10-K 1 a201210-k.htm 10-K 2012 10-K
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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, 2012
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, 2012 reported by the New York Stock Exchange) was approximately $17,960,459,000.
As of February 4, 2013, the registrant has outstanding 441,808,100 shares of common stock, $1 par value per share.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrant’s Definitive Proxy Statement for the 2013 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.


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Baker Hughes Incorporated
INDEX

 
 
Page
 
 
 
 
 
 
 
 
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
 
 
 
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
 
 
 
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
 
 
 
 
 
Item 15.


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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) 439-8600
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 products and services to the downstream refining, and 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, 2012, we had approximately 58,800 employees, of which approximately 58% work outside the United States (“U.S.”).
Our global oilfield operations are organized into a number of geomarket organizations, which are combined into eight geographic regions, each with its own president who in turn reports to one of 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.


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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 three regions - Canada, headquartered in Calgary, Alberta; and U.S. and Latin America regions, both 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.
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.
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. and Canada)
Latin America
Europe/Africa/Russia Caspian
Middle East/Asia Pacific
In addition to the above, our Industrial Services and Other segment includes our downstream refining, and process and pipeline services businesses.
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 9 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, PDC or “diamond”, and Kymerahybrid 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.


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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.
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.
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. Hydraulic fracturing is the practice of pumping fluid through a wellbore at pressures and rates sufficient to crack rock in the target formation, extend the cracks, and leave behind a propping agent to keep the cracks open after pumping ceases. The purpose of the cracks is to provide a pathway that allows for the passage of hydrocarbons from the rock to the wellbore, thus improving the production of hydrocarbons to the surface.
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 SmartCare 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 our downstream refining, and process and pipeline services businesses. Downstream refining 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 within our geomarkets 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 International, 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, Ecolab, Newpark Resources, and FTS International.


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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 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 Company 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 AND 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, 2012, 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.


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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 and location of seasonal events serve to reduce the impact to us of any individual event. 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.
Scheduled repair and maintenance of offshore facilities in the North Sea can reduce activity in the second and third quarters.
Many of our international oilfield customers increase orders for certain products and services in the fourth quarter.
Our Industrial and Other segment typically experiences lower 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 the supply of raw materials, but there can be no assurance that there will be no price or supply issues over the long term.
EMPLOYEES
As of December 31, 2012, we had approximately 58,800 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.


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EXECUTIVE OFFICERS OF BAKER HUGHES INCORPORATED
The following table shows, as of February 13, 2013, the name of each of our executive officers, together with his or her age and all offices presently held.

Name
 
Age

 
 
Martin S. Craighead
 
53

 
Chief Executive Officer since January 2012 and President since 2010. Director of the Company since 2011. Chief Operating Officer from 2010 to 2012. Senior Vice President from 2009 to 2010. Group President of Drilling and Evaluation since 2007 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; Region Manager for Baker Atlas in Latin America and Asia and Region Manager for E&P Solutions from 1995 to 2001. Employed by the Company in 1986. Mr. Craighead will become Chairman of the Board on April 25, 2013, in addition to his current role as President and Chief Executive Officer.
Peter A. Ragauss
 
55

 
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. Mr. Ragauss joined BP plc in 1998 as Assistant to the Group Chief Executive until 2000 when he became Chief Executive Officer of Air BP. 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.
Chad C. Deaton
 
60

 
Executive Chairman of the Board of the Company since January 2012 and Chairman of the Board from 2004 to January 2012. Chief Executive Officer of the Company from 2004 to 2012 and 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 and Executive Vice President of Schlumberger from 1998 to 1999. Employed by the Company in 2004. Mr. Deaton has announced he will retire on April 25, 2013.
Russell J. Cancilla
 
61

 
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
 
50

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

 
Vice President, Human Resources of the Company since 2007. Group Human Resources Director of Coats Plc, a global company engaged in the sewing thread and needlecrafts industry, from 2002 to 2007. Business Development of ID Applications for Gemplus S.A., a global company in the Smart Card industry, from 2000 to 2001. Various human resources positions at Schlumberger from 1989 to 2000. Employed by the Company in 2007.


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Alan R. Crain
 
61

 
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.
Archana Deskus
 
47

 
Vice President and Chief Information Officer of the Company since 2013. Vice President and Chief Information Officer for Ingersoll-Rand from 2011 to 2012. Senior Vice President and Chief Information Officer for Timex Group from 2007 to 2011 and Vice President and Chief Information Officer for Carrier North America from 2003 to 2006. Employed by the Company in 2013.
Alan J. Keifer
 
58

 
Vice President and Controller 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
 
61

 
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
 
42

 
Vice President of the Company since December 2008 and President Western Hemisphere Operations since January 2012. President, Products and Technology from May 2009 to January 2012. 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
 
64

 
Vice President, Office of the CEO since January 2012. Vice President of the Company since 1998 and President Western Hemisphere Operations from May 2009 to January 2012. President of BJ Services LLC from 2009 to 2010. 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.
Mario Ruscev
 
56

 
Vice President and Chief Technology Officer of the Company since August 2012. Chief Executive Officer of Geotech Seismic Services from January 2012 to August 2012 and Chief Executive Officer of FormFactor from 2008 to 2010. Various positions at Schlumberger for 20 years. Employed by the Company in 2012.
Arthur L. Soucy
 
50

 
Vice President of the Company since April 2009 and President Global Products and Services since January 2012. Vice President Supply Chain of the Company from April 2009 to January 2012. 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.
There are no family relationships among our executive officers.


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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 $32 million and $29 million, which includes accruals of $4 million and $5 million for the various Superfund sites, at December 31, 2012 and 2011, 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.



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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 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


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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 available 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.
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.
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.


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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 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 and terrorism threats.
Geopolitical and terrorism risks continue to grow in a number of 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.
Uncertainties in Venezuela have impacted the collection of accounts receivable and could further impact our business operations.
We are not able to predict how uncertainties in Venezuela may impact further collection of accounts receivable


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and our ability to continue operations. We continue to experience delays in receiving payments from our customers in Venezuela. As of December 31, 2012, our accounts receivable in Venezuela were approximately 6% of our total accounts receivable (after any provision for doubtful accounts). For the year ended December 31, 2012, revenue in Venezuela was approximately 2% of our total consolidated revenue. In addition, our operations in Venezuela could be impacted by any further devaluation of the local currency or other action of the Venezuelan government that impedes our ability to conduct operations, which could have a material adverse effect on our results of operations.
Our business is subject to cybersecurity risks and threats.
Threats to our information technology systems associated with cybersecurity risks and cyber incidents or attacks 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 could 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.
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.
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


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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. 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


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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.
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 United Kingdom (“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.
Current or future legislation, regulations and developments may curtail production and demand for hydrocarbons 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 with respect to, for example, construction standards for wells intended for hydraulic fracturing, certifications concerning the conduct of hydraulic fracturing operations, management of flowback waters from hydraulic fracturing operations, or other measures intended to prevent operational hazards. 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 actions 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 laws or regulations or any other governmental proposals or responses will ultimately occur, and accordingly, we are unable to assess the potential financial or operational impact they may have 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.


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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.
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.
Over one-half of the Company’s revenue and profit before tax are attributable to North America.
During the year ended December 31, 2012, over one-half of our revenue and 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:

North America:
  
Houston, Pasadena, Tomball, and The Woodlands, Texas; Barnsdall, Broken Arrow, Claremore, Tulsa and Sand Springs, Oklahoma; Bossier City, Broussard, and Lafayette, Louisiana.
Latin America:
  
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 include locations in Houston, Texas and Barnsdall, Oklahoma.
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 11 of the Notes to Consolidated Financial Statements in Item 8 herein.



