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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010


o		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 þ NO o

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

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 þ NO o

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 þ NO o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. o

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 þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(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 Exchange Act). YES o NO þ

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, 2010 reported by the New York Stock Exchange) was approximately $17,846,385,000.

As of February 18, 2011, the registrant has outstanding 434,260,224 shares of common stock, $1 par value per share.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Registrant’s Definitive Proxy Statement for the 2011 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.

PART I

ITEM 1. BUSINESS

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

AVAILABILITY OF INFORMATION FOR STOCKHOLDERS

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

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

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

Baker Hughes Incorporated
2929 Allen Parkway, Suite 2100
Houston, TX 77019-2118
Attention: Investor Relations
Telephone: (713) 439-8039

ABOUT BAKER HUGHES

Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry. We also provide industrial and other products and services to the downstream refining, and process and pipeline industries. Baker Hughes was formed 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 over 80 countries around the world and our corporate headquarters is in Houston, Texas. As of December 31, 2010, we had approximately 53,100 employees, of which approximately 58% work outside the United States.

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

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

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. We have manufacturing operations in various countries, including, but not limited to, the United States (Texas, Oklahoma and Louisiana), Canada (Calgary), Europe (Scotland, England and Germany), Latin America (Venezuela and Argentina), the Middle East (UAE and Saudi Arabia) and Asia Pacific (Thailand, China and Singapore).

On April 28, 2010, we completed the acquisition of BJ Services Company (“BJ Services”), a leading provider of pressure pumping and other oilfield services, for $6.9 billion in cash and stock. This acquisition provides us with a proven leader in the areas of pressure pumping, stimulation and fracturing and complements our existing product portfolio, allowing us to provide a full suite of products and services to meet the needs of our customers. For 2010, our results are inclusive of BJ Services results from the acquisition date through December 31, 2010. The acquired business represented approximately 46% of our consolidated total assets at December 31, 2010 and approximately 36% of our consolidated net income attributable to Baker Hughes for the year ended December 31, 2010.

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

	•		North America (Combined results for U.S. — including Gulf of Mexico, Canada, and Trinidad)

	•		Latin America (Combined results for Central and South America including Mexico and excluding Trinidad)

	•		Europe/Africa/Russia Caspian (“EARC”) (Combined results for Europe, Africa- excluding Egypt, and Russia Caspian)

	•		Middle East/Asia Pacific (“MEAP”) (Combined results for Middle East — including Egypt, and Asia Pacific)

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

Further information about our segments is set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 4 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 generally fall into one of two categories — Drilling and Evaluation or Completion and Production.

•

Drilling and Evaluation consists of drill bit systems, drilling systems, wireline systems and drilling fluids product lines.

	o		Drill bit systems — includes Tricone ^TM and PDC or “diamond” drill bits used for performance drilling, hole enlargement and coring.

	o		Drilling systems — 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.

	o		Wireline systems — 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.

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

•

Completion and Production consists of our well completion systems, wellbore intervention, intelligent production systems, artificial lift, upstream chemicals and pressure pumping services product lines.

	o		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.

	o		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.

	o		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.

	o		Artificial lift – includes electric submersible pumps 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.

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

	o		Pressure pumping services – includes cementing, stimulation 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.

Industrial Services and Other

Industrial Services and Other consists of our downstream chemicals; process and pipeline services; and stimulation chemicals. It also includes our reservoir technology and consulting group that provides consulting services and software products, including the Gaffney, Cline and Associates reservoir consulting services.

MARKETING, CONTRACTING, COMPETITION AND ECONOMIC CONDITIONS

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

Our customers include the large integrated major and super-major oil and natural gas companies, U.S. and international independent oil and gas companies, and the national oil companies. No single customer accounts for more than 10% of our business. In North America, most work is contracted and performed on a well-by-well basis. Outside North America, most work is contracted on a project-by-project basis or for an extended period of time, typically two to four years. 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 oil service companies such as Schlumberger, Halliburton and Weatherford, where the breadth of service capabilities as well as competitive position of each product line are the keys to differentiation in the market. We also compete with other companies who may participate in only a few product lines, for example, National Oilwell Varco, Champion Technologies, Inc., Nalco Holding Company, Newpark Resources, Inc., and Frac Tech Services, LLC.

Our products and services are sold in highly competitive markets, and revenues and earnings can be affected by changes in competitive 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 and 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 gas specific statutes that void any indemnity

agreement that attempts to relieve a party from liability resulting from its own negligence (“anti-indemnity statutes”). These statutes can void the allocation of liability agreed to in a contract; however, both the Texas and Louisiana anti-indemnity statutes include important exclusions. The Louisiana statute does not apply to property damage, and the Texas statute allows mutual indemnity agreements that are supported by insurance and has exclusions, which include, among other things, loss or liability for property damage that results from pollution and the cost of control of a wild well.

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

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

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

RESEARCH AND DEVELOPMENT; PATENTS

Our products and technology organization engages in research and development activities directed primarily toward the improvement of existing products and services, the design of specialized products to meet specific customer needs and the development of new products, processes and services. Our primary technology centers are located in the U.S. (Blacksburg, Virginia; Claremore, Oklahoma; 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, 2010, 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 to be adequate for the conduct of our business, and aggressively pursue protection of our patents against patent infringement worldwide. No single patent or trademark is considered to be critical to our business.

SEASONALITY

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

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

	•		In Canada, the timing and duration of the spring thaw directly affects activity levels beginning late in the first quarter and most severely in the second quarter.

	•		Hurricanes 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.

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

RAW MATERIALS

We purchase various raw materials and component parts for use in manufacturing our products. The principal materials we purchase are steel alloys (including chromium and nickel), titanium, beryllium, copper, lead, tungsten carbide, synthetic and natural diamonds, guar, 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. We have not experienced significant shortages of these materials and normally do not carry inventories of such materials in excess of those reasonably required to meet our production schedules. We do not expect significant interruptions in supply, but there can be no assurance that there will be no price or supply issues over the long term.

EMPLOYEES

On December 31, 2010, we had approximately 53,100 employees, of which the majority are outside the U.S. Less than 10% of these employees are represented under collective bargaining agreements or similar-type labor arrangements. Based upon the geographic diversification of these employees, we believe any risk of loss from employee strikes or other collective actions would not be material to the conduct of our operations taken as a whole.

EXECUTIVE OFFICERS OF BAKER HUGHES INCORPORATED

The following table shows, as of February 23, 2011, the name of each of our executive officers, together with his age and all offices presently held.


Name	Age
Chad C. Deaton		58	Chairman of the Board and Chief Executive Officer of the Company since 2004. President of the Company from 2008 to 2010. President and Chief Executive Officer of Hanover Compressor Company from 2002 to 2004. Senior Advisor to Schlumberger Oilfield Services from 1999 to 2001. Executive Vice President of Schlumberger from 1998 to 1999. Employed by the Company in 2004.

Peter A. Ragauss		53	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.

Alan R. Crain		59	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.

Martin S. Craighead		51	President since 2010 and Chief Operating Officer since 2009. 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.

Russell J. Cancilla		59	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.


Name	Age
Belgacem Chariag		48	Vice President of the Company and President Eastern Hemisphere Operations since 2009. Vice President HSE of Schlumberger Limited from May 2008 to May 2009. President of Well Services, a Schlumberger product line, from 2006 to 2008. Vice President Marketing Oilfield Services for Europe, Caspian and Africa of Schlumberger from 2004 to 2006. Various other operational and management positions at Schlumberger from 1989 to 2008. Employed by the Company in 2009.

Didier Charreton		47	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.

Alan J. Keifer		56	Vice President, Controller and Principal Accounting Officer of the Company since 1999. Western Hemisphere Controller of Baker Oil Tools from 1997 to 1999 and Director of Corporate Audit for the Company from 1990 to 1996. Employed by the Company in 1990.

Jay G. Martin		59	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		40	Vice President of the Company since December 2008. President, Products and Technology since May 2009. 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		62	Vice President of the Company since 1998 and President Western Hemisphere Operations since May 2009. President of Baker Petrolite Corporation from 2005 to May 2009. President of Baker Hughes Drilling Fluids from 2004 to 2005. Vice President, Business Process Development of the Company from 1998 to 2002; Vice President, Manufacturing, of Baker Oil Tools from 1990 to 1998 and Plant Manager of Hughes Tool Company from 1988 to 1990. Employed by the Company in 1975.

Arthur L. Soucy		48	Vice President Supply Chain of the Company since April 2009. Vice President, Global Supply Chain for Pratt and Whitney from 2007 to 2009. Sloan Fellows Program, Innovation and Global Leadership at Massachusetts Institute of Technology from 2006 to 2007. General Manager, Combustors, Augmenters and Nozzles of Pratt and Whitney from 2005 to 2006. Various managerial positions at Pratt and Whitney from 1995 to 2006. Employed by the Company in 2009.

Clifton N.B. Triplett		52	Vice President and Chief Information Officer of the Company since September 2008. Corporate Vice President, Motorola Global Services from 2007 to 2008 and Corporate Vice President and Chief Information Officer of Motorola’s Network and Enterprise Group from 2006 to 2007. Employed by General Motors from 1997 to 2006 as Global Information Systems Officer for Computing and Telecommunications Services from 2003 to 2006 and Global Manufacturing and Quality Information Systems Officer from 1997 to 2003. Employed by the Company in 2008.

There are no family relationships among our executive officers.

ENVIRONMENTAL MATTERS

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

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” or “CERCLA”) 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 United States 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 $18 million, which includes accruals of $7 million and $6 million for the various Superfund sites, at December 31, 2010 and 2009, respectively. Approximately $11 million of our total environmental accrual at December 31, 2010 relates to properties or liabilities acquired in connection with the BJ Services acquisition.

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

ITEM 1A. RISK FACTORS

An investment in our common stock involves various risks. When considering an investment in our Company, one should consider carefully 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 could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our Company.

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 or changes in the ability of our customers to access equity or credit markets could impact our customers’ spending levels and our revenues 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, and China, as well as 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 past 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 market could reduce our customers’ spending levels and reduce our revenues and operating results. Incremental weakness in global economic activity, particularly in China, India, 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, 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 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 economic conditions.

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

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

Productive capacity for oil and natural gas is dependent on our customers’ decisions to develop and produce oil and natural gas reserves. 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.

Access to prospects is also important to our customers. Access to prospects 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 adverse weather conditions adversely affect demand for our services and operations.

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

Risk Factors Related to Our Business

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

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

We operate in a highly competitive environment for marketing oilfield services and securing equipment and trained personnel. Our ability to continually provide competitive products and services can impact our ability to defend, maintain or increase prices for our products and services, maintain market share and negotiate acceptable contract terms with our customers. In order to be competitive, we must provide new technologies and reliable products and services that perform as expected and that create value for our customers. 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. In addition, our ability to negotiate acceptable contract terms and conditions with our customers, especially state-owned national oil companies, our ability to manage warranty claims and our ability to effectively manage our commercial agents can also impact our results of operations.

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, beryllium, copper, lead, tungsten carbide, synthetic and natural diamonds, guar, 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 and retention of the highly skilled workforce required by our plans and to manage the associated costs could impact our business. A well-trained, motivated work force has a positive impact on our ability to attract and retain business. Periods of rapid growth present a challenge to us and our industry to recruit, train and retain our employees while managing the impact of wage inflation and potential lack of available qualified labor in the markets where we operate. Likewise, when there is a downturn in the economy or our markets, we may have to adjust our workforce to control costs and yet not lose our skilled and diverse workforce. Labor-related actions, including strikes, slowdowns and facility occupations can also have a negative impact on our business.

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

Geopolitical and terrorism risks continue to grow in several key countries where we do business. Geopolitical and terrorism risks could lead to, among other things, a loss of our investment in the country, impair the safety of our employees and impair our ability to conduct our operations. Our informational technology systems are subject to possible breaches and other threats that could threaten our intellectual property, impair our ability to conduct our operations and cause other damages or loss.

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 DOJ and 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 and the efforts of our employees to comply with applicable law and the Baker Hughes Business Code of Conduct. We would be subject to severe 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 or adverse positions taken by taxing authorities could be costly and could affect operating results.

We have operations in the U.S. and in over 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 that impact the business environment include changes in accounting standards, changes in environmental laws, 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. 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.

These changes could have a significant financial impact on our future operations and the way we conduct, or if we conduct, business in the affected countries.

The May 2010 prior moratorium on drilling offshore in the U.S., as well as changes in and compliance with restrictions or regulations on offshore drilling in the U.S. Gulf of Mexico and in other areas around the world, has and may continue to adversely affect our business and operating results and reduce the need for our services in those areas.

While the moratorium on drilling offshore in the U.S. was lifted on October 12, 2010, there is a delay in resuming permitting of operations related to drilling offshore in the U.S. and there is no assurance that operations related to drilling offshore in the U.S. will reach the same levels that existed prior to the moratorium. The delay in resuming these activities or the failure of these activities to reach levels that existed prior to the moratorium has and could continue to adversely impact our operating results. The April 2010 Deepwater Horizon accident in the Gulf of Mexico and its aftermath has resulted in new and proposed legislation and regulation in the

U.S. of the offshore oil and gas industry, which may result in substantial increases in costs or delays in drilling or other operations in the Gulf of Mexico, oil and 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.

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 may adversely affect our business and operating results.

Our business is impacted by unexpected outcomes or material changes in environmental regulations. Our expectations regarding our compliance with environmental regulations and our expenditures to comply with environmental regulations, 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 the following factors: changes in environmental regulations; a material 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 new sites of which we are not aware and where additional expenditures may be required to comply with environmental regulations; an unexpected discharge of hazardous materials.

International, national, and state governments and agencies are currently evaluating and promulgating climate-related legislation and regulations that are focused on restricting greenhouse gas (“GHG”) emissions. In the U.S., the EPA has taken steps to regulate GHGs as pollutants under the Clean Air Act (“CAA”). The EPA’s “Mandatory Reporting of Greenhouse Gases” rule established a comprehensive scheme of regulations that require monitoring and reporting of GHG emissions that began in 2010. Furthermore, the EPA recently proposed additional GHG reporting rules specifically for the oil and gas industry. 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 cause or contribute to the GHG pollution. Following issuance of the Endangerment Finding, the EPA promulgated final motor vehicle GHG emission standards on April 1, 2010. These developments may curtail production and demand for fossil fuels such as oil and gas in areas of the world where our customers operate and thus adversely affect future demand for our services, which may in turn adversely affect future results of operations.

International developments focused on restricting the emission of carbon dioxide and other GHGs include the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol” (an internationally applied protocol, which has been ratified in Canada) and the European Union’s Emission Trading System. The Carbon Reduction Commitment in the U.K. is the first cap and trade scheme to affect Baker Hughes facilities. Domestic cap and trade programs include the Regional Greenhouse Gas Initiative or in the Northeastern United States, and the Western Regional Climate Action Initiative in the Western United States. A federal cap and trade regime may develop in the U.S. as well. These developments may curtail production and demand for fossil fuels

such as oil and gas in areas of the world where our customers operate and thus adversely affect future demand for our 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.

The EPA plans to study hydraulic fracturing practices, and legislation may be introduced in the U.S. Congress that would authorize the EPA to regulate hydraulic fracturing. In addition, a number of states are evaluating the adoption of legislation or regulations governing hydraulic fracturing. Such federal or state legislation and/or regulations could impair our operations and/or greatly reduce or eliminate demand for the Company’s pressure pumping services. Such legislation and/or regulations, if enacted, could adversely affect future results of operations. We are unable to predict whether the proposed legislation or any other proposals will ultimately be enacted, and if so, the impact on the Company’s business.

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

Changes in economic conditions and 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, particularly the British Pound Sterling, Euro, Canadian Dollar, Norwegian Krone, Russian Ruble, Australian Dollar, Brazilian Real and the Venezuelan Bolivar (which, for example, was devalued by the Venezuelan government in January 2010), can increase or decrease our revenue and expenses reported in U.S. Dollars and may impact our results of operations.

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 revolving credit agreements 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.

The merger with BJ Services may create additional risks for the Company.

The success of the merger will depend, in part, on our ability to realize certain anticipated benefits from combining the businesses of Baker Hughes and BJ Services. However, to realize these anticipated benefits, we must successfully integrate the operations and personnel of BJ Services and our existing business. If we are not able to achieve these objectives, the anticipated benefits of the merger may not be realized fully or at all or may take longer to realize than expected. Failure to achieve the anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect our future business, financial condition, operating results and prospects.

During the year ended December 31, 2010, approximately one-half of our revenue and approximately two-thirds of our profit before tax were attributable to North America. A decrease in demand for energy, natural gas exploration and production, or an increase in competition, in North America could result in a significant adverse effect on our operating results and the expected benefits of the merger.

Prior to the merger, BJ Services voluntarily disclosed information found in its internal investigations to the Department of Justice (“DOJ”) and SEC and engaged in discussions with these authorities in connection with their review of possible illegal payments. The Company cannot currently predict the outcome of these investigations, when any of these matters will be resolved, or what, if any, actions may be taken by the DOJ, the SEC or other authorities or the effect the actions may have on the business or consolidated financial statements of the Company. If the DOJ or SEC were to take action for failure to comply with the FCPA, it could significantly affect our results of operations.

In October of 2010, the Company made voluntary disclosures on behalf of BJ Services to the Department of Commerce and the Department of State for potential export control violations that occurred prior to the merger. The Department of State has issued a letter that notified the Company that they will not be taking any further action or imposing any penalty in relation to the disclosures that were filed with them. It is not possible at this time to predict the final outcome or penalty amounts that may be imposed by the Department of Commerce.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

We own or lease numerous facilities throughout the world. We consider our manufacturing plants, equipment repair and maintenance facilities, grinding plants, drilling fluids and chemical processing centers, and research and technology centers to be our principal properties. The locations of our principal properties include, but are not limited to, the following: (i) North America – Houston, Tomball and The Woodlands, Texas; Broken Arrow, Barnsdall, Claremore, Sand Springs and Tulsa, Oklahoma; Lafayette and Broussard, Louisiana; Calgary, Canada; (ii) Latin America – Maracaibo, Venezuela; Mendoza, Argentina; (iii) Europe/Africa/Russia Caspian – Aberdeen, Scotland; Liverpool and Hartlepool, England; Celle, Germany; (iv) Middle East/Asia Pacific – Dubai, United Arab Emirates; Dhahran, Saudi Arabia; Singapore and Chonburi, Thailand. The table below shows the number of facilities by geographic region:

Europe/

Middle

North

Latin

Africa/Russia

East/Asia

America

Caspian

Pacific

Total

Principal Properties

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, rental tools and manufacturing and other equipment. 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 14 of the Notes to Consolidated Financial Statements in Item 8 herein.

ITEM 4. [Removed and Reserved]

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 7, 2011, there were approximately 243,800 stockholders and approximately 14,400 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, 2010, and information regarding dividends declared on our common stock during the two years ended December 31, 2010, see Note 16 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 2010.

Issuer Purchases of Equity Securities


					Total						Maximum
					Number of						Number (or
					Shares				Total		Approximate
					Purchased				Number of		Dollar Value) of
					as Part of a				Shares		Shares that May
	Total Number		Average		Publicly		Average		Purchased		Yet Be
	of Shares		Price Paid		Announced		Price Paid		in the		Purchased Under
Period	Purchased⁽¹⁾		Per Share⁽¹⁾		Program⁽²⁾		Per Share⁽²⁾		Aggregate		the Program⁽³⁾

October 1-31, 2010		1,827	$	47.99		—	$	—		1,827	$	—
November 1-30, 2010		95,448		49.89		—		—		95,448		—
December 1-31, 2010		—		—		—		—		—		—

Total		97,275	$	49.85		—	$	—		97,275	$	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 as part of a publicly announced program during the fourth quarter of 2010.

(3)		Our Board of Directors has authorized a program to repurchase our common stock from time to time. During the fourth quarter of 2010, 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.

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 500 Stock Index and the cumulative total return on Standard & Poor’s 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


	2005		2006		2007		2008		2009		2010

Baker Hughes	$	100.00	$	123.68	$	135.24	$	54.01	$	69.25	$	99.07
S&P 500 Index		100.00		115.79		122.16		76.96		97.33		111.99
S&P 500 Oil and Gas Equipment and Services Index		100.00		115.54		170.88		69.76		111.76		155.66


*		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, 2005 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.

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)	2010			2009			2008			2007			2006

Revenues	$	14,414		$	9,664		$	11,864		$	10,428		$	9,027
Costs and expenses:
Cost of revenues		11,184			7,397			7,954			6,845			5,876
Research and engineering		429			397			426			372			339
Marketing, general and administrative		1,250			1,120			1,046			933			878
Acquisition-related costs		134			18			—			—			—
Litigation settlement		—			—			62			—			—

Total costs and expenses		12,997			8,932			9,488			8,150			7,093

Operating income		1,417			732			2,376			2,278			1,934
Equity in income of affiliates		—			—			2			1			60
Gain on sale of product line		—			—			28			—			—
Gain on sale of interest in affiliate		—			—			—			—			1,744
Gain (loss) on investments		6			4			(25	)		—			—
Interest expense, net		(141	)		(125	)		(62	)		(22	)		(1	)

Income from continuing operations before income taxes		1,282			611			2,319			2,257			3,737
Income taxes		(463	)		(190	)		(684	)		(743	)		(1,338	)

Income from continuing operations		819			421			1,635			1,514			2,399
Income from discontinued operations, net of tax		—			—			—			—			20

Net income		819			421			1,635			1,514			2,419
Net income attributable to noncontrolling interest		(7	)		—			—			—			—

Net income attributable to Baker Hughes	$	812		$	421		$	1,635		$	1,514		$	2,419


Per share of common stock:
Net income attributable to Baker Hughes:
Basic	$	2.06		$	1.36		$	5.32		$	4.76		$	7.32
Diluted		2.06			1.36			5.30			4.73			7.27
Dividends		0.60			0.60			0.56			0.52			0.52

Balance Sheet Data:
Cash, cash equivalents and short-term investments	$	1,706		$	1,595		$	1,955		$	1,054		$	1,104
Working capital (current assets minus current liabilities)		5,568			4,612			4,634			3,837			3,346
Total assets		22,986			11,439			11,861			9,857			8,706
Long-term debt		3,554			1,785			1,775			1,069			1,074
Stockholders’ equity		14,286			7,284			6,807			6,306			5,243

Notes To Selected Financial Data

(1)		Acquisition of BJ Services. We acquired BJ Services Company (“BJ Services”) on April 28, 2010, and their financial results from the date of acquisition through the end of 2010 are included in our results. For further discussion, see Note 2 – Acquisitions of the Notes to Consolidated Financial Statements in Item 8 herein. 2010 and 2009 income from continuing operations also includes costs incurred by Baker Hughes related to the acquisition and integration of BJ Services.

