10-K 1 fiscalyear2016form10-k.htm 10-K Document
                                                        

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2016
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-9397
Baker Hughes Incorporated
(Exact name of registrant as specified in its charter)
Delaware
 
76-0207995
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
17021 Aldine Westfield Road, Houston, Texas
 
77073-5101
(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
 
 
SIX Swiss Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES [X] NO [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. YES [ ] NO [X]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES [X] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
(Check one):
Large accelerated filer [X]
 
Accelerated filer [ ]
  
Non-accelerated filer [ ]
  
Smaller reporting company [ ]
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES [ ] NO [X]
The aggregate market value of the voting and non-voting common stock held by non-affiliates as of the last business day of the registrant's most recently completed second fiscal quarter (based on the closing price on June 30, 2016 reported by the New York Stock Exchange) was approximately $19,263,511,000.
As of January 31, 2017, the registrant has outstanding 425,325,600 shares of common stock, $1 par value per share.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrant's Definitive Proxy Statement for the 2017 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.



Baker Hughes Incorporated
Table of Contents

 
 
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PART I

ITEM 1. BUSINESS
Baker Hughes Incorporated is a Delaware corporation engaged in the oilfield services industry. As used herein, phrases such as "Baker Hughes," "Company," "we," "our" and "us" intend to 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 annual report or any other filing we make with the SEC.
We have 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 and HS&E 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
17021 Aldine Westfield Road
Houston, TX 77073
Attention: Investor Relations
Telephone: (713) 439-8600
ABOUT BAKER HUGHES
Baker Hughes is a leading supplier of oilfield services, products, technology and systems used in the worldwide oil and natural gas industry. We also provide products and services for other businesses including downstream chemicals, and process and pipeline services. Baker Hughes was formed as a corporation in April 1987 in connection with the combination of Baker International Corporation and Hughes Tool Company. We conduct our operations through subsidiaries, affiliates, ventures and alliances. We conduct business in more than 80 countries around the world and our corporate headquarters is in Houston, Texas. As of December 31, 2016, we had approximately 33,000 employees, of which approximately 64% work outside the United States (the "U.S.").
Our global oilfield operations are organized into a number of geomarket organizations, which are combined into four regions for assessing performance and allocating resources. The President of Global Operations manages our oilfield organization and reports to our chief executive officer. These regions form the basis of our four geographical operating segments as follows: North America; Latin America; Europe/Africa/Russia Caspian; and Middle East/Asia Pacific.


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Through the geographic organization, our management is located close to our customers, facilitating strong 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. In addition to the above, we have an Industrial Services segment, which includes the downstream chemicals business and the process and pipeline services business.
Certain support operations are organized at the enterprise level and include the supply chain and product line technology organizations. The supply chain organization is responsible for the cost-effective procurement and manufacturing of our products as well as product quality and reliability. The product line technology organization is responsible for innovating, developing, commercializing, and marketing reliable products designed to advance the performance of reservoirs for our customers. The product line technology organization also facilitates the development of cross-product line solutions, sales processes and integrated operations capabilities.
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 6. "Segment Information" of the Notes to Consolidated Financial Statements in Item 8 herein.
HALLIBURTON TERMINATED MERGER AGREEMENT
On November 16, 2014, Baker Hughes and Halliburton Company ("Halliburton") entered into a definitive agreement and plan of merger (the "Merger Agreement") under which Halliburton would acquire all outstanding shares of Baker Hughes in a stock and cash transaction (the "Merger"). In accordance with the provisions of Section 9.1 of the Merger Agreement, Baker Hughes and Halliburton agreed to terminate the Merger Agreement on April 30, 2016, as a result of the failure of the Merger to occur on or before April 30, 2016 due to the inability to obtain certain specified antitrust related approvals. Halliburton paid $3.5 billion to Baker Hughes on May 4, 2016, representing the antitrust termination fee required to be paid pursuant to the Merger Agreement. For further information about the Merger, see Note 2. "Halliburton Terminated Merger Agreement" of the Notes to Consolidated Financial Statements in Item 8 herein.
GENERAL ELECTRIC TRANSACTION AGREEMENT
On October 30, 2016, Baker Hughes, General Electric Company ("GE"), Bear Newco, Inc. ("Newco"), a direct wholly owned subsidiary of Baker Hughes, and Bear MergerSub, Inc. ("Merger Sub"), a direct wholly owned subsidiary of Newco, entered into a Transaction Agreement and Plan of Merger (the "Transaction Agreement"). Pursuant to the terms of the Transaction Agreement, Merger Sub will merge with and into Baker Hughes, with Baker Hughes as the surviving corporation (the "Surviving Entity") and a direct wholly owned subsidiary of Newco. As a result of the merger, each outstanding share of the Baker Hughes' common stock will be converted into the right to receive one share of Class A common stock of Newco ("Newco Class A Common Stock"). Immediately following the merger, Newco will cause the Surviving Entity to be converted into a Delaware limited liability company ("Newco LLC") and Newco will become the sole managing member of Newco LLC. Following this conversion, GE will receive an approximate 62.5% membership interest in Newco LLC in exchange for contributing $7.4 billion (less the Class B Purchase Price, as defined below) in cash and GE's oil and gas business ("GE O&G") to Newco LLC, and will also receive Class B common stock of Newco (the "Newco Class B Common Stock"), representing approximately 62.5% of the voting power of the outstanding shares of common stock of Newco, in exchange for contributing the par value thereof (the "Class B Purchase Price") to Newco. Newco will distribute as a special dividend an amount equal to $17.50 per share to the holders of record of the Newco Class A Common Stock, which are the former Baker Hughes stockholders. Newco will operate as a public company.
Immediately following the closing (the "Closing") of the transactions contemplated by the Transaction Agreement (collectively the "GE Transaction"), GE will hold 100% of the Newco Class B Common Stock, which will represent approximately 62.5% of the voting power of the outstanding shares of common stock of Newco, and Baker Hughes' stockholders immediately prior to the Closing will hold 100% of the Newco Class A Common Stock, which will represent approximately 37.5% of the voting power of the outstanding shares of common stock of Newco. In addition, GE will hold an approximate 62.5% membership interest in Newco LLC and Newco will hold an approximate 37.5% membership interest in Newco LLC. The membership interests in Newco LLC, together with the Newco Class B Common Stock, will be exchangeable on a 1:1 basis for Newco Class A Common Stock, subject to certain adjustments. The rights (including voting rights) of Newco Class A Common Stock and Newco Class B


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Common Stock are identical; provided that Newco Class B Common Stock has no economic rights. Effective from and following the Closing, Newco and its subsidiaries will operate under the name "Baker Hughes, a GE Company."
The GE Transaction is subject to the approval of Baker Hughes' stockholders, regulatory approvals and customary closing conditions. Baker Hughes and GE expect the GE Transaction to close in mid-2017. However, Baker Hughes cannot predict with certainty when, or if, the GE Transaction will be completed because completion of the GE Transaction is subject to conditions beyond the control of Baker Hughes. For further information about the GE Transaction, see Note 3. "General Electric Transaction Agreement" of the Notes to Consolidated Financial Statements in Item 8 herein.
PRODUCTS AND SERVICES
Oilfield Operations
We offer a full suite of products and services to our customers around the world. Our oilfield products and services fall into one of two categories, Drilling and Evaluation or Completion and Production. This classification is based on the two major phases of constructing an oil and/or natural gas well, the drilling phase and the completion phase, and how our products and services are utilized for each phase.
Drilling and Evaluation products and services consist of the following:
Drill Bits - Includes Tricone roller cone drill bits, polycrystalline diamond composite (PDC or "diamond" drill bits, Kymerahybrid drill bits and related cutter technology used for performance drilling, hole enlargement and coring.
Drilling Services - Includes directional drilling systems and services (rotary steerables, drilling motors, measurement-while-drilling (MWD) systems, etc.), logging-while-drilling (LWD) systems and services (resistivity, imaging, pressure testing and sampling, etc.), surface logging and coring systems and services, and geoscience services.
Wireline Services - Includes both open hole (imaging, fluids sampling, etc.) and cased hole (production logging, wellbore integrity, pipe recovery, etc.) well logging services.
Drilling and Completion Fluids - Includes emulsion (oil-based) and water-based drilling fluids systems; reservoir drill-in fluids; completion fluids, and fluids environmental services.
Completion and Production products and services consist of the following:
Completion Systems - Includes products and services used to control the flow of hydrocarbons within a wellbore including upper completions (packers, liner hangers, safety systems, etc.), lower completions (sand screens, tubing conveyed perforating, etc.) and unconventional multistage completion systems (frac plugs, frac balls, etc.).
Intelligent Production Systems - Includes products, services, and software used to monitor, analyze, and dynamically control production to optimize returns and ultimate recovery (production decisions services, chemical injection service, well monitoring services, intelligent well systems, and artificial lift monitoring).
Wellbore Intervention - Includes products and services used to intervene in existing wellbores to improve production and solve problems within the well (fishing services, wellbore cleanup, casing exit systems, workover systems, smart interventional technologies, and through-tubing intervention tools).
Artificial Lift - Includes products and services used to maintain production, improve recovery rates, and lower operating costs in wells in which a reservoir can no longer flow naturally (in-well electric submersible pumping systems; progressing cavity pump systems; gas lift systems); and horizontal surface pumping systems that move fluids on the surface for applications such as injection, disposal, transfer, and pipeline boosting.
Upstream Chemicals - Includes chemical technologies and services that solve production challenges related to flow assurance, production optimization, asset integrity, and water management.
Pressure Pumping - Includes onshore and offshore cementing, stimulation services (hydraulic fracturing, acidizing, stimulation vessels, etc.) and coiled tubing services used in the completion of new oil and natural gas wells and in remedial work on existing wells. Hydraulic fracturing is the practice of pumping fluid through a wellbore at pressures and rates sufficient to crack rock in the target formation, extend the cracks, and leave behind a propping agent to keep the cracks open after pumping ceases.


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The purpose of the cracks is to provide a pathway that allows for the passage of hydrocarbons from the rock to the wellbore, thus improving the production of hydrocarbons to the surface. On December 30, 2016, we contributed our North American onshore pressure pumping business to a newly formed venture ("BJ Services, LLC"), of which we retained a 46.7% interest and accounted for as an equity method investment.
We also provide dedicated project solutions to our customers through our Integrated Operations group. Integrated Operations is focused on the execution of projects that have one or more of the following attributes: project management, well site supervision, well construction, intervention, third-party contractor management, procurement and rig management. Contracts for this business unit tend to be longer in duration, often spanning multiple years, and may include significant third-party components to supplement the core products and services provided by us. By partnering with Integrated Operations, our customers have access to a comprehensive business solution that leverages our technical expertise, relationships with third-party and rig providers, and our industry leading technologies.
Additional information regarding our oilfield products and services can be found on the Company's website at www.bakerhughes.com. Our website also includes details of our hydraulic fracturing operations, including our hydraulic fracturing chemical disclosure policy and support of the online national hydraulic fracturing chemical registry at www.fracfocus.org, and information on our SmartCare qualified systems and products, which are intended to maximize performance while minimizing our impact on the community and environment.
Industrial Services
Industrial Services consists primarily of our downstream chemicals, and process and pipeline services businesses and provides chemical technologies, equipment, and services that optimize operations throughout the industrial lifecycle (midstream and transportation, processing and refining, water treatment, petrochemical processing). Specifically, downstream chemicals provides products and services that help to increase refinery production, as well as improve plant safety and equipment. Process and pipeline services work to improve efficiency and reduce downtime with inspection, pre-commissioning and commissioning of new and existing pipeline systems and process plants.
MARKETING, COMPETITION AND CONTRACTING
We market our products and services within our four geographic regions on a product line basis primarily through our own sales organizations. We 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 primary competitors include the major diversified oilfield service companies such as Schlumberger, Halliburton and Weatherford International, where the breadth of service capabilities as well as competitive position of each product line are the keys to differentiation in the market. We also compete with other companies who may participate in only a few of the same product lines as us, such as National Oilwell Varco, Ecolab, Newpark Resources and FTS International. Our products and services are sold in highly competitive markets and revenue and earnings are affected by changes in commodity prices, fluctuations in the level of drilling, workover and completion activity in major markets, general economic conditions, foreign currency exchange fluctuations and governmental regulations. We believe that the principal competitive factors in our industries are product and service quality, reliability and availability, health, safety and environmental standards, technical proficiency and price.
Our customers include the large integrated major and super-major oil and natural gas companies, U.S. and international independent oil and natural gas companies and the national or state-owned oil companies. No single customer accounts for more than 10% of our business. While we may have contracts with customers that include multiple well projects and that may extend over a period of time ranging from two to four years, our services and products are generally provided on a well-by-well basis. Most contracts cover our pricing of the products and services, but do not necessarily establish an obligation to use our products and services.
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


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practice, we generally take responsibility for our own people and property while our customers, such as the operator of a well, take responsibility for their own people, property and all liabilities related to the well and subsurface operations, regardless of either party's negligence. In general, any material limitations on indemnifications to us from our customers in support of this allocation of responsibility arise only by applicable statutes.
Certain states such as Texas, Louisiana, Wyoming, and New Mexico have enacted oil and natural gas specific statutes that void any indemnity agreement that attempts to relieve a party from liability resulting from its own negligence ("anti-indemnity statutes"). These statutes can void the allocation of liability agreed to in a contract; however, both the Texas and Louisiana anti-indemnity statutes include important exclusions. The Louisiana statute does not apply to property damage, and the Texas statute allows mutual indemnity agreements that are supported by insurance and has exclusions, which include, among other things, loss or liability for property damage that results from pollution and the cost of well control events. 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 because both Baker Hughes and our customers generally prefer to contract on the basis as we mutually agree. When this does not occur, we will generally use Texas law. With the exclusions contained in the Texas anti-indemnity statute, we are usually able to structure the contract such that the limitation on the indemnification obligations of the customer is limited and should not have a material impact on the terms of the contract. State law, laws or public policy in countries outside the U.S., or the negotiated terms of our agreement with the customer may also limit the customer's indemnity obligations in the event of the gross negligence or willful misconduct of a Company employee. The Company and the customer may also agree to other limitations on the customer's indemnity obligations in the contract.
The Company maintains a commercial general liability insurance policy program that covers against certain operating hazards, including product liability claims and personal injury claims, as well as certain limited environmental pollution claims for damage to a third party or its property arising out of contact with pollution for which the Company is liable; however, clean up and well control costs are not covered by such program. All of the insurance policies purchased by the Company are subject to deductible and/or self-insured retention amounts for which we are responsible for payment, specific terms, conditions, limitations and exclusions. There can be no assurance that the nature and amount of Company insurance will be sufficient to fully indemnify us against liabilities related to our business.
RESEARCH AND DEVELOPMENT AND PATENTS
Our products and technology organization engages in research and development activities directed primarily toward the development of new products, processes and services, the improvement of existing products and services and the design of specialized products to meet specific customer needs. We have technology centers located in the U.S. (several in Houston, Texas and surrounding areas and one in Claremore, Oklahoma), Germany (Celle), Russia (Novosibirsk), and Saudi Arabia (Dhahran). For information regarding the total amount of research and development expense in each of the three years in the period ended December 31, 2016, see Note 1. "Summary of Significant Accounting Policies" 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, trademarks, and related intellectual property rights are adequate for the conduct of our business, and aggressively pursue protection of our intellectual property rights against infringement worldwide. Additionally, we consider the quality and timely delivery of our products, the service we provide to our customers and the technical knowledge and skills of our personnel to be other important components of the portfolio of capabilities and assets supporting our ability to compete. 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, and our customers' budgetary cycles. Examples of seasonal events that can impact our business are set forth below:
The severity and duration of both the summer and the winter in North America can have a significant impact on activity levels. In Canada, the timing and duration of the spring thaw directly affects activity levels, which


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reach seasonal lows during the second quarter and build through the third and fourth quarters to a seasonal high in the first quarter.
Adverse weather conditions such as hurricanes and typhoons can disrupt coastal and offshore drilling and production operations.
Severe weather during the winter months normally results in reduced activity levels in the North Sea and Russia generally in the first quarter.
Scheduled repair and maintenance of offshore facilities in the North Sea can reduce activity in the second and third quarters.
Many of our international oilfield customers increase orders for certain products and services in the fourth quarter.
Our Industrial Services segment typically experiences lower sales during the first and fourth quarters of the year due to the Northern Hemisphere winter.
RAW MATERIALS
We purchase various raw materials and component parts for use in manufacturing our products and delivering our services. The principal materials we purchase include, but are not limited to, steel alloys (including chromium and nickel), titanium, barite, beryllium, copper, lead, tungsten carbide, synthetic and natural diamonds, gels, sand and other proppants, printed circuit boards and other electronic components and hydrocarbon-based chemical feed stocks. These materials are generally available from multiple sources and may be subject to price volatility. While we generally do not experience significant or long-term shortages of these materials, we have from time to time experienced temporary shortages of particular raw materials. We do not expect significant interruptions in the supply of raw materials, but there can be no assurance that there will be no price or supply issues over the long-term.
EMPLOYEES
As of December 31, 2016, we had approximately 33,000 employees, of which the majority are outside the U.S. Approximately 10% of these employees are represented under collective bargaining agreements or similar-type labor arrangements.
EXECUTIVE OFFICERS OF BAKER HUGHES INCORPORATED
The following table shows, as of February 7, 2017, the name of each of our executive officers, together with his or her age and all offices presently or previously held. There are no family relationships among our executive officers.
Name
 
Age
 
Background
Martin S. Craighead
 
57
 
Chairman of the Board of Directors of the Company since April 2013 and Director since 2011. Chief Executive Officer of the Company since January 2012 and President since 2010. Chief Operating Officer from 2009 to 2012. Group President of Drilling and Evaluation from 2007 to 2009. President of INTEQ from 2005 to 2007 and President of Baker Atlas from February 2005 to August 2005. Employed by the Company in 1986.
Kimberly A. Ross
 
51
 
Senior Vice President and Chief Financial Officer of the Company since October 2014. Executive Vice President and Chief Financial Officer of Avon Products Incorporated from 2011 to 2014. Executive Vice President and Chief Financial Officer of Royal Ahold N.V. from 2007 to 2011 and various other finance positions with Royal Ahold from 2001 to 2007. Ms. Ross serves on the board of directors and the audit committee of Chubb Limited. Employed by the Company in October 2014.
Belgacem Chariag
 
54
 
President, Global Operations since May 2016. Chief Integration Officer from December 2014 to May 2016. President, Global Products and Services of the Company from October 2013 to December 2014. President, Eastern Hemisphere Operations from 2009 to 2013. Vice President/Director HSE of Schlumberger Limited from May 2008 to May 2009. Various other executive positions at Schlumberger from 1989 to 2008. Employed by the Company in 2009.


