10-K 1 hal_12312017-10k.htm DECEMBER 31, 2017 FORM 10-K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2017
OR
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from ______ to ______
Commission File Number 001-03492
HALLIBURTON COMPANY
(Exact name of registrant as specified in its charter)

Delaware | 75-2677995
(State or other jurisdiction of | (I.R.S. Employer
incorporation or organization) | Identification No.)
3000 North Sam Houston Parkway East
Houston, Texas 77032
(Address of principal executive offices)
Telephone Number – Area code (281) 871-2699
Securities registered pursuant to Section 12(b) of the Act:
| Name of each exchange on
Title of each class | which registered
Common Stock par value $2.50 per share | New York Stock 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 Section 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 Web site, 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer [X] Accelerated filer [ ]
Non-accelerated filer [ ] (Do not check if a smaller reporting company)
Smaller reporting company [ ] Emerging growth company [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
The aggregate market value of Halliburton Company Common Stock held by nonaffiliates on June 30, 2017, determined using the per share closing price on the New York Stock Exchange Composite tape of $42.71 on that date, was approximately $37.1 billion.
As of February 2, 2018, there were 874,909,834 shares of Halliburton Company Common Stock, $2.50 par value per share, outstanding.
Portions of the Halliburton Company Proxy Statement for our 2018 Annual Meeting of Stockholders (File No. 001-03492) are incorporated by reference into Part III of this report.

HALLIBURTON COMPANY
Index to Form 10-K
For the Year Ended December 31, 2017

PART I |  | PAGE
Item 1. | Business | 1
Item 1(a). | Risk Factors | 7
Item 1(b). | Unresolved Staff Comments | 15
Item 2. | Properties | 15
Item 3. | Legal Proceedings | 15
Item 4. | Mine Safety Disclosures | 15
PART II |  |
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 16
Item 6. | Selected Financial Data | 17
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 17
Item 7(a). | Quantitative and Qualitative Disclosures About Market Risk | 17
Item 8. | Financial Statements and Supplementary Data | 18
Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 18
Item 9(a). | Controls and Procedures | 18
Item 9(b). | Other Information | 18
MD&A AND FINANCIAL STATEMENTS |
Management’s Discussion and Analysis of Financial Condition and Results of Operations | 19
Management’s Report on Internal Control Over Financial Reporting | 37
Reports of Independent Registered Public Accounting Firm | 38
Consolidated Statements of Operations | 41
Consolidated Statements of Comprehensive Income | 42
Consolidated Balance Sheets | 43
Consolidated Statements of Cash Flows | 44
Consolidated Statements of Shareholders’ Equity | 45
Notes to Consolidated Financial Statements | 46
Selected Financial Data (Unaudited) | 67
Quarterly Data and Market Price Information (Unaudited) | 68
PART III |  |
Item 10. | Directors, Executive Officers and Corporate Governance | 69
Item 11. | Executive Compensation | 69
Item 12(a). | Security Ownership of Certain Beneficial Owners | 69
Item 12(b). | Security Ownership of Management | 69
Item 12(c). | Changes in Control | 69
Item 12(d). | Securities Authorized for Issuance Under Equity Compensation Plans | 69
Item 13. | Certain Relationships and Related Transactions, and Director Independence | 69
Item 14. | Principal Accounting Fees and Services | 69
PART IV |  |
Item 15. | Exhibits | 70
Item 16. | Form 10-K Summary | 76
SIGNATURES |  | 77

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PART I
Item 1. Business.
General description of business
Halliburton Company’s predecessor was established in 1919 and incorporated under the laws of the State of Delaware in 1924. With approximately 55,000 employees, representing 140 nationalities in approximately 70 countries, we help our customers maximize value throughout the lifecycle of the reservoir - from locating hydrocarbons and managing geological data, to drilling and formation evaluation, well construction and completion and optimizing production throughout the life of the asset. We serve major, national and independent oil and natural gas companies throughout the world and operate under two divisions, which form the basis for the two operating segments we report, the Completion and Production segment and the Drilling and Evaluation segment.
Completion and Production delivers cementing, stimulation, intervention, pressure control, specialty chemicals, artificial lift and completion products and services. The segment consists of the following product service lines:

- | Production Enhancement: includes stimulation services and sand control services. Stimulation services optimize oil and natural gas reservoir production through a variety of pressure pumping services, nitrogen services and chemical processes, commonly known as hydraulic fracturing and acidizing. Sand control services include fluid and chemical systems and pumping services for the prevention of formation sand production.

- | Cementing: involves bonding the well and well casing while isolating fluid zones and maximizing wellbore stability. Our cementing product service line also provides casing equipment.

- | Completion Tools: provides downhole solutions and services to our customers to complete their wells, including well completion products and services, intelligent well completions, liner hanger systems, sand control systems and service tools.

- | Production Solutions: provides customized well intervention solutions to increase well performance, which includes coiled tubing, hydraulic workover units and downhole tools.

- | Pipeline & Process Services: provides a complete range of pre-commissioning, commissioning, maintenance and decommissioning services to the onshore and offshore pipeline and process plant construction, commissioning and maintenance industries.

- | Multi-Chem: provides customized specialty oilfield production and completion chemicals and services to maximize production, ensure integrity of well and pipeline assets and address production, processing and transportation challenges.

- | Artificial Lift: provides services to maximize reservoir and wellbore recovery by applying lifting technology, intelligent field management solutions and related services throughout the life of the well, including electrical submersible pumps and progressive cavity pumps.

Drilling and Evaluation provides field and reservoir modeling, drilling, evaluation and precise wellbore placement solutions that enable customers to model, measure, drill and optimize their well construction activities. The segment consists of the following product service lines:

- | Baroid: provides drilling fluid systems, performance additives, completion fluids, solids control, specialized testing equipment and waste management services for oil and natural gas drilling, completion and workover operations.

- | Sperry Drilling: provides drilling systems and services that offer directional control for precise wellbore placement while providing important measurements about the characteristics of the drill string and geological formations while drilling wells. These services include directional and horizontal drilling, measurement-while-drilling, logging-while-drilling, surface data logging, multilateral systems, underbalanced applications and rig site information systems.

- | Wireline and Perforating: provides open-hole logging services that supply information on formation evaluation and reservoir fluid analysis, including formation lithology, rock properties and reservoir fluid properties. Also offered are cased-hole and slickline services, including perforating, pipe recovery services, through-casing formation evaluation and reservoir monitoring, casing and cement integrity measurements and well intervention services.

- | Drill Bits and Services: provides roller cone rock bits, fixed cutter bits, hole enlargement and related downhole tools and services used in drilling oil and natural gas wells. In addition, coring equipment and services are provided to acquire cores of the formation drilled for evaluation.