(2)		Litigation settlement. 2008 income from continuing operations includes a net charge of $62 million relating to the settlement of litigation with ReedHycalog.

(3)		Gain on sale of product line. 2008 income from continuing operations includes $28 million for the gain on the sale of the Completion and Production segment’s Surface Safety Systems (“SSS”) product line.

(4)		Equity in income of affiliates and gain on sale of interest in affiliate. On April 28, 2006, we sold our 30% interest in WesternGeco, a seismic venture we formed with Schlumberger in 2000, and recorded a gain of $1,744 million on the sale.

(5)		Discontinued operations. The selected financial data in 2006 includes reclassifications to reflect Baker Supply Products Division, as discontinued operations.

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 gas wells;

	•		products and services for completion and production of oil and gas wells; and

	•		industrial and other services including downstream refining, and process and pipeline industries, and reservoir technology and consulting services.

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.

On April 28, 2010, we completed the acquisition of BJ Services, a leading provider of pressure pumping and other oilfield services, for $6.9 billion in cash and stock. This acquisition provides us with a proven leader in the areas of pressure pumping, stimulation and fracturing and complements our existing product portfolio, allowing us to provide a full suite of products and services to meet the needs of our customers. For 2010, our results are inclusive of BJ Services results from the acquisition date through December 31, 2010. The acquired business represented approximately 46% of our consolidated total assets at December 31, 2010 and approximately 36% of our consolidated net income attributable to Baker Hughes for the year ended December 31, 2010.

For 2010, we generated revenues of $14.41 billion, an increase of $4.75 billion or 49% compared to 2009. Our North America oilfield revenues for 2010 were $6.62 billion, an increase of 109% compared to 2009. Oilfield revenues outside of North America were $6.82 billion, an increase of 18% compared to 2009. Industrial Services and Other revenues were $971 million, an increase of 40% compared to 2009. These increases are primarily due to the acquisition of BJ Services on April 28, 2010, which provided $3.69 billion of revenue in 2010, and the strength of the North America segment driven by oil and gas-directed drilling primarily in unconventional reservoirs.

Net income attributable to Baker Hughes was $812 million for 2010 compared to $421 million for 2009. The increase is primarily due to the acquisition of BJ Services, which provided $290 million of net income in 2010, and improved profitability in our North America segment partially offset by lower profits internationally.

As of December 31, 2010, Baker Hughes had approximately 53,100 employees compared to approximately 34,400 employees as of December 31, 2009. The increase in employees is due primarily to the acquisition of BJ Services, who employed approximately 14,000 employees at the date of acquisition.

BUSINESS ENVIRONMENT

Global economic growth and the resultant demand for oil and natural gas are the primary drivers of our customers’ expenditures to develop and produce oil and gas. The expansion of the global economy following the recession of 2008/2009 continued through 2010. Increasing economic activity, particularly in the emerging economies in Asia and the Middle East, and expectations for continued economic growth supported expectations for increasing demand for oil and natural gas. Spending by oil and natural gas exploration and production companies, which is dependent upon their forecasts regarding the expected future supply and future demand for oil and natural gas products and their estimates of costs to find, develop, and produce reserves, increased in 2010 compared to 2009. Changes in oil and natural gas exploration and production spending result in increased or decreased demand for our products and services, which will be reflected in the rig count and other measures. At early February 2011 oil prices, many international projects have attractive economic returns.

In North America, customer spending increased for both oil and gas projects resulting in a 44% increase in the North America rig count in 2010 compared to 2009. The increase in oil-directed drilling reflected the global price of oil, which is trading at a premium, on a Btu basis, relative to natural gas in North America. The increase in gas-directed drilling was driven by activity in the unconventional shale gas plays, despite relatively low prices for natural gas. Spending on gas-directed projects in 2010 was supported by (1) hedges on production made in prior periods when future prices were higher, (2) the need to drill and produce natural gas to hold

leases acquired in earlier periods, (3) the influx of equity from companies interested in developing a position in the shale resource plays and (4) associated production of natural gas liquids in certain basins.

Outside of North America customer spending is most heavily influenced by oil prices, which increased 28% in 2010 compared to 2009 as the economic recovery continued. In response to higher oil prices and expectations that the expanding economy would support prices in excess of $70/Bbl, our customers’ spending increased. This was reflected in a 10% increase in the rig count outside North America.

Oil and Natural Gas Prices

Oil (Bloomberg West Texas Intermediate (“WTI”) Cushing Crude Oil Spot Price and Bloomberg Dated Brent (“Brent”)) and natural gas (Bloomberg Henry Hub Natural Gas Spot Price) prices are summarized in the table below as averages of the daily closing prices during each of the periods indicated.


	2010		2009		2008

WTI oil prices ($/Bbl)	$	79.51	$	61.99	$	99.92
Brent oil prices ($/Bbl)	$	79.73		62.04		97.69
Natural gas prices ($/mmBtu)		4.37		3.94		8.89

WTI oil prices averaged $79.51/Bbl in 2010. Prices ranged from a high of $91.49/Bbl in December 2010 to a low of $65.96/Bbl in May 2010. Oil prices strengthened from a low in late May 2010 through the end of the year driven by expectations of worldwide economic recovery and energy demand growth, particularly in Asia and the Middle East.

Natural gas prices averaged $4.37/mmBtu in 2010. Natural gas prices traded during 2010 in a range between $3.18/mmBtu and $7.51/mmBtu and have not traded above $5/mmBtu since late June 2010. At the end of 2010, working natural gas in storage was 3,097 Bcf, which was 0.8% or 26 Bcf below the corresponding week in 2009.

Rig Counts

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

Rigs in the U.S. 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. Rigs in Canada are counted as active if data obtained by the Canadian Association of Oilwell Drillers and Contractors indicates that drilling operations have occurred during the week and we are able to verify this information. In most international areas, rigs are counted as active if drilling operations have taken place for at least 15 days during the month. In some active international areas where better data is available, we compute a weekly or daily average of active rigs. In international areas where there is poor availability of data, the rig counts are estimated from third-party data. 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.

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


	2010		2009		2008

U.S. — land and inland waters		1,514		1,046		1,814
U.S. — offshore		31		44		65
Canada		348		222		382

North America		1,893		1,312		2,261

Latin America		383		356		384
North Sea		43		43		45
Continental Europe		51		41		53
Africa		83		62		65
Middle East		265		252		280
Asia Pacific		269		243		252

Outside North America		1,094		997		1,079

Worldwide		2,987		2,309		3,340

2010 Compared to 2009

The rig count in North America increased 44% reflecting a 19% increase in the gas-directed rig count and a 108% increase in the oil-directed rig count. Changes in regulation of drilling activity in the Gulf of Mexico as a result of the April 2010 Deepwater Horizon accident and related deepwater drilling moratorium and the delay and decrease in approving drilling permits negatively impacted activity in the latter seven months of 2010 where the U.S. offshore rig count averaged only 20 rigs compared to 48 rigs in the first five months of 2010 and 44 rigs for the year 2009. Outside North America the rig count increased 10%. The rig count in Latin America increased primarily due to higher activity in the Southern Cone geomarket (Argentina, Bolivia and Chile), the Andean geomarket (Colombia, Peru and Ecuador), and Brazil, and was partially offset by lower activity in the Venezuela/Mexico geomarket. The increase in rig count in the Continental Europe geomarket was led by Turkey, Italy and Romania. The rig count in Africa increased primarily due to higher activity in the Nigeria and Sub Saharan Africa geomarkets. The rig count increased in the Middle East due to higher activity in Egypt and Kuwait, offset partially by declines in activity in Oman and Pakistan. In the Asia Pacific region, activity increased primarily in India, Vietnam, and Offshore China, offset partially by lower activity in Indonesia and Australia.

RESULTS OF OPERATIONS

The discussions below relating to significant line items from our consolidated statements of operations are based on available information and represent our analysis of significant changes or events that impact the comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect comparability or trends and, where possible and practical, have quantified the impact of such items. We acquired BJ Services on April 28, 2010, and the financial results of its operations from the acquisition date through the end of 2010 are included in each of the five reportable segments in a manner consistent with our reporting structure. In addition, the discussions below for revenues and cost of revenues 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.

Segment Reporting Change

During 2010, we changed our internal reporting structure to align with our geographical organization which became the primary vehicle for allocating resources and assessing performance. As a result, we report our results for the following five segments:

	•		North America (Canada, U.S., and Trinidad)

	•		Latin America (Central and South America including Mexico and excluding Trinidad)

	•		Europe/Africa/Russia Caspian (“EARC”) (Europe, Africa — excluding Egypt, and Russia and the republics of the former Soviet Union)

	•		Middle East/Asia Pacific (“MEAP”) (Middle East — including Egypt)

	•		Industrial Services and Other (downstream chemicals, process and pipeline services, and reservoir and technology consulting businesses)

The four geographic segments represent our oilfield operations. All prior period segment disclosures have been recast to reflect the new segments.

Revenues and Profit Before Tax

The performance of our segments is evaluated based on segment profit before tax, which is defined as income before income taxes, interest expense, interest income, and certain gains and losses not allocated to the segments.

2010 Compared to 2009


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

Segment Revenues:
North America	$	6,621	$	3,165	$	3,456		109	%
Latin America		1,569		1,094		475		43	%
Europe/Africa/Russia Caspian		3,006		2,774		232		8	%
Middle East/Asia Pacific		2,247		1,937		310		16	%
Industrial Services and Other		971		694		277		40	%

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


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

Segment Profit Before Tax:
North America	$	1,163	$	201	$	962			479	%
Latin America		74		78		(4	)		(5	)%
Europe/Africa/Russia Caspian		260		458		(198	)		(43	)%
Middle East/Asia Pacific		177		241		(64	)		(27	)%
Industrial Services and Other		99		70		29			41	%

Segment profit before tax	$	1,773	$	1,048	$	725			69	%

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

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

North America

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

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

Latin America

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

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

Europe/Africa/Russia Caspian

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

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

Middle East/Asia Pacific

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

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

Industrial Services and Other

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

2009 Compared to 2008


	Year Ended
	December 31,
					Increase
	2009		2008		(decrease)			% Change

Segment Revenues:
North America	$	3,165	$	4,691	$	(1,526	)		(33	)%
Latin America		1,094		1,089		5			—
Europe/Africa/Russia Caspian		2,774		3,209		(435	)		(14	)%
Middle East/Asia Pacific		1,937		2,090		(153	)		(7	)%
Industrial Services and Other		694		785		(91	)		(12	)%

Segment revenues	$	9,664	$	11,864	$	(2,200	)		(19	)%


	Year Ended
	December 31,
					Increase
	2009		2008		(decrease)			% Change

Segment Profit Before Tax:
North America	$	201	$	1,249	$	(1,048	)		(84	)%
Latin America		78		196		(118	)		(60	)%
Europe/Africa/Russia Caspian		458		629		(171	)		(27	)%
Middle East/Asia Pacific		241		414		(173	)		(42	)%
Industrial Services and Other		70		192		(122	)		(64	)%

Segment profit before tax	$	1,048	$	2,680	$	(1,632	)		(61	)%

Revenues for 2009 decreased $2.20 billion or 19% compared to 2008 primarily due to a decrease in activity as evidenced by a 31% decline in the worldwide rig count, and to a lesser extent, pricing pressure on our products and services.

Profit before tax for 2009 decreased $1.63 billion or 61% compared to 2008 primarily due to a decline in activity, additional costs associated with reorganization, severance and acquisition activities, and an increase in our allowance for doubtful accounts.

North America

Revenues in North America, which accounted for 33% of total revenues, decreased 33% in 2009 compared to 2008 due to a sharp reduction in drilling and completion activity in the U.S. and Canada, as evidenced by a 42% reduction in rig count and lower realized pricing. The decline was most significant in the drilling and evaluation and completion product lines coupled with modest declines in production-related oilfield chemicals and artificial lift products and services.

North America profit before tax was $201 million in 2009, a decrease of 84% compared to 2008, as declining activity resulted in lower equipment utilization.

Latin America

Latin America revenue remained flat in 2009 compared to 2008 despite a reduction of 7% in the rig count over the same period. A sharp decline in activity and commensurate revenue decrease in the Southern Cone geomarket was offset by increased revenue in the Brazil geomarket. Increased directional drilling and drilling fluids revenue in the Brazil geomarket and directional drilling revenue in the Mexico/Venezuela geomarket was offset by decreased wireline revenue in the Southern Cone geomarket and artificial lift and completions revenue in the Mexico/Venezuela geomarket.

Latin America profit before tax decreased 60% in 2009 compared to 2008 reflecting lower realized pricing and challenging economics, particularly in the Venezuela/Mexico and the Southern Cone geomarkets.

Europe/Africa/Russia Caspian

Europe/Africa/Russia Caspian revenue decreased 14% in 2009 compared to 2008 where the rig count decreased 10%. Revenue declined in the U.K. and Russia Caspian geomarkets and was partially offset by increased revenue in the Continental Europe geomarket despite a sharp decline in the rig count. The decline was most significant in the drilling and evaluation and completion product lines with more modest declines in production-related oilfield chemicals.

Europe/Africa/Russia Caspian profit before tax decreased 27% in 2009 compared to 2008 due to higher overhead costs and lower realized pricing. Decrease in profit before tax in the Russia Caspian, Sub Saharan Africa and North Africa geomarkets was partially offset by an increase in profit before tax in the Continental Europe geomarket.

Middle East/Asia Pacific

Middle East/Asia Pacific revenue decreased 7% in 2009 compared to 2008 where lower activity was evidenced by a 7% decline in rig count. Saudi Arabia and Egypt geomarkets experienced the sharpest reduction in activity with a commensurate decline in revenue, partially offset by an increase in revenue in the Southeast Asia geomarket. The decline was most significant in directional drilling, completion equipment and drill bits offset partially by revenue increases in drilling fluids and production-related artificial lift and oilfield chemicals.

Middle East/Asia Pacific profit before tax decreased 42% in 2009 compared to 2008 where lower utilization levels and price erosion was partly offset by cost management programs. Profit before tax declined across all geomarkets except Southeast Asia where profit before tax increased slightly.

Industrial Services and Other

Industrial Services and Other revenue decreased 12% in 2009 compared to 2008. Industrial Services and Other profit before tax decreased 64% in 2009 compared to 2008.

Costs and Expenses

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


	2010					2009					2008
	$		%			$		%			$		%

Revenues	$	14,414		100	%	$	9,664		100	%	$	11,864		100	%
Cost of revenues		11,184		78	%		7,397		77	%		7,954		67	%
Research and engineering		429		3	%		397		4	%		426		4	%
Marketing, general and administrative		1,250		9	%		1,120		12	%		1,046		9	%

Cost of Revenues

Cost of revenues as a percentage of revenues was 78% and 77% for 2010 and 2009, respectively. The increase was primarily due to pricing pressures and higher operating costs for our geomarket organization which we are mitigating through productivity improvements and cost cutting measures. The additional depreciation and amortization expense for the eight months since the acquisition date of approximately $93 million for tangible and intangible assets associated with the BJ Services acquisition also contributed to the increase.

Cost of revenues as a percentage of revenues was 77% and 67% for 2009 and 2008, respectively. The increase was primarily due to significant declines in activity worldwide resulting in excess manufacturing capacity, lower utilization of our rental tools and price deterioration, primarily in North America. Additional contributing factors to this increase include costs associated with employee severance of $73 million; an increase in the net provision for doubtful accounts of $73 million; and a change in the geographic and product mix from the sale of our products and services as we continue to emphasize productivity and cost improvements.

Research and Engineering

Research and engineering expenses increased 8% in 2010 compared to 2009. We continue to be committed to developing and commercializing new technologies as well as investing in our core product offerings. Research and development costs increased 23% in 2010 compared to 2009.

Research and engineering expenses decreased 7% in 2009 compared to 2008. The decrease was in line with the decrease in activity. The decrease was offset by $5 million associated with employee severance. Research and development costs decreased 12% in 2009 compared to 2008.

Marketing, General and Administrative

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

MG&A expenses increased 7% in 2009 compared to 2008. This increase resulted primarily from an increase in costs associated with enterprise-wide accounting system implementations and reorganization activities of $46 million, and employee severance of $14 million. These increases were partially offset by lower marketing and compliance related expenses.

Acquisition-Related Costs

Acquisition-related costs are being expensed as incurred. They include expenses directly related to acquiring BJ Services and integration expenses incurred in combining the companies. During 2010 and 2009, we incurred $134 million and $18 million, respectively, of total acquisition-related costs.

Interest Expense, net

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

Net interest expense increased $63 million in 2009 compared to 2008 primarily due to the new long-term debt issuances of $1.25 billion in October 2008 resulting in higher average debt levels throughout 2009, and a reduction in the average interest rate earned and the average investment balance.

Income Taxes

Our effective tax rates in 2010, 2009 and 2008 were 36.1%, 31.1%, and 29.5% respectively. The current year effective tax rate is higher than the U.S. statutory income tax rate of 35% due to higher rates of tax on certain international operations and state income taxes partially offset by tax benefits arising from the repatriation of foreign earnings. The prior two years’ effective tax rates were lower than the U.S. statutory income tax rate of 35% due to lower rates of tax on certain international operations offset by state income taxes.

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 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. We have received tax assessments from various taxing authorities and are currently at varying stages of appeals and/or litigation regarding these matters. We believe we have substantial defenses to the questions being raised and will pursue all legal remedies should an unfavorable outcome result. However, resolution of these matters involves uncertainties and there are no assurances that the outcomes will be favorable.

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 gas, the impact of new government regulations and their ability to fund their capital programs.

The depth and pace of economic recovery from the global economic recession, the negative impact of the moratorium and new regulations following the Deepwater Horizon accident in the Gulf of Mexico, and drilling in the U.S. oil-and-gas shale plays are expected to be the primary drivers impacting the 2011 business environment.

As the worldwide economy recovers, demand for hydrocarbons is increasing. In its January 2011 World Economic Outlook Update, the International Monetary Fund (“IMF”) forecasted that global output would increase 4.4% in 2011 compared to 2010. Advanced economies’ economic growth is expected to remain sluggish at 2.5% in 2011 compared to 2010 while emerging and developing economies are expected to grow at 6.5% in 2011 compared to 2010. The IMF also noted that the downside risks to the recovery were elevated primarily due to sovereign and financial troubles with the Euro area and policies to redress fiscal imbalances in the advance economies in general.

The International Energy Agency (“IEA”) estimated in its February 2011 Oil Market Report that worldwide demand would increase 1.5 million barrels per day or 1.7% to 89.3 million barrels per day in 2011, up from 87.8 million barrels per day in 2010. The largest incremental demands for oil are expected to be generated by the developing and emerging economies in China, India and the Middle East. Increasing oil demand is expected to support oil prices between $70/Bbl and $100/Bbl in 2011.

In North America, the near-month futures prices for natural gas, as quoted in February 2011 for March 2011, were below $4.00/mmBtu, and the twelve month futures price was trading slightly below $4.40/mmBtu. Higher natural gas futures prices in 2008 and early 2009 provided an opportunity for many of our customers to hedge natural gas production. Cash flow of these customers benefited from the attractive prices received on hedged production allowing them to maintain exploration and development

activity. However, the decline in natural gas prices in 2010 and the roll-off of attractive hedge positions is placing increased emphasis on well economics, cash flow and capital budgets for many of our customers. In the near-term, the impact of lower cash flows from sales and hedging activity is being offset by investments by international oil companies seeking exposure to the U.S. shale plays. Capital discipline on the part of our competitors, attrition of existing rental fleets and rising demand are expected to result in an environment that supports continued price increases for our products and services in some markets by late 2011. In addition, project economies will be favorably impacted if the production is expected to include a significant amount of natural gas liquids or condensates, which can be sold at a higher price per mmBtu.

The impact of changes in the regulation of offshore drilling in the U.S. Gulf of Mexico is negatively impacting U.S. offshore drilling activity. The impact on offshore activity appears to be isolated to the Gulf of Mexico at this time. Equipment and people are being redeployed and reassigned to opportunities away from the Gulf coast. The negative impact is expected to be partially offset by incremental spending in other regions as oil and gas companies adjust their spending plans, as well as increased spending on workovers on the shelf in the Gulf of Mexico as permitted by the Bureau of Ocean Energy Management Regulation and Enforcement.

Our outlook for exploration and development spending is based upon our expectations for customer spending in the markets in which we operate, and is driven primarily by our perception of industry expectations for oil and natural gas prices and their likely impact on customer capital and operating budgets as well as other factors that could impact the economic return oil and gas companies expect for developing oil and gas reserves. Our forecasts are based on our analysis of information provided by our customers as well as market research and analyst reports including the Short Term Energy Outlook (“STEO”) published by the Energy Information Administration of the U.S. Department of Energy (“DOE”), the Oil Market Report published by the IEA and the Monthly Oil Market Report published by Organization for Petroleum Exporting Countries (“OPEC”). Our outlook for economic growth is based on our analysis of information published by a number of sources including the IMF, the Organization for Economic Cooperation and Development (“OECD”) and the World Bank.