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Archana Deskus
 
51
 
Vice President and Chief Information Officer of the Company since 2013. Vice President and Chief Information Officer for Ingersoll-Rand from 2011 to 2012. Senior Vice President and Chief Information Officer for Timex Group from 2006 to 2011. Various positions at United Technologies from 1987 to 2006, including Vice President and Chief Information Officer for Carrier North America. Employed by the Company in 2013.
Jack Hinton
 
63
 
Vice President, Health, Safety and Environment since 2015.  Vice President, Enterprise Solutions at the Company from 2011 to 2014 and Director Health, Safety and Environment at the Company from 2005 to 2010.  Dean and professor at the Kazakhstan Institute of Management, Economics and Strategic Research from 2004 to 2005. He previously spent 26 years at Texaco in various Health, Safety and Environment leadership roles. Employed by the Company in 2005.
Kelly C. Janzen
 
44
 
Vice President, Controller and Chief Accounting Officer since September 2016. Vice President, Finance and Chief Accounting Officer for McDermott International from December 2014 to August 2016. Distributed Power Global Controller at General Electric Company ("GE") from April 2013 to November 2014 and Operational Controller, Global Growth and Operations at GE from August 2011 to April 2013. Various corporate roles at GE from 2007 to 2011. Employed by the Company in 2016.
Murali Kuppuswamy
 
55
 
Chief Human Resources Officer since May 2016. Vice President, Human Resources for Europe, Africa and Russia Caspian from December 2013 through May 2016. Vice President, Human Resources for Global Products and Technology from September 2011 through December 2013. Various human resources leadership roles at GE from 1993 to 2011. Employed by the Company in 2011.
William D. Marsh
 
54
 
Vice President and General Counsel of the Company since February 2013. Vice President-Legal for Western Hemisphere from May 2009 to February 2013. Various executive, legal and corporate roles within the Company from 1998 to 2009. Partner at Ballard Spahr LLP from 1997 to 1998. Mr. Marsh serves on the Board of Directors of People's Utah Bancorp (bank holding company). Employed by the Company in 1998.
Jay G. Martin
 
65
 
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. Employed by the Company in 2004.
Derek Mathieson
 
46
 
Chief Commercial Officer since May 2016. Chief Technology and Marketing Officer of the Company from September 2015 to May 2016 and Chief Strategy Officer from October 2013 to September 2015. President Western Hemisphere Operations from 2012 to 2013. President, Products and Technology from May 2009 to January 2012. Chief Technology and Marketing Officer of the Company from December 2008 to May 2009. Employed by the Company in 2008.
Arthur L. Soucy
 
54
 
President, Products and Technology from May 2016. President, Europe, Africa and Russia Caspian Region of the Company from 2013 to May 2016. President, Global Products and Services from 2012 to 2013. Vice President Supply Chain of the Company from April 2009 to January 2012. Vice President, Global Supply Chain for Pratt and Whitney from 2007 to 2009. Employed by the Company in 2009.
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 extensive domestic (including U.S. federal, state and local) and international regulations with regard to air, land and water quality and other environmental matters. We believe we are in substantial compliance with these regulations. Regulation in this area continues to evolve, and changes in standards of enforcement of existing regulations, as well as the enactment and enforcement of new legislation, may require us and our customers to modify, supplement or replace equipment or facilities or to change or discontinue present methods of operation. Our environmental compliance expenditures and our capital costs for environmental control equipment may change accordingly.
We are involved in voluntary remediation projects at certain of our facilities. 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,


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and such amounts can be reasonably estimated. Accruals are recorded even if significant uncertainties exist over the ultimate cost of the remediation. Ongoing environmental compliance costs, such as obtaining environmental permits, installation of pollution control equipment and waste disposal, are expensed as incurred.
The Comprehensive Environmental Response, Compensation and Liability Act (known as "Superfund") imposes liability for the release of a "hazardous substance" into the environment. Superfund liability is imposed without regard to fault, even if the waste disposal was in compliance with laws and regulations. The U.S. Environmental Protection Agency (the "EPA") and appropriate state agencies supervise investigative and cleanup activities at Superfund sites. We have been identified as a potentially responsible party ("PRP") in remedial activities related to various Superfund sites, and we accrue our share of the estimated remediation costs of the site based on the ratio of the estimated volume of waste we contributed to the site to the total volume of waste disposed at the site. PRPs in Superfund actions have joint and several liability for all costs of remediation. Accordingly, a PRP may be required to pay more than its proportional share of such costs. For some projects, it is not possible to quantify our ultimate exposure because the projects are either in the investigative or early remediation stage, or allocation information is not yet available. However, based upon current information, we do not believe that probable or reasonably possible expenditures in connection with the sites are likely to have a material adverse effect on our consolidated financial statements because we have recorded adequate reserves to cover the estimate we presently believe will be our ultimate liability in the matter. Further, other PRPs involved in the sites have substantial assets and may reasonably be expected to pay their share of the cost of remediation, and, in some circumstances, we have insurance coverage or contractual indemnities from third parties to cover a portion of the ultimate liability.
Based upon current information, we believe that our overall compliance with environmental regulations, including routine environmental compliance costs and capital expenditures for environmental control equipment, will not have a material adverse effect on 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 was $31 million and $35 million at December 31, 2016 and 2015, respectively, which included accruals of $2 million in each year for the various Superfund sites.
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 are 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 by improving our assurance programs.
ITEM 1A. RISK FACTORS
An investment in our common stock involves various risks. When considering an investment in Baker Hughes, one should carefully consider all of the risk factors described below, as well as other information included and incorporated by reference in this annual report. There may be additional risks, uncertainties and matters not listed below, that we are unaware of, or that we currently consider immaterial. Any of these may adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in Baker Hughes.
Risk Factors Related to the Worldwide Oil and Natural Gas Industry
Our business is focused on providing products and services to the worldwide oil and natural gas industry; therefore, our risk factors include those factors that impact, either positively or negatively, the markets for oil and natural gas. Expenditures by our customers for exploration, development and production of oil and natural gas are based on their expectations of future hydrocarbon demand, their expectations for future energy prices, 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, spare productive 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.


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Demand for oil and natural gas is subject to factors beyond our control, which may adversely affect our operating results. Changes in the global economy could impact our customers' spending levels and our revenue and operating results.
Demand for oil and natural gas, as well as the demand for our services, is highly correlated with global economic growth, and in particular by the economic growth of countries such as the U.S., India, China, and developing countries in Asia and the Middle East who are either significant users of oil and natural gas or whose economies are experiencing the most rapid economic growth compared to the global average. Weakness or deterioration of the global economy or credit markets could reduce our customers' spending levels and reduce our revenue and operating results. Events such as Britain's vote in late June 2016 to leave the European Union and incremental weakness in global economic activity, particularly in China, India, Europe, the Middle East and developing countries in Asia, could reduce demand for oil and natural gas and result in lower oil and natural gas prices. Incremental strength in global economic activity in such areas will create more demand for oil and natural gas and support higher oil and natural gas prices. In addition, demand for oil and natural gas could be impacted by environmental regulation, including cap and trade legislation, regulation of hydraulic fracturing, carbon taxes and the cost for carbon capture and sequestration related regulations.
Supply of oil and natural gas is subject to factors beyond our control, which may adversely affect our operating results.
Productive capacity for oil and natural gas is dependent on our customers' decisions to develop and produce oil and natural gas reserves and on the regulatory environment in which our customers and we operate. The ability to produce oil and natural gas can be affected by the number and productivity of new wells drilled and completed, as well as the rate of production and resulting depletion of existing wells. Advanced technologies, such as horizontal drilling and hydraulic fracturing, improve total recovery but also result in a more rapid production decline and may become subject to more stringent regulation in the future.
Productive capacity in excess of demand ("spare productive capacity") is also an important factor influencing energy prices and spending by oil and natural gas exploration companies. 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, inventories, or spare productive capacity generally indicate that supply is exceeding demand and that energy prices are likely to soften. Low or decreasing storage, inventories, or spare productive capacity are generally an indicator that demand is growing faster than supply and that energy prices are likely to rise.
Access to prospects is also important to our customers and such access may be limited because host governments do not allow access to the reserves. 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 effect on our results of operations.
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. Since 2014, oil prices have declined significantly due in large part to increasing supplies, weakening demand growth and OPEC's position to not cut production until the fourth quarter of 2016. Expectations about future prices and price volatility are important for determining future spending levels.


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Lower oil and natural gas prices generally lead to decreased spending by our customers. While higher oil and natural gas prices generally lead to increased spending by our customers, sustained high energy prices can be an impediment to economic growth, and can therefore negatively impact spending by our customers. Our customers also take into account the volatility of energy prices and other risk factors by requiring higher returns for individual projects if there is higher perceived risk. Any of these factors could affect the demand for oil and natural gas and could have a material effect on our results of operations.
Our customers' activity levels and spending for our products and services and ability to pay amounts owed us could be impacted by the reduction of their cash flow and the ability of our customers to access equity or credit markets.
Our customers' access to capital is dependent on their ability to access the funds necessary to develop 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 available debt or equity financing may impact the ability of our customers to pay amounts owed to us and could cause us to increase our reserve for doubtful accounts.
Seasonal and weather conditions could adversely affect demand for our services and operations.
Variation from normal weather patterns, such as cooler or warmer summers and winters, can have a significant impact on demand. Adverse weather conditions, such as hurricanes in the Gulf of Mexico, may interrupt or curtail our operations, or our customers' operations, cause supply disruptions and result in a loss of revenue and damage to our equipment and facilities, which may or may not be insured. Extreme winter conditions in Canada, Russia or the North Sea may interrupt or curtail our operations, or our customers' operations, in those areas and result in a loss of revenue.
Risk Factors Related to Our Business
Our expectations regarding our business are affected by the following risk factors and the timing of any of these risk factors:
We operate in a highly competitive environment, which may adversely affect our ability to succeed.
We operate in a highly competitive environment for marketing oilfield services and securing equipment and trained personnel. Our ability to continually provide competitive products and services can impact our ability to defend, maintain or increase prices for our products and services, maintain market share, and negotiate acceptable contract terms with our customers. In order to be competitive, we must provide new technologies, reliable products and services that perform as expected and that create value for our customers, and successfully recruit, train and retain competent personnel. Our investments in new technologies and property, plant and equipment may not provide competitive returns. Our ability to defend, maintain or increase prices for our products and services is in part dependent on the industry's capacity relative to customer demand, and on our ability to differentiate the value delivered by our products and services from our competitors' products and services.
Managing development of competitive technology and new product introductions on a forecasted schedule and at forecasted costs can impact our financial results. Development of competing technology that accelerates the obsolescence of any of our products or services can have a detrimental impact on our financial results.
We may be disadvantaged competitively and financially by a significant movement of exploration and production operations to areas of the world in which we are not currently active.
The high cost or unavailability of infrastructure, materials, equipment, supplies and personnel, particularly in periods of rapid growth, could adversely affect our ability to execute our operations on a timely basis.
Our manufacturing operations are dependent on having sufficient raw materials, component parts and manufacturing capacity available to meet our manufacturing plans at a reasonable cost while minimizing inventories. Our ability to effectively manage our manufacturing operations and meet these goals can have an


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impact on our business, including our ability to meet our manufacturing plans and revenue goals, control costs, and avoid shortages or over supply of raw materials and component parts. Raw materials and components of particular concern include steel alloys (including chromium and nickel), titanium, barite, beryllium, copper, lead, tungsten carbide, synthetic and natural diamonds, gels, sand and other proppants, printed circuit boards and other electronic components and hydrocarbon-based chemical feed stocks. Our ability to repair or replace equipment damaged or lost in the well can also impact our ability to service our customers. A lack of manufacturing capacity could result in increased backlog, which may limit our ability to respond to orders with short lead times.
People are a key resource to developing, manufacturing and delivering our products and services to our customers around the world. Our ability to manage the recruiting, training, retention and efficient usage of the highly skilled workforce required by our plans and to manage the associated costs could impact our business. A well-trained, motivated workforce has a positive impact on our ability to attract and retain business. Periods of rapid growth present a challenge to us and our industry to recruit, train and retain our employees, while managing the impact of wage inflation and potential lack of available qualified labor in the markets where we operate.
Likewise, if the downturn in the economy or our markets continues, we may have to adjust our workforce to control costs and may 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 could be impacted by geopolitical and terrorism threats.
Geopolitical and terrorism risks continue to grow in a number of key countries where we do business. Geopolitical and terrorism risks could lead to, among other things, a loss of our investment in the country, impairment of the safety of our employees and impairment of our ability to conduct our operations.
Our business operations may be impacted by civil unrest, government expropriations and/or epidemic outbreaks.
In addition to other geopolitical and terrorism risks, civil unrest continues to grow in a number of key countries where we do business. Our ability to conduct business operations may be impacted by that civil unrest and our assets in these countries may also be subject to expropriation by governments or other parties involved in civil unrest. Epidemic outbreaks may also impact our business operations by, among other things, restricting travel to protect the health and welfare of our employees and decisions by our customers to curtail or stop operations in impacted areas.
Our business could be impacted by cybersecurity risks and threats.
Threats to our information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow and it is possible that breaches to our systems could go unnoticed for some period of time. Risks associated with these threats include, among other things, loss of intellectual property, impairment of our ability to conduct our operations, disruption of our customers' operations, loss or damage to our customer data delivery systems, and increased costs to prevent, respond to or mitigate cybersecurity events.
Our failure to comply with the Foreign Corrupt Practices Act ("FCPA") and other laws could have a negative impact on our ongoing operations.
Our ability to comply with the FCPA, the U.K. Bribery Act and various other anti-bribery and anti-corruption laws is dependent on the success of our ongoing compliance program, including our ability to continue to manage our agents and business partners, and supervise, train and retain competent employees. Our compliance program is also dependent on the efforts of our employees to comply with applicable law and the Baker Hughes Business Code of Conduct. We could be subject to sanctions and civil and criminal prosecution as well as fines and penalties in the event of a finding of a violation of any of these laws by us or any of our employees.
Compliance with and changes in laws could be costly and could affect operating results. In addition, government disruptions could negatively impact our ability to conduct our business.
We conduct business in the U.S. and in more than 80 countries that can be impacted by expected and unexpected changes in the legal and business environments in which we operate. Compliance related issues could


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also limit our ability to do business in certain countries and impact our earnings. 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. In addition, government disruptions, such as a U.S. government shutdown, may delay or halt the granting and renewal of permits, licenses and other items required by us and our customers to conduct our business.
Changes in tax laws or tax rates, adverse positions taken by taxing authorities and tax audits could impact operating results.
The U.S. and global tax environment today is evolving rapidly with a number of countries in which we operate enacting, or planning to enact, legislative changes that conform to the Organization for Economic Cooperation and Development's ("OECD") Base Erosion and Profit Shifting ("BEPS") project or otherwise make fundamental modifications to their tax regimes. These changes in tax laws or tax rates, the resolution of tax assessments or audits by various tax authorities, and the ability to fully utilize our tax loss carryforwards and tax credits could impact operating results, including additional valuation allowances for deferred tax assets. In addition, we may periodically restructure our legal entity organization. If taxing authorities were to disagree with our tax positions in connection with any such restructurings, our effective tax rate could be materially impacted.
Our tax filings for various periods are subject to audit by the tax authorities in most jurisdictions where we conduct business. We have received tax assessments from various taxing authorities and are currently at varying stages of appeals and/or litigation regarding these matters. These audits may result in assessment of additional taxes that are resolved with the authorities or through the courts. We believe these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. Resolution of any tax matter involves uncertainties and there are no assurances that the outcomes will be favorable.
Changes in and compliance with restrictions or regulations on offshore drilling may adversely affect our business and operating results and reduce the need for our services in those areas.
Legislation and regulation in the U.S. and other parts of the world of the offshore oil and natural gas industry may result in substantial increases in costs or delays in drilling or other operations in the Gulf of Mexico and other parts of the world, oil and natural gas projects becoming potentially non-economic, and a corresponding reduced demand for our services. 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, higher operating costs could result and adversely affect our business and operating results.
If the Company were to be involved in a future incident similar to the 2010 Deepwater Horizon accident, the Company could suffer significant financial losses that could severely impair the Company. Protections available to the Company through contractual terms and insurance coverage may not be sufficient to protect the Company in the event we were involved in that type of an incident.
Compliance with, and rulings and litigation in connection with, environmental regulations and the environmental impacts of our or our customers' operations may adversely affect our business and operating results.
Our business is impacted by material changes in environmental laws, rulings and litigation. Our expectations regarding our compliance with environmental laws and our expenditures to comply with environmental laws, including (without limitation) our capital expenditures for environmental control equipment, are only our forecasts regarding these matters. These forecasts may be substantially different from actual results, which may be affected by factors such as: changes in law that impose new restrictions on air emissions, wastewater management, waste disposal, hydraulic fracturing, or wetland and land use practices; more stringent enforcement of existing environmental regulations; a change in our allocation or other unexpected, adverse outcomes with respect to sites where we have been named as a PRP, including (without limitation) Superfund sites; the discovery of other sites where additional expenditures may be required to comply with environmental legal obligations; and the accidental discharge of hazardous materials.