- | Landmark Software and Services: supplies integrated exploration, drilling and production software and related professional and data management services for the upstream oil and natural gas industry.

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- | Testing and Subsea: provides acquisition and analysis of dynamic reservoir information and reservoir optimization solutions to the oil and natural gas industry through a broad portfolio of test tools, data acquisition services, fluid sampling, surface well testing and subsea safety systems.

- | Consulting and Project Management: provides integrated solutions to our customers by leveraging the full line of our oilfield services, products and technologies to solve customer challenges throughout the oilfield lifecycle. It includes project management, consulting, integrated asset management and well control and prevention services.

See Note 2 to the consolidated financial statements for further financial information related to each of our business segments. We have manufacturing operations in various locations, the most significant of which are located in the United States, Canada, Malaysia, Singapore and the United Kingdom.
Business strategy
Our value proposition is to collaborate and engineer solutions to maximize asset value for our customers. We strive to achieve superior growth and returns for our shareholders by delivering technology and services that improve efficiency, increase recovery and maximize production for our customers. Our objectives are to:

- | create a balanced portfolio of services and products supported by global infrastructure and anchored by technological innovation to further differentiate our company;

- | reach a distinguished level of operational excellence that reduces costs and creates real value;

- | preserve a dynamic workforce by being a preferred employer to attract, develop and retain the best global talent; and

- | uphold our strong ethical and business standards, and maintain the highest standards of health, safety and environmental performance.

For further discussion on our business strategies, see "Management’s Discussion and Analysis of Financial Condition and Results of Operations – Executive Overview."
Markets and competition
We are one of the world’s largest diversified energy services companies. Our services and products are sold in highly competitive markets throughout the world. Competitive factors impacting sales of our services and products include: price; service delivery; health, safety and environmental standards and practices; service quality; global talent retention; understanding the geological characteristics of the hydrocarbon reservoir; product quality; warranty; and technical proficiency.
We conduct business worldwide in approximately 70 countries. The business operations of our divisions are organized around four primary geographic regions: North America, Latin America, Europe/Africa/CIS and Middle East/Asia. In 2017, 2016 and 2015, based on the location of services provided and products sold, 53%, 41% and 44% of our consolidated revenue was from the United States. No other country accounted for more than 10% of our consolidated revenue during these periods. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information about our geographic operations. Because the markets for our services and products are vast and cross numerous geographic lines, it is not practicable to provide a meaningful estimate of the total number of our competitors. The industries we serve are highly competitive, and we have many substantial competitors. Most of our services and products are marketed through our service and sales organizations.
Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil unrest, war or other armed conflict, sanctions, expropriation or other governmental actions, inflation, changes in foreign currency exchange rates, foreign currency exchange restrictions and highly inflationary currencies, and other geopolitical factors. We believe the geographic diversification of our business activities reduces the risk that loss of operations in any one country, other than the United States, would be materially adverse to our business, consolidated results of operations or consolidated financial condition.
Information regarding our exposure to foreign currency fluctuations, risk concentration and financial instruments used to minimize risk is included in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financial Instrument Market Risk” and in Note 12 to the consolidated financial statements.
Customers
Our revenue from continuing operations during the past three years was derived from the sale of services and products to the energy industry. No customer represented more than 10% of our consolidated revenue in any period presented.
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Raw materials
Raw materials essential to our business are normally readily available. Market conditions can trigger constraints in the supply of certain raw materials, such as proppants (primarily sand), hydrochloric acid and gels, including guar gum (a blending additive used in hydraulic fracturing). We are always seeking ways to ensure the availability of resources, as well as manage costs of raw materials. Our procurement department uses our size and buying power to enhance our access to key materials at competitive prices.
Research and development costs
We maintain an active research and development program. The program improves products, processes and engineering standards and practices that serve the changing needs of our customers, such as those related to high pressure and high temperature environments, and also develops new products and processes. Our expenditures for research and development activities were $360 million in 2017, $329 million in 2016 and $487 million in 2015.
Patents
We own a large number of patents and have pending a substantial number of patent applications covering various products and processes. We are also licensed to utilize technology covered by patents owned by others, and we license others to utilize technology covered by our patents. We do not consider any particular patent to be material to our business operations.
Seasonality
Weather and natural phenomena can temporarily affect the performance of our services, but the widespread geographical locations of our operations mitigate those effects. Examples of how weather can impact our business include:

- | the severity and duration of the winter in North America can have a significant impact on natural gas storage levels and drilling activity;

- | the timing and duration of the spring thaw in Canada directly affects activity levels due to road restrictions;

- | typhoons and hurricanes can disrupt coastal and offshore operations; and

- | severe weather during the winter normally results in reduced activity levels in the North Sea and Russia.