In North America, the outlook for 2011 will be significantly influenced by the outlook for the natural gas industry. However, oil-directed rig activity has increased to levels not seen since early 1991, and is expected to continue to increase with oil prices greater than $70/Bbl, as many operators seek to diversify activity away from natural gas. The increase in gas-directed rig count from mid-2009 low levels and continued advances in horizontal drilling and advanced fracturing and completion technologies has led to increasing rates of initial production in the unconventional gas fields, resulting in high levels of gas production relative to demand.

Expectations for Oil Prices Due to expectations for the continued global economic expansion, the Energy Information Administration (“EIA”) expects global demand for oil to increase 1.5 million barrels per day in 2011 relative to 2010. Non-OPEC supply growth is expected to increase by 310 thousand barrels per day in 2011 as forecasted by the EIA. In its December 2010 meeting in Quito, Ecuador, OPEC left its production policy unchanged. OPEC spare productive capacity is expected to be essentially unchanged through 2011. In its February 2011 STEO report, the DOE forecasted oil prices to average $93/Bbl for the year 2011. In early February 2011, WTI oil prices, which normally trade at a premium to Brent oil prices, were trading at a significant discount (approximately $14/Bbl). The structural causes of this difference are expected to exist through the end of 2012.

Expectations for North America Natural Gas Prices – Increasing production and near record high storage levels are placing downward pressure on natural gas prices. Storage is expected to remain at or near historically high levels throughout the year. In its February 2011 STEO report, the DOE forecasted Henry Hub natural gas prices to average $4.16/mmBtu for 2011 compared to $4.37/mmBtu in 2010.

Our capital expenditures, excluding acquisitions, are expected to be approximately $2.3 billion to $2.7 billion for 2011. A significant portion of our planned capital expenditures can be adjusted to reflect changes in our expectations for future customer spending. We will manage our capital expenditures to match market demand.

COMPLIANCE

We do business in over 80 countries, including approximately 20 of the 40 countries having the lowest scores in the Transparency International’s Corruption Perception Index survey for 2010, which indicates high levels of corruption. We devote significant resources to the development, maintenance and enforcement of our Business Code of Conduct policy, our anti-bribery compliance policies, our internal control processes and procedures and other compliance related policies. Notwithstanding the devotion of such resources, and in part as a consequence thereof, from time to time we discover or receive information alleging potential violations of laws and regulations, including the FCPA and our policies, processes and procedures. We conduct internal investigations of these potential violations and take appropriate action depending upon the outcome of the investigation.

We anticipate that the devotion of significant resources to compliance-related issues, including the necessity for investigations, will continue to be an aspect of doing business in a number of the countries in which oil and natural gas exploration, development and

production take place and in which we are requested to conduct operations. Compliance-related issues have limited our ability to do business and/or have raised the cost of operating in these countries. In order to provide products and services in some of these countries, we may in the future utilize ventures with third parties, sell products to distributors or otherwise modify our business approach in order to improve our ability to conduct our business in accordance with applicable laws and regulations and our Business Code of Conduct.

Our Best-in-Class Global Ethics and Compliance Program (“Compliance Program”) is based on (i) our Core Values of Integrity, Performance, Teamwork and Learning; (ii) the standards contained in our Business Code of Conduct; (iii) the laws of the countries where we operate; and (iv) our commitments to the DOJ and the SEC. 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.

In connection with our settlements with the DOJ and SEC in April 2007, we retained an independent monitor (the “Monitor”) to assess and make recommendations about our compliance policies and procedures. The Monitor was retained for a term of three years. That term ended on July 1, 2010. In June 2010, the Monitor issued his final report certifying that “the anti-bribery compliance program of Baker Hughes, including its policies and procedures, is appropriately designed and implemented to ensure compliance with the FCPA, U.S. commercial bribery laws and foreign bribery laws.”

Highlights of our Compliance Program, including enhancements or additions as a result of the independent monitor’s recommendations, include the following:

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

	•		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 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 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 whistleblower 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 our reduction of the use of commercial sales representatives (“CSRs”) and processing agents, including the reduction of customs agents.

	•		We have a due diligence procedure for 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 reviewed and expanded the use of our centralized finance organization including further implementation of our enterprise-wide accounting system and company-wide policies regarding expense reporting, petty cash, the approval of invoice payments and general ledger account coding. Further, we have restructured our corporate audit function and have incorporated additional anti-corruption procedures into some of our audits, which are applied on a country-wide basis. We are also continuing to refine and enhance our procedures for FCPA risk assessments and legal audit procedures.

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

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

We have analyzed the BJ Services’ compliance programs and since the closing of the acquisition have been integrating our compliance programs within the operations of BJ Services, as appropriate.

LIQUIDITY AND CAPITAL RESOURCES

Our objective in financing our business is to maintain adequate financial resources and access to sufficient liquidity. At December 31, 2010, we had cash and cash equivalents of $1.46 billion, short-term investments of $250 million, and $1.7 billion available for borrowing under committed revolving credit facilities with commercial banks.

Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of our Company. In 2010, we used cash to pay for a variety of activities including working capital needs, dividends, debt maturities, acquisitions and capital expenditures.

Cash Flows

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


(In millions)	2010			2009			2008

Operating activities	$	856		$	1,239		$	1,614
Investing activities		(2,376	)		(966	)		(1,170	)
Financing activities		1,366			(675	)		541

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

Operating Activities

Cash flows from operating activities provided $856 million for the year ended December 31, 2010 and provided $1,239 million for the year ended December 31, 2009. This decrease in cash flows of $383 million is primarily due to the change in net operating assets and liabilities which used more cash in 2010 compared to 2009.

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

	•		An increase in accounts receivable used $702 million in cash in 2010 and provided $399 million in 2009. The change in accounts receivable was primarily due to an increase in activity partially offset by a decrease in the days sales outstanding (defined as the average number of days our net trade receivables are outstanding based on quarterly revenues) by approximately 6 days.

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

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

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

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

Cash flows from operating activities provided $1,239 million for the year ended December 31, 2009 and used $1,614 million for the year ended December 31, 2008. This decrease in cash flows of $375 million is primarily due to a decrease in net income offset by the change in net operating assets and liabilities that provided more cash in 2009 compared to 2008.

The underlying drivers in 2009 compared to 2008 of the changes in operating assets and liabilities are as follows:

	•		A decrease in accounts receivable provided $399 million in cash in 2009 and used $515 million in 2008. The decrease in accounts receivable was primarily due to the decrease in activity partially offset by an increase in the days sales outstanding (defined as the average number of days our net trade receivables are outstanding based on quarterly revenues) by approximately nine days, reflecting a slowdown in customer payments.

	•		Inventory provided $240 million in cash in 2009 and used $371 million in 2008 due to activity decreases in 2009 compared to 2008.

	•		A decrease in accounts payable used $89 million in cash in 2009 and provided $242 million in cash in 2008. This decrease in accounts payable corresponds with the decrease in operating assets to support decreased activity.

	•		Accrued employee compensation and other accrued liabilities used $130 million in cash in 2009 and provided $90 million in cash in 2008. The increase in the use of cash was primarily due to an increase in payments in 2009 compared to 2008 primarily related to employee bonuses earned in 2008 but paid in 2009.

	•		Our contributions to our defined benefit pension plans in 2009 and 2008 totaled $15 million in each year.

Investing Activities

Our principal recurring investing activity is the funding of capital expenditures to support the appropriate levels and types of rental tools we have in place to generate revenues from operations. Expenditures for capital assets totaled $1.49 billion, $1.09 billion and $1.30 billion for 2010, 2009 and 2008, respectively. While the majority of these expenditures were for rental tools, wireline tools, and machinery and equipment, we have also increased our spending on new facilities, expansions of existing facilities and other infrastructure projects.

Proceeds from disposal of assets were $208 million, $163 million and $222 million for 2010, 2009 and 2008, respectively. These disposals relate primarily to rental tools that were lost-in-hole, as well as machinery, rental tools and equipment no longer used in operations that were sold throughout the year.

On August 30, 2010, we completed the sale of two stimulation vessels and certain other assets used to perform sand control services in the U.S. Gulf of Mexico. We received cash of $55 million and incurred disposition costs of $16 million. The divestiture was required by the DOJ in connection with the acquisition of BJ Services. The sale was not material to our business or our financial performance.

We routinely evaluate potential acquisitions of businesses of third parties that may enhance our current operations or expand our operations into new markets or product lines. We may also from time to time sell business operations that are not considered part of our core business. During 2010, we paid cash of $680 million, net of cash acquired of $113 million, related to the BJ Services acquisition, and we paid $208 million, net of cash acquired of $4 million, for other acquisitions. In 2009, we paid $58 million, net of cash acquired of $4 million, for acquisitions including additional purchase price consideration for past acquisitions. In 2008, we paid $120 million for acquisitions, including $4 million of direct transaction costs and net of cash acquired of $5 million.

In 2008, we sold the assets associated with our Surface Safety Systems product line and received cash proceeds of $31 million.

During 2010, we purchased $250 million of short-term investments consisting of U.S. Treasury Bills, which will mature in May of 2011, the proceeds of which will be used to repay the BJ Services 5.75% notes maturing in June 2011.

Financing Activities

We had net borrowings of commercial paper and other short-term debt of $52 million in 2010, net repayments of commercial paper and other short-term debt of $16 million in 2009, and net borrowings of commercial paper and short-term debt of $15 million in 2008. On August 24, 2010, we sold $1.5 billion of 5.125% Senior Notes that will mature September 15, 2040. Net proceeds from the offering were approximately $1.48 billion after deducting the underwriting discounts and expenses of the offering. We used $511 million of the net proceeds to repay our outstanding commercial paper. We used $250 million of the net proceeds to purchase U.S. Treasury Bills, which will be used to repay the BJ Services 5.75% notes maturing in June 2011. The remaining net proceeds from the offering were used for general corporate purposes. In 2009, we repaid $525 million of maturing long-term debt. Total debt outstanding at December 31, 2010 was $3.89 billion, an increase of $2.09 billion compared to December 31, 2009. This increase is primarily due to the sale of $1.5 billion of notes and the assumption of $500 million principal amount of long-term debt from the BJ Services acquisition. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was 0.21 at December 31, 2010 and 0.20 at December 31, 2009.

On October 28, 2008, we sold $500 million of 6.50% Senior Notes that will mature November 15, 2013, and $750 million of 7.50% Senior Notes that will mature November 15, 2018. Net proceeds from the offering were $1.24 billion after deducting the underwriting discounts and expenses of the offering. We used a portion of the net proceeds to repay outstanding commercial paper, as well as to repay $325 million aggregate principal amount of our outstanding 6.25% notes, which matured on January 15, 2009, and $200 million aggregate principal amount of our outstanding 6.00% notes, which matured on February 15, 2009. We used the remaining net proceeds from the offering for general corporate purposes.

We received proceeds of $74 million, $51 million and $87 million in 2010, 2009 and 2008, 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 2008, we repurchased 9 million shares of our common stock at an average price of $68.12 per share for a total of $627 million. During 2010 and 2009 we did not repurchase any shares of common stock. We had authorization remaining to repurchase approximately $1.2 billion in common stock at the end of 2010.

We paid dividends of $241 million, $185 million and $173 million in 2010, 2009 and 2008, respectively. The increase in 2010 is primarily due to the 118 million shares issued in the acquisition of BJ Services.

Available Credit Facilities

On March 19, 2010, we entered into a credit agreement (the “2010 Credit Agreement”). The 2010 Credit Agreement is a three-year committed $1.2 billion revolving credit facility that expires on March 19, 2013; $800 million of the revolving credit facility was available immediately and the remaining $400 million of such facility became available after consummation of the acquisition of BJ Services, which occurred on April 28, 2010. Also on March 19, 2010, we terminated our 364-day credit agreement in the amount of $500 million, dated as of March 30, 2009 and expiring March 29, 2010. At December 31, 2010, we had $1.7 billion of committed revolving credit facilities with commercial banks, consisting of the 2010 Credit Agreement ($1.2 billion) and a $500 million facility expiring on July 7, 2012. Both facilities contain certain covenants which, among other things, require the maintenance of a funded indebtedness to total capitalization ratio (a defined formula per the facility), 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 facilities may be accelerated. Such events of default include payment defaults to lenders under the facilities, covenant defaults and other customary defaults.

At December 31, 2010, we were in compliance with all of the facility covenants of both committed credit facilities. There were no direct borrowings under the committed credit facilities at the end of 2010. We also have an outstanding commercial paper program under which we may issue from time to time up to $1.0 billion in commercial paper with maturity of no more than 270 days. To the extent we have outstanding commercial paper our ability to borrow under the committed credit facilities is reduced by a similar amount. At December 31, 2010, we had no commercial paper outstanding.

If market conditions were to change and revenues were to be significantly reduced 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 facilities. However, a downgrade in our credit ratings could increase the cost of borrowings under the facilities 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 facilities.

We believe our current credit ratings would allow us to obtain interim financing over and above our existing credit facilities 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 2011, we believe cash on hand and cash flows from operating activities 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 2011, we expect our capital expenditures to be between approximately $2.3 billion to $2.7 billion, excluding any amount related to acquisitions. The expenditures are expected to be used primarily for normal, recurring items necessary to support our business and operations. A significant portion of our capital expenditures can be adjusted based on future activity of our customers. We will manage our capital expenditures to match market demand. In 2011, we also expect to make interest payments of between $215

million and $225 million, based on debt levels as of December 31, 2010. We anticipate making income tax payments of between $975 million and $1,025 million in 2011.

We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. We anticipate paying dividends of between $260 million and $270 million in 2011; however, the Board of Directors can change the dividend policy at any time.

For all pension plans, we make annual contributions to the plans in amounts equal to or greater than amounts necessary to meet minimum governmental funding requirements. In 2011, we expect to contribute between $65 million and $85 million to our defined benefit pension plans. In 2011, we also expect to make benefit payments related to postretirement welfare plans of between $16 million and $18 million, and we estimate we will contribute between $185 million and $200 million to our defined contribution plans. See Note 13 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, 2010. 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
			Less Than		2 - 3		4 - 5		More than
(In millions)	Total		1 year		Years		Years		5 Years

Total debt ⁽¹⁾	$	3,880	$	330	$	500	$	—	$	3,050
Estimated interest payments ⁽²⁾		3,621		220		416		377		2,608
Operating leases⁽³⁾		681		186		228		116		151
Purchase obligations ⁽⁴⁾		264		246		18		—		—
Other long-term liabilities ⁽⁵⁾		168		14		70		26		58
Income tax liabilities for uncertain tax positions⁽⁶⁾		438		279		76		34		49

Total	$	9,052	$	1,275	$	1,308	$	553	$	5,916


⁽¹⁾		Amounts represent the expected cash payments for our total debt and do not include any unamortized discounts, deferred issuance costs or net deferred gains on terminated interest rate swap agreements.

⁽²⁾		Amounts represent the expected cash payments for interest on our long-term debt.

⁽³⁾		We enter into operating leases in the normal course of business. Some lease agreements provide us with the option to renew the lease. Our future operating lease payments as reflected in the table above would change if we exercised these renewal options or if we entered into additional operating lease agreements.

⁽⁴⁾		Purchase obligations include 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. Purchase obligations exclude agreements that are cancelable at anytime without penalty.

⁽⁵⁾		Amounts represent other long-term liabilities, including the current portion, reflected in the consolidated balance sheet where both the timing and amount of payment streams are known. Amounts include: payments for certain environmental remediation liabilities, payments for deferred compensation, payouts under acquisition agreements and payments for certain asset retirement obligations. Amounts do not include: payments for pension contributions and payments for various postretirement welfare benefit plans and postemployment benefit plans.

⁽⁶⁾		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 $1.16 billion at December 31, 2010. We also had commitments outstanding for purchase obligations related to capital expenditures and inventory under purchase orders and contracts of approximately $264 million at December 31, 2010. 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.

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, revenues and expenses and related disclosures and about 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 cannot be perceived with certainty, and accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the business environment in which we operate changes.

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

Allowance for Doubtful Accounts

The determination of the collectability of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customers’ payment history and current credit worthiness to determine that collectability is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Inherently, these uncertainties require us to make frequent judgments and estimates regarding our customers’ ability to pay amounts due us in order to determine the appropriate amount of valuation allowances required for doubtful accounts. Provisions for doubtful accounts are recorded when it becomes evident that the customer will not make the required payments at either contractual due dates or in the future. At December 31, 2010 and 2009, the allowance for doubtful accounts totaled $162 million, or 4%, and $157 million, or 6%, 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 $8 million in 2010.

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, 2010 and 2009, inventory reserves totaled $322 million, or 11%, and $297 million, or 14%, 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 $16 million in 2010.

Goodwill and Other Long-Lived Assets

Long-lived assets, which include property and equipment, goodwill, intangible assets, 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 goodwill, 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 revenues and costs related to the assets subject to review. In turn, these forecasts are uncertain in that they require assumptions about demand for our products and services, future market conditions and technological developments. We perform an annual impairment test of goodwill as of October 1 of each year. In performing the test, we individually test each of our reporting units, which are generally based on our regional structure. These tests involve the use of different valuation techniques, including a market approach, 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 2010 test 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 specific times, it is not possible to reasonably quantify the impact of changes in these assumptions.

The purchase price of acquired businesses is allocated to its identifiable assets and liabilities based upon estimated fair values as of the acquisition date. The excess of the consideration transferred over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. In determining estimated fair values, we use various sources and types of information, including but not limited to quoted market prices, replacement cost estimates, accepted valuation techniques such as discounted cash flows, and existing carrying value of acquired assets. As necessary, we utilize third-party appraisal firms to assist us in determining fair value of inventory, identifiable intangible assets, and any other significant assets or liabilities. During the measurement period and as necessary, we adjust the preliminary purchase price allocation if we obtain more information regarding asset valuations and liabilities assumed. The judgments, assumptions and estimates used or made in determining the estimated fair value assigned to assets acquired and liabilities assumed, as well as asset lives, can materially impact our results of operations.

Income Taxes

The liability method is used for determining our income taxes, 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 revenues 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 subjected to audit by the tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or through the courts. We believe these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. Resolution of these situations inevitably includes some degree of uncertainty; accordingly, we provide taxes only for the amounts we believe will ultimately result from these proceedings. The resulting change to our tax liability, if any, is dependent on numerous factors that are difficult to estimate. These include, among others, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a fair settlement through an administrative process; the impartiality of the local courts; the sheer number of countries in which we do business; and the potential for changes in the tax paid to one country to either produce, or fail to produce, an offsetting tax change in other countries. Our experience has been that the estimates and

assumptions we have used to provide for future tax assessments have proven to be appropriate. However, past experience is only a guide, and the potential exists that the tax resulting from the resolution of current and potential future tax controversies may differ materially from the amount accrued.

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

Pensions and Postretirement Benefit Obligations

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

The discount rate enables us to state expected future cash flows at a present value on the measurement date. The development of the discount rate for our largest plans was based on a bond matching model whereby the cash flows underlying the projected benefit obligation are matched against a yield curve constructed from a bond portfolio of high-quality, fixed-income securities. Use of a lower discount rate would increase the present value of benefit obligations and increase pension expense. We used a discount rate of 5.9% in 2010, 6.4% in 2009 and 6.0% in 2008 to determine pension expense. A 50 basis point reduction in the discount rate would have decreased income before income taxes by approximately $1 million in 2010.

To determine the expected rate of return on plan assets, we consider the current and target asset allocations, as well as historical and expected future returns on various categories of plan assets. A lower rate of return increases plan expenses. We assumed rates of return on our plan investments were 7.1% in 2010 and 8.0% in 2009 and in 2008. A 50 basis point reduction in the expected rate of return on assets of our principal plans would have decreased income before income taxes by approximately $4 million in 2010.

NEW ACCOUNTING STANDARDS AND ACCOUNTING STANDARDS UPDATES

In October 2009, the Financial Accounting Standards Board (“FASB”) issued an update to Accounting Standards Codification (“ASC”) 605, Revenue Recognition — Multiple Deliverable Revenue Arrangements. This Accounting Standards Update (“ASU”) addresses accounting for multiple-deliverable arrangements to enable vendors to account for deliverables separately. The provision establishes a selling price hierarchy for determining the selling price of a deliverable. This update requires expanded disclosures for multiple deliverable revenue arrangements. The ASU was effective for us for revenue arrangements entered into or materially modified on or after June 15, 2010. We adopted the provisions of this update with no material impact on our consolidated financial statements.

In December 2010, the FASB issued an update to ASC 805, Business Combinations. This ASU addresses the disclosure of comparative financial statements and expands on the supplementary pro forma information for business combinations. We will adopt this ASU prospectively for business combinations occurring on or after December 15, 2010.

RELATED PARTY TRANSACTIONS

There were no significant related party transactions during the three years ended December 31, 2010.

FORWARD-LOOKING STATEMENTS

MD&A and certain statements in the Notes to Consolidated Financial Statements include 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,” “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, market share and contract terms, costs and availability of resources, economic and regulatory conditions, the on-going integration of BJ Services, and environmental matters are only our forecasts regarding these matters.

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

Risk Factors

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

INTEREST RATE RISK AND INDEBTEDNESS

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

Interest Rate Swap Agreements

In June 2009, we entered into two interest rate swap agreements (the “Swap Agreements”) for a notional amount of $250 million each in order to hedge changes in the fair market value of our $500 million 6.5% senior notes maturing on November 15, 2013. Under the Swap Agreements, we receive interest at a fixed rate of 6.5% and pay interest at a floating rate of one-month Libor plus a spread of 3.67% on one swap and three-month Libor plus a spread of 3.54% on the second swap both through November 15, 2013. The Swap Agreements are designated, and each qualifies, as a fair value hedging instrument. The fair value of the Swap Agreements at December 31, 2010, was a $24 million asset and was based on quoted market prices for contracts with similar terms and maturity dates.

The financial institutions that are counterparties to the Swap Agreements are primarily the lenders in our credit facilities. Under the terms of the credit support documents governing the Swap Agreements, the relevant party will have to post collateral in the event such party’s long-term debt rating falls below investment grade or is no longer rated.

