10-K 1 d287548d10k.htm FORM 10-K FORM 10-K
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2011

OR

[  ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-9397

Baker Hughes Incorporated

(Exact name of registrant as specified in its charter)

Delaware   76-0207995
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)
2929 Allen Parkway, Suite 2100, Houston, Texas   77019-2118
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code: (713) 439-8600

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

 

Title of each class

 

Name of each exchange on which registered

Common Stock, $1 Par Value per Share   New York Stock Exchange
  SWX Swiss Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES [X ] NO [  ]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. YES [  ] NO [X]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [  ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES [X] NO [  ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [  ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer   [X]

  Accelerated filer   [  ]       Non-accelerated filer   [  ]       Smaller reporting company   [  ]

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES [  ] NO [X]

The aggregate market value of the voting and non-voting common stock held by non-affiliates as of the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing price on June 30, 2011 reported by the New York Stock Exchange) was approximately $31,476,833,000.

As of February 16, 2012, the registrant has outstanding 437,571,000 shares of common stock, $1 par value per share.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Registrant’s Definitive Proxy Statement for the 2012 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.


Table of Contents

Baker Hughes Incorporated

INDEX

 

          Page  
   Part I   
Item 1.    Business      2   
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      35   
Item 8.    Financial Statements and Supplementary Data      37   
Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      68   
Item 9A.    Controls and Procedures      68   
Item 9B.    Other Information      68   
   Part III   
Item 10.    Directors, Executive Officers and Corporate Governance      69   
Item 11.    Executive Compensation      69   
Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      69   
Item 13.    Certain Relationships and Related Transactions, and Director Independence      71   
Item 14.    Principal Accounting Fees and Services      71   
   Part IV   
Item 15.    Exhibits, Financial Statement Schedules      71   

 

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PART I

ITEM 1. BUSINESS

Baker Hughes Incorporated is a Delaware corporation engaged in the oilfield services industry. As used herein, “Baker Hughes,” “Company,” “we,” “our” and “us” may refer to Baker Hughes Incorporated and/or its subsidiaries. The use of these terms is not intended to connote any particular corporate status or relationships.

AVAILABILITY OF INFORMATION FOR STOCKHOLDERS

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made available free of charge on our Internet website at www.bakerhughes.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the Securities and Exchange Commission (the “SEC”). Information contained on or connected to our website is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing we make with the SEC.

We have adopted a Business Code of Conduct to provide guidance to our directors, officers and employees on matters of business conduct and ethics, including compliance standards and procedures. We have also required our principal executive officer, principal financial officer and principal accounting officer to sign a Code of Ethical Conduct Certification.

Our Business Code of Conduct and Code of Ethical Conduct Certifications are available on the Investor Relations section of our website at www.bakerhughes.com. We will disclose on a current report on Form 8-K or on our website information about any amendment or waiver of these codes for our executive officers and directors. Waiver information disclosed on our website will remain on the website for at least 12 months after the initial disclosure of a waiver. Our Corporate Governance Guidelines and the charters of our Audit/Ethics Committee, Compensation Committee, Executive Committee, Finance Committee and Governance Committee are also available on the Investor Relations section of our website at www.bakerhughes.com. In addition, a copy of our Business Code of Conduct, Code of Ethical Conduct Certifications, Corporate Governance Guidelines and the charters of the committees referenced above are available in print at no cost to any stockholder who requests them by writing or telephoning us at the following address or telephone number:

Baker Hughes Incorporated

2929 Allen Parkway, Suite 2100

Houston, TX 77019-2118

Attention: Investor Relations

Telephone: (713) 439-8039

ABOUT BAKER HUGHES

Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry. We also provide industrial and other products and services to the downstream refining, and the process and pipeline industries. Baker Hughes was formed as a corporation in April 1987 in connection with the combination of Baker International Corporation and Hughes Tool Company. We may conduct our operations through subsidiaries, affiliates, ventures and alliances. We operate in more than 80 countries around the world and our corporate headquarters is in Houston, Texas. As of December 31, 2011, we had approximately 57,700 employees, of which approximately 57% work outside the United States (“U.S.”).

Our global oilfield operations are organized into a number of geomarket organizations, which are combined into and report to nine region presidents, who in turn report to two hemisphere presidents. In addition, certain support operations are organized at the enterprise level and include the product line marketing and technology, supply chain, and information technology organizations, which comprise the Global Products and Services group.

Through the geographic organization, we have placed our management close to our customers, facilitating stronger customer relationships and allowing us to react quickly to local market conditions and customer needs. The geographic organization supports our oilfield operations and is responsible for sales, field operations and well site execution. Western Hemisphere operations consist of four regions - Canada, headquartered in Calgary, Alberta; and U.S. Land, Gulf of Mexico and Latin America regions, all headquartered in Houston, Texas. Eastern Hemisphere operations consist of five regions - Europe, headquartered in London, England; Africa, headquartered in Paris, France; Russia Caspian, headquartered in Moscow, Russia; Middle East, headquartered in Dubai, United Arab Emirates; and Asia Pacific, headquartered in Kuala Lumpur, Malaysia.

 

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Within the Global Products and Services group, the product line marketing and technology organization is responsible for product development, technology, marketing and delivery of innovative and reliable solutions for our customers to advance their reservoir performance. This enterprise organization facilitates cross-product line technology development, sales processes and integrated operations capabilities. The supply chain organization is responsible for development of cost-effective procurement and manufacturing of our products and services. The supply chain organization also focuses on product reliability and quality, process efficiency and increased tool utilization.

On April 28, 2010, we completed the acquisition of BJ Services Company (“BJ Services”), a leading provider of pressure pumping and other oilfield services, for $6.9 billion in cash and stock. This acquisition provided us with a proven leader in the areas of pressure pumping, stimulation and fracturing and complements our existing product portfolio, allowing us to provide a full suite of products and services to meet the needs of our customers. Our results are inclusive of BJ Services’ results from the acquisition date.

We report financial results for five segments. Four of these segments represent our oilfield operations and their geographic organization as detailed below:

 

   

North America (U.S. Land, Gulf of Mexico and Canada)

   

Latin America

   

Europe/Africa/Russia Caspian

   

Middle East/Asia Pacific

In addition to the above, we report in our Industrial Services and Other segment the financial results for downstream chemicals, process and pipeline services, and the reservoir development services group.

Further information about our segments is set forth in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 11 of the Notes to Consolidated Financial Statements in Item 8 herein.

PRODUCTS AND SERVICES

Oilfield Operations

We offer a full suite of products and services to our customers around the world. Our oilfield products and services fall into one of two groups, Drilling and Evaluation or Completion and Production. This classification is based on the two major phases of constructing an oil and/or natural gas well and how our products and services are utilized for each phase.

 

   

The Drilling and Evaluation group consists of the following products and services:

 

  ¡    

Drill Bits - includes Tricone TM and PDC or “diamond” drill bits used for performance drilling, hole enlargement and coring.

 

  ¡    

Drilling Services - includes conventional and rotary steerable systems used to drill wells directionally and horizontally; measurement-while-drilling and logging-while-drilling systems used to perform reservoir navigation services; drilling optimization services; tools for coil tubing drilling and wellbore re-entry systems; coring drilling systems; and surface logging.

 

  ¡    

Wireline Services - includes tools for both open hole and cased hole well logging used to gather data to perform petrophysical and geophysical analysis; reservoir evaluation coring; casing perforation; fluid characterization; production logging; well integrity testing; pipe recovery; and seismic and microseismic services.

 

  ¡    

Drilling and Completion Fluids - includes emulsion and water-based drilling fluids systems; reservoir drill-in fluids; and fluids environmental services.

 

   

The Completion and Production group consists of the following products and services:

 

  ¡    

Completion Systems - includes products and services used to control the flow of hydrocarbons within a wellbore including sand control systems; liner hangers; wellbore isolation; expandable tubulars; multilaterals; safety systems; packers and flow control; and tubing conveyed perforating.

 

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  ¡    

Wellbore Intervention - includes products and services used in existing wellbores to improve their performance including thru-tubing fishing; thru-tubing inflatables; conventional fishing; casing exit systems; production injection packers; remedial and stimulation tools; and wellbore cleanup.

 

  ¡    

Intelligent Production Systems - includes products and services used to monitor and dynamically control the production from individual wells or fields including production decisions services; chemical injection services; well monitoring services; intelligent well systems; and artificial lift monitoring.

 

  ¡    

Artificial Lift - includes electric submersible pump systems; progressing cavity pump systems; gas lift systems; and surface horizontal pumping systems used to lift large volumes of oil and water when a reservoir is no longer able to flow on its own.

 

  ¡    

Tubular Services - includes hammer services; tubular running systems; and completion assembly systems.

 

  ¡    

Upstream Chemicals - includes chemicals and chemical application systems to provide flow assurance, integrity management and production management for upstream hydrocarbon production.

 

  ¡    

Pressure Pumping - includes cementing, stimulation, including hydraulic fracturing, and coil tubing services used in the completion of new oil and natural gas wells and in remedial work on existing wells, both onshore and offshore.

Additional information regarding our oilfield products and services can be found on the Company’s website at www.bakerhughes.com. Our website also includes details of our hydraulic fracturing operations, including the chemical content of our fluids systems, our support of the Chemical Disclosure Registry at www.fracfocus.org, and information on our SmartCareTM qualified systems and products, which are intended to maximize performance while minimizing our impact on the community and environment.

Industrial Services and Other

Industrial Services and Other consists primarily of downstream chemicals, process and pipeline services, and the reservoir development services group. Downstream chemical services provides products and services that help to increase refinery production, as well as improve plant safety and equipment reliability. Process and pipeline services works to improve efficiency and reduce downtime with inspection, pre-commissioning and commissioning of new and existing pipeline systems and process plants.

MARKETING, CONTRACTING AND COMPETITION

We market our products and services on a product line basis primarily through our own sales organizations. We ordinarily provide technical and advisory services to assist in our customers’ use of our products and services. Stock points and service centers for our products and services are located in areas of drilling and production activity throughout the world.

Our customers include the large integrated major and super-major oil and natural gas companies, U.S. and international independent oil and natural gas companies, and the national or state-owned oil companies. No single customer accounts for more than 10% of our business. While we may have contracts with customers that include multiple well projects and that may extend over a period of time ranging from two to four years, our services and products are generally provided on a well-by-well basis. Most contracts cover our pricing of the products and services, but do not necessarily establish an obligation to use our products and services.

Our primary competitors include the major diversified oilfield service companies such as Schlumberger, Halliburton and Weatherford, where the breadth of service capabilities as well as competitive position of each product line are the keys to differentiation in the market. We also compete with other companies who may participate in only a few product lines, for example, National Oilwell Varco, Champion Technologies, Ecolab, Newpark Resources, and Frac Tech Services.

Our products and services are sold in highly competitive markets, and revenue and earnings can be affected by changes in commodity prices, fluctuations in the level of drilling, workover and completion activity in major markets, general economic conditions, foreign currency exchange fluctuations and governmental regulations. We believe that the principal competitive factors in our industries are product and service quality, availability and reliability, health, safety and environmental standards, technical proficiency and price.

We strive to negotiate the terms of our customer contracts consistent with what we consider to be best practices. The general industry practice is for oilfield service providers, like us, to be responsible for their own products and services and for our customers

 

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to retain liability for drilling and related operations. Consistent with this practice, we generally take responsibility for our own people and property while our customers, such as the operator of a well, take responsibility for their own people, property and all liabilities related to the well and subsurface operations, regardless of either party’s negligence. In general, any material limitations on indemnifications to us from our customers in support of this allocation of responsibility arise only by applicable statutes. Certain states such as Texas, Louisiana, Wyoming, and New Mexico have enacted oil and natural gas specific statutes that void any indemnity agreement that attempts to relieve a party from liability resulting from its own negligence (“anti-indemnity statutes”). These statutes can void the allocation of liability agreed to in a contract; however, both the Texas and Louisiana anti-indemnity statutes include important exclusions. The Louisiana statute does not apply to property damage, and the Texas statute allows mutual indemnity agreements that are supported by insurance and has exclusions, which include, among other things, loss or liability for property damage that results from pollution and the cost of control of a wild well.

Because both Baker Hughes and our customers generally prefer to contract on the basis as we mutually agree, we negotiate with our customers in the U.S. to include a choice of law provision adopting the law of a state that does not have an anti-indemnity statute. When this does not occur, we will generally use Texas law. With the exclusions contained in the Texas anti-indemnity statute, we are usually able to structure the contract such that the limitation on the indemnification obligations of the customer is limited and should not have a material impact on the terms of the contract.

State law, laws or public policy in countries outside the U.S., or the negotiated terms of our agreement with the customer may also limit the customer’s indemnity obligations in the event of the gross negligence or willful misconduct of a Baker Hughes employee. The Company and the customer may also agree to other limitations on the customer’s indemnity obligations in the contract.

The Company maintains a commercial general liability insurance policy program that covers against certain operating hazards, including product liability claims 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 the Company is liable, but clean up and well control costs are not covered by such program. All of the insurance policies purchased by the Company are subject to self-insured retention amounts for which we are responsible for payment, specific terms, conditions, limitations and exclusions. There can be no assurance that the nature and amount of Company insurance will be sufficient to fully indemnify us against liabilities related to our business.

RESEARCH AND DEVELOPMENT; PATENTS

Our products and technology organization engages in research and development activities directed primarily toward the improvement of existing products and services, the design of specialized products to meet specific customer needs and the development of new products, processes and services. We have technology centers located in the U.S. (Claremore, Oklahoma; and several in Houston, Texas and surrounding areas), Germany (Celle), Brazil (Rio de Janeiro), Russia (Novosibirsk), and Saudi Arabia (Dhahran). For information regarding the amounts of research and development expense in each of the three years in the period ended December 31, 2011, see Note 1 of the Notes to Consolidated Financial Statements in Item 8 herein.

We have followed a policy of seeking patent and trademark protection in numerous countries and regions throughout the world for products and methods that appear to have commercial significance. We believe our patents and trademarks are adequate for the conduct of our business, and aggressively pursue protection of our patents against patent infringement worldwide. No single patent or trademark is considered to be critical to our business.

SEASONALITY

Our operations can be affected by seasonal weather, which can temporarily affect the delivery and performance of our products and services, as well as customers’ budgetary cycles. The widespread geographic locations of our operations and the timing of seasonal events serve to reduce the impact of individual events. Examples of seasonal events which can impact our business include:

 

   

The severity and duration of both the summer and the winter in North America can have a significant impact on natural gas storage levels and drilling activity for natural gas.

 

   

In Canada, the timing and duration of the spring thaw directly affects activity levels, which reach seasonal lows during the second quarter and build through the third and fourth quarters to a seasonal high in the first quarter.

 

   

Hurricanes and typhoons can disrupt coastal and offshore drilling and production operations.

 

   

Severe weather during the winter months normally results in reduced activity levels in the North Sea and Russia generally in the first quarter.

 

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Scheduled repair and maintenance of offshore facilities in the North Sea can reduce activity in the second and third quarters.

 

   

Our Industrial Services and Other segment records its strongest sales in the second and third quarters of the year and weakest sales during the first and fourth quarters of the year due to the Northern Hemisphere winter.

RAW MATERIALS

We purchase various raw materials and component parts for use in manufacturing our products and delivering our services. The principal materials we purchase include, but are not limited to, steel alloys (including chromium and nickel), titanium, barite, beryllium, copper, lead, tungsten carbide, synthetic and natural diamonds, gels, sand and other proppants, printed circuit boards and other electronic components and hydrocarbon-based chemical feed stocks. These materials are generally available from multiple sources and may be subject to price volatility. While we generally do not experience significant shortages of these materials, we have from time to time experienced temporary shortages of particular raw materials. In addition, we normally do not carry inventories of such materials in excess of those reasonably required to meet our production schedules. We do not expect significant interruptions in supply, but there can be no assurance that there will be no price or supply issues over the long term.

EMPLOYEES

On December 31, 2011, we had approximately 57,700 employees, of which the majority are outside the U.S. Less than 10% of these employees are represented under collective bargaining agreements or similar-type labor arrangements. Based upon the geographic diversification of these employees, we believe any risk of loss from employee strikes or other collective actions would not be material to the conduct of our operations taken as a whole.

EXECUTIVE OFFICERS OF BAKER HUGHES INCORPORATED

The following table shows, as of February 23, 2012, the name of each of our executive officers, together with his age and all offices presently held.

 

Name    Age       

Chad C. Deaton

     59       Executive Chairman of the Board of the Company since January 2012. Chairman of the Board and Chief Executive Officer from October 2004 to December 2011. President of the Company from 2008 to 2010. President and Chief Executive Officer of Hanover Compressor Company from 2002 to 2004. Senior Advisor to Schlumberger Oilfield Services from 1999 to 2001. Executive Vice President of Schlumberger from 1998 to 1999. Employed by the Company in 2004.

Martin S. Craighead

     52       Chief Executive Officer of the Company since January 2012 and President of the Company since 2010. Director of the Company since 2011. Chief Operating Officer of the Company from 2009 to 2011 and Senior Vice President from 2009 to 2010. Group President of Drilling and Evaluation from 2007 to 2009 and Vice President of the Company from 2005 until 2009. President of INTEQ from 2005 to 2007. President of Baker Atlas from February 2005 to August 2005. Vice President of Worldwide Operations for Baker Atlas from 2003 to 2005 and Vice President, Marketing and Business Development for Baker Atlas from 2001 to 2003. Employed by the Company in 1986.

Peter A. Ragauss

     54       Senior Vice President and Chief Financial Officer of the Company since 2006. Segment Controller of Refining and Marketing for BP plc from 2003 to 2006. Chief Executive Officer of Air BP from 2000 to 2003 and Assistant to the Group Chief Executive for BP plc from 1998 to 2000. Vice President of Finance and Portfolio Management for Amoco Energy International immediately prior to its merger with BP in 1998. Vice President of Finance for El Paso Energy International from 1996 to 1998 and Vice President of Corporate Development for Tenneco Energy in 1996. Employed by the Company in 2006.

Alan R. Crain

     60       Senior Vice President and General Counsel of the Company since 2007. Vice President and General Counsel from 2000 to 2007. Executive Vice President, General Counsel and Secretary of Crown, Cork & Seal Company, Inc. from 1999 to 2000. Vice President and General Counsel from 1996 to 1999, and Assistant General Counsel from 1988 to 1996, of Union Texas Petroleum Holdings, Inc. Employed by the Company in 2000.

 

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Russell J. Cancilla

     60       Vice President and Chief Security Officer, Health, Safety, Environment and Security of the Company since 2009. Chief Security Officer from June 2006 to January 2009. Vice President and Chief Security Officer of Innovene from 2005 to 2006; Vice President, Resources &
      Capabilities for HSSE for BP from 2003 to 2005 and Vice President, Real Estate and Management Services for BP from 1998 to 2003. Employed by the Company in 2006.

Belgacem Chariag

     49       Vice President of the Company and President Eastern Hemisphere Operations since 2009. Vice President HSE of Schlumberger Limited from May 2008 to May 2009. President of Well Services, a Schlumberger product line, from 2006 to 2008. Vice President Marketing Oilfield Services for Europe, Caspian and Africa of Schlumberger from 2004 to 2006. Various other operational and management positions at Schlumberger from 1989 to 2008. Employed by the Company in 2009.

Didier Charreton

     48       Vice President, Human Resources of the Company since 2007. Group Human Resources Director of Coats plc from 2002 to 2007. Business Development of ID Applications for Gemplus S.A. from 2000 to 2001. Various human resources positions at Schlumberger from 1989 to 2000. Employed by the Company in 2007.

Alan J. Keifer

     57       Vice President, Controller and Principal Accounting Officer of the Company since 1999. Western Hemisphere Controller of Baker Oil Tools from 1997 to 1999 and Director of Corporate Audit for the Company from 1990 to 1996. Employed by the Company in 1990.

Jay G. Martin

     60       Vice President, Chief Compliance Officer and Senior Deputy General Counsel of the Company since 2004. Shareholder at Winstead Sechrest & Minick P.C. from 2001 to 2004. Partner, Phelps Dunbar from 2000 to 2001 and Partner, Andrews & Kurth from 1996 to 2000. Employed by the Company in 2004.

Derek Mathieson

     41       Vice President of the Company since 2008 and President Western Hemisphere Operations since January 2012. President, Products and Technology from May 2009 to December 2011. Chief Technology and Marketing Officer of the Company from December 2008 to May 2009. Chief Executive Officer of WellDynamics, Inc. from May 2007 to November 2008. Vice President Business Development, Technology and Marketing of WellDynamics, Inc. from April 2006 to May 2007; Technology Director and Chief Technology Officer from January 2004 to April 2006; Research and Development Manager from August 2002 to January 2004 and Reliability Assurance Engineer from April 2001 to August 2002 of WellDynamics, Inc. Well Engineer, Shell U.K. Exploration and Production 1997 to 2001. Employed by the Company in 2008.