Additionally, customer spending patterns for software, completion tools and various other oilfield services and products typically result in higher activity in the fourth quarter of the year.
Employees
At December 31, 2017, we employed approximately 55,000 people worldwide compared to approximately 50,000 at December 31, 2016. At December 31, 2017, approximately 13% of our employees were subject to collective bargaining agreements. Based upon the geographic diversification of these employees, we do not believe any risk of loss from employee strikes or other collective actions would be material to the conduct of our operations taken as a whole.
Environmental regulation
We are subject to numerous environmental, legal and regulatory requirements related to our operations worldwide. For further information related to environmental matters and regulation, see Note 7 to the consolidated financial statements and Item 1(a), “Risk Factors.”
Hydraulic fracturing
Hydraulic fracturing is a process that creates fractures extending from the well bore into the rock formation to enable natural gas or oil to move more easily from the rock pores to a production conduit. A significant portion of our Completion and Production segment provides hydraulic fracturing services to customers developing shale natural gas and shale oil. From time to time, questions arise about the scope of our operations in the shale natural gas and shale oil sectors, and the extent to which these operations may affect human health and the environment.
At the direction of our customer, we design and generally implement a hydraulic fracturing operation to 'stimulate' the well's production, once the well has been drilled, cased and cemented. Our customer is generally responsible for providing the base fluid (usually water) used in the hydraulic fracturing of a well. We generally supply the proppant (primarily sand) and at least a portion of the additives used in the overall fracturing fluid mixture. In addition, we mix the additives and proppant with the base fluid and pump the mixture down the wellbore to create the desired fractures in the target formation. The customer is responsible for disposing and/or recycling for further use any materials that are subsequently produced or pumped out of the well, including flowback fluids and produced water.
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As part of the process of constructing the well, the customer will take a number of steps designed to protect drinking water resources. In particular, the casing and cementing of the well are designed to provide 'zonal isolation' so that the fluids pumped down the wellbore and the oil and natural gas and other materials that are subsequently pumped out of the well will not come into contact with shallow aquifers or other shallow formations through which those materials could potentially migrate to freshwater aquifers or the surface.
The potential environmental impacts of hydraulic fracturing have been studied by numerous government entities and others. In 2004, the United States Environmental Protection Agency (EPA) conducted an extensive study of hydraulic fracturing practices, focusing on coalbed methane wells, and their potential effect on underground sources of drinking water. The EPA’s study concluded that hydraulic fracturing of coalbed methane wells poses little or no threat to underground sources of drinking water. In December 2016, the EPA released a final report, “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States” representing the culmination of a six-year study requested by Congress. While the EPA report noted a potential for some impact to drinking water sources caused by hydraulic fracturing, the agency confirmed the overall incidence of impacts is low. Moreover, a number of the areas of potential impact identified in the report involve activities for which we are not generally responsible, such as potential impacts associated with withdrawals of surface water for use as a base fluid and management of wastewater.
We have made detailed information regarding our fracturing fluid composition and breakdown available on our internet web site at www.halliburton.com. We also have proactively developed processes to provide our customers with the chemical constituents of our hydraulic fracturing fluids to enable our customers to comply with state laws as well as voluntary standards established by the Chemical Disclosure Registry, www.fracfocus.org.
We have also invested considerable resources in developing hydraulic fracturing technologies, in both the equipment and chemistry portions of our business, which offer our customers a variety of environment-friendly alternatives related to the use of hydraulic fracturing fluid additives and other aspects of our hydraulic fracturing operations. We created a hydraulic fracturing fluid system comprised of materials sourced entirely from the food industry. In addition, we have engineered a process that uses ultraviolet light to control the growth of bacteria in hydraulic fracturing fluids, allowing customers to minimize the use of chemical biocides. We are committed to the continued development of innovative chemical and mechanical technologies that allow for more economical and environmentally friendly development of the world’s oil and natural gas reserves, and that reduce noise while complying with Tier 4 lower emission legislation.
In evaluating any environmental risks that may be associated with our hydraulic fracturing services, it is helpful to understand the role that we play in the development of shale natural gas and shale oil. Our principal task generally is to manage the process of injecting fracturing fluids into the borehole to 'stimulate' the well. Thus, based on the provisions in our contracts and applicable law, the primary environmental risks we face are potential pre-injection spills or releases of stored fracturing fluids and potential spills or releases of fuel or other fluids associated with pumps, blenders, conveyors, or other above-ground equipment used in the hydraulic fracturing process.
Although possible concerns have been raised about hydraulic fracturing, the circumstances described above have helped to mitigate those concerns. To date, we have not been obligated to compensate any indemnified party for any environmental liability arising directly from hydraulic fracturing, although there can be no assurance that such obligations or liabilities will not arise in the future. For further information on risks related to hydraulic fracturing, see Item 1(a), “Risk Factors.”
Working capital
We fund our business operations through a combination of available cash and equivalents, short-term investments and cash flow generated from operations. In addition, our revolving credit facility is available for additional working capital needs.
Web site access
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 Exchange Act of 1934 are made available free of charge on our internet web site (www.halliburton.com) as soon as reasonably practicable after we have electronically filed the material with, or furnished it to, the Securities and Exchange Commission (SEC). The public may read and copy any materials we have filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains our reports, proxy and information statements and our other SEC filings. We have posted on our web site our Code of Business Conduct, which applies to all of our employees and Directors and serves as a code of ethics for our principal executive officer, principal financial officer, principal accounting officer and other persons performing similar functions. Any amendments to our Code of Business Conduct or any waivers from provisions of our Code
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of Business Conduct granted to the specified officers above are disclosed on our web site within four business days after the date of any amendment or waiver pertaining to these officers. There have been no waivers from provisions of our Code of Business Conduct for the years 2017, 2016, or 2015. Except to the extent expressly stated otherwise, information contained on or accessible from our web site or any other web site is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report.
Executive Officers of the Registrant
The following table indicates the names and ages of the executive officers of Halliburton Company as of February 9, 2018, including all offices and positions held by each in the past five years:

| Name and Age | Offices Held and Term of Office
| Anne L. Beaty (Age 61) | Senior Vice President, Finance of Halliburton Company, since March 2017
|  | Senior Vice President, Internal Assurance Services of Halliburton Company, November 2013 to March 2017
|  | Vice President, Internal Audit and Controls of Halliburton Company, January 2007 to November 2013
| James S. Brown (Age 63) | President, Western Hemisphere of Halliburton Company, since January 2008
| Eric J. Carre (Age 51) | Executive Vice President, Global Business Lines of Halliburton Company, since May 2016
|  | Senior Vice President, Drilling and Evaluation Division of Halliburton Company, June 2011 to April 2016
| Charles E. Geer, Jr. (Age 47) | Vice President and Corporate Controller of Halliburton Company, since January 2015
|  | Vice President, Finance of Halliburton Company, December 2013 to December 2014
|  | Vice President and Chief Accounting Officer of Select Energy Services, April 2011 to November 2013
| Myrtle L. Jones (Age 58) | Senior Vice President, Tax of Halliburton Company, since March 2013
|  | Senior Managing Director of Tax and Internal Audit, Service Corporation International, February 2008 to February 2013
| David J. Lesar (Age 64) | Executive Chairman of the Board of Directors of Halliburton Company, since August 2000
|  | Chief Executive Officer of Halliburton Company, August 2014 to May 2017
|  | President and Chief Executive Officer of Halliburton Company, August 2000 to July 2014
| Timothy M. McKeon (Age 45) | Vice President and Treasurer of Halliburton Company, since January 2014
|  | Assistant Treasurer of Halliburton Company, September 2011 to December 2013
| Jeffrey A. Miller (Age 54) | President and Chief Executive Officer of Halliburton Company, since June 2017
|  | President of Halliburton Company, August 2014 to May 2017
|  | Member of the Board of Directors of Halliburton Company, since August 2014
|  | Executive Vice President and Chief Operating Officer of Halliburton Company, September 2012 to July 2014