Indebtedness

We had fixed rate debt aggregating $3,800 million at December 31, 2010 and $1,800 million at December 31, 2009. The following table sets forth the required cash payments for our indebtedness, which bear a fixed rate of interest and are denominated in U.S. Dollars, and the related weighted average effective interest rates by expected maturity dates as of December 31, 2010 and 2009.


(Dollars in millions)	2010		2011			2012		2013			2014		2015		Thereafter			Total

As of December 31, 2010 Long-term debt ^{(1) (2)}	$	—	$	250		$	—	$	500		$	—	$	—	$	3,050		$	3,800
Weighted average effective interest rates				5.86	%				6.73	%						6.31	%		6.34	%

As of December 31, 2009 Long-term debt ^{(1) (2)}	$	—	$	—		$	—	$	500		$	—	$	—	$	1,300		$	1,800
Weighted average effective interest rates									6.73	%						7.58	%		7.34	%


⁽¹⁾		Amounts do not include any unamortized discounts, deferred issuance costs or net deferred gains on terminated interest rate swap agreements.

⁽²⁾		Fair market value of fixed rate long-term debt was $4,218 million at December 31, 2010 and $2,111 million at December 31, 2009.

FOREIGN CURRENCY AND FOREIGN CURRENCY FORWARD CONTRACTS

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

Foreign Currency Forward Contracts

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

At December 31, 2009, we had outstanding foreign currency forward contracts with notional amounts aggregating $153 million to hedge exposure to currency fluctuations in various foreign currencies. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of December 31, 2009 for contracts with similar terms and maturity dates, we recorded a loss of $1 million to adjust these foreign currency forward contracts to their fair market value. This loss offsets designated foreign currency exchange gains resulting from the underlying exposures and is included in MG&A expenses in the consolidated statement of operations.

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. Our control environment is the foundation for our system of internal control and is embodied in our Business Code of Conduct, which sets the tone of our Company and includes our Core Values of Integrity, Teamwork, Performance and Learning. Included in our system of internal control are written policies, an organizational structure providing division of responsibilities, the selection and training of qualified personnel and a program of financial and operations reviews by a professional staff of internal auditors. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our 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 (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting. Our evaluation was based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Based on our evaluation under the framework in Internal Control – Integrated Framework, our principal executive officer and principal financial officer concluded that our internal control over financial reporting was effective as of December 31, 2010. The conclusion of our principal executive officer and principal financial officer 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.

On April 28, 2010, the Company acquired BJ Services Company (“BJ Services”). For purposes of determining the effectiveness of our internal control over financial reporting, management has excluded BJ Services from its evaluation of these matters. The acquired business represented approximately 46% of our consolidated total assets at December 31, 2010 and approximately 36% of our consolidated net income attributable to Baker Hughes for the year ended December 31, 2010.

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/ CHAD C. DEATON	/s/ PETER A. RAGAUSS	/s/ ALAN J. KEIFER
Chad C. Deaton	Peter A. Ragauss	Alan J. Keifer
Chairman and	Senior Vice President and	Vice President and
Chief Executive Officer	Chief Financial Officer	Controller

Houston, Texas
February 23, 2011

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Baker Hughes Incorporated
Houston, Texas

We have audited the internal control over financial reporting of Baker Hughes Incorporated and subsidiaries (the “Company”) as of December 31, 2010, 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 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 the Company’s internal control over financial reporting based on our audit.

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

A company’s internal control over financial reporting is a process designed 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 Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As described in Management’s Report on Internal Control Over Financial Reporting, the Company acquired BJ Services Company (“BJ Services”) on April 28, 2010. For the purpose of assessing internal control over financial reporting, management excluded BJ Services, whose financial statements constitute 46% of consolidated total assets and 36% of consolidated net income attributable to Baker Hughes of the consolidated financial statements as of and for the year ended December 31, 2010. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of BJ Services.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule II as of and for the year ended December 31, 2010 of the Company and our report dated February 23, 2011 expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.

Houston, Texas
February 23, 2011

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, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included financial statement schedule II, valuation and qualifying accounts, listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedule based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Baker Hughes Incorporated and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, 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.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.

Houston, Texas
February 23, 2011

Baker Hughes Incorporated
Consolidated Balance Sheets
(In millions, except par value)


	December 31,
	2010			2009

ASSETS

Current Assets:
Cash and cash equivalents	$	1,456		$	1,595
Short-term investments		250			—
Accounts receivable — less allowance for doubtful accounts (2010 - $162; 2009 - $157)		3,942			2,331
Inventories, net		2,594			1,836
Deferred income taxes		234			268
Other current assets		231			195

Total current assets		8,707			6,225


Property, plant and equipment — less accumulated depreciation (2010 - $4,367; 2009 - $3,668)		6,310			3,161
Goodwill		5,869			1,418
Intangible assets, net		1,569			195
Other assets		531			440

Total assets	$	22,986		$	11,439


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Accounts payable	$	1,496		$	821
Short-term borrowings and current portion of long-term debt		331			15
Accrued employee compensation		589			448
Income taxes payable		219			95
Other accrued liabilities		504			234

Total current liabilities		3,139			1,613


Long-term debt		3,554			1,785
Deferred income taxes and other tax liabilities		1,360			309
Liabilities for pensions and other postretirement benefits		483			379
Other liabilities		164			69
Commitments and contingencies

Stockholders’ Equity:
Common stock, one dollar par value (shares authorized - 750; issued and outstanding: 2010 - 432; 2009 - 312)		432			312
Capital in excess of par value		7,005			874
Retained earnings		7,083			6,512
Accumulated other comprehensive loss		(420	)		(414	)

Baker Hughes stockholders’ equity		14,100			7,284
Noncontrolling interest		186			—

Total stockholders’ equity		14,286			7,284

Total liabilities and stockholders’ equity	$	22,986		$	11,439

See Notes to Consolidated Financial Statements

Baker Hughes Incorporated
Consolidated Statements of Stockholders’ Equity
(In millions, except per share amounts)


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

Balance, December 31, 2007	$	316		$	1,216		$	4,818		$	(44	)	$	—	$	6,306
Adoption of ASC 715, Compensation — Retirement Benefits								(4	)							(4	)

Adjusted beginning balance January 1, 2008		316			1,216			4,814			(44	)		—		6,302
Comprehensive income:
Net income								1,635
Foreign currency translation adjustments											(354	)
Defined benefit pension plans, net of tax of $67											(125	)
Total comprehensive income																1,156
Issuance of common stock, pursuant to employee stock plans		2			76											78
Tax benefit on stock plans					11											11
Stock-based compensation					60											60
Repurchase and retirement of common stock		(9	)		(618	)										(627	)
Cash dividends ($0.56 per share)								(173	)							(173	)

Balance, December 31, 2008		309			745			6,276			(523	)		—		6,807
Comprehensive income:
Net income								421
Foreign currency translation adjustments											122
Defined benefit pension plans, net of tax of $2											(13	)
Total comprehensive income																530
Issuance of common stock, pursuant to employee stock plans		3			43											46
Tax provision on stock plans					(2	)										(2	)
Stock-based compensation					88											88
Cash dividends ($0.60 per share)								(185	)							(185	)

Balance, December 31, 2009		312			874			6,512			(414	)		—		7,284
Comprehensive income:
Net income								812						7
Foreign currency translation adjustments											(41	)
Defined benefit pension plans, net of tax of $5											35
Total comprehensive income																813
Issuance of common stock, to acquire BJ Services		118			5,986											6,104
Issuance of common stock, pursuant to employee stock plans		2			60											62
Tax provision on stock plans					(2	)										(2	)
Stock-based compensation					87											87
Cash dividends ($0.60 per share)								(241	)							(241	)
Acquisition of noncontrolling interest														179		179

Balance, December 31, 2010	$	432		$	7,005		$	7,083		$	(420	)	$	186	$	14,286

See Notes to Consolidated Financial Statements

Baker Hughes Incorporated
Consolidated Statements of Cash Flows
(In millions, except per share amounts)


	Year Ended December 31,
	2010			2009			2008

Cash flows from operating activities:
Net income	$	819		$	421		$	1,635
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		1,069			711			637
(Gain) loss on investments		(6	)		(4	)		25
Stock-based compensation		87			88			60
Benefit for deferred income taxes		(188	)		(256	)		(21	)
Gain on sale of product line		—			—			(28	)
Gain on disposal of assets		(113	)		(64	)		(101	)
Provision for doubtful accounts		39			94			31
Changes in operating assets and liabilities:
Accounts receivable		(702	)		399			(515	)
Inventories		(243	)		240			(371	)
Accounts payable		292			(89	)		242
Accrued employee compensation and other accrued liabilities		(182	)		(130	)		90
Income taxes payable		23			(169	)		76
Liabilities for pensions and other postretirement benefits and other liabilities		(16	)		13			(38	)
Other		(23	)		(15	)		(108	)

Net cash flows from operating activities		856			1,239			1,614


Cash flows from investing activities:
Expenditures for capital assets		(1,491	)		(1,086	)		(1,303	)
Proceeds from disposal of assets		208			163			222
Proceeds from sale of businesses, net of disposal costs, and interests in affiliates		39			—			31
Acquisition of businesses, net of cash acquired		(888	)		(58	)		(120	)
Proceeds from sale/settlement of investments		6			15			—
Purchase of short-term investments		(250	)		—			—

Net cash flows from investing activities		(2,376	)		(966	)		(1,170	)


Cash flows from financing activities:
Net proceeds (payments) of commercial paper and other short-term debt		52			(16	)		15
Net proceeds from issuance of long-term debt		1,479			—			1,235
Repayment of long-term debt		—			(525	)		—
Proceeds from issuance of common stock		74			51			87
Repurchase of common stock		—			—			(627	)
Dividends		(241	)		(185	)		(173	)
Excess tax benefits from stock-based compensation		2			—			4

Net cash flows from financing activities		1,366			(675	)		541


Effect of foreign exchange rate changes on cash		15			42			(84	)

(Decrease) increase in cash and cash equivalents		(139	)		(360	)		901
Cash and cash equivalents, beginning of year		1,595			1,955			1,054

Cash and cash equivalents, end of year	$	1,456		$	1,595		$	1,955


Supplemental cash flows disclosures:
Income taxes paid	$	637		$	604		$	621
Interest paid	$	154		$	154		$	86
Supplemental disclosure of noncash investing activities:
Capital expenditures included in accounts payable	$	64		$	29		$	43

See Notes to Consolidated Financial Statements

Baker Hughes Incorporated
Notes to Consolidated Financial Statements

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Baker Hughes Incorporated (“Baker Hughes”) is engaged in the oilfield services industry. We are a leading supplier of wellbore-related products and technology services and systems and provide products and services for drilling, pressure pumping, formation evaluation, completion and production, and reservoir technology and consulting to the worldwide oil and natural gas industry. We also provide products and services to the downstream refining, and process and pipeline industries.

Basis of Presentation

The consolidated financial statements include the accounts of Baker Hughes and all majority owned subsidiaries (“Company,” “we,” “our” or “us”). Investments over which we have the ability to exercise significant influence over operating and financial policies, but do not hold a controlling interest, are accounted for using the equity method of accounting. All significant intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Consolidated Financial Statements, all dollar and share amounts in tabulations are in millions of dollars and shares, respectively, unless otherwise indicated.

Use of Estimates

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

Revenue Recognition

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

Research and Engineering

Research and engineering expenses include costs associated with the research and development of new products and services and costs associated with sustaining engineering of existing products and services. These costs are expensed as incurred and include research and development costs for new products and services of $283 million, $231 million and $263 million for the year ended December 31, 2010, 2009 and 2008, respectively.

Cash Equivalents

All highly liquid investments with an original maturity of three months or less at the time of purchase are reported as cash equivalents.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Short-Term Investments

Short-term investments have an original maturity of greater than three months. As of December 31, 2010, we held $250 million of short-term investments consisting of U.S. Treasury Bills, which will mature in May of 2011. These investments are classified as available-for-sale and are recorded at fair value, which approximates cost.

Inventories

Inventories are stated at the lower of cost or market. Cost is determined using the first-in, first-out (“FIFO”) method or the average cost method, which approximates FIFO, and includes the cost of materials, labor and manufacturing overhead.

Property, Plant and Equipment and Accumulated Depreciation

Property, plant and equipment (“PP&E”) is stated at cost less accumulated depreciation, which is generally provided by using the straight-line method over the estimated useful lives of the individual assets. Significant improvements and betterments are capitalized if they extend the useful life of the asset. We manufacture a substantial portion of our rental tools and equipment and the cost of these items, which includes direct and indirect manufacturing costs, are capitalized and carried in inventory until the tool is completed. Once the tool has been completed, the cost of the tool is reflected in capital expenditures and the tool is classified as rental tools and equipment in PP&E. Maintenance and repairs are charged to expense as incurred. The capitalized costs of computer software developed or purchased for internal use are classified in machinery and equipment in PP&E.

Goodwill, Intangible Assets and Amortization

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

Impairment of Goodwill and Other Long-Lived Assets

We review PP&E, intangible assets and certain other assets for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows, excluding interest expense. The amount of impairment loss, if any, is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related assets.

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

Income Taxes

We use the liability method for determining our income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. 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. Future tax benefits are recognized to the extent that realization of such benefits is more likely than not.

Deferred income taxes are provided for the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities. Deferred tax assets are also provided for certain tax credit carryforwards. A valuation allowance to reduce deferred tax assets is established when it is more likely than not that some portion or all of the deferred tax assets will not be realized.

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

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

jurisdictions are taxed on various bases: actual income before taxes, deemed profits (which are generally determined using a percentage of revenues 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 tax jurisdiction could have an impact upon the amount of income taxes that we provide during any given year.

Our tax filings for various periods are subjected to audit by tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or through the courts. We believe that these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. We have received tax assessments from various tax authorities and are currently at varying stages of appeals and/or litigation regarding these matters. We have provided for the amounts we believe will ultimately result from these proceedings. We believe we have substantial defenses to the questions being raised and will pursue all legal remedies should an unfavorable outcome result. However, resolution of these matters involves uncertainties and there are no assurances that the outcomes will be favorable.

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. We believe such tax reserves are adequate in relation to the potential for additional assessments. We classify interest and penalties related to uncertain tax positions as income taxes in our financial statements.

Environmental Matters

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

Foreign Currency

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

Derivative Financial Instruments

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

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

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

New Accounting Standards and Accounting Standards Updates

In October 2009, the Financial Accounting Standards Board (“FASB”) issued an update to Accounting Standards Codification (“ASC”) 605, Revenue Recognition – Multiple Deliverable Revenue Arrangements. This Accounting Standards Update (“ASU”) addresses accounting for multiple-deliverable arrangements to enable vendors to account for deliverables separately. The provision establishes a selling price hierarchy for determining the selling price of a deliverable. This update requires expanded disclosures for multiple deliverable revenue arrangements. The ASU was effective for us for revenue arrangements entered into or materially modified on or after June 15, 2010. We adopted the provisions of this update with no material impact on our consolidated financial statements.

NOTE 2. ACQUISITIONS

ACQUISITION OF BJ SERVICES

On April 28, 2010, we acquired 100% of the outstanding common stock of BJ Services Company (including its successor, “BJ Services”) in a cash and stock transaction valued at $6,897 million. BJ Services is a leading provider of pressure pumping and other oilfield services and was acquired to expand our suite of service and product offerings. Revenues and net income of BJ Services from the acquisition date included in our consolidated statement of operations for 2010 were $3,686 million and $290 million, respectively.

Pursuant to a final agreement with the Antitrust Division of the U.S. Department of Justice (“DOJ”) in connection with the governmental approval of the acquisition, we were required to divest two leased stimulation vessels (the HR Hughes and Blue Ray) and certain other assets used to perform sand control services in the U.S. Gulf of Mexico. Additionally, pursuant to a Hold Separate Stipulation and Order, the operation of our U.S. business and the U.S. business of BJ Services were required to be operated separately until these assets were divested. On August 30, 2010, we completed the sale of such assets for approximately $55 million in cash. Upon the completion of the sale, the Hold Separate Stipulation and Order terminated, and we commenced integration activities on a global basis.

Consideration

Under the terms of the acquisition agreement, BJ Services stockholders received $2.69 per share in cash and 0.40035 Baker Hughes shares of common stock for each BJ Services share of common stock they owned. In total, we paid $793 million in cash and issued 118 million shares valued at $6,048 million (based upon the closing price of our common stock on the acquisition date of $51.24). We also assumed all outstanding stock options held by BJ Services employees and directors.

The BJ Services stock options outstanding at closing were converted into Baker Hughes options at the conversion ratio. The estimated fair value associated with the Baker Hughes options issued in exchange for the BJ Services options was $58 million based on a Black-Scholes valuation model. All BJ Services stock options became fully vested and exercisable in accordance with pre-existing change-in-control provisions. Accordingly, $56 million of the estimated fair value was recorded as part of the consideration transferred, with the remaining $2 million recorded as an expense as of the date of the acquisition when all options vested and no further service was required.

Total consideration transferred in acquiring BJ Services is summarized as follows:


Cash consideration paid: 295 million shares at $2.69	$	793
Equity consideration paid: 118 million shares valued $51.24		6,048
Fair value of BJ Services options assumed		56

Fair value of consideration transferred	$	6,897

Recording of Assets Acquired and Liabilities Assumed

The transaction has been accounted for using the acquisition method of accounting which requires that, among other things, assets acquired and liabilities assumed be recorded at their fair values as of the acquisition date. The excess of the consideration transferred over those fair values is recorded as goodwill. While we have substantially completed the determination of the fair values of the

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

assets acquired and liabilities assumed, some of the estimated fair values set forth below are subject to adjustment once the valuations are completed. We will finalize these items as we obtain the information necessary to complete the analysis, which we expect to be completed during the first quarter of 2011. Under U.S. generally accepted accounting principles, companies have one year from the date of an acquisition to finalize the acquisition accounting. The following table summarizes the estimated amounts recognized for assets acquired and liabilities assumed as of the acquisition date.


	Estimated Fair Value

Assets:
Cash and cash equivalents	$	113
Accounts receivable		951
Inventories		419
Other current assets		125
Property, plant and equipment		2,757
Intangible assets		1,404
Goodwill		4,336
Other long-term assets		109
Liabilities:
Liabilities for change in control and transaction fees		(210	)
Current liabilities		(759	)
Deferred income taxes and other tax liabilities		(1,455	)
Debt		(531	)
Pension and other postretirement liabilities		(154	)
Other long-term liabilities		(29	)
Noncontrolling interests		(179	)

Net Assets Acquired	$	6,897

Property, plant and equipment (“PP&E”)

A step-up adjustment of $418 million was recorded to present the PP&E acquired at its fair value. The weighted average useful life used to calculate depreciation of the step-up related to PPE is approximately six years.

Intangible assets

We identified intangible assets including trade names, technology, in-process research and development (“IPR&D”), and customer relationships. We consider the BJ Services trade name to be an indefinite life intangible asset, which will not be amortized and will be subject to an annual impairment test. We account for IPR&D as an indefinite-lived intangible asset until completion or abandonment of the associated project. Therefore, such assets would not be amortized but would be tested for impairment. Once the research and development activities are completed, the assets would be amortized over the related product’s useful life. If the project is abandoned, the assets would be written off if they have no alternative future use.

The following table summarizes the fair values recorded for the identifiable intangible assets and their estimated useful lives:


	Fair Value		Estimated Useful Life

Customer relationships	$	428	3-16 years
Technology		451	5-15 years
BJ Services trade name		360	Indefinite
Other trade names		38	5-12 years
IPR&D		127	Indefinite

Total Identifiable Intangible Assets	$	1,404

Deferred taxes

We provided deferred taxes and other tax liabilities as part of the acquisition accounting related to the fair market value adjustments for acquired intangible assets and PP&E, as well as for uncertain tax positions taken in prior year tax returns. An adjustment of $1,283 million was recorded to present the deferred taxes and other tax liabilities at fair value. Included in the adjustment is deferred taxes of $575 million for the outside basis difference associated with shares in certain BJ Services foreign

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

subsidiaries for which no taxes have been previously provided. We expect to reverse the outside basis difference primarily through repatriating earnings from those subsidiaries in lieu of permanently reinvesting them and through the reorganization of those subsidiaries. We are still assessing certain factors that impact the outside basis difference related to the BJ Services foreign subsidiaries and uncertain tax positions. The deferred tax liabilities and other tax liabilities will be revised after the assessment is finalized, which we expect to be completed during the first quarter of 2011.

Debt

Our acquisition subsidiary assumed all of the obligations of BJ Services in respect of $250 million principal amount of 5.75% senior notes due June 2011 and $250 million principal amount of 6.00% senior notes due June 2018. A step-up adjustment of $34 million was recorded to present these notes at fair value.

Liabilities for pensions and other postretirement benefits

We assumed several defined benefit pension plans covering certain employees primarily in the U.K., Norway and Canada. Additionally, we assumed a non-qualified supplemental executive retirement plan, as well as postretirement benefit plans that provide certain health care and life insurance benefits for retired employees, primarily in the U.S., who meet specified age and service requirements. A step-up adjustment of $32 million was recorded to present these liabilities at fair value.

The following is a summary of the funded position of the assumed BJ Services plans as of the acquisition date, as well as associated weighted-average assumptions used to determine benefit obligations:


			Other Postretirement
	Pension Benefit Plans		Benefit Plans

Projected benefit obligation	$	287	$	27
Fair value of plan assets		160		—

Net Unfunded Status	$	127	$	27

The following is a summary of the amounts recognized in the Consolidated Balance Sheet:
Liabilities for pensions and other postretirement benefits	$	127	$	27

Weighted average assumptions used to determine benefit obligations at the acquisition date and net periodic benefit cost from the acquisition date through December 31, 2010 are as follows:


				Other Postretirement
	Pension Benefit Plans			Benefit Plans

Discount rate		5.24	%		6.18	%
Rate of compensation increase		4.30	%		n/a

Noncontrolling Interests

In conjunction with our acquisition of BJ Services, we obtained certain entities which were not wholly owned by BJ Services. A step-up adjustment of $134 million was recorded as a preliminary estimate to present the noncontrolling interests in these entities at fair value. This estimate represents the noncontrolling interest’s share in the fair value of the net assets acquired, including its share of goodwill, and is subject to change once we obtain the information necessary to complete the valuation during the first quarter of 2011.

