Baker Hughes Company
Annual Report 2015

Plain-text annual report

2015 ANNUAL REPORT FINANCIAL HIGHLIGHTS (In millions, except per share amounts) 2015 2014 2013 2012 2011 Year Ended December 31 As Reported: Revenue Operating income (loss) Net income (loss) Net income (loss) attributable to Baker Hughes Per share of common stock: Net income (loss) attributable to Baker Hughes: Basic Diluted Dividends Number of shares: $ 15,742 $ 24,551 $ 22,364 $ 21,361 $ 19,831 (2,396) (1,974) (1,967) 2,859 1,731 1,719 1,949 1,103 1,096 2,192 1,317 1,311 2,600 1,743 1,739 $ (4.49) $ 3.93 $ 2.47 $ 2.98 $ 3.99 (4.49) 0.68 3.92 0.64 2.47 0.60 2.97 0.60 3.97 0.60 Weighted average common shares diluted 438 439 444 441 438 Reconciliation from As Reported to Adjusted Net Income (Loss): Net income (loss) attributable to Baker Hughes $ (1,967) $ 1,719 $ 1,096 $ 1,311 $ 1,739 Adjustments(1) Adjusted net income (loss)(2) Per share of common stock: Adjusted net income (loss)(2): Basic Diluted Cash, cash equivalents and short-term investments Working capital Total assets Total debt Equity Total debt/capitalization Number of employees (thousands) 1,758 130 69 43 102 $ (209) $ 1,849 $ 1,165 $ 1,354 $ 1,841 $ (0.48) $ 4.23 $ 2.62 $ 3.08 $ 4.22 (0.48) 2,324 6,493 24,080 4,041 16,382 20% 43.0 4.22 1,740 7,408 28,827 4,133 18,730 18% 62.0 2.62 1,399 6,717 27,934 4,381 17,912 20% 59.4 3.07 1,015 6,293 26,689 4,916 17,268 22% 58.8 4.20 1,050 6,295 24,847 4,069 15,964 20% 57.7 (1) 2015 after-tax adjustments: cost of $1,415 million associated with asset impairments, workforce reductions, facility closures and contract terminations; cost of $214 million for merger and related expenses; cost of $138 million to adjust the carrying value of certain inventory; and a $9 million reduction in the accrual for litigation settlements for labor claims. 2014 after-tax adjustments: cost of $58 million related to restructuring our North Africa business; cost of $39 million for litigation settlements for labor claims; severance charges of $21 million in North America; cost of $20 million related to a technology royalty agreement; cost of $14 million related to an impairment of a technology investment; foreign exchange loss of $12 million from the devaluation of the Venezuelan currency; $34 million gain from the deconsolidation of a joint venture. 2013 after-tax adjustments: severance charges of $29 million; foreign exchange loss of $23 million from the devaluation of the Venezuelan currency; $17 million of restructuring charges related to Latin America. 2012 after-tax adjustments: expenses of $15 million from the closure of a chemical manufacturing facility in the United Kingdom; expenses of $28 million for internally developed software and other information technology assets. 2011 after-tax adjustments: a charge of $220 million related to our decision to minimize the use of the BJ Services trade name; tax benefit of $214 million from the reorganization of certain foreign subsidiaries; expenses of $70 million associated with increasing the reserves for bad debt, inventory and certain other assets as a result of civil unrest in Libya; loss of $26 million for the early extinguishment of debt. (2) Adjusted net income is a non-GAAP measure comprised of net income attributable to Baker Hughes excluding the impact of certain identified items. The Company believes that adjusted net income is useful to investors because it is a consistent measure of the underlying results of the Company’s business. Furthermore, management uses adjusted net income as a measure of the performance of the Company’s operations. Martin Craighead CHAIRMAN AND CHIEF EXECUTIVE OFFICER TO OUR SHAREHOLDERS After years of growth, 2015 was an increasingly challenging year marked by retrenchment, recalibration, transition and transformation in the global oil and gas industry as the sector wrestled with the impact of a supply-demand imbalance causing oil prices to drop to seven-year lows by the end of the year. As a result of these industry dynamics, customer activity and spending while ensuring that the company’s competitive position remained strong. declined significantly throughout We also incurred merger-related 2015, which was reflected in the 46% costs as we worked to close our decline in the global rig count since pending business combination with the fourth quarter of 2014. While Halliburton and plan for a successful the decline in the North American integration. Excluding these one-time market was most severe, this has charges, adjusted net loss (a non- truly been a global downturn. GAAP measure) for 2015 was $209 million ($0.48 per diluted share). The entire oilfield services industry was negatively affected by these spending Knowing that the market environment cuts as the customer community was fluid and would remain increasingly focused on reducing challenging throughout the year, costs and preserving cash flow. This we managed the company with a environment likewise had a negative quarter-to-quarter focus, adapting to impact on our results as Baker Hughes the rapidly changing environment. In reported a revenue decline of 36% to short, we focused on controlling those $15.7 billion in 2015 compared to 2014. factors within our control, such as On a GAAP basis, Baker Hughes efficiently managing our cost structure, reported a net loss for 2015 of $2 strengthening our cash performance billion ($4.49 per diluted share), and balance sheet, improving versus net income of $1.7 billion capital discipline, and delivering ($3.92 per diluted share) in 2014. innovative solutions and outstanding performance to our customers. Given the difficult market conditions throughout 2015, we took significant In spite of the revenue headwinds, we actions to align our business and cost were able to contain losses by taking structure with the market environment, actions to reduce costs companywide, in every phase of our business. The most difficult While we are working diligently to improve profitability, decisions have been the significant workforce reductions to comply with the merger agreement with Halliburton that were required to adjust our cost structure to be and in preparation for the combined Baker Hughes/ in line with revenue opportunities and profitability Halliburton entity we have retained certain costs, objectives. Yet, I am pleased that our workforce has which in the fourth quarter of 2015 exceeded 300 basis remained engaged, focused on customers, committed points, or in excess of ($0.16) earnings-per-share impact. to achieving our business and financial objectives, and This is the right approach to ensure that the proposed steadfast in its dedication to compliance and safety. combination has the best foundation for success. One of the ways in which I can see this collective In addition to reducing costs, one of our biggest engagement and dedication is through our Health, priorities in 2015 was to continue to strengthen our Safety and Environment (HSE) performance. In this balance sheet–in particular, our cash performance–and area, 2015 was a record year for Baker Hughes we made significant progress in this area. We generated with 146 “Perfect HSE Days” in which we had no $1.2 billion of free cash flow* during the year, and that injuries, environmental releases or vehicle accidents. total would have been $1.7 billion when you consider the Considering the many potential distractions our approximately $450 million in restructuring payments employees face, I am heartened by this performance we made during the year. This compares to $1.6 billion and we are focused on continuing this trend in 2016. of free cash flow in 2014. The LEAP adaptive production system *Free cash flow is defined as net cash flows provided by operating activities less disbursements for capital expenditures plus proceeds from disposal of assets. One of the drivers of our free cash flow performance lift systems), and a sensor, which provides pressure resulted from our reduction in capital spending from and temperature data to help ensure the highest level $1.8 billion in 2014 to $1 billion in 2015, a 46% of production optimization and system longevity. reduction, as we scrutinized investments to ensure the best possible return and alignment with market opportunities, while continuing to make sure we are CENesis PHASE™ multiphase encapsulated production solution helps operators avoid production interruptions competitively well-positioned for the long term. This in unconventional wells. Designed to separate natural diligent focus on spending will continue in 2016. gas from the oil stream before it can enter an electrical The outcome we achieved on cash performance mitigates production downtime and potential ESP is the result of our cost reduction initiatives, performance issues, which can ultimately improve commitment to capital discipline and solid progress reserve recovery. submersible pumping (ESP) system, the solution on initiatives to improve working capital, and these efforts will remain priorities in the year ahead. FATHOM™ XT SUBSEA 525 inhibitor helps control asphaltene deposition in deepwater wells, providing Even with this disciplined approach to spending, our better flow assurance and reducing remediation costs product pipeline remained robust in 2015. We introduced by minimizing the risk of blockages in production more than 200 new products last year, with revenue lines and equipment. This product can help prevent generated from these products exceeding $900 million deposits inside pumps and pipes that create serious in comparison to 2014’s record-setting $1 billion. When production issues such as plugged flow lines and you consider that operators have reduced spending clogged equipment, reducing the need to stop industry-wide by about 50% compared to 2014, the operations and perform costly procedures to get magnitude of this accomplishment becomes apparent. production back online at acceptable levels. Being the technology enthusiast that I am, I could probably spend an entire letter talking about our SPECTRE™ disintegrating frac plug is the first in the industry to completely disintegrate downhole after products. But, for the sake of brevity, I will highlight fracturing, enabling increased efficiency and maximized four from 2015. The LEAP™ adaptive production system was installed in December 2015 and is delivering 300% greater oil flexibility in plug-and-perf completions. The plug offers the same flexible stage placement as traditional plugs, but its ability to completely disintegrate downhole results in accelerated completion times, and lower costs production and 200% greater natural gas production and risks. It also leaves behind an unobstructed fullbore at the first field trial compared to the previous artificial production inside diameter for maximum flow area and lift solution. The downhole system consists of a simplified access. positive displacement pump, which can be installed to sit deeper in a well than traditional rod pumps, a These commercial advancements demonstrate our submersible linear electromagnetically actuated motor, capabilities in helping our customers solve their which drives the pump and eliminates the need for most complex challenges. As you would expect, with the long rod string (a primary source of failure in rod market conditions being what they are, our customers understandably are trying to maximize as much oil and Finally, one of our biggest areas of focus in 2015, which gas production as possible from their existing assets continues in 2016, has been our efforts to complete at the lowest possible cost. In helping our customers the Halliburton transaction. Undoubtedly, you are also meet these objectives, for example, Baker Hughes aware of the lawsuit by the United States Department is fortunate to be able to offer an outstanding value of Justice (DOJ), filed in April 2016, to block the proposition with our Artificial Lift and Production combination. The companies believe that the DOJ has Chemicals product lines. These are very good and strategic reached the wrong conclusion in its assessment of the businesses to have in this type of market environment. transaction and intend to vigorously contest this action. Likewise, there are some markets globally that are more As we continue to work toward closing the transaction, stable and resilient than others. We will continue to I remain proud of the efforts of the entire Baker Hughes focus our efforts in these areas in the near term while team in supporting the regulatory review process in remaining prepared to capitalize when the broader jurisdictions around the world and working on the market recovers and demand improves for a broader integration plans. range of services, and in more parts of the world. In closing, while 2015 was extremely challenging for the As to when that recovery will occur, it remains tough to industry and those challenges are continuing this year, say. History tells us that it will do so, and I firmly believe I feel very optimistic about the path forward–for our that. However, there are too many variables–ranging company and for our industry. I want to emphasize that from geopolitical dynamics to economic growth concerns our company’s Purpose–Enabling safe, affordable energy, in key markets–to predict when supply and demand improving people’s lives–is more relevant today than it ever will normalize. If commodity prices remain in the same has been. Our commitment to this Purpose is unwavering. range as we have seen during the early months of 2016, we could see global rig counts decline by another 30% this year on top of last year’s decline. Therefore, we will continue to focus in the near term on cash generation and improving profitability by efficiently managing costs and opportunistically seeking revenue opportunities. I remain confident that we will meet these challenges head on. Not only because of Baker Hughes’ outstanding products and capabilities but because of the experience of an engaged management team that has been through these down cycles before and is once again responding to the challenge. Martin Craighead CHAIRMAN AND CHIEF EXECUTIVE OFFICER FORM 10-K/A UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K/A Amendment No. 1 [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2015 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 (State or other jurisdiction of incorporation or organization) 76-0207995 (I.R.S. Employer Identification No.) 2929 Allen Parkway, Suite 2100, Houston, Texas (Address of principal executive offices) 77019-2118 (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, 2015 reported by the New York Stock Exchange) was approximately $26,830,538,000. As of February 10, 2016, the registrant has outstanding 437,853,899 shares of common stock, $1 par value per share. DOCUMENTS INCORPORATED BY REFERENCE Portions of Registrant’s Definitive Proxy Statement for the 2016 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K. EXPLANATORY NOTE Baker Hughes Incorporated (the "Company") is filing this Amendment No. 1 to its Form 10-K for the year ended December 31, 2015 originally filed with the Securities and Exchange Commission on February 17, 2016 (the "2015 Form 10-K") solely for the purpose of removing the caption "AEC Draft 2/16/2016" which was inadvertently included on the top right corner of the cover page of the 2015 Form 10-K. No items or disclosures appearing in the Company’s 2015 Form 10-K are affected by this filing other than the cover page correction. This report on Form 10-K/A is as of the filing date of the 2015 Form 10-K and does not reflect events occurring after that date, or modify or update disclosures in any way. For convenience, the entire Annual Report on Form 10-K, as amended, is being re-filed. Baker Hughes Incorporated Table of Contents Part I Part II Business Item 1. Item 1A. Risk Factors Item 1B. Unresolved Staff Comments Item 2. Properties Item 3. Item 4. Mine Safety Disclosures Legal Proceedings Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Item 6. Selected Financial Data Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Financial Statements and Supplementary Data Management’s Report on Internal Control Over Financial Reporting Report of Independent Registered Public Accounting Firm Consolidated Statements of Income (Loss) Consolidated Statements of Comprehensive Income (Loss) Consolidated Balance Sheets Consolidated Statements of Changes in Equity Consolidated Statements of Cash Flows Notes to Consolidated Financial Statements Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Item 9A. Controls and Procedures Item 9B. Other Information Part III Item 10. Directors, Executive Officers and Corporate Governance Item 11. Executive Compensation Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13. Certain Relationships and Related Transactions, and Director Independence Item 14. Principal Accounting Fees and Services Item 15. Exhibits and Financial Statement Schedules Signatures Part IV 1 Page 2 9 17 17 17 20 21 23 24 42 44 44 45 46 47 48 49 50 51 83 83 83 84 84 84 85 85 86 92 ITEM 1. BUSINESS PART I 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 2929 Allen Parkway, Suite 2100 Houston, TX 77019-2118 Attention: Investor Relations Telephone: (713) 439-8600 ABOUT BAKER HUGHES Baker Hughes is a leading supplier of oilfield services, products, technology and systems 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 operate in more than 80 countries around the world and our corporate headquarters is in Houston, Texas. As of December 31, 2015, we had approximately 43,000 employees, of which approximately 63% work outside the United States (the “U.S.”). 2 Our global oilfield operations are organized into a number of geomarket organizations, which are combined into and report to four region presidents, who in turn report to our chief executive officer. These regions form the basis of our four geographical operating segments detailed below: North America - headquartered in Houston, Texas Latin America - headquartered in Houston, Texas Europe/Africa/Russia Caspian - headquartered in London, England Middle East/Asia Pacific - headquartered in Dubai, United Arab Emirates 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, headquartered in Houston, Texas, 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 product development, technology and marketing of innovative and reliable solutions for our customers to advance their reservoir performance. The product line technology organization also facilitates cross- product line technology development, 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 5. "Segment Information" of the Notes to Consolidated Financial Statements in Item 8 herein. HALLIBURTON 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 will acquire all outstanding shares of Baker Hughes in a stock and cash transaction (the "Merger"). Under the terms of the Merger Agreement, each share of common stock of Baker Hughes will be converted into the right to receive 1.12 Halliburton shares plus $19.00 in cash. On March 27, 2015, Halliburton's stockholders approved the proposal to issue shares of Halliburton common stock as contemplated by the Merger Agreement. In addition, Baker Hughes' stockholders adopted the Merger Agreement and thereby approved the proposed combination of the two companies. The transaction is still subject to regulatory approvals and customary closing conditions. In that regard, Baker Hughes and Halliburton have agreed to extend the period for the parties to obtain required competition approvals to April 30, 2016, as permitted under the Merger Agreement, and remain focused on completing the transaction as early as possible in 2016. However, Baker Hughes cannot predict with certainty when, or if, the pending Merger will be completed because completion of the transaction is subject to conditions beyond the control of Baker Hughes. For further information about the Merger, see Note 2. "Halliburton Merger 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. 3 • Drilling and Evaluation products and services consist of the following: • Drill Bits - includes Tricone™, PDC or “diamond”, and Kymera™ hybrid drill bits used for performance drilling, hole enlargement and coring. • Drilling Services - includes conventional and rotary steerable systems used to drill wells directionally and horizontally; measurement-while-drilling and logging-while-drilling systems used to perform reservoir navigation services; drilling optimization services; tools for coil tubing drilling and wellbore re- entry systems; coring drilling systems; and surface logging. • Wireline Services - includes tools for both open hole and cased hole well logging used to gather data to perform petrophysical and geophysical analysis; reservoir evaluation coring; casing perforation; fluid characterization; production logging; well integrity testing; pipe recovery; and seismic and microseismic services. • Drilling and Completion Fluids - includes emulsion and water-based drilling fluids systems; reservoir drill-in fluids; and fluids environmental services. • 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 sand control systems; liner hangers; wellbore isolation; expandable tubulars; multilaterals; safety systems; packers and flow control; and tubing conveyed perforating. • Wellbore Intervention - includes products and services used in existing wellbores to improve their performance including thru-tubing fishing; thru-tubing inflatables; conventional fishing; casing exit systems; production injection packers; remedial and stimulation tools; and wellbore cleanup. Intelligent Production Systems - includes products and services used to monitor and dynamically control the production from individual wells or fields including production decisions services; chemical injection services; well monitoring services; intelligent well systems; and artificial lift monitoring. • • Artificial Lift - includes electric submersible pump systems; progressing cavity pump systems; gas lift systems; and surface horizontal pumping systems used to lift large volumes of oil and water when a reservoir is no longer able to flow on its own. • Upstream Chemicals - includes chemicals and chemical application systems to provide flow assurance, integrity management and production management for upstream hydrocarbon production. • Pressure Pumping - includes cementing, stimulation, including hydraulic fracturing, and coil tubing services used in the completion of new oil and natural gas wells and in remedial work on existing wells, both onshore and offshore. Hydraulic fracturing is the practice of pumping fluid through a wellbore at pressures and rates sufficient to crack rock in the target formation, extend the cracks, and leave behind a propping agent to keep the cracks open after pumping ceases. The purpose of the cracks is to provide a pathway that allows for the passage of hydrocarbons from the rock to the wellbore, thus improving the production of hydrocarbons to the surface. 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. Downstream chemicals provides products and services that help to increase refinery production, as 4 well as improve plant safety and equipment reliability. Process and pipeline services works to improve efficiency and reduce downtime with inspection, pre-commissioning and commissioning of new and existing pipeline systems and process plants. MARKETING, 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 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 self-insured retention amounts for which we are 5 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, 2015, 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 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. 6 EMPLOYEES As of December 31, 2015, we had approximately 43,000 employees, of which the majority are outside the U.S. Less than 10% of these employees are represented under collective bargaining agreements or similar-type labor arrangements. EXECUTIVE OFFICERS OF BAKER HUGHES INCORPORATED The following table shows, as of February 16, 2016, 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 Martin S. Craighead Age 56 Kimberly A. Ross 50 Belgacem Chariag 53 Alan R. Crain 64 Archana Deskus 50 Andrew C. Esparza 57 Alan J. Keifer William D. Marsh Jay G. Martin Derek Mathieson 61 53 64 45 Background 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. 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 (formerly ACE Limited). Employed by the Company in October 2014. Chief Integration Officer since December 2014. 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. Senior Vice President, Chief Legal and Governance Officer of the Company since 2013. Senior Vice President and General Counsel of the Company from 2007 to 2013. Vice President and General Counsel of the Company from 2000 to 2007. Employed by the Company in 2000. 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. Chief Human Resources Officer since January 2015. Former Chief Human Resources Officer for Dell from 2007 to 2010. Various other human resources roles at Dell between 1997 and 2010. Employed by the Company in 2015. Vice President and Controller of the Company since 1999. Western Hemisphere Controller of Baker Oil Tools from 1997 to 1999 and Director of Corporate Audit for the Company from 1990 to 1996. Employed by the Company in 1990. 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. 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. Chief Technology and Marketing Officer of the Company since September 2015. 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. 7 Khaled Nouh 48 Arthur L. Soucy 53 Richard Ward 47 Richard L. Williams 60 President, Middle East and Asia Pacific Region of the Company since October 2013. President, Middle East Region of the Company from 2009 to 2013. Vice President Integrated Project Management Middle East at Schlumberger from 2008 to 2009. Various other positions at Schlumberger from 1994 to 2008. Employed by the Company in 2009. President, Europe, Africa and Russia Caspian Region of the Company since 2013. 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. President, Global Products and Services of the Company since December 2014. President of Completions and Wellbore Intervention of the Company from October 2013 until December 2014, President, Completions and Production from June 2012 until October 2013, Region President for Asia Pacific from 2009 to 2012, Vice President for Baker Oil Tools in the Middle East Asia Pacific region from 2007 to 2009. Various positions within the Company from 1991 to 2007. Employed by the Company in 1991. President, North America Region of the Company since October 2013. President, U.S. Region from November 2012 to October 2013 and President, Gulf of Mexico Region from 2009 to 2012. Various executive positions within the Company from 1975 to 2009. Employed by the Company in 1975. 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, 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. 8 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 is $35 million and $35 million, which includes accruals of $2 million and $3 million for the various Superfund sites, at December 31, 2015 and 2014, respectively. We are subject to various other governmental proceedings and regulations, including foreign regulations, relating to environmental matters, but we do not believe that any of these matters 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. 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. 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 9 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. Over the past year oil prices have declined significantly due in large part to increasing supplies, weakening demand growth and OPEC's position to not cut production. Expectations about future prices and price volatility are important for determining future spending levels. Lower oil and natural gas prices generally lead to decreased spending by our customers. While higher oil and natural gas prices generally lead to increased spending by our customers, sustained high energy prices can be an impediment to economic growth, and can therefore negatively impact spending by our customers. Our customers also take into account the volatility of energy prices and other risk factors by requiring higher returns for individual projects if there is higher perceived risk. Any of these factors could affect the demand for oil and natural gas and could have a material 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 economically attractive projects based upon their expectations of future energy prices, required investments and resulting returns. Limited access to external sources of funding has and may continue to cause customers to reduce their capital spending plans to levels supported by internally-generated cash flow. In addition, a reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities or the lack of 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. 