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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.
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 4, 2013, there were approximately 188,800 stockholders and approximately 10,800 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, 2012, and information regarding dividends declared on our common stock during the two years ended December 31, 2012, see Note 14 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 2012.
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, 2012
3,268

 
$
44.73

 

 
$

 
3,268

 
$

November 1-30, 2012
553

 
41.91

 

 

 
553

 

December 1-31, 2012

 

 

 

 

 

Total
3,821

 
$
44.32

 

 
$

 
3,821

 
$
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 2012 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 2012, 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

 
2007
 
2008
 
2009
 
2010
 
2011
 
2012
Baker Hughes
$
100.00

 
$
39.96

 
$
51.28

 
$
73.37

 
$
63.08

 
$
53.73

S&P 500 Index
100.00

 
63.06

 
79.70

 
91.68

 
93.63

 
108.55

S&P 500 Oil and Gas Equipment and Services Index
100.00

 
40.83

 
65.41

 
91.07

 
80.49

 
80.52

* 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, 2007 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)
2012 (1)

 
2011 (1)

 
2010 (1)

 
2009
 
2008
Revenue
$
21,361

 
$
19,831

 
$
14,414

 
$
9,664

 
$
11,864

Operating income (2)
2,192

 
2,600

 
1,417

 
732

 
2,376

Non-operating expense, net
(210
)
 
(261
)
 
(135
)
 
(121
)
 
(57
)
Income before income taxes
1,982

 
2,339

 
1,282

 
611

 
2,319

Income taxes (3)
(665
)
 
(596
)
 
(463
)
 
(190
)
 
(684
)
Net income
1,317

 
1,743

 
819

 
421

 
1,635

Net (income) loss attributable to noncontrolling interests
(6
)
 
(4
)
 
(7
)
 

 

Net income attributable to Baker Hughes
$
1,311

 
$
1,739

 
$
812

 
$
421

 
$
1,635

Per share of common stock:
 
 
 
 
 
 
 
 
 
Net income attributable to Baker Hughes:
 
 
 
 
 
 
 
 
 
Basic
$
2.98

 
$
3.99

 
$
2.06

 
$
1.36

 
$
5.32

Diluted
2.97

 
3.97

 
2.06

 
1.36

 
5.30

Dividends
0.60

 
0.60

 
0.60

 
0.60

 
0.56

Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Cash, cash equivalents and short-term investments
$
1,015

 
$
1,050

 
$
1,706

 
$
1,595

 
$
1,955

Working capital (current assets minus current liabilities)
6,293

 
6,295

 
5,568

 
4,612

 
4,634

Total assets
26,689

 
24,847

 
22,986

 
11,439

 
11,861

Long-term debt
3,837

 
3,845

 
3,554

 
1,785

 
1,775

Total equity
17,268

 
15,964

 
14,286

 
7,284

 
6,807

Notes To Selected Financial Data
(1)
We acquired BJ Services on April 28, 2010, and accordingly, the financial results of BJ Services are included only from the date of acquisition.
(2)
Operating income for 2011 includes a charge of $315 million before-tax ($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 7 of the Notes to Consolidated Financial Statements in Item 8 herein.
(3)
Income taxes for 2011 include a tax benefit of $214 million associated with the reorganization of certain foreign subsidiaries. For further discussion, see Note 3 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 businesses, including downstream refining, and process and pipeline 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 2012, we generated revenue of $21.36 billion, an increase of $1.53 billion or 8% compared to 2011. North America oilfield revenue for 2012 was $10.84 billion, an increase of 5% compared to 2011. Oilfield revenue outside of North America was $9.30 billion, an increase of 11% compared to 2011. Industrial Services and Other revenue was $1.22 billion, an increase of 7% compared to 2011. These increases are primarily due to increases in activity for our product lines outside of pressure pumping in North America, driven by oil-directed drilling mainly in unconventional reservoirs, activity improvements in the Gulf of Mexico, and increased activity in our international markets, particularly the Middle East, Latin America and Africa.
Net income attributable to Baker Hughes was $1.31 billion for 2012 compared to $1.74 billion for 2011. Profitability in North America was adversely impacted by the volatility experienced within our pressure pumping product line related to both pricing pressure, as a result of the increasing supply of pressure pumping capacity in the market, and increased personnel and raw material costs. Our other product lines in the U.S., particularly drilling services, upstream chemicals, artificial lift and completions, experienced increased demand in 2012. International profitability increased in 2012 compared to 2011, driven primarily by the activity increases described above in the Middle East and Africa as well improved profitability in Europe and Russia Caspian.
As of December 31, 2012, Baker Hughes had approximately 58,800 employees compared to approximately 57,700 employees as of December 31, 2011.
BUSINESS ENVIRONMENT
In North America, customer spending decreased in 2012 compared to 2011, resulting in a 1% decrease in the North America rig count. Natural gas-directed drilling activity decreased 36% in 2012 compared to 2011 as a warm winter and increased production in unconventional natural gas shale basins contributed to high natural gas working inventories and ultimately lower commodity prices. This was largely offset by a 28% increase in oil-directed drilling in 2012 compared to 2011, as high oil prices during the year supported increased rig activity. In the U.S., customer spending in the natural gas shale basins declined throughout 2012 due to low natural gas prices, resulting in a 37% reduction in natural gas-directed rig activity in 2012 compared to 2011. This was offset by a 38% increase in oil-directed rig activity for the same time period. In Canada, low natural gas prices and high oil price differentials primarily due to constrained refinery and pipeline capacity resulted in reduced customer spending. These issues ultimately resulted in a 13% reduction in Canadian rig activity in 2012 compared to 2011.


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Outside of North America, customer spending is most heavily influenced by Brent oil prices. On average, Brent oil prices were flat in 2012 compared to 2011. During 2012, upward pricing pressure resulting from geopolitical tensions in the Middle East was offset by weak European demand caused by Europe's economic downturn, uncertainty regarding future economic growth in China and increasing global oil supplies. Despite overall flat oil prices, our customers’ activity and spending levels increased moderately in 2012 compared to 2011. Due to the long-term planning cycles associated with many international projects, customers do not tend to react to short-term movements in oil prices. As a result, the international rig count grew by 6% in 2012 compared to 2011, with the largest gains seen in the Middle East and Africa. Excluding Iraq, which Baker Hughes resumed publishing in June 2012, the international rig count grew by 2%.
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.