Goodwill

Goodwill of $4,336 million was recognized for this acquisition and is calculated as the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. It specifically includes the expected synergies and other benefits that we believe will result from combining the operations of BJ Services with the operations of Baker Hughes and any intangible assets that do not qualify for separate recognition such as the assembled workforce. We have allocated the goodwill to our reporting units based on the provisional amounts

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

recognized for the fair value of the assets acquired and liabilities assumed (See Note 10 - Goodwill and Intangible Assets). Goodwill in the amount of $43 million is deductible for tax purposes as a result of previous taxable acquisitions made by BJ Services.

Acquisition-Related Costs

Acquisition-related costs are being expensed as incurred. They include expenses directly related to acquiring BJ Services and integration expenses incurred in combining the companies. These costs are classified as acquisition-related costs on our consolidated statements of operations.

Pro Forma Impact of the Acquisition

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


	Year Ended December 31,
	2010		2009
	Pro Forma		Pro Forma

Revenues	$	15,903	$	13,301
Net income attributable to Baker Hughes	$	828	$	345
Net income attributable to Baker Hughes per share:
Basic	$	1.92	$	0.81
Diluted	$	1.91	$	0.80

OTHER ACQUISITIONS

During 2010, we completed several other acquisitions having an aggregate purchase price of approximately $208 million, net of cash acquired of $4 million. As a result of these acquisitions, we recorded $91 million of goodwill, which is subject to final acquisition accounting adjustments. Pro forma results of operations for these acquisitions have not been presented because the effect of these acquisitions was not material to our consolidated financial statements.

NOTE 3. GAIN ON SALE OF PRODUCT LINE

In February 2008, we sold the assets associated with our Surface Safety Systems (“SSS”) product line for $31 million and recorded a pre-tax gain of $28 million ($18 million after-tax). The SSS assets sold included hydraulic and pneumatic actuators, bonnet assemblies and control systems.

NOTE 4. SEGMENT INFORMATION

Baker Hughes operates under five reportable segments as detailed below. The four geographic segments represent our oilfield operations.

	•		North America (Canada, U.S., and Trinidad)

	•		Latin America (Central and South America including Mexico and excluding Trinidad)

	•		Europe/Africa/Russia Caspian (“EARC”) (Europe, Africa – excluding Egypt, and Russia and the republics of the former Soviet Union)

	•		Middle East/Asia Pacific (“MEAP”) (including Egypt)

	•		Industrial Services and Other (downstream chemicals, process and pipeline services, reservoir and technology consulting businesses)

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

During 2010, we changed our internal reporting structure to align with this new geographical and product line organization for which separate financial information is available and results are evaluated regularly by the Chief Operating Decision Makers (“CODM”). Accordingly, all prior period segment disclosures have been recast to reflect the new segments. The financial results of BJ Services have been included in each of the five reportable segments from the date of acquisition on April 28, 2010, through December 31, 2010, in a manner consistent with our internal reporting structure.

The performance of our segments is evaluated based on segment profit (loss), which is defined as income before income taxes, interest expense, interest income, and certain gains and losses not allocated to the segments.

Summarized financial information is shown in the following table:


	2010					2009					2008
Segments	Revenues		Profit (Loss)			Revenues		Profit (Loss)			Revenues		Profit (Loss)

North America	$	6,621	$	1,163		$	3,165	$	201		$	4,691	$	1,249
Latin America		1,569		74			1,094		78			1,089		196
Europe/Africa/Russia Caspian		3,006		260			2,774		458			3,209		629
Middle East/Asia Pacific		2,247		177			1,937		241			2,090		414
Industrial Services and Other		971		99			694		70			785		192

Total		14,414		1,773			9,664		1,048			11,864		2,680
Corporate and Other		—		(491	)		—		(437	)		—		(361	)

Total	$	14,414	$	1,282		$	9,664	$	611		$	11,864	$	2,319

For the years ended December 31, 2010, 2009 and 2008, there were no revenues attributable to one customer that accounted for more than 10% of total revenues.


	2010				2009				2008
			Depreciation				Depreciation				Depreciation
	Capital		and		Capital		and		Capital		and
Segments	Expenditures		Amortization		Expenditures		Amortization		Expenditures		Amortization

North America	$	589	$	432	$	275	$	255	$	374	$	246
Latin America		191		173		182		110		202		83
Europe/Africa/Russia Caspian		318		230		246		175		272		158
Middle East/Asia Pacific		208		187		185		143		168		112
Industrial Services and Other		179		44		196		17		285		15

Total		1,485		1,066		1,084		700		1,301		614
Corporate and Other		6		3		2		11		2		23

Total	$	1,491	$	1,069	$	1,086	$	711	$	1,303	$	637


Total Assets at December 31,	2010		2009		2008

North America	$	8,187	$	2,596	$	3,212
Latin America		2,723		1,168		1,031
Europe/Africa/Russia Caspian		3,544		2,248		2,456
Middle East/Asia Pacific		3,130		1,731		1,835
Industrial Services and Other		3,642		2,127		1,452

Total		21,226		9,870		9,986
Corporate and Other		1,760		1,569		1,875

Total	$	22,986	$	11,439	$	11,861

Assets of our supply chain and products and technology enterprise organizations are included in the Industrial Services and Other segment. Certain assets carried at the enterprise level that benefit the operating segments are allocated to the segments.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

The following table presents the details of “Corporate and Other” segment loss for the years ended December 31:


	2010			2009			2008

Corporate and other expenses	$	(222	)	$	(298	)	$	(240	)
Interest expense		(144	)		(131	)		(89	)
Interest and dividend income		3			6			27
Gain (loss) on investments		6			4			(25	)
Acquisition-related costs		(134	)		(18	)		—
Gain on sale of product line		—			—			28
Litigation settlement		—			—			(62	)

Total	$	(491	)	$	(437	)	$	(361	)

The following table presents the details of “Corporate and Other” total assets at December 31:


	2010		2009		2008

Cash and other assets	$	1,391	$	1,266	$	1,684
Accounts receivable		28		17		20
Current deferred tax asset		—		1		2
Property, plant and equipment		63		10		28
Other noncurrent assets		278		275		141

Total	$	1,760	$	1,569	$	1,875

The following table presents geographic consolidated revenues for the years ended December 31:


	2010		2009		2008

United States	$	6,043	$	3,091	$	4,512
Canada and other		1,186		493		666

North America		7,229		3,584		5,178
Latin America		1,583		1,134		1,127
Europe/Africa/Russia Caspian		3,218		2,925		3,386
Middle East/Asia Pacific		2,384		2,021		2,173

Total	$	14,414	$	9,664	$	11,864

The following table presents consolidated revenues for each group of similar products and services for the years ended December 31:


	2010		2009		2008

Completion and Production	$	8,547	$	4,454	$	5,094
Drilling and Evaluation		4,896		4,516		5,985
Industrial Services and Other		971		694		785

Total	$	14,414	$	9,664	$	11,864

The following table presents net property, plant and equipment by its geographic location at December 31:


	2010		2009		2008

United States	$	3,023	$	1,377	$	1,356
Canada and other		467		105		104

North America		3,490		1,482		1,460
Latin America		788		354		259
Europe/Africa/Russia Caspian		1,118		809		679
Middle East/Asia Pacific		914		516		435

Total	$	6,310	$	3,161	$	2,833

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

NOTE 5. STOCK-BASED COMPENSATION

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

The following table summarizes stock-based compensation costs for the years ended December 31, 2010, 2009 and 2008. There were no stock-based compensation costs capitalized as the amounts were not material.


	2010			2009			2008

Stock-based compensation costs	$	87		$	88		$	60
Tax benefit		(18	)		(15	)		(11	)

Stock-based compensation costs, net of tax	$	69		$	73		$	49

For our stock options and restricted stock awards and units, we currently have 25 million shares authorized for issuance and as of December 31, 2010, approximately 8.9 million shares were available for future grants. Our policy is to issue new shares for exercises of stock options, when restricted stock awards are granted, at vesting of restricted stock units, and issuances under the employee stock purchase plan.

Stock Options

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

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


	2010			2009			2008

Expected life (years)		5.0			6.0			5.5
Risk-free interest rate		2.2	%		2.6	%		3.1	%
Volatility		39.8	%		41.2	%		31.4	%
Dividend yield		1.2	%		1.8	%		0.8	%
Weighted average fair value per share at grant date	$	16.24		$	12.66		$	23.64

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

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


				Weighted Average
				Exercise Price
	Number of Options			Per Option

Outstanding at December 31, 2009		5,676		$	50.16
Granted		1,488			48.38
Assumed on acquisition of BJ Services		4,840			48.61
Exercised		(962	)		34.29
Forfeited		(86	)		43.74
Expired		(54	)		41.05

Outstanding at December 31, 2010		10,902		$	50.72

The total intrinsic value of stock options (defined as the amount by which the market price of our common stock on the date of exercise exceeds the exercise price of the option) exercised in 2010, 2009 and 2008 was $18 million, $0.4 million and $13 million, respectively. The income tax benefit realized from stock options exercised was $0.9 million, $0.1 million and $7 million in 2010, 2009 and 2008, respectively.

The total fair value of options vested in 2010, 2009 and 2008 was $20 million, $17 million and $17 million, respectively. As of December 31, 2010, there was $15 million of total unrecognized compensation cost related to nonvested stock options which is expected to be recognized over a weighted average period of two years.

The following table summarizes information about stock options outstanding as of December 31, 2010 (in thousands, except per option prices and remaining life):


	Outstanding						Exercisable
			Weighted						Weighted
			Average		Weighted				Average		Weighted
			Remaining		Average				Remaining		Average
			Contractual		Exercise				Contractual		Exercise
	Number of		Life		Price Per		Number of		Life		Price Per
Range of Exercise Prices	Options		(In years)		Option		Options		(In years)		Option

$ 14.79 – $16.78		3		2.8	$	15.84		3		2.8	$	15.84
24.94 – 35.81		2,601		5.6		28.97		2,036		4.9		28.88
39.23 – 56.21		5,272		6.2		47.51		3,061		4.1		49.12
65.11 – 86.50		3,026		4.8		75.07		2,836		4.7		75.18

Total		10,902		5.7	$	50.72		7,936		4.5	$	53.22

The total intrinsic value of stock options outstanding at December 31, 2010 was $124 million, of which $82 million relates to options vested and exercisable. The intrinsic value for stock options outstanding is calculated as the amount by which the quoted price of $57.17 of our common stock as of the end of 2010 exceeds the exercise price of the options.

Restricted Stock Awards and Units

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

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

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


				Weighted					Weighted
				Average					Average
	RSA			Grant Date		RSU			Grant Date
	Number of			Fair Value		Number of			Fair Value
	Shares			Per Share		Units			Per Unit

Nonvested balance at December 31, 2009		1,516		$	43.40		594		$	46.01
Granted		539			47.68		784			47.30
Vested		(577	)		48.21		(217	)		48.36
Forfeited		(79	)		43.78		(63	)		43.74

Nonvested balance at December 31, 2010		1,399		$	43.05		1,098		$	46.60

The weighted average grant date fair value per share for RSAs in 2010, 2009 and 2008 was $47.68, $31.18 and $72.82, respectively. The weighted average grant date fair value per unit for RSUs in 2010, 2009 and 2008 was $47.30, $31.54 and $75.96, respectively.

The total fair value of RSAs and RSUs vested in 2010, 2009 and 2008 was $36 million, $18 million and $30 million, respectively. As of December 31, 2010, there was $34 million and $33 million of total unrecognized compensation cost related to nonvested RSAs and RSUs, respectively, which is expected to be recognized over a weighted average period of two years.

Employee Stock Purchase Plan

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

We currently have 22.5 million shares authorized for issuance under the ESPP, and at December 31, 2010, there were 5.6 million shares reserved for future issuance under the ESPP. Compensation expense for the years ended December 31, was calculated using the Black-Scholes option pricing model with the following assumptions:


	2010			2009			2008

Expected life (years)		1.0			1.0			1.0
Risk-free interest rate		0.2	%		0.3	%		3.2	%
Volatility		44.2	%		69.5	%		32.8	%
Dividend yield		1.5	%		1.9	%		0.6	%

Fair value per share of the 15% cash discount	$	6.16		$	4.81		$	10.01
Fair value per share of the look-back provision		4.98			8.44			11.44

Total weighted average fair value per share at grant date	$	11.14		$	13.25		$	21.45

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

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

NOTE 6. INCOME TAXES

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


	2010			2009			2008

Current:
United States	$	179		$	65		$	292
Foreign		472			381			413

Total current		651			446			705

Deferred:
United States		(107	)		(210	)		(14	)
Foreign		(81	)		(46	)		(7	)

Total deferred		(188	)		(256	)		(21	)

Provision for income taxes	$	463		$	190		$	684

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


	2010		2009			2008

United States	$	534	$	(18	)	$	795
Foreign		748		629			1,524

Income before income taxes	$	1,282	$	611		$	2,319

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


	2010			2009			2008

Statutory income tax at 35%	$	449		$	214		$	812
Effect of foreign operations		(54	)		(53	)		(80	)
Net tax charge related to foreign losses		64			38			3
Adjustments of prior years tax positions		(35	)		(26	)		(50	)
State income taxes — net of U.S. tax benefit		19			6			19
Other — net		20			11			(20	)

Provision for income taxes	$	463		$	190		$	684

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, as well as operating loss and tax credit carryforwards. The tax effects of our temporary differences and carryforwards are as follows at December 31:


	2010			2009

Deferred tax assets:
Receivables	$	37		$	29
Inventory		213			233
Property		—			51
Employee benefits		120			131
Other accrued expenses		148			49
Operating loss carryforwards		186			76
Tax credit carryforwards		329			171
Capitalized research and development costs		4			8
Other		88			63

Subtotal		1,125			811
Valuation allowances		(232	)		(142	)

Total		893			669


Deferred tax liabilities:
Goodwill and other intangibles		578			142
Property		377			—
Undistributed earnings of foreign subsidiaries		583			64
Other		87			43

Total		1,625			249

Net deferred tax (liability) asset	$	(732	)	$	420

We record a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character in the future and in the appropriate taxing jurisdictions. We have provided a valuation allowance for operating loss and foreign tax credit carryforwards in certain non-U.S. jurisdictions. The majority of the $90 million net increase in the valuation allowance in 2010, represents net tax charges related to foreign losses. The operating loss carryforwards without a valuation allowance will expire in varying amounts over the next twenty years.

We have provided for U.S. and additional foreign taxes for the anticipated repatriation of certain earnings of our foreign subsidiaries. We consider the undistributed earnings of our foreign subsidiaries above the amount for which taxes have already been provided to be indefinitely reinvested, as we have no current intention to repatriate these earnings. As such, deferred income taxes are not provided for temporary differences of approximately $2.5 billion, $2.3 billion and $2.2 billion as of December 31, 2010, 2009 and 2008, respectively, representing earnings of non-U.S. subsidiaries intended to be permanently reinvested. These additional foreign earnings could become subject to additional tax if remitted, or deemed remitted, as a dividend. Computation of the potential deferred tax liability associated with these undistributed earnings and any other basis differences is not practicable.

At December 31, 2010, we had approximately $64 million of foreign tax credits which may be carried forward indefinitely under applicable foreign law and $263 million of foreign tax credits available to offset future payments of U.S. federal income taxes, primarily expiring in 2018 through 2020. In addition, at December 31, 2010, we had approximately $2 million of state tax credits expiring in varying amounts between 2016 and 2021.

As of December 31, 2010, we had $438 million of tax liabilities for gross unrecognized tax benefits, which includes liabilities for interest and penalties of $96 million and $18 million, respectively. If we were to prevail on all uncertain tax positions, the net effect would be a benefit to our effective tax rate of approximately $383 million. The remaining approximately $55 million is offset by deferred tax assets that represent tax benefits that would be received in different taxing jurisdictions in the event that we did not prevail on all uncertain tax positions.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

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


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

Balance at January 1, 2008	$	363		$	94		$	457
Increase (decrease) in prior year tax positions		(7	)		10			3
Increase in current year tax positions		17			5			22
Decrease related to settlements with taxing authorities		(24	)		(10	)		(34	)
Decrease related to lapse of statute of limitations		(20	)		(17	)		(37	)
Decrease due to effects of foreign currency translation		(6	)		(4	)		(10	)

Balance at January 1, 2009		323			78			401
Increase (decrease) in prior year tax positions		(75	)		10			(65	)
Increase in current year tax positions		16			6			22
Decrease related to settlements with taxing authorities		(6	)		(2	)		(8	)
Decrease related to lapse of statute of limitations		(9	)		(4	)		(13	)
Increase due to effects of foreign currency translation		1			1			2

Balance at January 1, 2010		250			89			339
Acquisition of BJ Services		102			28			130
Increase (decrease) in prior year tax positions		(16	)		4			(12	)
Increase in current year tax positions		4			3			7
Decrease related to settlements with taxing authorities		(7	)		(5	)		(12	)
Decrease related to lapse of statute of limitations		(6	)		(1	)		(7	)
Increase due to effects of foreign currency translation		(3	)		(4	)		(7	)

Balance at December 31, 2010	$	324		$	114		$	438

It is expected that the amount of unrecognized tax benefits will change in the next twelve months due to expiring statutes, audit activity, tax payments, competent authority proceedings related to transfer pricing, or final decisions in matters that are the subject of litigation in various taxing jurisdictions in which we operate. At December 31, 2010, we had approximately $239 million of tax liabilities, net of $40 million of tax assets, related to uncertain tax positions, each of which are individually insignificant, and each of which are reasonably possible of being settled within the next twelve months primarily as the result of audit settlements or statute expirations in several taxing jurisdictions.

At December 31, 2010, approximately $159 million of gross unrecognized tax benefits were included in the non-current portion of our income tax liabilities, for which the settlement period cannot be determined; however, it is not expected to be within the next twelve months.

We operate in over 80 countries and are subject to income taxes in most taxing jurisdictions in which we operate. The following table summarizes the earliest tax years that remain subject to examination by the major taxing jurisdictions in which we operate. These jurisdictions are those we project to have the highest tax liability for 2011.


Jurisdiction	Earliest Open Tax Period		Jurisdiction	Earliest Open Tax Period

Canada		1998	Norway		1999
Germany		2003	United Kingdom		2004
Netherlands		1999	United States		2002

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

NOTE 7. EARNINGS PER SHARE

A reconciliation of the number of shares used for the basic and diluted EPS computations is as follows for the years ended December 31:


	2010		2009		2008

Weighted average common shares outstanding for basic EPS		394		310		307
Effect of dilutive securities — stock plans		1		1		2

Adjusted weighted average common shares outstanding for diluted EPS		395		311		309


Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than the average market price for the period		7		4		2

NOTE 8. INVENTORIES

Inventories, net of reserves of $322 million and $297 million in 2010 and 2009, respectively, are comprised of the following at December 31:


	2010		2009

Finished goods	$	2,283	$	1,570
Work in process		181		126
Raw materials		130		140

Total	$	2,594	$	1,836

NOTE 9. PROPERTY, PLANT AND EQUIPMENT

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


	Depreciation
	Period	2010			2009

Land		$	191		$	81
Buildings and improvements	5 - 30 years		1,605			1,136
Machinery and equipment	3 - 20 years		6,409			3,384
Rental tools and equipment	1 - 15 years		2,472			2,228

Subtotal			10,677			6,829
Accumulated depreciation			(4,367	)		(3,668	)

Total		$	6,310		$	3,161

NOTE 10. GOODWILL AND INTANGIBLE ASSETS

In connection with the change in our reportable segments as discussed in Note 4 – Segment Information, we reallocated the goodwill that existed as of March 31, 2010 to the new reportable segments on a relative fair value basis. Goodwill of $4,336 million was recognized for the BJ Services acquisition (See Note 2 – Acquisitions) which has been allocated to our reporting units based on the provisional amounts recognized for the fair value of the assets acquired and liabilities assumed.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

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


											Europe/			Middle		Industrial
	Drilling			Completion							Africa/			East/		Services
	and			and			North		Latin		Russia			Asia		and
	Evaluation			Production			America		America		Caspian			Pacific		Other		Total

Balance as of December 31, 2009	$	979		$	439		$	—	$	—	$	—		$	—	$	—	$	1,418

Reallocation for change in segments		(980	)		(439	)		486		173		407			263		90		—
Acquisitions		—			—			2,229		706		531			629		332		4,427
Other adjustments		1			—			16		—		(2	)		3		6		24

Balance as of December 31, 2010	$	—		$	—		$	2,731	$	879	$	936		$	895	$	428	$	5,869

We perform an annual impairment test of goodwill as of October 1 of every year. There were no impairments of goodwill in 2010, 2009 or 2008 related to the annual impairment test.

Intangible assets are comprised of the following at December 31:


	2010							2009
	Gross							Gross
	Carrying		Accumulated					Carrying		Accumulated
	Amount		Amortization			Net		Amount		Amortization			Net

Definite lived intangibles:
Technology	$	760	$	(181	)	$	579	$	278	$	(141	)	$	137
Contract-based		20		(11	)		9		13		(9	)		4
Trade names		84		(18	)		66		36		(13	)		23
Customer relationships		495		(39	)		456		41		(10	)		31

Subtotal		1,359		(249	)		1,110		368		(173	)		195

Indefinite lived intangibles:
Trade name		360		—			360		—		—			—
IPR&D		99		—			99		—		—			—

Total	$	1,818	$	(249	)	$	1,569	$	368	$	(173	)	$	195

Intangible assets are amortized either on a straight-line basis with estimated useful lives ranging from 1 to 20 years, or on a basis that reflects the pattern in which the economic benefits of the intangible assets are expected to be realized, which range from 15 to 30 years. As a result of the acquisition of BJ Services, we recognized intangible assets of $1,404 million (See Note 2 – Acquisitions).