John A. O’Donnell

     63       Vice President of the Company since 1998 and Vice President Office of the Chief Executive Officer since January 2012. President Western Hemisphere Operations from May 2009 to December 2011. President of Baker Petrolite Corporation from 2005 to May 2009. President of Baker Hughes Drilling Fluids from 2004 to 2005. Vice President, Business Process Development of the Company from 1998 to 2002; Vice President, Manufacturing, of Baker Oil Tools from 1990 to 1998 and Plant Manager of Hughes Tool Company from 1988 to 1990. Employed by the Company in 1975.

Arthur L. Soucy

     49       President, Global Products and Services since January 2012. Vice President Supply Chain of the Company from April 2009 to December 2011. Vice President, Global Supply Chain for Pratt and Whitney from 2007 to 2009. Sloan Fellows Program, Innovation and Global Leadership at Massachusetts Institute of Technology from 2006 to 2007. General Manager, Combustors, Augmenters and Nozzles of Pratt and Whitney from 2005 to 2006. Various managerial positions at Pratt and Whitney from 1995 to 2006. Employed by the Company in 2009.

Clifton N.B. Triplett

     53       Vice President and Chief Information Officer of the Company since September 2008. Corporate Vice President, Motorola Global Services from 2007 to 2008 and Corporate Vice President and Chief Information Officer of Motorola’s Network and Enterprise Group from 2006 to 2007. Employed by General Motors from 1997 to 2006 as Global Information Systems Officer for Computing and Telecommunications Services from 2003 to 2006 and Global Manufacturing and Quality Information Systems Officer from 1997 to 2003. Employed by the Company in 2008.

 

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There are no family relationships among our executive officers.

ENVIRONMENTAL MATTERS

We are committed to the health and safety of people, protection of the environment and compliance with laws, regulations and our policies. Our past and present operations include activities that are subject to domestic (including U.S. federal, state and local) and international regulations with regard to air and water quality and other environmental matters. We believe we are in substantial compliance with these regulations. Regulation in this area continues to evolve, and changes in standards of enforcement of existing regulations, as well as the enactment and enforcement of new legislation, may require us and our customers to modify, supplement or replace equipment or facilities or to change or discontinue present methods of operation. Our environmental compliance expenditures and our capital costs for environmental control equipment may change accordingly.

We are involved in voluntary remediation projects at some of our present and former manufacturing locations or other facilities, the majority of which relate to properties obtained in acquisitions or to sites no longer actively used in operations. On rare occasions, remediation activities are conducted as specified by a government agency-issued consent decree or agreed order. Estimated remediation costs are accrued using currently available facts, existing environmental permits, technology and presently enacted laws and regulations. For sites where we are primarily responsible for the remediation, our cost estimates are developed based on internal evaluations and are not discounted. We record accruals when it is probable that we will be obligated to pay amounts for environmental site evaluation, remediation or related activities, and such amounts can be reasonably estimated. In general, we seek to accrue costs for the most likely scenario, where known. Accruals are recorded even if significant uncertainties exist over the ultimate cost of the remediation. Ongoing environmental compliance costs, such as obtaining environmental permits, installation of pollution control equipment and waste disposal, are expensed as incurred.

The Comprehensive Environmental Response, Compensation and Liability Act (known as “Superfund”) imposes liability for the release of a “hazardous substance” into the environment. Superfund liability is imposed without regard to fault, even if the waste disposal was in compliance with laws and regulations. The U.S. Environmental Protection Agency (the “EPA”) and appropriate state agencies supervise investigative and cleanup activities at Superfund sites.

We have been identified as a potentially responsible party (“PRP”) in remedial activities related to various Superfund sites, and we accrue our share of the estimated remediation costs of the site based on the ratio of the estimated volume of waste we contributed to the site to the total volume of waste disposed at the site. PRPs in Superfund actions have joint and several liability for all costs of remediation. Accordingly, a PRP may be required to pay more than its proportional share of such costs. For some projects, it is not possible to quantify our ultimate exposure because the projects are either in the investigative or early remediation stage, or allocation information is not yet available. However, based upon current information, we do not believe that probable or reasonably possible expenditures in connection with the sites are likely to have a material adverse effect on our consolidated financial statements because we have recorded adequate reserves to cover the estimate we presently believe will be our ultimate liability in the matter. Further, other PRPs involved in the sites have substantial assets and may reasonably be expected to pay their share of the cost of remediation, and, in some circumstances, we have insurance coverage or contractual indemnities from third parties to cover a portion of the ultimate liability.

Based upon current information, we believe that our overall compliance with environmental regulations, including routine environmental compliance costs and capital expenditures for environmental control equipment, will not have a material adverse effect upon our capital expenditures, earnings or competitive position because we have either established adequate reserves or our cost for that compliance is not expected to be material to our consolidated financial statements. Our total accrual for environmental remediation is $29 million and $32 million, which includes accruals of $5 million and $7 million for the various Superfund sites, at December 31, 2011 and 2010, respectively.

We are subject to various other governmental proceedings and regulations, including foreign regulations, relating to environmental matters, but we do not believe that any of these matters is likely to have a material adverse effect on our consolidated financial statements. We continue to focus on reducing future environmental liabilities by maintaining appropriate company standards and improving our assurance programs.

ITEM 1A. RISK FACTORS

An investment in our common stock involves various risks. When considering an investment in Baker Hughes, one should carefully consider all of the risk factors described below, as well as other information included and incorporated by reference in this report. There may be additional risks, uncertainties and matters not listed below, that we are unaware of, or that we currently consider

 

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immaterial. Any of these may adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in Baker Hughes.

Risk Factors Related to the Worldwide Oil and Natural Gas Industry

Our business is focused on providing products and services to the worldwide oil and natural gas industry; therefore, our risk factors include those factors that impact, either positively or negatively, the markets for oil and natural gas. Expenditures by our customers for exploration, development and production of oil and natural gas are based on their expectations of future hydrocarbon demand, the risks associated with developing the reserves, their ability to finance exploration for and development of reserves, and the future value of the reserves. Their evaluation of the future value is based, in part, on their expectations for global demand, global supply, excess production capacity, inventory levels, and other factors that influence oil and natural gas prices. The key risk factors we believe are currently influencing the worldwide oil and natural gas markets are discussed below.

Demand for oil and natural gas is subject to factors beyond our control, which may adversely affect our operating results. Changes in the global economy could impact our customers’ spending levels and our revenue and operating results.

Demand for oil and natural gas, as well as the demand for our services, is highly correlated with global economic growth, and in particular by the economic growth of countries such as the U.S., India, China, and developing countries in Asia and the Middle East who are either significant users of oil and natural gas or whose economies are experiencing the most rapid economic growth compared to the global average. The most recent slowdown in global economic growth and recession in the developed economies resulted in reduced demand for oil and natural gas, increased spare productive capacity and lower energy prices. Weakness or deterioration of the global economy or credit markets or a continuation of the European sovereign debt crisis could reduce our customers’ spending levels and reduce our revenue and operating results. Incremental weakness in global economic activity, particularly in China, India, Europe, the Middle East and developing countries in Asia, will reduce demand for oil and natural gas and result in lower oil and natural gas prices. Incremental strength in global economic activity in such areas will create more demand for oil and natural gas and support higher oil and natural gas prices. In addition, demand for oil and natural gas could be impacted by environmental regulation, including “cap and trade” legislation, regulation of hydraulic fracturing, carbon taxes and the cost for carbon capture and sequestration related regulations.

Volatility of oil and natural gas prices can adversely affect demand for our products and services.

Volatility in oil and natural gas prices can also impact our customers’ activity levels and spending for our products and services. Current energy prices are important contributors to cash flow for our customers and their ability to fund exploration and development activities. Expectations about future prices and price volatility are important for determining future spending levels.

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

Our customers’ activity levels and spending for our products and services and ability to pay amounts owed us could be impacted by the ability of our customers to access equity or credit markets.

Our customers’ access to capital is dependent on their ability to access the funds necessary to develop economically attractive projects based upon their expectations of future energy prices, required investments and resulting returns. Limited access to external sources of funding has and may continue to cause customers to reduce their capital spending plans to levels supported by internally-generated cash flow. In addition, a reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities or the lack of availability of debt or equity financing may impact the ability of our customers to pay amounts owed to us.

Supply of oil and natural gas is subject to factors beyond our control, which may adversely affect our operating results.

Productive capacity for oil and natural gas is dependent on our customers’ decisions to develop and produce oil and natural gas reserves and on the regulatory environment in which our customers and we operate. The ability to produce oil and natural gas can be affected by the number and productivity of new wells drilled and completed, as well as the rate of production and resulting depletion of existing wells. Advanced technologies, such as horizontal drilling and hydraulic fracturing, improve total recovery but also result in a more rapid production decline and may become subject to more stringent regulation in the future.

 

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Access to prospects is also important to our customers and such access may be limited because host governments do not allow access to the reserves or because another oil and natural gas exploration company owns the rights to develop the prospect.

Government regulations and the costs incurred by oil and natural gas exploration companies to conform to and comply with government regulations, may also limit the quantity of oil and natural gas that may be economically produced.

Supply can also be impacted by the degree to which individual Organization of Petroleum Exporting Countries (“OPEC”) nations and other large oil and natural gas producing countries, including, but not limited to, Norway and Russia, are willing and able to control production and exports of oil, to decrease or increase supply and to support their targeted oil price while meeting their market share objectives. Any of these factors could affect the supply of oil and natural gas and could have a material adverse effect on our results of operations.

Changes in spare productive capacity or inventory levels can be indicative of future customer spending to explore for and develop oil and natural gas which in turn influences the demand for our products and services.

Spare productive capacity and oil and natural gas storage inventory levels are an indicator of the relative balance between supply and demand. High or increasing storage or inventories generally indicate that supply is exceeding demand and that energy prices are likely to soften. Low or decreasing storage or inventories are an indicator that demand is growing faster than supply and that energy prices are likely to rise. Measures of maximum productive capacity compared to demand (“spare productive capacity”) are also an important factor influencing energy prices and spending by oil and natural gas exploration companies. When spare productive capacity is low compared to demand, energy prices tend to be higher and more volatile, reflecting the increased vulnerability of the entire system to disruption.

Seasonal and weather conditions could adversely affect demand for our services and operations.

Weather can have a significant impact on demand as consumption of energy is seasonal, and any variation from normal weather patterns, such as cooler or warmer summers and winters, can have a significant impact on demand. Adverse weather conditions, such as hurricanes in the Gulf of Mexico, may interrupt or curtail our operations, or our customers’ operations, cause supply disruptions and result in a loss of revenue and damage to our equipment and facilities, which may or may not be insured. Extreme winter conditions in Canada, Russia or the North Sea may interrupt or curtail our operations, or our customers’ operations, in those areas and result in a loss of revenue.

Risk Factors Related to Our Business

Our expectations regarding our business are affected by the following risk factors and the timing of any of these risk factors:

We operate in a highly competitive environment, which may adversely affect our ability to succeed.

We operate in a highly competitive environment for marketing oilfield services and securing equipment and trained personnel. Our ability to continually provide competitive products and services can impact our ability to defend, maintain or increase prices for our products and services, maintain market share and negotiate acceptable contract terms with our customers. In order to be competitive, we must provide new technologies, reliable products and services that perform as expected and that create value for our customers, and successfully recruit and train competent personnel. Our ability to defend, maintain or increase prices for our products and services is in part dependent on the industry’s capacity relative to customer demand, and on our ability to differentiate the value delivered by our products and services from our competitors’ products and services.

Managing development of competitive technology and new product introductions on a forecasted schedule and at forecasted costs can impact our financial results. Development of competing technology that accelerates the obsolescence of any of our products or services can have a detrimental impact on our financial results.

We may be disadvantaged competitively and financially by a significant movement of exploration and production operations to areas of the world in which we are not currently active.

The high cost or unavailability of infrastructure, materials, equipment, supplies and personnel, particularly in periods of rapid growth, could adversely affect our ability to execute our operations on a timely basis.

Our manufacturing operations are dependent on having sufficient raw materials, component parts and manufacturing capacity available to meet our manufacturing plans at a reasonable cost while minimizing inventories. Our ability to effectively manage our

 

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manufacturing operations and meet these goals can have an impact on our business, including our ability to meet our manufacturing plans and revenue goals, control costs, and avoid shortages of raw materials and component parts. Raw materials and components of

particular concern include steel alloys (including chromium and nickel), titanium, barite, beryllium, copper, lead, tungsten carbide, synthetic and natural diamonds, gels, sand and other proppants, printed circuit boards and other electronic components and hydrocarbon-based chemical feed stocks. Our ability to repair or replace equipment damaged or lost in the well can also impact our ability to service our customers. A lack of manufacturing capacity could result in increased backlog, which may limit our ability to respond to short lead time orders.

People are a key resource to developing, manufacturing and delivering our products and services to our customers around the world. Our ability to manage the recruiting, training, retention and efficient usage of the highly skilled workforce required by our plans and to manage the associated costs could impact our business. A well-trained, motivated workforce has a positive impact on our ability to attract and retain business. Periods of rapid growth present a challenge to us and our industry to recruit, train and retain our employees, while managing the impact of wage inflation and potential lack of available qualified labor in the markets where we operate. Likewise, when there is a downturn in the economy or our markets, we may have to adjust our workforce to control costs and yet not lose our skilled and diverse workforce. Labor-related actions, including strikes, slowdowns and facility occupations can also have a negative impact on our business.

Our business is subject to geopolitical, terrorism, and cybersecurity risks and other threats.

Geopolitical and terrorism risks continue to grow in several key countries where we do business. Geopolitical and terrorism risks could lead to, among other things, a loss of our investment in the country, impairment of the safety of our employees and impairment of our ability to conduct our operations. Threats to our information technology systems associated with cybersecurity risks and cyber incidents or attacks also continue to grow. It is also possible that breaches to our systems could go unnoticed for some period of time. Risks associated with these threats include, among other things, loss of intellectual property, impairment of our ability to conduct our operations, disruption of our customers’ operations, loss or damage to our customer data delivery systems and increased costs to prevent, respond to or mitigate cybersecurity events.

Our failure to comply with the Foreign Corrupt Practices Act (“FCPA”) would have a negative impact on our ongoing operations.

We entered into settlements with the U.S. Department of Justice (“DOJ”) and the SEC in April 2007 relating to violations of the FCPA by the Company. Our ability to comply with the FCPA is dependent on the success of our ongoing compliance program, including our ability to continue to manage our agents and business partners, and supervise, train and retain competent employees. Our compliance program is also dependent on the efforts of our employees to comply with applicable law and the Baker Hughes Business Code of Conduct. We would be subject to sanctions and civil and criminal prosecution as well as fines and penalties in the event of a finding of an additional violation of the FCPA by us or any of our employees.

Compliance with and changes in laws could be costly and could affect operating results.

We have operations in the U.S. and in more than 80 countries that can be impacted by expected and unexpected changes in the legal and business environments in which we operate. Our ability to manage our compliance costs and compliance programs will impact our ability to meet our earnings goals. Compliance related issues could also limit our ability to do business in certain countries. Changes that could impact the legal environment include new legislation, new regulations, new policies, investigations and legal proceedings and new interpretations of existing legal rules and regulations, in particular, changes in export control laws or exchange control laws, additional restrictions on doing business in countries subject to sanctions, and changes in laws in countries where we operate or intend to operate.

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

Changes in tax laws or tax rates, the resolution of tax assessments or audits by various tax authorities, and the ability to fully utilize our tax loss carryforwards and tax credits could impact 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 materially impacted.

Our tax filings for various periods are subject to audit by the tax authorities in most jurisdictions where we conduct business. We have received tax assessments from various taxing authorities and are currently at varying stages of appeals and/or litigation regarding these matters. These audits may result in assessment of additional taxes that are 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.

 

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Changes in and compliance with restrictions or regulations on offshore drilling has and may continue to adversely affect our business and operating results and reduce the need for our services in those areas.

While the moratorium on drilling offshore in the U.S. was lifted on October 12, 2010, there has been a delay in resuming permitting of operations related to drilling offshore in the U.S. and there is no assurance that operations related to drilling offshore in the U.S. will reach the same levels that existed prior to the moratorium. The delay in resuming these activities or the failure of these activities to reach levels that existed prior to the moratorium has and could continue to adversely impact our operating results. New and proposed legislation and regulation in the U.S. and other parts of the world of the offshore oil and natural gas industry may result in substantial increases in costs or delays in drilling or other operations in the Gulf of Mexico and other parts of the world, oil and natural gas projects becoming potentially non-economic, and a corresponding reduced demand for our services. We cannot predict with any certainty the impact of the prior moratorium or the substance or effect of any new or additional regulations. If the U.S. or other countries where we operate, enact stricter restrictions on offshore drilling or further regulate offshore drilling or contracting services operations, including without limitation cementing, higher operating costs could result and adversely affect our business and operating results.

If the Company were to be involved in a future incident similar to the 2010 Deepwater Horizon accident, the Company could suffer significant financial losses that could severely impair the Company. Protections available to the Company through contractual terms and insurance coverage may not be sufficient to protect the Company in the event we were involved in that type of an incident.

Uninsured claims and litigation against us could adversely impact our operating results.

We could be impacted by the outcome of pending litigation as well as unexpected litigation or proceedings. We have insurance coverage against operating hazards, including product liability claims and personal injury claims related to our products, to the extent deemed prudent by our management and to the extent insurance is available; however, no assurance can be given that the nature and amount of that insurance will be sufficient to fully indemnify us against liabilities arising out of pending and future claims and litigation. This insurance has deductibles or self-insured retentions and contains certain coverage exclusions. The insurance does not cover damages from breach of contract by us or based on alleged fraud or deceptive trade practices. In addition, the following risks apply with respect to our insurance coverage:

 

   

we may not be able to continue to obtain insurance on commercially reasonable terms;

   

we may be faced with types of liabilities that will not be covered by our insurance;

   

our insurance carriers may not be able to meet their obligations under the policies; or

   

the dollar amount of any liabilities may exceed our policy limits.

Whenever possible, we obtain agreements from customers that limit our liability. However, state law, laws or public policy in countries outside the U.S., or the negotiated terms of the agreement with the customer may not recognize those limitations of liability and/or limit the customer’s indemnity obligations to the Company. In addition, insurance and customer agreements do not provide complete protection against losses and risks from an event, like a well blow out that can lead to property damage, personal injury, death or the discharge of hazardous materials into the environment. Our results of operations could be adversely affected by unexpected claims not covered by insurance.

Compliance with, and rulings and litigation in connection with, environmental regulations and the environmental impacts of our or our customers’ operations may adversely affect our business and operating results.

Our business is impacted by unexpected outcomes or material changes in environmental laws, rulings and litigation. Our expectations regarding our compliance with environmental laws and our expenditures to comply with environmental laws, including (without limitation) our capital expenditures for environmental control equipment, are only our forecasts regarding these matters. These forecasts may be substantially different from actual results, which may be affected by factors such as: changes in law that impose new restrictions on air emissions, wastewater management, waste disposal, hydraulic fracturing, or wetland and land use practices; more stringent enforcement of existing environmental regulations; a change in our allocation or other unexpected, adverse outcomes with respect to sites where we have been named as a PRP, including (without limitation) Superfund sites; the discovery of other sites where additional expenditures may be required to comply with environmental legal obligations; and the accidental discharge of hazardous materials.

International, national, and state governments and agencies are currently evaluating and promulgating legislation and regulations that are focused on restricting emissions commonly referred to as greenhouse gas (“GHG”) emissions. In the U.S., the EPA has taken steps to regulate GHGs as pollutants under the Clean Air Act. The EPA’s “Mandatory Reporting of Greenhouse Gases” rule established in 2010 provided a comprehensive scheme of regulations that require monitoring and reporting of GHG emissions.

 

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Furthermore, the EPA has issued additional GHG reporting rules specifically for the oil and natural gas industry, which now include mobile as well as stationary GHG emission sources. These rules are expected to apply to some of our wellsite equipment and operations in the future. The EPA has also published a final rule, the “Endangerment Finding,” indicating that GHGs in the atmosphere endanger public health and welfare, and that emissions of GHGs from mobile sources also contribute. Following issuance of the Endangerment Finding, the EPA also promulgated final motor vehicle GHG emission standards on April 1, 2010. These developments may curtail production and demand for fossil fuels such as oil and natural gas in areas of the world where our customers operate and thus adversely affect future demand for our services, which may in turn adversely affect future results of operations.

International developments focused on restricting the emission of carbon dioxide and other gases include the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol” (an internationally applied protocol, which has been ratified in Canada) and the European Union’s Emission Trading System. The Carbon Reduction Commitment in the U.K. is the first cap and trade scheme to affect Baker Hughes’ facilities. Domestic cap and trade programs include the Regional Greenhouse Gas Initiative in the northeastern U.S. and the Western Regional Climate Action Initiative in the western U.S. These developments may curtail production and demand for fossil fuels such as oil and natural gas in areas of the world where our customers operate and thus adversely affect future demand for our services, which may in turn adversely affect future results of operations.

Demand for pressure pumping services could be reduced or eliminated by governmental regulation or a change in the law.