 
2012
 
2011
 
2010
Brent oil prices ($/Bbl) (1)
$
111.96

 
$
111.05

 
$
79.73

WTI oil prices ($/Bbl) (2)
94.12

 
95.08

 
79.51

Natural gas prices ($/mmBtu) (3)
2.76

 
3.99

 
4.37

(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 $111.96/Bbl in 2012. Brent oil prices fluctuated throughout the year, with the highest prices being seen in the first quarter as geopolitical disputes in the Middle East and Africa reduced output and threatened future production. Prices fell sharply in May and June as global oil supplies rose and economic concerns increased in Europe and China. Brent oil prices rebounded in July back above $100/Bbl, where they remained for the rest of the year, as geopolitical tensions increased in the Middle East. Overall, prices ranged from a high of $126.65/Bbl in February 2012 to a low of $88.74/Bbl in June 2012. The International Energy Agency (“IEA”) estimated in its January 2013 Oil Market Report that worldwide demand would increase 0.9 million barrels per day, or 1%, to 90.8 million barrels per day in 2013, up from 89.9 million barrels per day in 2012.
WTI oil prices averaged $94.12/Bbl in 2012. Similar to Brent oil prices, WTI oil prices fluctuated throughout the year, with the highest prices being recorded early in the year, followed by a steep decline mid-year. Prices later rebounded in the third quarter. Overall, WTI oil prices ranged from a high of $109.49/Bbl in February 2012 to a low of $77.69/Bbl in June 2012.
In North America, natural gas prices, as measured by the Henry Hub Natural Gas Spot Price, averaged $2.76/mmBtu in 2012. Natural gas prices, which declined sharply in late 2011, remained low throughout much of 2012 due to strong natural gas production levels, particularly in the unconventional natural gas shale plays in North America. Natural gas prices declined throughout the first quarter and bottomed early in the second quarter following a mild winter across much of the U.S. and Canada. Prices later increased due to a hotter than normal summer and colder than normal fall in the key consuming areas of the U.S. However, prices started to fall in December as temperatures were warmer than normal, and natural gas storage injections remained high despite a 13 year low in the U.S. natural gas rig count. Overall, natural gas prices ranged from a low of $1.84/mmBtu in April 2012 to a high of $3.77/mmBtu in November 2012. According to the U.S. Department of Energy (“DOE”), working natural gas in storage at the end of 2012 was 3,517 Bcf, which was 1% or 45 Bcf above the corresponding week in 2011.
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. We believe the counting process and resulting data is reliable;


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however, it is subject to our ability to obtain accurate and timely information. Rig counts are compiled weekly for the U.S. and Canada and monthly for all international rigs. Published international rig counts do not include rigs drilling in certain locations, such as Russia, the Caspian, Iran and onshore China because this information is not readily available. Baker Hughes resumed publication in June 2012 of the rig count in Iraq for the first time since August 1990.
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.
The rig counts are summarized in the table below as averages for each of the periods indicated.

 
2012

 
2011

 
2010

U.S. - land and inland waters
1,871

 
1,846

 
1,514

U.S. - offshore
47

 
32

 
31

Canada
364

 
418

 
348

North America
2,282

 
2,296

 
1,893

Latin America
423

 
424

 
383

North Sea
40

 
38

 
43

Continental Europe
79

 
80

 
51

Africa
96

 
78

 
83

Middle East
356

 
291

 
265

Asia Pacific
241

 
256

 
269

Outside North America
1,235

 
1,167

 
1,094

Worldwide
3,517

 
3,463

 
2,987

2012 Compared to 2011
The rig count in North America decreased 1% in 2012 compared to 2011 as natural gas-directed rig counts declined 36%, largely offset by an increase in oil-directed rig counts of 28%. The natural gas-directed rig count reflected a 37% decrease in the U.S. and a 27% decrease in Canada. The oil-directed rig count increased 38% in the U.S., but was slightly offset by a 6% decrease in Canada. Natural gas-directed drilling was negatively impacted by the continued weakness in North America natural gas prices which discouraged new investment in natural gas fields. The growth in oil-directed drilling in the U.S. was primarily a result of strong oil prices and the industry’s ability to apply drilling and completion techniques to unconventional oil reservoirs that were originally applied to similar natural gas reservoirs. In Canada, many operators curtailed their drilling plans in the second half of 2012 due to reduced cash flows from natural gas activities and high oil price differentials as compared to WTI. Overall, Canada rig counts declined 13% in 2012 compared to 2011.
Outside North America, the rig count increased 6% in 2012 compared to 2011. Starting June 2012, the Middle East rig count included Iraq. Excluding Iraq, which had an average of 43 rigs in 2012, the international rig count increased 2%. The rig count in Latin America was relatively flat as increased rig activity in Mexico and Ecuador was offset by reductions in Colombia and Venezuela. The rig count in Europe was also flat, with gains in the North Sea due to higher activity in the U.K. offset by reductions in Continental Europe. In Africa, the rig count increased primarily due to the resumption of drilling activities in Libya, as well as higher activity in Algeria. The rig count increased in the Middle East due to higher activity in Saudi Arabia, Oman and Abu Dhabi, as well as the inclusion of Iraq. In Asia Pacific, the rig count decreased as a result of decreased activity in Indonesia and offshore China, partially offset by increased activity in Malaysia and Australia.


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RESULTS OF OPERATIONS
The discussions below relating to significant line items from our consolidated statements of income 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. 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.
We conduct our business through operating segments that are aligned with our geographic regions, which have been aggregated into five reportable segments. Prior to 2012, our reservoir development services business (“RDS”), consisting of consulting services provided to third parties and internal support to our oilfield operations, was included within the Industrial Services and Other segment. In the first quarter of 2012, we changed our reporting structure to include RDS within our four oilfield geographic segments, and accordingly, all prior period segment disclosures for revenue and profit before tax have been reclassified. The impact of these changes to the Industrial Services and Other segment was to reduce revenue by $108 million and $92 million for the year ended December 31, 2011 and 2010, respectively; and increase profit before tax by $42 million and $28 million for the year ended December 31, 2011 and 2010, respectively.
Revenue and Profit Before Tax
The performance of our segments is evaluated based on profit before tax, which is defined as income before income taxes and before the following: net interest expense, corporate expenses, and certain gains and losses not allocated to the segments.
2012 Compared to 2011

 
Year Ended December 31,
 
 
  
2012
 
2011
 
$ Change
 
% Change
Revenue:
 
 
 
 
 
 
 
North America
$
10,836

 
$
10,279

 
$
557

 
5
 %
Latin America
2,399

 
2,190

 
209

 
10
 %
Europe/Africa/Russia Caspian
3,634

 
3,372

 
262

 
8
 %
Middle East/Asia Pacific
3,275

 
2,852

 
423

 
15
 %
Industrial Services and Other
1,217

 
1,138

 
79

 
7
 %
Total
$
21,361

 
$
19,831

 
$
1,530

 
8
 %
 
Year Ended December 31,
 
 
  
2012
 
2011
 
$ Change
 
% Change
Profit Before Tax:
 
 
 
 
 
 
 
North America
$
1,268

 
$
1,908

 
$
(640
)
 
(34
)%
Latin America
197

 
223

 
(26
)
 
(12
)%
Europe/Africa/Russia Caspian
586

 
336

 
250

 
74
 %
Middle East/Asia Pacific
313

 
310

 
3

 
1
 %
Industrial Services and Other
131

 
95

 
36

 
38
 %
Total Operations
2,495

 
2,872

 
(377
)
 
(13
)%
Corporate and Other
(513
)
 
(533
)
 
20

 
(4
)%
Total
$
1,982

 
$
2,339

 
$
(357
)
 