10 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 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 or other changes occur such as a decline in our stock price, we may have to make further impairments of our assets or 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. 11 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 have operations in the U.S. and in more than 80 countries that can be impacted by expected and unexpected changes in the legal and business environments in which we operate. Compliance related issues could 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. 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. 12 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. 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 certain of our wellsite equipment and operations. In addition, the U.S. government has proposed rules setting GHG emission standards for the oil and natural gas industry. We are unable to predict whether the proposed changes in laws or regulations will ultimately occur or what they will ultimately require, and accordingly, we are unable to assess the potential financial or operational impact they may have on our business. 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; the United Kingdom's Carbon Reduction Commitment which affects more than 40 Baker Hughes facilities; and, in the U.S., the Regional Greenhouse Gas Initiative, the Western Regional Climate Action Initiative, and various state programs implementing California Assembly Bill 32. 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. 13 Demand for pressure pumping services could be reduced or eliminated by governmental regulation or a change in the law. Some federal, state and foreign governmental bodies have adopted laws and regulations or are considering legislative and regulatory proposals that, if signed into law, would among other things require the public disclosure of chemicals used in well stimulation (including hydraulic fracturing) operations in more detail than the Company currently provides and would subject well stimulation (including hydraulic fracturing) to more stringent regulation with respect to, for example, construction standards for wells intended for hydraulic fracturing, certifications concerning the conduct of well stimulation (including hydraulic fracturing) operations, management of flowback waters from well stimulation (including hydraulic fracturing) operations, or other measures intended to prevent operational hazards. Such federal, state or foreign legislation and/or regulations could impair our operations, increase our operating costs, and/or greatly reduce or eliminate demand for the Company’s well stimulation (including hydraulic fracturing) services. The EPA and other governmental bodies are studying well stimulation (including hydraulic fracturing) operations. Government actions relating to the development of unconventional oil and natural gas resources may impede the development of these resources by our customers, delaying or reducing the demand for our services. We are unable to predict whether the proposed changes in laws or regulations or any other governmental proposals or responses will ultimately occur, and accordingly, we are unable to assess the potential financial or operational impact they may have on our business. 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. 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 14 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. The Company has a significant concentration of its business in North America. For the year ended December 31, 2015, over one-third of our revenue was attributable to North America compared to approximately one-half of our revenue attributable to North America for the year ended December 31, 2014. In North America, a decrease in demand for energy or in oil and natural gas exploration and production, or an increase in competition could result in a significant adverse effect on our operating results. 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, 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, and the downsizing of our presence in select markets. 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. Risk Factors Related to the Pending Merger with Halliburton Our expectations regarding our business may be impacted by the following risk factors related to the pending Merger with Halliburton: The pendency of our Merger with Halliburton could adversely affect our business. In connection with our pending Merger with Halliburton, 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 Merger is completed. We have agreed in the Merger Agreement to refrain from taking certain actions with respect to our business and financial affairs during the pendency of the Merger, which restrictions could be in place for an extended period of time if completion of the Merger is delayed and could adversely impact our financial condition, results of operations or cash flows. The process of seeking to accomplish the Merger could also divert the focus of our management from pursuing other opportunities that could be beneficial to us. We may be unable to attract and retain key employees during the pendency of our Merger with Halliburton. In connection with our pending Merger with Halliburton, current and prospective employees of Baker Hughes may experience uncertainty about their future roles with the combined company following the Merger, which may materially adversely affect our ability to attract and retain key personnel during the pendency of the Merger. Key 15 employees may depart because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company following the Merger. The ability of Baker Hughes and Halliburton to complete the Merger is subject to various closing conditions, including the receipt of consents and approvals from governmental authorities, which may impose conditions that could adversely affect Baker Hughes or cause the Merger to be abandoned. Each of Baker Hughes and Halliburton must make certain filings with and obtain certain other approvals and consents from various federal and state governmental and regulatory authorities. Baker Hughes and Halliburton have not yet obtained the regulatory clearances, consents and approvals required to complete the Merger. Governmental or regulatory agencies could seek to block or challenge the Merger or could impose restrictions they deem necessary or desirable in the public interest as a condition to approving the Merger. Baker Hughes and Halliburton will be unable to complete the Merger until approvals are received from the U.S. Department of Justice, the European Commission and various other governmental authorities. Regulatory authorities may impose certain requirements or obligations as conditions for their approval. The Merger Agreement may require Baker Hughes and/or Halliburton to accept conditions from these regulators that could adversely impact the combined company. If review by the relevant competition authorities extends beyond April 30, 2016, the Merger Agreement does not terminate automatically; the parties may continue to seek relevant competition approvals or either of the parties may terminate the Merger Agreement. Additionally, even after the statutory waiting period under the antitrust laws and even after completion of the Merger, governmental authorities could seek to block or challenge the Merger as they deem necessary or desirable in the public interest. In addition, in some jurisdictions, a competitor, customer or other third party could initiate a private action under the antitrust laws challenging or seeking to enjoin the Merger, before or after it is completed. Baker Hughes or Halliburton may not prevail and may incur significant costs in defending or settling any action under the antitrust laws. Failure to complete our Merger with Halliburton could negatively affect our stock price and our future business and financial results. If our Merger with Halliburton is not completed, our ongoing business may be adversely affected and will be subject to several risks, including the following: • • • • • the attention of our management may have been diverted to the Merger 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; having to pay certain significant costs relating to the Merger without receiving the benefits of the Merger; the trading price of Baker Hughes common stock may decline to the extent that the current trading price reflects a market assumption that the Merger will be completed; and the Company could be subject to litigation from shareholders related to the Merger Agreement. Following our Merger with Halliburton, the combined company may encounter difficulties in integrating the businesses of Baker Hughes and Halliburton and realizing the anticipated benefits of the Merger. The Merger involves the combination of two companies that currently operate as independent public companies. The combined company will be required to devote management attention and resources to integrating its business practices and operations, and prior to the Merger, management attention and resources will be required to plan for such integration. Potential difficulties the combined company may encounter in the integration process include the following: • the inability to successfully integrate the respective businesses of Baker Hughes and Halliburton in a manner that permits the combined company to achieve the cost savings and operating synergies anticipated to result from the Merger, which could result in the anticipated benefits of the Merger not being realized partly or wholly in the time frame currently anticipated or at all; 16 • • • • lost sales and customers as a result of certain customers of either or both of the two companies deciding not to do business with the combined company, or deciding to decrease their amount of business in order to reduce their reliance on a single company; integrating personnel from the two companies while maintaining focus on providing consistent, high quality products and services; potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated with the Merger; and performance shortfalls at one or both of the two companies as a result of the diversion of management’s attention caused by completing the Merger and integrating the companies’ operations. 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: North America: Houston, Pasadena, Tomball, and The Woodlands, Texas; Broken Arrow, Claremore, Tulsa and Sand Springs, Oklahoma; Bossier City, Broussard, and Lafayette, Louisiana - all located in the United States; Leduc, Canada Europe/Africa/Russia Caspian: Aberdeen, Scotland; Liverpool, England; Celle, Germany; Tananger, Norway; Middle East/Asia Pacific: Port Harcourt, Nigeria; Luanda, Angola; Tyumen and Novosibirsk, Russia Dubai, United Arab Emirates; Dhahran, Saudi Arabia; Singapore, Singapore; Chonburi, Thailand Principal properties for the Industrial Services segment include locations in Pasadena, Texas; Sand Springs and Barnsdall, Oklahoma; Taft, California; and Liverpool, England. We own or lease numerous other facilities such as service centers, 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. 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. 17 The following lawsuits have been filed in Delaware in connection with our pending Merger with Halliburton: • 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 Annettee 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. 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 remains subject to certain conditions, including consummation of the Merger, final documentation, and court approval. On November 26, 2014, a seventh class action challenging the Merger was filed by a purported shareholder of the Company in the United States District Court for the Southern District of Texas (Houston Division). The lawsuit, styled Marc Rovner v. Baker Hughes Inc., et al., Cause No. 4:14-cv-03416 (the "Rovner lawsuit"), asserts claims against the Company, most of our current Board of Directors, Halliburton, and Red Tiger. The lawsuit asserts substantially similar claims and seeks substantially similar relief as that sought in the Delaware lawsuits. On March 20, 2015, counsel for Mr. Rovner filed a notice of voluntary dismissal, and on March 23, 2015, the Court entered an order dismissing the Rovner lawsuit without prejudice. On October 9, 2014, our subsidiary 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. The due date for payment of all of these invoices has passed. On November 6, 2014, the customer filed its Response and Counterclaim, denying liability and counterclaiming damages for breach of contract of approximately $182 million. We deny any liability to the customer and intend to pursue our claims against the customer and defend the claims made under the counterclaim. The Parties have applied to the arbitration tribunal to extend the suspension of the arbitral proceedings to March 31, 2016, pending ongoing settlement discussions. No timetable for the conduct of the arbitration has yet been established. 18 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). The customer alleges damages of approximately $170 million plus interest at an annual rate of prime + 5%. A procedural schedule for the arbitration has not yet been set. 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. On December 15, 2015, the District Court entered an order staying the lawsuit in favor of the pending German Arbitration. At this time, we are not able to predict the outcome of these claims or whether either will have a 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 has 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. Investigation is ongoing as to the merits of the claim. At this time, we are not able to predict the outcome of this claim or whether it will 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 alleges that the Company failed to purchase the required sand tonnage for the contract year 2014-2015 and further alleges that the Company repudiated its yearly purchase obligations over the remaining contract term. The Claimant alleges damages of approximately $110 million plus interest, attorneys’ fees and costs. A procedural schedule for the arbitration has not yet been set. The Company intends to vigorously defend the claim. At this time, we are not able to predict the outcome of this claim or whether it will have a material impact on our financial position, results of operations or cash flows. During the second quarter of 2014, we recorded a charge of $62 million related to previously disclosed litigation settlements for wage and hour lawsuits. A portion of this settlement was to be paid on a claims made basis and during the second quarter of 2015, the date passed by which the class members could file a claim under this provision of the settlement agreement. The amount of claims made was less than estimated and, accordingly, we reduced the accrual by approximately $13 million, which was recorded as an adjustment for litigation settlements during the second quarter of 2015. 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. We are evaluating the background facts and at this time are not able to predict the outcome of this lawsuit or whether it will have a material impact 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 LLC and Packers Plus Energy Services Inc., sued Baker Hughes Canada Company in the Canada Federal Court on related Canadian patent 2,412,072. These patents relate primarily to certain specific downhole completions equipment. The case is set for a jury trial on September 25, 2017, in Tyler, Texas. 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. At this time, we are not able to predict the outcome of these claims or whether either will have a material impact on our financial position, results of operations or cash flows. 19 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 seeks 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. We are working with the DOJ to provide the requested documents and information. We are not able to predict what action, if any, might be taken in the future by the DOJ or other governmental authorities as a result of the investigation. 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. 20 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 February 10, 2016, there were approximately 9,275 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, 2015, and information regarding dividends declared on our common stock during the two years ended December 31, 2015, see Note 16. "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 2015. Issuer Purchases of Equity Securities Period October 1-31, 2015 November 1-30, 2015 December 1-31, 2015 Total Total Number of Shares Purchased (1) 5,149 Average Price Paid Per Share (1) 54.87 $ — 57 5,206 $ — 53.17 54.86 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 (2) $ $ $ 1,049,832,435 1,049,832,435 1,049,832,435 (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 2015 under our previously announced purchase program. Under the Merger Agreement with Halliburton, as described in Note 2. "Halliburton Merger Agreement" of the Notes to Consolidated Financial Statements in Item 8 herein, we have generally agreed not to repurchase any shares of our common stock while the Merger is pending. 21 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 2010 2011 2012 2013 2014 2015 Baker Hughes S&P 500 Index $100.00 $ 85.97 $ 73.23 $100.29 $102.78 $ 85.64 180.51 156.64 178.00 102.12 118.39 100.00 S&P 500 Oil and Gas Equipment and Services Index 100.00 88.38 88.41 115.50 106.47 86.64 * 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, 2010 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. 22 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. (In millions, except per share amounts) Revenue Operating (loss) income (1,2) Non-operating expense, net (Loss) income before income taxes Income taxes (3) Net (loss) income Net loss (income) attributable to noncontrolling interests Year Ended December 31, 2015 $ 15,742 2014 $ 24,551 2013 $ 22,364 2012 $ 21,361 2011 $ 19,831 (2,396) (217) (2,613) 639 (1,974) 7 2,859 (232) 2,627 (896) 1,731 (12) 1,949 (234) 1,715 (612) 1,103 (7) 2,192 (210) 1,982 (665) 1,317 (6) 2,600 (261) 2,339 (596) 1,743 (4) Net (loss) income attributable to Baker Hughes $ (1,967) $ 1,719 $ 1,096 $ 1,311 $ 1,739 Per share of common stock: Net (loss) income attributable to Baker Hughes: Basic Diluted Dividends Balance Sheet Data: $ (4.49) $ (4.49) 0.68 3.93 3.92 0.64 $ 2.47 2.47 0.60 $ 2.98 2.97 0.60 $ 3.99 3.97 0.60 Cash, cash equivalents and short-term investments $ 2,324 $ 1,740 $ 1,399 $ 1,015 $ 1,050 Working capital (current assets minus current liabilities) Total assets Long-term debt Total equity Notes To Selected Financial Data 6,493 24,080 3,890 16,382 7,408 28,827 3,913 18,730 6,717 27,934 3,882 17,912 6,293 26,689 3,837 17,268 6,295 24,847 3,845 15,964 (1) Operating income for 2015 includes impairment and restructuring charges of $1,993 million before-tax ($1,415 million after-tax) associated with asset impairments, workforce reductions, facility closures and contract terminations. See Note 3. "Impairment and Restructuring Charges" of the Notes to Consolidated Financial Statements in Item 8 herein. (2) Operating income for 2011 includes a charge of $315 million before-tax ($220 million net of tax), the majority of which relates to the impairment associated with the decision to minimize the use of the BJ Services trade name. Income taxes for 2011 include a tax benefit of $214 million associated with the reorganization of certain foreign subsidiaries. (3) 23 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 use 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, 2015, Baker Hughes had approximately 43,000 employees compared to approximately 62,000 employees as of December 31, 2014. 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. 2015 was an extremely challenging year for the oil and natural gas industry. Crude oil prices declined significantly in the fourth quarter of 2014 and experienced significant volatility in 2015, reaching a seven year low in December 2015 following OPEC's decision to eliminate its oil production ceiling. In response to the lower commodity prices in 2015, our customers curtailed their spending by reducing drilling activity in less economical unconventional plays and delaying well completion activities. As a result of these changes in market conditions and the significant decrease in activity and customer spending, we experienced a significant decline in demand and increased pricing pressure for our products and services. For 2015, we generated revenue of $15.74 billion, a decrease of $8.81 billion, or 36%, compared to 2014. Net loss attributable to Baker Hughes was $1.97 billion for 2015 compared to net income attributable to Baker Hughes of $1.72 billion for 2014. The steep decline in activity, as evidenced by the 46% decline in the global rig count since the fourth quarter of 2014, and price deterioration experienced across all our segments is a large driver for the decline in revenue and profitability, most notably in North America. Beginning in the first quarter of 2015, we initiated actions 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 $830 million in 2015, which included workforce reductions, contract terminations, facility closures and the write-down of excess machinery and equipment. In 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 $1.16 billion. These charges have been excluded from the results of our operating segments. In 2016, crude oil prices have continued to decline, reaching a twelve-year low in the first quarter. Although our visibility remains limited, we are expecting rig activity worldwide to continue to decline throughout the year and pricing pressures to continue across the globe. At current commodity prices, the global rig count could decline as much as 30% in 2016, as our customers’ challenges of maximizing production, lowering their overall costs, and protecting cash flows are now more acute. Our products and services put us in an excellent position to help our customers achieve their business objectives and to capitalize on opportunities to continue to convert our capabilities into earnings. While targeting these opportunities, we remain focused on generating positive cash flow by proactively managing our cost structure, reducing our working capital, and maximizing return on invested capital. 24 Halliburton Merger Agreement On November 16, 2014, Baker Hughes and Halliburton entered into a definitive agreement and plan of Merger under which Halliburton will acquire all outstanding shares of Baker Hughes in a stock and cash transaction. Under the terms of the Merger Agreement, each share of common stock of Baker Hughes will be converted into the right to receive 1.12 Halliburton shares plus $19.00 in cash. On March 27, 2015, Halliburton's stockholders approved the proposal to issue shares of Halliburton common stock as contemplated by the Merger Agreement. In addition, Baker Hughes' stockholders adopted the Merger Agreement and thereby approved the proposed combination of the two companies. The transaction is still subject to regulatory approvals and customary closing conditions. In that regard, Baker Hughes and Halliburton have agreed to extend the period for the parties to obtain required competition approvals to April 30, 2016, as permitted under the Merger Agreement, and remain focused on completing the transaction as early as possible in 2016. However, Baker Hughes cannot predict with certainty when, or if, the pending Merger will be completed because completion of the transaction is subject to conditions beyond the control of Baker Hughes. For further information about the Merger, see Note 2. "Halliburton Merger Agreement" of the Notes to Consolidated Financial Statements in Item 8 herein. BUSINESS ENVIRONMENT We operate 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. Brent oil prices ($/Bbl) (1) WTI oil prices ($/Bbl) (2) Natural gas prices ($/mmBtu) (3) 2015 2014 $ 52.31 $ 98.88 48.68 2.61 93.03 4.35 2013 $ 108.81 97.98 3.73 (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 high of $66.37/Bbl in May 2015 to a low of $34.78/Bbl in December 2015. Oil prices started to decline at the end of 2014 and continued to be volatile throughout the first half of 2015 as the market experienced a significant over supply of capacity. In the second half of 2015, and continuing into the first quarter of 2016, oil prices began to steadily decline again as rapidly increasing production, primarily from OPEC countries, coupled with unfavorable economic data from Europe and Asia, reignited fears of a long-term market imbalance. OPEC's decision in the fourth quarter to eliminate its official oil production ceiling, despite lower oil prices, put additional downward pressure on price expectations, and as a result, Brent oil prices approached seven-year lows and exited 2015 reflecting a 46% reduction compared to the peak earlier in the year. 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 in the second quarter. Overall, WTI oil prices ranged from a high of $61.43/Bbl in June 2015 to a low of $34.73/Bbl in December 2015. 25 In North America, natural gas prices, as measured by the Henry Hub Natural Gas Spot Price, averaged $2.61/ mmBtu in 2015, representing a 40% decrease over the prior year and the lowest annual average since 1999. Natural gas prices began 2015 supported by a colder than normal winter but fell throughout the year as production and storage inventories hit record levels despite a significant decline in the natural gas-directed rig count. In the fourth quarter of 2015, above average temperatures and forecasts of a warmer winter in the U.S. drove natural gas prices to further decline reaching a low of $1.53/mmBtu in December. According to the U.S. Department of Energy (“DOE”), working natural gas in storage at the end of 2015 was 3,756 billion cubic feet ("Bcf"), which was 16.7%, or 536 Bcf, above the corresponding week in 2014. 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 governed 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 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/or other outside sources. 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, or 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. U.S. - onshore U.S. - offshore Canada North America Latin America North Sea Continental Europe Africa Middle East Asia Pacific Outside North America Worldwide 2015 2014 2013 948 36 194 1,178 319 37 80 106 406 220 1,168 2,346 1,804 57 379 2,240 397 40 105 134 406 254 1,336 3,576 1,705 56 353 2,114 419 42 93 125 372 246 1,297 3,411 26 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. 