Amortization expense included in net income for the years ended December 31, 2010, 2009 and 2008 was $76 million, $31 million and $20 million, respectively. Estimated amortization expense for each of the subsequent five fiscal years is expected to be as follows: 2011 – $100 million; 2012 – $107 million; 2013 – $108 million; 2014 – $107 million; and 2015 – $99 million.

NOTE 11. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

Our financial instruments include cash and short-term investments, accounts receivable, accounts payable, debt, foreign currency forward contracts, foreign currency option contracts and interest rate swaps. Except as described below, the estimated fair value of such financial instruments at December 31, 2010 and 2009 approximates their carrying value as reflected in our consolidated balance sheets. The fair value of our debt, foreign currency forward contracts and interest rate swaps has been estimated based on quoted year end market prices.

Short-Term Investments

During the year ended December 31, 2010, we purchased $250 million of short-term investments consisting of U.S. Treasury Bills, which will mature in May of 2011.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Debt

The estimated fair value of total debt at December 31, 2010 and 2009 was $4,298 million and $2,126 million, respectively, which differs from the carrying amounts of $3,885 million and $1,800 million, respectively, included in our consolidated balance sheets.

Foreign Currency Forward Contracts

We conduct our business in over 80 countries around the world, and we are exposed to market risks resulting from fluctuations in foreign currency exchange rates. A number of our significant foreign subsidiaries have designated the local currency as their functional currency. We transact in various foreign currencies and have established a program that primarily utilizes foreign currency forward contracts to reduce the risks associated with the effects of certain foreign currency exposures. Under this program, our strategy is to have gains or losses on the foreign currency forward contracts mitigate the foreign currency transaction gains or losses to the extent practical. These foreign currency exposures typically arise from changes in the value of assets and liabilities which are denominated in currencies other than the functional currency. Our foreign currency forward contracts generally settle within 90 days. We do not use these forward contracts for trading or speculative purposes. We designate these forward contracts as fair value hedging instruments and, accordingly, we record the fair value of these contracts as of the end of our reporting period to our consolidated balance sheet with changes in fair value recorded in our consolidated statement of operations along with the change in fair value of the hedged item.

At December 31, 2010 and 2009, we had outstanding foreign currency forward contracts with notional amounts aggregating $156 million and $153 million, respectively, to hedge exposure to currency fluctuations in various foreign currencies. These contracts are designated and qualify as fair value hedging instruments. The fair value was determined using a model with Level 2 inputs including quoted market prices for contracts with similar terms and maturity dates.

Interest Rate Swaps

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

In June 2009, we entered into two interest rate swap agreements (“the Swap Agreements”) for a notional amount of $250 million each in order to hedge changes in the fair market value of our $500 million 6.5% senior notes maturing on November 15, 2013. Under the Swap Agreements, we receive interest at a fixed rate of 6.5% and pay interest at a floating rate of one-month Libor plus a spread of 3.67% on one swap and three-month Libor plus a spread of 3.54% on the second swap both through November 15, 2013. The counterparties are primarily the lenders in our credit facilities. The Swap Agreements are designated and each qualifies as a fair value hedging instrument. The swap to three-month Libor is deemed to be 100 percent effective resulting in no gain or loss recorded in the consolidated statement of operations. The effectiveness of the swap to one-month Libor, which is highly effective, is calculated as of each period end and any ineffective portion is recognized in the consolidated statement of operations. The fair value of the Swap Agreements was determined using a model with Level 2 inputs including quoted market prices for contracts with similar terms and maturity dates.

Fair Value of Derivative Instruments

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


		2010		2009
Derivative	Balance Sheet Location	Fair Value

Foreign Currency Forward Contracts	Other accrued liabilities	$	2	$	1
Interest Rate Swaps	Other assets		24		7

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

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


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

Foreign Currency Forward Contracts	Marketing, general and administrative	$	(7	)	$	11
Interest Rate Swaps	Interest expense	$	16		$	6

Concentration of Credit Risk

We sell our products and services to numerous companies in the oil and natural gas industry. Although this concentration could affect our overall exposure to credit risk, we believe that our risk is minimized since the majority of our business is conducted with major companies within the industry. We perform periodic credit evaluations of our customers’ financial condition and generally do not require collateral for our accounts receivable. In some cases, we will require payment in advance or security in the form of a letter of credit or bank guarantee.

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

NOTE 12. INDEBTEDNESS

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


	2010		2009

5.75% Notes due June 2011 with an effective interest rate of 5.86%	$	254	$	—
6.50% Senior Notes due November 2013 with an effective interest rate of 6.73%		522		504
6.00% Notes due June 2018 with an effective interest rate of 6.29%		267		—
7.50% Senior Notes due November 2018 with an effective interest rate of 7.61%		742		741
8.55% Debentures due June 2024 with an effective interest rate of 8.76%		148		148
6.875% Notes due January 2029 with an effective interest rate of 7.08%		393		392
5.125% Notes due September 2040 with an effective interest rate of 5.22%		1,479		—
Other debt		80		15

Total debt		3,885		1,800
Less short-term debt and current maturities of long-term debt		331		15

Long-term debt	$	3,554	$	1,785

On March 19, 2010, we entered into a credit agreement (the “2010 Credit Agreement”). The 2010 Credit Agreement is a three-year committed $1.2 billion revolving credit facility that expires on March 19, 2013. At December 31, 2010, we had $1.7 billion of committed revolving credit facilities with commercial banks, consisting of the 2010 Credit Agreement ($1.2 billion) and a $500 million facility expiring on July 7, 2012. Both facilities contain certain covenants which, among other things, require the maintenance of a funded indebtedness to total capitalization ratio (a defined formula per each agreement), 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 facilities may be accelerated. Such events of default include payment defaults to lenders under the facilities, covenant defaults and other customary defaults. At December 31, 2010, we were in compliance with all of the covenants of both committed credit facilities. There were no direct borrowings under the committed credit facilities during 2010. We also have an outstanding commercial paper program under which we may issue from time to time up to $1.0 billion in commercial paper with maturity of no more than 270 days. To the extent we have commercial paper outstanding, our ability to borrow under the facilities is reduced. At December 31, 2010, we had no outstanding commercial paper.

Concurrent with the acquisition of BJ Services, our acquisition subsidiary assumed and guaranteed the BJ Services outstanding notes, namely its $250 million principal amount of 5.75% senior notes due June 2011 and its $250 million principal amount of 6.00% senior notes due June 2018.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

On August 24, 2010, we sold $1,500 million of 5.125% Senior Notes that will mature September 15, 2040 (the “Notes”) under our Indenture dated as of October 28, 2008. Net proceeds from the offering were approximately $1,479 million 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 will use $250 million of the net proceeds to purchase U.S. Treasury Bills, which will be used to repay the BJ Services 5.75% senior notes maturing June 2011. The remaining net proceeds from the offering were used for general corporate purposes. Interest on the Notes is payable March 15 and September 15 of each year. The first interest payment will be made on March 15, 2011, and will consist of accrued interest from August 24, 2010. The Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to any future subordinated indebtedness; and effectively junior to our future secured indebtedness, if any, and structurally subordinated to all existing and future indebtedness of our subsidiaries. We may redeem, at our option, all or part of the Notes at any time, at the applicable make-whole redemption prices plus accrued and unpaid interest to the date of redemption.

Maturities of debt at December 31, 2010 are as follows: 2011 – $331 million; 2012 – $3 million; 2013 – $522 million; 2014 – $0 million; 2015 – $0 Million; and $3,029 million thereafter.

NOTE 13. EMPLOYEE BENEFIT PLANS

DEFINED BENEFIT PLANS

We have both funded and unfunded noncontributory defined benefit pension plans (“Pension Benefits”) covering certain employees primarily in the U.S., Canada, the U.K., Germany and several other countries in the Middle East and Asia Pacific region. Under the provisions of the U.S. qualified pension plan, a hypothetical cash balance account is established for each participant. Such accounts receive pay credits on a quarterly basis. The quarterly pay credit is based on a percentage according to the employee’s age on the last day of the quarter applied to quarterly eligible compensation. In addition to quarterly pay credits, a cash balance account receives interest credits based on the balance in the account on the last day of the quarter. The U.S. qualified pension plan also includes frozen accrued benefits for participants in legacy defined benefit plans. The Canada pension plan was frozen as of December 31, 2010, and we no longer accrue on a defined benefit basis. For the majority of the participants in the U.K. pension plans, we do not accrue benefits as the plans are frozen; however, there are a limited number of members who still accrue future benefits on a defined benefit basis. The Germany pension plan is an unfunded plan where benefits are based on creditable years of service, creditable pay and accrual rates. We also provide certain postretirement health care benefits (“other postretirement benefits”), through an unfunded plan, to substantially all U.S. employees who retire and have met certain age and service requirements.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Funded Status

Below is the reconciliation of the beginning and ending balances of benefit obligations, fair value of plan assets and the funded status of our plans. For our pension plans, the benefit obligation is the projected benefit obligation (“PBO”) and for our other post-retirement benefit plan, the benefit obligation is the accumulated postretirement benefit obligation (“APBO”).


							Non-U.S. Pension						Other Postretirement
	U.S. Pension Benefits						Benefits						Benefits
	2010			2009			2010			2009			2010			2009

Change in benefit obligation:
Benefit obligation at beginning of year	$	375		$	303		$	327		$	227		$	157		$	158
Service cost		32			29			8			3			10			8
Interest cost		22			20			26			15			9			10
Actuarial loss (gain)		31			51			4			49			10			(1	)
Benefits paid		(47	)		(19	)		(12	)		(7	)		(15	)		(13	)
Curtailment		—			(9	)		(1	)		(1	)		—			(5	)
Acquisitions of businesses		34			—			253			—			27			—
Plan amendments		—			—			—			—			(32	)		—
Other		(3	)		—			2			18			—			—
Exchange rate adjustments		—			—			(14	)		23			—			—

Benefit obligation at end of year		444			375			593			327			166			157


Change in plan assets:
Fair value of plan assets at beginning of year		346			290			248			197			—			—
Actual return on plan assets		48			77			36			24			—			—
Employer contributions		72			2			52			13			15			13
Benefits paid		(47	)		(19	)		(12	)		(7	)		(15	)		(13	)
Acquisitions of businesses		—			—			160			—			—			—
Other		(3	)		(4	)		1			(1	)		—			—
Exchange rate adjustments		—			—			(11	)		22			—			—

Fair value of plan assets at end of year		416			346			474			248			—			—



Funded status — underfunded at end of year	$	(28	)	$	(29	)	$	(119	)	$	(79	)	$	(166	)	$	(157	)


Accumulated benefit obligation	$	421		$	366		$	553		$	313		$	166		$	157

The amounts recognized in the consolidated balance sheet consist of the following as of December 31:


							Non-U.S. Pension						Other Postretirement
	U.S. Pension Benefits						Benefits						Benefits
	2010			2009			2010			2009			2010			2009

Noncurrent assets	$	—		$	—		$	10		$	—		$	—		$	—
Current liabilities		(3	)		(2	)		(5	)		(4	)		(16	)		(18	)
Noncurrent liabilities		(25	)		(27	)		(124	)		(75	)		(150	)		(139	)

Net amount recognized	$	(28	)	$	(29	)	$	(119	)	$	(79	)	$	(166	)	$	(157	)

The funded status position represents the difference between the benefit obligation and the plan assets. The PBO for pension benefits represents the actuarial present value of benefits attributed to employee services and compensation and includes an assumption about future compensation levels. The accumulated benefit obligation (“ABO”) is the actuarial present value of pension benefits attributed to employee service to date and present compensation levels. The ABO differs from the PBO in that the ABO does not include any assumptions about future compensation levels.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Information for the plans with ABOs in excess of plan assets is as follows at December 31:


									Other Postretirement
	U.S. Pension Benefits				Non-U.S. Pension Benefits				Benefits
	2010		2009		2010		2009		2010		2009

Projected benefit obligation	$	20	$	375	$	331	$	327		n/a		n/a
Accumulated benefit obligation		20		366		294		313	$	166	$	157
Fair value of plan assets		—		346		203		248		n/a		n/a

Weighted average assumptions used to determine benefit obligations for these plans are as follows for the years ended December 31:


							Non-U.S. Pension						Other Postretirement
	U.S. Pension Benefits						Benefits						Benefits
	2010			2009			2010			2009			2010			2009

Discount rate		4.9	%		5.9	%		5.5	%		5.6	%		4.9	%		5.9	%
Rate of compensation increase		5.4	%		4.0	%		4.3	%		4.1	%		n/a			n/a
Social security increase		2.8	%		3.5	%		2.9	%		3.1	%		n/a			n/a

The development of the discount rate for our U.S. plans was based on a bond matching model whereby a hypothetical bond portfolio of high-quality, fixed-income securities is selected that will match the cash flows underlying the projected benefit obligation. The discount rate assumption for our non-U.S. plans reflects the market rate for high-quality, fixed-income securities.

Accumulated Other Comprehensive Loss

The amounts recognized in accumulated other comprehensive loss consist of the following as of December 31:


					Non-U.S. Pension				Other Postretirement
	U.S. Pension Benefits				Benefits				Benefits
	2010		2009		2010		2009		2010			2009

Net loss	$	149	$	150	$	114	$	132	$	10		$	—
Net prior service cost (credit)		3		3		—		—		(31	)		2

Total	$	152	$	153	$	114	$	132	$	(21	)	$	2

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year are $14 million and $1 million, respectively. The estimated prior service credit for the other postretirement benefits that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year is $2 million.

Net Periodic Benefit Costs

The components of net periodic cost (benefit) are as follows for the years ended December 31:


	U.S. Pension Benefits									Non-U.S. Pension Benefits									Other Postretirement Benefits
	2010			2009			2008			2010			2009			2008			2010		2009		2008

Service cost	$	32		$	29		$	30		$	8		$	3		$	2		$	10	$	8	$	8
Interest cost		22			20			17			26			15			17			9		10		9
Expected return on plan assets		(28	)		(25	)		(38	)		(23	)		(15	)		(20	)		—		—		—
Amortization of prior service cost		—			1			—			—			—			—			1		1		1
Amortization of net loss		11			14			1			4			2			1			—		—		—
Curtailment		—			1			—			(1	)		—			—			—		—		—
Other		—			3			—			—			(1	)		(2	)		—		—		—

Net periodic cost (benefit)	$	37		$	43		$	10		$	14		$	4		$	(2	)	$	20	$	19	$	18

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Weighted average assumptions used to determine net periodic benefit costs for these plans are as follows for the years ended December 31:


	U.S. Pension Benefits									Non-U.S. Pension Benefits									Other Postretirement Benefits
	2010			2009			2008			2010			2009			2008			2010			2009			2008

Discount rate		5.9	%		6.3	%		6.3	%		5.6	%		6.4	%		5.7	%		5.9	%		6.3	%		6.3	%
Expected long-term return on plan assets		7.8	%		8.5	%		8.5	%		6.6	%		7.2	%		7.2	%		n/a			n/a			n/a
Rate of compensation increase		4.0	%		4.0	%		4.0	%		4.2	%		4.0	%		4.1	%		n/a			n/a			n/a
Social security increase		3.5	%		3.5	%		3.5	%		3.2	%		3.1	%		3.1	%		n/a			n/a			n/a

In selecting the expected rate of return on plan assets, we consider the average rate of earnings expected on the funds invested or to be invested to provide for the benefits of these plans. This includes considering the trusts’ asset allocation and the expected returns likely to be earned over the life of the plans.

Health Care Cost Trend Rates

Assumed health care cost trend rates have a significant effect on the amounts reported for other postretirement benefits. As of December 31, 2010, the health care cost trend rate was 8.0% for employees under age 65 and 6.5% for participants over age 65, with each declining gradually each successive year until it reaches 4.5% for both employees under age 65 and over age 65 in 2021. A one percentage point change in assumed health care cost trend rates would have had the following effects on 2010:


	One Percentage		One Percentage
	Point Increase		Point Decrease

Effect on total of service and interest cost components	$	0.3	$	(0.3	)
Effect on postretirement welfare benefit obligation		5.9		(5.6	)

Plan Assets – U.S. Pension Plan

We have investment committees that meet regularly to review the portfolio returns and to determine asset-mix targets based on asset/liability studies. Third-party investment consultants assist us in developing asset allocation strategies to determine our expected rates of return and expected risk for various investment portfolios. The investment committees considered these strategies in the formal establishment of the current asset-mix targets based on the projected risk and return levels for all major asset classes.

The investment policy of the U.S. pension plan (the “U.S. Plan”) was developed after examining the historical relationships of risk and return among asset classes and the relationship between the expected behavior of the U.S. Plan’s assets and liabilities. The investment policy of the U.S. Plan is designed to provide the greatest probability of meeting or exceeding the U.S. Plan’s objectives at the lowest possible risk.

In establishing its risk tolerance, the investment committee for the U.S. Plan (“U.S. Committee”) considers its ability to withstand short-term and intermediate-term volatility in market conditions. The U.S. Committee also reviews the long-term characteristics of various asset classes, focusing on balancing risk with expected return. Accordingly, the U.S. Committee selected the following four asset classes as allowable investments for the assets of the U.S. Plan: U.S. equities, Real Estate, U.S. fixed-income securities, and non-U.S. equities.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

The table below presents the fair values of the assets in the U.S. Plan by asset category and by levels of fair value as of December 31:


	2010								2009
	Total								Total
	Asset		Level		Level		Level		Asset		Level		Level		Level
Asset Category	Value		One		Two		Three		Value		One		Two		Three

Cash and Cash Equivalents	$	95	$	—	$	95	$	—	$	—	$	—	$	—	$	—
Fixed Income (a)		99		—		99		—		95		—		95		—
Non-U.S. Equity (b)		93		—		93		—		78		—		78		—
U.S. Small Cap Equity (c)		50		—		50		—		55		—		55		—
S&P500 Index Fund (d)		1		—		1		—		48		—		48		—
U.S. Large Cap Growth Equity (e)		34		—		34		—		30		—		30		—
U.S. Large Cap Value Equity (f)		26		—		26		—		23		—		23		—
Real Estate Fund (g)		14		—		—		14		13		—		—		13
Real Estate Investment Trust Equity		4		—		4		—		4		—		4		—

Total	$	416	$	—	$	402	$	14	$	346	$	—	$	333	$	13


(a)		A pooled fund with a strategy of investing in fixed income securities. The current allocation includes: 35% in corporate bonds; 24% in government bonds; 16% in government agencies; 10% in asset-backed securities; 8% in government mortgage-backed securities; and 7% in cash.

(b)		Multi-manager strategy investing in common stocks of non-U.S. listed companies using both value and growth approaches.

(c)		Multi-manager strategy investing in common stocks of smaller U.S. listed companies using both value and growth approaches.

(d)		A passively managed commingled fund investing in common stocks of the S&P 500 Index.

(e)		Multi-manager growth strategy investing in common stocks of U.S. listed, large capitalization companies.

(f)		Multi-manager value strategy investing in common stocks of U.S. listed, large capitalization companies.

(g)		Commingled fund investing in a diversified portfolio of U.S. based properties. The current allocation includes: 30% Apartments, 27% Office, 24% Retail, 11% Industrial and 8% Hotel.

Plan Assets – Non-U.S. Pension Plans

The investment policies of our pension plans with plan assets, which are primarily in Canada and the U.K., (the “Non-U.S. Plans”) cover the asset allocations that the governing boards believe are the most appropriate for these Non-U.S. Plans in the long term, taking into account the nature of the liabilities they expect to incur. The suitability of asset allocations and investment policies are reviewed periodically to ensure alignment with plan liabilities.

The table below presents the fair values of the assets in our Non-U.S. Plans by asset category and by levels of fair value as of December 31:


	2010								2009
	Total								Total
	Asset		Level		Level		Level		Asset		Level		Level		Level
Asset Category	Value		One		Two		Three		Value		One		Two		Three

Cash and Cash Equivalents	$	31	$	—	$	31	$	—	$	10	$	—	$	10	$	—
Asset Allocation (a)		80		—		80		—		—		—		—		—
Bonds — U.K. — Corporate (b)		40		—		40		—		39		—		39		—
Bonds — U.K. — Government (c)		114		—		114		—		51		—		51		—
Equities (d)		174		—		174		—		122		—		122		—
Property — U.K. (e)		19		—		—		19		19		—		—		19
Insurance contracts		16		—		—		16		7		—		—		7

Total	$	474	$	—	$	439	$	35	$	248	$	—	$	222	$	26


(a)		Invests in mixes of global common stocks and bonds to achieve broad diversification.

(b)		Invests passively in Sterling-denominated investment grade corporate bonds.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)


(c)		Invests passively in Sterling-denominated government issued bonds.

(d)		Invests in broad equity funds based on securities offered in various regions or countries. Equity funds are allocated by region as follows: 47% Global, 25% U.K., 8% North America, 8% Asia Pacific, 7% Europe, excluding the U.K., 3% U.S., and 2% Canada Small Cap.

(e)		Invests in a diversified range of property throughout the U.K., principally in the retail, office and industrial/warehouse sectors.

The following table presents the changes in the fair value of assets using Level 3 unobservable inputs:


				Non-U.S.		Non-U.S.
	U.S. Property			Property		Insurance
	Fund			Fund		Contracts			Total

Beginning balance at January 1, 2009	$	19		$	18	$	7		$	44
Unrealized gains (losses)		(6	)		1		1			(4	)
Net sales		—			—		(1	)		(1	)

Ending balance at December 31, 2009	$	13		$	19	$	7		$	39
Unrealized gains		1			—		—			1
Net purchases		—			—		9			9

Ending balance at December 31, 2010	$	14		$	19	$	16		$	49

Expected Cash Flows

For all pension plans, we make annual contributions to the plans in amounts equal to or greater than amounts necessary to meet minimum governmental funding requirements. In 2011, we expect to contribute between $40 million and $50 million to our U.S. pension plans and between $25 million and $35 million to the non-U.S. pension plans. In 2011, we also expect to make benefit payments related to postretirement welfare plans of between $16 million and $18 million.