(15
)%


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Revenue for 2012 increased $1.53 billion, or 8%, compared to 2011, with growth coming from all operating segments. Revenue growth in North America was driven by increased demand in the U.S. for product lines other than pressure pumping and increased activity in deepwater drilling in the Gulf of Mexico. International revenue increased primarily as a result of increased activity in the Middle East, Latin America and Africa.
Profit before tax from operations for 2012 decreased $377 million, or 13%, compared to 2011. Despite the increase in revenue, our profit before tax was significantly impacted by reduced prices, increased raw material expenses and higher personnel costs in our pressure pumping product line in North America. Additional provisions for doubtful accounts in Latin America and high operating costs and third party expenses related to new integrated operations contracts in the Middle East impacted profits in the Latin America and Middle East/Asia Pacific (“MEAP”) segments. The Europe/Africa/Russia Caspian (“EARC”) segment experienced improved profitability driven by increased activity throughout the entire geographic region as well as improved market conditions in Africa. In 2012, we incurred a charge of $43 million before-tax related to the impairment of certain information technology assets primarily associated with internally developed software and other assets, and a charge of $20 million before-tax related to the closure of a chemical manufacturing facility in the U.K. As our information technology and supply chain organizations support our global operations, these charges have been allocated to all segments. In 2011, profit before tax includes a charge of $315 million related to the impairment of trade names. For further discussion of the trade name impairments see Note 7. Goodwill and Intangible Assets. The amount of the trade name impairment charge recorded by segment was as follows: North America - $105 million; Latin America - $64 million; Europe/Africa/Russia Caspian - $48 million; Middle East/Asia Pacific - $47 million; and Industrial Services and Other - $51 million.
North America
North America revenue increased 5% in 2012 compared to 2011, despite rig counts declining 1%. The primary catalysts for the revenue growth in North America include sustained high oil prices during 2012 compared to historical prices and new innovative technologies for drilling and completion systems and wireline services that have resulted in increased revenue, particularly in the unconventional reservoirs in U.S. Land and deepwater of the Gulf of Mexico. Additionally, the continuing shift of drilling activities from the natural gas-directed unconventional reservoirs to the oil-directed reservoirs in U.S. Land resulted in significant increases in activity particularly for our production product lines, artificial lift and upstream chemicals. In the Gulf of Mexico, revenue increased 32% in 2012 compared to 2011 as rig counts increased 47%, driven primarily by increased deepwater activity. These increases in revenue were offset by reduced demand and pricing in our pressure pumping product line in the U.S. and Canada primarily due to an oversupply of pressure pumping capacity in the industry. Additionally, as a result of reduced customer spending in Canada, oil-directed rig counts decreased 6% and natural gas-directed rig counts were down 27% compared to 2011. Overall, this resulted in a 10% reduction in our Canadian revenue during 2012 compared to 2011.
North America profit before tax was $1.27 billion in 2012, a decrease of $640 million, or 34%, compared to 2011. Despite higher revenue, profits in U.S. Land and Canada were impacted significantly by decreased fleet utilization and lower pricing, higher personnel costs, increased costs for critical raw materials, and higher depreciation expenses primarily in our pressure pumping product line. Profit before tax in Canada was further impacted by the reduced customer spending. These reductions were partially offset by increased activity by our U.S. Land product lines other than pressure pumping and improved profits in the Gulf of Mexico, where both revenue and profit margins have returned to pre-moratorium levels as activity has increased substantially. During 2012, deepwater drilling activity increased significantly compared to shelf drilling activity. The shift from shelf activity to deepwater activity led to a favorable change in sales mix to products and services with higher margins. The improved margins in drilling and wireline services in the deepwater resulted in a significant increase in profits in the Gulf of Mexico during 2012 compared to 2011. North America profit before tax in 2012 was negatively impacted by a $33 million charge associated with the information technology expenses and the facility closure, while 2011 profit before tax was impacted by the trade name impairment charge discussed previously.
Latin America
Latin America revenue increased 10% in 2012 compared to 2011. The primary driver was higher activity benefiting our drilling services, artificial lift, completion systems and pressure pumping product lines in Brazil and


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the Andean region, improved pricing and increased activity in the pressure pumping product line in Argentina and higher land activity in Mexico.
Latin America profit before tax decreased 12% in 2012 compared to 2011. Despite the increase in revenue, profits were negatively impacted by an increase of $85 million in our allowance for doubtful accounts and higher personnel costs. Latin America profit before tax in 2012 was also negatively impacted by a $7 million charge associated with the information technology expenses and the facility closure, while 2011 profit before tax was impacted by the trade name impairment charge discussed previously.
In February 2013, Venezuela's currency was devalued from the prior exchange rate of 4.3 Bolivars Fuertes per U.S. Dollar to 6.3 Bolivars Fuertes per U.S. Dollar to apply to our local currency denominated balances and transactions. We estimate the impact of this devaluation to be a loss of approximately $25 million, which will be recorded in the first quarter of 2013. Going forward, although this devaluation will result in a reduction in the U.S. Dollar reported amount of local currency denominated revenues and expenses, we do not believe the impact will be material to our consolidated financial statements.
Europe/Africa/Russia Caspian
EARC revenue increased 8% in 2012 compared to 2011. Strong growth was seen in Africa, particularly with drilling systems in Mozambique and Nigeria, completion systems in Nigeria and Angola, wireline services in Nigeria, Uganda and Angola and resumed operations in Libya. Revenue increases in Africa were augmented by increases in our Europe region due primarily to increased wireline services activity in Norway, the U.K. and Eastern Mediterranean as well as increased drilling fluids activity in the U.K. and Eastern Mediterranean. Revenue also increased in Russia, with sizable growth in our artificial lift, drilling services and drilling fluids product lines.
EARC profit before tax increased 74% in 2012 compared to 2011. A favorable change in sales mix in Russia and Sub Sahara Africa, particularly in Uganda and Angola, as well as increased activity in Mozambique, Nigeria and Libya contributed to improved margins and increased profitability. The activity gains in Europe further increased profitability for 2012. EARC profit before tax in 2012 was negatively impacted by a $11 million charge associated with the information technology expenses and the facility closure. In 2011, EARC profit before tax was negatively impacted by a $70 million charge associated with the cessation of operations due to civil unrest in Libya in addition to the trade name impairment charge discussed previously.
Middle East/Asia Pacific
MEAP revenue increased 15% in 2012 compared to 2011. The increase in this segment was attributable to significant growth for our completions systems, drilling services and drilling fluids product lines in Saudi Arabia, as well as new integrated operations contracts and increased wireline services and upstream chemicals activity in Iraq. In Asia Pacific, increased activity, particularly for completions systems in Australia and pressure pumping in Malaysia and Thailand, was partially offset by reduced activity for pressure pumping and drilling fluids in India.
MEAP profit before tax remained relatively flat in 2012 compared to 2011. While revenue increased, profit before tax was impacted by high operating and third party costs associated with the new integrated operations activities in Iraq and increased personnel costs. In 2012, MEAP profit before tax was also negatively impacted by a $10 million charge associated with the information technology expenses and the facility closure, while 2011 profit before tax was impacted by the trade name impairment charge discussed previously.
Industrial Services and Other
For Industrial Services and Other, revenue increased 7% and profit before tax increased 38% in 2012 compared to 2011. The increase in revenue was primarily driven by increased demand for our process and pipeline business and downstream chemical products in North America. The increase in profit before tax in 2012 compared to 2011 is mainly attributable to the $51 million trade name impairment charge recorded in 2011, which did not recur in 2012. Industrial Services and Other profit before tax in 2012 was negatively impacted by a $2 million charge associated with the information technology expenses and the facility closure.