Some federal, state and foreign governmental bodies have adopted laws and regulations or are considering legislative and regulatory proposals that, if signed into law, would among other things require the public disclosure of chemicals used in hydraulic fracturing operations and would subject hydraulic fracturing to more stringent regulation. Such federal, state or foreign legislation and/or regulations could impair our operations, increase our operating costs, and/or greatly reduce or eliminate demand for the Company’s pressure pumping services. The EPA and other governmental bodies are studying hydraulic fracturing operations. Government responses to these studies and to public concerns relating to the development of unconventional oil and natural gas resources may impede the development of these resources by our customers, delaying or reducing the demand for our services. We are unable to predict whether the proposed changes in law or any other governmental proposals or responses will ultimately occur, and if so, the impact on our business.

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

Much of the world’s oil and natural gas reserves are controlled by state-owned oil companies. State-owned oil companies may require their contractors to meet local content requirements or other local standards, such as joint ventures, that could be difficult or undesirable for the Company to meet. The failure to meet the local content requirements and other local standards may adversely impact the Company’s operations in those countries. In addition, our ability to work with state-owned oil companies is subject to our ability to negotiate and agree upon acceptable contract terms.

In addition, many state-owned oil companies may require integrated contracts or turnkey contracts that could require the Company to provide services outside its core business. Providing services on an integrated or turnkey basis generally requires the Company to assume additional risks.

Currency fluctuations may impact our operating results.

Fluctuations in foreign currencies relative to the U.S. Dollar can impact our revenue and our costs of doing business. Most of our products and services are sold through contracts denominated in U.S. Dollars or local currency indexed to U.S. Dollars; however, some of our revenue, local expenses and manufacturing costs are incurred in local currencies and therefore changes in the exchange rates between the U.S. Dollar and foreign currencies can increase or decrease our revenue and expenses reported in U.S. Dollars and may impact our results of operations.

Changes in economic conditions may impact our ability to borrow and/or cost of borrowing.

The condition of the capital markets and equity markets in general can affect the price of our common stock and our ability to obtain financing, if necessary. If the Company’s credit rating is downgraded, this would increase borrowing costs under our credit facility and commercial paper program, as well as the cost of renewing or obtaining, or make it more difficult to renew or obtain or issue new debt financing.

 

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Changes in market conditions may impact any stock repurchases.

To the extent the Company engages in stock repurchases, such activity is subject to market conditions, such as the trading prices for our stock, as well as the terms of any stock purchase plans intended to comply with Rule 10b5-1 or Rule 10b-18 of the Exchange Act. Management, in its discretion, may engage in or discontinue stock repurchases at any time.

The Company’s revenue and profit before tax are concentrated in North America.

During the year ended December 31, 2011, over one-half of our revenue and over three-fourths of our profit before tax were attributable to North America. In North America, a decrease in demand for energy or in oil and natural gas exploration and production, or an increase in competition could result in a significant adverse effect on our operating results.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

We own or lease numerous properties throughout the world. We consider our manufacturing plants, equipment assembly, maintenance, and overhaul facilities, grinding plants, drilling fluids and chemical processing centers, and research and technology centers to be our principal properties. The following sets forth the location of our principal owned or leased facilities for our oilfield operations by geographic segment:

 

NorthAmerica:

   Houston, Pasadena, Tomball, and The Woodlands, Texas; Barnsdall, Broken Arrow, Claremore and Sand Springs, Oklahoma; Bossier City, Broussard, and Lafayette, Louisiana.

LatinAmerica:

   Maracaibo, Venezuela; Macae (Rio de Janeiro), Brazil.

Europe/Africa/Russia Caspian:

   Aberdeen, Scotland; Liverpool, England; Celle, Germany; Tananger, Norway; Port Harcourt, Nigeria.

Middle East/Asia Pacific:

   Dubai, United Arab Emirates; Dhahran, Saudi Arabia; Singapore, Singapore; Chonburi, Thailand.

Principal properties for the Industrial Services and Other segment are mainly shared facilities with the oilfield operations located in Houston, Texas; Barnsdall, Oklahoma; Aberdeen, Scotland; Liverpool, England; and Dubai, United Arab Emirates.

We own or lease numerous other facilities such as service centers, shops and sales and administrative offices throughout the geographic regions in which we operate. We also have a significant investment in service vehicles, tools and manufacturing and other equipment. All of our owned properties are unencumbered. We believe that our facilities are well maintained and suitable for their intended purposes.

ITEM 3. LEGAL PROCEEDINGS

The information with respect to Item 3. Legal Proceedings is contained in Note 13 of the Notes to Consolidated Financial Statements in Item 8 herein.

ITEM 4. MINE SAFETY DISCLOSURES

Our barite mining operations, in support of our drilling fluids products and services business, are subject to regulation by the federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this report.

 

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock, $1.00 par value per share, is principally traded on the New York Stock Exchange. Our common stock is also traded on the SWX Swiss Exchange. As of February 16, 2012, there were approximately 257,100 stockholders and approximately 12,500 stockholders of record.

For information regarding quarterly high and low sales prices on the New York Stock Exchange for our common stock during the two years ended December 31, 2011, and information regarding dividends declared on our common stock during the two years ended December 31, 2011, see Note 15 of the Notes to Consolidated Financial Statements in Item 8 herein.

The following table contains information about our purchases of equity securities during the fourth quarter of 2011.

Issuer Purchases of Equity Securities

 

Period    Total Number
of Shares
Purchased (1)
    

Average

Price Paid
Per Share (1)

     Total
Number of
Shares
Purchased
as Part of a
Publicly
Announced
Program (2)
     Average
Price Paid
Per Share (2)
     Total
Number of
Shares
Purchased
in the
Aggregate
     Maximum
Number (or
Approximate
Dollar Value) of
Shares that May
Yet Be
Purchased Under
the Program (3)
 

October 1-31, 2011

     3,822       $ 53.74         —         $ —           3,822       $ —     

November 1-30, 2011

     96         48.87         —           —           96         —     

December 1-31, 2011

     —           —           —           —           —           —     

Total

     3,918       $ 53.62         —         $ —           3,918       $ 1,197,127,803   

 

  (1) 

Represents shares purchased from employees to pay the option exercise price related to stock-for-stock exchanges in option exercises or to satisfy the tax withholding obligations in connection with the vesting of restricted stock awards and restricted stock units.

  (2) 

There were no share repurchases during the fourth quarter of 2011 as part of a publicly announced program.

  (3) 

Our Board of Directors has authorized a program to repurchase our common stock from time to time. During the fourth quarter of 2011, we did not repurchase any shares of our common stock under the program. We had authorization remaining to repurchase up to a total of $1,197 million of our common stock.

 

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Corporate Performance Graph

The following graph compares the yearly change in our cumulative total stockholder return on our common stock (assuming reinvestment of dividends into common stock at the date of payment) with the cumulative total return on the published Standard & Poor’s (“S&P”) 500 Stock Index and the cumulative total return on the S&P 500 Oil and Gas Equipment and Services Index over the preceding five-year period.

Comparison of Five-Year Cumulative Total Return *

Baker Hughes Incorporated; S&P 500 Index and S&P 500 Oil and Gas Equipment and Services Index

 

LOGO

 

     2006      2007      2008      2009      2010      2011  

Baker Hughes

   $ 100.00       $ 109.35       $ 43.72       $ 56.06       $ 80.20       $ 69.07   

S&P 500 Index

     100.00         105.49         66.46         84.05         96.71         98.75   

S&P 500 Oil and Gas Equipment and Services Index

     100.00         147.90         60.38         96.73         134.72         119.16   

* Total return assumes reinvestment of dividends on a quarterly basis.

The comparison of total return on investment (change in year-end stock price plus reinvested dividends) assumes that $100 was invested on December 31, 2006 in Baker Hughes common stock, the S&P 500 Index and the S&P 500 Oil and Gas Equipment and Services Index.

The corporate performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that Baker Hughes specifically incorporates it by reference into such filing.

 

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ITEM 6. SELECTED FINANCIAL DATA

The Selected Financial Data should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data, both contained herein.

 

     Year Ended December 31,  

(In millions, except per share amounts)

     2011        2010 (3)      2009        2008        2007   

Revenue

   $ 19,831      $ 14,414      $ 9,664      $ 11,864      $ 10,428   

Operating income (1)

     2,600        1,417        732        2,376        2,278   

Non-operating expense, net

     (261     (135     (121     (57     (21

Income before income taxes

     2,339        1,282        611        2,319        2,257   

Income taxes (2)

     (596     (463     (190     (684     (743

Net income

     1,743        819        421        1,635        1,514   

Net income attributable to noncontrolling interest

     (4     (7     —          —          —     

Net income attributable to Baker Hughes

   $ 1,739      $ 812      $ 421      $ 1,635      $ 1,514   

Per share of common stock:

          

Net income attributable to Baker Hughes:

          

Basic

   $ 3.99      $ 2.06      $ 1.36      $ 5.32      $ 4.76   

Diluted

     3.97        2.06        1.36        5.30        4.73   

Dividends

     0.60        0.60        0.60        0.56        0.52   

Balance Sheet Data:

          

Cash, cash equivalents and short-term investments

   $ 1,050      $ 1,706      $ 1,595      $ 1,955      $ 1,054   

Working capital (current assets minus current liabilities)

     6,295        5,568        4,612        4,634        3,837   

Total assets

     24,847        22,986        11,439        11,861        9,857   

Long-term debt

     3,845        3,554        1,785        1,775        1,069   

Equity

     15,964        14,286        7,284        6,807        6,306   

Notes To Selected Financial Data

 

  (1) 

Operating income for 2011 includes a charge of $315 million ($220 million net of tax), the majority of which relates to the impairment associated with the decision to minimize the use of the BJ Services trade name. For further discussion, see Note 8 of the Notes to Consolidated Financial Statements in Item 8 herein.

  (2) 

Income taxes for 2011 include a tax benefit of $214 million associated with the reorganization of certain foreign subsidiaries. For further discussion, see Note 4 of the Notes to Consolidated Financial Statements in Item 8 herein.

  (3) 

We acquired BJ Services on April 28, 2010, and their financial results from the date of acquisition through the end of 2010 are included in our results. For further discussion, see Note 2 of the Notes to Consolidated Financial Statements in Item 8 herein.

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the consolidated financial statements of Item 8. Financial Statements and Supplementary Data contained herein.

EXECUTIVE SUMMARY

Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry. We provide products and services for:

 

   

drilling and evaluation of oil and natural gas wells;

   

completion and production of oil and natural gas wells; and

   

other industries, including downstream refining and process and pipeline industries as well as reservoir development services.

We operate our business primarily through geographic regions that have been aggregated into five reportable segments: North America, Latin America, Europe/Africa/Russia Caspian, Middle East/Asia Pacific and Industrial Services and Other. The four geographical segments represent our oilfield operations.

Within our oilfield operations, the primary driver of our businesses is our customers’ capital and operating expenditures dedicated to oil and natural gas exploration, field development and production. Our business is cyclical and is dependent upon our customers’ expectations for future oil and natural gas prices, economic growth, hydrocarbon demand and estimates of current and future oil and natural gas production.

For 2011, we generated revenue of $19.83 billion, an increase of $5.42 billion or 38% compared to 2010. North America oilfield revenue for 2011 was $10.26 billion, an increase of 55% compared to 2010. Oilfield revenue outside of North America was $8.33 billion, an increase of 22% compared to 2010. Industrial Services and Other revenue was $1.25 billion, an increase of 28% compared to 2010. These increases are primarily due to the increase in activity and service intensity primarily in North America, driven by oil-directed drilling mainly in unconventional reservoirs. The increase in revenue was also due to the acquisition of BJ Services, which occurred in April of 2010.

Net income attributable to Baker Hughes was $1.74 billion for 2011 compared to $812 million for 2010. The increase in net income was chiefly due to increased activity in North America and to a lesser extent internationally. The increase in net income was also due to the acquisition of BJ Services.

As of December 31, 2011, Baker Hughes had approximately 57,700 employees compared to approximately 53,100 employees as of December 31, 2010.

BUSINESS ENVIRONMENT

In North America, customer spending increased for both oil and natural gas projects resulting in a 21% increase in the North America rig count in 2011 compared to 2010. Oil-directed drilling increased 60% in 2011 compared to 2010, reflecting an energy equivalent premium relative to natural gas in North America. Natural gas-directed drilling activity declined 6% in 2011 compared to 2010, as decreased activity in unconventional natural gas shale plays with relatively little associated natural gas liquids (dry gas) was partially offset by increased activity in the unconventional liquid-rich natural gas shale plays with relatively high volumes of associated natural gas liquids (wet gas). Despite relatively weak natural gas prices, spending on natural gas-directed projects in 2011 was supported by: (1) associated production of natural gas liquids and crude oil in certain basins; (2) hedges on production made in prior periods when future prices were higher; (3) the need of companies to drill and produce natural gas to hold leases acquired in earlier periods; and (4) the influx of equity from companies interested in developing a position in the unconventional shale resource plays.

Outside of North America customer spending is most heavily influenced by Brent oil prices, which increased 39% in 2011 compared to 2010 as the economic recovery continued. While oil prices were higher year over year, recent concerns about European fiscal issues, slower growth in China, India and the threat of a U.S. recession have restrained oil prices; however, our customers’ spending was not adversely affected in 2011. This was reflected in a 7% increase in the rig count outside of North America.

 

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Oil and Natural Gas Prices

Oil and natural gas prices are summarized in the table below as averages of the daily closing prices during each of the periods indicated.

 

      2011      2010      2009  

Brent oil prices ($/Bbl) (1)

   $ 111.05       $ 79.73       $ 62.04   

WTI oil prices ($/Bbl) (2)

     95.08         79.51         61.99   

Natural gas prices ($/mmBtu) (3)

     3.99         4.37         3.94   

 

  (1) Bloomberg Dated Brent (“Brent”)
  (2) Bloomberg West Texas Intermediate (“WTI”) Cushing Crude Oil Spot Price
  (3) Bloomberg Henry Hub Natural Gas Spot Price

Brent oil prices averaged $111.05/Bbl in 2011. Prices ranged from a low of $92.98/Bbl in January 2011 to a high of $126.74/Bbl in April 2011. Beginning in May 2011 and continuing throughout the remainder of 2011, oil prices weakened driven by expectations of a slowdown of the worldwide economic recovery and energy demand growth, particularly in Europe. The International Energy Agency (“IEA”) estimated in its February 2012 Oil Market Report that worldwide demand would increase 0.8 million barrels per day, or 0.9%, to 89.9 million barrels per day in 2012, up from 89.1 million barrels per day in 2011.

WTI oil prices averaged $95.08/Bbl in 2011. Prices ranged from a high of $113.93/Bbl in April 2011 to a low of $75.67/Bbl in October 2011. Similar to the Brent oil prices, WTI oil prices climbed through the first four months of 2011 but then weakened throughout the remainder of 2011.

Natural gas prices averaged $3.99/mmBtu in 2011. Much like oil prices, natural gas prices peaked mid-year with a high of $4.92/mmBtu in June 2011 and then continued to weaken throughout the latter half of 2011, falling to a low of $2.83/mmBtu in late November 2011. According to the U.S. Department of Energy (“DOE”), working natural gas in storage at the end of 2011 was 3,472/Bcf, which was 12% or 375/Bcf above the corresponding week in 2010.

Rig Counts

Baker Hughes has been providing rig counts to the public since 1944. We gather all relevant data through our field service personnel, who obtain the necessary data from routine visits to the various rigs, customers, contractors and/or other outside sources. This data is then compiled and distributed to various wire services and trade associations and is published on our website. Rig counts are compiled weekly for the U.S. and Canada and monthly for all international and U.S. workover rigs. Published international rig counts do not include rigs drilling in certain locations, such as Russia, the Caspian, Iraq and onshore China, because this information is not readily available.

Rigs in the U.S. and Canada are counted as active if, on the day the count is taken, the well being drilled has been started but drilling has not been completed and the well is anticipated to be of sufficient depth to be a potential consumer of our drill bits. In international areas, rigs are counted on a weekly basis and deemed active if drilling activities occurred during the majority of the week. The weekly results are then averaged for the month and published accordingly. The rig count does not include rigs that are in transit from one location to another, rigging up, being used in non-drilling activities, including production testing, completion and workover, and are not expected to be significant consumers of drill bits.

 

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Our rig counts are summarized in the table below as averages for each of the periods indicated.

 

      2011      2010      2009  

U.S. - land and inland waters

     1,846         1,514         1,046   

U.S. - offshore

     32         31         44   

Canada

     418         348         222   

North America

     2,296         1,893         1,312   

Latin America

     424         383         356   

North Sea

     38         43         43   

Continental Europe

     80         51         41   

Africa

     78         83         62   

Middle East

     291         265         252   

Asia Pacific

     256         269         243   

Outside North America

     1,167         1,094         997   

Worldwide

     3,463         2,987         2,309   

2011 Compared to 2010

The rig count in North America increased 21% reflecting a 66% increase in the U.S. oil-directed rig count partially offset by a 6% decrease in the U.S. natural gas-directed rig count, and a 40% increase in the Canadian oil-directed rig count partially offset by a 5% decrease in the Canadian natural gas-directed rig count. The growth in oil-directed drilling was primarily a result of the industry’s ability to apply drilling and completion techniques to unconventional oil reservoirs that were originally applied to similar natural gas reservoirs. As these techniques have proved successful, they have enabled a substantial volume of oil reserves to be produced in the U.S., which has led to a significant increase in oil-directed drilling activity. Natural gas-directed drilling was negatively impacted by the continued weakness in U.S. natural gas prices, which discouraged new investment in natural gas fields.

Outside North America the rig count increased 7%. In general, the international rig count increased as operators responded to relatively strong oil prices that were well above the level considered economical to develop new reserves in the primary hydrocarbon basins of the world. The rig count in Latin America increased primarily due to higher rig activity in Colombia, Venezuela and Brazil. The increase in Continental Europe was led by Turkey and Poland. The rig count in Africa decreased chiefly due to the shutdown of activity in Libya, partially offset with stronger activity in Algeria and Gabon. The rig count increased in the Middle East primarily due to higher activity in Kuwait, Egypt and Abu Dhabi, partially offset by decline in activity in Yemen. In Asia Pacific, activity decreased primarily in Malaysia, Indonesia and Vietnam while activity increased in India.

RESULTS OF OPERATIONS

The discussions below relating to significant line items from our consolidated statements of operations are based on available information and represent our analysis of significant changes or events that impact the comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect comparability or trends and, where possible and practical, have quantified the impact of such items. We acquired BJ Services on April 28, 2010, and the financial results of its operations since the acquisition date are included in each of the five reportable segments. In addition, the discussions below for revenue and cost of revenue are on a total basis as the business drivers for the individual components of product sales and services are similar. All dollar amounts in tabulations in this section are in millions of dollars, unless otherwise stated.

Revenue and Profit Before Tax

The performance of our operating segments is evaluated based on profit before tax, which is defined as income before the following: income taxes, net interest expense, corporate expenses, and certain gains and losses not allocated to the segments. For 2011, operating segment profit before tax includes a charge of $315 million related to the impairment of trade names.

 

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2011 Compared to 2010

 

     Year Ended December 31,         
      2011      2010     

Increase

(decrease)

    % Change  

Revenue:

          

North America

   $ 10,257       $ 6,621       $ 3,636        55

Latin America

     2,183         1,569         614        39

Europe/Africa/Russia Caspian

     3,325         3,006         319        11

Middle East/Asia Pacific

     2,820         2,247         573        26

Industrial Services and Other

     1,246         971         275        28

Total

   $ 19,831       $ 14,414       $ 5,417        38
     Year Ended December 31,         
      2011      2010      Increase
(decrease)
    % Change  

Profit Before Tax:

          

North America

   $ 1,929       $ 1,163       $ 766        66

Latin America

     227         74         153        207

Europe/Africa/Russia Caspian

     342         260         82        32

Middle East/Asia Pacific

     321         177         144        81

Industrial Services and Other

     53         99         (46     (46 )% 

Total

   $ 2,872       $ 1,773       $ 1,099        62

Revenue for 2011 increased $5.42 billion or 38% compared to 2010. The primary drivers of the change included increased activity and improved pricing in the U.S. Land and Canada markets and to a lesser extent, increased activity in our international segments. The increase is also due to the acquisition of BJ Services in April of 2010.

Profit before tax for 2011 increased $1.10 billion or 62% compared to 2010. The primary driver of this increase was the growth in revenue from all areas, but in particular in the North America segment where increased service intensity in the unconventional markets has led to increased efficiency, utilization, and pricing improvement. Additionally, profit before tax also benefitted from worldwide cost management initiatives and improved absorption of manufacturing and other overhead costs. The increase is also due to the acquisition of BJ Services in April of 2010. The increase in profit before tax was partially offset by the impairment of certain trade names.

North America

North America revenue increased 55% in 2011 compared to 2010. Revenue and pricing increases were supported by a 22% increase in the U.S. land and inland waters rig count and a 20% increase in the Canada rig count. The unconventional reservoirs continue to be the primary catalyst for the rapid growth seen in North America. The unconventional reservoirs require a substantially higher proportion of services from Baker Hughes across all product lines. Revenue in the Gulf of Mexico increased compared to 2010 as permitting modestly improved, but still lagged meaningfully behind pre-moratorium levels.

