services, Inc.’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, Superior Energy Services, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Superior Energy Services, Inc. and subsidiaries as of December 31, 2014 and 2013, 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, 2014,  and our report dated February 26, 2015 expressed an unqualified opinion on those consolidated financial statements.

 

KPMG LLP

 

 

Houston,  Texas

February 26, 2015 

 

 

 

64

 


 

Item 9B. Other Information

 

None.

 

PART III

 

Item 10.  Directors, Executive Officers and Corporate Governance

 

Information relating to our executive officers is included in “Executive Officers of Registrants” in Part I of this Annual Report on Form 10-K, and is incorporated herein by reference.  Information relating to our Code 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, 2014 and 2013

Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012

Consolidated Statements of Comprehensive Income/Loss for the years ended December 31, 2014, 2013 and 2012

Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2014, 2013 and 2012

Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012

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, 2014, 2013 and 2012

 

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

65

 


 

 

 

 

 

 

 

Exhibit No.

Description

2.1

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

3.1

Restated Certificate of Incorporation of Superior Energy Services, Inc. (incorporated herein by reference to Exhibit 3.1 to Superior Energy Services, Inc.’s Quarterly Report on Form 10-Q filed August 7, 2013 (File No. 001-34037)).

3.2

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

4.1

Specimen Stock Certificate (incorporated herein by reference to Post-Effective Amendment No. 1 to Superior Energy Services, Inc.’s Form S-4 on Form SB-2 filed January 9, 1997 (Registration Statement No. 33-94454)).

4.2

Indenture, dated April 27, 2011, among SESI, L.L.C., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to Superior Energy Services, Inc.’s Current Report on Form 8-K filed April 27, 2011 (File No. 001-34037)), as amended by Supplemental Indenture, dated February 29, 2012, by and among SESI, L.L.C., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as 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)).

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)).

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)). 

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)).

66

 


 

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^  

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

10.11^

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

10.12^

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)).

10.13^

Superior Energy Services, Inc. 2013 Stock Incentive Plan (incorporated herein by reference to Appendix A to Superior Energy Services, Inc.’s Definitive Proxy Statement filed April 29, 2013 (File No. 001-34037)).

10.14^

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)).

10.15^

Form of Restricted Stock Unit Agreement under the Superior Energy Services, Inc. 2013 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.20 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 Stock Option Agreement under the Superior Energy Services, Inc. 2013 Stock Incentive 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, 2013 (File No. 001-34037)).

67

 


 

10.17^

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)).

10.18^*

Form of Performance Share Unit Agreement under the Superior Energy Services, Inc. 2013 Stock Incentive Plan (for awards made in 2015).

10.19^

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)).

10.20^

Form of Notice of Grant of Restricted Stock Units for Non-Management Directors under the Superior Energy Services, Inc. 2013 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.6 to Superior Energy Services, Inc.’s Quarterly Report on Form 10-Q filed November 6, 2013 (File No. 001-34037)).

10.21^

Complete Production Services, Inc. Amended and Restated 2001 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.23 to Superior Energy Services, Inc.’s Annual Report on Form 10-K filed February 28, 2012 (File No. 001-34037)).

10.22^

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)).

10.23^

Complete Production Services, Inc. 2008 Incentive Award Plan (incorporated herein by reference to Exhibit 10.25 to Superior Energy Services, Inc.’s Annual Report on Form 10-K filed February 28, 2012 (File No. 001-34037)).

10.24^

Amendment No. 1 to the Complete Production Services, Inc. 2008 Incentive Award Plan (incorporated herein by reference to Exhibit 10.26 to Superior Energy Services, Inc.’s Annual Report on Form 10-K filed February 28, 2012 (File No. 001-34037)).

10.25^

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

10.26^

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

10.27^

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

10.28^

Amended and Restated Complete Production Services, Inc. Executive Agreement, dated December 31, 2008, by and between Complete Production Services, Inc. and Brian K. Moore (incorporated herein by reference to Exhibit 10.34 to Superior Energy Services, Inc.’s Annual Report on Form 10-K filed February 28, 2012 (File No. 001-34037)).

10.29^*

Superior Energy Services, Inc. Directors Deferred Compensation Plan, as amended and restated December 8, 2014.

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)).

68

 


 

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 

Third Amended and Restated Credit Agreement, dated February 7, 2012, among SESI, L.L.C., Superior Energy Services, Inc., JPMorgan Chase Bank, N.A. and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Current Report on Form 8-K filed February 8, 2012 (File No. 001-34037)), as amended by the First Amendment to Third Amended and Restated Credit Agreement, dated November 20, 2013, among SESI, L.L.C., Superior Energy Services, Inc., JPMorgan Chase Bank, N.A. and the lenders party thereto (incorporated herein by reference to Exhibit 10.38 to Superior Energy Services, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 001-34037)).

14.1*

Our Shared Core Values at Work (Code of Conduct).

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, 2014 on Certain Properties owned by Superior Energy Services, Inc.

99.2

Appraisal Report as of December 31, 2013 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 27, 2013 ((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

 

 

 

 

69

 


 

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 26, 2015

 

 

 

 

 

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 26, 2015

    David D. Dunlap

(Principal Executive Officer)

 

 

 

 

 

 

 

/s/ Robert S. Taylor

Executive Vice President, Treasurer and

February 26, 2015

    Robert S. Taylor

Chief Financial Officer

 

 

(Principal Financial and Accounting Officer)

 

 

 

 

 

 

 

/s/ Terence E. Hall

Chairman of the Board

February 26, 2015

    Terence E. Hall

 

 

 

 

 

 

 

 

/s/  Harold J. Bouillion

Director

February 26, 2015

    Harold J. Bouillion

 

 

 

 

 

 

 

 

/s/  Enoch L. Dawkins

Director

February 26, 2015

    Enoch L. Dawkins

 

 

 

 

 

 

 

 

/s/ James M. Funk

Director

February 26, 2015

    James M. Funk

 

 

 

 

 

 

 

 

/s/ Peter D. Kinnear

Director

February 26, 2015

    Peter D. Kinnear

 

 

 

 

 

 

 

 

/s/ Michael M. McShane

Director

February 26, 2015

    Michael M. McShane

 

 

 

 

 

 

 

 

/s/ W. Matt Ralls 

Director

February 26, 2015

    W. Matt Ralls

 

 

 

 

 

 

 

 

/s/ Justin L. Sullivan

Director

February 26, 2015

    Justin L. Sullivan

 

 

 

 

 

 

70

 


 

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Schedule II Valuation and Qualifying Accounts

Years Ended December 31, 2014, 2013 and 2012

(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

Year ended December 31, 2014:
    Allowance for doubtful accounts

 

$

31,030 

 

$

6,299 

 

$

10,639 

 

$

4,614 

 

$

22,076 

Year ended December 31, 2013:
    Allowance for doubtful accounts

 

$

28,715 

 

$

7,587 

 

$

7,763 

 

 

(2,491)

 

$

31,030 

Year ended December 31, 2012:
    Allowance for doubtful accounts

 

$

17,484 

 

$

11,038 

 

$

2,308 

 

 

(2,501)

 

$

28,715 

 

71