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2011 Compared to 2010

 
Year Ended December 31,
 
 
  
2011
 
2010
 
$ Change
 
% Change
Revenue:
 
 
 
 
 
 
 
North America
$
10,279

 
$
6,642

 
$
3,637

 
55
 %
Latin America
2,190

 
1,576

 
614

 
39
 %
Europe/Africa/Russia Caspian
3,372

 
3,050

 
322

 
11
 %
Middle East/Asia Pacific
2,852

 
2,267

 
585

 
26
 %
Industrial Services and Other
1,138

 
879

 
259

 
29
 %
Total
$
19,831

 
$
14,414

 
$
5,417

 
38
 %
 
Year Ended December 31,
 
 
  
2011
 
2010
 
$ Change
 
% Change
Profit Before Tax:
 
 
 
 
 
 
 
North America
$
1,908

 
$
1,146

 
$
762

 
66
 %
Latin America
223

 
74

 
149

 
201
 %
Europe/Africa/Russia Caspian
336

 
257

 
79

 
31
 %
Middle East/Asia Pacific
310

 
169

 
141

 
83
 %
Industrial Services and Other
95

 
127

 
(32
)
 
(25
)%
Total Operations
2,872

 
1,773

 
1,099

 
62
 %
Corporate and Other
(533
)
 
(491
)
 
(42
)
 
9
 %
Total
$
2,339

 
$
1,282

 
$
1,057

 
82
 %
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. We acquired BJ Services in April of 2010, and the financial results of its operations since the acquisition date are included in each of the five reportable segments. The increase in revenue is also due to the acquisition of BJ Services.
Profit before tax from operations 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 benefited 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. 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 $1.91 billion in 2011, an increase of $762 million, or 66%, 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


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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 benefiting 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.
Latin America profit before tax increased 201% 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
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 the Eastern Mediterranean; 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 remainder of the year.
EARC profit before tax increased 31% 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
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 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 83% 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 29% in 2011 compared to 2010. Industrial Services and Other profit before tax decreased 25% 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.





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Costs and Expenses
The table below details certain consolidated statement of income data and their percentage of revenue.

 
2012
 
2011
 
2010
  
$
 
%
 
$
 
%
 
$
 
%
Revenue
$
21,361

 
100
%
 
$
19,831

 
100
%
 
$
14,414

 
100
%
Cost of revenue
17,356

 
81
%
 
15,264

 
77
%
 
11,184

 
78
%
Research and engineering
497

 
2
%
 
462

 
2
%
 
429

 
3
%
Marketing, general and administrative
1,316

 
6
%
 
1,190

 
6
%
 
1,250

 
9
%
Cost of Revenue
Cost of revenue as a percentage of revenue was 81% and 77% for 2012 and 2011, respectively. The increase in cost of revenue as a percentage of revenue was due primarily to lower pricing and higher costs with respect to our pressure pumping product line in North America, start-up and third party costs associated with the new integrated operations activities in Iraq, as well as increased amortization expense. In 2012, we recorded charges totaling $85 million to increase our allowance for doubtful accounts in Latin America and a charge of $20 million related to the closure of a chemical manufacturing facility as part of our supply chain cost saving initiative.
Cost of revenue as a percentage of revenue 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 remainder of the year.
Research and Engineering
Research and engineering expenses increased 8% in both 2012 and 2011 when compared to the corresponding previous year. The increase in research and engineering expenses was driven by the ramp-up of activity and staffing at our technology centers in Brazil and Saudi Arabia, which opened in the fourth quarter of 2011. Additionally, research and engineering expenses were impacted by increasing material costs and higher material usage related to research and development activities. We continue to be committed to developing and commercializing new technologies as well as investing in our core product offering.
Marketing, General and Administrative
Marketing, general and administrative (“MG&A”) expenses increased 11% in 2012 compared to 2011. The increase in MG&A expenses was primarily due to a charge of $43 million related to the impairment of certain information technology assets primarily associated with internally developed software and other assets. In addition to these costs, the increase in MG&A expenses resulted from ongoing activities to further improve productivity and efficiency through the coordination and integration of our worldwide operations, including software implementations and enhancements, partially offset by decreased personnel costs.
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 realized through the continued integration of BJ Services into our operations.
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.


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Interest Expense, net
Interest expense, net of interest income, decreased $11 million in 2012 compared to 2011. The decrease was primarily due to the repayment of our 5.75% notes in the second quarter of 2011, the early extinguishment in the third quarter of 2011 of our 6.5% senior notes due in November 2013 and the increase in capitalized interest in 2012 associated with the increase in our capital expenditures. The decrease in interest expense was partially offset by the issuance of $750 million 3.2% senior notes in August 2011, the inception of two capital leases in the second and third quarters of 2011 for pumping vessels and increased borrowings under our commercial paper program in 2012.
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 of debt in the second and third quarters of 2011, respectively.
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 $665 million, $596 million and $463 million for 2012, 2011 and 2010, respectively. Income tax expense in 2011 includes a $214 million tax benefit associated with the reorganization of certain foreign subsidiaries. Excluding the impact of the reorganization in 2011, our effective tax rate on operating profits in 2012, 2011, and 2010 was 33.6%, 34.6% and 36.1%, respectively. The 2012 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 and adjustments to prior years' tax positions partially offset by state income taxes. 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.
On January 2, 2013, the retroactive extension of the research and development credit and other favorable tax benefits were enacted as part of the American Taxpayer Relief Act of 2012. We are currently evaluating the financial impact of this legislation. We expect to record a discrete benefit in the first quarter of 2013 for the 2012 full year impact, and we expect to record the 2013 benefit throughout the year 2013 as a decrease in the annual effective tax rate.
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


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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.
The primary drivers expected to impact the 2013 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. The outlook for 2013 is one of gradual strengthening of economic activity amidst ongoing concerns fueled by sovereign debt issues in Europe, a slowdown in the Chinese economy, and the moderate rate of the economic growth in the U.S. The European sovereign debt crisis and the reduction in economic activity have impacted the economies of major exporters, including the U.S. and China. Although steps have been taken by governments to resolve this issue, the crisis in the Euro area remains a threat to the global economic outlook. 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. While China's growth rate slowed down sharply in 2012, activity is expected to pick up in 2013 in response to measures supporting domestic demand. 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, and the expectation is for only modest economic growth in the U.S. throughout 2013. However, this growth may be hampered by weakness or further deterioration of the global economy, particularly in China and Europe.
Demand for Hydrocarbons - In its January 2013 Oil Market Report, the IEA said that it expects global demand for oil to increase 0.9 million barrels per day in 2013. This expected increase in demand for oil, mainly driven by countries outside the OECD, should support higher expenditures within the oil and gas sector. In addition, natural gas is an increasingly important hydrocarbon to meet the world's energy needs. In its January 2013 Short-Term Energy Outlook, the EIA stated that U.S. natural gas demand would be 69.7 billion cubic feet per day in 2013, which is unchanged from 2012.
Oil Production - The EIA January 2013 Short-Term Energy Outlook projects non-OPEC production to increase by 1.4 million barrels per day in 2013 over 2012. This increase is largely due to continued production growth from U.S. tight oil formations and Canadian oil sands, fostered by sustained higher oil prices. Global OPEC surplus capacity, overwhelmingly concentrated in Saudi Arabia, is anticipated to increase from approximately 0.8 million barrels per day to 3.1 million barrels per day in 2013. At the same time, OPEC production is anticipated to fall by 0.6 million barrels per day in 2013 to approximately 30 million barrels per day. While significant investments are expected to be required to support increases in production capacity, price volatility driven by global economic and geopolitical uncertainties may lead to delays in operator investment decisions across the rest of the world.
Natural Gas Production - Worldwide natural gas production continues to grow. Despite this overall trend, low natural gas prices in North America have resulted in a reduction in the natural gas-directed rig and completion activity in this region. This began to impact North America natural gas production in 2012, resulting in a gradual increase in Henry Hub spot gas prices in the second half of 2012, but a relatively mild winter season in key consuming regions in the U.S. has pressured natural gas prices downward since November 2012. Overall, worldwide natural gas production will, however, tend to be more stable as high natural gas prices in places such as Europe and Asia encourage sustained global growth of natural gas production. In addition, the announced shift away from nuclear power generation by several countries and the development of natural gas projects in the OECD outside North America is expected to further support natural gas prices.
Oil Prices - With WTI oil prices trading between $77.69/Bbl and $109.49/Bbl, and Brent trading between $88.74/Bbl and $126.65/Bbl during 2012, we believe most oil developments globally will continue to provide adequate returns to encourage incremental investment. New midstream infrastructure in the U.S. is expected during 2013 which should help to narrow the price gap between WTI and Brent. Based on oil supply forecasts and modest anticipated economic growth globally, we would expect oil prices to remain relatively strong throughout 2013 barring any major macro-economic events.
Natural Gas Prices - With natural gas prices trading between $1.84/mmBtu and $3.77/mmBtu during 2012, which are particularly low when compared to oil on a Btu equivalent basis, we believe that the economics of