North America profit before tax was $1.93 billion in 2011, an increase of $766 million compared to 2010. The higher revenue for this segment, driven by activity and pricing, was the primary reason for this increase in profitability. Other drivers of the increase included improved tool utilization and improved absorption of manufacturing and other overhead. This improvement was offset by a decline in the fourth quarter of 2011 in the profitability of our pressure pumping services where we incurred increased costs related to shortages of raw materials, logistical inefficiencies and higher labor costs. Although there is positive progress in the Gulf of Mexico, the pace of re-permitting has not enabled activity to return to pre-moratorium levels. North America profit before tax was negatively impacted by a $105 million charge associated with the impairment of trade names.

Latin America

Latin America revenue increased 39% in 2011 compared to 2010. The primary drivers of the increase were the acceleration of activity benefitting our drilling fluids and artificial lift product lines in the Andean area as well as robust deep water growth through the use of our drilling services in Brazil, and to a lesser extent, modest pricing improvements.

 

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Latin America profit before tax increased 207% in 2011 compared to 2010. While increased revenue was a contributor to the increased profitability, the primary factors included cost containment initiatives, which improved overhead cost absorption, as well as meaningful operational improvements to lower our internal operating costs, a favorable change in the mix of the products and services sold to higher margin activity, and the completion of certain low margin contracts in early 2011. Latin America profit before tax was negatively impacted by a $64 million charge associated with the impairment of trade names.

Europe/Africa/Russia Caspian

Europe/Africa/Russia Caspian (“EARC”) revenue increased 11% in 2011 compared to 2010. The primary drivers of the increase were sales of completion tools and drilling fluids in Norway; increased drilling services activity in Turkey and Israel; modestly improving market conditions across Europe and Russia and higher drilling fluids, wireline services and drilling services activities in Nigeria. These increases were partially offset by the impact of decreased sales in Libya where our operations ceased during the second quarter of 2011 as a result of the civil unrest with minimal operational activity resuming during the fourth quarter of the year.

EARC profit before tax increased 32% in 2011 compared to 2010 primarily as a result of our increased focus on cost management initiatives and operating efficiencies. In addition, profitability improved as a result of increased activity and more favorable sales mix toward products and services with higher margins. EARC profit before tax was negatively impacted by a $70 million charge associated with increasing the allowance for doubtful accounts and reserves for inventory and certain other assets as a result of the civil unrest in Libya and by a $48 million charge associated with the impairment of trade names.

Middle East/Asia Pacific

Middle East/Asia Pacific (“MEAP”) revenue increased 26% in 2011 compared to 2010. The increase in this segment was attributable to higher activity in directional drilling and artificial lift systems and share gains in Saudi Arabia, as well as significant revenue gains in Kuwait, Iraq and Southeast Asia on production enhancement activity. Additionally, wireline and completions activity increased in Southeast Asia.

MEAP profit before tax increased 81% in 2011 compared to 2010 primarily as a result of our increased focus on cost management initiatives and operating efficiencies. In addition, profitability improved as a result of increased activity and more favorable sales mix, partially offset by costs for start-up activities in Iraq and elsewhere. MEAP profit before tax was negatively impacted by a $47 million charge associated with the impairment of trade names.

Industrial Services and Other

Industrial Services and Other revenue increased 28% in 2011 compared to 2010. Industrial Services and Other profit before tax decreased 46% in 2011 compared to 2010 primarily driven by a $51 million charge associated with the impairment of trade names and from an overall increase in cost of goods and services sold. This was partially offset by increased revenue and related profitability.

2010 Compared to 2009

 

     Year Ended December 31,         
              2010                      2009              Increase
(decrease)
     % Change  

Revenue:

           

North America

     $  6,621               $  3,165               $  3,456               109%       

Latin America

     1,569               1,094               475               43%       

Europe/Africa/Russia Caspian

     3,006               2,774               232               8%       

Middle East/Asia Pacific

     2,247               1,937               310               16%       

Industrial Services and Other

     971               694               277               40%       

Total

     $14,414               $  9,664               $  4,750               49%       

 

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     Year Ended December 31,         
            2010                  2009            Increase
(decrease)
     % Change  

Profit Before Tax:

           

North America

     $      1,163                   $      201                   $      962                   479%        

Latin America

     74                   78                   (4)                  (5)%        

Europe/Africa/Russia Caspian

     260                   458                   (198)                  (43)%        

Middle East/Asia Pacific

     177                   241                   (64)                  (27)%        

Industrial Services and Other

     99                   70                   29                   41%        

Total

     $      1,773                   $      1,048                   $      725                   69%        

Revenue for 2010 increased $4.75 billion or 49% compared to 2009. Excluding BJ Services, revenue for 2010 was up 11%. The primary drivers of the change included increased activity and improved pricing in the U.S. Land and Canada markets and to a lesser extent, increased activity in our international segments.

Profit before tax for 2010 increased $725 million or 69% compared to 2009. Excluding BJ Services, profit before tax was up 18% primarily due to strong activity in the North America segment where increased activity led to increased utilization, improved absorption of manufacturing and other overhead costs, and realized pricing improvement, partially offset by price degradation and lower profits in our international segments.

North America

North America revenue increased 109% in 2010 compared to 2009. Excluding BJ Services, revenue for 2010 was up 28%. Revenue and pricing increases were supported by a 45% increase in the U.S. land and inland waters rig count and a 57% increase in the Canada rig count. The unconventional reservoirs demanded our more advanced technology to deliver longer horizontals, complex completions, increased hydraulic horsepower and more fracturing stages resulting in improved pricing and higher revenue. This improvement was partially offset by a decline in our U.S. Gulf of Mexico revenue resulting from the drilling moratorium in the Gulf of Mexico.

North America profit before tax was $1.16 billion in 2010, an increase of $962 million compared to 2009. Excluding BJ Services, profit before tax for 2010 was up $438 million. In addition to higher revenue driven by increased activity, the primary drivers of the increase in profitability included improved tool utilization, improved absorption of manufacturing and other overhead, and higher pricing. This improvement was partially offset by a decline in our profitability in the U.S. Gulf of Mexico due to the drilling moratorium in the Gulf of Mexico.

Latin America

Latin America revenue increased 43% in 2010 compared to 2009. Excluding BJ Services, revenue for 2010 was up 14%. The primary drivers of the increase included increased activity and commensurate revenue growth in the Andean, Brazil and Southern Cone geomarkets driven by strong demand for artificial lift, directional drilling and drilling fluids products and services, partially offset by reduced activity in the Venezuela/Mexico geomarket.

Latin America profit before tax decreased 5% in 2010 compared to 2009. Excluding BJ Services, profit before tax increased 17%. Improved profit before tax from the Andean and Southern Cone geomarkets was partially offset by decreased profit before tax from the Brazil and Venezuela/Mexico geomarkets.

Europe/Africa/Russia Caspian

EARC revenue increased 8% in 2010 compared to 2009. Excluding BJ Services, revenue for 2010 decreased 1%. Reduced revenue from the North Africa and Continental Europe geomarkets was partially offset by higher revenue in the Russia, U.K., Nigeria and Norway geomarkets, where strong demand for directional drilling and artificial lift products and services was experienced.

EARC profit before tax decreased 43% in 2010 compared to 2009. Excluding BJ Services, profit before tax decreased 41%. Improved profit before tax in the Russia and Nigeria geomarkets was more than offset by reduced profit before tax throughout the rest of the region primarily due to lower activity in the North Africa geomarket, higher overhead costs and lower realized pricing.

 

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Middle East/Asia Pacific

MEAP revenue increased 16% in 2010 compared to 2009. Excluding BJ Services, revenue for 2010 was flat. Revenue increases occurred in the Saudi Arabia, Egypt, Australasia and Southeast Asia geomarkets, driven by higher activity benefiting our chemicals, artificial lift and completion systems products and services. These increases were offset by decreased revenue primarily in the Middle East Gulf and India geomarkets.

MEAP profit before tax decreased 27% in 2010 compared to 2009. Excluding BJ Services, profit before tax decreased 34% as improved profit before tax in the Egypt and North Asia geomarkets was more than offset by lower realized pricing and higher overhead costs throughout the rest of the region.

Industrial Services and Other

Industrial Services and Other revenue increased 40% in 2010 compared to 2009. Excluding BJ Services, revenue for 2010 increased 10%. Industrial Services and Other profit before tax increased 41% in 2010 compared to 2009. Excluding BJ Services, profit before tax increased 14%.

Costs and Expenses

The table below details certain consolidated statement of operations data and their percentage of revenue.

 

     2011     2010     2009  
      $      %     $      %     $      %  

Revenue

   $ 19,831         100   $ 14,414         100   $ 9,664         100

Cost of revenue

     15,264         77     11,184         78     7,397         77

Research and engineering

     462         2     429         3     397         4

Marketing, general and administrative

     1,190         6     1,250         9     1,120         12

Cost of Revenue

Cost of revenue as a percentage of revenue, which remained stable in 2011, was 77% and 78% for 2011 and 2010, respectively. The slight decrease was due primarily to improved pricing in North America coupled with improved operational efficiency and cost management initiatives implemented globally, which was offset by higher raw material, logistics and labor costs. In addition, cost of revenue was impacted by a $70 million charge in Libya where our operations ceased during the second quarter of 2011 with minimal operational activity resuming during the fourth quarter of the year.

Cost of revenue as a percentage of revenue was 78% and 77% for 2010 and 2009, respectively. The slight increase was primarily due to pricing pressures and higher operating costs for our geomarket organization, which we are mitigating through productivity improvements and cost cutting measures. As a result of the BJ Services acquisition, we incurred additional depreciation and amortization expense of $93 million in 2010 related to the step-up adjustments for property, plant and equipment and intangible assets.

Research and Engineering

Research and engineering expenses increased 8% in both 2011 and 2010 when compared to the corresponding previous year as we continue to be committed to developing and commercializing new technologies as well as investing in our core product offerings. We have global technology centers strategically placed around the world where we often collaborate with customers and local universities to jointly develop technology for specific regional needs as well as next-generation technology.

Marketing, General and Administrative

Marketing, general and administrative (“MG&A”) expenses decreased 5% in 2011 compared to 2010. The decrease in expenses resulted from cost reduction and management measures implemented in the latter half of 2010 and synergies we are realizing as we continue to integrate BJ Services into our operations.

MG&A expenses increased 12% in 2010 compared to 2009. The increase resulted primarily from costs associated with finance redesign efforts, software implementation activities and the acquisition of BJ Services.

 

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Impairment of Trade Names

In 2011, we recognized a charge of $315 million related to the impairment of certain trade names, the majority of which related to the BJ Services trade name. The impairment of the BJ Services trade name was due to the decision to minimize the use of the BJ Services trade name as part of our overall branding strategy for Baker Hughes.

Interest Expense, net

Interest expense, net of interest income, increased $80 million in 2011 compared to 2010. The increase was primarily due to the assumption of $500 million of debt associated with the acquisition of BJ Services in April 2010, issuance of $1.5 billion of debt in August 2010 and the issuance of $750 million of debt in August 2011. The increase in interest expense was partially offset by the repayment of $250 million of debt and the early extinguishment of $500 million debt in the second and third quarters of 2011, respectively.

Net interest expense increased $16 million in 2010 compared to 2009. The increase was primarily due to the issuance of $1.5 billion of debt in August 2010 and the assumption of $500 million of debt associated with the acquisition of BJ Services, partially offset by gains on our interest rate swaps of $16 million.

Loss on Early Extinguishment of Debt

In 2011, we redeemed in full $500 million of debt maturing November 2013 and paid a redemption premium of $63 million. The redemption resulted in a pre-tax loss of $40 million on the early extinguishment of debt which included the redemption premium and the write off of the remaining original debt issuance costs and debt discount, partially offset by the $25 million gain from the termination of two related interest rate swap agreements.

Income Taxes

Total income tax expense was $596 million for 2011. This amount includes a $214 million tax benefit associated with the reorganization of certain foreign subsidiaries. As a result of the reorganization, previously accrued U.S. deferred income taxes related to those subsidiaries were reduced by certain foreign tax credits that existed prior to the acquisition of BJ Services and are now available to offset future U.S. taxes. Excluding the impact of the reorganization, our effective tax rate on operating profits in 2011, 2010, and 2009 were 34.6%, 36.1% and 31.1%, respectively. The 2011 effective tax rate is lower than the U.S. statutory income tax rate of 35% due to lower rates of tax on certain international operations partially offset by state income taxes. The 2010 effective tax rate was higher than the U.S. statutory income tax rate of 35% due to higher rates of tax on certain international operations and state income taxes partially offset by tax benefits arising from the repatriation of foreign earnings. The 2009 effective tax rate was lower than the U.S. statutory rate of 35% due to lower rates of tax on certain international operations offset by state income taxes.

OUTLOOK

This section should be read in conjunction with the factors described in “Part I, Item 1A. Risk Factors” and in the “Forward-Looking Statements” section in this Part II, Item 7, both contained herein. These factors could impact, either positively or negatively, our expectation for: oil and natural gas demand; oil and natural gas prices; exploration and development spending and drilling activity; and production spending.

Our industry is cyclical, and past cycles have been driven primarily by alternating periods of ample supply or shortage of oil and natural gas relative to demand. As an oilfield services company, our revenue is dependent on spending by our customers for oil and natural gas exploration, field development and production. This spending is dependent on a number of factors, including our customers’ forecasts of future energy demand, their expectations for future energy prices, their access to resources to develop and produce oil and natural gas, their ability to fund their capital programs, and the impact of new government regulations.

Our outlook for exploration and development spending is based upon our expectations for customer spending in the markets in which we operate, and is driven primarily by our perception of industry expectations for oil and natural gas prices and their likely impact on customer capital and operating budgets as well as other factors that could impact the economic return oil and natural gas companies expect for developing oil and natural gas reserves. Our forecasts are based on evaluating a number of external sources as well as our internal estimates. External sources include publications by the IEA, OPEC, Energy Information Administration (“EIA”), and the Organization for Economic Cooperation and Development (“OECD”). We acknowledge that there is a substantial amount of uncertainty regarding these forecasts, thus, while we have internal estimates regarding economic expansion, hydrocarbon demand and overall oilfield activity, we position ourselves to be flexible and responsive to a wide range of potential outcomes.

 

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The primary drivers impacting the 2012 business environment include the following:

 

   

Worldwide Economic Growth - In general there is a strong linkage between overall economic activity, growth and the demand for hydrocarbons. Although we continue to see modest economic growth across the OECD countries and relatively strong growth among many developing economies, there is substantial concern regarding the economic outlook going into 2012. These concerns are primarily fueled by a concern over sovereign debt issues in Europe and a slowdown in the Chinese economy. The European sovereign debt crisis poses substantial risk to the worldwide economy as any substantial reduction in economic activity in Europe is likely to impact other major economies such as China, India and the U.S. Although steps are being taken to resolve this issue, there is still concern in the financial and equity markets that European economic activity will substantially slow in 2012. China’s rapid economic growth and industrialization has been a major factor in driving up world-wide economic growth since the recession of 2008/2009. It is expected that China will continue to grow at a meaningful pace, however, there is concern that the Chinese central bank’s efforts to limit inflation may temper growth prospects. In the U.S., there has been a slow recovery from the recession of 2008/2009 as the economy continues to deal with the effects of the financial crisis. Going forward, the expectation is that the U.S. will see modest economic growth in 2012; however, weakness or deterioration of the global economy, particularly in China, India and Europe, could curtail U.S. economic growth from current estimates.

 

   

Demand for Hydrocarbons - In its February 2012 Oil Market Report, the IEA said that it expects global demand for oil to increase 0.8 million barrels per day in 2012 relative to 2011. While forecasts by IEA, EIA and OPEC have been revised modestly lower in the past few months, primarily as a reaction to higher oil prices and uncertainty regarding the strength of the economic recovery, the expected increase in demand for hydrocarbons is expected to support increased spending to develop oil. Natural gas is an increasingly important hydrocarbon to meet the world’s energy needs and recent innovations in the U.S. have substantially improved the production of natural gas in the U.S. As a result, natural gas demand is at an all-time high in the U.S. and is expected to continue to increase into 2012. Further, Europe and Asia are increasing their demand for natural gas as production from major gas fields in the Middle East, Africa and Asia Pacific are imported into the consuming regions.

 

   

Oil Production - Global spare oil production capacity is relatively limited and is proving to be inadequate to decouple oil prices from geopolitical supply disruptions throughout North Africa and the Middle East. Several key OPEC countries have announced plans to increase their exploration and development efforts to develop resources to meet the expected increase in global demand. Sustained higher oil prices have led producers, particularly in the U.S., to increase capital spending and apply new technology to increase oil production. Although this is a positive trend for the U.S. that is expected to continue for many years to come, it will provide only a modest offset to any potential supply disruption across the rest of the world.

 

   

Natural Gas Production - Worldwide natural gas production continues to grow as a result of the emergence of the unconventional shale plays in North America as well as an abundance of large conventional fields in the Middle East, Asia and Latin America. Low natural gas prices in the U.S. have driven a reduction in the natural gas-directed rig activity in the U.S. It is anticipated that this will begin to impact natural gas production, but to date, natural gas production continues to increase per the latest reports by the DOE. Worldwide natural gas production will tend to be more stable as high natural gas prices in places such as Europe and Asia encourage natural gas production at current levels.

 

   

Oil and Natural Gas Prices - With WTI oil prices trading between $75.67/Bbl and $113.93/Bbl most unconventional plays in the U.S. as well as most conventional developments internationally will provide adequate returns to encourage incremental investment. Internationally, most oil developments are based on Brent oil prices which have also been at a high enough level to justify further investment in field development. Based on the tightness of the oil supply and the anticipated modest economic growth, we would expect commodity prices to remain relatively strong throughout 2012 barring a major macro-economic event. In North America, natural gas prices are particularly low when compared to oil on a BTU equivalent basis. This low price is driven by a combination of far more efficient production from the unconventional plays in the U.S. as well as a particularly warm winter. Although industrial demand and power generation are gradually increasing and demanding more natural gas, it is not enough to offset the increase in production from the unconventional plays. As a result, the expectation is that natural gas prices will remain particularly low throughout 2012.

Activity and Spending Outlook for North America - Overall customer spending in North America is expected to increase in fiscal 2012 compared to fiscal 2011. Unconventional plays with crude oil and natural gas liquids content are attracting incremental investment while investment in dry gas plays are expected to continue to decline due to historically low natural gas pricing levels. Service intensity has increased in North America as customers are demanding advanced directional drilling, more complex completion systems and pressure pumping to develop the unconventional plays. The demand for these key technologies has grown faster than the

 

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industry’s ability to produce them resulting in support for higher prices. In the Gulf of Mexico, activity on the continental shelf has remained steady, while during the second half of 2011 we saw a modest increase in deep water permits and subsequently deep water drilling. The level of activity in the deep water Gulf of Mexico remains below pre-moratorium levels; however, we have confidence that as the permitting process is better understood deepwater activity will ultimately return to pre-moratorium levels. We are investing in our people and processes to ensure that we will be fully compliant with the new and more stringent regulatory requirements in the Gulf of Mexico.

Activity and Spending Outlook Outside North America - International activity is driven primarily by the price of oil which is high enough to provide attractive economic returns in almost every region. Customers are expected to increase spending to develop new resources and offset declines from existing developed resources. Areas that are expected to see increased spending in 2012 include: the Middle East, in particular Iraq and Saudi Arabia; Brazil with the investment in the pre-salt resources; and Colombia which has seen a rapid expansion associated with improved fiscal terms for our customers.

Capital Expenditures - Our capital expenditures, excluding acquisitions, are expected to be between $3.1 billion and $3.4 billion for 2012. A portion of our planned capital expenditures can be adjusted to reflect changes in our expectations for future customer spending.

COMPLIANCE

We do business in more than 80 countries, including approximately 25 of the 40 countries having the lowest scores in the Transparency International’s Corruption Perception Index survey for 2011, which indicates high levels of corruption. We devote significant resources to the development, maintenance, communication and enforcement of our Business Code of Conduct, our anti-bribery compliance policies, our internal control processes and procedures and other compliance related policies. Notwithstanding the devotion of such resources, and in part as a consequence thereof, from time to time we discover or receive information alleging potential violations of laws and regulations, including the FCPA and our policies, processes and procedures. We conduct timely internal investigations of these potential violations and take appropriate action depending upon the outcome of the investigation.

We anticipate that the devotion of significant resources to compliance-related issues, including the necessity for investigations, will continue to be an aspect of doing business in a number of the countries in which oil and natural gas exploration, development and production take place and in which we are requested to conduct operations. Compliance-related issues have limited our ability to do business and/or have raised the cost of operating in these countries. In order to provide products and services in some of these countries, we may in the future utilize ventures with third parties, sell products to distributors or otherwise modify our business approach in order to improve our ability to conduct our business in accordance with applicable laws and regulations and our Business Code of Conduct.