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International, national, and state governments and agencies continue to evaluate and promulgate legislation and regulations that are focused on restricting emissions commonly referred to as greenhouse gas ("GHG") emissions. In the U.S., the EPA has taken steps to regulate GHG emissions as air pollutants under the Clean Air Act. The EPA's Greenhouse Gas Reporting Rule requires monitoring and reporting of GHG emissions from, among others, certain mobile and stationary GHG emission sources in the oil and natural gas industry, which in turn may include data from some of our wellsite equipment and operations. The EPA has also proposed other related GHG emission standards that are applicable to the oil and natural gas industry, including several targeting methane, some of which have been adopted. The impact of these standards on our business, both proposed and adopted, remains unclear given recent actions taken by Congress and the current U.S. Administration. Other developments focused on restricting GHG emissions include the United Nations Framework Convention on Climate Change, which includes the Paris Agreement and the Kyoto Protocol; the European Union Emission Trading System; and, the United Kingdom's Carbon Reduction Commitment which affects more than 40 Baker Hughes facilities. Other regulatory changes have been proposed related to climate change including emissions trading schemes, carbon taxes and emissions reduction targets in various areas across the globe.
We are unable to predict whether proposed changes in laws or regulations will ultimately occur or what the adopted and proposed changes will ultimately require, and accordingly, we are unable to assess the potential financial or operational impact they may have on our business. In addition, current or future legislation, regulations and developments may curtail production and demand for hydrocarbons such as oil and natural gas in areas of the world where our customers operate and thus adversely affect future demand for our services, which may in turn adversely affect future results of operations.
We may be subject to litigation if another party claims that we have infringed upon its intellectual property rights.
The tools, techniques, methodologies, programs and components we use to provide our services may infringe upon the intellectual property rights of others. Infringement claims generally result in significant legal and other costs and may distract management from running our core business. Royalty payments under licenses from third parties, if available, would increase our costs. Additionally, developing non-infringing technologies would increase our costs. If a license were not available, we might not be able to continue providing a particular service or product, which could adversely affect our financial condition, results of operations and cash flows.
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 control failure 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.


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Control of oil and natural gas reserves by state-owned oil companies may impact the demand for our services and create additional risks in our operations.
Much of the world's oil and natural gas reserves are controlled by state-owned oil companies. State-owned oil companies may require their contractors to meet local content requirements or other local standards, such as joint ventures, that could be difficult or undesirable for the Company to meet. The failure to meet the local content requirements and other local standards may adversely impact the Company's operations in those countries. In addition, our ability to work with state-owned oil companies is subject to our ability to negotiate and agree upon acceptable contract terms.
Providing services on an integrated or turnkey basis could require the Company to assume additional risks.
Many state-owned oil companies and other operators may require integrated contracts or turnkey contracts and the Company may choose to provide services outside its core business. Providing services on an integrated or turnkey basis generally subjects the Company to additional risks, such as costs associated with unexpected delays or difficulties in drilling or completion operations and risks associated with subcontracting arrangements.
Currency fluctuations or devaluations may impact our operating results.
Fluctuations or devaluations in foreign currencies relative to the U.S. Dollar can impact our revenue and our costs of doing business. Most of our products and services are sold through contracts denominated in U.S. Dollars or local currency indexed to U.S. Dollars; however, some of our revenue, local expenses and manufacturing costs are incurred in local currencies and therefore changes in the exchange rates between the U.S. Dollar and foreign currencies can increase or decrease our revenue and expenses reported in U.S. Dollars and may impact our results of operations.
Changes in economic and/or market conditions may impact our ability to borrow and/or cost of borrowing.
The condition of the capital markets and equity markets in general can affect the price of our common stock and our ability to obtain financing, if necessary. If the Company's credit rating is downgraded, this could increase borrowing costs under our credit facility and commercial paper program, as well as the cost of renewing or obtaining, or make it more difficult to renew or obtain or issue new debt financing.
Our restructuring activities may not achieve the results we expect and could increase, which could materially and adversely affect our results of operations and financial condition.
During 2015 and 2016, we implemented a number of restructuring activities to reduce expenses, which included a reduction in our workforce, the termination of various contracts, the closing or abandoning of certain facilities, the downsizing of our presence in select markets and the contribution of our North American onshore pressure pumping business to BJ Services, LLC. There can be no assurance that our restructuring activities will produce the cost savings we anticipate in the expected timeframe or that the cumulative restructuring activities and charge will not have to increase in order to achieve our cost savings targets. Any delay or failure to achieve the expected cost savings and any increase in our anticipated cumulative restructuring activities and charge would likely cause our future earnings to be lower than anticipated.
The BJ Services, LLC venture may not achieve the results we expect and could result in a loss of our investment in the North America onshore pressure pumping business.
The Company will no longer control its North America onshore pressure pumping business and must rely on the management of BJ Services, LLC to operate that business.  Poor performance or additional government regulation of that business could result in lower profitability than expected and could ultimately result in a loss of the investment the Company has in the business through its ownership of the LLC. This investment, and the related earnings, will be excluded from our North America segment.


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Risk Factors Related to the GE Transaction
Our expectations regarding our business may be impacted by the following risk factors related to the pending GE Transaction:
The pendency of the GE Transaction could adversely affect our business.
In connection with the GE Transaction, some of our suppliers and customers may delay or defer sales and purchasing decisions, which could negatively impact revenues, earnings and cash flows regardless of whether the GE Transaction is completed. We have agreed in the Transaction Agreement to refrain from taking certain actions with respect to our business and financial affairs during the pendency of the GE Transaction, which restrictions could be in place for an extended period of time if completion of the GE Transaction is delayed and could adversely impact our financial condition, results of operations or cash flows. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business before completion of the GE Transaction or termination of the Transaction Agreement. The process of seeking to accomplish the GE Transaction could also divert the focus of our management from pursuing other opportunities that could be beneficial to us.
The pursuit of the GE Transaction and the preparation for the integration of Baker Hughes and GE O&G have placed, and will continue to place, a significant burden on our management and internal resources. There is a significant degree of difficulty and management distraction inherent in the process of seeking to close the GE Transaction and integrate Baker Hughes and GE O&G, which could cause an interruption of, or loss of momentum in, the activities of our existing business, regardless of whether the GE Transaction is eventually completed. Our management team will be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our existing businesses, service existing customers, attract new customers and develop new products, services or strategies. One potential consequence of such distractions could be the failure of management to realize other opportunities that could be beneficial to us. If our senior management is not able to effectively manage the process leading up to and immediately following Closing, or if any significant business activities are interrupted as a result of the integration process, the business of Baker Hughes could suffer.
We may be unable to attract and retain key employees during the pendency of the GE Transaction.
In connection with the GE Transaction, current and prospective employees of Baker Hughes may experience uncertainty about their future roles with Baker Hughes, a GE Company following the GE Transaction ("New Baker Hughes"), which may materially adversely affect our ability to attract and retain key personnel during the pendency of the GE Transaction. Key employees may depart because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with New Baker Hughes following the Transaction. The departure of existing key employees or the failure of potential key employees to accept employment with New Baker Hughes, despite our recruiting efforts, could have a material adverse impact on our business, financial condition and operating results, regardless of whether the GE Transaction is eventually completed.
The GE Transaction may not be completed on the terms or timeline currently contemplated, or at all, and failure to complete the GE Transaction may result in material adverse consequences to our business and operations.
The GE Transaction is subject to several closing conditions, including the adoption of the Transaction Agreement by our stockholders, the expiration or termination of any applicable waiting period under the U.S. Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act") and the receipt of regulatory approvals in certain other jurisdictions. The closing conditions also include the delivery by GE to us of the audited financial statements of GE O&G and the absence of differences between such audited financial statements and the unaudited financial statements of GE O&G that were delivered by GE to us prior to the date of the Transaction Agreement that are material to the intrinsic value of GE O&G (as determined in a manner consistent with appropriate valuation methodologies), excluding changes in goodwill and certain other exclusions. If any one of these conditions is not satisfied or waived, the GE Transaction may not be completed. There is no assurance that the GE Transaction will be completed on the terms or timeline currently contemplated, or at all.
The parties have not yet obtained all regulatory clearances, consents and approvals required to complete the GE Transaction. Governmental or regulatory agencies could still seek to block or challenge the GE Transaction or


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could impose restrictions they deem necessary or desirable in the public interest as a condition to approving the GE Transaction. These restrictions could include a requirement to sell certain specified businesses that GE is obligated under the terms of the Transaction Agreement to divest if necessary to obtain such regulatory approvals. If these approvals are not received, then neither we nor GE will be obligated to complete the GE Transaction. If the approvals could be received, but the applicable regulatory agency is not satisfied that a qualified buyer has been found or imposes on a party any antitrust action that would have an effect exceeding $200 million in revenue for the twelve months ended December 31, 2015 (other than with respect to the divestiture of certain specified businesses, which are not subject to the preceding limitations), GE would not be required to agree to undertake such actions and neither we nor GE would be obligated to complete the GE Transaction.
If our stockholders do not approve and adopt the Transaction Agreement or if the GE Transaction is not completed for any other reason, we would be subject to a number of risks, including the following:
the attention of our management may have been diverted to the GE Transaction instead of on our operations and pursuit of other opportunities that may have been beneficial to us;
resulting negative customer perception could adversely affect our ability to compete for, or to win, new and renewal business in the marketplace;
we and our stockholders would not realize the anticipated benefits of the GE Transaction, including a special one-time cash dividend of $17.50 per share of Newco Class A Common Stock and any anticipated synergies from combining our business with GE O&G;
we may be required to pay a termination fee of $750 million if the Transaction Agreement is terminated in the case of certain events described in the Transaction Agreement, including due to an adverse change in our board of directors' recommendation to our stockholders to approve the GE Transaction;
the trading price of our common stock may experience increased volatility to the extent that the current market prices reflect a market assumption that the GE Transaction will be completed; or
the Company could be subject to litigation from shareholders related to the Transaction Agreement.
The occurrence of any of these events individually or in combination could have a material adverse effect on our results of operations or the trading price of our common stock.
Even if the GE Transaction is closed, the integration of Baker Hughes and GE O&G following the Closing will present significant challenges that may result in a decline in the anticipated benefits of the GE Transaction.
The GE Transaction involves the combination of two businesses that currently operate as independent businesses. New Baker Hughes will be required to devote management attention and resources to integrating its business practices and operations, and prior to the GE Transaction, management attention and resources will be required to plan for such integration. Potential difficulties New Baker Hughes may encounter in the integration process include the following:
the inability to successfully integrate the two businesses, including operations, technologies, products and services, in a manner that permits New Baker Hughes to achieve the cost savings and operating synergies anticipated to result from the GE Transaction, which could result in the anticipated benefits of the GE Transaction not being realized partly or wholly in the time frame currently anticipated or at all;
lost sales and customers as a result of certain customers of either or both of the two businesses deciding not to do business with New Baker Hughes, or deciding to decrease their amount of business in order to reduce their reliance on a single company;
the necessity of coordinating geographically separated organizations, systems and facilities;
potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated with the GE Transaction;


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integrating personnel with diverse business backgrounds and business cultures, while maintaining focus on providing consistent, high-quality products and services;
consolidating and rationalizing information technology platforms and administrative infrastructures as well as accounting systems and related financial reporting activities;
preserving important relationships of both Baker Hughes and GE O&G and resolving potential conflicts that may arise; and
performance shortfalls at one or both of Baker Hughes and GE O&G as a result of the diversion of management's attention caused by completing the GE Transaction and integrating the two businesses' operations.
The Transaction Agreement contains provisions that may discourage other companies from trying to acquire us.
The Transaction Agreement contains provisions that may discourage third parties from submitting business combination proposals to us that might result in greater value to our stockholders than the GE Transaction. The Transaction Agreement generally prohibits us from soliciting any competing acquisition proposal. In addition, if the Transaction Agreement is terminated by us or GE in circumstances that obligates us to pay a termination fee and to reimburse transaction expenses to GE, our financial condition may be adversely affected as a result of the payment of the termination fee and transaction expenses, which might deter third parties from proposing alternative business combination proposals.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
We own or lease numerous properties throughout the world. We consider our manufacturing plants, equipment assembly, maintenance and overhaul facilities, grinding plants, drilling fluids and chemical processing centers, and primary research and technology centers to be our principal properties. The following sets forth the location of our principal owned or leased facilities for our oilfield operations and Industrial Services segments as of December 31, 2016:

North America:
 
Houston, Pasadena, and The Woodlands, Texas; Broken Arrow, Claremore, Tulsa and Sand Springs, Oklahoma; Bossier City, Broussard, and Lafayette, Louisiana - all located in the United States; and Leduc, Canada
Europe/Africa/Russia Caspian:
 
Aberdeen, Scotland; Liverpool, England; Celle, Germany; Tananger, Norway; Port Harcourt, Nigeria; Luanda, Angola; Tyumen and Novosibirsk, Russia
Middle East/Asia Pacific:
 
Dubai, United Arab Emirates; Dhahran, Saudi Arabia; Singapore, Singapore; Chonburi, Thailand; and Hsinchu, Taiwan
Industrial Services:
 
Pasadena, Texas; Sand Springs and Barnsdall, Oklahoma; Taft, California; and Liverpool, England
We own or lease numerous other facilities such as service centers, blend plants, workshops and sales and administrative offices throughout the geographic regions in which we operate. We also have a significant investment in service vehicles, tools and manufacturing and other equipment. All of our owned properties are unencumbered. We believe that our facilities are well maintained and suitable for their intended purposes.


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ITEM 3. LEGAL PROCEEDINGS
We are subject to a number of lawsuits and claims arising out of the conduct of our business. The ability to predict the ultimate outcome of such matters involves judgments, estimates and inherent uncertainties. We record a liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated, including accruals for self-insured losses which are calculated based on historical claim data, specific loss development factors and other information. A range of total possible losses for all litigation matters cannot be reasonably estimated. Based on a consideration of all relevant facts and circumstances, we do not expect the ultimate outcome of any currently pending lawsuits or claims against us will have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these matters.
We insure against risks arising from our business 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 or future legal proceedings or other claims. Most of our 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 following lawsuits were filed in Delaware in connection with our Merger with Halliburton. Subsequent to the filing of the lawsuits, on April 30, 2016, the Merger Agreement with Halliburton was terminated as described in Note 2. "Halliburton Terminated Merger Agreement."
On November 24, 2014, Gary Molenda, a purported shareholder of the Company, filed a class action lawsuit in the Court of Chancery of the State of Delaware ("Delaware Chancery Court") against Baker Hughes, the Company's Board of Directors, Halliburton, and Red Tiger LLC, a wholly owned subsidiary of Halliburton ("Red Tiger" and together with all defendants, "Defendants") styled Gary R. Molenda v. Baker Hughes, Inc., et al., Case No. 10390-CB.
On November 26, 2014, a second purported shareholder of the Company, Booth Family Trust, filed a substantially similar class action lawsuit in Delaware Chancery Court.
On December 1, 2014, New Jersey Building Laborers Annuity Fund and James Rice, two additional purported shareholders of the Company, filed substantially similar class action lawsuits in Delaware Chancery Court.
On December 10, 2014, a fifth purported shareholder of the Company, Iron Workers Mid-South Pension Fund, filed another substantially similar class action lawsuit in the Delaware Chancery Court.
On December 24, 2014, a sixth purported shareholder of the Company, Annette Shipp, filed another substantially similar class action lawsuit in the Delaware Chancery Court.
All of the lawsuits make substantially similar claims.  The plaintiffs generally allege that the members of the Company's Board of Directors breached their fiduciary duties to our shareholders in connection with the Merger negotiations by entering into the Merger Agreement and by approving the Merger, and that the Company, Halliburton, and Red Tiger aided and abetted the purported breaches of fiduciary duties.  More specifically, the lawsuits allege that the Merger Agreement provides inadequate consideration to our shareholders, that the process resulting in the Merger Agreement was flawed, that the Company's directors engaged in self-dealing, and that certain provisions of the Merger Agreement improperly favor Halliburton and Red Tiger, precluding or impeding third parties from submitting potentially superior proposals, among other things.  The lawsuit filed by Annette Shipp also alleges that our Board of Directors failed to disclose material information concerning the proposed Merger in the preliminary registration statement on Form S-4.  On January 7, 2015, James Rice amended his complaint, adding similar allegations regarding the disclosures in the preliminary registration statement on Form S-4.  The lawsuits seek unspecified damages, injunctive relief enjoining the Merger, and rescission of the Merger Agreement, among other relief.  On January 23, 2015, the Delaware lawsuits were consolidated under the caption In re Baker Hughes Inc. Stockholders Litigation, Consolidated C.A. No. 10390-CB (the "Consolidated Case"). Pursuant to the Court's consolidation order, plaintiffs filed a consolidated complaint on February 4, 2015, which alleges substantially similar claims and seeks substantially similar relief to that raised in the six individual complaints, except that while Baker Hughes is named as a defendant, no claims are asserted against the Company.