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most dry natural gas-directed investments in North America have become marginal. This is primarily due to the abundant supplies available from the unconventional plays in North America, including natural gas produced in association with unconventional oil wells, which is expected to remain high in 2013. The EIA said in its January 2013 Short-term Energy Outlook that working natural gas inventories remain at near record high levels. The EIA, however, expects natural gas prices in North America to increase to an average of $3.74/mmBtu in 2013 as a result of the reduction in natural gas-directed drilling activity.
Activity and Spending Outlook for North America - Overall customer spending in North America is expected to increase in 2013 compared to 2012, but the average annual rig count is expected to remain close to the levels in the fourth quarter of 2012, in part reflecting improved efficiencies in drilling performance. The slowdown in the spending directly related to natural gas development has been largely offset by incremental investment to develop unconventional plays with crude oil and natural gas liquids content. In the unconventional dry gas plays, while investment declined throughout most of 2012 due to historically low natural gas pricing levels, the rig count for gas drilling stabilized in the fourth quarter of 2012 as gas prices have rebounded moderately. Overall service intensity has increased in North America during the year as customers are demanding key technologies, such as advanced directional drilling, more complex completion systems and pressure pumping to develop the unconventional plays with liquids content. Despite this increase in demand, however, pricing has declined in some basins, particularly for hydraulic fracturing where current pressure pumping capacity exceeds demand. This pricing pressure is expected to continue into early 2013. In the Gulf of Mexico, the active rig count has increased to near pre-moratorium levels. Activity on the continental shelf has been strong, and there has been a steady increase in the granting of new deepwater permits. It is expected that exploration drilling as well as completions and development activity in the Gulf of Mexico will continue to increase throughout 2013, with additional deepwater rigs being added. In Canada, overall rig activity in 2013 is expected to decline approximately 8% compared to 2012.
Activity and Spending Outlook Outside North America - International activity is driven primarily by the price of oil, which is currently high enough to provide attractive economic returns in almost every region and to support some major gas export projects. Customers are expected to increase spending to develop new resources and offset declines from existing developed reserves, increasingly relying on higher technology services to support exploration and production activities in deep water, heavy or viscous oils and tight reservoirs. Areas that are expected to see increased spending in 2013 include: the Middle East, in particular Iraq, including the Kurdistan province, and Saudi Arabia; and Latin America, with the largest growth expected in Mexico, Brazil and Colombia. Within Southeast Asia, there is an increased focus on exploring and developing indigenous oil and natural gas resources to meet rapid local demand growth rather than the historic role of meeting exports. In Africa, traditional growth areas such as Angola and Nigeria are being augmented by new provinces such as Ghana, Uganda and Mozambique. Russia is striving to maintain 10 million barrels of oil per day until the end of the decade by investing in Eastern Siberia and eventually in the Arctic offshore. Efforts in Russia at developing tight oil using vertical drilling are already underway with potential for pilot projects in 2013 and beyond for more complex horizontal drilling and completions. Australia is leading the expansion of export liquefied natural gas (“LNG”) projects, requiring conventional offshore gas drilling in the northwest shelf as well as coal bed methane operations onshore Queensland. While overall unconventional drilling outside North America is still at its infancy, activities in Australia, China, Saudi Arabia and Argentina are showing early promise, with active interest at ministry and national oil company level in defining unconventional resource potential in almost all countries with active oil and natural gas industries. The globalization of natural gas trade via rapid expansion in LNG as well as major gas pipelines will spur drilling for natural gas in all regions, but most specifically for the fast growing Asian energy markets.
Capital Expenditures - Our capital expenditures, excluding any potential acquisitions, are expected to be approximately $2.0 billion, a reduction of approximately 30% compared to 2012. The reduction in 2013 is primarily related to pressure pumping horsepower and infrastructure spending in North America. 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 19 of the 40 countries having the lowest scores in the Transparency International’s Corruption Perception Index survey for 2012, 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


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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 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.
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 in audits of certain countries. 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, 2012, we had cash and cash equivalents of $1.02 billion, of which substantially all was held by foreign subsidiaries. A substantial portion of the cash held by foreign subsidiaries at December 31, 2012 was reinvested in our international operations as our intent is to use this cash to, among other things, fund the


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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 have a $2.5 billion committed revolving credit facility with commercial banks and a commercial paper program under which we may issue up to $2.5 billion. The maximum combined borrowing at any time under both the credit facility and the commercial paper program is $2.5 billion. At December 31, 2012, we had commercial paper outstanding of $925 million; therefore, the amount available for borrowing under the facility as of December 31, 2012 was $1.575 billion. 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 2012, we used cash to pay for a variety of activities including working capital needs, capital expenditures, and payment of dividends.
Cash Flows
Cash flows provided (used) by type of activity were as follows for the years ended December 31:

(In millions)
2012
 
2011
 
2010
Operating activities
$
1,835

 
$
1,507

 
$
856

Investing activities
(2,521
)
 
(1,891
)
 
(2,376
)
Financing activities
646

 
(30
)
 
1,366

Operating Activities
Cash flows from operating activities provided $1.84 billion and $1.51 billion for the year ended December 31, 2012 and 2011, respectively. Cash flows from operating activities increased $328 million in 2012 primarily due to the change in net operating assets and liabilities, which used less cash in 2012 compared to 2011.
The underlying drivers in 2012 compared to 2011 of the changes in operating assets and liabilities are as follows:
The change in accounts receivable provided cash of $16 million and used cash of $1.02 billion in 2012 and 2011, respectively. The slight change in accounts receivable in 2012 was primarily due to improved collections over the prior year partially offset by an increase in activity. The change in accounts receivable in 2011 was primarily due to an increase in activity as well as an increase in days sales outstanding (defined as the average number of days our net trade receivables are outstanding based on quarterly revenue) due to temporary invoicing delays resulting from the implementation of our enterprise wide software system for BJ Services in North America.
An increase in inventory used cash of $547 million and $641 million in 2012 and 2011, respectively, driven by an increase in activity levels.
Accrued employee compensation and other accrued liabilities used cash of $90 million and provided cash of $58 million in 2012 and 2011, respectively. The net change of $148 million was due primarily to an increase in payments related to employee bonuses earned in 2011 but paid in 2012 coupled with lower employee compensation accruals in 2012.
Income taxes payable used cash of $56 million and $121 million in 2012 and 2011, respectively. The change of $65 million was primarily due to a decrease in income taxes paid in 2012 compared to 2011.
Other operating items used cash of $213 million and $19 million in 2012 and 2011, respectively. The net
change of $194 million was primarily due to an increase in payments for prepaid assets in line with increased activity and an increase in contributions to our pension plans.
Cash flows from operating activities provided $1.51 billion and $856 million for the year ended December 31, 2011 and 2010, respectively. 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.
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 cash of $58 million in 2011 and used cash of $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.
Investing Activities
Our principal recurring investing activity is 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 $2.91 billion, $2.46 billion and $1.49 billion for 2012, 2011 and 2010, 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 $389 million, $311 million and $208 million for 2012, 2011 and 2010, respectively. These disposals related to equipment that was lost-in-hole; and property, machinery, and equipment no longer used in operations that was 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.
Financing Activities
We had net borrowings of commercial paper and other short-term debt of $847 million, $125 million and $52 million in 2012, 2011 and 2010, respectively. In 2011, we completed a private placement of $750 million 3.2% senior notes that will mature in August 2021, resulting in net proceeds of approximately $742 million after deducting the underwriting discounts and expenses of the offering and used $563 million of the net proceeds to redeem our 6.5% notes in full. The remaining net proceeds from the senior notes were used for general corporate purposes. In addition in 2011, we repaid $250 million of our 5.75% notes that matured.
In March 2012, pursuant to a registration rights agreement, we filed a registration statement with the SEC that became effective with respect to an offer to exchange the unregistered 3.2% senior notes for substantially identical
registered notes without the existing transfer restrictions. The offer closed in May 2012 with all notes exchanged. This exchange had no impact to our financial statements or cash flows.
Total debt outstanding at December 31, 2012 was $4.92 billion, an increase of $847 million compared to December 31, 2011. The total debt to total capitalization (defined as total debt plus equity) ratio was 0.22 at December 31, 2012 and 0.20 at December 31, 2011.
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