Our Best-in-Class Global Ethics and Compliance Program (“Compliance Program”) is based on (i) our Core Values of Integrity, Performance, Teamwork and Learning; (ii) the standards contained in our Business Code of Conduct; and (iii) the laws of the countries where we operate. Our Compliance Program is referenced within the Company as “C2” or “Completely Compliant.” The Completely Compliant theme is intended to establish the proper Tone-at-the-Top throughout the Company. Employees are consistently reminded that they play a crucial role in ensuring that the Company always conducts its business ethically, legally and safely.

Highlights of our Compliance Program include the following:

 

   

We have comprehensive internal policies over such areas as facilitating payments; travel, entertainment, gifts and charitable donations connected to non-U.S. government officials; payments to non-U.S. commercial sales representatives; and the use of non-U.S. police or military organizations for security purposes. In addition, we have country-specific guidance for customs standards, export and re-export controls, economic sanctions and antiboycott laws.

 

   

We have a comprehensive employee compliance training program covering substantially all employees.

 

   

We have a due diligence procedure for commercial sales, processing and professional agents, an enhanced process for classifying distributors and are creating a formal policy to guide business personnel in determining when subcontractors should be subjected to compliance due diligence.

 

   

We have a special compliance committee, which is made up of senior officers, that meets no less than once a year to review the oversight reports for all active commercial sales representatives.

 

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We have continued our reduction of the use of commercial sales representatives and processing agents, including the reduction of customs agents.

 

   

We use technology to monitor and report on compliance matters, including a web-based antiboycott reporting tool and a global trade management software tool.

 

   

We have a program designed to encourage reporting of any ethics or compliance matter without fear of retaliation including a worldwide Business Helpline operated by a third party and currently available toll-free in 150 languages to ensure that our helpline is easily accessible to employees in their own language.

 

   

We have continued to expand the use and scope of our centralized finance organization including further implementation of our enterprise-wide accounting system and company-wide policies. In addition, the corporate audit function has incorporated additional anti-corruption procedures into some of their audits, which are applied on a country-wide basis. We are also continuing to refine and enhance our procedures for FCPA risk assessments and legal audit procedures.

 

   

We continue to work to ensure that we have adequate legal compliance coverage around the world, including the coordination of compliance advice and training across all regions and countries where we do business.

 

   

We are continuing to centralize our human resources function, including creating consistent standards for pre-hire screening of employees, the screening of existing employees prior to promoting them to positions where they may be exposed to corruption-related risks, and creating a uniform policy for new hire training.

LIQUIDITY AND CAPITAL RESOURCES

Our objective in financing our business is to maintain adequate financial resources and access to sufficient liquidity. At December 31, 2011, we had cash and cash equivalents of $1.05 billion, of which approximately $1.03 billion was held by foreign subsidiaries. A substantial portion of the cash held by foreign subsidiaries at December 31, 2011 was reinvested in our international operations as our intent is to use this cash to, among other things, fund the operations of our foreign subsidiaries. If we decide at a later date to repatriate those funds to the U.S., we may be required to provide taxes on certain of those funds based on applicable U.S. tax rates net of foreign taxes. In addition, we had $2.5 billion available for borrowing under a committed revolving credit facility with commercial banks. We believe that cash on hand, cash flows from operations and the available credit facility, including the issuance of commercial paper, will provide sufficient liquidity to manage our global cash needs.

Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of our Company. In 2011, we used cash to pay for a variety of activities including working capital needs, capital expenditures, repayment of debt and payment of dividends.

Cash Flows

Cash flows provided (used) by continuing operations by type of activity were as follows for the years ended December 31:

 

(In millions)    2011     2010     2009  

Operating activities

   $ 1,507      $ 856      $ 1,239   

Investing activities

     (1,891     (2,376     (966

Financing activities

     (30     1,366        (675

Statements of cash flows for entities with international operations that are local currency functional exclude the effects of the changes in foreign currency exchange rates that occur during any given year, as these are noncash changes. As a result, changes reflected in certain accounts on the consolidated statements of cash flows may not equal the changes in corresponding accounts on the consolidated balance sheet.

Operating Activities

Cash flows from operating activities provided $1.5 billion for the year ended December 31, 2011 and provided $856 million for the year ended December 31, 2010. This increase in cash flows of $651 million is primarily due to an increase in net income offset by the change in net operating assets and liabilities, which used more cash in 2011 compared to 2010.

 

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The underlying drivers in 2011 compared to 2010 of the changes in operating assets and liabilities are as follows:

 

   

An increase in accounts receivable used cash of $1.02 billion and $702 million in 2011 and 2010, respectively. The change in accounts receivable was primarily due to an increase in activity and the corresponding revenue growth as well as an increase in the days sales outstanding (defined as the average number of days our net trade receivables are outstanding based on quarterly revenue) of approximately 2 days.

   

An increase in inventory used cash of $641 million and $243 million in 2011 and 2010, respectively, driven by activity increases.

   

An increase in accounts payable provided cash of $314 million and $292 million in 2011 and 2010, respectively, resulting from an increase in operating assets to support increased activity.

   

Accrued employee compensation and other accrued liabilities provided $58 million in cash in 2011 and used $182 million in 2010. The increase in cash provided in 2011 was due primarily to increased employee bonus accruals for 2011, partially offset by employee bonuses paid in 2011 but earned and accrued for in 2010.

Cash flows from operating activities provided $856 million for the year ended December 31, 2010 and provided $1.24 billion for the year ended December 31, 2009. This decrease in cash flows of $383 million is primarily due to the change in net operating assets and liabilities which used more cash in 2010 compared to 2009.

The underlying drivers in 2010 compared to 2009 of the changes in operating assets and liabilities are as follows:

 

   

Accounts receivable used $702 million in cash in 2010 and provided $399 million in 2009. The change in accounts receivable was primarily due to an increase in activity partially offset by a decrease in the days sales outstanding by approximately 6 days.

   

Inventory used $243 million in cash in 2010 and provided $240 million in 2009 driven by activity increases.

   

Accounts payable provided $292 million in cash in 2010 and used $89 million in 2009. The increase was primarily due to an increase in operating assets to support increased activity.

   

A decrease in accrued employee compensation and other accrued liabilities used cash of $182 million and $130 million in 2010 and 2009, respectively. The increase in the use of cash in 2010 was due primarily to the payments of pre-existing change of control and other contractual obligations to certain BJ Services employees partially offset by a decrease in payments related to employee bonuses earned in 2009 but paid in 2010.

   

Income taxes payable provided $23 million in 2010 in cash and used $169 million in 2009. The use of cash in 2009 was primarily due to federal income tax payments made in 2009 of $155 million for two quarterly installment payments related to 2008. The U.S. Internal Revenue Service allowed companies impacted by Hurricane Ike to defer the third and fourth quarter installment payments for 2008 until January 2009.

Investing Activities

Our principal recurring investing activity was the funding of capital expenditures to ensure that we have the appropriate levels and types of machinery and equipment in place to generate revenue from operations. Expenditures for capital assets totaled $2.46 billion, $1.49 billion and $1.09 billion for 2011, 2010 and 2009, respectively. While the majority of these expenditures were for machinery and equipment, we have continued our spending on new facilities, expansions of existing facilities and other infrastructure projects.

Proceeds from the disposal of assets were $311 million, $208 million and $163 million for 2011, 2010 and 2009, respectively. These disposals related to equipment that was lost-in-hole, and property, machinery, and equipment no longer used in operations that were sold throughout the year.

During 2010, we purchased $250 million of short-term investments consisting of U.S. Treasury Bills. The U.S. Treasury Bills matured in May 2011 and we received proceeds of $250 million.

We routinely evaluate potential acquisitions of businesses of third parties that may enhance our current operations or expand our operations into new markets or product lines. We may also from time to time sell business operations that are not considered part of our core business. During 2010, we paid cash of $680 million, net of cash acquired of $113 million, related to the BJ Services acquisition, and we paid $208 million, net of cash acquired of $4 million, for other acquisitions. In 2009, we paid $58 million, net of cash acquired of $4 million, for acquisitions including additional purchase price consideration for past acquisitions.

Financing Activities

We had net borrowings of commercial paper and other short-term debt of $125 million and $52 million in 2011 and 2010, respectively, and net repayments of commercial paper and short-term debt of $16 million in 2009. In 2011, we completed a private

 

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placement of $750 million 3.2% senior notes that have registration rights and will mature in August 2021, resulting in net proceeds of approximately $742 million after deducting the underwriting discounts and expenses of the offering. The 3.2% notes may only be transferred or resold in a transaction registered under or exempt from registration requirements of federal and state securities laws. We intend to file a registration statement with the SEC with respect to an offer to exchange the notes for registered notes with substantially identical terms pursuant to a registration rights agreement. We used $563 million of the net proceeds to redeem our 6.5% notes. The remaining net proceeds from the offering were used for general corporate purposes. Also in 2011, we repaid $250 million of our 5.75% notes that matured. Total debt outstanding at December 31, 2011 was $4.07 billion, an increase of $184 million compared to December 31, 2010. The total debt to total capitalization (defined as total debt plus equity) ratio was 0.20 at December 31, 2011 and 0.21 at December 31, 2010.

In 2010, we sold $1.5 billion of 5.125% senior notes that will mature in September 2040. Net proceeds from the offering were approximately $1.48 billion after deducting the underwriting discounts and expenses of the offering. We used $511 million of the net proceeds to repay our outstanding commercial paper. We used $250 million of the net proceeds to purchase U.S. Treasury Bills, which were used to repay the BJ Services 5.75% notes that matured in June 2011. The remaining net proceeds from the offering were used for general corporate purposes. In 2009, we repaid $525 million of maturing long-term debt.

We received proceeds of $183 million, $74 million and $51 million in 2011, 2010 and 2009, respectively, from the issuance of common stock through the exercise of stock options and the employee stock purchase plan.

Our Board of Directors has authorized a program to repurchase our common stock from time to time. During 2011, 2010 and 2009 we did not repurchase any shares of common stock. We had authorization remaining to repurchase approximately $1.2 billion in common stock at the end of 2011.

We paid dividends of $261 million, $241 million and $185 million in 2011, 2010 and 2009, respectively. The increase in 2010 and 2011 is primarily due to the 118 million shares issued in the acquisition of BJ Services.

Available Credit Facility

At December 31, 2011, we had a $2.5 billion committed revolving credit facility with commercial banks that matures in September 2016. This facility contains certain covenants which, among other things, restrict certain merger transactions or the sale of all or substantially all of our assets or a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the occurrence of certain events of default, our obligations under the facility may be accelerated. Such events of default include payment defaults to lenders under the facility, covenant defaults and other customary defaults. At December 31, 2011, we were in compliance with all of the facility’s covenants. There were no direct borrowings under the committed credit facility at the end of 2011. We also have an outstanding commercial paper program under which we may issue from time to time up to $2.5 billion in commercial paper with maturity of no more than 270 days. The maximum combined borrowing at any point in time under both the commercial paper program and the credit facility is $2.5 billion. At December 31, 2011, we had $130 million of commercial paper outstanding.

If market conditions were to change and our revenue was reduced significantly or operating costs were to increase, our cash flows and liquidity could be reduced. Additionally, it could cause the rating agencies to lower our credit rating. There are no ratings triggers that would accelerate the maturity of any borrowings under our committed credit facility. However, a downgrade in our credit ratings could increase the cost of borrowings under the facility and could also limit or preclude our ability to issue commercial paper. Should this occur, we would seek alternative sources of funding, including borrowing under the facility.

We believe our current credit ratings would allow us to obtain interim financing over and above our existing credit facility for any currently unforeseen significant needs or growth opportunities. We also believe that such interim financings could be funded with subsequent issuances of long-term debt or equity, if necessary.

Cash Requirements

In 2012, we believe cash on hand, cash flows from operating activities and the available credit facility will provide us with sufficient capital resources and liquidity to manage our working capital needs, meet contractual obligations, fund capital expenditures, and support the development of our short-term and long-term operating strategies. We may issue commercial paper or other short-term debt to fund cash needs in the U.S. in excess of the cash generated in the U.S.

In 2012, we expect our capital expenditures to be between approximately $3.1 billion to $3.4 billion, excluding any amount related to acquisitions. The expenditures are expected to be used primarily for normal, recurring items necessary to support our business and operations. A significant portion of our capital expenditures can be adjusted based on future activity of our customers. We will

 

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manage our capital expenditures to match market demand. In 2012, we also expect to make interest payments of between $225 million and $240 million, based on debt levels as of December 31, 2011. We anticipate making income tax payments of between $1.3 billion and $1.4 billion in 2012.

We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. We anticipate paying dividends of between $257 million and $267 million in 2012; however, the Board of Directors can change the dividend policy at any time.

For all pension plans, we make annual contributions to the plans in amounts equal to or greater than amounts necessary to meet minimum governmental funding requirements. In 2012, we expect to contribute between $80 million and $95 million to our defined benefit pension plans. In 2012, we also expect to make benefit payments related to postretirement welfare plans of between $16 million and $18 million, and we estimate we will contribute between $263 million and $286 million to our defined contribution plans. See Note 12 of the Notes to Consolidated Financial Statements in Item 8 herein for further discussion of our employee benefit plans.

Contractual Obligations

In the table below, we set forth our contractual cash obligations as of December 31, 2011. Certain amounts included in this table are based on our estimates and assumptions about these obligations, including their duration, anticipated actions by third parties and other factors. The contractual cash obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.

 

     Payments Due by Period  
(In millions)    Total      Less Than
1 Year
     2 - 3
Years
     4 - 5
Years
     More Than
5 Years
 

Total debt and capital lease obligations (1)

   $ 4,098       $ 224       $ 18       $ 28       $ 3,828   

Estimated interest payments (2)

     3,664         227         449         440         2,548   

Operating leases (3)

     578         148         203         103         124   

Purchase obligations (4)

     2,056         683         836         512         25   

Income tax liabilities for uncertain tax positions (5)

     379         176         118         51         34   

Other long-term liabilities

     129         19         35         11         64   

Total

   $ 10,904       $ 1,477       $ 1,659       $ 1,145       $ 6,623   

 

  (1) 

Amounts represent the expected cash payments for the principal amounts related to our debt and capital lease obligations. Amounts for debt do not include any unamortized discounts or deferred issuance costs. Expected cash payments for interest are excluded from these amounts.

  (2) 

Amounts represent the expected cash payments for interest on our long-term debt and capital lease obligations.

  (3) 

We enter into operating leases, some of which include renewal options. We have excluded renewal options from the table above.

  (4) 

Purchase obligations include capital improvements as well as agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction.

  (5) 

The estimated income tax liabilities for uncertain tax positions will be settled as a result of expiring statutes, audit activity, competent authority proceedings related to transfer pricing, or final decisions in matters that are the subject of litigation in various taxing jurisdictions in which we operate. The timing of any particular settlement will depend on the length of the tax audit and related appeals process, if any, or an expiration of a statute. If a liability is settled due to a statute expiring or a favorable audit result, the settlement of the tax liability would not result in a cash payment.

Off-Balance Sheet Arrangements

In the normal course of business with customers, vendors and others, we have entered into off-balance sheet arrangements, such as letters of credit and other bank issued guarantees, which totaled approximately $1.3 billion at December 31, 2011. It is not practicable to estimate the fair value of these financial instruments. None of the off-balance sheet arrangements either has, or is likely to have, a material effect on our consolidated financial statements.

Other than normal operating leases, we do not have any off-balance sheet financing arrangements such as securitization agreements, liquidity trust vehicles, synthetic leases or special purpose entities. As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such financing arrangements.

 

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CRITICAL ACCOUNTING ESTIMATES

The preparation of our consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses and related disclosures and disclosures about any contingent assets and liabilities. We base these estimates and judgments on historical experience and other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects are subject to uncertainty, and accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the business environment in which we operate changes.

We have defined a critical accounting estimate as one that is both important to the portrayal of either our financial condition or results of operations and requires us to make difficult, subjective or complex judgments or estimates about matters that are uncertain. We have reviewed our critical accounting estimates with the Audit/Ethics Committee of our Board of Directors and the Audit/Ethics Committee has reviewed the disclosure presented below. During the past three fiscal years, we have not made any material changes in the methodology used to establish the critical accounting estimates, and we believe that the following are the critical accounting estimates used in the preparation of our consolidated financial statements. There are other items within our consolidated financial statements that require estimation and judgment but they are not deemed critical as defined above.

Allowance for Doubtful Accounts

The determination of the collectability of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customers’ payment history and current credit worthiness to determine that collectability is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Inherently, these uncertainties require us to make frequent judgments and estimates regarding our customers’ ability to pay amounts due us in order to determine the amount of valuation allowances required for doubtful accounts. Provisions for doubtful accounts are recorded when it becomes evident that the customer will not make the required payments at either contractual due dates or in the future. At December 31, 2011 and 2010, the allowance for doubtful accounts totaled $229 million, or 4%, and $162 million, or 4%, of total gross accounts receivable, respectively. We believe that our allowance for doubtful accounts is adequate to cover potential bad debt losses under current conditions; however, uncertainties regarding changes in the financial condition of our customers, either adverse or positive, could impact the amount and timing of any additional provisions for doubtful accounts that may be required. A five percent change in the allowance for doubtful accounts would have had an impact on income before income taxes of approximately $11 million in 2011.

Inventory Reserves

Inventory is a significant component of current assets and is stated at the lower of cost or market. This requires us to record provisions and maintain reserves for excess, slow moving and obsolete inventory. To determine these reserve amounts, we regularly review inventory quantities on hand and compare them to estimates of future product demand, market conditions, production requirements and technological developments. These estimates and forecasts inherently include uncertainties and require us to make judgments regarding potential future outcomes. At December 31, 2011 and 2010, inventory reserves totaled $304 million, or 9%, and $322 million, or 11%, of gross inventory, respectively. We believe that our reserves are adequate to properly value potential excess, slow moving and obsolete inventory under current conditions. Significant or unanticipated changes to our estimates and forecasts could impact the amount and timing of any additional provisions for excess or obsolete inventory that may be required. A five percent change in this inventory reserve balance would have had an impact on income before income taxes of approximately $15 million in 2011.

Goodwill and Other Long-Lived Assets

The purchase price of acquired businesses is allocated to its identifiable assets and liabilities based upon estimated fair values as of the acquisition date. Goodwill is the excess of the consideration transferred over the fair value of the tangible and identifiable intangible assets and liabilities recognized. In determining estimated fair values, we use various sources and types of information, including, but not limited to, quoted market prices, replacement cost estimates, accepted valuation techniques such as discounted cash flows, and existing carrying value of acquired assets. As necessary, we utilize third-party appraisal firms to assist us in determining fair value of inventory, identifiable intangible assets, and any other significant assets or liabilities. During the measurement period, we adjust the preliminary purchase price allocation if we obtain more information regarding asset valuations and liabilities assumed. The judgments, assumptions and estimates used or made in determining the estimated fair value assigned to assets acquired and liabilities assumed, as well as future asset lives, can materially impact our results of operations. We perform an annual impairment test of goodwill as of October 1 of each year. In performing the test, we individually test each of our reporting units, which are generally based on our regional structure. These tests involve the use of different valuation techniques, including a market approach,

 

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comparable transactions and discounted cash flow methodology, all of which include, but are not limited to, assumptions regarding matters such as discount rates, anticipated growth rates and expected profitability rates and similar items. The results of the 2011 test indicated that there were no impairments of goodwill; however, for one reporting unit, the excess of estimated fair value over the carrying value was less than 10% of the related carrying value. Goodwill associated with this reporting unit totaled approximately $419 million at December 31, 2011. Unanticipated changes, including even small revisions, to these assumptions could require a provision for impairment in a future period. Given the nature of these evaluations and their application to specific assets and time-frames, it is not possible to reasonably quantify the impact of changes in these assumptions.

Long-lived assets, which include property and equipment, intangible assets other than goodwill, and certain other assets, comprise a significant amount of our total assets. We review the carrying values of these assets for impairment periodically, and at least annually for certain intangible assets, or whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires us to make judgments regarding long-term forecasts of future revenue and costs related to the assets subject to review. These forecasts are uncertain in that they require assumptions about demand for our products and services, future market conditions and technological developments.

Income Taxes

The liability method is used for determining our income tax provisions, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In determining the need for valuation allowances, we have considered and made judgments and estimates regarding estimated future taxable income and ongoing prudent and feasible tax planning strategies. These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to adjust the valuation allowances for our deferred tax assets. Historically, changes to valuation allowances have been caused by major changes in the business cycle in certain countries and changes in local country law. The ultimate realization of the deferred tax assets depends on the generation of sufficient taxable income in the applicable taxing jurisdictions.

We operate in more than 80 countries under many legal forms. As a result, we are subject to the jurisdiction of numerous domestic and foreign tax authorities, as well as to tax agreements and treaties among these governments. Our operations in these different jurisdictions are taxed on various bases: actual income before taxes, deemed profits (which are generally determined using a percentage of revenue rather than profits) and withholding taxes based on revenue. Determination of taxable income in any jurisdiction requires the interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of deductions, permissible revenue recognition methods under the tax law and the sources and character of income and tax credits. Changes in tax laws, regulations, agreements and treaties, foreign currency exchange restrictions or our level of operations or profitability in each taxing jurisdiction could have an impact on the amount of income taxes that we provide during any given year.