2014 Compared to 2013 The rig count in North America increased 6% in 2014 compared to 2013 primarily driven by a 9% growth in oil- directed rigs. The oil-directed rig count increased 11% in the U.S. as a result of increased exploration and production spending, but decreased by 6% in Canada where many operators curtailed their oil-directed drilling plans in the second half of 2014 due to high oil price differentials as compared to WTI and wet weather in southern Alberta and Saskatchewan. The natural gas-directed rig count in North America declined 2% reflecting a 13% decrease in the U.S. partially offset by a 34% increase in Canada. Natural gas-directed drilling in the U.S. was negatively impacted by the continued weakness in North America natural gas prices which discouraged new investment in natural gas fields. In Canada, the increase in natural gas-directed rigs was driven by drilling in condensate rich zones in Alberta to service the oil sands drilling activity. Overall, Canada rig counts increased 7% in 2014 compared to 2013. Outside North America, the rig count increased 3% in 2014 compared to 2013. The rig count in Latin America decreased 5% as a result of reduced rig activity in Brazil and Mexico, partially offset by an increase in activity in the emerging unconventional plays in Argentina. The North Sea rig count decreased by 5%, primarily due to a decline in the rig activity in Norway. The rig count in Continental Europe increased by 13% with higher activity in Turkey and Romania. In Africa, the rig count increased 7% primarily due to higher activity in Kenya, Angola, and Chad. The rig count increased 9% in the Middle East due to higher activity in Saudi Arabia, Oman and Kuwait, slightly offset by a reduction in Iraq due to political unrest. The rig count in Asia Pacific increased 3% due to increased activity in offshore China, partially offset by activity reduction in Indonesia, Malaysia 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. 27 Revenue and Profit Before Tax Revenue and profit (loss) before tax for each of our five operating segments is provided below. The performance of our operating segments is evaluated based on profit or loss before tax, which is defined as income or loss before income taxes and before the following: net interest expense, corporate expenses, and certain gains and losses, including impairment and restructuring charges, not allocated to the operating segments. 2015 Compared to 2014 Revenue: North America Latin America Europe/Africa/Russia Caspian Middle East/Asia Pacific Industrial Services Total Profit (Loss) Before Tax: North America Latin America Europe/Africa/Russia Caspian Middle East/Asia Pacific Industrial Services Total Operations Corporate and other Total North America Year Ended December 31, 2015 2014 $ Change % Change 6,009 1,799 3,278 3,441 1,215 15,742 $ $ 12,078 2,236 4,417 4,456 1,364 24,551 $ $ (6,069) (437) (1,139) (1,015) (149) (8,809) (50)% (20)% (26)% (23)% (11)% (36)% Year Ended December 31, 2015 2014 $ Change % Change (687) 134 157 204 97 (95) (2,518) (2,613) $ 1,466 $ (2,153) 290 621 675 119 3,171 (544) 2,627 $ (156) (464) (471) (22) (3,266) (1,974) (5,240) $ (147)% (54)% (75)% (70)% (18)% (103)% 363 % (199)% $ $ $ $ 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 loss before tax was $687 million in 2015, a decrease of $2.15 billion, or 147%, compared to 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 28 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 profit before tax decreased $156 million, or 54%, 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. Europe/Africa/Russia Caspian (“EARC”) 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 profit before tax decreased $464 million, or 75%, 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. The unfavorable change in foreign exchange rates in 2015 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”) 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 profit before tax decreased $471 million, or 70%, 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 profit before tax decreased 18% 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. 29 2014 Compared to 2013 Revenue: North America Latin America Europe/Africa/Russia Caspian Middle East/Asia Pacific Industrial Services Total Profit Before Tax: North America Latin America Europe/Africa/Russia Caspian Middle East/Asia Pacific Industrial Services Total Operations Corporate and other Total North America Year Ended December 31, 2014 2013 $ Change % Change $ $ 12,078 2,236 4,417 4,456 1,364 24,551 $ $ 10,878 2,307 4,041 3,859 1,279 22,364 $ $ 1,200 (71) 376 597 85 2,187 11 % (3)% 9 % 15 % 7 % 10 % Year Ended December 31, 2014 2013 $ Change % Change $ 1,466 $ 290 621 675 119 3,171 (544) $ 968 66 591 457 135 2,217 (502) $ 2,627 $ 1,715 $ 498 224 30 218 (16) 954 (42) 912 51 % 339 % 5 % 48 % (12)% 43 % 8 % 53 % North America revenue in 2014 increased $1.2 billion or 11% compared to 2013, with rig counts increasing 6% from the prior year average. The increase in revenue was driven almost entirely by our U.S. onshore operations, where higher activity levels, improved utilization and market conditions in pressure pumping, along with increased demand for new technologies in the unconventional plays contributed to solid growth across all our districts and product lines. The largest contributor to the revenue growth was our pressure pumping operations, where market conditions gradually improved during the year, reversing the over supply of hydraulic fracturing equipment; which, when combined with our multi-year improvement initiative for this product line, resulted in improved utilization and increased efficiencies. Our artificial lift, drilling services and drill bit product lines also delivered exceptionally strong growth, as demand increased for our new technologies specifically designed for the unconventional plays. Revenue in Canada declined in 2014 as compared to 2013, in part due to a 6% decline in the oil-directed rig count, which is a significant driver of our operations in the country. Revenue in the Gulf of Mexico declined slightly despite a relatively flat rig count in 2014 compared to 2013. The revenue decline is attributable to activity delays, primarily in drilling and stimulation, that resulted from unusually strong ocean currents in the second half of 2014. North America profit before tax was $1,466 million in 2014, an increase of $498 million or 51% compared to 2013. In addition to the strong activity levels in U.S. onshore, increased profitability was driven by improved contractual terms and utilization in our pressure pumping operations, as well as other efficiency gains and cost savings recognized as part of our pressure pumping profit improvement plan. The growing demand for new technologies, which command a higher premium, also contributed to the improvement. In the Gulf of Mexico, profitability improved, despite the decline in revenue, as a result of a more favorable mix of revenue with an increase in deepwater completion systems. In Canada, profitability decreased in line with the revenue decline, as costs savings achieved in pressure pumping were offset by the foreign exchange impact of the weakening Canadian dollar. Profitability in 2014 was negatively impacted by $29 million of severance costs and $13 million of costs associated with a technology royalty agreement. 30 Latin America Latin America revenue decreased $71 million or 3% in 2014 compared to 2013. Revenue reductions in Brazil and Venezuela were partially offset by increased revenue throughout the rest of the region. Revenue declined across most product lines in Brazil due to lower activity levels in 2014, as evidenced by a 27% reduction in the rig count compared to 2013. Revenue in Venezuela decreased across all product lines as a result of the devaluation of the Bolivares Fuertes relative to the U.S. Dollar Latin America profit before tax increased $224 million or 339% in 2014 compared to 2013. The significant improvement in profitability can be primarily attributed to cost reduction strategies implemented throughout the region in the second half of 2013, with particular focus on Brazil. 2013 includes a charge of $19 million for severance related to these actions. Increased activity in Argentina, Mexico and Ecuador also contributed to the profitability improvement in 2014. Profitability was also impacted by foreign exchange losses of $12 million and $23 million in 2014 and 2013, respectively, due to the currency devaluation in Venezuela. Europe/Africa/Russia Caspian EARC revenue increased $376 million or 9% in 2014 compared to 2013. In 2014, we delivered strong revenue growth in Africa, Continental Europe and Russia Caspian. Revenue was negatively impacted by the unfavorable change in exchange rates of several currencies including the Russian Ruble relative to the U.S. Dollar. In Africa, revenue increased as a result of activity growth and share gains across most of the region, predominately in West Africa. These increases were slightly offset by activity declines in Libya due to political instability during the third quarter of 2014. In Continental Europe, revenue growth was driven by increased demand for our completion and production product lines. In the Russia Caspian region, revenue growth was driven by increased activity in our completion and production product lines. EARC profit before tax increased $30 million or 5% in 2014 compared to 2013. Incremental profitability growth from increased revenue was almost entirely offset by a $58 million charge associated with the restructuring of our operations in North Africa and impairment of certain assets, mainly due to the recent disruption in our operations in Libya. Profitability was also negatively impacted by foreign exchange losses as a result of the devaluation of several currencies, including the Russian Ruble. Middle East/Asia Pacific MEAP revenue increased $597 million or 15% in 2014 compared to 2013, while the corresponding rig count increased only 7% over the same period. We posted strong revenue growth in virtually all geographies, most notably in Saudi Arabia, Iraq, the Arabian Gulf, Southeast Asia and China. In Saudi Arabia, revenue increases were primarily related to activity growth in our integrated operations contracts. In addition, we experienced strong demand for our drilling services and completion services product lines. In Iraq, revenue increased in 2014 over the prior year, as 2013 was negatively impacted by a significant disruption in operations in the fourth quarter partially offset by a decline in activity in 2014 due to a demobilization on a major contract. Revenue increased in the Arabian Gulf due to increased demand for our drilling services and pressure pumping product lines in the United Arab Emirates and India. Within Asia Pacific, revenue growth was strongest in South East Asia and China, predominately in our drilling services product line. MEAP profit before tax improved $218 million or 48% in 2014 compared to 2013. The primary driver of the increase in profit before tax was higher incremental profit on increased revenue across the segment, most notably in Saudi Arabia and Iraq. Further, we experienced a favorable shift in product mix with a higher proportion of revenue derived from our drilling services product line. Profit before tax in 2013 was negatively impacted by $79 million of losses in Iraq related to the significant disruption to our operations, expenses associated with personnel movements and security measures, and other non-recurring items. Industrial Services Industrial Services revenue increased 7% and profit before tax decreased 12% in 2014 compared to 2013. The increase in revenue was primarily driven by the acquisition of a complementary pipeline services business in the 31 third quarter of 2014. Profitability in the segment decreased as a result of integration expenses related to this acquisition, along with an increase in environmental costs compared to the prior year. Costs and Expenses The table below details certain data from our consolidated statements of income (loss) and as a percentage of revenue. Revenue Cost of revenue Research and engineering Marketing, general and administrative Cost of Revenue 2015 2014 2013 $ $ 15,742 14,502 483 1,173 % 100% $ 24,551 $ % 100% $ 22,364 $ 92% 3% 7% 19,746 613 1,271 80% 2% 5% 18,553 556 1,306 % 100% 83% 2% 6% 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. 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 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 2015. 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, and $87 million of expenses related to the Merger. Cost of revenue as a percentage of revenue was 80% and 83% for 2014 and 2013, respectively. The improvement in cost of revenue as a percentage of revenue was due primarily to the continued improvement in our U.S. onshore pressure pumping business, which resulted in higher asset utilization and organizational efficiencies, as well as improved contractual terms. In Latin America, margins improved due to cost reduction strategies implemented throughout the region in the second half of 2013. Margins in the MEAP segment were improved by higher incremental profit on increased revenue, combined with a favorable shift in product mix. Reduced disruptions in our Iraq operations for 2014 also contributed to lower cost of revenue in the MEAP segment. In the EARC segment, profitability increased in Continental Europe, the United Kingdom and most of Africa but were partially offset by restructuring charges of $58 million associated with our operations in North Africa, primarily from disruptions in Libya. These improvements were partially offset by $113 million of increased depreciation expense across all segments except Latin America; $29 million of severance charges in North America; and $29 million of costs associated with a technology royalty agreement. Research and Engineering Research and engineering expenses decreased 21% in 2015 compared to 2014, yet increased slightly as a percentage of revenue. The reduction in research and engineering expense was driven by cost reduction measures, partially offset by $17 million of expenses related to the Merger. Research and engineering expenses increased 10% in 2014 compared to 2013 as we continued our commitment to invest in the research and product development required to meet our customers' need for innovative new products and emerging technologies, focusing on lowering the cost of well construction, optimizing well production and increasing ultimate recoveries. As a result of our research and development activities in 2014, we commercially launched over 160 new products and services. 32 Marketing, General and Administrative Marketing, general and administrative (“MG&A”) expenses decreased 8% in 2015 compared to 2014. The reduction in MG&A costs is mainly a result of workforce reductions and lower discretionary spending. Included in MG&A expenses for 2015 are costs of $191 million related to the Merger, which partially offset the impact of the cost reduction measures. MG&A expenses decreased 3% in 2014 compared to 2013. MG&A expenses in 2014 includes a net gain of $34 million recognized on the deconsolidation of a jointly owned legal entity. Cost savings experienced across the organization were mostly offset by a charge of $14 million related to the impairment of a technology investment and $11 million of Merger related expenses. Also included in MG&A in 2014 and 2013 are foreign exchange losses of $12 million and $23 million, respectively, due to the currency devaluation in Venezuela. Impairment and Restructuring Charges During 2015, we recorded 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 3. “Impairment and Restructuring Charges” of the Notes to Financial Statements in Item 8 herein. The reduction in costs from eliminating depreciation and reduced employee expenses in 2015 was approximately $700 million and is expected to be more than $1.6 billion on an annualized basis in 2016. Litigation Settlement During the second quarter of 2014, we recorded a charge of $62 million related to previously disclosed litigation settlements for wage and hour lawsuits. A portion of this settlement was to be paid on a claims made basis and during the second quarter of 2015, the date passed by which the class members could file a claim under this provision of the settlement agreement. The amount of claims made was less than estimated and, accordingly, we reduced the accrual by approximately $13 million, which was recorded as an adjustment for litigation settlements during the second quarter of 2015. Interest Expense, Net Interest expense, net of interest income of $20 million, was $217 million in 2015, a decrease of $15 million compared to $232 million in 2014. The decrease is due primarily to lower short-term borrowings in Latin America and an increase in interest income. Interest expense, net of interest income of $13 million, remained relatively flat in 2014 when compared to $234 million in 2013. Income Taxes Total income tax benefit was $639 million in 2015 compared to income tax expense of $896 million and $612 million for 2014 and 2013, respectively. Our effective tax rate on operating profits or losses in 2015, 2014 and 2013 was 24.5%, 34.1% and 35.7%, respectively. 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. The 2013 effective tax rate is higher than the U.S. statutory income tax rate of 35% due to higher rates on certain international operations, primarily resulting from foreign losses with no tax benefit, and state income taxes partially offset by adjustments to prior years’ tax positions. 33 COMPLIANCE We do business in more than 80 countries, including approximately 16 of the 40 countries having the lowest scores in the Transparency International’s Corruption Perception Index survey for 2015, 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 process for classifying distributors. • We have continued our reduction of the use of commercial sales representatives and processing agents, including the reduction of customs agents. • 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 use technology to monitor and report on compliance matters, including a web-based antiboycott reporting tool and a global trade management software tool. • We have a program designed to encourage reporting of any ethics or compliance matter without fear of retaliation including a worldwide business helpline operated by a third party and currently available toll-free in 150 languages to ensure that our helpline is easily accessible to employees in their own language. • We have 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 third party commercial agents 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. 34 • 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, 2015, we had cash and cash equivalents of $2.32 billion, of which approximately $2.01 billion was held by foreign subsidiaries. A substantial portion of the cash held by foreign subsidiaries at December 31, 2015 was reinvested in our international operations as our intent is to use this cash to, among other things, fund the operations of our foreign subsidiaries. If we decide at a later date to repatriate those funds to the U.S., we may be required to provide taxes on certain of those funds based on applicable U.S. tax rates net of foreign 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 $2.50 billion. At December 31, 2015, we had no commercial paper outstanding; therefore, the amount available for borrowing under the credit facility as of December 31, 2015 was $2.50 billion. 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. In 2015, we used cash to pay for a variety of activities including working capital needs, capital expenditures and payment of dividends. Cash Flows Cash flows provided by (used in) each type of activity were as follows for the years ended December 31: (In millions) Operating activities Investing activities Financing activities Operating Activities 2015 2014 2013 $ 1,796 (905) (282) $ 2,953 (1,659) (939) $ 3,161 (1,663) (1,103) Cash flows from operating activities provided $1.80 billion and $2.95 billion for the years ended December 31, 2015 and 2014, respectively. Cash flows from operating activities decreased $1.16 billion in 2015 primarily due to the decrease in net income after noncash charges, partially offset by the reduction in working capital (receivables, inventories and accounts payable), which provided more cash in 2015 compared to 2014 due to lower activity levels. Additionally, the decrease in net income and market activity resulted in lower income taxes paid. Included in our cash flows from operating activities for 2015 are payments of $446 million 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 $2.95 billion and $3.16 billion for the year ended December 31, 2014 and 2013, respectively. Cash flows from operating activities decreased $208 million in 2014 primarily due to the increase in working capital, which used more cash in 2014 compared to 2013, partially offset by the increase in net income. The main drivers of the increase in working capital were due to the increase in activity levels and the continuation of vendor management initiatives, partially offset by improved collections. Additionally, the increase in net income and market activity resulted in higher income taxes paid. 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 $965 million, $1.79 billion and $2.09 billion for 2015, 2014 and 2013, respectively. The decline in capital expenditures in 2015 is a result of lower demand for our products and services. While the majority of these expenditures were for machinery and equipment, it also includes expenditures for new facilities, expansions of existing facilities and other infrastructure projects. 35 Proceeds from the disposal of assets were $388 million, $437 million and $455 million for 2015, 2014 and 2013, 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 2015, we purchased short-term and long-term investment securities totaling $310 million. In 2014, we paid $314 million for acquisitions, net of cash acquired of $7 million. Under the Merger Agreement with Halliburton, as described in Note 2. "Halliburton Merger Agreement" of the Notes to Consolidated Financial Statements in Item 8 herein, we have restrictions on our ability to acquire or dispose of any businesses while the Merger is pending. Financing Activities We had net repayments of commercial paper and other short-term debt of $45 million, $248 million and $571 million in 2015, 2014 and 2013, respectively. Total debt outstanding at December 31, 2015 was $4.04 billion, a decrease of $92 million compared to December 31, 2014. The total debt-to-capital (defined as total debt plus equity) ratio was 0.20 at December 31, 2015 and 0.18 at December 31, 2014. We received proceeds of $116 million, $216 million and $101 million in 2015, 2014 and 2013, respectively, from the issuance of common stock through the exercise of stock options and the employee stock purchase plan. Our Board of Directors has authorized a program to repurchase our common stock from time to time. During 2013, our Board of Directors increased the authorization to purchase our common stock under our share repurchase program by $800 million. During 2015, we did not repurchase any shares of common stock. We had authorization remaining to repurchase approximately $1.05 billion in common stock at the end of 2015. During 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. During 2013, we repurchased 6.3 million shares of our common stock at an average prices of $55.59 per share, for a total of $350 million. We paid dividends of $297 million, $279 million and $267 million in 2015, 2014 and 2013, respectively. Under the Merger Agreement with Halliburton, as described in Note 2. "Halliburton Merger 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 Merger is pending. Available Credit Facility As discussed above, we have a committed revolving 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. The credit facility matures in September 2016 and contains certain covenants which, among other things, restrict certain Merger transactions or the sale of all or substantially all of our assets or a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the occurrence of certain events of default, our obligations under the credit facility may be accelerated. Such events of default include payment defaults to lenders under the credit facility, 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 2015. 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, 2015, 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. 36 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 2016, 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 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 2016 will be made as appropriate at a rate that we estimate would equal $450 million to $550 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 $300 million to $350 million in 2016. For all defined benefit, defined contribution and other postretirement plans, we expect to contribute between $245 million to $275 million to these plans in 2016. See Note 13. "Employee Benefit Plans" of the Notes to Consolidated Financial Statements in Item 8 herein for further discussion. In May 2014, the Board of Directors approved a $0.02 per share increase in the quarterly cash dividend to $0.17 per share of common stock for the August 2014 holders of record over the previous quarter's dividend of $0.15 per share of common stock. We anticipate paying dividends in the range of $70 million to $78 million in the first quarter of 2016. Under the Merger Agreement with Halliburton, as described in Note 2. "Halliburton Merger Agreement" of the Notes to Consolidated Financial Statements in Item 8 herein, we have agreed not to increase the quarterly dividend while the Merger is pending. Contractual Obligations In the table below, we set forth our contractual cash obligations as of December 31, 2015. 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. (In millions) Total debt and capital lease obligations (1) Estimated interest payments (2) Operating leases (3) Purchase obligations (4) Liabilities for uncertain income tax positions (5) Other long-term liabilities Total (6) Payments Due by Period Total Less Than 1 Year 2 - 3 Years 4 - 5 Years More Than 5 Years $ 4,069 $ 151 $ 1,046 $ 34 $ 2,787 590 848 312 137 223 183 202 93 34 432 184 349 54 37 288 72 230 127 6 2,838 1,844 151 67 38 60 $ 8,743 $ 886 $ 2,102 $ 757 $ 4,998 (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 37 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 $80 million to $95 million in 2016 as the majority of these contributions are amounts in excess of minimum funding requirements and as such would not be considered a contractual obligation. 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 $1.2 billion at December 31, 2015. 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, 2015, 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, 2015 and 2014, the allowance for doubtful accounts totaled $383 million, or 11%, and $224 million, or 4%, of total gross accounts receivable, respectively. We believe that our 38 allowance for doubtful accounts is adequate to cover potential bad debt losses under current conditions; however, uncertainties regarding changes in the financial condition of our customers, either adverse or positive, could impact the amount and timing of any additional provisions for doubtful accounts that may be required. A five percent change in the allowance for doubtful accounts would have had an impact on income before income taxes of approximately $19 million in 2015. Inventory Reserves Inventory is a significant component of current assets and is stated at the lower of cost or market. This requires us to record provisions and maintain reserves for excess, slow moving and obsolete inventory. To determine these reserve amounts, we regularly review inventory quantities on hand and compare them to estimates of future product demand, market conditions, production requirements and technological developments. These estimates and forecasts inherently include uncertainties and require us to make judgments regarding potential future outcomes. At December 31, 2015 and 2014, inventory reserves totaled $278 million, or 9%, and $319 million, or 7%, of gross inventory, respectively. We believe that our reserves are adequate to properly value potential excess, slow moving and obsolete inventory under current conditions. Significant or unanticipated changes to our estimates and forecasts could impact the amount and timing of any additional provisions for excess, 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 before income taxes of approximately $14 million in 2015. 