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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.
We received proceeds of $81 million, $183 million and $74 million in 2012, 2011 and 2010, 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 2012, 2011 and 2010, 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 2012.
We paid dividends of $263 million, $261 million and $241 million in 2012, 2011 and 2010, respectively.
Available Credit Facility
At December 31, 2012, 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, 2012, we were in compliance with all of the facility’s covenants. There were no direct borrowings under the committed credit facility in 2012. We also have a 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, 2012, we had $925 million of commercial paper outstanding; therefore, the amount available for borrowing under the facility as of December 31, 2012 was $1.575 billion.
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 2013, 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 2013, we expect our capital expenditures to be approximately $2.0 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, and accordingly, we will manage our capital expenditures to match market demand. In 2013, we also expect to make interest payments of between $225 million and $240 million, based on debt levels as of December 31, 2012. We anticipate making income tax payments of between $800 million and $900 million in 2013.
We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. We anticipate paying dividends of between $263 million and $273 million in 2013; however, the Board of Directors can change the dividend policy at any time.


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For all defined benefit, defined contribution and other postretirement plans, we expect to contribute between $385 million and $420 million to these plans in 2013. See Note 10 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, 2012. 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)
$
4,945

 
$
1,079

 
$
23

 
$
23

 
$
3,820

Estimated interest payments (2)
3,438

 
225

 
445

 
436

 
2,332

Operating leases (3)
676

 
204

 
255

 
98

 
119

Purchase obligations (4)
1,482

 
496

 
711

 
261

 
14

Income tax liabilities for uncertain tax positions (5)
267

 
49

 
121

 
40

 
57

Other long-term liabilities
145

 
29

 
49

 
19

 
48

Total
$
10,953

 
$
2,082

 
$
1,604

 
$
877

 
$
6,390

(1)
Amounts represent the expected cash payments for the principal amounts related to our debt, including outstanding commercial paper of $925 million, 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 $1.5 billion at December 31, 2012. 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 as well as 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. The Audit/Ethics Committee of our Board of Directors has reviewed our critical accounting estimates and 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 make 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. We monitor our customers’ payment history and current credit worthiness to determine that collectability is reasonably assured. We also consider the overall business climate in which our customers operate. 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, 2012 and 2011, the allowance for doubtful accounts totaled $308 million, or 6%, and $229 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 $15 million in 2012.
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, 2012 and 2011, inventory reserves totaled $346 million, or 8%, and $304 million, or 9%, 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 $17 million in 2012.
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. The judgments, assumptions


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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 assessment of goodwill for impairment as of October 1 of each year for each of our reporting units, which are generally based on our regional structure. These assessments include both qualitative and quantitative factors. When necessary, we calculate the fair value of a reporting unit using different valuation techniques, including a market approach, 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 2012 assessment indicated that there were no impairments of goodwill. 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 including, 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 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


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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 consolidated statements of income 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 liabilities. We evaluate these critical assumptions at least annually, and as necessary, we utilize third party actuarial firms to assist us. 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 weighted average discount rate of 4.6% in 2012, 5.2% in 2011 and 5.9% in 2010 to determine pension expense. A 50 basis point reduction in the weighted average discount rate would have decreased income before income taxes by approximately $2 million in 2012.
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 would decrease plan assets which results in higher pension expense. We assumed a weighted average rate of return on our plan investments of 7.0% in 2012, 7.2% in 2011 and 7.1% in 2010. A 50 basis point reduction in the weighted average expected rate of return on assets of our principal plans would have decreased income before income taxes by approximately $4 million in 2012.
NEW ACCOUNTING STANDARDS UPDATES
In June 2011, the Financial Accounting Standards Board (“FASB”) issued an update to Accounting Standards Codification (“ASC”) 220, Comprehensive Income. This Accounting Standards Update (“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. We adopted the new presentation requirement in the first quarter of 2012 and are using the two-statement approach.
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


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goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We adopted this ASU effective January 1, 2012, with no impact to our consolidated financial statements.
In July 2012, the FASB issued an update to ASC 350, Intangibles - Goodwill and Other. This ASU amends the guidance in ASC 350-30 on testing indefinite-lived intangible assets for impairment. The revised guidance permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test. The ASU is effective for impairment tests performed for fiscal years beginning after September 15, 2012. We will adopt this ASU for our 2013 impairment testing and do not expect it 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, 2012.
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,” “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.
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
We are subject to interest rate risk on our debt and investment portfolio. We maintain an interest rate risk management strategy, which primarily uses a mix of fixed and variable rate debt that is intended to mitigate the risk exposure to changes in interest rates in the aggregate. 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.


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We had fixed rate long-term debt aggregating $3.8 billion at December 31, 2012 and December 31, 2011. The following table sets forth our fixed rate long-term debt and the related weighted average interest rates by expected maturity dates as of December 31, 2012 and 2011.

(In millions)
2012

 
2013
 
2014
 
2015
 
2016
 
2017

 
Thereafter
 
Total
As of December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt (1) (2)
$

 
$

 
$

 
$

 
$

 
$

 
$
3,800

 
$
3,800

Weighted average interest rates

 

 

 

 

 

 
5.72
%
 
5.72
%
As of December 31, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt (1) (2)
$

 
$

 
$

 
$

 
$

 
$

 
$
3,800

 
$
3,800

Weighted average interest rates

 

 

 

 

 

 
5.72
%
 
5.72
%
(1)
Amounts do not include any unamortized discounts or deferred issuance costs.
(2)
Fair market value of our fixed rate long-term debt was $4,684 million at December 31, 2012 and $4,611 million at December 31, 2011.
FOREIGN CURRENCY EXCHANGE RISK
We conduct our operations around the world in a number of different currencies, and we are exposed to market risks resulting from fluctuations in foreign currency exchange rates. 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, 2012 and 2011, we had outstanding foreign currency forward contracts with notional amounts aggregating $207 million and $117 million, respectively, to hedge exposure to currency fluctuations in various foreign currencies. The notional amounts of our foreign exchange contracts do not generally represent amounts exchanged by the parties and, thus are not a measure of the cash requirements related to these contracts or of any possible loss exposure. The amounts actually exchanged are calculated by reference to the notional amounts and by other terms of the derivative contracts, such as exchange rates. Based on quoted market prices as of December 31, 2012 and 2011 for contracts with similar terms and maturity dates, we recorded a loss of $1 million each year, 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 statements of income.