The following table presents the expected benefit payments over the next ten years. The U.S. and non-U.S. pension benefit payments are made by the respective pension trust funds. The other postretirement benefits are net of expected Medicare subsidies of approximately $2 million per year and are payments that are expected to be made by us.


					Other
	U.S. Pension		Non-U.S. Pension		Postretirement
Year	Benefits		Benefits		Benefits

2011	$	24	$	15	$	17
2012		27		15		16
2013		30		17		16
2014		33		19		16
2015		36		21		17
2016-2020		220		121		90

DEFINED CONTRIBUTION PLANS

During the periods reported, generally all of our U.S. employees were eligible to participate in our sponsored Thrift Plans, which are 401(k) plans under the Internal Revenue Code of 1986, as amended (“the Code”). The Thrift Plans allow eligible employees to elect to contribute portions of their salaries to an investment trust. Employee contributions are matched by the Company in cash at the rate of $1.00 per $1.00 employee contribution for the first 5% to 6% of the employee’s salary and such contributions vest immediately. In addition, we make cash contributions for all eligible employees between 2% and 5% of their salary depending on the employee’s age. Such contributions are fully vested to the employee after three years of employment. The Thrift Plans provide several investment options, for which the employee has sole investment discretion. The Thrift Plans do not offer Baker Hughes common stock as an investment option. Our contributions to the Thrift Plans and several other non-U.S. defined contribution plans amounted to $169 million, $129 million and $137 million in 2010, 2009 and 2008, respectively.

For certain non-U.S. employees who are not eligible to participate in the Thrift Plan, we provide a non-qualified defined contribution plan that provides basically the same benefits as the Thrift Plan. In addition, we provide a non-qualified supplemental retirement plan (“SRP”) for certain officers and employees whose benefits under the Thrift Plan and/or the U.S. defined benefit pension plan are limited by federal tax law. The SRP also allows the eligible employees to defer a portion of their eligible compensation and provides for employer matching and base contributions pursuant to limitations. Both non-qualified plans are

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

invested through trusts, and the assets and corresponding liabilities are included in our consolidated balance sheet. Our contributions to these non-qualified plans were $11 million, $11 million and $9 million for 2010, 2009 and 2008, respectively.

In 2011, we estimate we will contribute between $185 million and $200 million to our defined contribution plans, which is an increase from prior years due to the acquisition of BJ Services.

POSTEMPLOYMENT BENEFITS

We provide certain postemployment disability income, medical and other benefits to substantially all qualifying former or inactive U.S. employees. Income benefits for long-term disability are provided through a fully-insured plan. The continuation of medical and other benefits while on disability (“Continuation Benefits”) are provided through a qualified self-insured plan. The accrued postemployment liability for Continuation Benefits at December 31, 2010 and 2009 was $15 million and $13 million, respectively, and is included in other liabilities in our consolidated balance sheet.

NOTE 14. COMMITMENTS AND CONTINGENCIES

LEASES

At December 31, 2010, we had long-term non-cancelable operating leases covering certain facilities and equipment. The minimum annual rental commitments, net of amounts due under subleases, for each of the five years in the period ending December 31, 2015 are $186 million, $135 million, $93 million, $67 million and $49 million, respectively, and $151 million in the aggregate thereafter. Rent expense, which generally includes vessels, transportation equipment and warehouse facilities, was $355 million, $241 million and $227 million for the years ended December 31, 2010, 2009 and 2008, respectively. We have not entered into any significant capital leases during the three years ended December 31, 2010.

LITIGATION

We are involved in litigation or proceedings that have arisen in our ordinary business activities. We insure against these risks to the extent deemed prudent by our management and to the extent insurance is available, but 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 legal proceedings. Many of these insurance policies contain deductibles or self-insured retentions in amounts we deem prudent and for which we are responsible for payment. In determining the amount of self-insurance, it is our policy to self-insure those losses that are predictable, measurable and recurring in nature, such as claims for automobile liability, general liability and workers compensation. The accruals for losses are calculated by estimating losses for claims using historical claim data, specific loss development factors and other information as necessary.

BJ Services Acquisition Related Stockholder Lawsuits

The stockholder lawsuits filed in connection with the BJ Services acquisition have been settled. On July 15, 2010, the Delaware Chancery Court certified the Class of BJ Services stockholders, approved the settlement terms, awarded $500,000 in attorneys’ fees and $36,000 in costs to the Class counsel, and entered a Final Judgment dismissing all of the Class claims with prejudice, In re: BJ Services Company Shareholders Litigation, C.A. No. 4851-VCN. On July 23, 2010, the 80^th Judicial District Court of Harris County, Texas, entered a Final Judgment dismissing the plaintiff’s claims with prejudice in the consolidated actions styled as Garden City Employees’ Retirement System, et al. v. BJ Services Company, et al., Cause No. 2009-57320, 80^th Judicial District Court of Harris County, Texas.

Customer Claim

On November 19, 2009, BJ Services received correspondence from a customer operating in the North Sea, claiming that BJ Services’ decision to move a stimulation vessel out of the North Sea market constituted a breach of contract. The customer alleges that it was forced to purchase well stimulation services from other providers at a higher cost than in the original agreement between the customer and BJ Services. The customer further alleges that it has incurred actual and estimated future damages of $38 million. The customer has initiated a request for arbitration and we are responding accordingly. We believe that this claim is without merit, and we intend to vigorously defend ourselves in this matter based on the information available to us at this time. We do not expect the outcome of this matter to have a material adverse effect on our consolidated financial statements; however, there can be no assurance as to the ultimate outcome of this matter.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

ENVIRONMENTAL MATTERS

Our past and present operations include activities which are subject to extensive domestic (including U.S. federal, state and local) and international environmental regulations with regard to air, land and water quality and other environmental matters. Our environmental procedures, policies and practices are designed to ensure compliance with existing laws and regulations and to minimize the possibility of significant environmental damage.

We have also been identified as a potentially responsible party (“PRP”) in remedial activities related to various Superfund sites. We participate in the process set out in the Joint Participation and Defense Agreement to negotiate with government agencies, identify other PRPs, determine each PRP’s allocation and estimate remediation costs. We have accrued what we believe to be our pro-rata share of the total estimated cost of remediation and associated management of these Superfund sites. This share is based upon the ratio that the estimated volume of waste we contributed to the site bears to the total estimated volume of waste disposed at the site. Applicable United States federal law imposes joint and several liability on each PRP for the cleanup of these sites leaving us with the uncertainty that we may be responsible for the remediation cost attributable to other PRPs who are unable to pay their share. No accrual has been made under the joint and several liability concept for those Superfund sites where our participation is de minimis since we believe that the probability that we will have to pay material costs above our volumetric share is remote. We believe there are other PRPs who have greater involvement on a volumetric calculation basis, who have substantial assets and who may be reasonably expected to pay their share of the cost of remediation. For those Superfund sites where we are a significant PRP, remediation costs are estimated to include recalcitrant parties. In some cases, we have insurance coverage or contractual indemnities from third parties to cover a portion of the ultimate liability.

Our total accrual for environmental remediation is $32 million and $18 million, which includes accruals of $7 million and $6 million for the various Superfund sites, at December 31, 2010 and 2009, respectively. Approximately $11 million of our total environmental accrual at December 31, 2010 relates to properties or liabilities acquired in connection with the BJ Services acquisition. The determination of the required accruals for remediation costs is subject to uncertainty, including the evolving nature of environmental regulations and the difficulty in estimating the extent and type of remediation activity that is necessary. We believe that the likelihood of material losses in excess of the amounts accrued is remote.

OTHER

In connection with the settlement of litigation with ReedHycalog, in June 2008, the Company paid ReedHycalog $70 million in royalties for prior use of certain patented technologies, and ReedHycalog paid the Company $8 million in royalties for the license of certain Company patented technologies. The net pre-tax charge of $62 million for the settlement of this litigation is reflected in the 2008 consolidated statement of operations.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

NOTE 15. ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table presents the changes in accumulated other comprehensive loss, net of tax:


	Pensions and			Foreign			Accumulated
	Other			Currency			Other
	Postretirement			Translation			Comprehensive
	Benefits			Adjustments			Loss

Balance at December 31, 2008	$	(181	)	$	(342	)	$	(523	)
Translation adjustments		—			122			122
Amortization of prior service cost		1			—			1
Amortization of actuarial net loss		16			—			16
Actuarial net losses arising in the year		(22	)		—			(22	)
Effect of exchange rate		(10	)		—			(10	)
Deferred taxes		2			—			2

Balance at December 31, 2009		(194	)		(220	)		(414	)
Translation adjustments		—			(41	)		(41	)
Amortization of prior service cost		1			—			1
Amortization of actuarial net loss		14			—			14
Actuarial net gains arising in the year		20			—			20
Effect of exchange rate		5			—			5
Deferred taxes		(5	)		—			(5	)

Balance at December 31, 2010	$	(159	)	$	(261	)	$	(420	)

NOTE 16. QUARTERLY DATA (UNAUDITED)


	First		Second		Third		Fourth		Total
	Quarter		Quarter		Quarter		Quarter		Year

2010
Revenues	$	2,539	$	3,374	$	4,078	$	4,423	$	14,414
Gross profit ⁽¹⁾		533		600		771		897		2,801
Net income attributable to Baker Hughes		129		93		255		335		812
Basic earnings per share of Baker Hughes		0.41		0.23		0.59		0.78		2.06
Diluted earnings per share of Baker Hughes		0.41		0.23		0.59		0.77		2.06
Dividends per share		0.15		0.15		0.15		0.15		0.60
Common stock market prices:
High		51.86		54.18		50.23		57.17
Low		41.24		35.87		37.58		42.82

2009
Revenues	$	2,668	$	2,336	$	2,232	$	2,428	$	9,664
Gross profit ⁽¹⁾		599		437		383		451		1,870
Net income attributable to Baker Hughes		195		87		55		84		421
Basic earnings per share of Baker Hughes		0.63		0.28		0.18		0.27		1.36
Diluted earnings per share of Baker Hughes		0.63		0.28		0.18		0.27		1.36
Dividends per share		0.15		0.15		0.15		0.15		0.60
Common stock market prices:
High		38.08		42.33		44.01		47.67
Low		26.58		29.22		33.41		38.04


⁽¹⁾		Represents revenues less cost of sales, cost of services and research and engineering.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this annual report, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act of 1934, as amended (the “Exchange Act”). This evaluation was carried out under the supervision and with the participation of our management, including our principal executive officer and principal financial officer. Based on this evaluation, these officers have concluded that, as of December 31, 2010, our disclosure controls and procedures, as defined by Rule 13a-15(e) of the Exchange Act, are effective at a reasonable assurance level.

On April 28, 2010, the Company acquired BJ Services. For purposes of determining the effectiveness of our disclosure controls and procedures and any change in our internal control over financial reporting, management has excluded BJ Services from its evaluation of these matters. The acquired business represented approximately 46% of our consolidated total assets at December 31, 2010 and approximately 36% of our consolidated net income attributable to Baker Hughes for the year ended December 31, 2010.

Disclosure controls and procedures are our controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act, such as this annual report, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Design and Evaluation of Internal Control Over Financial Reporting

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, our management included a report of their assessment of the design and effectiveness of our internal controls over financial reporting as part of this Annual Report on Form 10-K for the fiscal year ended December 31, 2010. 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. Management’s report and the independent registered public accounting firm’s attestation report are included in Item 8 under the caption entitled “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm” and are incorporated herein by reference.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal controls over financial reporting during the quarter ended December 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B. OTHER INFORMATION

Item 5.02(b). Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.

Item 5.03(a). Amendments to Articles of Incorporation or Bylaws; Changes in Fiscal Year.

On February 24, 2011, the Board of Directors amended Article III, Section 1 of the Company’s Bylaws to decrease the authorized number of directors from thirteen to eleven, effective April 28, 2011, which will eliminate the vacancies on the Board of Directors that will result from the retirement of Messrs. Edward P. Djerejian and James L. Payne as directors of the Company following the Company’s 2011 annual meeting of stockholders. Because this Annual Report on Form 10-K is being filed within four business days from February 24, 2011, the retirement of Messrs. Edward P. Djerejian and James L. Payne and the restatement of the Bylaws are being disclosed hereunder rather than under Items 5.02(b) and 5.03(a) of Form 8-K. The restated Bylaws are attached hereto and incorporated by reference as Exhibits 3.3 and 4.4.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding the Business Code of Conduct and Code of Ethical Conduct Certificates for our principal executive officer, principal financial officer and principal accounting officer are described in Item 1. Business of this Annual Report. Information concerning our directors is set forth in the sections entitled “Proposal No. 1, Election of Directors,” and “Corporate Governance – Committees of the Board – Audit/Ethics Committee” in our Definitive Proxy Statement for the 2011 Annual Meeting of Stockholders to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2010 (“Proxy Statement”), which sections are incorporated herein by reference. For information regarding our executive officers, see “Item 1. Business – Executive Officers” in this Annual Report on Form 10-K. Additional information regarding compliance by directors and executive officers with Section 16(a) of the Exchange Act is set forth under the section entitled “Compliance with Section 16(a) of the Securities Exchange Act of 1934” in our Proxy Statement, which section is incorporated herein by reference. For information concerning our Business Code of Conduct and Code of Ethical Conduct Certificates, see “Item 1. Business” in this Annual Report on Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

Information for this item is set forth in the following sections of our Proxy Statement, which sections are incorporated herein by reference: “Compensation Discussion and Analysis,” “Executive Compensation,” “Director Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report.”

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information concerning security ownership of certain beneficial owners and our management is set forth in the sections entitled “Voting Securities” and “Security Ownership of Management” in our Proxy Statement, which sections are incorporated herein by reference.

Our Board of Directors has approved procedures for use under our Securities Trading and Disclosure Policy to permit our employees, officers and directors to enter into written trading plans complying with Rule 10b5-1 under the Exchange Act. Rule 10b5-1 provides criteria under which such an individual may establish a prearranged plan to buy or sell a specified number of shares of a company’s stock over a set period of time. Any such plan must be entered into in good faith at a time when the individual is not in possession of material, nonpublic information. If an individual establishes a plan satisfying the requirements of Rule 10b5-1, such individual’s subsequent receipt of material, nonpublic information will not prevent transactions under the plan from being executed. Certain of our officers have advised us that they have and may enter into a stock sales plan for the sale of shares of our common stock which are intended to comply with the requirements of Rule 10b5-1 of the Exchange Act. In addition, the Company has and may in the future enter into repurchases of our common stock under a plan that complies with Rule 10b5-1 or Rule 10b-18 of the Exchange Act.

Equity Compensation Plan Information

The information in the following table is presented as of December 31, 2010 with respect to shares of our common stock that may be issued under our existing equity compensation plans, including the Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan, the Baker Hughes Incorporated 2002 Directors & Officers Long-Term Incentive Plan, the BJ Services 1995 Incentive Plan, the BJ Services 1997 Incentive Plan, the BJ Services 2000 Incentive Plan and the BJ Services 2003 Incentive Plan, all of which have been approved by our stockholders (in millions, except per share prices).

Number of Securities

Number of

Remaining Available

Securities to be

for Future Issuance

Issued Upon

Weighted Average

Under Equity

Exercise of

Exercise Price of

Compensation Plans

Outstanding

(excluding securities

Options, Warrants

reflected in the first

Equity Compensation Plan Category

and Rights

column)

Stockholder-approved plans (excluding Employee Stock Purchase Plan)

10.8

50.84

8.4

Nonstockholder-approved plans ⁽¹⁾

0.1

34.21

0.5

Subtotal (except for weighted average exercise price)

10.9

50.72

8.9

Employee Stock Purchase Plan ⁽²⁾

—

5.6

Total

10.9

50.72

14.5


⁽¹⁾		The table includes the following nonstockholder-approved plans: the 1998 Employee Stock Option Plan and the Director Compensation Deferral Plan. A description of each of these plans is set forth below.

⁽²⁾		The per share purchase price under the Baker Hughes Incorporate Employee Stock Purchase Plan is determined in accordance with section 423 of the Code as 85% of the lower of the fair market value of a share of our common stock on the date of grant or the date of purchase.

Our nonstockholder-approved plans are described below:

1998 Employee Stock Option Plan

The Baker Hughes Incorporated 1998 Employee Stock Option Plan (the “1998 ESOP”) was adopted effective as of October 1, 1998. The number of shares authorized for issuance under the 1998 ESOP was 7.0 million shares. Nonqualified stock options may be granted under the 1998 ESOP to our employees. The exercise price of the options will be equal to the fair market value per share of our common stock on the date of grant, and option terms may be up to ten years. Under the terms and conditions of the option award agreements for options issued under the 1998 ESOP, options generally vest and become exercisable in installments over the optionee’s period of service, and the options vest on an accelerated basis in the event of a change in control. As of December 31, 2010, options covering approximately 68,000 shares of our common stock were outstanding under the 1998 ESOP and options covering approximately 47,000 shares were exercised during fiscal year 2010. There are no shares available for grants of future options as the plan expired on October 1, 2008.

Director Compensation Deferral Plan

The Baker Hughes Incorporated Director Compensation Deferral Plan, as amended and restated effective July 24, 2002 (the “Deferral Plan”), is intended to provide a means for members of our Board of Directors to defer compensation otherwise payable and provide flexibility with respect to our compensation policies. Under the provisions of the Deferral Plan, directors may elect to defer income with respect to each calendar year. The compensation deferrals may be stock option-related deferrals or cash-based deferrals. If a director elects a stock option-related deferral, on the last day of each calendar quarter he or she will be granted a nonqualified stock option. The number of shares subject to the stock option is calculated by multiplying the amount of the deferred compensation that otherwise would have been paid to the director during the quarter by 4.4 and then dividing by the fair market value of our common stock on the last day of the quarter. The per share exercise price of the option will be the fair market value of a share of our common stock on the date the option is granted. Stock options granted under the Deferral Plan vest on the first anniversary of the date of grant and must be exercised within ten years of the date of grant. If a director’s directorship terminates for any reason, any options outstanding will expire three years after the termination of the directorship. The maximum aggregate number of shares of our common stock that may be issued under the Deferral Plan is 0.5 million. As of December 31, 2010, options covering approximately 3,000 shares of our common stock were outstanding under the Deferral Plan, there were no shares exercised during fiscal 2010 and approximately 0.5 million shares remained available for future options.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information for this item is set forth in the sections entitled “Corporate Governance-Director Independence” and “Certain Relationships and Related Transactions” in our Proxy Statement, which sections are incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information concerning principal accounting fees and services is set forth in the section entitled “Fees Paid to Deloitte & Touche LLP” in our Proxy Statement, which section is incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)

List of Documents filed as part of this Report.

	(1)		Financial Statements

			All financial statements of the Registrant as set forth under Item 8 of this Annual Report on Form 10-K.

	(2)		Financial Statement Schedules

			Schedule II — Valuation and Qualifying Accounts

	(3)		Exhibits

			Each exhibit identified below is filed as a part of this report. Exhibits designated with an “*” are filed as an exhibit to this Annual Report on Form 10-K. Exhibits designated with a “+” are identified as management contracts or compensatory plans or arrangements. Exhibits previously filed as indicated below are incorporated by reference.


3.1		Certificate of Amendment dated April 22, 2010 and the Restated Certificate of Incorporation (filed as Exhibit 3.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2010).

3.2		Restated Bylaws of Baker Hughes Incorporated effective as of April 28, 2010 (filed as Exhibit 3.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed April 29, 2010).

3.3*		Restated Bylaws of Baker Hughes Incorporated effective as of April 28, 2011.

4.1		Rights of Holders of the Company’s Long-Term Debt. The Company has no long-term debt instrument with regard to which the securities authorized there under equal or exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. The Company agrees to furnish a copy of its long-term debt instruments to the SEC upon request.

4.2		Certificate of Amendment dated April 22, 2010 and the Restated Certificate of Incorporation (filed as Exhibit 3.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2010).

4.3		Restated Bylaws of Baker Hughes Incorporated effective as of April 28, 2010 (filed as Exhibit 3.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed April 29, 2010).

4.4*		Restated Bylaws of Baker Hughes Incorporated effective as of April 28, 2011 (filed as Exhibit 3.3 to this Annual Report on Form 10-K).

4.5		Indenture dated as of May 15, 1994 between Western Atlas Inc. and The Bank of New York, Trustee, providing for the issuance of securities in series (filed as Exhibit 4.4 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2004).


4.6		Indenture dated October 28, 2008, between Baker Hughes Incorporated and The Bank of New York Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 29, 2008).

4.7		Officers’ Certificate of Baker Hughes Incorporated dated October 28 2008 establishing the 6.50% Senior Notes due 2013 and the 7.50% Senior Notes due 2018 (filed as Exhibit 4.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 29, 2008).

4.8		Form of 6.50% Senior Notes Due 2013 (filed as Exhibit 4.3 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 29, 2008).

4.9		Form of 7.50% Senior Notes Due 2018 (filed as Exhibit 4.4 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 29, 2008).

4.10		Officers’ Certificate of Baker Hughes Incorporated dated August 24, 2010 establishing the 5.125% Senior Notes due 2040 (filed as Exhibit 4.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed August 24, 2010).

4.11		Form of 5.125% Senior Notes due 2040 (filed as Exhibit 4.3 to Current Report of Baker Hughes Incorporated on Form 8- K filed August 24, 2010).

4.12		Indenture, dated June 8, 2006, between BJ Services Company, as issuer, and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to Current Report on BJ Services Company Form 8-K filed on June 12, 2006).

4.13		First Supplemental Indenture, dated June 8, 2006, between BJ Services Company, as issuer, and Wells Fargo Bank, N.A., as trustee, with respect to the 5.75% Senior Notes due 2011 (incorporated by reference to Exhibit 4.2 to Current Report on BJ Services Company Form 8-K filed on June 12, 2006).

4.14		Third Supplemental Indenture, dated May 19, 2008, between BJ Services Company, as issuer, and Wells Fargo Bank, N.A., as trustee, with respect to the 6% Senior Notes due 2018 (incorporated by reference to Exhibit 4.2 to Current Report on BJ Services Company Form 8-K filed on May 23, 2008).