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| Lawrence J. Pope (Age 49) | Executive Vice President of Administration and Chief Human Resources Officer of Halliburton Company, since January 2008
| Joe D. Rainey (Age 61) | President, Eastern Hemisphere of Halliburton Company, since January 2011
| Robb L. Voyles (Age 60) | Executive Vice President, Secretary and General Counsel of Halliburton Company, since May 2015
|  | Interim Chief Financial Officer of Halliburton Company, March 2017 to June 2017
|  | Executive Vice President and General Counsel of Halliburton Company, January 2014 to April 2015
|  | Senior Vice President, Law of Halliburton Company, September 2013 to December 2013
|  | Partner, Baker Botts L.L.P., January 1989 to August 2013
| Christopher T. Weber (Age 45) | Executive Vice President and Chief Financial Officer of Halliburton Company, since June 2017
|  | Senior Vice President and Chief Financial Officer of Parker Drilling Company, May 2013 to May 2017
|  | Vice President and Treasurer of Ensco plc, from 2011 to May 2013

There are no family relationships between the executive officers of the registrant or between any director and any executive officer of the registrant.
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Item 1(a). Risk Factors.
The statements in this section describe the known material risks to our business and should be considered carefully.
Trends in oil and natural gas prices affect the level of exploration, development and production activity of our customers and the demand for our services and products, which could have a material adverse effect on our business, consolidated results of operations and consolidated financial condition.
Demand for our services and products is particularly sensitive to the level of exploration, development and production activity of, and the corresponding capital spending by, oil and natural gas companies. The level of exploration, development and production activity is directly affected by trends in oil and natural gas prices, which historically have been volatile and are likely to continue to be volatile.
Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of other economic factors that are beyond our control. Crude oil prices have fluctuated significantly since 2014, with West Texas Intermediate (WTI) oil spot prices declining from a high of $108 per barrel in June 2014 to a low of $26 per barrel in February 2016, and subsequently increasing to reach a high of $60 per barrel in December 2017. For more information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment and Results of Operations.”
The reduction in oil and natural gas prices in 2015 through 2016 depressed levels of exploration, development and production activity and negatively impacted our operating results during those periods. Although commodity prices improved in 2017, average prices remained well below 2014 levels. Any prolonged reductions of commodity prices could once again have a material adverse effect on our business, consolidated results of operations and consolidated financial condition, including potential asset impairments and severance costs. Given the long-term nature of many large-scale development projects, even the perception of longer-term lower oil and natural gas prices by oil and natural gas companies can similarly cause them to reduce or defer major expenditures. We also have a small number of integrated projects that have remuneration tied to hydrocarbon production. Reduction in oil and gas prices can affect the overall returns for these projects, either lengthening the time until the expected returns are realized or by impairing the value of the asset.
Factors affecting the prices of oil and natural gas include:

- | the level of supply and demand for oil and natural gas;

- | governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves;

- | weather conditions and natural disasters;

- | worldwide political, military and economic conditions;

- | the ability or willingness of the Organization of Petroleum Exporting Countries (OPEC) to set and maintain oil production levels;

- | the level of oil production by non-OPEC countries;

- | oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;

- | the cost of producing and delivering oil and natural gas; and

- | increased demand for alternative fuels and electric vehicles, including government initiatives to promote the use of renewable energy sources and public sentiment around alternatives to oil and gas.

Our business is dependent on capital spending by our customers, and reductions in capital spending could have a material adverse effect on our business, consolidated results of operations and consolidated financial condition.
Our business is directly affected by changes in capital expenditures by our customers, and reductions in their capital spending could reduce demand for our services and products and have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition. Some of the items that may impact our customer's capital spending include:

- | oil and natural gas prices, including volatility of oil and natural gas prices and expectations regarding future prices;

- | the inability of our customers to access capital on economically advantageous terms;

- | the consolidation of our customers;

- | customer personnel changes; and

- | adverse developments in the business or operations of our customers, including write-downs of reserves and borrowing base reductions under customer credit facilities.

Many of our customers reduced capital spending in 2015 and 2016 as a result of decreases in commodity prices. While customer budgets generally increased in 2017 in response to improved market conditions, any significant reduction in
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commodity prices or a change in our customers’ expectations of future oil and natural gas prices, economic growth or the demand for oil and natural gas may result in capital budget reductions in the future.
Our operations are subject to political and economic instability and risk of government actions that could have a material adverse effect on our business, consolidated results of operations and consolidated financial condition.
We are exposed to risks inherent in doing business in each of the countries in which we operate. Our operations are subject to various risks unique to each country that could have a material adverse effect on our business, consolidated results of operations and consolidated financial condition. With respect to any particular country, these risks may include:

- | political and economic instability, including:

•civil unrest, acts of terrorism, war and other armed conflict;
•inflation; and
•currency fluctuations, devaluations and conversion restrictions; and

- | governmental actions that may:

•result in expropriation and nationalization of our assets in that country;
•result in confiscatory taxation or other adverse tax policies;
•limit or disrupt markets or our operations, restrict payments, or limit the movement of funds;
•impose sanctions on our ability to conduct business with certain customers or persons;
•result in the deprivation of contract rights; and
•result in the inability to obtain or retain licenses required for operation.
For example, due to the unsettled political conditions in many oil-producing countries, our operations, revenue and profits are subject to the adverse consequences of war, terrorism, civil unrest, strikes, currency controls and governmental actions. These and other risks described above could result in the loss of our personnel or assets, cause us to evacuate our personnel from certain countries, cause us to increase spending on security worldwide, cause us to cease operating in certain countries, disrupt financial and commercial markets, including the supply of and pricing for oil and natural gas, and generate greater political and economic instability in some of the geographic areas in which we operate. Areas where we operate that have significant risk include, but are not limited to: the Middle East, North Africa, Angola, Azerbaijan, Colombia, Indonesia, Kazakhstan, Mexico, Nigeria, Russia and Venezuela. In addition, any possible reprisals as a consequence of military or other action, such as acts of terrorism in the United States or elsewhere, could have a material adverse effect on our business, consolidated results of operations and consolidated financial condition.
Our operations are subject to cyber-attacks that could have a material adverse effect on our business, consolidated results of operations and consolidated financial condition.
Our operations are increasingly dependent on digital technologies and services. We use these technologies for internal purposes, including data storage, processing and transmissions, as well as in our interactions with customers and suppliers. Digital technologies are subject to the risk of cyber-attacks. If our systems for protecting against cybersecurity risks prove not to be sufficient, we could be adversely affected by, among other things: loss of or damage to intellectual property, proprietary or confidential information, or customer, supplier, or employee data; interruption of our business operations; and increased costs required to prevent, respond to, or mitigate cybersecurity attacks. These risks could harm our reputation and our relationships with customers, suppliers, employees and other third parties, and may result in claims against us. These risks could have a material adverse effect on our business, consolidated results of operations and consolidated financial condition.
Our operations outside the United States require us to comply with a number of United States and international regulations, violations of which could have a material adverse effect on our business, consolidated results of operations and consolidated financial condition.
Our operations outside the United States require us to comply with a number of United States and international regulations. For example, our operations in countries outside the United States are subject to the United States Foreign Corrupt Practices Act (FCPA), which prohibits United States companies and their agents and employees from providing anything of value to a foreign official for the purposes of influencing any act or decision of these individuals in their official capacity to help obtain or retain business, direct business to any person or corporate entity, or obtain any unfair advantage. Our activities create the risk of unauthorized payments or offers of payments by our employees, agents, or joint venture partners that could be in violation of anti-corruption laws, even though some of these parties are not subject to our control. We have internal control policies and procedures and have implemented training and compliance programs for our employees and agents with respect to the FCPA. However, we cannot assure that our policies, procedures and programs always will protect us from reckless or criminal acts committed by our employees or agents. We are also subject to the risks that our employees, joint venture partners and agents outside of the United States may fail to comply with other applicable laws. Allegations of violations of applicable anti-corruption laws have resulted and may in the future result in internal, independent, or government investigations. Violations of anti-corruption laws may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could
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have a material adverse effect on our business, consolidated results of operations and consolidated financial condition.
In addition, the shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import activities are governed by the unique customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments may also impose economic sanctions against certain countries, persons and entities that may restrict or prohibit transactions involving such countries, persons and entities, which may limit or prevent our conduct of business in certain jurisdictions. During 2014, the United States and European Union imposed sectoral sanctions directed at Russia’s oil and gas industry. Among other things, these sanctions restrict the provision of U.S. and EU goods, services and technology in support of exploration or production for deep water, Arctic offshore, or shale projects that have the potential to produce oil in Russia. These sanctions resulted in our winding down and ending work on two projects in Russia in 2014, and have prevented us from pursuing certain other projects in Russia. In 2017, the U.S. Government imposed additional sanctions against Russia’s oil and gas industry and certain Russian companies. Our ability to engage in certain future projects in Russia or involving certain Russian customers is dependent upon whether or not our involvement in such projects is restricted under U.S. or EU sanctions laws and the extent to which any of our current or prospective operations in Russia or with certain Russian customers may be subject to those laws. Those laws may change from time to time, and any expansion of sanctions against Russia’s oil and gas industry could further hinder our ability to do business in Russia or with certain Russian customers, which could have a material adverse effect on our consolidated results of operations.
During 2017, the U.S. Government imposed economic sanctions in Venezuela around certain financing transactions as further discussed below.
The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations can cause delays in shipments and unscheduled operational downtime. Moreover, any failure to comply with applicable legal and regulatory trading obligations could result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from governmental contracts, seizure of shipments and loss of import and export privileges. In addition, investigations by governmental authorities and legal, social, economic and political issues in these countries could have a material adverse effect on our business, consolidated results of operations and consolidated financial condition.
Our business in Venezuela subjects us to actions by the Venezuelan government, sanctions imposed or other actions by the U.S. and foreign governments, the risk of delayed payments and currency risks, all of which could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
There are risks associated with our operations in Venezuela, which continues to experience significant political and economic turmoil. The political and economic conditions deteriorated in 2017, leading to uncertainty in the future business climate, the state of security and governance of the country. This environment increases the risk of civil unrest, armed conflicts, adverse actions by the government of Venezuela, including the possibility that the Venezuelan government could assume control over our operations and assets, and imposition of additional sanctions or other actions by the U.S. and foreign governments that may restrict our ability to continue operations or realize the value of our assets. In 2017, the U.S. Government announced sanctions directed at certain Venezuelan individuals and imposed additional economic sanctions around certain financing transactions in Venezuela. These sanctions prohibit dealings by our U.S. employees and entities in certain new debt issued by our primary customer in Venezuela or the Venezuelan government as well as dealings in existing Venezuelan government bonds. There can be no assurance that other sanctions affecting our business in Venezuela will not be imposed in the future that may have a material adverse effect on our ability to operate in Venezuela.
We have continued to experience delays in collecting payments on our receivables from our primary customer in Venezuela, including recent delays in scheduled payments on our existing promissory note. In November 2017, several credit rating agencies downgraded this customer’s credit rating, some as low as a default level. As a result of this credit downgrade, delayed payments on our promissory note and accounts receivable, and deteriorating market conditions in Venezuela, we recognized an aggregate charge of $647 million during 2017, representing a fair market value adjustment on our promissory note and a full reserve against our other accounts receivable with this customer.
On January 29, 2018, the Venezuelan government announced that it has changed the existing dual-rate foreign exchange system by eliminating the DIPRO foreign exchange rate. All future currency transactions will now be carried out at the DICOM floating rate. We are currently evaluating the impact that this change in foreign exchange system will have on our business, consolidated results of operations and consolidated financial condition. This includes potential further write-downs of our net investment in Venezuela, which was approximately $202 million as of December 31, 2017.
9