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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, 2012. 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 13, 2013


42


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, 2012 and 2011, and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2012. 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, 2012, 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, 2012 and 2011 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, 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, 2012, 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 13, 2013


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BAKER HUGHES INCORPORATED
CONSOLIDATED STATEMENTS OF INCOME


 
Year Ended December 31,
(In millions, except per share amounts)
2012
 
2011
 
2010
Revenue:
 
 
 
 
 
Sales
$
7,274

 
$
6,382

 
$
5,516

Services
14,087

 
13,449

 
8,898

Total revenue
21,361

 
19,831

 
14,414

Costs and expenses:
 
 
 
 
 
Cost of sales
5,758

 
5,122

 
4,359

Cost of services
11,598

 
10,142

 
6,825

Research and engineering
497

 
462

 
429

Marketing, general and administrative
1,316

 
1,190

 
1,250

Impairment of trade names

 
315

 

Acquisition-related costs

 

 
134

Total costs and expenses
19,169

 
17,231

 
12,997

Operating income
2,192

 
2,600

 
1,417

Gain on investments

 

 
6

Interest expense, net
(210
)
 
(221
)
 
(141
)
Loss on early extinguishment of debt

 
(40
)
 

Income before income taxes
1,982

 
2,339

 
1,282

Income taxes
(665
)
 
(596
)
 
(463
)
Net income
1,317

 
1,743

 
819

Net (income) loss attributable to noncontrolling interests
(6
)
 
(4
)
 
(7
)
Net income attributable to Baker Hughes
$
1,311

 
$
1,739

 
$
812

 
 
 
 
 
 
Basic earnings per share attributable to Baker Hughes
$
2.98

 
$
3.99

 
$
2.06

 
 
 
 
 
 
Diluted earnings per share attributable to Baker Hughes
$
2.97

 
$
3.97

 
$
2.06

See Notes to Consolidated Financial Statements



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BAKER HUGHES INCORPORATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


 
Year Ended December 31,
(In millions)
2012
 
2011
 
2010
Net income
$
1,317

 
$
1,743

 
$
819

Other comprehensive income (loss):
 
 
 
 
 
Foreign currency translation adjustments during the period
78

 
(44
)
 
(41
)
Pension and other postretirement benefits, net of tax (2012 - $(13); 2011 - $44; 2010 - $(5))
1

 
(92
)
 
35

Other comprehensive income (loss)
79

 
(136
)
 
(6
)
Comprehensive income
1,396

 
1,607

 
813

Comprehensive (income) loss attributable to noncontrolling interests
(6
)
 
(3
)
 
(7
)
Comprehensive income attributable to Baker Hughes
$
1,390

 
$
1,604

 
$
806

See Notes to Consolidated Financial Statements



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BAKER HUGHES INCORPORATED
CONSOLIDATED BALANCE SHEETS


 
December 31,
(In millions, except par value)
2012
 
2011
ASSETS
Current Assets:
 
 
 
Cash and cash equivalents
$
1,015

 
$
1,050

 Accounts receivable - less allowance for doubtful accounts
(2012 - $308; 2011 - $229)
4,815

 
4,878

Inventories, net
3,781

 
3,222

Deferred income taxes
266

 
251

Other current assets
540

 
396

Total current assets
10,417

 
9,797

 
 
 
 
Property, plant and equipment - less accumulated depreciation
(2012 - $6,315; 2011 - $5,251)
8,707

 
7,415

Goodwill
5,958

 
5,956

Intangible assets, net
993

 
1,143

Other assets
614

 
536

Total assets
$
26,689

 
$
24,847

LIABILITIES AND EQUITY
Current Liabilities:
 
 
 
Accounts payable
$
1,737

 
$
1,810

Short-term debt and current portion of long-term debt
1,079

 
224

Accrued employee compensation
646

 
704

Income taxes payable
226

 
289

Other accrued liabilities
436

 
475

Total current liabilities
4,124

 
3,502

 
 
 
 
Long-term debt
3,837

 
3,845

Deferred income taxes and other tax liabilities
745

 
810

Liabilities for pensions and other postretirement benefits
579

 
578

Other liabilities
136

 
148

Commitments and contingencies

 

 
 
 
 
Equity:
 
 
 
Common stock, one dollar par value (shares authorized - 750; issued and outstanding: 2012 - 441; 2011 - 437)
441

 
437

Capital in excess of par value
7,495

 
7,303

Retained earnings
9,609

 
8,561

Accumulated other comprehensive loss
(476
)
 
(555
)
Baker Hughes stockholders’ equity
17,069

 
15,746

Noncontrolling interests
199

 
218

Total equity
17,268

 
15,964

Total liabilities and equity
$
26,689

 
$
24,847

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 at December 31, 2009
$
312

 
$
874

 
$
6,512

 
 
$
(414
)
 
 
 
$

 
 
$
7,284

Comprehensive income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income
 
 
 
 
812

 
 
 
 
 
 
7

 
 
819

Other comprehensive (loss)
 
 
 
 
 
 
 
(6
)
 
 
 
 
 
 
(6
)
Issuance of common stock to acquire BJ Services
118

 
5,986

 
 
 
 
 
 
 
 
 
 
 
6,104

Activity related to stock plans
2

 
58

 
 
 
 
 
 
 
 
 
 
 
60

Stock-based compensation cost
 
 
87

 
 
 
 
 
 
 
 
 
 
 
87

Cash dividends ($0.60 per share)
 
 
 
 
(241
)
 
 
 
 
 
 
 
 
 
(241
)
Net activity related to noncontrolling interests
 
 
 
 
 
 
 
 
 
 
 
179

 
 
179

Balance at December 31, 2010
$
432

 
$
7,005

 
$
7,083

 
 
$
(420
)
 
 
 
$
186

 
 
$
14,286

Comprehensive income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income
 
 
 
 
1,739

 
 
 
 
 
 
4

 
 
1,743

Other comprehensive (loss)
 
 
 
 
 
 
 
(135
)
 
 
 
(1
)
 
 
(136
)
Activity related to stock plans
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 at December 31, 2011
$
437

 
$
7,303

 
$
8,561

 
 
$
(555
)
 
 
 
$
218

 
 
$
15,964

Comprehensive income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income
 
 
 
 
1,311

 
 
 
 
 
 
6

 
 
1,317

Other comprehensive income
 
 
 
 
 
 
 
79

 
 
 

 
 
79

Activity related to stock plans
4

 
55

 
 
 
 
 
 
 
 
 
 
 
59

Stock-based compensation cost
 
 
115

 
 
 
 
 
 
 
 
 
 
 
115

Cash dividends ($0.60 per share)
 
 
 
 
(263
)
 
 
 
 
 
 
 
 
 
(263
)
Net activity related to noncontrolling interests
 
 
22

 
 
 
 
 
 
 
 
(25
)
 
 
(3
)
Balance at December 31, 2012
$
441

 
$
7,495

 
$
9,609

 
 
$
(476
)
 
 
 
$
199

 
 
$
17,268

See Notes to Consolidated Financial Statements


47

Table of Contents                                

BAKER HUGHES INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS


 
Year Ended December 31,
(In millions)
2012
 
2011
 
2010
Cash flows from operating activities:
 
 
 
 
 
Net income
$
1,317

 
$
1,743

 
$
819

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
 
 
Depreciation and amortization
1,568

 
1,321

 
1,069

Benefit for deferred income taxes
(114
)
 
(492
)
 
(188
)
Impairment of trade names

 
315

 

Gain on disposal of assets
(222
)
 
(179
)
 
(119
)
Stock-based compensation cost