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On March 18, 2015, the parties reached an agreement in principle to settle the Consolidated Case in exchange for the Company making certain additional disclosures. Those disclosures were contained in a Form 8-K filed with the SEC on March 18, 2015. The settlement was made subject to certain conditions, including consummation of the Merger, final documentation, and court approval. With the termination of the Merger Agreement with Halliburton, the March 18, 2015 settlement agreement is rendered null and void. On May 31, 2016, the Consolidated Case and the claims asserted therein were dismissed, save and except for plaintiffs counsel's Fee and Expense Application to the Delaware Chancery Court. On October 13, 2016, the Delaware Chancery Court ruled on plaintiffs counsel's Fee and Expense Application. The amount awarded does not have a material impact on our financial position, results of operations or cash flows.
On October 9, 2014, one of our subsidiaries filed a Request for Arbitration against a customer before the London Court of International Arbitration, pursuing claims for the non-payment of invoices for goods and services provided in an amount provisionally quantified to exceed $67.9 million. In our Request for Arbitration, we also noted that invoices in an amount exceeding $57 million had been issued to the customer, and would be added to the claim in the event that they became overdue. On November 6, 2014, the customer filed its Response and Counterclaim, denying liability and counterclaiming damages for breach of contract of approximately $182 million. On March 31, 2016, the parties agreed to a settlement principally involving the purchase by the customer of certain inventory held by our subsidiary, with all other claims and counterclaims being released and discharged by each party, and the arbitral proceedings being discontinued. On April 18, 2016, all claims and counterclaims filed in the London Court of International Arbitration were released and discontinued. The settlement did not have a material impact on our financial position, results of operations or cash flows.
During 2014, we received customer notifications related to a possible equipment failure in a natural gas storage system in Northern Germany, which includes certain of our products. We are currently investigating the cause of the possible failure and, if necessary, possible repair and replacement options for our products. Similar products were utilized in other natural gas storage systems for this and other customers. The customer initiated arbitral proceedings against us on June 19, 2015, under the rules of the German Institute of Arbitration e.V. (DIS). On August 3, 2016, the customer amended its claims and now alleges damages of approximately $224 million plus interest at an annual rate of prime + 5%. A hearing before the arbitration panel was held January 16, 2017 through January 23, 2017, and an additional hearing is scheduled for March 20, 2017 and March 21, 2017. In addition, on September 21, 2015, TRIUVA Kapitalverwaltungsgesellschaft mbH filed a lawsuit in the United States District Court for the Southern District of Texas Houston Division against the Company and Baker Hughes Oilfield Operations, Inc. alleging that the plaintiff is the owner of gas storage caverns in Etzel, Germany in which the Company provided certain equipment in connection with the development of the gas storage caverns. The plaintiff further alleges that the Company supplied equipment that was either defectively designed or failed to warn of risks that the equipment posed, and that these alleged defects caused damage to the plaintiff's property. The plaintiff seeks recovery of alleged compensatory and punitive damages of an unspecified amount, in addition to reasonable attorneys' fees, court costs and pre-judgment and post-judgment interest. The allegations in this lawsuit are related to the claims made in the June 19, 2015 German arbitration referenced above. At this time, we are not able to predict the outcome of these claims or whether either will have any material impact on our financial position, results of operations or cash flows.
On August 31, 2015, a customer of one of the Company's subsidiaries issued a Letter of Claim pursuant to a Construction and Engineering Contract. The customer had claimed $369 million plus loss of production resulting from a breach of contract related to five electric submersible pumps installed by the subsidiary in Europe. On January 29, 2016, the Customer served its Statement of Claim, Case No. CL-2015-00584, in the Commercial Court Queen's Bench Division of the High Court of Justice. On September 20, 2016, the parties entered a settlement agreement by which all claims were released and discharged by each party. On October 6, 2016, the Commercial Court entered a Consent Order dismissing all claims in the litigation. The settlement did not have a material impact on our financial position, results of operations or cash flows.
On October 30, 2015, Chieftain Sand and Proppant Barron, LLC initiated arbitration against our subsidiary, Baker Hughes Oilfield Operations, Inc., in the American Arbitration Association. The Claimant alleged that the Company failed to purchase the required sand tonnage for the contract year 2014-2015 and further alleged that the Company repudiated its yearly purchase obligations over the remaining contract term. The Claimant alleged damages of approximately $110 million plus interest, attorneys' fees and costs. On June 2, 2016, the parties agreed to a settlement of all claims and counterclaims asserted in the Arbitration. The settlement did not have a material impact on our financial position, results of operations or cash flows.


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On April 30, 2015, a class and collective action lawsuit alleging that we failed to pay a nationwide class of workers overtime in compliance with the Fair Labor Standards Act and North Dakota law was filed titled Williams et al. v. Baker Hughes Oilfield Operations, Inc. in the U.S. District Court for the District of North Dakota.  On February 8, 2016, the Court conditionally certified certain subclasses of employees for collective action treatment. We are evaluating the background facts and at this time cannot predict the outcome of this lawsuit and are not able to reasonably estimate the potential impact, if any, such outcome would have on our financial position, results of operations or cash flows.
On July 31, 2015, Rapid Completions LLC filed a lawsuit in federal court in the Eastern District of Texas against Baker Hughes Incorporated, Baker Hughes Oilfield Operations, Inc., and others claiming infringement of U.S. Patent Nos. 6,907,936; 7,134,505; 7,543,634; 7,861,774; and 8,657,009.  On August 6, 2015, Rapid Completions amended its complaint to allege infringement of U.S. Patent No. 9,074,451.  On September 17, 2015, Rapid Completions and Packers Plus Energy Services Inc., sued Baker Hughes Canada Company in the Canada Federal Court on related Canadian patent 2,412,072. On April 1, 2016, Rapid Completions removed U.S. Patent No. 6,907,936 from its claims in the lawsuit. On April 5, 2016, Rapid Completions filed a second lawsuit in federal court in the Eastern District of Texas against Baker Hughes Incorporated, Baker Hughes Oilfield Operations, Inc. and others claiming infringement of U.S. Patent No. 9,303,501. These patents relate primarily to certain specific downhole completions equipment. The plaintiff has requested a permanent injunction against further alleged infringement, damages in an unspecified amount, supplemental and enhanced damages, and additional relief such as attorney's fees and costs.  During August and September 2016, the United States Patent and Trademark office agreed to institute an inter-partes review of U.S. Patent Nos 7,861,774; 7,134,505; 7,534,634; 6,907,936; 8,657,009; and 9,074,451. At this time, we are not able to predict the outcome of these claims or whether they will have a material impact on our financial position, results of operations or cash flows.
On April 6, 2016, a civil Complaint against Baker Hughes Incorporated and Halliburton Company was filed by the United States of America seeking a permanent injunction restraining Baker Hughes and Halliburton from carrying out the planned acquisition of Baker Hughes by Halliburton or any other transaction that would combine the two companies. The lawsuit is styled United States of America v. Halliburton Co. and Baker Hughes Inc., in the U.S. District Court for the District of Delaware, Case No. 1:16-cv-00233-UNA. The Complaint alleges that the proposed transaction between Halliburton and Baker Hughes would violate Section 7 of the Clayton Act. Subsequent to the filing of the Complaint, on April 30, 2016, the Merger Agreement with Halliburton was terminated as described in Note 2. "Halliburton Terminated Merger Agreement." On May 4, 2016, the United States filed a Notice of Voluntary Dismissal of the Complaint.
On May 30, 2013, we received a Civil Investigative Demand ("CID") from the U.S. Department of Justice ("DOJ") pursuant to the Antitrust Civil Process Act. The CID sought documents and information from us for the period from May 29, 2011 through the date of the CID in connection with a DOJ investigation related to pressure pumping services in the U.S. On May 18, 2016, we received notice from the DOJ that they have closed the investigation with no further action requested of the Company.
ITEM 4. MINE SAFETY DISCLOSURES
Our barite mining operations, in support of our drilling fluids products and services business, are subject to regulation by the federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this annual report.


21


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 SIX Swiss Exchange. As of January 31, 2017, there were approximately 8,847 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, 2016, and information regarding dividends declared on our common stock during the two years ended December 31, 2016, see Note 17. "Quarterly Data (Unaudited)" 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 2016.
Issuer Purchases of Equity Securities

Period
Total Number
of Shares
Purchased
(1)
 
Average
Price Paid
Per Share (1)
 
Total Number of
Shares Purchased as
Part of a Publicly
Announced Program (2)
 
Maximum Dollar Value
of Shares that May Yet Be
Purchased Under the Program (3)
October 1-31, 2016
9,640

 
$
52.35

 
 
$
1,237,161,230

November 1-30, 2016

 

 
 
$
1,237,161,230

December 1-31, 2016
69,214

 
64.71

 
 
$
1,237,161,230

Total
78,854

 
$
63.20

 
 
 
(1) 
Represents shares purchased from employees to satisfy the tax withholding obligations in connection with the vesting of restricted stock awards and restricted stock units.
(2) 
There were no repurchases during the fourth quarter of 2016 under our previously announced purchase program.
(3) 
Under the transaction agreement with General Electric, as described in Note 3. "General Electric Transaction Agreement" of the Notes to Consolidated Financial Statements in Item 8 herein, we have agreed not to repurchase any shares of our common stock other than in connection with shares repurchased from employees to satisfy the tax withholding obligations in connection with the vesting of equity awards.


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Corporate Performance Graph
The following graph compares the yearly change in our cumulative total stockholder return on our common stock (assuming reinvestment of dividends into common stock at the date of payment) with the cumulative total return on the published Standard & Poor's ("S&P") 500 Stock Index and the cumulative total return on the S&P 500 Oil and Gas Equipment and Services Index over the preceding five-year period.
Comparison of Five-Year Cumulative Total Return *
Baker Hughes Incorporated; S&P 500 Index and S&P 500 Oil and Gas Equipment and Services Index

stockperformancegraph2017a02.jpg
 
2011
 
2012
 
2013
 
2014
 
2015
 
2016
Baker Hughes
$
100.00

 
$
85.18

 
$
116.65

 
$
119.55

 
$
99.62

 
$
142.17

S&P 500 Index
100.00

 
115.93

 
153.39

 
174.29

 
176.75

 
197.75

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

 
100.00

 
130.65

 
120.46

 
97.87

 
129.12

* 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, 2011 in Baker Hughes common stock, the S&P 500 Index and the S&P 500 Oil and Gas Equipment and Services Index.
The corporate performance graph and related information shall not be deemed "soliciting material" or to be "filed" with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that Baker Hughes specifically incorporates it by reference into such filing.



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ITEM 6. SELECTED FINANCIAL DATA
The Selected Financial Data should be read in conjunction with Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data, both contained herein.

 
Year Ended December 31,
(In millions, except per share amounts)
2016

 
2015

 
2014

 
2013

 
2012

Revenue
$
9,841

 
$
15,742

 
$
24,551

 
$
22,364

 
$
21,361

Gross Profit
(516
)
 
861

 
4,192

 
3,255

 
3,508

Marketing, general and administrative
815

 
969

 
1,333

 
1,306

 
1,316

Impairment and restructuring charges (1)
1,735

 
1,993

 

 

 

Goodwill impairment (2)
1,858

 

 

 

 

Merger and related costs
199

 
295

 

 

 

Merger termination fee (3)
(3,500
)
 

 

 

 

Operating (loss) income
(1,623
)
 
(2,396
)
 
2,859

 
1,949

 
2,192

Non-operating expense, net
(417
)
 
(217
)
 
(232
)
 
(234
)
 
(210
)
(Loss) income before income taxes
(2,040
)
 
(2,613
)
 
2,627

 
1,715

 
1,982

Income tax (provision) benefit
(696
)
 
639

 
(896
)
 
(612
)
 
(665
)
Net (loss) income
(2,736
)
 
(1,974
)
 
1,731

 
1,103

 
1,317

Net (income) loss attributable to noncontrolling interests
(2
)
 
7

 
(12
)
 
(7
)
 
(6
)
Net (loss) income attributable to Baker Hughes
$
(2,738
)
 
$
(1,967
)
 
$
1,719

 
$
1,096

 
$
1,311

Per share of common stock:
 
 
 
 
 
 
 
 
 
Net (loss) income attributable to Baker Hughes:
 
 
 
 
 
 
 
 
 
Basic
$
(6.31
)
 
$
(4.49
)
 
$
3.93

 
$
2.47

 
$
2.98

Diluted
(6.31
)
 
(4.49
)
 
3.92

 
2.47

 
2.97

Dividends
0.68

 
0.68

 
0.64

 
0.60

 
0.60

Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Cash, cash equivalents and short-term investments
$
4,572

 
$
2,324

 
$
1,740

 
$
1,399

 
$
1,015

Working capital (current assets minus current liabilities)
6,863

 
6,493

 
7,408

 
6,717

 
6,293

Total assets
19,034

 
24,080

 
28,827

 
27,934

 
26,689

Long-term debt
2,886

 
3,890

 
3,913

 
3,882

 
3,837

Total equity
12,737

 
16,382

 
18,730

 
17,912

 
17,268

Notes To Selected Financial Data
(1) 
Impairment and restructuring charges associated with asset impairments, workforce reductions, facility closures and contract terminations recorded during 2015 and 2016. See Note 4. "Impairment and Restructuring Charges" of the Notes to Consolidated Financial Statements in Item 8 herein for further discussion.
(2) 
Goodwill impairment recognized in the second and third quarters of 2016. See Note 12. "Goodwill and Intangible Assets" of the Notes to Consolidated Financial Statements in Item 8 herein for further discussion.
(3) 
Merger termination fee received from Halliburton. See Note 2. "Halliburton Terminated Merger Agreement" of the Notes to Consolidated Financial Statements in Item 8 herein for further discussion.


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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") should be read in conjunction with the consolidated financial statements included in Item 8. Financial Statements and Supplementary Data contained herein.
EXECUTIVE SUMMARY
Baker Hughes is a leading supplier of oilfield services, products, technology and systems used in the worldwide oil and natural gas industry, referred to as our oilfield operations. We manage our oilfield operations through four geographic segments consisting of North America, Latin America, Europe/Africa/Russia Caspian, and Middle East/Asia Pacific. Our Industrial Services businesses are reported in a fifth segment. As of December 31, 2016, Baker Hughes had approximately 33,000 employees compared to approximately 43,000 employees as of December 31, 2015.
Within our oilfield operations, the primary driver of our businesses is our customers' capital and operating expenditures dedicated to oil and natural gas exploration, field development and production. The main products and services provided by oilfield operations fall into one of two categories, Drilling and Evaluation or Completion and Production. This classification is based on the two major phases of constructing an oil and/or natural gas well, the drilling phase and the completion phase, and how our products and services are utilized in each phase. We also provide products and services to the downstream chemicals, and process and pipeline services, referred to as Industrial Services.
During 2016, we continued to face difficult industry conditions as commodity prices deteriorated to levels not seen in more than a decade. Activity declined across the globe as reflected by the worldwide rig count, which decreased 32% as compared to the 2015 average. Customers continued to reduce spending to cope with this challenging low-commodity price environment, resulting in further price deterioration for our products and services. The steady decline in U.S. oil production along with the production cuts announced during the fourth quarter of 2016 by OPEC and certain non-OPEC countries drove oil prices higher resulting in an 11% increase when comparing the fourth quarter closing price for West Texas Intermediate Cushing Crude of $53.72/Bbl to the third quarter closing price of $48.24/Bbl. This increase stimulated improvement in activity in the North America market as evidenced by the 29% growth in the rig count in the fourth quarter of 2016 as compared to the third quarter of 2016. Despite this improvement, there has yet to be any meaningful increase in the prices we are able to charge for our products and services, and thus the impact on our profitability has been minimal. International and deep water activity continued to decline in the fourth quarter, as most operators are awaiting for a sustainable rebalancing of the oil market before increasing activity.
Against the back-drop of another difficult year for the industry, we achieved significant progress on our commitment to improve financial performance by reducing costs and simplifying our operational structure, optimizing our capital structure, and strengthening our commercial strategy. More specifically, we generated $4.23 billion of cash flows from operations, which includes the $3.5 billion Halliburton merger termination fee, paid down $1.0 billion in debt, repurchased $763 million in shares, accelerated innovation with over 100 new product introductions, and built new sales channels to take our products and technology to market faster and more efficiently. As we executed on our strategy to strengthen profitability and return on invested capital, we rationalized under-performing product lines in select markets based on our objectives of profitable growth. While these reductions have had minimal impact on our revenue they have had a positive impact on operating profitability. In addition, we contributed our North American onshore pressure pumping business into a new venture that is better positioned to participate efficiently and cost-effectively in the anticipated growth of this market segment.
For 2016, we generated revenue of $9.84 billion, a decrease of $5.90 billion, or 37%, compared to 2015. Net loss attributable to Baker Hughes was $2.74 billion for 2016 compared to $1.97 billion for 2015. The steep decline in activity, as evidenced by the 32% decline in the average global rig count year-over-year, and price deterioration experienced across all our segments are the main drivers for the decline in revenue and profitability. We have continued to restructure and adjust our operations and cost structure to reflect reduced activity levels. As a result of these restructuring activities, we recorded charges totaling $1.17 billion in 2016, which included workforce reductions, contract terminations, facility closures and the write-down of excess machinery and equipment. In


25


addition to our restructuring activities, as a result of the downturn in the energy market and its impact on our business outlook, we determined that the carrying amount of certain assets exceeded their respective fair values; therefore, we recorded an impairment charge of $567 million. Further, we recorded goodwill impairment charges primarily related to our North America reporting unit totaling $1.86 billion. These charges have been excluded from the results of our operating segments.
OUTLOOK
Oil prices started to rebound in the fourth quarter of 2016 as a result of the announced supply cut agreements by OPEC and 11 non-OPEC producers, and a modest increase in the forecasted demand for oil. However, North American production remains uncertain due to the unpredictable actions of North American shale operators who can bring on production and impact commodity prices much more quickly than their peers in other operating environments. Since details of OPEC’s plans surfaced in October, rig counts for the fourth quarter of 2016 increased by 23% in the U.S. compared to the third quarter of 2016, with a corresponding increase in U.S. shale production already materializing. Therefore, the operators' ability to quickly get resources from the ground into production could limit near-term commodity price gains. This North America dynamic, combined with questions about OPEC's ability to implement and sustain these cuts, leave room for skepticism that these agreed-upon production cuts could lead to a more sustainable improvement in oil prices, and in turn, to a more material increase in spending by exploration and production companies.
While some are more optimistic about the prospects for the near-term recovery, we continue to believe that oil prices sustained in the mid-to-high $50s are required for confidence in the customer community to improve and investment to accelerate. Also, activity needs to increase meaningfully before excess service capacity can be substantially absorbed and meaningful pricing recovery takes place. We are seeing the first signs of this in select product lines in a few of the North American basins, but we still believe there remains a fair amount of capacity that must be absorbed before service pricing will become more tightly correlated with higher commodity prices and increased activity.
Further, we believe recovery paths will vary depending on the location and operating environment. In the North American market, onshore activity continues to climb upward, and we expect that trend to continue through 2017. Conversely, in offshore markets around the world, where full cycle lifting costs are higher, particularly deepwater, we expect activity to remain challenging with more declines expected in 2017. Overall, internationally we expect the market to be flat to down slightly in the first half of 2017, with continued activity declines and pricing pressure near-term, partially offset by pockets of moderate growth onshore. As a result of the expected continued market variability, we believe our tax rate will continue to be volatile.
Despite the near-term volatility, the long-term outlook for our industry remains strong. We believe the world’s demand for energy will continue to rise, and the supply of energy will continue to increase in complexity, requiring greater service intensity and more advanced technology from oilfield service companies. As such, we remain focused on delivering innovative cost-efficient solutions that deliver step changes in operating and economic performance for our customers.
HALLIBURTON TERMINATED MERGER AGREEMENT
On November 16, 2014, Baker Hughes and Halliburton Company ("Halliburton") entered into a definitive agreement and plan of merger (the "Merger Agreement") under which Halliburton would acquire all outstanding shares of Baker Hughes in a stock and cash transaction (the "Merger"). In accordance with the provisions of Section 9.1 of the Merger Agreement, Baker Hughes and Halliburton agreed to terminate the Merger Agreement on April 30, 2016, as a result of the failure of the Merger to occur on or before April 30, 2016, due to the inability to obtain certain specified antitrust related approvals. Halliburton paid $3.5 billion to Baker Hughes on May 4, 2016, representing the antitrust termination fee required to be paid pursuant to the Merger Agreement. For further information about the Merger, see Note 2. "Halliburton Terminated Merger Agreement" of the Notes to Consolidated Financial Statements in Item 8 herein.