Our tax filings for various periods are subject to audit by the tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are 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 these situations inevitably includes some degree of uncertainty; accordingly, we provide taxes only for the amounts we believe will ultimately result from these proceedings. The resulting change to our tax liability, if any, is dependent on numerous factors that are difficult to estimate. These include, among others, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a fair settlement through an administrative process; the impartiality of the local courts; the sheer number of countries in which we do business; and the potential for changes in the tax paid to one country to either produce, or fail to produce, an offsetting tax change in other countries. Our experience has been that the estimates and assumptions we have used to provide for future tax assessments have proven to be appropriate. However, past experience is only a guide, and the potential exists that the tax resulting from the resolution of current and potential future tax controversies may differ materially from the amount accrued.

In addition to the aforementioned assessments that have been received from various tax authorities, we also provide for taxes for uncertain tax positions where formal assessments have not been received. The determination of these liabilities requires the use of estimates and assumptions regarding future events. Once established, we adjust these amounts only when more information is available or when a future event occurs necessitating a change to the reserves such as changes in the facts or law, judicial decisions regarding the application of existing law or a favorable audit outcome. We believe that the resolution of tax matters will not have a material effect on the consolidated financial condition of the Company, although a resolution could have a material impact on our

 

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consolidated statement of operations for a particular period and on our effective tax rate for any period in which such resolution occurs.

Pensions and Postretirement Benefit Obligations

Pensions and postretirement benefit obligations and the related expenses are calculated using actuarial models and methods. This involves the use of two critical assumptions, the discount rate and the expected rate of return on assets, both of which are important elements in determining pension expense and in measuring plan assets and liabilities. We evaluate these critical assumptions at least annually. Although considered less critical, other assumptions used in determining benefit obligations and related expenses, such as demographic factors like retirement age, mortality and turnover, are also evaluated periodically and are updated to reflect our actual and expected experience.

The discount rate enables us to determine expected future cash flows at a present value on the measurement date. The development of the discount rate for our largest plans was based on a bond matching model whereby the cash flows underlying the projected benefit obligation are matched against a yield curve constructed from a bond portfolio of high-quality, fixed-income securities. Use of a lower discount rate would increase the present value of benefit obligations and increase pension expense. We used a discount rate of 5.2% in 2011, 5.9% in 2010 and 6.4% in 2009 to determine pension expense. A 50 basis point reduction in the discount rate would have decreased income before income taxes by approximately $2 million in 2011.

To determine the expected rate of return on plan assets, we consider the current and target asset allocations, as well as historical and expected future returns on various categories of plan assets. A lower rate of return increases plan expenses. We assumed rates of return on our plan investments were 7.2% in 2011, 7.1% in 2010 and 8.0% in 2009. A 50 basis point reduction in the expected rate of return on assets of our principal plans would have decreased income before income taxes by approximately $5 million in 2011.

NEW ACCOUNTING STANDARDS UPDATES

In May 2011, the Financial Accounting Standards Board (“FASB”) issued an update to Accounting Standards Codification (“ASC”) 820, Fair Value Measurement. The Accounting Standards Update (“ASU”) conforms certain sections of ASC 820 to International Financial Reporting Standards in order to provide a single converged guidance on the measurement of fair value. This update also expands the existing disclosure requirements for fair value measurements. This ASU is effective for interim and annual periods beginning after December 15, 2011. We will adopt this ASU prospectively in the first quarter of 2012. We currently do not expect this ASU to have a material impact, if any, on our consolidated financial statements.

In June 2011, the FASB issued an update to ASC 220, Comprehensive Income. This ASU requires entities to present components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements that would include reclassification adjustments by component for items that are reclassified from other comprehensive income to net income on the face of the financial statements. In December 2011, the FASB issued an update to this ASU indefinitely deferring the implementation of the reclassification adjustments by component requirement of the ASU issued in June 2011. These ASUs are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We will adopt the new presentation requirements of these ASUs retrospectively in the first quarter of 2012.

In September 2011, the FASB issued an update to ASC 350, Intangibles - Goodwill and Other. This ASU amends the guidance in ASC 350-20 on testing for goodwill impairment. The revised guidance allows entities testing for goodwill impairment to have the option of performing a qualitative assessment before calculating the fair value of the reporting unit. The ASU does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirement to test annually for impairment. The ASU is limited to goodwill and does not amend the annual requirement for testing other indefinite-lived intangible assets for impairment. The ASU is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We will adopt this ASU for our 2012 goodwill impairment testing. We do not expect this ASU to have a material impact, if any, on our consolidated financial statements.

RELATED PARTY TRANSACTIONS

There were no significant related party transactions during the three years ended December 31, 2011.

FORWARD-LOOKING STATEMENTS

This Form 10-K, including MD&A and certain statements in the Notes to Consolidated Financial Statements, includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act (each a “forward-looking statement”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “probable,” “project,”

 

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“forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “potential, “ “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward-looking statements. Our forward-looking statements are based on assumptions that we believe to be reasonable but that may not prove to be accurate. The statements do not include the potential impact of future transactions, such as an acquisition, disposition, merger, joint venture or other transaction that could occur. We undertake no obligation to publicly update or revise any forward-looking statement. Our expectations regarding our business outlook, including changes in revenue, pricing, capital spending, profitability, strategies for our operations, impact of any common stock repurchases, oil and natural gas market conditions, the business plans of our customers, market share and contract terms, costs and availability of resources, legal, economic and regulatory conditions, and environmental matters are only our forecasts regarding these matters.

All of our forward-looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in Item 1A. Risk Factors and those set forth from time to time in our filings with the SEC. These documents are available through our website or through the SEC’s Electronic Data Gathering and Analysis Retrieval System (“EDGAR”) at http://www.sec.gov.

Risk Factors

For discussion of our risk factors and cautions regarding forward-looking statements, see Item 1A. Risk Factors and the “Forward-Looking Statements” section in Item 7, both contained herein.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to certain market risks that are inherent in our financial instruments and arise from changes in interest rates and foreign currency exchange rates. We may enter into derivative financial instrument transactions to manage or reduce market risk but do not enter into derivative financial instrument transactions for speculative purposes. A discussion of our primary market risk exposure in financial instruments is presented below.

INTEREST RATE RISK AND INDEBTEDNESS

We are subject to interest rate risk on our long-term fixed interest rate debt. Commercial paper borrowings, other short-term borrowings and variable rate long-term debt do not give rise to significant interest rate risk because these borrowings either have maturities of less than three months or have variable interest rates similar to the interest rates we receive on our short-term investments. All other things being equal, the fair market value of debt with a fixed interest rate will increase as interest rates fall and will decrease as interest rates rise. This exposure to interest rate risk can be managed by borrowing money that has a variable interest rate or using interest rate swaps to change fixed interest rate borrowings to variable interest rate borrowings.

Interest Rate Swap Agreements

We are subject to interest rate risk on our debt and investment of cash and cash equivalents arising in the normal course of our business, as we do not engage in speculative trading strategies. We maintain an interest rate management strategy, which primarily uses a mix of fixed and variable rate debt that is intended to mitigate the exposure to changes in interest rates in the aggregate for our investment portfolio. We may use interest rate swaps to manage the economic effect of fixed rate obligations associated with certain debt.

In September 2011, we redeemed in full our $500 million 6.5% fixed rate senior notes maturing November 2013. Consequently, we terminated two related interest rate swap agreements resulting in a net gain on the swap agreements of $25 million. The two swap agreements were entered into in June 2009 for a notional amount of $250 million each in order to hedge changes in the fair market value of the debt. The swap agreements had been designated and each qualified as a fair value hedging instrument.

Indebtedness

We had fixed rate debt aggregating $3.8 billion at December 31, 2011 and December 31, 2010. The following table sets forth the required cash payments for our indebtedness, which bear a fixed rate of interest and are denominated in U.S. Dollars, and the related weighted average interest rates by expected maturity dates as of December 31, 2011 and 2010.

 

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(In millions)    2011     2012      2013     2014      2015      2016      Thereafter     Total  

As of December 31, 2011

                    

Long-term debt (1) (2)

   $ -      $ -       $ -      $ -       $ -       $ -       $ 3,800      $ 3,800   

Weighted average interest rates

     -        -         -        -         -         -         5.72     5.72

As of December 31, 2010

                    

Long-term debt (1) (2)

   $ 250      $ -       $ 500      $ -       $ -       $ -       $ 3,050      $ 3,800   

Weighted average interest rates

     5.86     -         6.73     -         -         -         6.31     6.34

 

  (1) 

Amounts do not include any unamortized discounts or deferred issuance costs.

  (2) 

Fair market value of fixed rate long-term debt was $4,611 million at December 31, 2011 and $4,218 million at December 31, 2010.

FOREIGN CURRENCY FORWARD CONTRACTS

We conduct operations around the world in a number of different currencies. Many of our significant foreign subsidiaries have designated the local currency as their functional currency. As such, future earnings are subject to change due to fluctuations in foreign currency exchange rates when transactions are denominated in currencies other than our functional currencies. To minimize the need for foreign currency forward contracts to hedge this exposure, our objective is to manage foreign currency exposure by maintaining a minimal consolidated net asset or net liability position in a currency other than the functional currency.

At December 31, 2011 and 2010, we had outstanding foreign currency forward contracts with notional amounts aggregating $117 million and $156 million, respectively, to hedge exposure to currency fluctuations in various foreign currencies. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of December 31, 2011 and 2010 for contracts with similar terms and maturity dates, we recorded a loss of $1 million and $2 million, respectively, to adjust these foreign currency forward contracts to their fair market value. These losses offset designated foreign currency exchange gains resulting from the underlying exposures and are included in MG&A expenses in the consolidated statement of operations.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over our financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). 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.

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we assessed the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, our principal executive officer and principal financial officer concluded that our internal control over financial reporting was effective as of December 31, 2011. This conclusion is based on the recognition that there are inherent limitations in all systems of internal control. Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. 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.

Deloitte & Touche LLP, the Company’s independent registered public accounting firm, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting.

 

/s/ MARTIN S. CRAIGHEAD

Martin S. Craighead

President and

Chief Executive Officer

    

/s/ PETER A. RAGAUSS

Peter A. Ragauss

Senior Vice President and

Chief Financial Officer

     

/s/ ALAN J. KEIFER

Alan J. Keifer

Vice President and

Controller

Houston, Texas

February 22, 2012

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Baker Hughes Incorporated

Houston, Texas

We have audited the accompanying consolidated balance sheets of Baker Hughes Incorporated and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, changes in equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included financial statement schedule II, valuation and qualifying accounts, listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, 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 Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the 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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Baker Hughes Incorporated and subsidiaries as of December 31, 2011 and 2010 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such 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. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 22, 2012

 

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Baker Hughes Incorporated

Consolidated Statements of Operations

(In millions, except per share amounts)

 

     Year Ended December 31,  
      2011     2010     2009  

Revenue:

      

Sales

   $ 6,382      $ 5,516      $ 4,809   

Services

     13,449        8,898        4,855   

Total revenue

     19,831        14,414        9,664   

Costs and expenses:

      

Cost of sales

     5,122        4,359        3,858   

Cost of services

     10,142        6,825        3,539   

Research and engineering

     462        429        397   

Marketing, general and administrative

     1,190        1,250        1,120   

Impairment of trade names

     315        -        -   

Acquisition-related costs

     -        134        18   

Total costs and expenses

     17,231        12,997        8,932   

Operating income

     2,600        1,417        732   

Gain on investments

     -        6        4   

Interest expense, net

     (221     (141     (125

Loss on early extinguishment of debt

     (40     -        -   

Income before income taxes

     2,339        1,282        611   

Income taxes

     (596     (463     (190

Net income

     1,743        819        421   

Net income attributable to noncontrolling interests

     (4     (7     -   

Net income attributable to Baker Hughes

   $ 1,739      $ 812      $ 421   

Basic earnings per share attributable to Baker Hughes

   $ 3.99      $ 2.06      $ 1.36   

Diluted earnings per share attributable to Baker Hughes

   $ 3.97      $ 2.06      $ 1.36   

See Notes to Consolidated Financial Statements

 

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Baker Hughes Incorporated

Consolidated Balance Sheets

(In millions, except par value)

 

     December 31,  
      2011     2010  
ASSETS     

Current Assets:

    

Cash and cash equivalents

   $ 1,050      $ 1,456   

Short-term investments

     -        250   

Accounts receivable - less allowance for doubtful accounts
(2011 - $229; 2010 - $162)

     4,878        3,942   

Inventories, net

     3,222        2,594   

Deferred income taxes

     251        234   

Other current assets

     396        231   

Total current assets

     9,797        8,707   

Property, plant and equipment - less accumulated depreciation
(2011 - $5,251; 2010 - $4,367)

     7,415        6,310   

Goodwill

     5,956        5,869   

Intangible assets, net

     1,143        1,569   

Other assets

     536        531   

Total assets

   $ 24,847      $ 22,986   
LIABILITIES AND EQUITY     

Current Liabilities:

    

Accounts payable

   $ 1,810      $ 1,496   

Short-term debt and current portion of long-term debt

     224        331   

Accrued employee compensation

     704        589   

Income taxes payable

     289        219   

Other accrued liabilities

     475        504   

Total current liabilities

     3,502        3,139   

Long-term debt

     3,845        3,554   

Deferred income taxes and other tax liabilities

     810        1,360   

Liabilities for pensions and other postretirement benefits

     578        483   

Other liabilities

     148        164   

Commitments and contingencies

    

Equity:

    

Common stock, one dollar par value (shares authorized - 750; issued
and outstanding: 2011 - 437; 2010 - 432)

     437        432   

Capital in excess of par value

     7,303        7,005   

Retained earnings

     8,561        7,083   

Accumulated other comprehensive loss

     (555     (420

Baker Hughes stockholders’ equity

     15,746        14,100   

Noncontrolling interests

     218        186   

Total equity

     15,964        14,286   

Total liabilities and equity

   $ 24,847      $ 22,986   

See Notes to Consolidated Financial Statements

 

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Baker Hughes Incorporated

Consolidated Statements of Changes in Equity

(In millions, except per share amounts)

 

      Common
Stock
     Capital in
Excess of
Par Value
     Retained
Earnings
    Accumulated
Other
Comprehensive
Loss
    Noncontrolling
Interests
    Total  

Balance, December 31, 2008

   $ 309       $ 745       $ 6,276      $ (523   $ -      $ 6,807   

Comprehensive income:

              

Net income

           421         

Foreign currency translation adjustments

             122       

Defined benefit pension plans, net of tax of $2

             (13    

Total comprehensive income

                 530   

Issuance of common stock

     3         41               44   

Stock-based compensation cost

        88               88   

Cash dividends ($0.60 per share)

                       (185                     (185

Balance, December 31, 2009

   $ 312       $ 874       $ 6,512      $ (414   $ -      $ 7,284   

Comprehensive income:

              

Net income

           812          7     

Foreign currency translation adjustments

             (41    

Defined benefit pension plans, net of tax of $(5)

             35       

Total comprehensive income

                 813   

Issuance of common stock, to acquire BJ Services

     118         5,986               6,104   

Issuance of common stock

     2         58               60   

Stock-based compensation cost

        87               87   

Cash dividends ($0.60 per share)

           (241         (241

Acquisition of noncontrolling interests

                                       179        179   

Balance, December 31, 2010

   $ 432       $ 7,005       $ 7,083      $ (420   $ 186      $ 14,286   

Comprehensive income:

              

Net income

           1,739          4     

Foreign currency translation adjustments

             (43     (1  

Defined benefit pension plans, net of tax of $44

             (92    

Total comprehensive income

                 1,607   

Issuance of common stock

     5         179               184   

Stock-based compensation cost

        108               108   

Cash dividends ($0.60 per share)

           (261         (261

Net activity related to noncontrolling interests

              11                         29        40   

Balance, December 31, 2011

   $ 437       $ 7,303       $ 8,561      $ (555   $ 218      $ 15,964   

See Notes to Consolidated Financial Statements

 

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Baker Hughes Incorporated

Consolidated Statements of Cash Flows

(In millions)

 

     Year Ended December 31,  
      2011     2010     2009  

Cash flows from operating activities:

      

Net income

   $ 1,743      $ 819      $ 421   

Adjustments to reconcile net income to net cash flows from operating activities:

      

Depreciation and amortization

     1,321        1,069        711   

Benefit for deferred income taxes

     (492     (188     (256

Impairment of trade names

     315        -        -   

Gain on disposal of assets

     (179     (113     (64

Stock-based compensation cost

     108        87        88   

Provision for doubtful accounts

     84        39        94   

Loss on early extinguishment of debt

     40        -        -   

Gain on investments

     -        (6     (4

Changes in operating assets and liabilities:

      

Accounts receivable

     (1,024     (702     399   

Inventories

     (641     (243     240   

Accounts payable

     314        292        (89

Accrued employee compensation and other accrued liabilities

     58        (182     (130

Income taxes payable

     (121     23        (169

Other operating items, net

     (19     (39     (2

Net cash flows from operating activities

     1,507        856        1,239   

Cash flows from investing activities:

      

Expenditures for capital assets

     (2,461     (1,491     (1,086

Proceeds from disposal of assets

     311        208        163   

Purchase of short-term investments

     -        (250     -   

Proceeds from maturities of short-term investments

     250        -        -   

Acquisition of businesses, net of cash acquired

     (5     (888     (58

Other investing items, net

     14        45        15   

Net cash flows from investing activities

     (1,891     (2,376     (966

Cash flows from financing activities:

      

Net proceeds (payments) of commercial paper and other short-term debt

     125        52        (16

Net proceeds from issuance of long-term debt

     742        1,479        -   

Repayment of long-term debt

     (813     -        (525

Proceeds from termination of interest rate swap agreements

     26        -        -   

Proceeds from issuance of common stock

     183        74        51   

Dividends paid

     (261     (241     (185

Purchase of noncontrolling interest

     (26     -        -   

Other financing items, net

     (6     2        -   

Net cash flows from financing activities

     (30     1,366        (675

Effect of foreign exchange rate changes on cash

     8        15        42   

Decrease in cash and cash equivalents

     (406     (139     (360

Cash and cash equivalents, beginning of year

     1,456        1,595        1,955   

Cash and cash equivalents, end of year

   $ 1,050      $ 1,456      $ 1,595   

Supplemental cash flows disclosures:

      

Income taxes paid, net of refunds

   $ 1,192      $ 637      $ 604   

Interest paid

   $ 237      $ 154      $ 154   

Supplemental disclosure of noncash investing activities:

      

Capital expenditures included in accounts payable

   $ 111      $ 64      $
29
  

See Notes to Consolidated Financial Statements

 

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Baker Hughes Incorporated

Notes to Consolidated Financial Statements

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Baker Hughes Incorporated (“Baker Hughes,” “Company,” “we,” “our,” or “us,”) is a leading supplier of oilfield services, products, technology and systems used for drilling, formation evaluation, completion and production, pressure pumping, and reservoir development in the worldwide oil and natural gas industry. We also provide products and services to the downstream refining and process and pipeline industries.

Basis of Presentation

The consolidated financial statements include the accounts of Baker Hughes and all of our subsidiaries where we exercise control. For investments in subsidiaries that are not wholly-owned, but where we exercise control, the equity held by the minority owners and their portion of net income (loss) are reflected as noncontrolling interests. Investments over which we have the ability to exercise significant influence over operating and financial policies, but do not hold a controlling interest, are accounted for using the equity method of accounting. All significant intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Consolidated Financial Statements, all dollar and share amounts in tabulations are in millions of dollars and shares, respectively, unless otherwise indicated.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S.”) requires management to make estimates and judgments that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. We base our estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. Estimates are used for, but are not limited to, determining the following: allowance for doubtful accounts and inventory valuation reserves; recoverability of long-lived assets; useful lives used in depreciation and amortization; income taxes and related valuation allowances; accruals for contingencies and actuarial assumptions to determine costs and liabilities related to employee benefit plans; stock-based compensation and fair value of assets acquired and liabilities assumed in acquisitions.

Revenue Recognition

Our products and services are generally sold based upon purchase orders or contracts with the customer that include fixed or determinable prices and that do not include right of return or other similar provisions or other significant post-delivery obligations. Our products are produced in a standard manufacturing operation, even if produced to our customer’s specifications, and are sold in the ordinary course of business. We recognize revenue for these products upon delivery, when title passes, when collectability is reasonably assured and there are no further significant obligations for future performance. Provisions for estimated warranty returns or similar types of items are made at the time the related revenue is recognized. Revenue for services is recognized as the services are rendered and when collectability is reasonably assured. Rates for services are typically priced on a per day, per meter, per man hour or similar basis. In certain situations, revenue is generated from transactions that may include multiple products and services under one contract or agreement and which may be delivered to the customer over an extended period of time. Revenue from these arrangements is recognized in accordance with the above criteria and as each item or service is delivered based on their relative fair value.