4.15		Fourth Supplemental Indenture, dated April 28, 2010, between BJ Services Company, as issuer, BSA Acquisition LLC, Baker Hughes Incorporated and Wells Fargo Bank, N.A., as trustee, with respect to the 5.75% Senior Notes due 2011 and the 6% Senior Notes due 2018 (incorporated by reference to Exhibit 4.4 to Current Report on Baker Hughes Incorporated Form 8-K filed on April 29, 2010).

4.16+		Form of Incentive Stock Option Assumption Agreement for BJ Services incentive plans (incorporated by reference to Exhibit 4.5 to Current Report on Baker Hughes Incorporated Form 8-K filed on April 29, 2010).

4.17+		Form of Nonqualified Stock Option Assumption Agreement for BJ Services incentive plans (incorporated by reference to Exhibit 4.6 to Current Report on Baker Hughes Incorporated Form 8-K filed on April 29, 2010).

10.1+		Amendment and Restatement of Employment Agreement between Chad C. Deaton and Baker Hughes Incorporated dated as of January 1, 2009 (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed December 19, 2008).

10.2+		Form of Amended and Restated Change in Control Agreement between Baker Hughes Incorporated and each of the executive officers effective as of January 1, 2009 (filed as Exhibit 10.2 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2008).

10.3+		Letter Agreement between Peter A. Ragauss and Baker Hughes Incorporated dated as of March 27, 2006 (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed March 31, 2006).

10.4+		Amendment and Restatement of the Baker Hughes Incorporated Change in Control Severance Plan effective as of January 1, 2009 (filed as Exhibit 10.3 to Current Report of Baker Hughes Incorporated on Form 8-K filed December 19, 2008).


10.5+		Form of Indemnification Agreement between Baker Hughes Incorporated and each of the directors and executive officers (filed as Exhibit 10.4 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.6+		Form of Amendment to the Indemnification Agreement between Baker Hughes Incorporated and each of the directors and executive officers effective as of January 1, 2009 (filed as Exhibit 10.4 to Current Report of Baker Hughes Incorporated on Form 8-K filed December 19, 2008).

10.7+		Baker Hughes Incorporated Director Retirement Policy for Certain Members of the Board of Directors (filed as Exhibit 10.10 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.8+		Baker Hughes Incorporated Director Compensation Deferral Plan, as amended and restated effective as of January 1, 2009 (filed as Exhibit 10.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2008).

10.9+		Amendment to Baker Hughes Incorporated Director Compensation Deferral Plan effective as of January 1, 2009 (filed as Exhibit 10.5 to Current Report of Baker Hughes Incorporated on Form 8-K filed on December 19, 2008).

10.10+		Baker Hughes Incorporated Executive Severance Plan, as amended and restated on February 7, 2008 (filed as Exhibit 10.17 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2007).

10.11+		Amendment to Exhibit A of Baker Hughes Incorporated Executive Severance Plan as of July 20, 2009 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2009).

10.12+		Baker Hughes Incorporated Annual Incentive Compensation Plan, as amended and restated on February 20, 2008 (filed as Exhibit 10.18 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2007).

10.13+		Amendment to the Baker Hughes Annual Incentive Compensation Plan effective as of January 1, 2009 (filed as Exhibit 10.7 to Current Report of Baker Hughes Incorporated on Form 8-K filed on December 19, 2008).

10.14+		Baker Hughes Incorporated Supplemental Retirement Plan, as amended and restated effective as of January 1, 2011 (filed as Exhibit 10.2 to Current Report of Baker Hughes Incorporated on Form 8-K, filed on June 26, 2010).

10.15+		Amendment to the Baker Hughes Incorporated Supplemental Retirement Plan effective as of January 1, 2009 (filed as Exhibit 10.6 to Current Report of Baker Hughes Incorporated on Form 8-K filed on December 19, 2008).

10.16+		Long-Term Incentive Plan, as amended by Amendment No. 1999-1 to Long-Term Incentive Plan (filed as Exhibit 10.18 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2002).

10.17+		Baker Hughes Incorporated 1998 Employee Stock Option Plan, as amended by Amendment No. 1999-1 to 1998 Employee Stock Option Plan (filed as Exhibit 10.3 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2003).

10.18		Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan (filed as Exhibit 4.4 to Registration Statement No. 333-87372 of Baker Hughes Incorporated on Form S-8 filed May 1, 2002).

10.19+		Amendment to Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan, effective July 24, 2008 (filed as Exhibit 10.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2008).

10.20+		Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan (filed as Exhibit 10.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2003).


10.21+		Amendment to 2002 Director & Officer Long-Term Incentive Plan, effective as of October 27, 2005 (filed as Exhibit 10.3 of Baker Hughes Incorporated to Quarterly Report on Form 10-Q for the quarter ended September 30, 2005).

10.22+		Amendment to Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan effective July 24, 2008 (filed as Exhibit 10.3 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2008).

10.23		Baker Hughes Incorporated Employee Stock Purchase Plan, as amended and restated, effective as of January 1, 2010 (filed as Exhibit 10.25 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2009).

10.24+		Form of Stock Option Agreement for executive officers effective October 1, 1998 (filed as Exhibit 10.37 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2000).

10.25+		Form of Nonqualified Stock Option Agreement for directors effective October 25, 1998 (filed as Exhibit 10.39 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2000).

10.26+		Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement for executive officers, dated January 24, 2001 (filed as Exhibit 10.41 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2001).

10.27+		Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement for employees, dated January 30, 2002 (filed as Exhibit 10.43 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2001).

10.28+		Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement with Terms and Conditions for officers (filed as Exhibit 10.30 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2009).

10.29+		Form of Baker Hughes Incorporated Incentive Stock Option Agreement for employees, dated January 30, 2002 (filed as Exhibit 10.44 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2001).

10.30+		Form of Baker Hughes Incorporated Stock Option Award Agreements, with Terms and Conditions (filed as Exhibit 10.46 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2002).

10.31+		Form of Baker Hughes Incorporated Incentive Stock Option Agreement with Terms and Conditions for officers (filed as Exhibit 10.33 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2009).

10.32+		Form of Restricted Stock Award Resolution, including Terms and Conditions (filed as Exhibit 10.3 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2004).

10.33+		Form of Baker Hughes Incorporated Restricted Stock Award Agreement (filed as Exhibit 10.54 to Annual Report on Form 10-K for the year ended December 31, 2004).

10.34+		Form of Baker Hughes Incorporated Restricted Stock Award Terms and Conditions (filed as Exhibit 10.54 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2004).

10.35+		Form of Baker Hughes Incorporated Restricted Stock Award with Terms and Conditions for officers (filed as Exhibit 10.37 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2009).

10.36+		Form of Baker Hughes Incorporated Restricted Stock Unit Agreement, including Terms and Conditions (filed as Exhibit 10.18 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2007).


10.37+		Form of Baker Hughes Incorporated Restricted Stock Unit Agreement (filed as Exhibit 10.54 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2004).

10.38+		Form of Baker Hughes Incorporated Restricted Stock Unit Terms and Conditions (filed as Exhibit 10.54 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2004).

10.39+		Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and Conditions for officers (filed as Exhibit 10.41 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2009).

10.40+		Form of Baker Hughes Incorporated Restricted Stock Award, including Terms and Conditions for directors (filed as Exhibit 10.40 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2005).

10.41+		Form of Baker Hughes Incorporated Stock Option Award Agreement, including Terms and Conditions for directors (filed as Exhibit 10.41 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2005).

10.42+		Form of Baker Hughes Incorporated Performance Unit Award Agreement and Terms and Conditions for officers (filed as Exhibit 10.48 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2009).

10.43+		Form of Baker Hughes Incorporated Performance Unit Award Agreement, including Terms and Conditions (filed as Exhibit 10.42 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2007).

10.44+		Form of Baker Hughes Incorporated Performance Unit Award Agreement, including Terms and Conditions (filed as Exhibit 10.42 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2005).

10.45+		Form of 2009 Performance Unit Award Agreement, including Terms and Conditions (filed as Exhibit 10.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed March 31, 2009).

10.46+		Performance Goals adopted October 21, 2010 for the Performance Unit Awards Granted in 2009 under the Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 22, 2010).

10.47+		Performance Goals adopted October 21, 2010 for the Performance Unit Awards Granted in 2010 under the Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan (filed as Exhibit 10.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 22, 2010).

10.48 +		Performance Goals adopted October 21, 2010 for the Performance Unit Awards to be granted in 2011 under the Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan (filed as Exhibit 10.3 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 22, 2010).

10.49+		Amendment to Baker Hughes Incorporated Executive Severance Plan dated April 22, 2010 (filed as Exhibit 10.1 to Current Report on Baker Hughes Incorporated Form 8-K filed on April 23, 2010).

10.50+		Amendment to Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan dated March 31, 2010 (filed as Annex G to the Registration Statement No. 333-162463 on Form S-4 filed on February 9, 2010).

10.51		Amendment to Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan dated March 31, 2010 (filed as Annex H to the Registration Statement No. 333-162463 on Form S-4 filed on February 9, 2010).

10.52		Credit Agreement dated as of March 19, 2010, among Baker Hughes Incorporated, JP Morgan Chase Bank, N.A., as Administrative Agent and twenty-one lenders for $1.2 billion, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report on Baker Hughes Incorporated Form 8-K filed on March 22, 2010).


10.53		BJ Services Company 1995 Incentive Plan (filed as Exhibit 4.5 to BJ Services Company’s Registration Statement on Form S-8 (Reg. No. 33-58637) and incorporated herein by reference).

10.54		Amendments effective January 25, 1996, and December 12, 1996, to BJ Services Company 1995 Incentive Plan (filed as Exhibit 10.9 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 1996 (file no. 1-10570), and incorporated herein by reference).

10.55		Amendment effective July 22, 1999 to BJ Services Company 1995 Incentive Plan (filed as Exhibit 10.25 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 1999 (file no. 1-10570), and incorporated herein by reference).

10.56		Amendment effective January 27, 2000 to BJ Services Company 1995 Incentive Plan (filed as Appendix B to BJ Services Company’s Proxy Statement dated December 20, 1999 (file no. 1-10570) and incorporated herein by reference).

10.57		Amendment effective May 10, 2001 to BJ Services Company 1995 Incentive Plan (filed as Appendix B to BJ Services Company’s Proxy Statement dated April 10, 2001 and (file no. 1-10570) incorporated herein by reference).

10.58		Eighth Amendment effective October 15, 2001 to BJ Services Company 1995 Incentive Plan (filed as Exhibit 10.12 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 2001 (file no. 1-10570) and incorporated herein by reference).

10.59		Tenth Amendment effective December 5, 2008 to BJ Services Company 1995 Incentive Plan (filed as Exhibit 10.1 to BJ Services Company’s Quarterly Report on Form 10-Q for the quarterly period ended December 31, 2008 (file no. 1-10570) and incorporated herein by reference).

10.60		BJ Services Company 1997 Incentive Plan (filed as Appendix B to BJ Services Company’s Proxy Statement dated December 22, 1997 (file no. 1-10570) and incorporated herein by reference).

10.61		Amendment effective July 22, 1999 to BJ Services Company 1997 Incentive Plan (filed as Exhibit 10.26 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 1999 (file no. 1-10570) and incorporated herein by reference).

10.62		Amendment effective January 27, 2000 to BJ Services Company 1997 Incentive Plan (filed as Appendix C to BJ Services Company’s Proxy Statement dated December 20, 1999 (file no. 1-10570) and incorporated herein by reference).

10.63		Amendment effective May 10, 2001 to BJ Services Company 1997 Incentive Plan (filed as Appendix C to BJ Services Company’s Proxy Statement dated April 10, 2001 (file no. 1-10570) and incorporated herein by reference).

10.64		Fifth Amendment effective October 15, 2001 to BJ Services Company 1997 Incentive Plan (filed as Exhibit 10.17 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 2001 (file no. 1-10570) and incorporated herein by reference).

10.65		Eighth Amendment effective November 15, 2006 to BJ Services Company 1997 Incentive Plan (filed as Exhibit 10.3 to BJ Services Company’s Current Report on Form 8-K filed on December 13, 2006 and incorporated herein by reference).

10.66		Ninth Amendment effective October 13, 2008 to BJ Services Company 1997 Incentive Plan (filed as Exhibit 10.16 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 2008 (file no. 1-10570) and incorporated herein by reference).

10.67		Tenth Amendment effective December 5, 2008 to BJ Services Company 1997 Incentive Plan (filed as Exhibit 10.2 to BJ Services Company’s Quarterly Report for the quarterly period ended December 31, 2008 (file no. 1-10570) and incorporated herein by reference).


10.68+		BJ Services Company 2000 Incentive Plan (filed as Appendix B to BJ Services Company’s Proxy Statement dated December 20, 2000 (file no. 1-10570) and incorporated herein by reference).

10.69+		First Amendment effective March 22, 2001 to BJ Services Company 2000 Incentive Plan (filed as Exhibit 10.2 to BJ Services Company’s Registration Statement on Form S-8 (Reg. No. 333-73348) and incorporated herein by reference).

10.70+		Second Amendment effective May 10, 2001 to BJ Services Company 2000 Incentive Plan (filed as Appendix D to BJ Services Company’s Proxy Statement dated April 10, 2001 (file no. 1-10570) and incorporated herein by reference).

10.71+		Third Amendment effective October 15, 2001 to BJ Services Company 2000 Incentive Plan (filed as Exhibit 10.24 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 2001 (file no. 1-10570) and incorporated herein by reference).

10.72+		Fifth Amendment effective November 15, 2006 to BJ Services Company 2000 Incentive Plan (filed as Exhibit 10.4 to BJ Services Company’s Current Report on Form 8-K filed on December 13, 2006 (file no. 1-10570) and incorporated herein by reference).

10.73+		Sixth Amendment effective October 13, 2008 to BJ Services Company 2000 Incentive Plan (filed as Exhibit 10.22 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 2008 (file no. 1-10570) and incorporated herein by reference).

10.74+		Seventh Amendment effective December 5, 2008 to BJ Services Company 2000 Incentive Plan (filed as Exhibit 10.3 to BJ Services Company’s Quarterly Report for the quarterly period ended December 31, 2008 (file no. 1-10570) and incorporated herein by reference).

10.75+		Amended and Restated BJ Services Company 2003 Incentive Plan (filed as Appendix A to BJ Services Company’s Proxy Statement dated December 15, 2008 (file no. 1-10570) and incorporated herein by reference).

10.76+		First Amendment to the Amended and Restated BJ Services Company 2003 Incentive Plan (filed as Exhibit 10.1 to BJ Services Company’s Quarterly Report for the quarterly period ended March 31, 2008 (file no. 1-10570) and incorporated herein by reference).

10.77+*		Compensation Table for Named Executive Officers and Directors.

10.78		Form of Credit Agreement, dated as of July 7, 2005, among Baker Hughes Incorporated, JPMorgan Chase Bank, N.A., as Administrative Agent and fourteen lenders for $500 million, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed July 11, 2005).

10.79		First Amendment to the Credit Agreement dated June 7, 2006, among Baker Hughes Incorporated and fifteen banks for $500 million, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed on June 12, 2006).

10.80		Second Amendment to the Credit Agreement dated May 31, 2007, among Baker Hughes Incorporated and fifteen banks for $500 million, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed June 4, 2007).

10.81		Third Amendment to Credit Agreement dated as of April 1, 2008, among Baker Hughes Incorporated, JP Morgan Chase Bank, N.A., as Administrative Agent, and fifteen lenders for $500 million, in the aggregate for all banks (filed as Exhibit 10.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed April 2, 2008).

10.82		Credit Agreement dated as of March 30, 2009, among Baker Hughes Incorporated, JP Morgan Chase Bank, N.A., as Administrative Agent, and thirteen lenders for $500 million, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed March 31, 2009).



10.83		Agreement of Resignation, Appointment and Acceptance by and among Baker Hughes Incorporated, Citibank, N.A. and the Bank of New York Trust Company, N.A. dated as of April 26, 2007, effective May 1, 2007 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

10.84		Agreement and Plan of Merger among Baker Hughes Incorporated, Baker Hughes Delaware I, Inc. and Western Atlas Inc. dated as of May 10, 1998 (filed as Exhibit 10.30 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.85+		Employee Benefits Agreement dated October 31, 1997, between Western Atlas Inc. and UNOVA Inc. (filed as Exhibit 10.32 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.86		Deferred Prosecution Agreement between Baker Hughes Incorporated and the United States Department of Justice filed on April 26, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 10.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

10.87		Plea Agreement between Baker Hughes Services International, Inc. and the United States Department of Justice filed on April 26, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 10.5 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

10.88		Agreement and Plan of Merger dated as of August 30, 2009, among Baker Hughes Incorporated, BSA Acquisition LLC and BJ Services Company (filed as Exhibit 2.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed August 31, 2009).

21.1*		Subsidiaries of Registrant.

23.1*		Consent of Deloitte & Touche LLP.

31.1*		Certification of Chad C. Deaton, Chief Executive Officer, dated February 24, 2011, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.

31.2*		Certification of Peter A. Ragauss, Chief Financial Officer, dated February 24, 2011, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.

32*		Statement of Chad C. Deaton, Chief Executive Officer, and Peter A. Ragauss, Chief Financial Officer, dated February 24, 2011, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.

99.1		Baker Hughes Incorporated Information document filed on April 26, 2007, by the United States Attorney’s Office for the Southern District of Texas and the United States Department of Justice (filed as Exhibit 99.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

99.2		Baker Hughes Services International, Inc. Information document filed on April 26, 2007, by the United States Attorney’s Office for the Southern District of Texas and the United States Department of Justice (filed as Exhibit 99.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

99.3		Sentencing Memorandum and Motion for Waiver of Pre-Sentence Investigation of Baker Hughes Services International, Inc. (filed as Exhibit 99.3 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

99.4		Baker Hughes Services International, Inc. Sentencing Letter from the United States Department of Justice dated April 24, 2007 (filed as Exhibit 99.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

99.5		The Complaint by the Securities and Exchange Commission vs. Baker Hughes Incorporated filed on April 26, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 99.5 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

KNOWN ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Chad C. Deaton and Peter A. Ragauss, each of whom may act without joinder of the other, as their true and lawful attorneys-in-fact and agents, each with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/CHAD C. DEATON (Chad C. Deaton)	Chairman of the Board and Chief Executive Officer (principal executive officer)	February 24, 2011

/s/PETER A. RAGAUSS (Peter A. Ragauss)	Senior Vice President and Chief Financial Officer (principal financial officer)	February 24, 2011

/s/ALAN J. KEIFER (Alan J. Keifer)	Vice President and Controller (principal accounting officer)	February 24, 2011

/s/LARRY D. BRADY (Larry D. Brady)	Director	February 24, 2011

/s/CLARENCE P. CAZALOT, JR. (Clarence P. Cazalot, Jr.)	Director	February 24, 2011

/s/EDWARD P. DJEREJIAN (Edward P. Djerejian)	Director	February 24, 2011

/s/ANTHONY G. FERNANDES (Anthony G. Fernandes)	Director	February 24, 2011

/s/CLAIRE W. GARGALLI (Claire W. Gargalli)	Director	February 24, 2011

/s/PIERRE H. JUNGELS (Pierre H. Jungels)	Director	February 24, 2011

/s/JAMES A. LASH (James A. Lash)	Director	February 24, 2011

/s/J. LARRY NICHOLS (J. Larry Nichols)	Director	February 24, 2011

(James L. Payne)	Director	February , 2011

/s/H. JOHN RILEY, JR. (H. John Riley, Jr.)	Director	February 24, 2011

/s/ J. W. STEWART (J. W. STEWART)	Director	February 24, 2011

(Charles L. Watson)	Director	February , 2011


	Page
Part I
Item 1. Business		2
Item 1A. Risk Factors		8
Item 1B. Unresolved Staff Comments		14
Item 2. Properties		14
Item 3. Legal Proceedings		14
Item 4. [Removed and Reserved]		14
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		15
Item 6. Selected Financial Data		17
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18
Item 7A. Quantitative and Qualitative Disclosures About Market Risk		35
Item 8. Financial Statements and Supplementary Data		37
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		72
Item 9A. Controls and Procedures		72
Item 9B. Other Information		72
Part III
Item 10. Directors, Executive Officers and Corporate Governance		73
Item 11. Executive Compensation		73
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		73
Item 13. Certain Relationships and Related Transactions, and Director Independence		75
Item 14. Principal Accountant Fees and Services		75
Part IV
Item 15. Exhibits and Financial Statement Schedules		75


99.6		Final Judgment by the Securities and Exchange Commission as to Defendant Baker Hughes Incorporated dated and filed on May 1, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 99.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2007).

**101.INS		XBRL Instance Document

**101.SCH		XBRL Schema Document

**101.CAL		XBRL Calculation Linkbase Document

**101.LAB		XBRL Label Linkbase Document

**101.PRE		XBRL Presentation Linkbase Document

**101.DEF		XBRL Definition Linkbase Document


	BAKER HUGHES INCORPORATED
Date: February 24, 2011	/s/CHAD C. DEATON
	Chad C. Deaton
	Chairman of the Board and Chief Executive Officer


	Balance at		Charged to								Balance at
	Beginning		Cost and					Other			End of
(In millions)	of Period		Expenses		Write-offs⁽¹⁾			Changes⁽²⁾			Period

Year ended December 31, 2010
Reserve for doubtful accounts receivable	$	157	$	39	$	(24	)	$	(10	)	$	162
Reserve for inventories		297		33		(32	)		24			322

Year ended December 31, 2009
Reserve for doubtful accounts receivable		74		94		(12	)		1			157
Reserve for inventories		244		101		(53	)		5			297

Year ended December 31, 2008
Reserve for doubtful accounts receivable		59		31		(15	)		(1	)		74
Reserve for inventories		221		61		(30	)		(8	)		244


⁽¹⁾		Represents the elimination of accounts receivable and inventory deemed uncollectible or worthless.

⁽²⁾		Represents transfers, currency translation adjustments and divestitures.