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GENERAL ELECTRIC TRANSACTION AGREEMENT
On October 30, 2016, Baker Hughes, GE, Newco and Merger Sub entered into a Transaction Agreement and Plan of Merger, pursuant to which, among other things, GE’s oil and gas business and Baker Hughes will be combined and operate under the name "Baker Hughes, a GE Company". The GE Transaction is subject to the approval of Baker Hughes’ stockholders, regulatory approvals and customary closing conditions. Baker Hughes and GE expect the GE Transaction to close in mid-2017. However, Baker Hughes cannot predict with certainty when, or if, the GE Transaction will be completed because completion of the GE Transaction is subject to conditions beyond the control of Baker Hughes. For further information about the transaction, see Note 3. "General Electric Transaction Agreement" of the Notes to Consolidated Financial Statements in Item 8 herein. Newco will operate as a public company.
BUSINESS ENVIRONMENT
We conduct business in more than 80 countries helping customers find, evaluate, drill, produce, transport and process hydrocarbon resources. Our revenue is predominately generated from the sale of products and services to major, national, and independent oil and natural gas companies worldwide, and 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 and supply, their access to resources to develop and produce oil and natural gas, their ability to fund their capital programs, the impact of new government regulations and most importantly, their expectations for oil and natural gas prices as a key driver of their cash flows.
Oil and Natural Gas Prices
Oil and natural gas prices are summarized in the table below as averages of the daily closing prices during each of the periods indicated.

 
2016
 
2015
 
2014
Brent oil prices ($/Bbl) (1)
$
44.11

 
$
52.31

 
$
98.88

WTI oil prices ($/Bbl) (2)
43.34

 
48.68

 
93.03

Natural gas prices ($/mmBtu) (3)
2.49

 
2.61

 
4.35

(1) 
Bloomberg Dated Brent ("Brent") Oil Spot Price per Barrel
(2) 
Bloomberg West Texas Intermediate ("WTI") Cushing Crude Oil Spot Price per Barrel
(3) 
Bloomberg Henry Hub Natural Gas Spot Price per million British Thermal Unit
Outside North America, customer spending is most heavily influenced by Brent oil prices, which fluctuated significantly throughout the year, ranging from a low of $26.39/Bbl in January 2016 to a high of $55.57/Bbl in December 2016. Oil prices bottomed early in 2016 due to the impending production increases in Iran after economic sanctions were lifted. During 2016, OPEC considered production cuts, and in the fourth quarter they announced their first agreement since 2008 to cut production. Along with OPEC's agreed-upon production cuts, other non-OPEC countries similarly agreed to reduce production. As a result, in the fourth quarter, Brent oil prices shifted meaningfully higher. In addition, demand for oil was higher than expected due to robust consumption in North America and revisions to Chinese, Russian, and European demand growth expectations.
In North America, customer spending is highly driven by WTI oil prices, which, similar to Brent oil prices, fluctuated significantly throughout the year, with the highest prices being recorded towards the end of the year. Overall, WTI oil prices ranged from a low of $26.21/Bbl in February 2016 to a high of $54.06/Bbl in December 2016.
Although oil prices have rebounded more than 100% from the previous twelve-year low of $26/Bbl reached earlier this year to near $55/Bbl at the end of the year, there has yet to be any material change in customer behavior, other than in certain U.S. basins, to suggest a near-term broader recovery in activity levels.
In North America, natural gas prices, as measured by the Henry Hub Natural Gas Spot Price, averaged $2.49/mmBtu in 2016, representing a 5% decrease over the prior year. The warmer-than-average winter at the start of


27


2016 significantly reduced demand and storage inventories hit record highs. In late 2016, once production and drilling activity tapered off and the seasonal demand picked up, the spot prices improved. According to the U.S. Department of Energy ("DOE"), working natural gas in storage at the end of 2016 was 3,311 billion cubic feet ("Bcf"), which was 9.9%, or 364 Bcf, below the corresponding week in 2015.
Baker Hughes Rig Count
The Baker Hughes rig counts are an important business barometer for the drilling industry and its suppliers. When drilling rigs are active they consume products and services produced by the oil service industry. Rig count trends are driven by the exploration and development spending by oil and natural gas companies, which in turn is influenced by current and future price expectations for oil and natural gas. Therefore, the counts may reflect the relative strength and stability of energy prices and overall market activity. However, these counts should not be solely relied on as other specific and pervasive conditions may exist that affect overall energy prices and market activity.
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 other outside sources, as necessary. We base the classification of a well as either oil or natural gas primarily upon filings made by operators in the relevant jurisdiction. This data is then compiled and distributed to various wire services and trade associations and is published on our website. We believe the counting process and resulting data is reliable; however, it is subject to our ability to obtain accurate and timely information. Rig counts are compiled weekly for the U.S. and Canada and monthly for all international rigs. Published international rig counts do not include rigs drilling in certain locations, such as Russia, the Caspian region, Iran and onshore China because this information is not readily available.
Rigs in the U.S. and Canada are counted as active if, on the day the count is taken, the well being drilled has been started but drilling has not been completed and the well is anticipated to be of sufficient depth to be a potential consumer of our drill bits. In international areas, rigs are counted on a weekly basis and deemed active if drilling activities occurred during the majority of the week. The weekly results are then averaged for the month and published accordingly. The rig count does not include rigs that are in transit from one location to another, rigging up, being used in non-drilling activities including production testing, completion and workover, and are not expected to be significant consumers of drill bits.
The rig counts are summarized in the table below as averages for each of the periods indicated.

 
2016
 
2015
 
2014
U.S. - onshore
490

 
948

 
1,804

U.S. - offshore
23

 
36

 
57

Canada
129

 
194

 
379

North America
642

 
1,178

 
2,240

Latin America
198

 
319

 
397

North Sea
28

 
37

 
40

Continental Europe
68

 
80

 
105

Africa
85

 
106

 
134

Middle East
390

 
406

 
406

Asia Pacific
187

 
220

 
254

Outside North America
956

 
1,168

 
1,336

Worldwide
1,598

 
2,346

 
3,576



28


2016 Compared to 2015
The rig count in North America decreased 46% in 2016 compared to 2015 primarily driven by a 44% decline in oil-directed rigs, as a result of reduced spending from our customers as they adapt to a lower oil price environment. The oil-directed rig count decreased 45% in the U.S. as lower WTI prices have forced operators to reduce their exploration and development spending in order to protect their cash flows, as they focus more on production optimization opportunities. In Canada, the oil-directed rig count has decreased by 28% as many operators curtailed their drilling plans as most heavy oil sands projects are not economical at current oil prices. The natural gas-directed rig count in North America declined 50% in 2016 as natural gas well productivity improved, with natural gas-directed drilling declining 56% in the U.S. and 38% in Canada.
Outside North America, the rig count decreased 18% in 2016 compared to 2015, also driven by reduced customer spending and a lower oil price environment. The rig count in Latin America decreased 38% as a result of customer budgetary constraints across most of the region, primarily in Argentina, Mexico, Brazil, and Colombia. The North Sea rig count decreased by 24%, largely due to a decline in the drilling activity in the United Kingdom. The rig count in Continental Europe decreased by 15% as a result of reduced drilling across the area with the largest decline seen in Romania. In Africa, the rig count decreased 20%, predominantly due to reduced customer spending across the majority of the region, particularly in Nigeria, Angola, Chad, and Gabon. The rig count in the Middle East decreased 4% in 2016 due to reduced activity in Egypt and Iraq, partially offset by increased activity in Abu Dhabi. The rig count in Asia Pacific decreased 15% as a consequence of reduced drilling activity primarily in Indonesia and Australia.
2015 Compared to 2014
The rig count in North America decreased 47% in 2015 compared to 2014 primarily driven by a 52% decline in oil-directed rigs, as a result of reduced spending from our customers as they adapt to a lower oil price environment. The oil-directed rig count decreased 51% in the U.S. as lower WTI prices have forced operators to reduce their exploration and development spending in order to protect their cash flows, as they focus more on production optimization opportunities. In Canada, the oil-directed rig count has decreased by 61% as many operators curtailed their drilling plans as most heavy oil sands projects are not economical at current oil prices. The natural gas-directed rig count in North America declined 32% in 2015 as natural gas prices deteriorated 40% compared to the 2014 average, with natural gas-directed drilling declining 32% in the U.S. and 33% in Canada.
Outside North America, the rig count decreased 13% in 2015 compared to 2014, also driven by reduced customer spending and a lower oil price environment. The rig count in Latin America decreased 20% as a result of customer budgetary constraints across most of the region, primarily in Mexico, Colombia, and Ecuador. The one exception was in the emerging unconventional plays in Argentina where activity remained relatively stable in 2015. The North Sea rig count decreased by 7%, largely due to a decline in the drilling activity in the Netherlands. The rig count in Continental Europe decreased by 24%, mainly as a result of reduced drilling in Turkey and Romania. In Africa, the rig count decreased 21%, predominantly due to reduced customer spending across the majority of the region, particularly in Libya, Chad, Angola, and Nigeria. The 2015 rig count in the Middle East remained unchanged from 2014 as activity declines in Iraq and Egypt were offset by increased activity in Saudi Arabia, Oman, Abu Dhabi and Kuwait. The rig count in Asia Pacific decreased 13% as a consequence of reduced drilling activity primarily in India, Indonesia, Australia and New Zealand.
RESULTS OF OPERATIONS
The discussions below relating to significant line items from our consolidated statements of income (loss) 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 reasonably practicable, have quantified the impact of such items. In addition, the discussions below for revenue and cost of revenue are on a total basis as the business drivers for product sales and services are similar. All dollar amounts in tabulations in this section are in millions of dollars, unless otherwise stated.


29


Revenue and Profit Before Tax
Revenue and operating profit (loss) before tax for each of our five operating segments is provided below. The performance of our operating segments is evaluated based on operating profit (loss) before tax, which is defined as income (loss) before income taxes and before the following: net interest expense, corporate expenses, impairment and restructuring charges, goodwill impairment charges, the merger termination fee, loss on sale of business interest, loss on early extinguishment of debt, and certain gains and losses not allocated to the operating segments.
Beginning in 2016, we excluded merger and related costs, from both the terminated Halliburton and the proposed GE transactions, from our operating segments. These costs are now presented as a separate line item in the consolidated statement of income (loss). Prior year merger and related costs have been reclassified to conform to the current year presentation.
2016 Compared to 2015

 
Year Ended December 31,
 
 
  
2016
 
2015
 
$ Change
 
% Change
Revenue:
 
 
 
 
 
 
 
North America
$
2,936

 
$
6,009

 
$
(3,073
)
 
(51
)%
Latin America
980

 
1,799

 
(819
)
 
(46
)%
Europe/Africa/Russia Caspian
2,201

 
3,278

 
(1,077
)
 
(33
)%
Middle East/Asia Pacific
2,705

 
3,441

 
(736
)
 
(21
)%
Industrial Services
1,019

 
1,215

 
(196
)
 
(16
)%
Total
$
9,841

 
$
15,742

 
$
(5,901
)
 
(37
)%
 
Year Ended December 31,
 
 
 
 
 
2016
 
2015
 
$ Change
 
% Change
Operating Profit (Loss) Before Tax:
 
 
 
 
 
 
 
North America
$
(687
)
 
$
(639
)
 
$
(48
)
 
(8
)%
Latin America
(276
)
 
144

 
(420
)
 
(292
)%
Europe/Africa/Russia Caspian
(273
)
 
183

 
(456
)
 
(249
)%
Middle East/Asia Pacific
69

 
229

 
(160
)
 
(70
)%
Industrial Services
(6
)
 
108

 
(114
)
 
(106
)%
Total Operations
(1,173
)
 
25

 
(1,198
)
 
N/M

Corporate
(158
)
 
(133
)
 
(25
)
 
19
 %
Loss on sale of business interest
(97
)
 

 
(97
)
 
N/M

Loss on early extinguishment of debt
(142
)
 

 
(142
)
 
N/M

Interest expense, net
(178
)
 
(217
)
 
39

 
(18
)%
Impairment and restructuring charges
(1,735
)
 
(1,993
)
 
258

 
(13
)%
Goodwill impairment
(1,858
)
 

 
(1,858
)
 
N/M

Merger and related costs
(199
)
 
(295
)
 
96

 
(33
)%
Merger termination fee
3,500

 

 
3,500

 
N/M

Total
$
(2,040
)
 
$
(2,613
)
 
$
573

 
(22
)%
"N/M" represents not meaningful.
North America
North America revenue for 2016 was $2.94 billion, a decrease of $3.07 billion, or 51%, compared to 2015, primarily as a result of the steep drop in activity as reflected in the 46% year-over-year average rig count decline,


30


and to a lesser extent, deteriorating pricing conditions as operators further reduced their spending levels in 2016. All product lines have been unfavorably impacted by the drop in activity. In addition, our onshore pressure pumping business incurred share reductions, driven by efforts to reduce losses and improve cash flow in a market where pricing was unsustainable. Conversely, production chemicals reflected the smallest decrease in activity as revenue in this product line is more highly correlated to production than rig count. In addition, deepwater operations and artificial lift also showed signs of resilience.
North America operating loss before tax was $687 million in 2016, a decrease of $48 million, or 8%, compared to the $639 million operating loss in 2015. Although operating results were negatively impacted by the sharp reduction in activity and an increasingly unfavorable pricing environment, actions taken in the past year to reduce our workforce, close and consolidate facilities and improve commercial terms with vendors resulted in significantly lower operating costs. These actions to restructure our North America operations to operate in a lower activity and pricing environment, combined with the reduction of depreciation and amortization expense from asset impairments, helped mitigate the impact of the ongoing decline in revenue experienced since early 2015. Our operating results for 2016 include $230 million of costs related to writing off certain excess inventory, compared to costs of $181 million during 2015 due to lower of cost or market adjustments.
On December 30, 2016, we contributed our North American onshore pressure pumping business to a newly formed venture, of which we retained a 46.7% interest and accounted for as an equity method investment. This investment, and the related earnings, will be excluded from our operating segments. For further information, see Note 5. "Acquisitions and Dispositions" of the Notes to Consolidated Financial Statements in Item 8 herein.
Latin America
Latin America revenue for 2016 was $980 million, a decrease of $819 million, or 46%, compared to 2015. The reduction in this segment is attributed to activity declines across the region as evident in the 38% drop in the rig count. Activity has declined across the entire segment and across all product lines. The largest year-over-year declines were pressure pumping in Argentina, artificial lift in the Andean Area, and drilling services in Brazil and Mexico.
Latin America operating loss before tax was $276 million in 2016, a decrease of $420 million, or 292%, compared to operating profit before tax of $144 million in 2015. The reduction in profitability is mainly attributed to the decline in activity, and to a lesser extent price, which was exacerbated by an increase of $96 million for provisions for doubtful accounts year-over-year, almost entirely in Ecuador. Additionally, we incurred costs of $84 million in 2016 to write off the carrying value of certain excess inventory compared to $13 million in 2015. The reduction in profitability was partially mitigated by lower operating costs and depreciation and amortization expense resulting from our efforts to structurally align the segment to reflect current and expected near-term activity levels. We also benefited from reduced foreign exchanges losses.
Europe/Africa/Russia Caspian ("EARC")
EARC revenue for 2016 was $2.20 billion, a decrease of $1.08 billion, or 33%, compared to 2015. The decrease can be attributed primarily to activity reductions across all markets and product lines, with the largest decline experienced in the North Sea and West Africa, most notably in the drilling services and completion systems product lines. In addition to reduced activity in the North Sea, the region was also negatively impacted by labor union strikes in the fourth quarter of 2016. To a lesser extent, unfavorable pricing also impacted revenue. In addition, in 2016 unfavorable exchange rates, mainly for the British Pound, Nigerian Naira, Russian Ruble, Angolan Kwanza and the Norwegian Krone accounted for more than 10% of the decline in revenue. Despite the activity reductions, we did see resiliency in our production chemicals product line as a result of increased share in Africa.
EARC operating loss before tax was $273 million in 2016, a decrease of $456 million, or 249%, compared to operating profit before tax of $183 million in 2015. The decline in operating profit from lower activity levels and unfavorable pricing was compounded by valuation allowances on indirect taxes in Africa. In addition, we incurred costs of $143 million to write off certain excess inventory during 2016. These reductions in profitability were partially offset by the benefit of implemented cost reduction measures, lower depreciation and amortization expense, and reduced foreign exchange losses.