The future results of our Venezuelan operations will be affected by many factors, including the foreign currency exchange rate, actions of the Venezuelan government, general economic conditions such as continued inflation, existing or future sanctions, future customer spending and the ability of our primary customer to pay its debts. For further information, see Note 3 to the consolidated financial statements and "Management's Discussion and Analysis of Financial Condition and Results of Operations - Business Environment and Results of Operations - International operations - Venezuela."
Changes in, compliance with, or our failure to comply with laws in the countries in which we conduct business may negatively impact our ability to provide services in, make sales of equipment to and transfer personnel or equipment among some of those countries and could have a material adverse effect on our business and consolidated results of operations.
In the countries in which we conduct business, we are subject to multiple and, at times, inconsistent regulatory regimes, including those that govern our use of radioactive materials, explosives and chemicals in the course of our operations. Various national and international regulatory regimes govern the shipment of these items. Many countries, but not all, impose special controls upon the export and import of radioactive materials, explosives and chemicals. Our ability to do business is subject to maintaining required licenses and complying with these multiple regulatory requirements applicable to these special products. In addition, the various laws governing import and export of both products and technology apply to a wide range of services and products we offer. In turn, this can affect our employment practices of hiring people of different nationalities because these laws may prohibit or limit access to some products or technology by employees of various nationalities. Changes in, compliance with, or our failure to comply with these laws may negatively impact our ability to provide services in, make sales of equipment to and transfer personnel or equipment among some of the countries in which we operate and could have a material adverse effect on our business and consolidated results of operations.
The adoption of any future federal, state, or local laws or implementing regulations imposing reporting obligations on, or limiting or banning, the hydraulic fracturing process could make it more difficult to complete natural gas and oil wells and could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
Various federal and state legislative and regulatory initiatives have been or could be undertaken which could result in additional requirements or restrictions being imposed on hydraulic fracturing operations. For example, the EPA released the final results of its comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water resources in December 2016. The EPA concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. The results of the EPA’s study could spur action towards federal or state legislation and regulation of hydraulic fracturing or similar production operations.
At the same time, legislation and/or regulations have been adopted in many states that require additional disclosure regarding chemicals used in the hydraulic fracturing process but that generally include protections for proprietary information. Legislation and/or regulations are being considered at the state and local level that could impose further chemical disclosure or other regulatory requirements (such as restrictions on the use of certain types of chemicals or prohibitions on hydraulic fracturing operations in certain areas) that could affect our operations. Three states (New York, Maryland and Vermont) have banned the use of high volume hydraulic fracturing. Moreover, in light of concerns about seismic activity being triggered by the injection of produced waters into underground wells and hydraulic fracturing, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. Local jurisdictions in some states have adopted ordinances that restrict or in certain cases prohibit the use of hydraulic fracturing. In addition, governmental authorities in various foreign countries where we have provided or may provide hydraulic fracturing services have imposed or are considering imposing various restrictions or conditions that may affect hydraulic fracturing operations.
The adoption of any future federal, state, local, or foreign laws or regulations imposing reporting obligations on, or limiting or banning, the hydraulic fracturing process could make it more difficult to complete natural gas and oil wells and could have a material adverse effect on our business, consolidated results of operations and consolidated financial condition.
Liabilities arising out of catastrophic well incidents, such as the Deepwater Horizon blowout in April 2010, could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
Catastrophic events can occur at well sites where we conduct our operations, including blow outs resulting in explosions, fires, personal injuries, property damage, pollution and regulatory responsibility. Generally, we rely on contractual indemnities, releases and limitations on liability with our customers, and liability insurance coverage, to protect us from potential liability related to such occurrences. However, we do not have these contractual provisions in all contracts, and even where we do, it is possible that the respective customer or insurer could seek to avoid or be financially unable to meet its obligations or a court may decline to enforce such provisions. Damages that are not indemnified or released could greatly exceed available insurance coverage and could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
10

Liability for cleanup costs, natural resource damages and other damages arising as a result of environmental laws could be substantial and could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
We are exposed to claims under environmental requirements and, from time to time, such claims have been made against us. In the United States, environmental requirements and regulations typically impose strict liability. Strict liability means that in some situations we could be exposed to liability for cleanup costs, natural resource damages and other damages as a result of our conduct that was lawful at the time it occurred or the conduct of prior operators or other third parties. Liability for damages arising as a result of environmental laws could be substantial and could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
We are periodically notified of potential liabilities at federal and state superfund sites. These potential liabilities may arise from both historical Halliburton operations and the historical operations of companies that we have acquired. Our exposure at these sites may be materially impacted by unforeseen adverse developments both in the final remediation costs and with respect to the final allocation among the various parties involved at the sites. The relevant regulatory agency may bring suit against us for amounts in excess of what we have accrued and what we believe is our proportionate share of remediation costs at any superfund site. We also could be subject to third-party claims, including punitive damages, with respect to environmental matters for which we have been named as a potentially responsible party.
Failure on our part to comply with, and the costs of compliance with, applicable health, safety and environmental requirements could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
Our business is subject to a variety of health, safety and environmental laws, rules and regulations in the United States and other countries, including those covering hazardous materials and requiring emission performance standards for facilities. For example, our well service operations routinely involve the handling of significant amounts of waste materials, some of which are classified as hazardous substances. We also store, transport and use radioactive and explosive materials in certain of our operations. Applicable regulatory requirements include those concerning:

- | the containment and disposal of hazardous substances, oilfield waste and other waste materials;

- | the importation and use of radioactive materials;

- | the use of underground storage tanks;

- | the use of underground injection wells; and

- | the protection of worker safety both onshore and offshore.

These and other requirements generally are becoming increasingly strict. The failure to comply with the requirements, many of which may be applied retroactively, may result in:

- | administrative, civil and criminal penalties;

- | revocation of permits to conduct business; and

- | corrective action orders, including orders to investigate and/or clean up contamination.

Failure on our part to comply with applicable environmental requirements or costs arising from regulatory compliance, including compliance with changes in or expansion of applicable regulatory requirements, could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
Existing or future laws, regulations, treaties or international agreements related to greenhouse gases and climate change could have a negative impact on our business and may result in additional compliance obligations with respect to the release, capture and use of carbon dioxide that could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
Changes in environmental requirements related to greenhouse gases and climate change may negatively impact demand for our services. For example, oil and natural gas exploration and production may decline as a result of environmental requirements, including land use policies responsive to environmental concerns. State, national and international governments and agencies have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases in areas in which we conduct business. Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties, or international agreements related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, may reduce demand for oil and natural gas and could have a negative impact on our business. Likewise, such restrictions may result in additional compliance obligations with respect to the release, capture, sequestration and use of carbon dioxide that could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
11

Our business could be materially and adversely affected by severe or unseasonable weather where we have operations.
Our business could be materially and adversely affected by severe weather, particularly in Canada, the Gulf of Mexico, Russia and the North Sea. Some experts believe global climate change could increase the frequency and severity of extreme weather conditions. Repercussions of severe or unseasonable weather conditions may include:

- | evacuation of personnel and curtailment of services;

- | weather-related damage to offshore drilling rigs resulting in suspension of operations;

- | weather-related damage to our facilities and project work sites;

- | inability to deliver materials to jobsites in accordance with contract schedules;

- | decreases in demand for oil and natural gas during unseasonably warm winters; and

- | loss of productivity.

Changes in or interpretation of tax law and currency/repatriation control could impact the determination of our income tax liabilities for a tax year.
We have operations in approximately 70 countries. Consequently, we are subject to the jurisdiction of a significant number of taxing authorities. The income earned in these various jurisdictions is taxed on differing bases, including net income actually earned, net income deemed earned and revenue-based tax withholding. The final determination of our income tax liabilities involves the interpretation of local tax laws, tax treaties and related authorities in each jurisdiction, as well as the significant use of estimates and assumptions regarding the scope of future operations and results achieved and the timing and nature of income earned and expenditures incurred. Changes in the operating environment, including changes in or interpretation of tax law and currency/repatriation controls, could impact the determination of our income tax liabilities for the year.
Additionally, we are currently evaluating provisions of United States tax reform enacted in December 2017, which among other things, lowered the corporate income tax rate from 35% to 21% and moved the country towards a territorial tax system with a one-time mandatory tax on previously deferred foreign earnings of foreign subsidiaries. In the fourth quarter of 2017, we recorded a total provision to income taxes of $770 million related to our preliminary assessment of the net effects of tax reform. As we do not have all the necessary information to analyze all income tax effects of tax reform, this is a provisional amount which we believe represents a reasonable estimate of the accounting implications of this tax reform. We will continue to evaluate tax reform and adjust the provisional amounts as additional information is obtained. The ultimate impact of tax reform may differ from our provisional amounts due to changes in our interpretations and assumptions, as well as additional regulatory guidance that may be issued. We expect to complete our detailed analysis no later than the fourth quarter of 2018. For further information, see Note 8 to the consolidated financial statements.
We are subject to foreign exchange risks and limitations on our ability to reinvest earnings from operations in one country to fund the capital needs of our operations in other countries or to repatriate assets from some countries.
A sizable portion of our consolidated revenue and consolidated operating expenses is in foreign currencies. As a result, we are subject to significant risks, including:

- | foreign currency exchange risks resulting from changes in foreign currency exchange rates and the implementation of exchange controls; and

- | limitations on our ability to reinvest earnings from operations in one country to fund the capital needs of our operations in other countries.

As an example, we conduct business in countries that have restricted or limited trading markets for their local currencies and restrict or limit cash repatriation. We may accumulate cash in those geographies, but we may be limited in our ability to convert our profits into United States dollars or to repatriate the profits from those countries. For further information, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Business Environment and Results of Operations" and Note 8 to the consolidated financial statements.
Our failure to protect our proprietary information and any successful intellectual property challenges or infringement proceedings against us could materially and adversely affect our competitive position.
We rely on a variety of intellectual property rights that we use in our services and products. We may not be able to successfully preserve these intellectual property rights in the future, and these rights could be invalidated, circumvented or challenged. In addition, the laws of some foreign countries in which our services and products may be sold do not protect intellectual property rights to the same extent as the laws of the United States. Our failure to protect our proprietary information and any successful intellectual property challenges or infringement proceedings against us could materially and adversely affect our competitive position.
12

If we are not able to design, develop and produce commercially competitive products and to implement commercially competitive services in a timely manner in response to changes in the market, customer requirements, competitive pressures and technology trends, our business and consolidated results of operations could be materially and adversely affected, and the value of our intellectual property may be reduced.
The market for our services and products is characterized by continual technological developments to provide better and more reliable performance and services. If we are not able to design, develop and produce commercially competitive products and to implement commercially competitive services in a timely manner in response to changes in the market, customer requirements, competitive pressures and technology trends, our business and consolidated results of operations could be materially and adversely affected, and the value of our intellectual property may be reduced. Likewise, if our proprietary technologies, equipment, facilities, or work processes become obsolete, we may no longer be competitive, and our business and consolidated results of operations could be materially and adversely affected.
If we lose one or more of our significant customers or if our customers delay paying or fail to pay a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
We depend on a limited number of significant customers. While none of these customers represented more than 10% of consolidated revenue in any period presented, the loss of one or more significant customers could have a material adverse effect on our business and our consolidated results of operations.
In most cases, we bill our customers for our services in arrears and are, therefore, subject to our customers delaying or failing to pay our invoices. In weak economic or commodity price environments, we may experience increased delays and failures due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to the credit markets. If our customers delay paying or fail to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
We sometimes provide integrated project management services in the form of long-term, fixed price contracts that may require us to assume additional risks associated with cost over-runs, operating cost inflation, labor availability and productivity, supplier and contractor pricing and performance, and potential claims for liquidated damages.
We sometimes provide integrated project management services outside our normal discrete business in the form of long-term, fixed price contracts. Some of these contracts are required by our customers, primarily national oil companies (NOCs). These services include acting as project managers as well as service providers and may require us to assume additional risks associated with cost over-runs. These customers may provide us with inaccurate information in relation to their reserves, which is a subjective process that involves location and volume estimation, that may result in cost over-runs, delays and project losses. In addition, NOCs often operate in countries with unsettled political conditions, war, civil unrest, or other types of community issues. These issues may also result in cost over-runs, delays and project losses.
Providing services on an integrated basis may also require us to assume additional risks associated with operating cost inflation, labor availability and productivity, supplier pricing and performance, and potential claims for liquidated damages. We rely on third-party subcontractors and equipment providers to assist us with the completion of these types of contracts. To the extent that we cannot engage subcontractors or acquire equipment or materials in a timely manner and on reasonable terms, our ability to complete a project in accordance with stated deadlines or at a profit may be impaired. If the amount we are required to pay for these goods and services exceeds the amount we have estimated in bidding for fixed-price work, we could experience losses in the performance of these contracts. These delays and additional costs may be substantial, and we may be required to compensate our customers for these delays. This may reduce the profit to be realized or result in a loss on a project.
Constraints in the supply of, prices for and availability of transportation of raw materials can have a material adverse effect on our business and consolidated results of operations.
Raw materials essential to our business, such as proppants (primarily sand), hydrochloric acid, and gels, including guar gum, are normally readily available. Shortage of raw materials as a result of high levels of demand or loss of suppliers during market challenges can trigger constraints in the supply chain of those raw materials, particularly where we have a relationship with a single supplier for a particular resource. Many of the raw materials essential to our business require the use of rail, storage and trucking services to transport the materials to our jobsites. These services, particularly during times of high demand, may cause delays in the arrival of or otherwise constrain our supply of raw materials. These constraints could have a material adverse effect on our business and consolidated results of operations. In addition, price increases imposed by our vendors for raw materials used in our business and the inability to pass these increases through to our customers could have a material adverse effect on our business and consolidated results of operations.
13

Our acquisitions, dispositions and investments may not result in anticipated benefits and may present risks not originally contemplated, which may have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
We continually seek opportunities to maximize efficiency and value through various transactions, including purchases or sales of assets, businesses, investments, or joint venture interests. These transactions are intended to (but may not) result in the realization of savings, the creation of efficiencies, the offering of new products or services, the generation of cash or income, or the reduction of risk. Acquisition transactions may use cash on hand or be financed by additional borrowings or by the issuance of our common stock. These transactions may also affect our liquidity, consolidated results of operations and consolidated financial condition.
These transactions also involve risks, and we cannot ensure that:

- | any acquisitions we attempt will be completed on the terms announced, or at all;

- | any acquisitions would result in an increase in income or provide an adequate return of capital or other anticipated benefits;

- | any acquisitions would be successfully integrated into our operations and internal controls;

- | the due diligence conducted prior to an acquisition would uncover situations that could result in financial or legal exposure, including under the FCPA, or that we will appropriately quantify the exposure from known risks;

- | any disposition would not result in decreased earnings, revenue, or cash flow;

- | use of cash for acquisitions would not adversely affect our cash available for capital expenditures and other uses; or

- | any dispositions, investments, or acquisitions, including integration efforts, would not divert management resources.