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, 2015 and 2014, totaled $6.07 billion and $6.08 billion, respectively. We perform an annual test of goodwill for impairment as of October 1 of each year for each of our reporting units which 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. In 2015 and 2014, we performed a qualitative assessment for our annual goodwill impairment test. In 2013, a quantitative assessment for the determination of impairment was made by comparing the carrying amount of each reporting unit with its fair value. In performing our annual goodwill impairment analysis for 2015, our qualitative assessment included consideration of current industry and market conditions and circumstances as well as any mitigating factors that would most affect the fair value of the Company and its reporting units. Among those mitigating factors, we considered the value of the consideration to be received at closing of the Merger, based on the terms of the Merger Agreement, compared to the carrying value of the Company and its reporting units. Based on our assessment and consideration of the totality of the facts and circumstances, including our business environment in the fourth quarter of 2015, we determined that it was not more likely than not that the fair value of the Company or any of its reporting units is less than their respective carrying amounts. As such, no impairments of goodwill were recorded for the year ended December 31, 2015, or any of the prior years included in the accompanying financial statements. 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. 39 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. Income Taxes The liability method is used for determining our income tax provisions, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In determining the need for valuation allowances, we have considered and made judgments and estimates regarding estimated future taxable income and ongoing prudent and feasible tax planning strategies. These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to adjust the valuation allowances for our deferred tax assets. Historically, changes to valuation allowances have been caused by major changes in the business cycle in certain countries and changes in local country law. The ultimate realization of the deferred tax assets depends on the generation of sufficient taxable income in the applicable taxing jurisdictions. We operate in more than 80 countries under many legal forms. As a result, we are subject to the jurisdiction of numerous domestic and foreign tax authorities, as well as to tax agreements and treaties among these governments. Our operations in these different jurisdictions are taxed on various bases, 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 consolidated financial condition of the Company, although a resolution could have a material impact on our 40 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 3.6% in 2015, 4.5% in 2014 and 4.0% in 2013 to determine pension expense. A 50 basis point reduction in the weighted average discount rate would have increased pension expense and the projected benefit obligation of our principal pension plans by approximately $7 million and $85 million, respectively, in 2015. 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 6.8% in 2015, 6.7% in 2014 and 6.9% in 2013. 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 $7 million in 2015. NEW ACCOUNTING STANDARDS UPDATES In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers. The ASU will supersede most of the existing revenue recognition requirements in U.S. GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Company expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires significantly expanded disclosures regarding the qualitative and quantitative information of an entity's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The pronouncement is to be applied retrospectively and is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted as of January 1, 2017. We have not completed an evaluation of the impact the pronouncement will have on our consolidated financial statements and related disclosures. In April 2015, the FASB issued ASU No. 2015-3, Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The pronouncement is effective for annual reporting periods beginning after December 15, 2015. We currently report debt issuance costs consistent with the guidance of this ASU; therefore there will be no impact on our consolidated financial statements and related disclosures upon adoption. In April 2015, the FASB issued ASU No. 2015-5, Customer's Accounting for Fees Paid in a Cloud Computing Arrangement. The ASU provides guidance to customers about whether a cloud computing arrangement includes a software license and the related accounting treatment. The pronouncement is effective for annual reporting periods beginning after December 15, 2015. Adoption of this pronouncement is not expected to have a material impact on our consolidated financial statements and related disclosures. In July 2015, the FASB issued ASU No. 2015-11, Simplifying the Measurement of Inventory, which requires inventory measured using the FIFO or average cost methods to be subsequently measured at the lower of cost or 41 net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Currently, inventory measured using these methods is required to be subsequently measured at the lower of cost or market with market defined as replacement cost, net realizable value or net realizable value less a normal profit margin. This pronouncement is effective for annual reporting periods beginning after December 15, 2016 on a prospective basis. Early adoption is permitted. We have not completed an evaluation of the impact the pronouncement will have on our consolidated financial statements and related disclosures. In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes, which amends existing guidance on income taxes to require the classification of all deferred tax assets and liabilities as noncurrent on the balance sheet. The pronouncement is effective for annual reporting periods beginning after December 15, 2016, and may be applied either prospectively or retrospectively. We have not completed an evaluation of the impact the pronouncement will have on our consolidated financial statements and related disclosures. RELATED PARTY TRANSACTIONS There were no significant related party transactions during the three years ended December 31, 2015. 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 Halliburton. We undertake no obligation to publicly update or revise any forward-looking statement. Our expectations regarding our business outlook, including changes in revenue, pricing, capital spending, profitability, strategies for our operations, impact of any common stock repurchases, oil and natural gas market conditions, the business plans of our customers, market share and contract terms, costs and availability of resources, legal, economic and regulatory conditions, and environmental matters are only our forecasts regarding these matters. All of our forward-looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all 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. 42 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, 2015 or 2014. The following table sets forth our fixed rate long-term debt and the related weighted average interest rates by expected maturity dates. (In millions) As of December 31, 2015 Long-term debt (1) (2) 2016 2017 2018 2019 2020 Thereafter Total (3) $ — $ 24 $ 1,022 $ 22 $ 12 $ 2,838 $3,918 Weighted average interest rates — 7.77% 7.28% 5.94% 5.03% 5.18% 5.79% As of December 31, 2014 Long-term debt (1) (2) $ 27 $ 20 $ 1,022 $ 22 $ 12 $ 2,838 $3,941 Weighted average interest rates 8.44% 7.88% 7.28% 5.94% 5.03% 5.18% 5.83% (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 $4.17 billion at December 31, 2015 and $4.44 billion at December 31, 2014. (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, 2015 and 2014, we had outstanding foreign currency forward contracts with notional amounts aggregating $499 million and $580 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 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, 2015 and 2014 for contracts with similar terms and maturity dates, we recorded losses of $1 million and $11 million, respectively, to adjust these foreign currency forward contracts to their fair market value. These losses offset designated foreign currency exchange gains resulting from the underlying exposures and are included in MG&A expenses in the consolidated statements of income (loss). 43 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, 2015. 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/ ALAN J. KEIFER Alan J. Keifer Vice President and Controller Houston, Texas February 16, 2016 44 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, 2015 and 2014, 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, 2015. 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, 2015, 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, 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, 2015, 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 16, 2016 45 BAKER HUGHES INCORPORATED CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions, except per share amounts) Revenue: Sales Services Total revenue Costs and expenses: Cost of sales Cost of services Research and engineering Marketing, general and administrative Impairment and restructuring charges Litigation settlements Total costs and expenses Operating (loss) income Interest expense, net (Loss) income before income taxes Income taxes Net (loss) income Net loss (income) attributable to noncontrolling interests Year Ended December 31, 2015 2014 2013 $ 5,649 $ 8,056 $ 7,594 10,093 15,742 4,863 9,639 483 1,173 1,993 (13) 18,138 (2,396) (217) (2,613) 639 (1,974) 7 16,495 24,551 6,294 13,452 613 1,271 — 62 21,692 2,859 (232) 2,627 (896) 1,731 (12) 14,770 22,364 5,932 12,621 556 1,306 — — 20,415 1,949 (234) 1,715 (612) 1,103 (7) Net (loss) income attributable to Baker Hughes $ (1,967) $ 1,719 $ 1,096 Basic (loss) earnings per share attributable to Baker Hughes Diluted (loss) earnings per share attributable to Baker Hughes $ (4.49) $ (4.49) $ $ 3.93 3.92 $ $ 2.47 2.47 See Notes to Consolidated Financial Statements 46 BAKER HUGHES INCORPORATED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (In millions) Net (loss) income Other comprehensive (loss) income: Foreign currency translation adjustments during the period Pension and other postretirement benefits, net of tax (2015 - $15; 2014 - $9; 2013 - $(23)) Other comprehensive loss Comprehensive (loss) income Comprehensive loss (income) attributable to noncontrolling interests Year Ended December 31, 2015 $ (1,974) 2014 $ 1,731 2013 $ 1,103 (241) (15) (256) (2,230) 7 (216) (29) (245) 1,486 (12) (61) 33 (28) 1,075 (7) Comprehensive (loss) income attributable to Baker Hughes $ (2,223) $ 1,474 $ 1,068 See Notes to Consolidated Financial Statements 47 BAKER HUGHES INCORPORATED CONSOLIDATED BALANCE SHEETS (In millions, except par value) Current Assets: Cash and cash equivalents ASSETS Accounts receivable - less allowance for doubtful accounts (2015 - $383; 2014 - $224) Inventories, net Deferred income taxes Other current assets Total current assets Property, plant and equipment - less accumulated depreciation (2015 - $7,378; 2014 - $8,215) Goodwill Intangible assets, net Other assets Total assets Current Liabilities: Accounts payable LIABILITIES AND EQUITY Short-term debt and current portion of long-term debt Accrued employee compensation Income taxes payable Other accrued liabilities Total current liabilities Long-term debt Deferred income taxes and other tax liabilities Liabilities for pensions and other postretirement benefits Other liabilities Commitments and contingencies Equity: Common stock, one dollar par value (shares authorized - 750; issued and outstanding: 2015 - 437; 2014 - 434) Capital in excess of par value Retained earnings Accumulated other comprehensive loss Treasury stock Baker Hughes stockholders’ equity Noncontrolling interests Total equity Total liabilities and equity December 31, 2015 2014 $ 2,324 $ 1,740 3,217 2,917 301 509 9,268 6,693 6,070 583 1,466 24,080 1,409 151 690 55 470 2,775 3,890 252 646 135 437 7,261 9,614 (1,005) (9) 16,298 84 16,382 24,080 5,418 4,074 418 395 12,045 9,063 6,081 812 826 28,827 2,807 220 782 265 563 4,637 3,913 740 629 178 434 7,062 11,878 (749) — 18,625 105 18,730 28,827 $ $ $ $ $ $ See Notes to Consolidated Financial Statements 48 BAKER HUGHES INCORPORATED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (In millions, except per share amounts) Capital in Excess of Par Value Common Stock Retained Earnings Accumulated Other Comprehensive Loss Treasury Stock Non- controlling Interests Total Balance at December 31, 2012 $ 441 $ 7,495 $ 9,609 $ (476) $ — $ 199 $17,268 Baker Hughes Stockholders' Equity Comprehensive income: Net income Other comprehensive loss Activity related to stock plans Repurchase and retirement of common stock Stock-based compensation cost Cash dividends ($0.60 per share) Net activity related to noncontrolling interests 1,096 7 1,103 (28) 3 (6) 75 (344) 115 (267) (28) 78 (350) 115 (267) (7) (7) Balance at December 31, 2013 $ 438 $ 7,341 $ 10,438 $ (504) $ — $ 199 $17,912 Comprehensive income: Net income Other comprehensive loss Activity related to stock plans Repurchase and retirement of common stock Stock-based compensation cost Cash dividends ($0.64 per share) Net activity related to noncontrolling interests 1,719 12 1,731 (245) 5 (9) 200 (591) 122 (10) (279) (245) 205 (600) 122 (279) (106) (116) Balance at December 31, 2014 $ 434 $ 7,062 $ 11,878 $ (749) $ — $ 105 $18,730 Comprehensive income: Net loss Other comprehensive loss Activity related to stock plans Stock-based compensation cost Cash dividends ($0.68 per share) Net activity related to noncontrolling interests (1,967) (7) (1,974) 3 101 120 (22) (297) (256) (9) (256) 95 120 (297) (14) (36) Balance at December 31, 2015 $ 437 $ 7,261 $ 9,614 $ (1,005) $ (9) $ 84 $16,382 See Notes to Consolidated Financial Statements 49 BAKER HUGHES INCORPORATED CONSOLIDATED STATEMENTS OF CASH FLOWS (In millions) Cash flows from operating activities: Net (loss) income Adjustments to reconcile net (loss) income to net cash flows from operating activities: Depreciation and amortization (Benefit) provision for deferred income taxes Gain on disposal or deconsolidation of assets Stock-based compensation cost Provision for doubtful accounts Loss on impairment of assets Changes in operating assets and liabilities: Accounts receivable Inventories Accounts payable Income taxes payable Other operating items, net Net cash flows provided by operating activities Cash flows from investing activities: Expenditures for capital assets Proceeds from disposal of assets Purchase of investment securities Acquisition of businesses, net of cash acquired Other investing items, net Net cash flows used in investing activities Cash flows from financing activities: Net repayments of commercial paper borrowings and other debt with three months or less original maturity Repayment of short-term debt with greater than three months original maturity Proceeds of short-term debt with greater than three months original maturity Repurchase of common stock Proceeds from issuance of common stock Dividends paid Other financing items, net Net cash flows used in financing activities Effect of foreign exchange rate changes on cash and cash equivalents Increase in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period Supplemental cash flows disclosures: Income taxes paid, net of refunds Interest paid Supplemental disclosure of noncash investing activities: Capital expenditures included in accounts payable $ $ $ $ Year Ended December 31, 2014 2013 2015 $ (1,974) $ 1,731 $ 1,103 1,742 (809) (157) 120 193 1,436 1,943 1,092 (1,349) (305) (136) 1,796 (965) 388 (310) — (18) (905) (53) (293) 301 — 116 (297) (56) (282) (25) 584 1,740 2,324 483 242 44 $ $ $ $ 1,814 (70) (297) 122 102 — (524) (259) 291 90 (47) 2,953 (1,791) 437 — (314) 9 (1,659) (216) (217) 185 (600) 216 (279) (28) (939) (14) 341 1,399 1,740 881 250 171 $ $ $ $ 1,698 1 (275) 115 75 — (453) (120) 845 (31) 203 3,161 (2,085) 455 — (22) (11) (1,663) (650) (163) 242 (350) 101 (267) (16) (1,103) (11) 384 1,015 1,399 651 247 142 See Notes to Consolidated Financial Statements 50 Baker Hughes Incorporated Notes to Consolidated Financial Statements NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Operations Baker Hughes Incorporated (“Baker Hughes,” “Company,” “we,” “our,” or “us,”) is a leading supplier of oilfield services, products, technology and systems used 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. Basis of Presentation Our consolidated financial statements are prepared in conformity with United States generally accepted accounting principles ("GAAP"). The consolidated financial statements include the accounts of Baker Hughes and all of our subsidiaries where we exercise control. For investments in subsidiaries that are not wholly-owned, but where we exercise control, the equity held by the minority owners and their portions of net income (loss) are reflected as noncontrolling interests. Investments over which we have the ability to exercise significant influence over operating and financial policies, but do not hold a controlling interest, are accounted for using the equity method of accounting. Intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Consolidated Financial Statements, all dollar and share amounts in tabulations are in millions of dollars and shares, respectively, unless otherwise indicated. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities, disclosure of any contingent assets or liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. We base our estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty, and accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. Estimates are used for, but are not limited to, determining the following: allowance for doubtful accounts and inventory valuation reserves; recoverability of long-lived assets; useful lives used in depreciation and amortization; income taxes and related valuation allowances; accruals for contingencies; actuarial assumptions to determine costs and liabilities related to employee benefit plans; stock-based compensation expense and the fair value of assets acquired and liabilities assumed in acquisitions. Revenue Recognition Our products and services are sold based upon purchase orders, contracts or other agreements with the customer that include fixed or determinable prices and that do not include right of return or other similar provisions or other significant post-delivery obligations. We recognize revenue for products sold upon delivery, when title passes, when collectability is reasonably assured and when there are no further significant obligations for future performance. Provisions for estimated warranty returns or similar arrangements are made at the time the related revenue is recognized. Revenue for services is recognized as the services are rendered and when collectability is reasonably assured. Rates for services are typically priced on a per day, per distance drilled, per man hour or similar basis. In certain situations, revenue is generated from transactions that may include multiple products and services under one contract or agreement and which may be delivered to the customer over an extended period of time. Revenue from these arrangements is recognized in accordance with the above criteria and as each item or service is delivered based on their relative fair value. Research and Engineering Research and engineering expenses are expensed as incurred and include costs associated with the research and development of new products and services and costs associated with sustaining engineering of existing 51 Baker Hughes Incorporated Notes to Consolidated Financial Statements products and services. Costs for research and development of new products and services were $347 million, $430 million and $370 million for the years ended December 31, 2015, 2014 and 2013, respectively. Cash and Cash Equivalents Cash equivalents include only those investments with an original maturity of three months or less. We maintain cash deposits with financial institutions that may exceed federally insured limits. We monitor the credit ratings and our concentration of risk with these financial institutions on a continuing basis to safeguard our cash deposits. Allowance for Doubtful Accounts We establish an allowance for doubtful accounts based on various factors including the payment history and financial condition of our customers and the economic environment. 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. Provision for doubtful accounts recorded in cost of sales was $193 million, $102 million and $75 million for the years ended December 31, 2015, 2014 and 2013, respectively. Concentration of Credit Risk We grant credit to our customers who primarily operate in the oil and natural gas industry. Although this concentration affects our overall exposure to credit risk, our trade receivables are spread over a diverse group of customers across many countries, which mitigates this risk. We perform periodic credit evaluations of our customers’ financial condition, including monitoring our customers’ payment history and current credit worthiness to manage this risk. We do not generally require collateral in support of our trade receivables, but we may require payment in advance or security in the form of a letter of credit or bank guarantee. During 2015, 2014 and 2013, no individual customer accounted for more than 10% of our consolidated revenue. Inventories Inventories are stated at the lower of cost or market. Cost is determined using the average cost method, and includes the cost of materials, labor and manufacturing overhead. As necessary, we record provisions and maintain reserves for excess, slow moving and obsolete inventory. To determine these reserve amounts, we regularly review inventory quantities on hand and compare them to estimates of future product demand, market conditions, production requirements and technological developments. Property, Plant and Equipment and Accumulated Depreciation Property, plant and equipment (“PP&E”) is stated at cost less accumulated depreciation, which is generally provided by using the straight-line method over the estimated useful lives of the individual assets. Significant improvements and betterments are capitalized if they extend the useful life of the asset. We manufacture a substantial portion of our tools and equipment and the cost of these items, which includes direct and indirect manufacturing costs, is capitalized and carried in inventory until it is completed. When complete, the cost is reflected in capital expenditures and is classified as machinery, equipment and other in PP&E. Maintenance and repairs are charged to expense as incurred. Upon sale or other disposition, the applicable amounts of asset cost and accumulated depreciation are removed from the balance sheet and the net amount, less proceeds from disposal, is charged or credited to income. The capitalized costs of computer software developed or purchased for internal use are classified in machinery, equipment and other. Goodwill, Intangible Assets and Amortization Goodwill is the excess of the consideration transferred over the fair value of the tangible and identifiable intangible assets and liabilities recognized in acquisitions. Goodwill and intangible assets with indefinite lives are not amortized. Intangible assets with finite useful lives are amortized on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized, which is generally on a straight-line basis over the asset’s estimated useful life. 52 Baker Hughes Incorporated Notes to Consolidated Financial Statements Impairment of PP&E, Intangibles, Other Long-lived Assets and Goodwill We review PP&E, intangible assets and certain other long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable and at least annually for certain intangible assets. The determination of recoverability is made based upon the estimated undiscounted future net cash flows. The amount of impairment loss, if any, is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related assets. We perform an annual impairment test of goodwill for each of our reporting units as of October 1, or more frequently if an event occurs or circumstances change to indicate that it is more likely than not that an impairment may exist. Our reporting units are based on our organizational and reporting structure and are the same as our five reportable segments. Corporate and other assets and liabilities are allocated to the reporting units to the extent that they relate to the operations of those reporting units in determining their carrying amount. When performing the annual impairment test we have the option of first performing a qualitative assessment to determine the existence of events and circumstances that would lead to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If such a conclusion is reached, we would then be required to perform a quantitative impairment assessment of goodwill. However, if the assessment leads to a determination that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then no further assessments are required. In 2015 and 2014, we performed a qualitative assessment for our annual goodwill impairment test. In 2013, a quantitative assessment for the determination of impairment was made by comparing the carrying amount of each reporting unit with its fair value, which is generally calculated using a combination of market, comparable transaction and discounted cash flow approaches. In performing our annual goodwill impairment analysis for 2015, our qualitative assessment included consideration of current industry and market conditions and circumstances as well as any mitigating factors that would most affect the fair value of the Company and its reporting units. Among those mitigating factors, we considered the value of the consideration to be received at closing of the Merger (as defined below), based on the terms of the Merger Agreement (as defined below), compared to the carrying value of the Company and its reporting units. Based on our assessment and consideration of the totality of the facts and circumstances, including our business environment in the fourth quarter of 2015, we determined that it is not more likely than not that the fair value of the Company or any of its reporting units is less than their respective carrying amounts; however, a decline in our stock price could require an impairment in future periods. As such, no impairments of goodwill were recorded for the year ended December 31, 2015, or any of the prior years included in the accompanying financial statements. Income Taxes We use the liability method in determining our provision and liabilities for our income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Deferred tax liabilities and assets, which are computed on the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities, are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. A valuation allowance to reduce deferred tax assets is established when it is more likely than not that some portion or all of the deferred tax assets will not be realized. We intend to indefinitely reinvest certain earnings of our foreign subsidiaries in operations outside the U.S., and accordingly, we have not provided for U.S. income taxes on such earnings. We do provide for the U.S. and additional non-U.S. taxes on earnings anticipated to be repatriated from our non-U.S. subsidiaries. Our tax filings for various periods are subject to audit by tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or through the courts. We have provided for the amounts we believe will ultimately result from these proceedings. In addition to the assessments that have been received from various tax authorities, we also provide for taxes for uncertain tax positions where formal assessments have not been received. We classify interest and penalties related to uncertain tax positions as income taxes in our financial statements. 