31


Middle East/Asia Pacific ("MEAP")
MEAP revenue for 2016 was $2.71 billion, a decrease of $736 million, or 21%, compared to 2015. The revenue decline in this segment was driven by lower activity across most of the region, and to a lesser extent region-wide pricing pressure. The most noticeable reductions occurred in completion systems, pressure pumping and drilling services across Asia Pacific, particularly in Australia, Malaysia and Vietnam, across all product lines in Iraq, and in deepwater operations in India. These reductions were partially offset by activity growth in Kuwait, mainly in artificial lift, drilling services and pressure pumping.
MEAP operating profit before tax decreased $160 million, or 70%, in 2016 compared to 2015. The reduction in profitability was driven largely by lower activity levels and unfavorable pricing, partially offset by operating cost reductions and lower depreciation and amortization expense from asset impairments. During 2016, we incurred costs of $117 million to write off certain excess inventory. During 2015, we incurred charges in Iraq related to our integrated operations.
Industrial Services
Industrial Services revenue was $1.02 billion, a decrease of $196 million, or 16%, compared to 2015. The decline in revenue in this segment was driven by activity reductions as customers reduced spending and delayed projects including several major pipeline construction and maintenance projects. Revenue was further negatively impacted by pricing deterioration.
Industrial Services operating loss before tax in 2016 was $6 million, a decrease 106% compared to operating profit before tax of $108 million in 2015. The reduction in profitability resulting from lower activity levels and pricing deterioration was partially offset by operating cost reductions and lower depreciation and amortization expense from asset impairments. During 2016, we incurred costs of $43 million to write off certain excess inventory.
2015 Compared to 2014

 
Year Ended December 31,
 
 
  
2015
 
2014
 
$ Change
 
% Change
Revenue:
 
 
 
 
 
 
 
North America
$
6,009

 
$
12,078

 
$
(6,069
)
 
(50
)%
Latin America
1,799

 
2,236

 
(437
)
 
(20
)%
Europe/Africa/Russia Caspian
3,278

 
4,417

 
(1,139
)
 
(26
)%
Middle East/Asia Pacific
3,441

 
4,456

 
(1,015
)
 
(23
)%
Industrial Services
1,215

 
1,364

 
(149
)
 
(11
)%
Total
$
15,742

 
$
24,551

 
$
(8,809
)
 
(36
)%


32


 
Year Ended December 31,
 
 
 
 
  
2015
 
2014
 
$ Change
 
% Change
Operating Profit (Loss) Before Tax:
 
 
 
 
 
 
 
North America
$
(639
)
 
$
1,466

 
$
(2,105
)
 
(144
)%
Latin America
144

 
290

 
(146
)
 
(50
)%
Europe/Africa/Russia Caspian
183

 
621

 
(438
)
 
(71
)%
Middle East/Asia Pacific
229

 
675

 
(446
)
 
(66
)%
Industrial Services
108

 
119

 
(11
)
 
(9
)%
Total Operations
25

 
3,171

 
(3,146
)
 
(99
)%
Corporate
(133
)
 
(312
)
 
179

 
(57
)%
Interest expense, net
(217
)
 
(232
)
 
15

 
(6
)%
Impairment and restructuring charges
(1,993
)
 

 
(1,993
)
 
N/M

Merger and related costs
(295
)
 

 
(295
)
 
N/M

Total
$
(2,613
)
 
$
2,627

 
$
(5,240
)
 
(199
)%
North America
North America revenue for 2015 was $6.01 billion, a decrease of $6.07 billion, or 50%, compared to 2014. The steep reduction in commodity prices experienced by the industry in 2015 severely impacted onshore North America exploration and production companies as a result of the higher lifting cost per barrel of many of these producers. These operators have addressed these cash constraints by reducing drilling activity in less economical unconventional plays, delaying well completion activities, and driving price discounts from their service providers as they await higher commodity prices. These lower activity levels, as evident in the 47% rig count drop, and deteriorating pricing conditions were the main drivers for the revenue decline in this segment. All product lines have been unfavorably impacted by the drop in activity, with production chemicals, deepwater operations and artificial lift showing the most resilience. Additionally, the reduced activity and well completion delays created an oversupply of hydraulic fracturing equipment, which caused the price deterioration in the onshore pressure pumping product line to be more severe. As such, we lost market share in this product line in 2015 as we worked to maintain cash flow positive operations despite an oversupplied market.
North America operating loss before tax was $639 million in 2015, a decrease of $2.11 billion, or 144%, compared to operating profit before tax of $1.47 billion in 2014. The reduction in profitability was primarily due to the sharp decline in activity and an increasingly unfavorable pricing environment. Additionally, as a result of the industry downturn and its impact on our business, we incurred costs of $181 million in 2015 to write down the carrying value of certain inventory. The impact from these unfavorable market conditions was partially mitigated by actions taken in the year to reduce our workforce, close and consolidate facilities and improve commercial terms with vendors, which ultimately resulted in lower operating costs.
Latin America
Latin America revenue for 2015 was $1.80 billion, a decrease of $437 million, or 20%, compared to 2014. The reduction in this segment is attributed to activity declines across the region as a result of customer budgetary constraints, predominately in the Andean area where the rig count has declined 46%, and in Venezuela where we restructured our operational footprint in late 2014. This reduction was partially offset by revenue growth in Brazil from share gains in our drilling services product line.
Latin America operating profit before tax decreased $146 million, or 50%, in 2015 compared to 2014. The reduction in profitability is mainly attributed to the decline in activity, foreign exchange losses, primarily in Argentina, and an increase in expense related to reserves for doubtful accounts. Additionally, we incurred costs of $13 million in 2015 to write down the carrying value of certain inventory. This was partially offset by improvements made to our operational cost structure.


33


Europe/Africa/Russia Caspian
EARC revenue for 2015 was $3.28 billion, a decrease of $1.14 billion, or 26%, compared to 2014. The decrease was driven mainly by activity declines and unfavorable pricing across the region. Revenue was also negatively impacted by the unfavorable change in foreign exchange rates, which accounted for approximately one third of the revenue reduction in 2015. The deconsolidation of a joint venture in North Africa late last year also contributed to the decline in revenue. All product lines have been unfavorably impacted by the drop in activity and price, with production chemicals and drilling services showing the most resilience.
EARC operating profit before tax decreased $438 million, or 71%, in 2015 compared to 2014. The unfavorable impact to profitability from pricing deterioration, lower activity levels, the change in foreign exchange rates, and increased costs related to reserves for doubtful accounts was partially offset by the savings from recent cost reduction measures. In addition, in 2015 unfavorable exchange rates, mainly for the Russian Ruble, Euro and the British Pound, accounted for approximately 40% of the decline in profitability. Also, 2014 included a $58 million charge associated with the restructuring of our operations in North Africa, and impairment of certain assets, that did not repeat in 2015.
Middle East/Asia Pacific
MEAP revenue for 2015 was $3.44 billion, a decrease of $1.02 billion, or 23%, compared to 2014. The revenue decline in this segment was driven primarily by lower activity across most of Asia, in particular China, Australia and Vietnam, and reduced revenue in Iraq. The revenue drop in Iraq is attributed to reduced activity, as evident by the 34% decline in rig count, and the rationalization of our operational footprint in the country, including completing our integrated operations activities. Revenue was also impacted by unfavorable pricing across the region.
MEAP operating profit before tax decreased $446 million, or 66%, in 2015 compared to 2014. The reduction in profitability was driven largely by lower activity levels and unfavorable pricing. The current year also includes charges related to reducing our operations in Iraq. These reductions were partially offset by the benefit of the recent cost-saving actions.
Industrial Services
Industrial Services revenue was $1.22 billion, a decrease of $149 million, or 11%, compared to 2014. The decline in revenue in this segment was driven primarily by reduced activity and the unfavorable change in foreign exchange rates.
Industrial Services operating profit before tax decreased 9% in 2015 compared to 2014. The reduction in profitability resulting from lower activity levels was partially offset by cost-saving efforts. However, Industrial Services profit before tax for the prior year included integration costs related to the pipeline services business acquired in 2014, which we did not incur in 2015.


34


Costs and Expenses
The table below details certain data from our consolidated statements of income (loss) and as a percentage of revenue.

 
2016
 
2015
 
2014
  
$
 
%
 
$
 
%
 
$
 
%
Revenue
$
9,841

 
100
 %
 
$
15,742

 
100
%
 
$
24,551

 
100
%
Cost of revenue
9,973

 
101
 %
 
14,415

 
92
%
 
19,746

 
80
%
Research and engineering
384

 
4
 %
 
466

 
3
%
 
613

 
2
%
Marketing, general and administrative
815

 
8
 %
 
969

 
6
%
 
1,333

 
5
%
Impairment and restructuring charges
1,735

 
18
 %
 
1,993

 
13
%
 

 
%
Goodwill impairment
1,858

 
19
 %
 

 
%
 

 
%
Merger and related costs
199

 
2
 %
 
295

 
2
%
 

 
%
Merger termination fee
(3,500
)
 
(36
)%
 

 
%
 

 
%
Loss on sale of business interest
97

 
1
 %
 

 
%
 

 
%
Loss on early extinguishment of debt
142

 
1
 %
 

 
%
 

 
%
Interest expense, net
178

 
2
 %
 
217

 
1
%
 
232

 
1
%
Cost of Revenue
Cost of revenue as a percentage of revenue was 101% and 92% for 2016 and 2015, respectively. The increase in cost of revenue as a percentage of revenue is due mainly to deteriorating pricing conditions as operators reduced their spending, partially offset by the benefit of implemented cost reduction measures and lower depreciation and amortization expense from asset impairments. Despite actions to restructure our global operations to operate in a lower price and activity environment, the decline in revenue has outpaced the benefit of our cost saving measures. Additionally, the product lines most significantly impacted by the downturn in rig activity are also the most capital-intensive. Accordingly, the fixed costs associated with those product lines lessened the positive impact of our cost reduction efforts in 2016 and 2015. Cost of revenue for 2016 was also negatively impacted by a charge of $617 million to write off and dispose of certain excess inventory compared to a write-down of $194 million in the prior year due to lower of cost or market adjustments.
Cost of revenue as a percentage of revenue was 92% and 80% for 2015 and 2014, respectively. As a result of the steep decline in activity and customer spending, we experienced significant pricing pressure and a decline in the demand for our products and services. Cost of revenue for 2015 was also negatively impacted by a charge of $194 million to adjust the carrying value of certain inventory due to the industry-wide market decline.
Research and Engineering
Research and engineering expenses decreased 18% in 2016 compared to 2015 and decreased 24% in 2015 compared to 2014. These declines were driven by cost reduction measures in light of the severe decline in activity resulting in lower revenues and profitability.
Marketing, General and Administrative
Marketing, general and administrative ("MG&A") expenses decreased by $154 million, or 16%, in 2016 compared to 2015. The reduction in MG&A costs is mainly a result of workforce reductions, lower discretionary spending, reduced foreign exchange losses and a $23 million investment gain, partially offset by legal settlement costs of $44 million.
MG&A expenses decreased by $364 million, or 27%, in 2015 compared to 2014. The reduction in MG&A costs is mainly a result of workforce reductions and lower discretionary spending.


35


Impairment and Restructuring Charges
During 2016, we recorded impairment and restructuring charges of $1.74 billion consisting of $272 million for workforce reduction costs, $192 million for contract termination costs and $1.27 billion for asset impairments related to excess machinery and equipment, facilities and intangible assets. Total cash paid during 2016 related to workforce reductions and contract terminations was $419 million.
During 2015, we recorded impairment and restructuring charges of $830 million consisting of $436 million for workforce reduction costs, $121 million for contract termination costs and $273 million for asset impairments related to excess machinery and equipment and facilities. Total cash paid during 2015 related to these charges was $446 million. In addition to our restructuring activities, in response to the downturn in the energy market and its impact on our business outlook, we determined that the carrying amount of a number of our assets exceeded their respective fair values; therefore, we recorded an impairment charge of $1.16 billion. These charges have been excluded from the results of our operating segments. For further discussion of these impairment and restructuring charges, see Note 4. "Impairment and Restructuring Charges" of the Notes to Consolidated Financial Statements in Item 8 herein.
The reduction in costs from eliminated depreciation, reduced employee expenses, and reduced interest expense on long-term debt in 2016 is approximately $550 million, and is expected to be approximately $900 million on an annualized basis, $700 million of which is related to actions taken post Halliburton merger.
Goodwill Impairment
In the second quarter of 2016, we determined the fair value of our reporting units using a combination of techniques including discounted cash flows derived from our long-term plans and a market approach that provides value indications through a comparison with guideline public companies. Based on the results of our impairment test, we determined that goodwill of two of our reporting units was impaired, and performed the second step of the goodwill impairment test. We substantially completed all actions necessary in the determination of the implied fair value of goodwill in the second quarter of 2016; however, some of the estimated fair values and allocations were subject to adjustment once the valuations and other computations were completed. Accordingly, in the second quarter of 2016, we recorded an estimate of the goodwill impairment loss of $1.84 billion, which consisted of $1.53 billion for the North America segment and $311 million for the Industrial Services segment. During the third quarter of 2016, we finalized all valuations and computations, and adjusted our final goodwill impairment loss for the first nine months of 2016 to $1.86 billion, consisting of $1.55 billion for the North America segment and $309 million for the Industrial Services segment. There were no goodwill-related impairments recorded in the fourth quarter of 2016.
Merger and Related Costs and Merger Termination Fee
We incurred costs related to the terminated merger with Halliburton of $180 million and $295 million in 2016 and 2015, respectively. These costs included certain expenses under our retention programs and obligations for minimum incentive compensation costs which, based on meeting eligibility criteria, have been treated as merger and related costs. On April 30, 2016, the Merger Agreement with Halliburton was terminated and as a result, Halliburton paid us $3.5 billion on May 4, 2016, which represents the termination fee required to be paid pursuant to the Merger Agreement. In 2016, we also incurred costs related to the pending transaction with GE of $19 million.
Interest Expense, Net
Interest expense, net of interest income of $33 million, was $178 million in 2016, a decrease of $39 million compared to $217 million, net of interest income of $20 million, in 2015. The decrease is due primarily to the bond buy back that occurred in June of 2016, and to a lesser extent, the growth in interest income earned on higher cash balances and short-term investments. Interest expense, net of interest income, of $217 million in 2015 decreased by $15 million compared to $232 million, net of interest income of $13 million, in 2014. The reduction is due primarily to lower short-term borrowings in Latin America and an increase in interest income.


36


Income Taxes
Total income tax expense was $696 million in 2016 compared to income tax benefit of $639 million for 2015 and income tax expense of $896 million for 2014. Our effective tax rate on operating profits or losses in 2016, 2015 and 2014 was (34.1)%, 24.5% and 34.1%, respectively. The 2016 negative effective tax rate is due primarily to the geographical mix of earnings and losses such that taxes in certain jurisdictions, including withholding and deemed profit taxes, exceed the tax benefit from the losses in other jurisdictions due to valuation allowances provided in most jurisdictions and goodwill impairments with no tax benefit. The 2015 effective tax rate is lower than the U.S. statutory income tax rate of 35% due to losses in foreign jurisdictions with no tax benefit and adjustments to prior years' tax positions, partially offset by favorable amended returns and other return to accrual adjustments. The 2014 effective tax rate is lower than the U.S. statutory income tax rate of 35% due to lower rates on certain international operations, partially offset by state income taxes and adjustments to prior years' tax positions.
As a result of the geographic mix of earnings and losses, including the goodwill impairment, asset impairment, restructuring charges, and other discrete tax items, our rate has been, and will continue to be volatile until the market stabilizes.
COMPLIANCE
We conduct business in more than 80 countries, including approximately 15 of the countries having the lowest scores in the Transparency International's Corruption Perception Index survey for 2016, which indicates high levels of corruption. We devote significant resources to the development, maintenance, communication and enforcement of our Business Code of Conduct, our anti-bribery compliance policies, our internal control processes and procedures and numerous other compliance related policies. Notwithstanding the devotion of such resources, and in part as a consequence thereof, from time to time we discover or receive information alleging potential violations of laws and regulations, including the FCPA and our policies, processes and procedures. We conduct timely internal investigations of these potential violations and take appropriate action depending upon the outcome of the investigation.
We anticipate that the devotion of significant resources to compliance-related issues, including the necessity for investigations, will continue to be an aspect of doing business in a number of the countries in which oil and natural gas exploration, development and production take place and in which we conduct operations. Compliance-related issues have, from time to time, limited our ability to do business 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 (our "Compliance Program") is based on (i) our Core Values of Integrity, Performance, Teamwork, Learning and Courage; (ii) the standards contained in our Business Code of Conduct; and (iii) the laws of the countries where we operate. Our Compliance Program is referenced within the Company as "C2" or "Completely Compliant." The Completely Compliant theme is intended to establish the proper Tone-at-the-Top throughout the Company. Employees are consistently reminded that they play a crucial role in ensuring that the Company always conducts its business ethically, legally and safely.
Highlights of our Compliance Program include the following:
We have comprehensive internal policies over such areas as facilitating payments; travel, entertainment, gifts and charitable donations connected to non-U.S. government officials; payments to non-U.S. commercial sales representatives; and the use of non-U.S. police or military organizations for security purposes. In addition, we have country-specific guidance for customs standards, visa processing, export and re-export controls, economic sanctions and antiboycott laws.
We have a comprehensive employee compliance training program covering substantially all employees.
We have a due diligence procedure for commercial sales, processing and professional agents and an enhanced risk-based process for classifying distributors and suppliers.
We have continued our reduction of the use of commercial sales representatives and processing agents, including the reduction of customs agents.