Research and Engineering

Research and engineering expenses include costs associated with the research and development of new products and services and costs associated with sustaining engineering of existing products and services. These costs are expensed as incurred and include research and development costs for new products and services of $324 million, $283 million and $231 million for the years ended December 31, 2011, 2010 and 2009, respectively.

 

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Baker Hughes Incorporated

Notes to Consolidated Financial Statements

 

Cash, Cash Equivalents and Short-term Investments

We maintain cash deposits with financial institutions that may exceed federally insured limits. We monitor the credit ratings and our concentration of risk with these financial institutions on a continuing basis to safeguard our cash deposits.

Cash equivalents include only those investments with an original maturity of three months or less. Short-term investments have an original maturity of greater than three months but less than one year.

Allowance for Doubtful Accounts

We establish an allowance for doubtful accounts based on various factors including historical experience, current aging status of the customer accounts, and the payment history and financial condition of our customers. Provisions for doubtful accounts are recorded when it becomes evident that the customer will not make the required payments at either contractual due dates or in the future.

Concentration of Credit Risk

We grant credit to our customers, which operate primarily in the oil and natural gas industry. Although this concentration could affect our overall exposure to credit risk, we believe that our risk is minimized because the majority of our business is conducted with major companies many of which are geographically diverse, thus spreading the credit risk. To manage this risk, we perform periodic credit evaluations of our customers’ financial condition, including monitoring our customers’ payment history and current credit worthiness. We do not generally require collateral in support of our trade receivables, but we may require payment in advance or security in the form of a letter of credit or bank guarantee. During 2011, 2010 and 2009, no individual customer accounted for more than 10% of our consolidated revenue.

Inventories

Inventories are stated at the lower of cost or market. Cost is determined using the first-in, first-out (“FIFO”) method or the average cost method, which approximates FIFO, and includes the cost of materials, labor and manufacturing overhead. As necessary, we record provisions and maintain reserves for excess, slow moving and obsolete inventory. To determine these reserve amounts, we regularly review inventory quantities on hand and compare them to estimates of future product demand, market conditions, production requirements and technological developments.

Property, Plant and Equipment and Accumulated Depreciation

Property, plant and equipment (“PP&E”) is stated at cost less accumulated depreciation, which is generally provided by using the straight-line method over the estimated useful lives of the individual assets. Significant improvements and betterments are capitalized if they extend the useful life of the asset. We manufacture a substantial portion of our tools and equipment and the cost of these items, which includes direct and indirect manufacturing costs, are capitalized and carried in inventory until it is completed. When complete, the cost is reflected in capital expenditures and is classified as machinery, equipment and other in PP&E. Maintenance and repairs are charged to expense as incurred. Upon sale or other disposition, the applicable amounts of asset cost and accumulated depreciation are removed from the balance sheet and the net amount, less proceeds from disposal, is charged or credited to income. The capitalized costs of computer software developed or purchased for internal use are classified in machinery, equipment and other.

Goodwill, Intangible Assets and Amortization

Goodwill is the excess of the consideration transferred over the fair value of the tangible and identifiable intangible assets and liabilities recognized. Goodwill and intangible assets with indefinite lives are not amortized. Intangible assets with finite useful lives are amortized on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized, which is generally on a straight-line basis over the asset’s estimated useful life.

Impairment of PP&E, Goodwill, Intangibles and Other Long-lived Assets

We review PP&E, intangible assets and certain other long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable and at least annually for certain intangible assets. The determination of recoverability is made based upon the estimated undiscounted future net cash flows. The amount of impairment loss,

 

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if any, is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related assets.

We perform an annual impairment test of goodwill for each of our reporting units as of October 1, or more frequently if circumstances indicate that impairment may exist. Our reporting units are based on our organizational and reporting structure. Corporate and other assets and liabilities are allocated to the reporting units to the extent that they relate to the operations of those reporting units in determining their carrying amount. The determination of impairment is made by comparing the carrying amount with its fair value, which is generally calculated using a combination of the market, comparable transaction and discounted cash flow approaches.

Income Taxes

We use the liability method for determining our income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Deferred tax liabilities and assets, which are computed on the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities, are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. Future tax benefits are recognized to the extent that realization of such benefits is more likely than not. A valuation allowance to reduce deferred tax assets is established when it is more likely than not that some portion or all of the deferred tax assets will not be realized.

We intend to indefinitely reinvest certain earnings of our foreign subsidiaries in operations outside the U.S., and accordingly, we have not provided for U.S. income taxes on such earnings. We do provide for the U.S. and additional non-U.S. taxes on earnings anticipated to be repatriated from our non-U.S. subsidiaries.

Our tax filings for various periods are subject to audit by tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or through the courts. We have provided for the amounts we believe will ultimately result from these proceedings. In addition to the assessments that have been received from various tax authorities, we also provide for taxes for uncertain tax positions where formal assessments have not been received. We classify interest and penalties related to uncertain tax positions as income taxes in our financial statements.

Environmental Matters

Estimated remediation costs are accrued using currently available facts, existing environmental permits, technology and enacted laws and regulations. For sites where we are primarily responsible for the remediation, our cost estimates are developed based on internal evaluations and are not discounted. Accruals are recorded when it is probable that we will be obligated to pay for environmental site evaluation, remediation or related activities, and such costs can be reasonably estimated. As additional information becomes available, accruals are adjusted to reflect current cost estimates. Ongoing environmental compliance costs, such as obtaining environmental permits, installation of pollution control equipment and waste disposal, are expensed as incurred. Where we have been identified as a potentially responsible party in a U.S. federal or state “Superfund” site, we accrue our share of the estimated remediation costs of the site. This share is based on the ratio of the estimated volume of waste we contributed to the site to the total volume of waste disposed at the site.

Foreign Currency

A number of our significant foreign subsidiaries have designated the local currency as their functional currency and, as such, gains and losses resulting from balance sheet translation of foreign operations are included as a separate component of accumulated other comprehensive loss within stockholders’ equity. Gains and losses from foreign currency transactions, such as those resulting from the settlement of receivables or payables in the non-functional currency, are included in marketing, general and administrative (“MG&A”) expenses in the consolidated statements of operations as incurred. For those foreign subsidiaries that have designated the U.S. Dollar as the functional currency, monetary assets and liabilities are remeasured at period-end exchange rates, and nonmonetary items are remeasured at historical exchange rates. Gains and losses resulting from this balance sheet remeasurement are also included in MG&A expenses in the consolidated statements of operations as incurred.

Derivative Financial Instruments

We monitor our exposure to various business risks including commodity prices, foreign currency exchange rates and interest rates and regularly use derivative financial instruments to manage these risks. Our policies do not permit the use of derivative financial instruments for speculative purposes. We use foreign currency forward contracts to hedge certain firm commitments and transactions

 

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denominated in foreign currencies, and we use interest rate swap contracts to manage interest rate risk.

At the inception of a new derivative, we designate the derivative as a hedge or we determine the derivative to be undesignated as a hedging instrument as the facts dictate. We document the relationships between the hedging instruments and the hedged items, as well as our risk management objectives and strategy for undertaking various hedge transactions. We assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of the hedged item at both the inception of the hedge and on an ongoing basis.

New Accounting Standards Updates

In May 2011, the Financial Accounting Standards Board (“FASB”) issued an update to Accounting Standards Codification (“ASC”) 820, Fair Value Measurement. The Accounting Standards Update (“ASU”) conforms certain sections of ASC 820 to International Financial Reporting Standards in order to provide a single converged guidance on the measurement of fair value. This update also expands the existing disclosure requirements for fair value measurements. This ASU is effective for interim and annual periods beginning after December 15, 2011. We will adopt this ASU prospectively in the first quarter of 2012. We currently do not expect this ASU to have a material impact, if any, on our consolidated financial statements.

In June 2011, the FASB issued an update to ASC 220, Comprehensive Income. This ASU requires entities to present components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements that would include reclassification adjustments by component for items that are reclassified from other comprehensive income to net income on the face of the financial statements. In December 2011, the FASB issued an update to this ASU indefinitely deferring the implementation of the reclassification adjustments by component requirement of the ASU issued in June 2011. These ASUs are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We will adopt the new presentation requirements of these ASUs retrospectively in the first quarter of 2012.

In September 2011, the FASB issued an update to ASC 350, Intangibles - Goodwill and Other. This ASU amends the guidance in ASC 350-20 on testing for goodwill impairment. The revised guidance allows entities testing for goodwill impairment to have the option of performing a qualitative assessment before calculating the fair value of the reporting unit. The ASU does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirement to test annually for impairment. The ASU is limited to goodwill and does not amend the annual requirement for testing other indefinite-lived intangible assets for impairment. The ASU is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We will adopt this ASU for our 2012 goodwill impairment testing. We do not expect this ASU to have a material impact, if any, on our consolidated financial statements.

NOTE 2. ACQUISITIONS

ACQUISITION OF BJ SERVICES

On April 28, 2010, we acquired 100% of the outstanding common stock of BJ Services Company (“BJ Services”) in a cash and stock transaction valued at $6,897 million. This acquisition provided us with a proven leader in the areas of pressure pumping, stimulation and fracturing, and expanded our suite of service and product offerings. Total consideration consisted of $793 million in cash, 118 million shares valued at $6,048 million, and Baker Hughes options with a fair value of $56 million in exchange for BJ Services options held by BJ Services employees and directors, all of which we assumed. Revenue and net income of BJ Services from the acquisition date included in our consolidated statement of operations for 2010 were $3,686 million and $290 million, respectively. Pursuant to an agreement with the Antitrust Division of the U.S. Department of Justice in connection with the governmental approval of the acquisition, in August 2010 we sold two leased stimulation vessels and certain other assets used to perform sand control services in the U.S. Gulf of Mexico for approximately $55 million in cash.

Recording of Assets Acquired and Liabilities Assumed

The transaction has been accounted for using the acquisition method of accounting and, accordingly, assets acquired and liabilities assumed were recorded at their fair values as of the acquisition date. The excess of the consideration transferred over those fair values totaling $4,406 million was recorded as goodwill.

 

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The following table summarizes the amounts recognized for assets acquired and liabilities assumed.

 

 

      Fair Values  

  Assets:

  

Cash and cash equivalents

   $ 113   

Accounts receivable

     951   

Inventories

     419   

Other current assets

     125   

Property, plant and equipment

     2,745   

Intangible assets

     1,404   

Goodwill

     4,406   

Other long-term assets

     109   

  Liabilities:

  

Liabilities for change in control and transaction fees

     210   

Current liabilities

     776   

Deferred income taxes and other tax liabilities

     1,428   

Long-term debt

     531   

Liabilities for pensions and other post retirement benefits

     154   

Other long-term liabilities

     29   

Noncontrolling interests

     247   

  Net assets acquired

   $ 6,897   

The significant step-up adjustments recorded to present the asset or liability at fair value were $406 million for property, plant and equipment, with a depreciable life of approximately six years; $1,262 million for deferred taxes and other tax liabilities; and $202 million for noncontrolling interests.

The table below summarizes the fair values recorded for the identifiable intangible assets and their estimated useful lives as of the acquisition date.

 

 

      Fair Values      Useful Lives  

  Customer relationships

   $ 428         3-16 years   

  Technology

     451         5-15 years   

  BJ Services trade name

     360         Indefinite   

  Other trade names

     38         5-12 years   

  In-process research and development

     127         Indefinite   

  Total identifiable intangible assets

   $ 1,404      

Pro Forma Impact of the Acquisition

The following unaudited supplemental pro forma results present consolidated information as if the acquisition had been completed as of January 1, 2010 and January 1, 2009. The pro forma results include: (i) the amortization associated with an estimate of the acquired intangible assets, (ii) interest expense associated with debt used to fund a portion of the acquisition and reduced interest income associated with cash used to fund a portion of the acquisition, (iii) the impact of certain fair value adjustments such as additional depreciation expense for adjustments to property, plant and equipment and reduction to interest expense for adjustments to debt, and (iv) costs directly related to acquiring BJ Services. The pro forma results do not include any potential synergies, cost savings or other expected benefits of the acquisition. Accordingly, the pro forma results should not be considered indicative of the results that would have occurred if the acquisition and related borrowings had been consummated as of January 1, 2009 or January 1, 2010, nor are they indicative of future results.

 

 

      Years Ended December 31,  
   2010
Pro Forma
     2009      
Pro Forma      
 

Revenue

   $ 15,903       $ 13,301   

Net income

   $ 828       $ 345   

Basic net income per share

   $ 1.92       $ 0.81   

Diluted net income per share

   $ 1.91       $ 0.80   

 

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OTHER ACQUISITIONS

We had no material acquisitions in 2011. During 2010, we completed several other acquisitions having an aggregate purchase price of approximately $208 million, net of cash acquired of $4 million. As a result of these acquisitions, we recorded $91 million of goodwill. Pro forma results of operations for these acquisitions have not been presented because the effect of these acquisitions was not material to our consolidated financial statements.

NOTE 3. STOCK-BASED COMPENSATION

Stock-based compensation cost is measured at the date of grant, based on the calculated fair value of the award, and is recognized as expense over the employee’s service period, which is generally the vesting period of the equity grant. Additionally, compensation cost is recognized based on awards ultimately expected to vest; therefore, we have reduced the cost for estimated forfeitures based on historical forfeiture rates. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods to reflect actual forfeitures.

The following table summarizes stock-based compensation costs for the years ended December 31, 2011, 2010 and 2009. There were no stock-based compensation costs capitalized as the amounts were not material.

 

 

      2011     2010     2009  

Stock-based compensation cost

   $ 108      $ 87      $ 88   

Tax benefit

     (22     (18     (15

Stock-based compensation cost, net of tax

   $ 86      $ 69      $ 73   

For our stock options and restricted stock awards and units, we currently have 32.5 million shares authorized for issuance and as of December 31, 2011, approximately 12 million shares were available for future grants. Our policy is to issue new shares for exercises of stock options, when restricted stock awards are granted, at vesting of restricted stock units, and issuances under the employee stock purchase plan.

Stock Options

Our stock option plans provide for the issuance of stock options to directors, officers and other key employees at an exercise price equal to the fair market value of the stock at the date of grant. Although subject to the terms of the stock option agreement, substantially all of the stock options become exercisable in three equal annual installments, beginning a year from the date of grant, and generally expires ten years from the date of grant. The stock option plans provide for the acceleration of vesting upon the employee’s retirement; therefore, the service period is reduced for employees that are or will become retirement eligible during the vesting period and, accordingly, the recognition of compensation expense for these employees is accelerated. Compensation cost related to stock options is recognized on a straight-line basis over the vesting or service period and is net of forfeitures.

The fair value of each stock option granted is estimated using the Black-Scholes option pricing model. The following table presents the weighted average assumptions used in the option pricing model for options granted. The expected life of the options represents the period of time the options are expected to be outstanding. The expected life is based on our historical exercise trends and post-vest termination data incorporated into a forward-looking stock price model. The expected volatility is based on our implied volatility, which is the volatility forecast that is implied by the prices of our actively traded options to purchase our stock observed in the market. The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the options were granted. The dividend yield is based on our history of dividend payouts.

 

 

      2011     2010     2009  

  Expected life (years)

     5.0        5.0        6.0   

  Risk-free interest rate

     1.8     2.2     2.6

  Volatility

     40.8     39.8     41.2

  Dividend yield

     0.9     1.2     1.8

  Weighted average fair value per share at grant date

   $ 24.20      $ 16.24      $ 12.66   

 

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The following table presents the changes in stock options outstanding and related information (in thousands, except per option prices):

 

 

      Number of Options   Weighted Average Exercise
Price Per Option

  Outstanding at December 31, 2010

   10,902   $        50.72

  Granted

     1,281             68.94

  Exercised

   (2,636)             43.05

  Forfeited

         (78)             52.29

  Expired

         (37)             59.10

  Outstanding at December 31, 2011

     9,432   $        55.34

The total intrinsic value of stock options (defined as the amount by which the market price of our common stock on the date of exercise exceeds the exercise price of the option) exercised in 2011, 2010 and 2009 was $74 million, $18 million and $0.4 million, respectively. The income tax benefit realized from stock options exercised was $20 million, $0.9 million and $0.1 million in 2011, 2010 and 2009, respectively.

The total fair value of options vested in 2011, 2010 and 2009 was $22 million, $20 million and $17 million, respectively. As of December 31, 2011, there was $14 million of total unrecognized compensation cost related to unvested stock options, which is expected to be recognized over a weighted average period of two years.

The following table summarizes information about stock options outstanding at December 31, 2011 (in thousands, except per option prices and remaining life):

 

 

       Outstanding    Exercisable
    Range of Exercise Prices      Number of
Options
    

Weighted Average
Remaining
Contractual Life

(In years)

   Weighted
Average
Exercise Price
Per Option
   Number of
Options
    

Weighted Average
Remaining
Contractual Life

(In years)

   Weighted
Average
Exercise Price
Per Option
   $ 14.79    -    $ 16.78         3       1.8    $    15.84      3       1.8    $      15.84    
       22.88   -      33.32         1,536       6.1          28.76      1,274       5.9            28.69    
       34.45   -      50.94         2,841       7.1          43.73      1,578       6.3            42.10    
       51.73   -      77.41         3,930       6.6          67.14      2,704       5.3            66.01    
       77.84   -      86.50         1,122       4.6          79.91      1,122       4.6            79.91    
Total               9,432       6.4    $    55.34      6,681       5.5    $      55.56    

The total intrinsic value of stock options outstanding at December 31, 2011 was $45 million, of which $36 million relates to options vested and exercisable. The intrinsic value for stock options outstanding is calculated as the amount by which the quoted price of $48.64 of our common stock as of the end of 2011 exceeds the exercise price of the options.

Restricted Stock Awards and Units

In addition to stock options, officers, directors and key employees may be granted restricted stock awards (“RSA”), which is an award of common stock with no exercise price, or restricted stock units (“RSU”), where each unit represents the right to receive, at the end of a stipulated period, one unrestricted share of stock with no exercise price. RSAs and RSUs are subject to cliff or graded vesting, generally ranging over a three to five year period. We determine the fair value of restricted stock awards and restricted stock units based on the market price of our common stock on the date of grant. Compensation cost for RSAs and RSUs is primarily recognized on a straight-line basis over the vesting period and is net of forfeitures.

 

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The following table presents the changes in RSAs and RSUs and related information (in thousands, except per share/unit prices):

 

 

     

RSA

Number of
Shares

   

Weighted Average

Grant Date Fair
Value Per Share

  

RSU

Number of
Units

   

Weighted Average

Grant Date Fair
Value Per Unit

  Unvested balance at December 31, 2010

     1,399      $    43.05      1,098      $    46.60

  Granted

     698            62.85      351            63.33

  Vested

     (691         46.24      (421         47.38

  Forfeited

     (94         49.72      (88         51.06

  Unvested balance at December 31, 2011

     1,312      $    51.43      940      $    52.08

The weighted average grant date fair value per share for RSAs granted in 2011, 2010 and 2009 was $62.85, $47.68 and $31.18, respectively. The weighted average grant date fair value per unit for RSUs granted in 2011, 2010 and 2009 was $63.33, $47.30 and $31.54, respectively.

The total fair value of RSAs and RSUs vested in 2011, 2010 and 2009 was $52 million, $36 million and $18 million, respectively. As of December 31, 2011, there was $40 million and $29 million of total unrecognized compensation cost related to unvested RSAs and RSUs, respectively, which is expected to be recognized over a weighted average period of two years.

Employee Stock Purchase Plan

The Employee Stock Purchase Plan (“ESPP”) provides for eligible employees to purchase shares on an after-tax basis in an amount between 1% and 10% of their annual pay: (i) on June 30 of each year at a 15% discount of the fair market value of our common stock on January 1 or June 30, whichever is lower, and (ii) on December 31 of each year at a 15% discount of fair market value of our common stock on July 1 or December 31, whichever is lower. An employee may not purchase more than $5,000 in either of the six-month measurement periods described above or $10,000 annually.

We currently have 22.5 million shares authorized for issuance, and at December 31, 2011, there were 4.1 million shares reserved for future issuance. Compensation cost for the years ended December 31, was calculated using the Black-Scholes option pricing model with the following assumptions:

 

 

      2011     2010     2009  

  Expected life (years)

     1.0        1.0        1.0   

  Risk-free interest rate

     0.1     0.2     0.3

  Volatility

     36.6     44.2     69.5

  Dividend yield

     1.0     1.5     1.9

  Fair value per share of the 15% cash discount

     $    9.62        $    6.16        $    4.81   

  Fair value per share of the look-back provision

     6.50        4.98        8.44   

  Total weighted average fair value per share at grant date

     $  16.12        $  11.14        $  13.25   

We calculated estimated volatility using historical daily prices based on the expected life of the stock purchase plan. The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the ESPP shares were granted. The dividend yield is based on our history of dividend payouts.