53 Baker Hughes Incorporated Notes to Consolidated Financial Statements Environmental Matters Estimated remediation costs are accrued using currently available facts, existing environmental permits, technology and enacted laws and regulations. Our cost estimates are developed based on internal evaluations and are not discounted. Accruals are recorded when it is probable that we will be obligated to pay for environmental site evaluation, remediation or related activities, and such costs can be reasonably estimated. As additional information becomes available, accruals are adjusted to reflect current cost estimates. Ongoing environmental compliance costs, such as obtaining environmental permits, installation of pollution control equipment and waste disposal are expensed as incurred. Where we have been identified as a potentially responsible party in a U.S. federal or state Comprehensive Environmental Response, Compensation and Liability Act (“Superfund”) site, we accrue our share of the estimated remediation costs of the site. This share is based on the ratio of the estimated volume of waste we contributed to the site to the total volume of waste disposed at the site. Foreign Currency A number of our significant foreign subsidiaries have designated the local currency as their functional currency and, as such, gains and losses resulting from balance sheet translation of foreign operations are included as a separate component of accumulated other comprehensive loss within stockholders’ equity. Gains and losses from foreign currency transactions, such as those resulting from the settlement of receivables or payables in the non- functional currency, are included in marketing, general and administrative (“MG&A”) expenses in the consolidated statements of income (loss) as incurred. For those foreign subsidiaries that have designated the U.S. Dollar ("USD") as the functional currency, monetary assets and liabilities are remeasured at period-end exchange rates, and nonmonetary items are remeasured at historical exchange rates. Gains and losses resulting from this balance sheet remeasurement are also included in MG&A expenses as incurred. In 2015 and 2014, the Venezuelan government modified its currency exchange systems, which impacted the rate at which we could reasonably expect to exchange the Venezuelan Bolivars Fuertes ("BsF") for the U.S. Dollar. As a result of the change in the exchange rate, in 2015 and 2014, we recognized a foreign currency loss of approximately $5 million and $12 million, respectively, related to the remeasurement of our BsF denominated assets and liabilities. This loss was recorded in MG&A expenses. We believe any further devaluation of Venezuela's currency would not have a material impact on our financial position, results of operations or cash flows. In 2013, Venezuela's currency was devalued from the prior exchange rate of 4.3 BsF per USD to 6.3 BsF per USD. The impact of this devaluation was a loss of $23 million that was recorded in MG&A expenses. Fair Value Measurement The Company defines fair value as the price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants at a measurement date. The Company applies the following fair value hierarchy, which prioritizes the inputs used to measure fair value into three levels and bases the categorization within the hierarchy upon the lowest level of input that is available and significant to the fair value measurement: • • • Level One: The use of quoted prices in active markets for identical financial instruments. Level Two: The use of quoted prices for similar instruments in active markets or quoted prices for identical or similar instruments in markets that are not active or other inputs that are observable in the market or can be corroborated by observable market data. Level Three: The use of significantly unobservable inputs that typically require the use of management's estimates of assumptions that market participants would use in pricing. Financial Instruments Our financial instruments include cash and cash equivalents, accounts receivable, investments, accounts payable, short and long-term debt, and derivative financial instruments. Except for long-term debt, the estimated fair value of our financial instruments at December 31, 2015 and 2014 approximates their carrying value as 54 Baker Hughes Incorporated Notes to Consolidated Financial Statements reflected in our consolidated balance sheets. For further information on the fair value of our debt, see Note 12. "Indebtedness." We monitor our exposure to various business risks including commodity prices, foreign currency exchange rates and interest rates and regularly use derivative financial instruments to manage these risks. Our policies do not permit the use of derivative financial instruments for speculative purposes. At the inception of a new derivative, we designate the derivative as a hedge or we determine the derivative to be undesignated as a hedging instrument. We document the relationships between the hedging instruments and the hedged items, as well as our risk management objectives and strategy for undertaking various hedge transactions. We assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of the hedged item at both the inception of the hedge and on an ongoing basis. We have a program that utilizes foreign currency forward contracts to reduce the risks associated with the effects of certain foreign currency exposures. Under this program, our strategy is to have gains or losses on the foreign currency forward contracts mitigate the foreign currency transaction and translation gains or losses to the extent practical. These foreign currency exposures typically arise from changes in the value of assets and liabilities which are denominated in currencies other than the functional currency. Our foreign currency forward contracts generally settle in less than 180 days. We record all derivatives as of the end of our reporting period in our consolidated balance sheet at fair value. For those forward contracts designated as fair value hedging instruments or held as undesignated hedging instruments, we record the changes in fair value of the forward contracts in our consolidated statements of income (loss) along with the change in fair value of the hedged item. Changes in the fair value of forward contracts designated as cash flow hedging instruments are recognized in other comprehensive income until the hedged item is recognized in earnings. For derivatives designated as a cash flow hedge, the ineffective portion of that derivative's change in fair value is recognized in earnings. Recognized gains and losses on derivatives entered into to manage foreign currency exchange risk are included in MG&A expenses in the consolidated statements of income (loss). We had outstanding foreign currency forward contracts with notional amounts aggregating $499 million and $580 million to hedge exposure to currency fluctuations in various foreign currencies at December 31, 2015 and 2014, respectively. Based on quoted market prices as of December 31, 2015 or 2014 for forward contracts with similar terms and maturity dates, we recorded losses of $1 million and $11 million, respectively, to adjust these forward contracts to their fair market value. New Accounting Standards Updates In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers. The ASU will supersede most of the existing revenue recognition requirements in U.S. GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Company expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires significantly expanded disclosures regarding the qualitative and quantitative information of an entity's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The pronouncement is to be applied retrospectively and is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted as of January 1, 2017. We have not completed an evaluation of the impact the pronouncement will have on our consolidated financial statements and related disclosures. In April 2015, the FASB issued ASU No. 2015-3, Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The pronouncement is effective for annual reporting periods beginning after December 15, 2015. We currently report debt issuance costs consistent with the guidance of this ASU; therefore there will be no impact on our consolidated financial statements and related disclosures upon adoption. In April 2015, the FASB issued ASU No. 2015-5, Customer's Accounting for Fees Paid in a Cloud Computing Arrangement. The ASU provides guidance to customers about whether a cloud computing arrangement includes a software license and the related accounting treatment. The pronouncement is effective for annual reporting periods 55 Baker Hughes Incorporated Notes to Consolidated Financial Statements beginning after December 15, 2015. Adoption of this pronouncement is not expected to have a material impact on our consolidated financial statements or related disclosures. In July 2015, the FASB issued ASU No. 2015-11, Simplifying the Measurement of Inventory, which requires inventory measured using the FIFO or average cost methods to be subsequently measured at the lower of cost or net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Currently, inventory measured using these methods is required to be subsequently measured at the lower of cost or market with market defined as replacement cost, net realizable value or net realizable value less a normal profit margin. This pronouncement is effective for annual reporting periods beginning after December 15, 2016 on a prospective basis. Early adoption is permitted. We have not completed an evaluation of the impact the pronouncement will have on our consolidated financial statements and related disclosures. In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes, which amends existing guidance on income taxes to require the classification of all deferred tax assets and liabilities as noncurrent on the balance sheet. The pronouncement is effective for annual reporting periods beginning after December 15, 2016, and may be applied either prospectively or retrospectively. We have not completed an evaluation of the impact the pronouncement will have on our consolidated financial statements and related disclosures. NOTE 2. HALLIBURTON MERGER AGREEMENT On November 16, 2014, Baker Hughes, Halliburton Company (“Halliburton”) and a wholly owned subsidiary of Halliburton (“Merger Sub”), entered into an Agreement and Plan of Merger (the “Merger Agreement”), under which Halliburton will acquire all of the outstanding shares of Baker Hughes through a merger of Baker Hughes with and into Merger Sub (the "Merger"). Subject to certain specified exceptions, at the effective time of the Merger, each share of Baker Hughes common stock will be converted into the right to receive (i) 1.12 shares of Halliburton common stock and (ii) $19.00 in cash. On March 27, 2015, Halliburton's stockholders approved the proposal to issue shares of Halliburton common stock as contemplated by the Merger Agreement. In addition, Baker Hughes’ stockholders adopted the Merger Agreement and thereby approved the proposed combination of the two companies. The obligation of the parties to consummate the Merger is still subject to additional customary closing conditions, including: (i) applicable regulatory approvals; (ii) the absence of legal restraints and prohibitions; and (iii) other customary closing conditions. Halliburton is required to take all actions necessary to obtain regulatory approvals (including agreeing to divestitures) unless the assets, businesses or product lines subject to such actions would account for more than $7.5 billion of 2013 revenue. Under the U.S. Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act") and the rules promulgated thereunder by the Federal Trade Commission (the “FTC”), the Merger cannot be completed until each of Halliburton and Baker Hughes has filed a notification and report form with the FTC and the Antitrust Division of the Department of Justice (the “DOJ”) under the HSR Act and the applicable waiting period has expired or been terminated. Each of Halliburton and Baker Hughes filed an initial notification and report form on December 8, 2014. Halliburton withdrew its filing on January 7, 2015 and refiled on January 9, 2015 in order to provide the FTC and the DOJ with an additional 30-day period to review the filings. On February 9, 2015, the DOJ issued a request for additional information under the HSR Act (the “Second Request”). On July 10, 2015, Halliburton and Baker Hughes entered into a timing agreement with the DOJ, and on September 28, 2015, Halliburton and Baker Hughes announced an amendment to the timing agreement which extended the period for the DOJ's review of the Merger to the later of December 15, 2015 or 30 days following the date on which both companies have certified final, substantial compliance with the Second Request. On December 16, 2015, Baker Hughes' and Halliburton's timing agreement with the DOJ expired without reaching a settlement or the DOJ initiating litigation to block the pending Merger. The companies intend to continue their discussions with the DOJ and other competition agencies that have expressed an interest in the transaction, and remain focused on completing the Merger as early as possible in 2016. In that regard, Baker Hughes and Halliburton have agreed to extend the period for the parties to obtain required competition approvals to April 30, 56 Baker Hughes Incorporated Notes to Consolidated Financial Statements 2016, as permitted under the Merger Agreement, though the parties would proceed with closing prior to such date if all relevant competition approvals have been obtained. If review by the relevant competition authorities extends beyond April 30, 2016, the Merger Agreement does not terminate automatically; the parties may continue to seek relevant competition approvals or either of the parties may terminate the Merger Agreement. Baker Hughes cannot predict with certainty when, or if, the Merger will be completed because completion of the Merger is subject to conditions beyond the control of Baker Hughes. Baker Hughes and Halliburton each made customary representations, warranties and covenants in the Merger Agreement, including, among others, covenants by each of Baker Hughes and Halliburton to, subject to certain exceptions, conduct its business in the ordinary course. In particular, among other restrictions and subject to certain exceptions, Baker Hughes agreed to generally refrain from acquiring new businesses, incurring new indebtedness, repurchasing shares, issuing new common stock or equity awards (other than equity awards granted to employees, officers and directors materially consistent with historical long-term incentive awards granted), or entering into new material contracts or commitments outside the normal course of business, without the consent of Halliburton, during the period between the execution of the Merger Agreement and the consummation of the Merger. With respect to equity awards granted after the Merger Agreement to officers and employees, such awards will not vest solely as a result of the Merger but will be converted to an equivalent Halliburton equity award. However, they will vest entirely if an officer or employee is terminated within one year following the closing of the Merger with Halliburton. Baker Hughes and Halliburton are each permitted to pay regular quarterly cash dividends during such period. In addition, under the terms of the Merger Agreement, Halliburton and Baker Hughes have agreed to coordinate the declaration and payment of dividends in respect of each party's common stock including record dates and payment dates relating thereto, which we expect to be in the third month of each quarter. Under the Merger Agreement, we have agreed not to increase the quarterly dividend while the Merger is pending. In the event the Merger Agreement is terminated by (i) either party as a result of the failure of the Merger to occur on or before the end date (as it may be extended) due to the failure to achieve certain specified antitrust- related approvals when all other closing conditions (other than receipt of antitrust and other specified regulatory approvals and conditions that by their nature cannot be satisfied until the closing but subject to such conditions being capable of being satisfied if the closing date were the date of termination) have been satisfied, (ii) either party as a result of any antitrust-related final, non-appealable order or injunction prohibiting the closing, or (iii) Baker Hughes as a result of Halliburton’s material breach of its obligations to obtain regulatory approval such that the antitrust-related condition to closing is incapable of being satisfied, then in each case Halliburton would be required to pay Baker Hughes a termination fee of $3.5 billion. Baker Hughes incurred costs related to the Merger of $295 million during 2015, including costs under our retention program and obligations for minimum incentive compensation costs, which, based on meeting eligibility criteria, have been treated as Merger related expenses. NOTE 3. IMPAIRMENT AND RESTRUCTURING CHARGES IMPAIRMENT CHARGES We conduct impairment tests on long-lived assets whenever events or changes in circumstances indicate that the carrying value may not be recoverable based on estimated future cash flows. In the fourth quarter of 2015, negative market sentiment increased and oil prices fell to a seven year low. Additionally, the current market outlook is for a prolonged recovery. We considered these events to be possible impairment indicators and performed testing of long-lived assets for impairment. As a result of our testing, certain machinery and equipment, with a total carrying value of $1.64 billion, was written down to its estimated fair value, resulting in an impairment charge of $1.05 billion. Additionally, certain intangible assets, comprised of customer relationships and trade names, with a total carrying value of $178 million, were written down to their estimated fair values, resulting in an impairment charge of $116 million. Total impairment charges for 2015 were $1.16 billion. The majority of the machinery and equipment and intangible assets impaired related to our pressure pumping business in North America. The estimated fair values for these assets were determined using discounted future cash flows. The significant level 3 unobservable inputs used in the 57 Baker Hughes Incorporated Notes to Consolidated Financial Statements determination of the fair value of these assets were the estimated future cash flows and the weighted average cost of capital of 9.8%. RESTRUCTURING CHARGES Beginning in the second half of 2014 and throughout 2015, the oil and natural gas market experienced a significant over supply of capacity leading to a substantial and rapid decline in oil prices resulting in significantly lower activity and customer spending. Accordingly, to adjust to the lower level of activity, beginning in the first quarter of 2015, we initiated actions to restructure and adjust our operations and cost structure to reflect current and expected near-term activity levels. These restructuring activities included workforce reductions, contract terminations, facility closures and the removal of excess machinery and equipment that resulted in asset impairments. As a result of these restructuring activities, we recorded restructuring charges of $830 million in 2015. Depending on future market conditions and activity levels, further actions may be necessary to adjust our operations which may result in additional charges. Our restructuring charges as summarized below: Restructuring Charges Workforce reductions Contract terminations Impairment of buildings and improvements Impairment of machinery and equipment Total restructuring charges Year Ended December 31, 2015 $ $ 436 121 82 191 830 Workforce reduction costs: During 2015, we initiated workforce reductions that will result in the elimination of approximately 18,000 positions worldwide. As of December 31, 2015, we have eliminated approximately 17,000 positions. As a result of these workforce reductions, we recorded a charge for severance expense of $436 million during 2015, net of related employee benefit plan gains of $10 million. As of December 31, 2015, we have made payments totaling $365 million relating to workforce reductions. We expect that substantially all of the accrued severance remaining will be paid by the middle of 2016. Contract termination costs: During 2015, we incurred costs of $121 million to terminate or restructure various contracts, primarily in North America. This includes the accrual for costs to settle leases on closed facilities and certain equipment, and other estimated exit costs, and is net of expected sublease income. This also includes costs to terminate or restructure certain take-or-pay supply contracts related to the purchase of materials used in our pressure pumping operations in North America, including the write-off of $14 million of prepayments made in 2014. As of December 31, 2015, we have made payments totaling $81 million relating to contract termination costs. Impairment of buildings and improvements: We are consolidating facilities and shutting down certain operations and as a result are closing and abandoning or selling certain facilities, both owned and leased. During 2015, we recognized $82 million of impairment charges related to facilities primarily in North America and Latin America. For leased facilities, this charge includes the impairment of the leasehold improvements made to those facilities. Impairment of machinery and equipment: We are exiting or substantially downsizing our presence in select markets primarily in our pressure pumping product line in North America and Latin America. During 2015, we recognized $191 million of impairment losses to adjust the carrying value of certain machinery and equipment to its fair value, net of costs to dispose. We are currently in the process of disposing of this machinery and equipment through sale or scrap. OTHER CHARGES In addition to the matters described above, during 2015, we also recorded charges of $194 million, of which $37 million is reported in cost of sales and $157 million is reported in cost of services, to write-down the carrying value 58 Baker Hughes Incorporated Notes to Consolidated Financial Statements of certain inventory. The write-down, primarily in North America, includes lower of cost or market adjustments due to the significant decline in activity and related prices for our products coupled with declines in replacement costs. In addition, the adjustments include provisions for excess inventory levels based on estimates of current and future market demand. The product lines impacted are primarily pressure pumping and drilling and completion fluids. NOTE 4. ACQUISITIONS In September 2014, we completed the acquisition of the pipeline and specialty services business of Weatherford International Ltd. ("PSS") for total cash consideration of $248 million, subject to the finalization of the post-closing working capital adjustments. PSS provides an expanded range of pre-commissioning, deepwater and in-line inspection services worldwide and is included in our Industrial Services segment. The transaction has been accounted for using the acquisition method of accounting and accordingly, assets acquired and liabilities assumed were recorded at their fair values as of the acquisition date. As a result of the acquisition, we recorded approximately $73 million of goodwill and approximately $37 million of intangible assets. Pro forma results of operations for this acquisition have not been presented because the effect of this acquisition was not material to our consolidated financial statements. NOTE 5. SEGMENT INFORMATION We are a supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas business, referred to as oilfield operations, which are managed through operating segments that are aligned with our geographic regions. We also provide services and products to the downstream chemicals, and process and pipeline services, referred to as Industrial Services. The performance of our operating segments is evaluated based on profit or loss before tax, which is defined as income or loss before income taxes and before the following: net interest expense, corporate expenses, and certain gains and losses, including impairment and restructuring charges, not allocated to the operating segments. The following table presents revenue and profit (loss) before tax by segment for the years ended December 31: 2015 2014 2013 Segments North America Latin America Europe/Africa/Russia Caspian Middle East/Asia Pacific Industrial Services Total Operations Corporate Interest expense, net Impairment and restructuring charges Litigation settlements Total Revenue 6,009 $ 1,799 3,278 3,441 1,215 15,742 — — — — Profit (Loss) Before Tax $ Revenue (687) $ 12,078 2,236 134 Profit (Loss) Before Tax 1,466 $ Revenue $ 10,878 Profit (Loss) Before Tax 968 $ 157 204 97 (95) (321) (217) (1,993) 13 4,417 4,456 1,364 290 621 675 119 2,307 4,041 3,859 1,279 24,551 3,171 22,364 — — — — (250) (232) — (62) — — — — 66 591 457 135 2,217 (268) (234) — — $ 15,742 $ (2,613) $ 24,551 $ 2,627 $ 22,364 $ 1,715 59 Baker Hughes Incorporated Notes to Consolidated Financial Statements The following table presents total assets by segment at December 31: Segments North America Latin America Europe/Africa/Russia Caspian Middle East/Asia Pacific Industrial Services Shared assets Total Operations Corporate Total 2015 Assets 2014 Assets 2013 Assets $ 6,599 $ 9,782 $ 2,323 3,077 3,441 1,106 5,613 22,159 1,921 2,508 4,106 4,029 1,260 5,423 27,108 1,719 9,672 2,709 4,098 3,705 980 5,110 26,274 1,660 $ 24,080 $ 28,827 $ 27,934 Shared assets consist primarily of the assets carried at the enterprise level and include our supply chain, product line technology and information technology organizations. These assets are used to support our operating segments and consist primarily of manufacturing inventory, property, plant and equipment used in manufacturing and information technology, intangible assets related to technology, and certain deferred tax assets. All costs and expenses from these organizations, including depreciation and amortization, are allocated to our operating segments as these enterprise organizations support our global operations. Corporate assets include cash, certain facilities, and certain other noncurrent assets. The following table presents capital expenditures and depreciation and amortization by segment for the years ended December 31: Segments North America Latin America Europe/Africa/Russia Caspian Middle East/Asia Pacific Industrial Services Shared assets Total Operations Corporate Total 2015 2014 2013 Capital Expenditures 228 $ Depreciation and Amortization 714 $ Capital Expenditures 465 $ Depreciation and Amortization 842 $ Capital Expenditures 718 $ Depreciation and Amortization 814 $ 103 175 247 21 188 962 3 965 $ 213 378 344 87 — 1,736 6 171 373 385 46 342 1,782 9 220 351 321 70 — 1,804 10 198 429 365 53 262 2,025 60 235 302 268 58 — 1,677 21 $ 1,742 $ 1,791 $ 1,814 $ 2,085 $ 1,698 60 Baker Hughes Incorporated Notes to Consolidated Financial Statements The following tables present geographic consolidated revenue based on the location to where the product is shipped or the services are performed for the years ended December 31, and net property, plant and equipment by its geographic location at December 31. Amounts for Industrial Services have been included in the applicable geographic locations. U.S. Canada and other North America Latin America (1) Europe/Africa/Russia Caspian Middle East/Asia Pacific Total U.S. Canada and other North America Latin America (1) Europe/Africa/Russia Caspian Middle East/Asia Pacific Total 2015 Revenue 2014 Revenue 2013 Revenue $ 5,800 $ 11,499 $ 10,133 839 6,639 1,847 3,555 3,701 1,336 12,835 2,300 4,705 4,711 1,446 11,579 2,368 4,359 4,058 $ 15,742 $ 24,551 $ 22,364 2015 Net Property, Plant and Equipment 2014 Net Property, Plant and Equipment 2013 Net Property, Plant and Equipment $ 2,989 $ 4,417 $ 260 3,249 716 1,400 1,328 482 4,899 890 1,805 1,469 $ 6,693 $ 9,063 $ 4,582 571 5,153 887 1,761 1,275 9,076 (1) Latin America includes Mexico, and Central and South America. The following table presents consolidated revenue for each category of similar products and services for the years ended December 31: Completion and Production Drilling and Evaluation Industrial Services Total 2015 2014 2013 $ 8,831 $ 14,572 $ 13,323 5,696 1,215 8,615 1,364 7,762 1,279 $ 15,742 $ 24,551 $ 22,364 NOTE 6. STOCK-BASED COMPENSATION Stock-based compensation cost is measured at the date of grant based on the calculated fair value of the award and is generally recognized on a straight-line basis over the vesting period of the equity grant. The compensation cost is determined based on awards ultimately expected to vest; therefore, we have reduced the cost for estimated forfeitures based on historical forfeiture rates. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods to reflect actual forfeitures. There were no stock-based compensation costs capitalized as the amounts were not material. 61 Baker Hughes Incorporated Notes to Consolidated Financial Statements Stock-based compensation costs are as follows for the years ended December 31: Stock-based compensation cost Tax benefit Stock-based compensation cost, net of tax 2015 2014 2013 $ $ 120 $ (28) 92 $ 122 (26) 96 $ $ 115 (24) 91 For our stock options and restricted stock awards and units, we currently have 60.7 million shares authorized for issuance and as of December 31, 2015, approximately 21.3 million shares were available for future grants. Our policy is to issue new shares for exercises of stock options, when restricted stock awards are granted, at vesting of restricted stock units and for issuances under the employee stock purchase plan. Stock Options Our stock option plans provide for the issuance of stock options to directors, officers and other key employees at an exercise price equal to the fair market value of the stock at the date of grant. Although subject to the terms of the stock option agreement, substantially all of the stock options become exercisable in three equal annual installments, beginning a year from the date of grant, and generally expire ten years from the date of grant. The stock option plans provide for the acceleration of vesting upon the employee’s retirement; therefore, the service period is reduced for employees that are or will become retirement eligible during the vesting period, and accordingly, the recognition of compensation expense for these employees is accelerated. No stock options were granted in 2015. The fair value of each stock option granted is estimated using the Black-Scholes option pricing model. The following table presents the weighted average assumptions used in the option pricing model for options granted. The expected life of the options represents the period of time the options are expected to be outstanding. The expected life is based on our historical exercise trends and post-vest termination data incorporated into a forward- looking stock price model. The expected volatility is based on our implied volatility, which is the volatility forecast that is implied by the prices of actively traded options to purchase our stock observed in the market. The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the options were granted. The dividend yield is based on our history of dividend payouts. Expected life (years) Risk-free interest rate Volatility Dividend yield Weighted average fair value per share at grant date 2014 4.6 1.5% 31.9% 1.0% 2013 5.2 1.3% 36.0% 1.3% $ 16.81 $ 13.79 62 Baker Hughes Incorporated Notes to Consolidated Financial Statements The following table presents the changes in stock options outstanding and related information (in thousands, except per option prices): Outstanding at December 31, 2014 Granted Exercised Forfeited Expired Outstanding at December 31, 2015 Exercisable at December 31, 2015 Number of Options 9,737 — (873) (124) (138) 8,602 7,363 Weighted Average Exercise Price Per Option $ 53.80 — 44.25 53.90 67.85 54.56 54.46 $ $ The weighted average remaining contractual term for options outstanding and options exercisable at December 31, 2015 were 4.7 years and 4.2 years, respectively. The total intrinsic value of stock options (defined as the amount by which the market price of our common stock on the date of exercise exceeds the exercise price of the option) exercised in 2015, 2014 and 2013 was $15 million, $70 million and $11 million, respectively. The income tax benefit realized from stock options exercised was $3.8 million, $19.6 million and $2.0 million in 2015, 2014 and 2013, respectively. The total fair value of options vested in 2015, 2014 and 2013 was $24 million, $29 million and $31 million, respectively. As of December 31, 2015, there was $5 million of total unrecognized compensation cost related to unvested stock options, which is expected to be recognized over a weighted average period of one year. The total intrinsic value of stock options outstanding at December 31, 2015 was $15.1 million, of which $14.8 million relates to options vested and exercisable. The intrinsic value for stock options outstanding is calculated as the amount by which the quoted price of $46.15 of our common stock as of the end of 2015 exceeds the exercise price of the options. Restricted Stock Awards and Units In addition to stock options, our officers, directors and key employees may be granted restricted stock awards (“RSA”), which is an award of common stock with no exercise price, or restricted stock units (“RSU”), where each unit represents the right to receive, at the end of a stipulated period, one unrestricted share of stock with no exercise price. RSAs and RSUs are subject to cliff or graded vesting, generally ranging over a three year period, or over a one year period for non-employee directors. We determine the fair value of restricted stock awards and restricted stock units based on the market price of our common stock on the date of grant. The following table presents the combined changes of RSAs and RSUs and related information (in thousands, except per award/unit prices): Unvested balance at December 31, 2014 Granted Vested Forfeited Unvested balance at December 31, 2015 63 Number of Awards and Units Weighted Average Grant Date Fair Value Per Award/Unit 2,732 $ 2,314 (1,299) (391) 3,356 $ 57.88 57.37 55.09 54.62 58.99 Baker Hughes Incorporated Notes to Consolidated Financial Statements The weighted average grant date fair value per share for RSAs and RSUs granted in 2015, 2014 and 2013 was $57.37, $69.67 and $45.58, respectively. The total fair value of RSAs and RSUs vested in 2015, 2014 and 2013 was $72 million, $60 million and $58 million, respectively. As of December 31, 2015, there was $117 million of total unrecognized compensation cost related to unvested RSAs and RSUs, which is expected to be recognized over a weighted average period of two years. Employee Stock Purchase Plan The Employee Stock Purchase Plan (“ESPP”) provides for eligible employees to purchase shares on an after- tax basis in an amount between 1% and 10% of their annual pay: (i) on June 30 of each year at a 15% discount of the fair market value of our common stock on January 1 or June 30, whichever is lower, and (ii) on December 31 of each year at a 15% discount of the fair market value of our common stock on July 1 or December 31, whichever is lower. An employee may not contribute more than $5,000 in either of the six-month measurement periods described above or $10,000 annually. We currently have 30.5 million shares authorized for issuance, and at December 31, 2015, there were 4.2 million shares reserved for future issuance. Compensation cost for the years ended December 31, was calculated using the Black-Scholes option pricing model with the following assumptions: Expected life (years) Risk-free interest rate Volatility Dividend yield Fair value per share of the 15% cash discount Fair value per share of the look-back provision Total weighted average fair value per share at grant date 2015 0.5 0.1% 30.9% 1.2% 2014 0.5 0.03% 24.7% 1.0% 2013 0.5 0.1% 30.3% 1.4% $ 8.79 $ 9.72 $ 6.45 4.97 4.39 3.58 $13.76 $14.11 $10.03 We calculated estimated volatility using historical daily prices based on the expected life of the stock purchase plan. The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the ESPP shares were granted. The dividend yield is based on our history of dividend payouts. 64 Baker Hughes Incorporated Notes to Consolidated Financial Statements NOTE 7. INCOME TAXES The benefit or provision for income taxes is comprised of the following for the years ended December 31: Current: U.S. Foreign Total current Deferred: U.S. Foreign Total deferred (Benefit) provision for income taxes 2015 2014 2013 $ (55) $ 365 601 966 225 170 $ 159 452 611 (762) (47) (809) (52) (18) (70) $ (639) $ 896 (54) 55 1 $ 612 The geographic sources of loss or income before income taxes are as follows for the years ended December 31: U.S. Foreign (Loss) income before income taxes 2015 2014 2013 $ (2,288) $ (325) 920 1,707 $ (2,613) $ 2,627 $ 512 1,203 $ 1,715 The benefit or provision for income taxes differs from the amount computed by applying the U.S. statutory income tax rate to the loss or income before income taxes for the reasons set forth below for the years ended December 31: U.S. statutory income tax rate Effect of foreign operations Change in valuation allowances related to foreign losses Adjustments of prior years’ tax positions State income taxes - net of U.S. tax benefit Impact of reorganization of certain foreign subsidiaries Other - net Total effective tax rate 2015 2014 35.0% 35.0% 35.0% 2013 (5.3) (8.7) (1.5) (7.3) (1.5) 1.4 — 4.0 1.2 0.9 — 8.9 0.9 0.8 (1.0) (0.2) (1.6) (1.7) 24.5% 34.1% 35.7% During the fourth quarter of 2013, we recognized a net tax benefit of $18 million as a result of the reorganization of certain of our foreign subsidiaries. This included a $360 million tax benefit resulting from the reversal of a deferred tax liability related to our decision to indefinitely reinvest the earnings of certain foreign subsidiaries which was made in conjunction with the reorganization that occurred during the fourth quarter of 2013. Due to the fact that these undistributed foreign earnings are no longer a source of future income against which the foreign tax credits will be utilized, we also recognized a tax charge of $342 million to record a valuation allowance against certain foreign tax credit carryforwards. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, as well as operating loss and tax credit carryforwards. 65 Baker Hughes Incorporated Notes to Consolidated Financial Statements The tax effects of our temporary differences and carryforwards are as follows at December 31: Deferred tax assets: Receivables Inventory Employee benefits Other accrued expenses Operating loss carryforwards Tax credit carryforwards Other Subtotal Valuation allowances Total Deferred tax liabilities: Goodwill and other intangibles Property Undistributed earnings of foreign subsidiaries Other Total Net deferred tax asset (liability) 2015 2014 $ 84 253 143 141 1,153 458 112 2,344 (1,210) 1,134 $ 65 376 106 173 493 481 104 1,798 (1,051) 747 272 47 21 35 375 759 $ 334 459 26 16 835 (88) $ We record a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character in the future and in the appropriate taxing jurisdictions. At December 31, 2015, valuation allowances totaled $1,210 million consisting of $672 million for operating loss carryforwards, $425 million for foreign tax credit carryforwards, and $113 million for other deferred tax assets in various jurisdictions. There are $481 million of deferred tax assets related to operating loss carryforwards without a valuation allowance as we expect that the deferred tax assets will be realized within the carryforward period. The majority of these deferred tax assets will expire in varying amounts over the next twenty years. We have provided relevant U.S. and foreign taxes for the anticipated repatriation of certain earnings of our foreign subsidiaries. We consider the undistributed earnings of our foreign subsidiaries above the amount for which taxes have already been provided to be indefinitely reinvested, as we have no current intention to repatriate these earnings. As of December 31, 2015, the cumulative amount of earnings upon which the U.S. income taxes have not been provided is approximately $5.6 billion. These additional foreign earnings could become subject to additional tax, if remitted, or deemed remitted, as a dividend. Computation of the potential deferred tax liability associated with these undistributed earnings and any other basis differences, is not practicable. At December 31, 2015, we had approximately $126 million of foreign tax credits which may be carried forward indefinitely under applicable foreign law, and $310 million of foreign tax credits and $22 million of other credits which expire in 2016 through 2035 under U.S. tax law. At December 31, 2015, we had $312 million of tax liabilities for total gross unrecognized tax benefits related to uncertain tax positions, which includes liabilities for interest and penalties of $30 million and $21 million, respectively. If we were to prevail on all uncertain tax positions, the net effect would be an increase to our income tax benefit of approximately $289 million. The remaining approximately $23 million is offset by deferred tax assets that represent tax benefits that would be received in different taxing jurisdictions in the event that we did not prevail on all uncertain tax positions. 66 Baker Hughes Incorporated Notes to Consolidated Financial Statements The following table presents the changes in our gross unrecognized tax benefits and associated interest and penalties included in the consolidated balance sheets. Gross Unrecognized Tax Benefits, Excluding Interest and Penalties Interest and Penalties Total Gross Unrecognized Tax Benefits Balance at December 31, 2012 $ Increase (decrease) in prior year tax positions Increase in current year tax positions Decrease related to settlements with taxing authorities Decrease related to lapse of statute of limitations Decrease due to effects of foreign currency translation Balance at December 31, 2013 (Decrease) increase in prior year tax positions Increase in current year tax positions Decrease related to settlements with taxing authorities Decrease related to lapse of statute of limitations Decrease due to effects of foreign currency translation Balance at December 31, 2014 Increase in prior year tax positions Increase in current year tax positions Decrease related to settlements with taxing authorities Decrease related to lapse of statute of limitations Decrease due to effects of foreign currency translation Balance at December 31, 2015 $ 196 20 44 (15) (17) — 228 (7) 39 (5) (6) (7) 242 19 26 (8) (11) (8) 260 $ $ 71 (2) 1 (4) (10) (2) 54 1 2 (1) (3) (4) 49 15 1 (2) (7) (4) 52 $ $ 267 18 45 (19) (27) (2) 282 (6) 41 (6) (9) (11) 291 34 27 (10) (18) (12) 312 It is expected that the amount of unrecognized tax benefits will change in the next twelve months due to expiring statutes, audit activity, tax payments, competent authority proceedings related to transfer pricing or final decisions in matters that are the subject of litigation in various taxing jurisdictions in which we operate. At December 31, 2015, we had approximately $80 million of tax liabilities, net of $13 million of tax assets, related to uncertain tax positions, each of which are individually insignificant, and each of which are reasonably possible of being settled within the next twelve months. At December 31, 2015, approximately $219 million of tax liabilities for total gross unrecognized tax benefits were included in the noncurrent portion of our income tax liabilities, for which the settlement period cannot be determined; however, it is not expected to be within the next twelve months. We operate in more than 80 countries and are subject to income taxes in most taxing jurisdictions in which we operate. The following table summarizes the earliest tax years that remain subject to examination by the major taxing jurisdictions in which we operate. In addition to the U.S., we include foreign jurisdictions that we project to have the highest tax liability for 2016. Jurisdiction Earliest Open Tax Period Jurisdiction Earliest Open Tax Period Argentina Norway 2008 2005 Ecuador Netherlands 2012 2010 Saudi Arabia U.S. 2004 2010 67 Baker Hughes Incorporated Notes to Consolidated Financial Statements NOTE 8. EARNINGS PER SHARE A reconciliation of the number of shares used for the basic and diluted loss or earnings per share (“EPS”) computations is as follows for the years ended December 31: Weighted average common shares outstanding for basic EPS Effect of dilutive securities - stock plans Adjusted weighted average common shares outstanding for diluted EPS Anti-dilutive shares excluded from diluted EPS (1) Future potentially dilutive shares excluded from diluted EPS (2) 2015 2014 2013 438 — 438 2 3 437 2 439 — 2 443 1 444 — 4 (1) The calculation of diluted net loss per share for 2015, excludes shares potentially issuable under stock- based incentive compensation plans and the employee stock purchase plan, as their effect, if included, would have been anti-dilutive. (2) Options where the exercise price exceeds the average market price are excluded from the calculation of diluted net loss or earnings per share because their effect would be anti-dilutive. NOTE 9. INVENTORIES Inventories, net of reserves of $278 million and $319 million in 2015 and 2014, respectively, are comprised of the following at December 31: Finished goods Work in process Raw materials Total inventories 2015 $ 2,649 132 136 $ 2,917 2014 $ 3,644 227 203 $ 4,074 During 2015, we recorded a charge of $194 million to adjust the carrying value of certain inventory. See Note 3. "Impairment and Restructuring Charges" for further discussion. NOTE 10. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment are comprised of the following at December 31: Land Buildings and improvements Machinery, equipment and other Subtotal Less: Accumulated depreciation Total property, plant and equipment Useful Life 2015 2014 5 - 30 years 1 - 20 years $ 263 $ 286 2,624 11,184 14,071 7,378 2,718 14,274 17,278 8,215 $ 6,693 $ 9,063 Depreciation expense relating to property, plant and equipment was $1,637 million, $1,706 million and $1,579 million in 2015, 2014 and 2013, respectively. During 2015, we recorded impairment charges relating to property, plant and equipment totaling $1.32 billion. See Note 3. "Impairment and Restructuring Charges" for further discussion. 68 Baker Hughes Incorporated Notes to Consolidated Financial Statements NOTE 11. GOODWILL AND INTANGIBLE ASSETS The changes in the carrying amount of goodwill are detailed below by segment. Balance at December 31, 2014 Currency translation adjustments Balance at December 31, 2015 North America $ 3,102 (5) $ 3,097 Latin America 587 $ Europe/ Africa/ Russia Caspian $ 1,068 (3) — $ 584 $ 1,068 Middle East/ Asia Pacific $ $ 819 — 819 Industrial Services 505 $ Total Goodwill $ 6,081 (3) (11) $ 502 $ 6,070 We perform an annual impairment test of goodwill as of October 1 of every year. There were no impairments of goodwill in any of the three years ended December 31, 2015 related to the annual impairment test. Intangible assets are comprised of the following at December 31: Gross Carrying Amount Technology Customer relationships (1) Trade names (1) Other Total intangibles $ $ 866 251 108 18 1,243 2015 Less: Accumulated Amortization 452 $ 106 89 13 660 $ Net 414 145 19 5 583 $ $ Gross Carrying Amount $ $ 870 488 120 23 1,501 2014 Less: Accumulated Amortization 393 $ 191 92 13 689 $ Net 477 297 28 10 812 $ $ (1) During 2015, we recorded impairments relating to our customer relationships and trade names intangible assets totaling $116 million. See Note 3. "Impairment and Restructuring Charges" for further discussion. Intangible assets are generally amortized on a straight-line basis with estimated useful lives ranging from 3 to 30 years. Amortization expense for the years ended December 31, 2015, 2014 and 2013 was $104 million, $107 million and $119 million, respectively. Estimated amortization expense for each of the subsequent five fiscal years is expected to be as follows: Year 2016 2017 2018 2019 2020 Estimated Amortization Expense $ 87 84 77 72 62 69 Baker Hughes Incorporated Notes to Consolidated Financial Statements NOTE 12. INDEBTEDNESS Total debt consisted of the following at December 31, net of unamortized discount and debt issuance cost: 6.0% Notes due June 2018 7.5% Senior Notes due November 2018 3.2% Senior Notes due August 2021 8.55% Debentures due June 2024 6.875% Notes due January 2029 5.125% Notes due September 2040 Other debt Total debt Less: short-term debt and current portion of long-term debt Total long-term debt $ 2015 2014 $ 255 747 746 149 394 258 746 745 148 394 1,482 1,481 268 361 4,041 4,133 151 220 $ 3,890 $ 3,913 The estimated fair value of total debt at December 31, 2015 and 2014 was $4,321 million and $4,663 million, respectively, which differs from the carrying amounts of $4,041 million and $4,133 million, respectively, included in our consolidated balance sheets. The fair value was determined using quoted period end market prices. At December 31, 2015, we have a committed revolving credit facility (“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. The credit facility matures in September 2016. As of December 31, 2015, we were in compliance with all of the credit facility's covenants, and there were no direct borrowings under the credit facility during 2015. 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, 2015, we had no borrowings outstanding under the commercial paper program. Maturities of debt at December 31, 2015 are as follows: 2016 - $151 million; 2017 - $24 million; 2018 - $1,024 million; 2019 - $22 million; 2020 - $12 million; and $2,808 million thereafter. The weighted average interest rate on short-term borrowings outstanding at December 31, 2015 and 2014 were 12.0% and 10.0%, respectively. NOTE 13. EMPLOYEE BENEFIT PLANS DEFINED BENEFIT PLANS We have both funded and unfunded noncontributory defined benefit pension plans (“Pension Benefits”) covering certain employees primarily in the U.S., the U.K., Germany and Canada. Under the provisions of the U.S. qualified pension plan (the “U.S. Pension Plan”), a hypothetical cash balance account is established for each participant. Such accounts receive quarterly credits based on a percentage according to the employee’s age on the last day of the quarter applied to quarterly eligible compensation and interest credits based on the balance in the account on the last day of the quarter. The U.K. and Canada plans are frozen for the majority of the participants; therefore, we do not accrue benefits for those participants. The Germany pension plan is an unfunded plan where benefits are based on creditable years of service, creditable pay and accrual rates. We also provide certain postretirement health care benefits (“Other Postretirement Benefits”), through an unfunded plan, to a closed group of U.S. employees who retire and have met certain age and service requirements. During 2015, as a result of the workforce reductions stemming from our restructuring activities, we remeasured certain pension and other postretirement benefit obligations, which resulted in reductions in our projected benefit obligations of $28 million, and curtailment gains of $18 million. 70 Baker Hughes Incorporated Notes to Consolidated Financial Statements Funded Status Below is the reconciliation of the beginning and ending balances of benefit obligations, fair value of plan assets and the funded status of our plans. U.S. Pension Benefits Non-U.S. Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 2015 2014 Change in benefit obligation: Benefit obligation at beginning of year Service cost Interest cost Actuarial loss (gain) Benefits paid Plan amendments Curtailment Other Foreign currency translation adjustments Benefit obligation at end of year Change in plan assets: Fair value of plan assets at beginning of year Actual return on plan assets Employer contributions Benefits paid Other Foreign currency translation adjustments Fair value of plan assets at end of year $ 728 64 26 (4) (59) — (24) 4 — 735 648 (5) 16 (59) (5) — 595 Funded status - underfunded at end of year $ (140) Accumulated benefit obligation $ 681 $ $ $ 649 70 28 21 (35) — — (5) — 728 617 39 32 (35) (5) — 648 (80) 662 $ $ $ 872 15 30 (23) (35) — (2) (6) (53) 798 767 4 28 (35) (6) (45) 713 $ 799 11 34 120 (29) — — (3) (60) 872 645 122 78 (29) — (49) 767 $ 122 5 4 (10) (11) — (2) (1) — 107 — — 11 (11) — — — $ 128 6 5 1 (7) (11) — — — 122 — — 7 (7) — — — (85) $ (105) $ (107) $ (122) 763 $ 832 $ 107 $ 122 The amounts recognized in the consolidated balance sheets consist of the following at December 31: Noncurrent assets Current liabilities Noncurrent liabilities Net amount recognized U.S. Pension Benefits Non-U.S. Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 2015 2014 $ — $ — $ (2) (138) $ (140) (2) (78) (80) $ $ 51 (6) (130) (85) $ 42 (7) (140) $ (105) $ — $ — (13) (109) $ (122) (16) (91) $ (107) The funded status position represents the difference between the benefit obligation and the plan assets. The projected benefit obligation (“PBO”) for pension benefits represents the actuarial present value of benefits attributed to employee services and compensation and includes an assumption about future compensation levels. The accumulated benefit obligation (“ABO”) is the actuarial present value of pension benefits attributed to employee service to date and present compensation levels. The ABO differs from the PBO in that the ABO does not include any assumptions about future compensation levels. 71 Baker Hughes Incorporated Notes to Consolidated Financial Statements Information for the plans with ABOs in excess of plan assets is as follows at December 31: Projected benefit obligation Accumulated benefit obligation Fair value of plan assets U.S. Pension Benefits Non-U.S. Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 2015 2014 $ $ $ 735 681 595 $ $ 19 18 $ — $ $ $ 149 114 12 $ $ $ 164 125 17 n/a n/a $ 107 $ 122 n/a n/a Weighted average assumptions used to determine benefit obligations for these plans are as follows for the years ended December 31: Discount rate Rate of compensation increase Social security increase U.S. Pension Benefits Non-U.S. Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 4.2% 5.9% 2.8% 3.8% 5.8% 2.8% 3.7% 4.1% 2.2% 3.5% 4.1% 2.1% 2015 3.7% n/a n/a 2014 3.4% n/a n/a The development of the discount rate for our U.S. plans and substantially all non-U.S. plans was based on a bond matching model, whereby a hypothetical bond portfolio of high-quality, fixed-income securities is selected that will match the cash flows underlying the projected benefit obligation. Accumulated Other Comprehensive Loss The amount recorded before-tax in accumulated other comprehensive loss related to employee benefit plans consists of the following at December 31: Net actuarial loss Net prior service cost (credit) Total U.S. Pension Benefits Non-U.S. Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 2015 2014 $ $ 191 — 191 $ $ 174 1 175 $ $ 229 — 229 $ $ 231 — 231 $ $ 10 (54) (44) $ $ 25 (83) (58) The estimated net actuarial loss and prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive loss and included in net periodic benefit cost in 2016 are $17 million and $0.3 million, respectively. The estimated prior service credit for the other postretirement benefits that will be amortized from accumulated other comprehensive loss and included in net periodic benefit cost in 2016 is $9 million. No amortization of the net actuarial loss for the other postretirement benefits from accumulated other comprehensive loss is expected in 2016. 