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We have a compliance governance committee, which includes senior officers of the Company, that reviews our effectiveness and compliance with processes and controls of the Company's global Compliance Program including all areas covered by the Business Code of Conduct.
We have a special compliance committee, which is made up of senior officers, that meets no less than once a year to review the oversight reports for all active commercial sales representatives.
We have compliance committees that have been formed and are operating successfully in all of the Company's geomarkets.
We use technology to monitor and report on compliance matters, including an internal investigations management software, a web-based antiboycott reporting tool and a global trade management software tool.
We have a compliance 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 a centralized finance organization including an enterprise-wide accounting system and company-wide policies. In addition, the corporate audit function has incorporated anti-corruption procedures in audits of certain countries. We also conduct FCPA risk assessments and legal audit procedures relating to higher risk third parties in non-U.S. jurisdictions.
We continue to work to ensure that we have adequate legal compliance coverage around the world, including the coordination of compliance advice and customized training across all regions and countries where we do business.
We have a centralized human resources function, including, among other things, 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 a uniform policy for new hire training with a compliance component.
LIQUIDITY AND CAPITAL RESOURCES
Our objective in financing our business is to maintain sufficient liquidity, adequate financial resources and financial flexibility in order to fund the requirements of our business. At December 31, 2016, we had cash and cash equivalents of $4.57 billion compared to $2.32 billion of cash and cash equivalents at December 31, 2015. On May 4, 2016, Halliburton paid us $3.5 billion, which represents the termination fee required to be paid pursuant to the Merger Agreement. Part of the proceeds received were used to purchase $1.0 billion face value of our long-term notes and debentures, which included portions of each tranche of notes and debentures, and $763 million of our common stock.
At December 31, 2016, approximately $2.92 billion of our cash and cash equivalents was held by foreign subsidiaries compared to approximately $2.01 billion at December 31, 2015. A substantial portion of the cash held by foreign subsidiaries at December 31, 2016 was reinvested in our international operations as our current intent is to use this cash to, among other things, fund the operations of our foreign subsidiaries. If we decide at a later date to repatriate those funds to the U.S., we may be required to provide taxes on certain of those funds based on applicable U.S. tax rates net of foreign tax credits. We have a committed revolving credit facility (the "credit facility") with commercial banks and a related commercial paper program under which the maximum combined borrowing at any time under both the credit facility and the commercial paper program is $2.5 billion. At December 31, 2016, we had no commercial paper outstanding; therefore, the amount available for borrowing under the credit facility as of December 31, 2016 was $2.5 billion. During 2016, we used cash to fund a variety of activities including certain working capital needs and restructuring costs, capital expenditures, repurchases of long-term debt and common stock, and the payment of dividends. We believe that cash on hand, cash flows generated from operations and the available credit facility, including the issuance of commercial paper, will provide sufficient liquidity to manage our global cash needs.


38


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

(In millions)
2016
 
2015
 
2014
Operating activities
$
4,229

 
$
1,796

 
$
2,953

Investing activities
203

 
(905
)
 
(1,659
)
Financing activities
(2,185
)
 
(282
)
 
(939
)
Operating Activities
Cash flows from operating activities provided cash of $4.23 billion and $1.80 billion for the year ended December 31, 2016 and 2015, respectively. Cash flows from operating activities increased $2.43 billion in 2016 primarily due to the receipt of the $3.5 billion merger termination fee, changes in the components of our working capital (receivables, inventories and accounts payable) as a result of lower activity which provided cash of $695 million, and an income tax refund in the U.S. of approximately $415 million. These cash inflows were partially offset by an increase in our net loss, adjusted for non-cash items. Included in our cash flows from operating activities for 2016 and 2015 are payments of $419 million and $446 million, respectively, made for employee severance and contract termination costs as a result of our restructuring activities initiated during the year.
Cash flows from operating activities provided cash of $1.80 billion and $2.95 billion for the year ended December 31, 2015 and 2014, respectively. Cash flows from operating activities decreased $1.16 billion in 2015 primarily due to the decrease in our net income, adjusted for non-cash items, partially offset by the changes in the components of our working capital due to lower activity levels, which provided more cash in 2015 compared to 2014.
Investing Activities
Our principal recurring investing activity is the funding of capital expenditures to ensure that we have the appropriate levels and types of machinery and equipment in place to generate revenue from operations. Expenditures for capital assets totaled $332 million, $965 million and $1.79 billion for 2016, 2015 and 2014, respectively. The decline in capital expenditures over the past two years is a result of lower demand for our products and services and our continued focus on capital discipline.
Proceeds from the disposal of assets were $283 million, $388 million and $437 million for 2016, 2015 and 2014, respectively. These disposals related to equipment that was lost-in-hole and property, machinery, and equipment no longer used in operations that was sold throughout the year.
In 2016, we purchased short-term and long-term investment securities totaling $349 million and received proceeds of $453 million from the maturities of various investment securities.
During the fourth quarter of 2016, we contributed our North American onshore pressure pumping business into a new venture and received $142 million of cash, net of $8 million of direct transaction fees, and a 46.7% interest in the new venture. As a result of this transaction, we deconsolidated this business and recognized a $97 million loss on the sale of our majority interest in this business. See Note 5. "Acquisitions and Dispositions" of the Notes to Consolidated Financial Statements in Item 8 herein for further discussion.
Financing Activities
We had net repayments of commercial paper and other short-term debt of $60 million, $45 million and $248 million in 2016, 2015 and 2014, respectively. Total debt outstanding at December 31, 2016 was $3.02 billion, a decrease of $1.02 billion compared to December 31, 2015. The total debt-to-capital (defined as total debt plus equity) ratio was 0.19 at December 31, 2016 and 0.20 at December 31, 2015.
In June 2016, we purchased $1.0 billion of the aggregate outstanding principal amount associated with our long-term outstanding notes and debentures, which included portions of each tranche of notes and debentures.


39


Pursuant to a cash tender offer, the purchases resulted in the payment of an early-tender premium, including various fees, of $135 million and a pre-tax loss on the early extinguishment of debt of $142 million, which includes the premium and the write-off of a portion of the remaining original debt issue costs and debt discounts or premiums. The bond purchases will result in $55 million of annualized interest savings and $632 million of interest savings over the life of the bonds.
We received proceeds of $91 million, $116 million and $216 million in 2016, 2015 and 2014, respectively, from the issuance of common stock through the exercise of stock options and the employee stock purchase plan.
We paid dividends of $293 million, $297 million and $279 million in 2016, 2015 and 2014, respectively.
Beginning in May 2016, following the termination of the Merger with Halliburton, through September 30, 2016, we repurchased 16.2 million shares of our common stock at an average price of $47.09 per share, for a total of $763 million. We had authorization remaining to repurchase approximately $1.24 billion in common stock at December 31, 2016. We had no stock repurchases during the fourth quarter of 2016 or during 2015. In 2014, we repurchased 9.1 million shares of our common stock at an average price of $65.75 per share, for a total of $600 million.
Under the Transaction Agreement with GE entered into on October 30, 2016 as described in Note 3. "General Electric Transaction Agreement" of the Notes to Consolidated Financial Statements in Item 8 herein, we have generally agreed not to repurchase any shares of common stock or increase the quarterly dividend while the transaction is pending.
Available Credit Facility
On July 13, 2016, we entered into a new five-year $2.5 billion committed revolving credit facility (the "2016 Credit Agreement") with commercial banks maturing in July 2021, which replaced our existing credit facility of $2.5 billion, but maintained the existing commercial paper program. The previous credit facility had a maturity date in September of 2016. The maximum combined borrowing at any time under both the 2016 Credit Agreement and the commercial paper program is $2.5 billion. The 2016 Credit Agreement contains certain covenants, which, among other things, require the maintenance of a total debt-to-total capitalization ratio, 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 2016 Credit Agreement may be accelerated. Such events of default include payment defaults to lenders under the 2016 Credit Agreement, covenant defaults and other customary defaults.
We were in compliance with all of the credit facility's covenants, and there were no direct borrowings under the credit facility during 2016. Under the commercial paper program, we may issue from time to time up to $2.5 billion in commercial paper with maturities of no more than 270 days. The amount available to borrow under the credit facility is reduced by the amount of any commercial paper outstanding. At December 31, 2016, we had no outstanding borrowings under the commercial paper program.
If market conditions were to change and our revenue was reduced significantly or operating costs were to increase, our cash flows and liquidity could be reduced. Additionally, it could cause the rating agencies to lower our credit rating. There are no ratings triggers that would accelerate the maturity of any borrowings under our committed credit facility. However, a downgrade in our credit ratings could increase the cost of borrowings under the credit facility and could also limit or preclude our ability to issue commercial paper. Should this occur, we would seek alternative sources of funding, including borrowing under the credit facility.
We believe our current credit ratings would allow us to obtain interim financing over and above our existing credit facility for any currently unforeseen significant needs.
Cash Requirements
In 2017, we believe cash on hand, cash flows from operating activities and the available credit facility will provide us with sufficient capital resources and liquidity to manage our working capital needs, meet contractual obligations, fund capital expenditures and dividends, and support the development of our short-term and long-term


40


operating strategies. If necessary, 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.
Our capital expenditures can be adjusted and managed by us to match market demand and activity levels. In light of the current market conditions, capital expenditures in 2017 will be made as appropriate at a rate that we estimate would equal $450 million to $500 million on an annualized basis. The expenditures are expected to be used primarily for normal, recurring items necessary to support our business. We also anticipate making income tax payments in the range of $225 million to $275 million in 2017. For all defined benefit, defined contribution and other postretirement plans, we expect to contribute between $205 million to $222 million to these plans in 2017. See Note 14. "Employee Benefit Plans" of the Notes to Consolidated Financial Statements in Item 8 herein for further discussion.
We anticipate paying dividends in the range of $140 million to $160 million in the first half of 2017 prior to the expected Closing of the GE Transaction.
Contractual Obligations
In the table below, we set forth our contractual cash obligations as of December 31, 2016. Certain amounts included in this table are based on our estimates and assumptions about these obligations, including their duration, anticipated actions by third parties and other factors. The contractual cash obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.

 
Payments Due by Period
(In millions)
Total
 
Less Than
1 Year
 
2 - 3
Years
 
4 - 5
Years
 
More Than
5 Years
Total debt and capital lease obligations (1)
$
3,038

 
$
132

 
$
778

 
$
538

 
$
1,590

Estimated interest payments (2)
1,953

 
168

 
269

 
216

 
1,300

Operating leases (3)
344

 
118

 
106

 
48

 
72

Purchase obligations (4)
286

 
102

 
81

 
66

 
37

Liabilities for uncertain income tax positions (5)
351

 
216

 
68

 
32

 
35

Other long-term liabilities
164

 
34

 
42

 
14

 
74

Total (6)
$
6,136

 
$
770

 
$
1,344

 
$
914

 
$
3,108

(1) 
Amounts represent the expected cash payments for the principal amounts related to our debt, including capital lease obligations. Amounts for debt do not include any unamortized discounts or deferred issuance costs. Expected cash payments for interest are excluded from these amounts.
(2) 
Amounts represent the expected cash payments for interest on our long-term debt and capital lease obligations.
(3) 
Amounts represent the future minimum payments under noncancelable operating leases with initial or remaining terms of one year or more. We enter into operating leases, some of which include renewal options; however, we have excluded renewal options from the table above unless it is anticipated that we will exercise such renewals.
(4) 
Purchase obligations include capital improvements as well as agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction.
(5) 
The estimated income tax liabilities for uncertain tax positions will be settled as a result of expiring statutes, audit activity, competent authority proceedings related to transfer pricing, or final decisions in matters that are the subject of litigation in various taxing jurisdictions in which we operate. The timing of any particular settlement will depend on the length of the tax audit and related appeals process, if any, or an expiration of a statute. If a liability is settled due to a statute expiring or a favorable audit result, the settlement of the tax liability would not result in a cash payment.
(6) 
Amounts do not include expected contributions to our pension and other postretirement defined benefit plans of between $70 million to $80 million in 2017 as the majority of these contributions are amounts in excess of minimum funding requirements and as such would not be considered a contractual obligation.


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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 surety bonds for performance, letters of credit and other bank issued guarantees, which totaled approximately $1.0 billion at December 31, 2016. 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.
As of December 31, 2016, we had no material off-balance sheet financing arrangements other than normal operating leases, as discussed above. 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, revenue and expenses and related disclosures as well as disclosures about any contingent assets and liabilities. We base these estimates and judgments on historical experience and other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects are subject to uncertainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the business environment in which we operate changes.
We have defined a critical accounting estimate as one that is both important to the portrayal of either our financial condition or results of operations and requires us to make difficult, subjective or complex judgments or estimates about matters that are uncertain. The Audit/Ethics Committee of our Board of Directors has reviewed our critical accounting estimates and the disclosure presented below. During the past three fiscal years, we have not made any material changes in the methodology used to establish the critical accounting estimates, and we believe that the following are the critical accounting estimates used in the preparation of our consolidated financial statements. There are other items within our consolidated financial statements that require estimation and judgment but they are not deemed critical as defined above.
Allowance for Doubtful Accounts
The determination of the collectability of amounts due from our customers requires us to make judgments and estimates regarding our customers' ability to pay amounts due us in order to determine the amount of valuation allowances required for doubtful accounts. We monitor our customers' payment history and current credit worthiness to determine that collectability is reasonably assured. We also consider the overall business climate in which our customers operate. Provisions for doubtful accounts are recorded based on the aging status of the customer accounts or 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, 2016 and 2015, the allowance for doubtful accounts totaled $509 million, or 18%, and $383 million, or 11%, 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 (loss) before income taxes of approximately $25 million in 2016.
Inventory Reserves
Inventory is a significant component of current assets and is stated at the lower of cost or net realizable value. 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, 2016 and 2015, inventory reserves totaled $188 million, or 9%, and $278 million, or 9%, of gross inventory, respectively. During 2016, we wrote off the carrying value of certain excess inventory resulting in charges of $583 million. This amount was net of existing reserves of $272 million. We believe


42


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, slow moving or obsolete inventory that may be required. A five percent change in this inventory reserve balance would have had an impact on income (loss) before income taxes of approximately $9 million in 2016.
Goodwill and Other Long-Lived Assets
The purchase price of acquired businesses is allocated to its identifiable assets and liabilities based upon estimated fair values as of the acquisition date. Goodwill is the excess of the purchase price over the fair value of tangible and identifiable intangible assets and liabilities acquired in a business acquisition. Our goodwill at December 31, 2016 and 2015, totaled $4.08 billion and $6.07 billion, respectively. We perform an annual impairment test of goodwill on a qualitative or quantitative basis for each of our reporting units as of October 1 of each year, or more frequently when circumstances indicate an impairment may exist at the reporting unit level. Our reporting units are the same as our five reportable segments. When performing the annual impairment test we have the option of performing a qualitative or quantitative assessment to determine if an impairment has occurred. If a qualitative assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then we would be required to perform a quantitative impairment test for goodwill.
Goodwill is tested for impairment using a two-step approach. In the first step, the fair value of each reporting unit is determined and compared to the reporting unit's carrying value, including goodwill. If the fair value of a reporting unit is less than its carrying value, the second step of the goodwill impairment test is performed to measure the amount of impairment, if any. In the second step, the fair value of the reporting unit is allocated to the assets and liabilities of the reporting unit as if it had been acquired in a business combination and the purchase price was equivalent to the fair value of the reporting unit. The excess of the fair value of the reporting unit over the amounts assigned to its assets and liabilities is referred to as the implied fair value of goodwill. The implied fair value of the reporting unit's goodwill is then compared to the actual carrying value of goodwill. If the implied fair value of goodwill is less than the carrying value of goodwill, an impairment loss is recognized for the difference.
In determining the carrying amount of reporting units, corporate and other assets and liabilities are allocated to the extent that they relate to the operations of those reporting units. When necessary, we calculate the fair value of a reporting unit using various valuation techniques, including a market approach, a comparable transactions approach and discounted cash flow ("DCF") methodology. The market approach and comparable transactions approach provide value indications for a company through a comparison with guideline public companies or guideline transactions, respectively. Both entail selecting relevant financial information of the subject company, and capitalizing those amounts using valuation multiples that are based on empirical market observations. The DCF methodology includes, but is not limited to, assumptions regarding matters such as discount rates, anticipated growth rates, expected profitability rates and the timing of expected future cash flows. Unanticipated changes, including even small revisions, to these assumptions could result in a provision for impairment in a future period. In addition, a decline in our stock price could result in an impairment. Given the nature of these evaluations and their application to specific assets and time-frames, it is not possible to reasonably quantify the impact of changes in these assumptions.
In the second quarter of 2016, as a result of the termination of the Merger Agreement with Halliburton, we concluded it was necessary to conduct a quantitative assessment for potential goodwill impairment and determined that goodwill of two of our reporting units was impaired. The quantitative assessment was calculated using a combination of market and discounted cash flow approaches. As a result, we recorded an impairment charge of $1.86 billion, of which $1.55 billion pertained to the North America reporting unit and $309 million pertained to Industrial Services. See Note 12. "Goodwill and Intangible Assets" of the Notes to Consolidated Financial Statements in Item 8 herein for further description. In addition to the quantitative assessment performed in the second quarter of 2016, and consistent with our policy stated above, we also performed our annual goodwill impairment test for all reporting units as of October 1, 2016. This assessment was performed on a qualitative basis, and included our consideration of changes in industry and market conditions since the performance of our quantitative analysis in the second quarter of 2016. Based on this assessment, we determined no additional impairment of goodwill was necessary in the fourth quarter of 2016. In 2015 and 2014, we performed a qualitative assessment for our annual goodwill impairment test and determined no impairments of goodwill were necessary in 2015 or 2014.