 

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NOTE 4. INCOME TAXES

The provision for income taxes is comprised of the following for the years ended December 31:

 

 

      2011     2010     2009  

Current:

      

United States

   $ 609      $ 179      $ 65   

Foreign

     479        472        381   

Total current

     1,088        651        446   

Deferred:

      

United States

     (315     (107     (210

Foreign

     (177     (81     (46

Total deferred

     (492     (188     (256

Provision for income taxes

   $ 596      $ 463      $ 190   

The geographic sources of income before income taxes are as follows for the years ended December 31:

 

 

      2011      2010      2009  

United States

   $ 1,466       $ 534       $ (18

Foreign

     873         748         629   

Income before income taxes

   $ 2,339       $ 1,282       $ 611   

The provision for income taxes differs from the amount computed by applying the U.S. statutory income tax rate to income before income taxes for the reasons set forth below for the years ended December 31:

 

 

      2011     2010     2009  

Statutory income tax at 35%

   $ 819      $ 449      $ 214   

Effect of foreign operations

     (11     (54     (53

Net tax charge related to foreign losses

     51        64        38   

Adjustments of prior years’ tax positions

     (51     (35     (26

State income taxes - net of U.S. tax benefit

     40        19        6   

Impact of reorganization of foreign subsidiaries

     (214     -        -   

Other - net

     (38     20        11   

Provision for income taxes

   $ 596      $ 463      $ 190   

During the third quarter of 2011, we reorganized certain of our foreign subsidiaries. As a result of the reorganization, previously accrued U.S. deferred income taxes related to those subsidiaries were reduced by $214 million to account for certain foreign tax credits that existed prior to the acquisition of BJ Services and are now available to offset future U.S. taxes.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, as well as operating loss and tax credit carryforwards.

 

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The tax effects of our temporary differences and carryforwards are as follows at December 31:

 

 

      2011     2010  

Deferred tax assets:

    

Receivables

   $ 42      $ 37   

Inventory

     228        213   

Employee benefits

     131        120   

Other accrued expenses

     173        148   

Operating loss carryforwards

     228        186   

Tax credit carryforwards

     372        329   

Other

     84        92   

Subtotal

     1,258        1,125   

Valuation allowances

     (318     (232

Total

     940        893   

Deferred tax liabilities:

    

Goodwill and other intangibles

     423        578   

Property

     273        377   

Undistributed earnings of foreign subsidiaries

     366        583   

Other

     42        87   

Total

     1,104        1,625   

Net deferred tax liability

   $ (164   $ (732

We record a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character in the future and in the appropriate taxing jurisdictions. We have provided a valuation allowance for operating loss and foreign tax credit carryforwards in certain non-U.S. jurisdictions. The increase in the valuation allowances of $86 million resulted primarily from net tax charges related to foreign losses. The operating loss carryforwards without a valuation allowance will expire in varying amounts over the next twenty years.

We have provided for U.S. and additional foreign taxes for the anticipated repatriation of certain earnings of our foreign subsidiaries. The reduction in the deferred tax liability for undistributed earnings of foreign subsidiaries of $217 million resulted primarily from the reorganization of certain foreign subsidiaries that resulted in certain foreign tax credits that existed prior to the acquisition of BJ Services to now be available to offset future U.S. taxes. We consider the undistributed earnings of our foreign subsidiaries above the amount for which taxes have already been provided to be indefinitely reinvested, as we have no current intention to repatriate these earnings. As such, deferred income taxes are not provided for temporary differences of approximately $1.0 billion, $2.5 billion and $2.3 billion at December 31, 2011, 2010 and 2009, respectively, representing earnings of non-U.S. subsidiaries intended to be permanently reinvested. These additional foreign earnings could become subject to additional tax, if remitted, or deemed remitted, as a dividend. Computation of the potential deferred tax liability associated with these undistributed earnings and any other basis differences, is not practicable.

The reduction in the deferred tax liability for goodwill and other intangibles of $155 million includes a reduction of $95 million related to the impairment of the BJ Services trade name.

At December 31, 2011, we had approximately $92 million of foreign tax credits which may be carried forward indefinitely under applicable foreign law and $278 million of foreign tax credits available to offset future payments of U.S. federal income taxes, primarily expiring in 2018 through 2021. In addition, at December 31, 2011, we had approximately $2 million of state tax credits expiring in varying amounts between 2016 and 2021.

At December 31, 2011, we had $379 million of tax liabilities for gross unrecognized tax benefits, which includes liabilities for interest and penalties of $64 million and $32 million, respectively. If we were to prevail on all uncertain tax positions, the net effect would be a benefit to our effective tax rate of approximately $349 million. The remaining approximately $30 million is offset by deferred tax assets that represent tax benefits that would be received in different taxing jurisdictions in the event that we did not prevail on all uncertain tax positions.

 

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Baker Hughes Incorporated

Notes to Consolidated Financial Statements

 

The following table presents the changes in our unrecognized tax benefits and associated interest and penalties included in the consolidated balance sheet.

 

 

      Gross Unrecognized Tax
Benefits, Excluding
Interest and Penalties
  Interest and
Penalties
    Total Gross
Unrecognized Tax
Benefits
 

  Balance at December 31, 2008

   $      323     $      78        $      401   

  Increase (decrease) in prior year tax positions

             (75)     10        (65

  Increase in current year tax positions

               16     6        22   

  Decrease related to settlements with taxing authorities

                (6)     (2     (8

  Decrease related to lapse of statute of limitations

                (9)     (4     (13

  Increase due to effects of foreign currency translation

                 1     1        2   

  Balance at December 31, 2009

             250     89        339   

  Acquisition of BJ Services

             102     28        130   

  Increase (decrease) in prior year tax positions

               (16)     4        (12

  Increase in current year tax positions

                 4     3        7   

  Decrease related to settlements with taxing authorities

                (7)     (5     (12

  Decrease related to lapse of statute of limitations

                (6)     (1     (7

  Decrease due to effects of foreign currency translation

                (3)     (4     (7

  Balance at December 31, 2010

            324     114        438   

  Increase (decrease) in prior year tax positions

                (5)     12        7   

  Increase in current year tax positions

                 8     11        19   

  Decrease related to settlements with taxing authorities

                (3)     (1     (4

  Decrease related to lapse of statute of limitations

                (38)     (38     (76

  Decrease due to effects of foreign currency translation

                (3)     (2     (5

  Balance at December 31, 2011

   $       283     $      96        $      379   

It is expected that the amount of unrecognized tax benefits will change in the next twelve months due to expiring statutes, audit activity, tax payments, competent authority proceedings related to transfer pricing, or final decisions in matters that are the subject of litigation in various taxing jurisdictions in which we operate. At December 31, 2011, we had approximately $159 million of tax liabilities, net of $17 million of tax assets, related to uncertain tax positions, each of which are individually insignificant, and each of which are reasonably possible of being settled within the next twelve months.

At December 31, 2011, approximately $203 million of total gross unrecognized tax benefits were included in the noncurrent portion of our income tax liabilities, for which the settlement period cannot be determined; however, it is not expected to be within the next twelve months.

We operate in more than 80 countries and are subject to income taxes in most taxing jurisdictions in which we operate. The following table summarizes the earliest tax years that remain subject to examination by the major taxing jurisdictions in which we operate. These jurisdictions are those we project to have the highest tax liability for 2012.

 

 

Jurisdiction    Earliest Open Tax Period    Jurisdiction    Earliest Open Tax Period

Canada

   1998    Norway    1999

Germany

   2003    United Kingdom    2007

Netherlands

   2006    United States    2004

 

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Baker Hughes Incorporated

Notes to Consolidated Financial Statements

 

NOTE 5. EARNINGS PER SHARE

A reconciliation of the number of shares used for the basic and diluted earnings per share (“EPS”) computations is as follows for the years ended December 31:

 

 

      2011      2010      2009  

Weighted average common shares outstanding for basic EPS

     436         394         310   

Effect of dilutive securities - stock plans

     2         1         1   

Adjusted weighted average common shares outstanding for diluted EPS

     438         395         311   

Future potentially dilutive shares excluded from diluted EPS:

        

Options with an exercise price greater than the average market price for the period

     3         7         4   

NOTE 6. INVENTORIES

Inventories, net of reserves of $304 million and $322 million in 2011 and 2010, respectively, are comprised of the following at December 31:

 

 

      2011      2010  

Finished goods

   $ 2,830       $ 2,283   

Work in process

     231         181   

Raw materials

     161         130   

Total

   $ 3,222       $ 2,594   

NOTE 7. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are comprised of the following at December 31:

 

 

      Useful Life    2011      2010  

Land

      $ 193       $ 191   

Buildings and improvements

   5 - 30 years      1,998         1,605   

Machinery, equipment and other

   1 - 20 years      10,475         8,881   

Subtotal

        12,666         10,677   

Less: Accumulated depreciation

          5,251         4,367   

Total

        $ 7,415       $ 6,310   

Depreciation expense relating to property, plant and equipment was $1,221 million, $991 million and $680 million in 2011, 2010 and 2009, respectively.

NOTE 8. GOODWILL AND INTANGIBLE ASSETS

The changes in the carrying amount of goodwill are detailed below by reportable segment.

 

 

     

North

America

   

Latin

America

   

Europe/

Africa/

Russia

Caspian

    

Middle
East/

Asia

Pacific

   

Industrial

Services

And Other

    Total  

  Balance at December 31, 2010

   $ 2,731      $ 879      $ 936       $ 895      $ 428      $ 5,869   

  Purchase price adjustments for previous acquisitions

     337        (293     90         (38     (11     85   

  Acquisitions

     4        -        -         -        -        4   

  Other

     (3     -        1         -        -        (2

  Balance at December 31, 2011

   $ 3,069      $ 586      $ 1,027       $ 857      $ 417      $ 5,956   

 

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Baker Hughes Incorporated

Notes to Consolidated Financial Statements

 

We perform an annual impairment test of goodwill as of October 1 of every year. There were no impairments of goodwill in any of the three years ended December 31, 2011 related to the annual impairment test.

Intangible assets are comprised of the following at December 31:

 

 

     2011      2010  
     

Gross

Carrying

Amount

    

Less:

Accumulated

Amortization

     Net     

Gross

Carrying

Amount

    

Less:

Accumulated

Amortization

     Net  

Definite lived intangibles:

                 

Technology

   $ 755         $    231       $ 524       $ 760         $    181       $ 579   

Contract-based

     17         9         8         20         11         9   

Trade names

     121         16         105         84         18         66   

Customer relationships

     497         77         420         495         39         456   

Subtotal

     1,390         333         1,057         1,359         249         1,110   

Indefinite lived intangibles:

                 

Trade name

     -         -         -         360         -         360   

IPR&D

     86         -         86         99         -         99   

Total

   $ 1,476         $    333       $ 1,143       $ 1,818         $    249       $ 1,569   

During the fourth quarter of 2011, we recorded a charge of $315 million before-tax ($220 million net of tax) related to the impairment of certain trade names, the majority of which related to the impairment of the BJ Services trade name. The BJ Services trade name was classified as an indefinite lived intangible asset and, therefore, was not being amortized. The impairment of the BJ Services trade name was due to the decision to minimize the use of the BJ Services trade name as part of our overall branding strategy. The BJ Services trade name was revalued resulting in a revised fair value of $61 million, with a remaining useful life of three years, which we will begin amortizing in 2012 on an accelerated basis. We estimated the fair value of this intangible asset based on an income approach using the relief-from-royalty method, which is dependent on a number of estimates and assumptions such as future growth and trends, royalty rates, discount rates and other variables. We based our fair value estimates on assumptions we believe to be reasonable, but which are unpredictable and inherently uncertain.

The following table details the impairment charge by reportable segment.

 

 

North America

   $ 105   

Latin America

     64   

Europe/Africa/Russia Caspian

     48   

Middle East/Asia Pacific

     47   

Industrial Services and Other

     51   

Total

   $ 315   

Intangible assets are generally amortized on a straight-line basis with estimated useful lives ranging from 2 to 20 years. Amortization expense included in net income for the years ended December 31, 2011, 2010 and 2009 was $96 million, $76 million and $31 million, respectively. Estimated amortization expense for each of the subsequent five fiscal years is expected to be as follows: 2012 - $135 million; 2013 - $113 million; 2014 - $98 million; 2015 - $90 million; and 2016 - $89 million.

NOTE 9. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

Our financial instruments include cash and cash equivalents, short-term investments, accounts receivable, accounts payable, debt, foreign currency forward contracts, foreign currency option contracts and interest rate swaps. Except as described below, the estimated fair value of such financial instruments at December 31, 2011 and 2010 approximates their carrying value as reflected in our consolidated balance sheet.

Short-term Investments

In 2010, we purchased short-term investments consisting of $250 million in U.S. Treasury Bills, which matured in May of 2011, and were used to repay the $250 million principal amount of our 5.75% Notes that matured in June 2011. The fair value at December 31, 2010 was determined using level 1 inputs including quoted period end market prices. These investments were classified as available-for-sale and were recorded at fair value, which approximated cost.

 

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Baker Hughes Incorporated

Notes to Consolidated Financial Statements

 

Debt

The estimated fair value of total debt at December 31, 2011 and 2010 was $4,910 million and $4,298 million, respectively, which differs from the carrying amounts of $4,069 million and $3,885 million, respectively, included in our consolidated balance sheet. The fair value was determined using level 2 inputs including quoted period end market prices.

Foreign Currency Forward Contracts

We conduct our business in more than 80 countries around the world, and we are exposed to market risks resulting from fluctuations in foreign currency exchange rates. A number of our significant foreign subsidiaries have designated the local currency as their functional currency. We transact in various foreign currencies and have established a program that primarily utilizes foreign currency forward contracts to reduce the risks associated with the effects of certain foreign currency exposures. Under this program, our strategy is to have gains or losses on the foreign currency forward contracts mitigate the foreign currency transaction gains or losses to the extent practical. These foreign currency exposures typically arise from changes in the value of assets and liabilities which are denominated in currencies other than the functional currency. Our foreign currency forward contracts generally settle in less than 180 days. We do not use these forward contracts for trading or speculative purposes. We designate these forward contracts as fair value hedging instruments or hold these contracts as undesignated hedging instruments and, accordingly, we record the fair value of these contracts as of the end of our reporting period in our consolidated balance sheet with changes in fair value recorded in our consolidated statement of operations along with the change in fair value of the hedged item.

We had outstanding foreign currency forward contracts with notional amounts aggregating $117 million and $156 million to hedge exposure to currency fluctuations in various foreign currencies at December 31, 2011 and 2010, respectively. These contracts are either undesignated hedging instruments or designated and qualify as fair value hedging instruments. The fair value was determined using level 2 inputs including quoted market prices for contracts with similar terms and maturity dates.

Interest Rate Swaps

We are subject to interest rate risk on our debt and investment of cash and cash equivalents arising in the normal course of our business, as we do not engage in speculative trading strategies. We maintain an interest rate management strategy, which primarily uses a mix of fixed and variable rate debt that is intended to mitigate the exposure to changes in interest rates in the aggregate for our investment portfolio. We may use interest rate swaps to manage the economic effect of fixed rate obligations associated with certain debt.

In September 2011, we redeemed in full our $500 million 6.5% Senior Notes maturing November 2013. In conjunction with this debt redemption, we terminated two related interest rate swap agreements resulting in a net gain on the swap agreements of $25 million. The two swap agreements were entered into in June 2009 for a notional amount of $250 million each in order to hedge changes in the fair market value of the debt. The swap agreements had been designated and each qualified as a fair value hedging instrument.

Fair Value of Derivative Instruments

The fair value of derivative instruments included in our consolidated balance sheet was as follows at December 31:

 

 

          2011      2010  
Derivative    Balance Sheet Location    Fair Value  

Foreign Currency Forward Contracts

   Other current assets    $ 1       $ -   

Foreign Currency Forward Contracts

   Other accrued liabilities    $ 2       $ 2   

Interest Rate Swaps

   Other assets    $ -       $ 24   

The effects of derivative instruments in our consolidated statement of operations were as follows for the years ended December 31 (amounts exclude any income tax effects):

 

 

          Amount of Gain (Loss) Recognized in Income  
Derivative    Statement of Operations Location    2011     2010     2009  

Foreign Currency Forward Contracts

   Marketing, general and administrative    $ (7   $ (7   $ 11   

Interest Rate Swaps

   Interest expense, net    $ 8      $ 16      $ 6   

 

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Baker Hughes Incorporated

Notes to Consolidated Financial Statements

 

NOTE 10. INDEBTEDNESS

Total debt consisted of the following at December 31, net of unamortized discount and debt issuance cost:

 

 

      2011      2010  

5.75% Notes due June 2011 with an effective interest rate of 5.86%

     $            -         $        254   

6.5% Senior Notes due November 2013 with an effective interest rate of 6.73%

     -         522   

6.0% Notes due June 2018 with an effective interest rate of 6.29%

     265         267   

7.5% Senior Notes due November 2018 with an effective interest rate of 7.61%

     743         742   

3.2% Senior Notes due August 2021 with an effective interest rate of 3.32%

     742         -   

8.55% Debentures due June 2024 with an effective interest rate of 8.76%

     148         148   

6.875% Notes due January 2029 with an effective interest rate of 7.08%

     393         393   

5.125% Notes due September 2040 with an effective interest rate of 5.22%

     1,479         1,479   

Other debt

     299         80   

Total debt

     4,069         3,885   

Less short-term debt and current portion of long-term debt

     224         331   

Long-term debt

     $    3,845         $    3,554   

In August 2011, we completed a private placement of $750 million 3.2% unsecured Senior Notes under our existing indenture dated October 28, 2008 that have registration rights and will mature in August 2021. Net proceeds from the offering were approximately $742 million after deducting the underwriting discount and expense of the offering. Interest is payable February 15 and August 15 of each year. The 3.2% Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future indebtedness; senior in right of payment to any future subordinated indebtedness; and effectively junior to our future secured indebtedness, if any, and structurally subordinated to all existing and future indebtedness of our subsidiaries. We may redeem, at our option, all or part of the 3.2% Notes at any time, at the applicable make-whole redemption prices plus accrued and unpaid interest to the date of redemption. In September 2011, we used $563 million of the net proceeds from the offering to redeem in full our 6.5% Notes, and the remainder will be used for general corporate purposes, which could include funding on-going operations, business acquisitions and repurchases of our common stock. The redemption of our 6.5% Notes resulted in the payment of a redemption premium of $63 million and in a pre-tax loss on the early extinguishment of this debt of $40 million, which includes the redemption premium and the write off of the remaining original debt issuance cost and debt discount, partially offset by the $25 million gain from the termination of two related interest rate swap agreements.

In June 2011, we repaid the $250 million principal amount of our 5.75% Notes using proceeds from U.S. Treasury Bills that matured in May 2011.

In September 2011, we entered into a five-year committed $2.5 billion revolving credit facility maturing in September 2016. The new revolving credit facility replaced our existing committed revolving credit facilities of $500 million maturing in July 2012 and $1.2 billion maturing in March 2013, both of which were terminated in September 2011. There were no direct borrowings under any of the committed revolving credit facilities during 2011. We also have a commercial paper program under which we may issue up to $2.5 billion in commercial paper with maturities of no more than 270 days. The maximum combined borrowing at any point in time under both the commercial paper program and the credit facility is $2.5 billion. At December 31, 2011, we had $130 million of commercial paper outstanding.

Maturities of debt at December 31, 2011 are as follows: 2012 - $224 million; 2013 - $8 million; 2014 - $10 million; 2015 - $13 million; 2016 - $15 million; and $3,799 million thereafter.

NOTE 11. SEGMENT INFORMATION

We conduct our business primarily through operating segments that are aligned with our geographic regions, which have been aggregated into the following five reportable segments:

 

   

North America (U.S. Land, Gulf of Mexico and Canada)

   

Latin America

   

Europe/Africa/Russia Caspian

   

Middle East/Asia Pacific

   

Industrial Services and Other

 

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Baker Hughes Incorporated

Notes to Consolidated Financial Statements

 

We aggregate our operating segments within each reportable segment, as they have similar economic characteristics and because the long-term financial performance of the segments is affected by similar economic conditions. The performance of our operating segments is evaluated based on profit before tax, which is defined as income before the following: income taxes, net interest expense, corporate expenses, and certain gains and losses not allocated to the segments. For 2011, our operating segment profit includes the charge of $315 million related to the impairment of trade names. For further discussion of the trade name impairments and breakdown by reportable segment, see Note 8. Goodwill and Intangible Assets.

Summarized financial information is shown in the following table.

 

 

     2011     2010     2009  
Segments    Revenue      Profit (Loss)     Revenue      Profit (Loss)     Revenue      Profit (Loss)  

North America

   $ 10,257       $ 1,929      $ 6,621       $ 1,163      $ 3,165       $ 201   

Latin America

     2,183         227        1,569         74        1,094         78   

Europe/Africa/Russia Caspian

     3,325         342        3,006         260        2,774         458   

Middle East/Asia Pacific

     2,820         321        2,247         177        1,937         241   

Industrial Services and Other

     1,246         53        971         99        694         70   

Total Operations

     19,831         2,872        14,414         1,773        9,664         1,048   

Corporate and Other