72 Baker Hughes Incorporated Notes to Consolidated Financial Statements Net Periodic Cost The components of net periodic cost are as follows for the years ended December 31: Service cost Interest cost Expected return on plan assets Amortization of prior service credit Amortization of net actuarial loss Curtailment gain Other Net periodic cost U.S. Pension Benefits Non-U.S. Pension Benefits Other Postretirement Benefits 2015 $ 64 26 (49) 1 9 — 8 $ 59 2014 $ 70 2013 $ 65 2015 $ 15 2014 $ 11 2013 $ 12 2015 5 $ 2014 6 $ 2013 6 $ 28 (44) 21 (39) — 8 — — — 13 — — $ 62 $ 60 $ 30 (47) — 6 (1) — 3 34 (41) 31 (37) 4 — 5 — — 5 — — 9 $ — 8 — 2 (11) (11) 1 (17) — 1 — (3) $ 16 $ (18) $ (2) $ 5 — (7) 2 — — 6 Weighted average assumptions used to determine net periodic cost for these plans are as follows for the years ended December 31: U.S. Pension Benefits Non-U.S. Pension Benefits Other Postretirement Benefits Discount rate 2014 2015 2014 3.7% 4.5% 3.6% 3.5% 4.4% 4.4% 3.3% 4.0% 3.2% 2013 2014 2013 2015 2013 2015 Expected long-term return on plan assets 7.6% 7.3% 7.4% 6.3% 6.1% 6.5% Rate of compensation increase 5.8% 5.6% 5.6% 4.1% 4.4% 4.4% Social security increase 2.8% 2.8% 2.8% 2.1% 2.4% 2.1% n/a n/a n/a n/a n/a n/a n/a n/a n/a In selecting the expected rate of return on plan assets, we consider the average rate of earnings expected on the funds invested or to be invested to provide for the benefits of these plans. This includes considering the trusts’ asset allocation and the expected returns likely to be earned over the life of the plans. Health Care Cost Trend Rates Assumed health care cost trend rates can have a significant effect on the amounts reported for other postretirement benefits. As of December 31, 2015, the health care cost trend rate was 7.3% for employees under age 65, declining gradually each successive year until it reaches 4.5%. A one percentage point change in assumed health care cost trend rates would have had the following effects on 2015: Effect on total of service and interest cost components Effect on postretirement welfare benefit obligation Plan Assets One Percentage Point Increase One Percentage Point Decrease $ $ 0.1 0.9 $ $ (0.1) (1.2) We have investment committees that meet regularly to review the portfolio returns and to determine asset-mix targets based on asset/liability studies. Third-party investment consultants assist such committees in developing asset allocation strategies to determine our expected rates of return and expected risk for various investment portfolios. The investment committees considered these strategies in the formal establishment of the current asset- mix targets based on the projected risk and return levels for all major asset classes. 73 Baker Hughes Incorporated Notes to Consolidated Financial Statements The majority of investments are held in the form of units of funds. The funds hold underlying securities and are redeemable as of the measurement date. Investments in equities and fixed-income funds are generally measured at fair value based on daily closing prices provided by active exchanges or on the basis of observable, market- based inputs. Investments in hedge funds are generally measured at fair value on the basis of their net asset values, which are provided by the investment sponsor or third party administrator. The fair values of private equity investments and real estate funds are based on appraised values developed using comparable market transactions or discounted cash flows. U.S. Pension Plan The investment policy of the U.S. Pension Plan was developed after examining the historical relationships of risk and return among asset classes and the relationship between the expected behavior of the U.S. Plan’s assets and liabilities. The investment policy of the U.S. Plan is designed to provide the greatest probability of meeting or exceeding the U.S. Plan’s objectives at the lowest possible risk. In evaluating risk, the investment committee for the U.S. Pension Plan (“U.S. Committee”) reviews the long-term characteristics of various asset classes, focusing on balancing risk with expected return. Accordingly, the U.S. Committee selected the following six asset classes as allowable investments for the assets of the U.S. Pension Plan: U.S. equities, non-U.S. equities, global fixed-income securities, real estate, hedge funds and private equity. The table below presents the fair value of the assets in the U.S. Pension Plan by asset category and by valuation technique at December 31: Asset Category Cash and Cash Equivalents Fixed Income (1) Non-U.S. Equity (2) U.S. Equity (3) Hedge Funds (4) Real Estate Funds (5) Real Estate Investment Trust Equity Private Equity Fund (6) Total 2015 2014 Total Asset Value 16 $ 109 129 129 152 10 9 41 Level One $ 12 — 31 — — — — — Level Two $ 4 Level Three $ — $ Total Asset Value 3 Level One Level Two $ — $ 3 Level Three $ — 109 98 129 — — 9 — — — — 152 10 — 41 125 148 169 164 10 8 21 — 30 — — — — — 125 118 169 — — 8 — — — — 164 10 — 21 $ 595 $ 43 $ 349 $ 203 $ 648 $ 30 $ 423 $ 195 (1) A multi-manager strategy investing in fixed income securities and funds. The current allocation includes: 29% in government bonds; 24% in government agencies; 20% in unconstrained bond funds; 11% in corporate bonds; 11% in government mortgage-backed securities; 3% in asset-backed securities; and 2% in cash and other securities. (2) Multi-manager strategy investing in common stocks of non-U.S. listed companies using both value and growth approaches. (3) Multi-manager strategy investing in common stocks of U.S. listed companies using value and growth approaches. (4) Strategies taking long and short positions in equities, fixed income securities, currencies and derivative contracts. (5) Strategy investing in the global private real estate secondary market using a value-based investment approach. (6) Partnership making opportunistic investments on a global basis across asset classes, capital structures and geographies. 74 Baker Hughes Incorporated Notes to Consolidated Financial Statements Non-U.S. Pension Plans The investment policies of our pension plans with plan assets, which are primarily in Canada and the U.K., (the “Non-U.S. Plans”), cover the asset allocations that the governing boards believe are the most appropriate for these Non-U.S. Plans in the long-term, taking into account the nature of the liabilities they expect to incur. The suitability of asset allocations and investment policies are reviewed periodically to ensure alignment with plan liabilities. The table below presents the fair value of the assets in our Non-U.S. Plans by asset category and by valuation technique at December 31: 2015 2014 Asset Category Cash and Cash Equivalents Asset Allocation (1) Bonds - Canada - Corporate (2) Bonds - Canada - Government (3) Bonds - U.K. - Corporate (4) Bonds - U.K. - Government (5) Bonds - Global - Corporate (6) Equities (7) Real Estate Fund (8) Pooled Swap Funds (9) Insurance contracts Total Asset Value 5 $ 152 6 19 8 211 64 128 23 85 12 Total $ 713 $ 5 — — — — — — — — — — 5 Level One Level Two Level Three $ $ — $ — $ Total Asset Value 10 Level One $ 10 Level Two Level Three $ — $ — 152 6 19 8 211 64 128 — 85 — $ 673 $ — — — — — — — 23 — 12 35 124 — 25 113 196 — 133 22 127 17 — — — — — — — — — — 124 — 25 113 196 — 133 — 127 — $ 767 $ 10 $ 718 $ — — — — — — — 22 — 17 39 (1) (2) (3) (4) (5) (6) (7) (8) (9) Invests in mixes of global common stocks and bonds to achieve broad diversification. Invests in Canadian Dollar-denominated high quality corporate bonds. Invests in Canadian Dollar-denominated government issued bonds intended to match the duration of plan liabilities. Invests passively in British Pound Sterling-denominated investment grade corporate bonds. Invests passively in British Pound Sterling-denominated government issued bonds. Invests globally in high quality corporate bonds. Invests in broad equity funds based on securities offered in various regions or countries. Equity funds are allocated by region as follows: 49% Global; 31% U.K.; 6% Emerging Markets; 5% North America; 5% Asia Pacific; and 4% Europe. Invests in a diversified range of property throughout the U.K., principally in the retail, office and industrial/ warehouse sectors. Invests in a range of pooled funds which include positions in swap contracts and U.K. sovereign bonds; pooled funds are categorized by maturities of underlying positions. Pooled funds employ leverage in order to match the U.K. Plan's duration and inflation. 75 Baker Hughes Incorporated Notes to Consolidated Financial Statements The following table presents the changes in the fair value of assets determined using level 3 unobservable inputs: U.S. Private Equity Fund U.S. Real Estate Fund U.S. Hedge Funds Non-U.S. Real Estate Fund 16 2 — (10) 8 16 — 1 (4) 8 21 — — (4) 24 41 $ $ 7 — — — 2 9 1 — — — 10 — 1 (2) 1 10 $ 172 $ 12 7 (84) 83 190 6 7 (85) 46 164 (6) 1 (15) 8 $ 152 $ 20 1 — — — 21 1 — — — 22 — — — 1 23 Non-U.S. Insurance Contracts 16 $ Total $ 231 2 — (2) 2 18 (1) — — — 17 (2) — (5) 2 12 $ 17 7 (96) 95 254 7 8 (89) 54 234 (8) 2 (26) 36 238 $ Balance at December 31, 2012 $ Unrealized gains Realized gains Sales Purchases Balance at December 31, 2013 Unrealized gains (losses) Realized gains Sales Purchases Balance at December 31, 2014 Unrealized losses Realized gains Sales Purchases Balance at December 31, 2015 $ Expected Cash Flows For all pension plans, we make annual contributions to the plans in amounts equal to or greater than amounts necessary to meet minimum governmental funding requirements. In 2016, we expect to contribute between $65 million and $75 million to our funded and unfunded pension plans. In 2016, we also expect to make benefit payments related to other postretirement benefits of between $15 million and $20 million. The following table presents the expected benefit payments over the next ten years. The U.S. and non-U.S. pension benefit payments are made by the respective pension trust funds. Year 2016 2017 2018 2019 2020 2021-2025 U.S. Pension Benefits 47 $ Non-U.S. Pension Benefits 24 $ Other Postretirement Benefits 17 $ $ $ $ $ $ 41 43 46 48 280 $ $ $ $ $ 25 28 33 32 204 $ $ $ $ $ 13 11 10 10 43 DEFINED CONTRIBUTION PLANS During the periods reported, generally all of our U.S. employees were eligible to participate in our sponsored 401(k) plan (“Thrift Plan”). The Thrift Plan allows eligible employees to elect to contribute portions of their salaries to an investment trust. Employee contributions are matched by the Company in cash at the rate of $1.00 per $1.00 employee contribution for the first 5% of the employee’s salary, and such contributions vest immediately. In addition, we make cash contributions for all eligible employees between 2% and 5% of their salary depending on 76 Baker Hughes Incorporated Notes to Consolidated Financial Statements the employee’s age. Such contributions are fully vested to the employee after three years of employment. The Thrift Plan provides several investment options, for which the employee has sole investment discretion. The Thrift Plan does not offer the Company's common stock as an investment option. Our contributions to the Thrift Plan and several other non-U.S. defined contribution plans amounted to $202 million, $263 million and $240 million in 2015, 2014 and 2013, respectively. For certain non-U.S. employees who are not eligible to participate in the Thrift Plan, we provide a non-qualified defined contribution international retirement plan that provides basically the same benefits as those provided in the Thrift Plan. In addition, we provide a non-qualified supplemental retirement plan (“SRP”) for certain officers and employees whose benefits under the Thrift Plans and/or the U.S. qualified pension plan are limited by federal tax law. The SRP also allows eligible employees to defer a portion of their eligible compensation and provides for employer matching and base contributions pursuant to limitations. Both non-qualified plans are invested through trusts, and the assets and corresponding liabilities are included in our consolidated balance sheets. Our contributions to these non-qualified plans amounted to $15 million, $17 million and $15 million in 2015, 2014 and 2013, respectively. In 2016, we estimate we will contribute between $165 million and $180 million to all of our defined contribution plans. POSTEMPLOYMENT BENEFITS We provide certain postemployment disability income, medical and other benefits to substantially all qualifying former or inactive U.S. employees. Income benefits for long-term disability are provided through a fully-insured plan. The continuation of medical and other benefits while on disability (“Continuation Benefits”) are provided through a qualified self-insured plan. The accrued postemployment liability for Continuation Benefits at December 31, 2015 and 2014 was $34 million and $30 million, respectively, and is included in other liabilities in our consolidated balance sheets. NOTE 14. COMMITMENTS AND CONTINGENCIES LEASES At December 31, 2015, we had long-term non-cancelable operating leases covering certain facilities and equipment. The minimum annual rental commitments, net of amounts due under subleases, for each of the five years in the period ending December 31, 2020 are $183 million, $119 million, $65 million, $51 million and $21 million, respectively, and $151 million in the aggregate thereafter. Rent expense was $514 million, $747 million and $702 million for the years ended December 31, 2015, 2014 and 2013, respectively. We did not enter into any significant capital leases during the three years ended December 31, 2015. LITIGATION 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. 77 Baker Hughes Incorporated Notes to Consolidated Financial Statements The following lawsuits have been filed in Delaware in connection with our pending Merger with Halliburton: • 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 Annettee 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. 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 remains subject to certain conditions, including consummation of the Merger, final documentation, and court approval. On November 26, 2014, a seventh class action challenging the Merger was filed by a purported shareholder of the Company in the United States District Court for the Southern District of Texas (Houston Division). The lawsuit, styled Marc Rovner v. Baker Hughes Inc., et al., Cause No. 4:14-cv-03416 (the "Rovner lawsuit"), asserts claims against the Company, most of our current Board of Directors, Halliburton, and Red Tiger. The lawsuit asserts substantially similar claims and seeks substantially similar relief as that sought in the Delaware lawsuits. On March 20, 2015, counsel for Mr. Rovner filed a notice of voluntary dismissal, and on March 23, 2015, the Court entered an order dismissing the Rovner lawsuit without prejudice. On October 9, 2014, our subsidiary 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. The due date for payment of all of these invoices has passed. On November 6, 2014, the customer filed its Response and Counterclaim, denying liability and counterclaiming damages for breach of contract of approximately $182 million. We deny any liability to the customer and intend to pursue our claims against the customer and defend the claims made under the counterclaim. The Parties have applied to the 78 Baker Hughes Incorporated Notes to Consolidated Financial Statements arbitration tribunal to extend the suspension of the arbitral proceedings to March 31, 2016, pending ongoing settlement discussions. No timetable for the conduct of the arbitration has yet been established. 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). The customer alleges damages of approximately $170 million plus interest at an annual rate of prime + 5%. A procedural schedule for the arbitration has not yet been set. 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. On December 15, 2015, the District Court entered an order staying the lawsuit in favor of the pending German Arbitration. At this time, we are not able to predict the outcome of these claims or whether either will have a 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 has 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. Investigation is ongoing as to the merits of the claim. At this time, we are not able to predict the outcome of this claim or whether it will 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 alleges that the Company failed to purchase the required sand tonnage for the contract year 2014-2015 and further alleges that the Company repudiated its yearly purchase obligations over the remaining contract term. The Claimant alleges damages of approximately $110 million plus interest, attorneys’ fees and costs. A procedural schedule for the arbitrations has not yet been set. The Company intends to vigorously defend the claim. At this time, we are not able to predict the outcome of this claim or whether it will have a material impact on our financial position, results of operations or cash flows. During the second quarter of 2014, we recorded a charge of $62 million related to previously disclosed litigation settlements for wage and hour lawsuits. A portion of this settlement was to be paid on a claims made basis and during the second quarter of 2015, the date passed by which the class members could file a claim under this provision of the settlement agreement. The amount of claims made was less than estimated and, accordingly, we reduced the accrual by approximately $13 million, which was recorded as an adjustment for litigation settlements during the second quarter of 2015. 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. We are evaluating the background facts and at this time are not able to predict the outcome of this lawsuit or whether it will have a material impact 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 LLC and Packers Plus Energy Services Inc., sued Baker Hughes Canada Company in the Canada 79 Baker Hughes Incorporated Notes to Consolidated Financial Statements Federal Court on related Canadian patent 2,412,072. These patents relate primarily to certain specific downhole completions equipment. The case is set for a jury trial on September 25, 2017, in Tyler, Texas. 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. At this time, we are not able to predict the outcome of these claims or whether either will have a material impact on our financial position, results of operations or cash flows. 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 seeks 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. We are working with the DOJ to provide the requested documents and information. We are not able to predict what action, if any, might be taken in the future by the DOJ or other governmental authorities as a result of the investigation. ENVIRONMENTAL MATTERS Our past and present operations include activities that are subject to extensive domestic (including U.S. federal, state and local) and international environmental regulations with regard to air, land and water quality and other environmental matters. Our environmental procedures, policies and practices are designed to ensure compliance with existing laws and regulations and to minimize the possibility of significant environmental damage. We 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. Remediation costs are accrued based on estimates of probable exposure using currently available facts, existing environmental permits, technology and presently enacted laws and regulations. Remediation cost estimates include direct costs related to the environmental investigation, external consulting activities, governmental oversight fees, treatment equipment and costs associated with long-term operation, maintenance and monitoring of a remediation project. We have also been identified as a potentially responsible party (“PRP”) in remedial activities related to various Superfund sites. In these instances, we participate in the process set out in the Joint Participation and Defense Agreement to negotiate with government agencies, identify other PRPs, and determine each PRP’s allocation and estimate remediation costs. We have accrued what we believe to be our pro-rata share of the total estimated cost of remediation and associated management of these Superfund sites. This share is based upon the ratio that the estimated volume of waste we contributed to the site to the total estimated volume of waste disposed at the site. Applicable U.S. federal law imposes joint and several liability on each PRP for the cleanup of these sites leaving us with the uncertainty that we may be responsible for the remediation cost attributable to other PRPs who are unable to pay their share. No accrual has been made under the joint and several liability concept for those Superfund sites where our participation is de minimis since we believe that the probability that we will have to pay material costs above our volumetric share is remote. We believe there are other PRPs who have greater involvement on a volumetric calculation basis, who have substantial assets and who may be reasonably expected to pay their share of the cost of remediation. For those Superfund sites where we are a significant PRP, remediation costs are estimated to include recalcitrant parties. In some cases, we have insurance coverage or contractual indemnities from third parties to cover a portion of the ultimate liability. Our total accrual for environmental remediation is $35 million and $35 million, which includes accruals of $2 million and $3 million for the various Superfund sites, at December 31, 2015 and 2014, respectively. The determination of the required accruals for remediation costs is subject to uncertainty, including the evolving nature of environmental regulations and the difficulty in estimating the extent and type of remediation activity that is necessary. OTHER 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 $1.2 billion at December 31, 2015. 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 80 Baker Hughes Incorporated Notes to Consolidated Financial Statements on our consolidated financial statements. We also had commitments outstanding for purchase obligations related to capital expenditures, inventory and services under contracts, for each of the five years in the period ending December 31, 2020 of $202 million, $187 million, $162 million, $124 million and $106 million, respectively, and $67 million in the aggregate thereafter. NOTE 15. ACCUMULATED OTHER COMPREHENSIVE LOSS The following table presents the changes in accumulated other comprehensive loss, net of tax: Balance at December 31, 2013 Other comprehensive income before reclassifications: Foreign currency translation adjustments Pensions and other postretirement benefits: Actuarial net loss arising in the year Deferred taxes Amounts reclassified from accumulated other comprehensive loss: Amortization of net actuarial loss Amortization of prior service credit Deferred taxes Balance at December 31, 2014 Other comprehensive income before reclassifications: Foreign currency translation adjustments Pensions and other postretirement benefits: Actuarial net loss arising in the year Deferred taxes Amounts reclassified from accumulated other comprehensive loss: Amortization of net actuarial loss Amortization of prior service credit Curtailment Deferred taxes Balance at December 31, 2015 $ Pensions and Other Postretirement Benefits Foreign Currency Translation Adjustments Accumulated Other Comprehensive Loss $ (217) $ (287) $ (504) (216) (216) (38) 10 14 (14) (1) (246) (18) 10 16 (10) (18) 5 (261) $ (38) 10 14 (14) (1) (749) (241) (18) 10 16 (10) (18) 5 (1,005) (503) (241) (744) $ The amounts reclassified from accumulated other comprehensive loss during the twelve months ended December 31, 2015 and 2014 represent the amortization of net actuarial loss and prior service credit, and curtailments which are included in the computation of net periodic pension cost (see Note 13. "Employee Benefit Plans" for additional details). Net periodic pension cost is recorded across the various cost and expense line items within the consolidated statement of income (loss). 81 Baker Hughes Incorporated Notes to Consolidated Financial Statements NOTE 16. QUARTERLY DATA (UNAUDITED) 2015 Revenue Gross profit (1) Impairment and restructuring charges (2) Net loss attributable to Baker Hughes Basic loss per share attributable to Baker Hughes Diluted loss per share attributable to Baker Hughes Dividends per share Common stock market prices: High Low First Quarter Second Quarter Third Quarter Fourth Quarter Total Year $ 4,594 $ 3,968 $ 3,786 $ 3,394 $ 15,742 114 573 (589) (1.35) (1.35) 0.17 229 76 (188) (0.43) (0.43) 0.17 268 98 (159) (0.36) (0.36) 0.17 146 1,246 757 1,993 (1,031) (1,967) (2.35) (2.35) 0.17 (4.49) (4.49) 0.68 65.04 53.53 69.13 61.11 61.13 45.76 57.33 43.36 2014 Revenue Gross profit (1) Net income attributable to Baker Hughes Basic earnings per share attributable to Baker Hughes Diluted earnings per share attributable to Baker Hughes Dividends per share Common stock market prices: High Low $ 5,731 $ 5,935 $ 6,250 $ 6,635 $ 24,551 868 328 0.75 0.74 0.15 65.27 51.82 1,031 353 0.81 0.80 0.15 74.63 63.37 984 375 0.86 0.86 0.17 75.35 65.06 1,309 663 1.53 1.52 0.17 65.83 50.02 4,192 1,719 3.93 3.92 0.64 (1) Represents revenue less cost of sales, cost of services and research and engineering. (2) Impairment and restructuring charges associated with asset impairments, workforce reductions, facility closures and contract terminations recorded during 2015. See Note 3. "Impairment and Restructuring Charges" for further discussion. 82 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures As of the end of the period covered by this annual report, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act of 1934, as amended (the “Exchange Act”). This evaluation was carried out under the supervision and with the participation of our management, including our principal executive officer and principal financial officer. Based on this evaluation, these officers have concluded that, as of December 31, 2015, our disclosure controls and procedures, as defined by Rule 13a-15(e) of the Exchange Act, are effective at a reasonable assurance level. Disclosure controls and procedures are our controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act, such as this annual report, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Design and Evaluation of Internal Control Over Financial Reporting Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, our management included a report of their assessment of the design and effectiveness of our internal controls over financial reporting as part of this annual report on Form 10-K for the fiscal year ended December 31, 2015. Deloitte & Touche LLP, the Company’s independent registered public accounting firm, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting. Management’s report and the independent registered public accounting firm’s attestation report are included in Item 8 under the caption entitled “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm” and are incorporated herein by reference. Changes in Internal Control Over Financial Reporting There has been no change in our internal controls over financial reporting during the quarter ended December 31, 2015 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting. ITEM 9B. OTHER INFORMATION None. 83 PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE Information regarding the Business Code of Conduct and Code of Ethical Conduct Certificates for our principal executive officer, principal financial officer and principal accounting officer are described in Item 1. Business of this Annual Report. Information concerning our directors is set forth in the sections entitled “Proposal No. 1, Election of Directors,” and “Corporate Governance - Committees of the Board” in our Definitive Proxy Statement for the 2016 Annual Meeting of Stockholders to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2015 (“Proxy Statement”), which sections are incorporated herein by reference. For information regarding our executive officers, see “Item 1. Business - Executive Officers” in this annual report on Form 10-K. Additional information regarding compliance by directors and executive officers with Section 16(a) of the Exchange Act is set forth under the section entitled “Compliance with Section 16(a) of the Securities Exchange Act of 1934” in our Proxy Statement, which section is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION Information for this item is set forth in the following sections of our Proxy Statement, which sections are incorporated herein by reference: “Compensation Discussion and Analysis,” “Director Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report.” ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Information concerning security ownership of certain beneficial owners and our management is set forth in the sections entitled “Voting Securities” and “Security Ownership of Management” in our Proxy Statement, which sections are incorporated herein by reference. Our Board of Directors has approved procedures for use under our Securities Trading and Disclosure Policy to permit our employees, officers and directors to enter into written trading plans complying with Rule 10b5-1 under the Exchange Act. Rule 10b5-1 provides criteria under which such an individual may establish a prearranged plan to buy or sell a specified number of shares of a company’s stock over a set period of time. Any such plan must be entered into in good faith at a time when the individual is not in possession of material, nonpublic information. If an individual establishes a plan satisfying the requirements of Rule 10b5-1, such individual’s subsequent receipt of material, nonpublic information will not prevent transactions under the plan from being executed. Certain of our officers have advised us that they have and may enter into a stock sales plan for the sale of shares of our common stock which are intended to comply with the requirements of Rule 10b5-1 of the Exchange Act. In addition, the Company has and may in the future enter into repurchases of our common stock under a plan that complies with Rule 10b5-1 or Rule 10b-18 of the Exchange Act. Under the Merger Agreement with Halliburton, as described in Note 2. "Halliburton Merger Agreement," we have generally agreed not to repurchase any shares of common stock while the Merger is pending. Equity Compensation Plan Information The information in the following table is presented as of December 31, 2015 with respect to shares of our common stock that may be issued under our existing equity compensation plans, including the Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan, the Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan, and the Employee Stock Purchase Plan, all of which have been approved by our stockholders (in millions, except per share prices). 84 Equity Compensation Plan Category Stockholder-approved plans (excluding Employee Stock Purchase Plan) Nonstockholder-approved plans (1) Subtotal (except for weighted average exercise price) Employee Stock Purchase Plan (2) Total Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights Weighted Average Exercise Price of Outstanding Options, Warrants and Rights Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities reflected in the first column) 8.5 0.1 8.6 — 8.6 $ 54.57 46.72 54.56 — $ 54.56 20.8 0.5 21.3 4.2 25.5 (1) The table includes the following nonstockholder-approved plan: the Director Compensation Deferral Plan. A description of this plan is set forth below. (2) The per share purchase price under the Baker Hughes Incorporated Employee Stock Purchase Plan is determined in accordance with section 423 of the Code and is 85% of the lower of the fair market value of a share of our common stock on the date of grant or the date of purchase. Our nonstockholder-approved plan is described below: Director Compensation Deferral Plan The Baker Hughes Incorporated Director Compensation Deferral Plan, as amended and restated effective January 1, 2009 and as further amended on July 25, 2013 (the “Deferral Plan”), is intended to provide a means for members of our Board of Directors to defer compensation otherwise payable and provide flexibility with respect to our compensation policies. Under the provisions of the Deferral Plan, directors may elect to defer income with respect to each calendar year. The compensation deferrals may be stock option-related deferrals or cash-based deferrals. If a director elects a stock option-related deferral, on the last day of each calendar quarter he or she will be granted a non-qualified stock option. The number of shares subject to the stock option is calculated by multiplying the amount of the deferred compensation that otherwise would have been paid to the director during the quarter by 4.4 and then dividing by the fair market value of our common stock on the last day of the quarter. The per share exercise price of the option will be the fair market value of a share of our common stock on the date the option is granted. Stock options granted under the Deferral Plan vest on the first anniversary of the date of grant and must be exercised within ten years of the date of grant. If a director’s directorship terminates for any reason, any options outstanding will expire on the earlier of five years after the termination of the directorship or the option expiration date. The maximum aggregate number of shares of our common stock that may be issued under the Deferral Plan is 0.5 million. As of December 31, 2015, options covering approximately 17,000 shares of our common stock were outstanding under the Deferral Plan, there were no shares exercised during fiscal year 2015 and approximately 0.5 million shares remained available for future options. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE Information for this item is set forth in the sections entitled “Corporate Governance-Director Independence” and “Certain Relationships and Related Transactions” in our Proxy Statement, which sections are incorporated herein by reference. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES Information concerning principal accountant fees and services is set forth in the section entitled “Fees Paid to Deloitte & Touche LLP” in our Proxy Statement, which section is incorporated herein by reference. 85 PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (a) List of Documents filed as part of this annual report. (1) Financial Statements All financial statements of the Company as set forth under Item 8 of this annual report on Form 10-K. (2) Financial Statement Schedules Schedule II - Valuation and Qualifying Accounts (3) Exhibits Each exhibit identified below is filed as a part of this annual report. Exhibits designated with an "*" are filed as an exhibit to this annual report on Form 10-K and exhibits designated with an "**" are furnished as an exhibit to this annual report on Form 10-K. Exhibits designated with a "+" are identified as management contracts or compensatory plans or arrangements. Exhibits previously filed as indicated below are incorporated by reference. Exhibit Number 2.1 3.1 3.2 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9 4.10 Exhibit Description Agreement and Plan of Merger dated as of November 16, 2014 among Halliburton Company, Red Tiger LLC and Baker Hughes Incorporated (filed as Exhibit 2.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on November 18, 2014). Certificate of Amendment dated April 22, 2010 and the Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2010). Restated Bylaws of Baker Hughes Incorporated effective as of June 5, 2014 (filed as Exhibit 3.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on June 6, 2010). Rights of Holders of the Company’s Long-Term Debt. The Company has no long-term debt instrument with regard to which the securities authorized thereunder equal or exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. The Company agrees to furnish a copy of its long-term debt instruments to the SEC upon request. Certificate of Amendment dated April 22, 2010 and the Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2010). Restated Bylaws of Baker Hughes Incorporated effective as of June 5, 2014 (filed as Exhibit 3.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on June 6, 2010). Indenture dated as of May 15, 1994 between Western Atlas Inc. and The Bank of New York, Trustee, providing for the issuance of securities in series (filed as Exhibit 4.4 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2004). Indenture dated October 28, 2008, between Baker Hughes Incorporated and The Bank of New York Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on October 29, 2008). First Supplemental Indenture, dated August 17, 2011, between Baker Hughes Incorporated and The Bank of New York Mellon Trust Company, N.A., as trustee (including form of Notes) (filed as Exhibit 4.2 to the Current Report of Baker Hughes Incorporated on Form 8-K filed August 23, 2011). Officers’ Certificate of Baker Hughes Incorporated dated October 28, 2008 establishing the 6.50% Senior Notes due 2013 and the 7.50% Senior Notes due 2018 (filed as Exhibit 4.2 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on October 29, 2008). Form of 7.50% Senior Notes Due 2018 (filed as Exhibit 4.4 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on October 29, 2008). Officers’ Certificate of Baker Hughes Incorporated dated August 24, 2010 establishing the 5.125% Senior Notes due 2040 (filed as Exhibit 4.2 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on August 24, 2010). Form of 5.125% Senior Notes due 2040 (filed as Exhibit 4.3 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on August 24, 2010). 86 4.11 4.12 4.13 4.14 4.15 10.1+ 10.2+ 10.3+ 10.4+ 10.5+ 10.6+ 10.7+ 10.8+ 10.9+ 10.10+ 10.11+ 10.12+ 10.13+ 10.14+ Indenture, dated June 8, 2006, between BJ Services Company, as issuer, and Wells Fargo Bank, N.A., as trustee (filed as Exhibit 4.1 to the Current Report of BJ Services Company on Form 8-K filed on June 12, 2006). Third Supplemental Indenture, dated May 19, 2008, between BJ Services Company, as issuer, and Wells Fargo Bank, N.A., as trustee, with respect to the 6% Senior Notes due 2018 (filed as Exhibit 4.2 to the Current Report of BJ Services Company on Form 8-K filed on May 23, 2008). Fourth Supplemental Indenture, dated April 28, 2010, between BJ Services Company, as issuer, BSA Acquisition LLC, Baker Hughes Incorporated and Wells Fargo Bank, N.A., as trustee, with respect to the 5.75% Senior Notes due 2011 and the 6% Senior Notes due 2018 (filed as Exhibit 4.4 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on April 29, 2010). Fifth Supplemental Indenture, dated June 21, 2011, between BJ Services Company LLC, as company, Western Atlas Inc. as successor company and Wells Fargo Bank, N.A., as trustee, with respect to the 6.00% Senior Notes due 2018 (incorporated by reference to Exhibit 4.4 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on June 23, 2011). Registration Rights Agreement dated August 17, 2011 among Baker Hughes Incorporated and J.P. Morgan Securities LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representatives of the several initial purchasers named therein (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on August 23, 2011). Form of Amended and Restated Change in Control Agreement between Baker Hughes Incorporated and each of the executive officers effective as of January 1, 2009 (filed as Exhibit 10.2 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on December 19, 2008). Amendment and Restatement of the Baker Hughes Incorporated Change in Control Severance Plan effective as of January 1, 2009 (filed as Exhibit 10.3 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on December 19, 2008). Form of Change in Control Agreement between Baker Hughes Incorporated and certain of the executive officers effective as of July 16, 2012 (filed as Exhibit 10.1 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2012). Form of Executive Loyalty, Confidentiality, Non-Solicitation, and Non-Competition Agreement between Baker Hughes Incorporated and certain of the executive officers (filed as Exhibit 10.3 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2011). Baker Hughes Incorporated Compensation Recoupment Policy effective January 1, 2014 (filed as Exhibit 10.10 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 28, 2014). Letter Agreement between Baker Hughes Incorporated and Peter A. Ragauss dated December 8, 2013 (filed as Exhibit 10.4 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2013). Form of Indemnification Agreement between Baker Hughes Incorporated and each of the directors and executive officers (filed as Exhibit 10.4 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003). Form of Amendment to the Indemnification Agreement between Baker Hughes Incorporated and each of the directors and executive officers effective as of January 1, 2009 (filed as Exhibit 10.4 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on December 19, 2008). Baker Hughes Incorporated Director Retirement Policy for Certain Members of the Board of Directors (filed as Exhibit 10.10 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003). Baker Hughes Incorporated Director Compensation Deferral Plan, as amended and restated effective as of January 1, 2009 (filed as Exhibit 10.2 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2008). Amendment to Baker Hughes Incorporated Director Compensation Deferral Plan effective as of January 1, 2009 (filed as Exhibit 10.5 to the Current Report of Baker Hughes Incorporated on Form 8- K filed on December 19, 2008). Amendment to the Baker Hughes Incorporated Director Compensation Deferral Plan effective as of July 25, 2013 (filed as Exhibit 10.11 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2013). Baker Hughes Incorporated Executive Severance Plan, as amended and restated on February 7, 2008 (filed as Exhibit 10.17 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2007). Amendment to Exhibit A of Baker Hughes Incorporated Executive Severance Plan as of July 20, 2009 (filed as Exhibit 10.1 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2009). 87 10.15+ 10.16+ 10.17+ 10.18+ 10.19+ 10.20+ 10.21+ 10.22+ 10.23+ 10.24+ 10.25+ 10.26+ 10.27+ 10.28+ 10.29+ 10.30+ 10.31+ 10.32+ 10.33+ 10.34+ Amendment to Baker Hughes Incorporated Executive Severance Plan dated April 22, 2010 (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on April 23, 2010). Baker Hughes Incorporated Annual Incentive Compensation Plan for officers, as amended and restated on January 23, 2014 (filed as Exhibit 10.5 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 28, 2014). Amendment to the Amended and Restated Baker Hughes Incorporated Annual Incentive Compensation Plan for employees dated March 13, 2015 (filed as Exhibit 10.2 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on March 18, 2015). Baker Hughes Incorporated Supplemental Retirement Plan, as amended and restated effective as of January 1, 2012 (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8- K filed on December 20, 2011). Amended and Restated Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan effective April 24, 2014 (filed as Exhibit 10.2 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on April 29, 2014). Amended and Restated Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan effective April 24, 2014 (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on April 29, 2014). Baker Hughes Incorporated Employee Stock Purchase Plan, as amended and restated, effective as of January 1, 2012 (filed as Exhibit 10.25 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ending December 31, 2012). Amendment to the Baker Hughes Incorporated Employee Stock Purchase Plan effective as of April 25, 2013 (filed as Exhibit 10.2 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on April 30, 2013). Amendment to the Baker Hughes Incorporated Employee Stock Purchase Plan effective as of December 31, 2014 (filed as Exhibit 10.28 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the fiscal year ending December 31, 2014). Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement with Terms and Conditions for officers (filed as Exhibit 10.30 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2009). Form of Baker Hughes Incorporated Nonqualified Stock Option Award Agreement and Terms and Conditions for officers (filed as Exhibit 10.70 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2011). Form of Baker Hughes Incorporated Nonqualified Stock Option Award Agreement and Terms and Conditions for officers (filed as Exhibit 10.6 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 28, 2014). Form of Baker Hughes Incorporated Nonqualified Stock Option Award Agreement and Terms and Conditions for officers (filed as Exhibit 10.6 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2014). Form of Baker Hughes Incorporated Incentive Stock Option Award Agreement and Terms and Conditions for officers (filed as Exhibit 10.33 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2009). Form of Baker Hughes Incorporated Incentive Stock Option Award Agreement and Terms and Conditions for officers (filed as Exhibit 10.71 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2011). Form of Baker Hughes Incorporated Incentive Stock Option Award Agreement and Terms and Conditions for officers (filed as Exhibit 10.7 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 28, 2014). Form of Baker Hughes Incorporated Incentive Stock Option Award Agreement and Terms and Conditions for officers (filed as Exhibit 10.7 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2014). Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and Conditions for officers (filed as Exhibit 10.9 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 28, 2014). Form of Baker Hughes Incorporated Restricted Stock Award Agreement and Terms and Conditions for officers (filed as Exhibit 10.8 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 28, 2014). Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and Conditions for officers (filed as Exhibit 10.5 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2014). 88 10.35+ 10.36+ 10.37+ 10.38+ 10.39+ 10.40+ 10.41+ 10.42+ 10.43+ 10.44+ 10.45+ 10.46 10.47 21.1* 23.1* 31.1** 31.2** 32** 95* 99.1 Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and Conditions for officers (filed as Exhibit 10.42 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2014). Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and Conditions for directors (filed as Exhibit 10.44 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2014). Form of Baker Hughes Incorporated Stock Option Award Agreement, including Terms and Conditions for directors (filed as Exhibit 10.41 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2005). Form of Baker Hughes Incorporated Performance Unit Award Agreement and Terms and Conditions for officers (filed as Exhibit 10.72 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2011). Form of Baker Hughes Incorporated Performance Unit Award Agreement and Terms and Conditions for certain officers payable in cash (filed as Exhibit 10.3 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 28, 2014). Form of Baker Hughes Incorporated Performance Unit Award Agreement and Terms and Conditions for certain officers payable in shares (filed as Exhibit 10.4 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 28, 2014). Form of Baker Hughes Incorporated Performance Unit Award Agreement and Terms and Conditions for certain officers payable in cash (filed as Exhibit 10.3 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2014). Form of Baker Hughes Incorporated Performance Unit Award Agreement and Terms and Conditions for certain officers payable in shares (filed as Exhibit 10.4 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2014). Performance Goals adopted February 27, 2013 for the Performance Unit Awards granted in 2013 (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on March 4, 2013). Performance Goals adopted January 22, 2014 for the Performance Unit Awards payable in cash granted in 2014 (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 28, 2014). Performance Goals adopted January 22, 2014 for the Performance Unit Awards payable in shares granted in 2014 (filed as Exhibit 10.2 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 28, 2014). Credit Agreement dated as of September 13, 2011, among Baker Hughes Incorporated, JP Morgan Chase Bank, N.A., as Administrative Agent and twenty-one lenders for $2.5 billion, in the aggregate for all banks (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed September 14, 2011). Plea Agreement between Baker Hughes Services International, Inc. and the United States Department of Justice filed on April 26, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 10.5 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007). Subsidiaries of Company. Consent of Deloitte & Touche LLP. Certification of Martin S. Craighead, Chairman and Chief Executive Officer, furnished pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended. Certification of Kimberly A. Ross, Chief Financial Officer, furnished pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended. Statement of Martin S. Craighead, Chairman and Chief Executive Officer, and Kimberly A. Ross, Chief Financial Officer, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended. Mine Safety Disclosures. Notice of Extension, dated July 10, 2015, of the Agreement and Plan of Merger among Halliburton Company, Red Tiger LLC and Baker Hughes Incorporated dated November 16, 2014, extending the termination date to December 1, 2015 (filed as Exhibit 99.1 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2015). 89 99.2 99.3* Notice of Extension, dated September 25, 2015, of the Agreement and Plan of Merger among Halliburton Company, Red Tiger LLC and Baker Hughes Incorporated dated November 16, 2014, extending the termination date to December 16, 2015 (filed as Exhibit 99.2 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2015). Notice of Extension, dated December 15, 2015, of the Agreement and Plan of Merger among Halliburton Company, Red Tiger LLC and Baker Hughes Incorporated dated November 16, 2014, extending the termination date to April 30, 2016. 101.INS* XBRL Instance Document. 101.SCH* XBRL Schema Document. 101.CAL* XBRL Calculation Linkbase Document. 101.LAB* XBRL Label Linkbase Document. 101.PRE* XBRL Presentation Linkbase Document. 101.DEF* XBRL Definition Linkbase Document. 90 Baker Hughes Incorporated Schedule II - Valuation and Qualifying Accounts (In millions) Year Ended December 31, 2015 Balance at Beginning of Period Charged to Cost and Expenses Write- offs (1) Other Changes (2) (3) Balance at End of Period Reserve for doubtful accounts receivable Reserve for inventories $ Year Ended December 31, 2014 Reserve for doubtful accounts receivable Reserve for inventories Year Ended December 31, 2013 Reserve for doubtful accounts receivable Reserve for inventories $ 224 319 238 382 308 346 193 195 102 37 75 85 $ (23) $ (235) (71) (92) (115) (46) (11) $ (1) (45) (8) (30) (3) 383 278 224 319 238 382 (1) Represents the elimination of accounts receivable and inventory deemed uncollectible or worthless. (2) Represents transfers, currency translation adjustments and divestitures. (3) For the year ended December 31, 2014 and 2013, the reserve for doubtful accounts receivable includes a $39 million and $30 million reduction, respectively, due to the currency devaluation in Venezuela. 91 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SIGNATURES Date: February 18, 2016 BAKER HUGHES INCORPORATED /s/ MARTIN S. CRAIGHEAD Martin S. Craighead Chairman and Chief Executive Officer KNOWN ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Martin S. Craighead and Kimberly A. Ross, each of whom may act without joinder of the other, as their true and lawful attorneys-in-fact and agents, each with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on this 18th day of February 2016. Signature Title /S/ MARTIN S. CRAIGHEAD (Martin S. Craighead) Chairman and Chief Executive Officer (principal executive officer) /S/ KIMBERLY A. ROSS (Kimberly A. Ross) /S/ ALAN J. KEIFER (Alan J. Keifer) Senior Vice President and Chief Financial Officer (principal financial officer) Vice President and Controller (principal accounting officer) 92 * (Larry D. Brady) * (Gregory D. Brenneman) * (Clarence P. Cazalot, Jr.) * (William H. Easter III) * (Lynn L. Elsenhans) * (Anthony G. Fernandes) * (Claire W. Gargalli) * (Pierre H. Jungels) * (James A. Lash) * (J. Larry Nichols) * (James W. Stewart) * (Charles L. Watson) * By: /s/ KIMBERLY A. ROSS Kimberly A. Ross Attorney-in-fact Director Director Director Director Director Director Director Director Director Director Director Director 93 CORPORATE INFORMATION BOARD OF DIRECTORS EXECUTIVE LEADERSHIP Larry D. Brady Former Chairman and Chief Executive Officer Intermec, Inc. Gregory D. Brenneman Chairman, President, and Chief Executive Officer CCMP Capital Advisors, LLC Clarence P. Cazalot, Jr. Former Executive Chairman, President, and Chief Executive Officer Marathon Oil Corporation Martin S. Craighead Chairman and Chief Executive Officer Baker Hughes Incorporated William H. Easter III Former Chairman, President, and Chief Executive Officer DCP Midstream LLC Lynn L. Elsenhans Former Executive Chairman, Chief Executive Officer, and President, Sunoco, Inc. Anthony G. Fernandes Former Chairman, President, and Chief Executive Officer Philip Services Corporation Claire W. Gargalli Former Vice Chairman Diversified Search and Diversified Health Search Companies Pierre H. Jungels, CBE Former President The Institute of Petroleum James A. Lash Chairman Manchester Principal LLC J. Larry Nichols Executive Chairman Devon Energy Corporation James W. Stewart Former Chairman, President, and Chief Executive Officer BJ Services Company Charles L. Watson Chairman Twin Eagle Management Resources OTHER CORPORATE OFFICERS David E. Emerson Vice President, Corporate Development Alan J. Keifer Vice President and Controller William D. Marsh Vice President and General Counsel Jay G. Martin Vice President, Chief Compliance Officer, and Senior Deputy Counsel Ronald E. Martz Vice President, Internal Audit Mike W. Sumruld Vice President and Treasurer Lee Whitley Vice President and Corporate Secretary Martin S. Craighead Chairman and Chief Executive Officer Baker Hughes Incorporated Belgacem Chariag Vice President and Chief Integration Officer Derek Mathieson Vice President and Chief Technology and Marketing Officer Khaled Nouh President Middle East/Asia Pacific Alan R. Crain Senior Vice President, Chief Legal and Governance Officer Kimberly A. Ross Senior Vice President and Chief Financial Officer Archana Deskus Vice President and Chief Information Officer Andrew Esparza Vice President and Chief Human Resources Officer Jack Hinton Vice President Health, Safety, and Environment Julio Lera President Latin America Arthur L. Soucy President Europe/Africa/Russia Caspian Richard Ward President Global Products and Services Richard L. Williams President North America As a Baker Hughes stockholder, you are invited to take advantage of our convenient stockholder services or request more information about Baker Hughes. Computershare Investor Services, our transfer agent, maintains the records for our registered stockholders and can help you with a variety of stockholder-related services at no charge, including: n Change of name or address enrollment n Duplicate mailings n Lost stock certificates n Additional administrative services n Consolidation of accounts n Transfer of stock to another person n Dividend reinvestment Access your investor statements online 24 hours a day, seven days a week. For more information, go to https://www.computershare.com/investor Stockholder Information Transfer Agent and Registrar Computershare Investor Services P.O. Box 30170 College Station, Texas 77842-3170 +1.888.216.8057 Stock Exchange Listings Ticker Symbol “BHI” New York Stock Exchange, Inc. SIX Swiss Exchange New York Stock Exchange Last year our Annual CEO Certification, without qualifica- tions, was timely submitted to the NYSE. Also, we file our certifications required under SOX as exhibits to our Form 10-K. Investor Relations Office Alondra Oteyza Director, Investor Relations Baker Hughes Incorporated P.O. Box 4740 Houston, Texas 77210-4740 ir@bakerhughes.com Form 10-K Additional copies of the Company’s Annual Report to the Securities and Exchange Commission (Form10-K) are available by writing: Baker Hughes Investor Relations P.O. Box 4740 Houston, Texas 77210-4740 Also available at our website: http://www.bakerhughes.com/ annualreport Annual Meeting The Company’s Annual Meeting of Stockholders will be held: 9:00 a.m. Houston-Texas-time May 24, 2016 6760 Concord Park Drive R.C. Baker Room Houston, Texas 77040 Corporate Office Location and Mailing Address 2929 Allen Parkway, Suite 2100 Houston, Texas 77019-2118 Telephone: +1.713.439.8600 P.O. Box 4740 Houston, Texas 77210-4740 Website www.bakerhughes.com 2929 Allen Parkway, Suite 2100 Houston, Texas 77019-2118 P.O. Box 4740 Houston, Texas 77210-4740 BakerHughes.com 

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