43


Long-lived assets, which include property and equipment, intangible assets other than goodwill, and certain other assets, comprise a significant amount of our total assets. We review the carrying values of these assets for impairment periodically, and at least annually for certain intangible assets or whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires us to make judgments regarding long-term forecasts of future revenue and costs and cash flows related to the assets subject to review. These forecasts are uncertain in that they require assumptions about demand for our products and services, future market conditions and technological developments. See Note 4. "Impairment and Restructuring Charges" of the Notes to Consolidated Financial Statements in Item 8 herein for further discussion of impairment of certain property and equipment and intangible assets recorded in 2016 and 2015.
Income Taxes
The liability method is used for determining our income tax provisions, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In determining the need for valuation allowances, we have considered and made judgments and estimates regarding estimated future taxable income and ongoing prudent and feasible tax planning strategies. These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to adjust the valuation allowances for our deferred tax assets. Historically, changes to valuation allowances have been caused by major changes in the business cycle in certain countries and changes in local country law. The ultimate realization of the deferred tax assets depends on the generation of sufficient taxable income in the applicable taxing jurisdictions.
We conduct business 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, including actual income before taxes, deemed profits (which are generally determined using a percentage of revenue rather than profits) and withholding taxes based on revenue. Determination of taxable income in any jurisdiction requires the interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of deductions, permissible revenue recognition methods under the tax law and the sources and character of income and tax credits. Changes in tax laws, regulations, agreements and treaties, foreign currency exchange restrictions or our level of operations or profitability in each taxing jurisdiction could have an impact on the amount of income taxes that we provide during any given year.
Our tax filings for various periods are subject to audit by the tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or through the courts. We believe these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. Resolution of these situations inevitably includes some degree of uncertainty; accordingly, we provide taxes only for the amounts we believe will ultimately result from these proceedings. The resulting change to our tax liability, if any, is dependent on numerous factors including, among others, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a fair settlement through an administrative process; the impartiality of the local courts; the number of countries in which we do business; and the potential for changes in the tax paid to one country to either produce, or fail to produce, an offsetting tax change in other countries. Our experience has been that the estimates and 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


44


consolidated financial condition of the Company, although a resolution could have a material impact on our consolidated statements of income (loss) for a particular period and on our effective tax rate for any period in which such resolution occurs.
Pensions and Postretirement Benefit Obligations
Pensions and postretirement benefit obligations and the related expenses are calculated using actuarial models and methods. This involves the use of two critical assumptions, the discount rate and the expected rate of return on assets, both of which are important elements in determining pension expense and in measuring plan liabilities. We evaluate these critical assumptions at least annually, and as necessary, we utilize third-party actuarial firms to assist us. Although considered less critical, other assumptions used in determining benefit obligations and related expenses, such as demographic factors like retirement age, mortality and turnover, are also evaluated periodically and are updated to reflect our actual and expected experience.
The discount rate enables us to determine expected future cash flows at a present value on the measurement date. The development of the discount rate for our largest plans was based on a bond matching model whereby the cash flows underlying the projected benefit obligation are matched against a yield curve constructed from a bond portfolio of high-quality, fixed-income securities. Use of a lower discount rate would increase the present value of benefit obligations and increase pension expense. We used a weighted average discount rate of 3.9% in 2016, 3.6% in 2015 and 4.5% in 2014 to determine pension expense. A 50 basis point reduction in the weighted average discount rate would have increased pension expense of our principal pension plans by approximately $1 million in 2016.
To determine the expected rate of return on plan assets, we consider the current and target asset allocations, as well as historical and expected future returns on various categories of plan assets. A lower rate of return would decrease plan assets which results in higher pension expense. We assumed a weighted average expected rate of return on our plan assets of 5.9% in 2016, 6.8% in 2015 and 6.7% in 2014. A 50 basis point reduction in the weighted average expected rate of return on assets of our principal pension plans would have increased pension expense by approximately $6 million in 2016.
New Accounting Standards
See Note 1. "Summary of Significant Accounting Policies" of the Notes to Consolidated Financial Statements in Item 8 herein for further discussion of accounting standards adopted and to be adopted.
RELATED PARTY TRANSACTIONS
There were no significant related party transactions during the three years ended December 31, 2016.
FORWARD-LOOKING STATEMENTS
This Form 10-K, including MD&A and certain statements in the Notes to Consolidated Financial Statements, contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act of 1934, as amended, (each a "forward-looking statement"). The words "anticipate," "believe," "ensure," "expect," "if," "intend," "estimate," "probable," "project," "forecasts," "predict," "outlook," "aim," "will," "could," "should," "would," "potential," "may," "likely" and similar expressions, and the negative thereof, are intended to identify forward-looking statements. Our forward-looking statements are based on assumptions that we believe to be reasonable but that may not prove to be accurate. The statements do not include the potential impact of future transactions, such as an acquisition, disposition, merger, joint venture or other transaction that could occur, including the pending Merger with GE. We undertake no obligation to publicly update or revise any forward-looking statement. Our expectations regarding our business outlook, including changes in revenue, pricing, capital spending, profitability, strategies for our operations, impact of any common stock repurchases, oil and natural gas market conditions, the business plans of our customers, market share and contract terms, costs and availability of resources, legal, economic and regulatory conditions, and environmental matters are only our forecasts regarding these matters.


45


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 risk factors, these risks and uncertainties include the factors and the timing of any of those factors identified in this annual report under Item 1A. Risk Factors and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 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 (EDGAR) system at http://www.sec.gov. In light of such risks and uncertainties, we caution you not to place undue reliance on these forward-looking statements. These forward-looking statements speak only as of the date of this annual report, or if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities law.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to certain market risks that are inherent in our financial instruments and arise from changes in interest rates and foreign currency exchange rates. We may enter into derivative financial instrument transactions to manage or reduce market risk but do not enter into derivative financial instrument transactions for speculative purposes. A discussion of our primary market risk exposure in financial instruments is presented below.
INTEREST RATE RISK
We have debt in fixed and floating rate instruments. We are subject to interest rate risk on our debt and investment portfolio. We maintain an interest rate risk management strategy which primarily uses a mix of fixed and variable rate debt that is intended to mitigate the risk exposure to changes in interest rates in the aggregate. We may use interest rate swaps to manage the economic effect of fixed rate obligations associated with certain debt. There were no outstanding interest rate swap agreements as of December 31, 2016 or 2015. The following table sets forth our fixed rate long-term debt and the related weighted average interest rates by expected maturity dates.
(In millions)
2017
 
2018
 
2019
 
2020
 
2021
 
Thereafter
 
Total (3)
As of December 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt (1) (2)
$

 
$
751

 
$
27

 
$
12

 
$
526

 
$
1,590

 
$
2,906

Weighted average interest rates
%
 
7.39
%
 
6.45
%
 
5.03
%
 
3.43
%
 
5.84
%
 
5.86
%
As of December 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt (1) (2)
$
24

 
$
1,022

 
$
22

 
$
12

 
$
761

 
$
2,077

 
$
3,918

Weighted average interest rates
7.77
%
 
7.28
%
 
5.94
%
 
5.03
%
 
3.40
%
 
5.84
%
 
5.79
%
(1) 
Amounts do not include any unamortized discounts, premiums or deferred issuance costs on our fixed rate long-term debt.
(2) 
Fair market value of our fixed rate long-term debt was $3.23 billion at December 31, 2016 and $4.17 billion at December 31, 2015.
(3) 
Amounts represent the principal value of our long-term debt outstanding and related weighted average interest rates at the end of the respective period.
FOREIGN CURRENCY EXCHANGE RISK
We conduct our operations around the world in a number of different currencies, and we are exposed to market risks resulting from fluctuations in foreign currency exchange rates. Many of our significant foreign subsidiaries have designated the local currency as their functional currency. As such, future earnings are subject to change due to fluctuations in foreign currency exchange rates when transactions are denominated in currencies other than our functional currencies. To minimize the need for foreign currency forward contracts to hedge this exposure, our objective is to manage foreign currency exposure by maintaining a minimal consolidated net asset or net liability position in a currency other than the functional currency.
At December 31, 2016 and 2015, we had outstanding foreign currency forward contracts with notional amounts aggregating $271 million and $499 million, respectively, to hedge exposure to currency fluctuations in various foreign currencies. These contracts are either undesignated hedging instruments or designated and qualify as fair value hedging instruments. The notional amounts of our foreign currency forward contracts do not generally


46


represent amounts exchanged by the parties, and thus are not a measure of the cash requirements related to these contracts or of any possible loss exposure. The amounts actually exchanged are calculated by reference to the notional amounts and by other terms of the derivative contracts, such as exchange rates. Based on quoted market prices as of December 31, 2016 and 2015 for contracts with similar terms and maturity dates, we recorded a gain of $1 million and a loss of $1 million, respectively, to adjust these foreign currency forward contracts to their fair market value. These gains and losses offset designated foreign currency exchange gains and losses resulting from the underlying exposures and are included in MG&A expenses in the consolidated statements of income (loss).


47


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over our financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we assessed the effectiveness of our internal control over financial reporting based on the 2013 framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, our principal executive officer and principal financial officer concluded that our internal control over financial reporting was effective as of December 31, 2016. This conclusion is based on the recognition that there are inherent limitations in all systems of internal control. Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Deloitte & Touche LLP, the Company's independent registered public accounting firm, has issued an attestation report on the effectiveness of the Company's internal control over financial reporting.

/s/ MARTIN S. CRAIGHEAD
Martin S. Craighead
Chairman and
Chief Executive Officer
  
/s/ KIMBERLY A. ROSS
Kimberly A. Ross
Senior Vice President and
Chief Financial Officer
  
/s/ KELLY C. JANZEN
Kelly C. Janzen
Vice President, Controller and Chief Accounting Officer
Houston, Texas
February 7, 2017



48


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, 2016 and 2015, and the related consolidated statements of income (loss), comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2016. Our audits also included financial statement schedule II, valuation and qualifying accounts, listed in the Index at Item 15. We also have audited the Company's internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company's internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Baker Hughes Incorporated and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 7, 2017


49


BAKER HUGHES INCORPORATED
CONSOLIDATED STATEMENTS OF INCOME (LOSS)


 
Year Ended December 31,
(In millions, except per share amounts)
2016
 
2015
 
2014
Revenue:
 
 
 
 
 
Sales
$
3,870

 
$
5,649

 
$
8,056

Services
5,971

 
10,093

 
16,495

Total revenue
9,841

 
15,742

 
24,551

Costs and expenses:
 
 
 
 
 
Cost of sales
3,722

 
4,833

 
6,294

Cost of services
6,251

 
9,582

 
13,452

Research and engineering
384

 
466

 
613

Marketing, general and administrative
815

 
969

 
1,333

Impairment and restructuring charges
1,735

 
1,993

 

Goodwill impairment
1,858

 

 

Merger and related costs
199

 
295

 

Merger termination fee
(3,500
)
 

 

Total costs and expenses
11,464

 
18,138

 
21,692

Operating (loss) income
(1,623
)
 
(2,396
)
 
2,859

Loss on sale of business interest
(97
)
 

 

Loss on early extinguishment of debt
(142
)
 

 

Interest expense, net
(178
)
 
(217
)
 
(232
)
(Loss) income before income taxes
(2,040
)
 
(2,613
)
 
2,627

Income tax (provision) benefit
(696
)
 
639

 
(896
)
Net (loss) income
(2,736
)
 
(1,974
)
 
1,731

Net (income) loss attributable to noncontrolling interests
(2
)
 
7

 
(12
)
Net (loss) income attributable to Baker Hughes
$
(2,738
)
 
$
(1,967
)
 
$
1,719

 
 
 
 
 
 
Basic (loss) earnings per share attributable to Baker Hughes
$
(6.31
)
 
$
(4.49
)
 
$
3.93

 
 
 
 
 
 
Diluted (loss) earnings per share attributable to Baker Hughes
$
(6.31
)
 
$
(4.49
)
 
$
3.92

See Notes to Consolidated Financial Statements



50


BAKER HUGHES INCORPORATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


 
Year Ended December 31,
(In millions)
2016
 
2015
 
2014
Net (loss) income
$
(2,736
)
 
$
(1,974
)
 
$
1,731

Other comprehensive (loss) income:
 
 
 
 
 
Foreign currency translation adjustments
(5
)
 
(241
)
 
(216
)
Pension and other postretirement benefits, net of tax
(23
)
 
(15
)
 
(29
)
Other comprehensive loss
(28
)
 
(256
)
 
(245
)
Comprehensive (loss) income
(2,764
)
 
(2,230
)
 
1,486

Comprehensive (income) loss attributable to noncontrolling interests
(2
)
 
7

 
(12
)
Comprehensive (loss) income attributable to Baker Hughes
$
(2,766
)
 
$
(2,223
)
 
$
1,474

See Notes to Consolidated Financial Statements



51


BAKER HUGHES INCORPORATED
CONSOLIDATED BALANCE SHEETS

 
December 31,
(In millions, except par value)
2016
 
2015
ASSETS
Current Assets:
 
 
 
Cash and cash equivalents
$
4,572

 
$
2,324

Accounts receivable - less allowance for doubtful accounts
(2016 - $509; 2015 - $383)
2,251

 
3,217

Inventories, net
1,809

 
2,917

Other current assets
535

 
810

Total current assets
9,167

 
9,268

 
 
 
 
Property, plant and equipment - less accumulated depreciation
(2016 - $6,567; 2015 - $7,378)
4,271

 
6,693

Goodwill
4,084

 
6,070

Intangible assets, net
318

 
583

Other assets
1,194

 
1,466

Total assets
$
19,034

 
$
24,080

LIABILITIES AND EQUITY
Current Liabilities:
 
 
 
Accounts payable
$
1,027

 
$
1,409

Short-term debt and current portion of long-term debt
132

 
151

Accrued employee compensation
566

 
690

Income taxes payable
78

 
55

Other accrued liabilities
501

 
470

Total current liabilities
2,304

 
2,775

 
 
 
 
Long-term debt
2,886

 
3,890

Deferred income taxes and other tax liabilities
328

 
252

Liabilities for pensions and other postretirement benefits
626

 
646

Other liabilities
153

 
135

Commitments and contingencies

 

 
 
 
 
Equity:
 
 
 
Common stock, one dollar par value
(shares authorized - 750; issued and outstanding: 2016 - 424; 2015 - 437)
425

 
437

Capital in excess of par value
6,708

 
7,261

Retained earnings
6,583

 
9,614

Accumulated other comprehensive loss
(1,033
)
 
(1,005
)
Treasury stock
(27
)
 
(9
)
Baker Hughes stockholders' equity
12,656

 
16,298

Noncontrolling interests
81

 
84

Total equity
12,737

 
16,382

Total liabilities and equity
$
19,034

 
$
24,080

See Notes to Consolidated Financial Statements


52


BAKER HUGHES INCORPORATED
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY


 
Baker Hughes Stockholders' Equity
 
 
 
 
(In millions, except per share amounts)
Common Stock
 
Capital in Excess of Par Value
 
Retained Earnings
 
Accumulated Other Comprehensive Loss
 
Treasury Stock
 
Non-controlling Interests
 
Total
Balance at December 31, 2013
$
438

 
$
7,341

 
$
10,438

 
$
(504
)
 
$

 
$
199

 
$
17,912

Comprehensive income:
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income
 
 
 
 
1,719

 
 
 
 
 
12

 
1,731

Other comprehensive loss
 
 
 
 
 
 
(245
)
 
 
 

 
(245
)
Activity related to stock plans
5

 
200

 
 
 
 
 
 
 
 
 
205

Repurchase and retirement of common stock
(9
)
 
(591
)
 
 
 
 
 
 
 
 
 
(600
)
Stock-based compensation cost
 
 
122

 
 
 
 
 
 
 
 
 
122

Cash dividends ($0.64 per share)
 
 
 
 
(279
)
 
 
 
 
 
 
 
(279
)
Net activity related to noncontrolling interests
 
 
(10
)
 
 
 
 
 
 
 
(106
)
 
(116
)
Balance at December 31, 2014
$
434

 
$
7,062

 
$
11,878

 
$
(749
)
 
$

 
$
105

 
$
18,730

Comprehensive income:
 
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 
 
 
 
(1,967
)
 
 
 
 
 
(7
)
 
(1,974
)
Other comprehensive loss
 
 
 
 
 
 
(256
)
 
 
 
 
 
(256
)
Activity related to stock plans
3

 
101

 
 
 
 
 
(9
)
 
 
 
95

Stock-based compensation cost
 
 
120

 
 
 
 
 
 
 
 
 
120

Cash dividends ($0.68 per share)
 
 
 
 
(297
)
 
 
 
 
 
 
 
(297
)
Net activity related to noncontrolling interests
 
 
(22
)