Actions of and disputes with our joint venture partners could have a material adverse effect on the business and results of operations of our joint ventures and, in turn, our business and consolidated results of operations.
We conduct some operations through joint ventures in which unaffiliated third parties may control the operations of the joint venture or we may share control. As with any joint venture arrangement, differences in views among the joint venture participants may result in delayed decisions, the joint venture operating in a manner that is contrary to our preference or in failures to agree on major issues. We also cannot control the actions of our joint venture partners, including any nonperformance, default, or bankruptcy of our joint venture partners. These factors could have a material adverse effect on the business and results of operations of our joint ventures and, in turn, our business and consolidated results of operations.
Our ability to operate and our growth potential could be materially and adversely affected if we cannot attract, employ and retain technical personnel at a competitive cost.
Many of the services that we provide and the products that we sell are complex and highly engineered and often must perform or be performed in harsh conditions. We believe that our success depends upon our ability to attract, employ and retain technical personnel with the ability to design, utilize and enhance these services and products. A significant increase in the wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. If either of these events were to occur, our cost structure could increase, our margins could decrease and any growth potential could be impaired.
The loss or unavailability of any of our executive officers or other key employees could have a material adverse effect on our business.
We depend greatly on the efforts of our executive officers and other key employees to manage our operations. The loss or unavailability of any of our executive officers or other key employees could have a material adverse effect on our business.
14

Item 1(b). Unresolved Staff Comments.
None.
Item 2. Properties.
We own or lease numerous properties in domestic and foreign locations. Our principal properties include manufacturing facilities, research and development laboratories, technology centers and corporate offices. We also have numerous small facilities that include sales, project and support offices and bulk storage facilities throughout the world. All of our owned properties are unencumbered. We believe all properties that we currently occupy are suitable for their intended use.
The following locations represent our major facilities by segment:

– | Completion and Production: Arbroath, United Kingdom; Johor Bahru, Malaysia; and Lafayette, Louisiana

– | Drilling and Evaluation: Alvarado, Texas; Nisku, Canada; and The Woodlands, Texas

– | Shared/corporate facilities: Carrollton, Texas; Denver, Colorado; Dhahran, Saudi Arabia; Dubai, United Arab Emirates (corporate executive offices); Duncan, Oklahoma; Houston, Texas (corporate executive offices); Kuala Lumpur, Malaysia; London, England; Moscow, Russia; Panama City, Panama; Pune, India; Rio de Janeiro, Brazil; Singapore; and Tananger, Norway

Item 3. Legal Proceedings.
Information related to Item 3. Legal Proceedings is included in Note 7 to the consolidated financial statements.
Item 4. Mine Safety Disclosures.
Our barite and bentonite mining operations, in support of our fluid 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 (17 CFR 229.104) is included in Exhibit 95 to this annual report.
15

PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Halliburton Company’s common stock is traded on the New York Stock Exchange. Information related to the high and low market prices of our common stock and quarterly dividend payments is included under the caption “Quarterly Data and Market Price Information” on page 68 of this annual report. Quarterly cash dividends on our common stock, which were paid in March, June, September and December of each year, were $0.18 per share for all four quarters of 2016 and 2017. The declaration and payment of future dividends will be at the discretion of the Board of Directors and will depend on, among other things, future earnings, general financial condition and liquidity, success in business activities, capital requirements and general business conditions. Subject to Board of Directors approval, our intention is to continue paying dividends at our current rate during 2018.
The following graph and table compare total shareholder return on our common stock for the five-year period ended December 31, 2017, with the Philadelphia Oil Service Index (OSX) and the Standard & Poor’s 500 ® Index over the same period. This comparison assumes the investment of $100 on December 31, 2012 and the reinvestment of all dividends. The shareholder return set forth is not necessarily indicative of future performance.

| December 31
| 2012 | 2013 | 2014 | 2015 | 2016 | 2017
Halliburton | $ | 100.00 |  | $ | 148.00 |  | $ | 116.03 |  | $ | 102.26 |  | $ | 165.22 |  | $ | 151.61 |
Philadelphia Oil Service Index (OSX) | 100.00 |  | 121.15 |  | 95.32 |  | 71.30 |  | 83.08 |  | 67.60 |
Standard & Poor’s 500 ® Index | 100.00 |  | 156.82 |  | 178.28 |  | 180.75 |  | 202.37 |  | 246.55 |

16

At February 2, 2018, we had 12,374 shareholders of record. In calculating the number of shareholders, we consider clearing agencies and security position listings as one shareholder for each agency or listing.
The following table is a summary of repurchases of our common stock during the three-month period ended December 31, 2017.

Period | Total Number of Shares Purchased (a) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (b) | Maximum Number (or Approximate Dollar Value) of Shares that may yet be Purchased Under the Program (b)
October 1 - 31 | 25,254 | $43.06 | — | $5,700,004,373
November 1 - 30 | 17,384 | $42.88 | — | $5,700,004,373
December 1 - 31 | 193,421 | $43.98 | — | $5,700,004,373
Total | 236,059 | $43.80 | — |

(a) | All of the 236,059 shares purchased during the three-month period ended December 31, 2017 were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase common stock.

(b) | Our Board of Directors has authorized a plan to repurchase our common stock from time to time. During the fourth quarter of 2017, we did not repurchase shares of our common stock pursuant to that plan. We have authorization remaining to repurchase up to a total of approximately $5.7 billion of our common stock.

Item 6. Selected Financial Data.
Information related to selected financial data is included on page 67 of this annual report.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Information related to Management’s Discussion and Analysis of Financial Condition and Results of Operations is included on pages 19 through 36 of this annual report.
Item 7(a). Quantitative and Qualitative Disclosures About Market Risk.
Information related to market risk is included in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financial Instrument Market Risk” and Note 12 to the consolidated financial statements.
17

Item 8. Financial Statements and Supplementary Data.

| Page No.
Management’s Report on Internal Control Over Financial Reporting | 37
Reports of Independent Registered Public Accounting Firm | 38
Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015 | 41
Consolidated Statements of Comprehensive Income for the years ended December 31, 2017, 2016 and 2015 | 42
Consolidated Balance Sheets at December 31, 2017 and 2016 | 43
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015 | 44
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2017, 2016 and 2015 | 45
Notes to Consolidated Financial Statements | 46
Selected Financial Data (Unaudited) | 67
Quarterly Data and Market Price Information (Unaudited) | 68

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9(a). Controls and Procedures.
In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2017 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
There has been no change in our internal control over financial reporting that occurred during the three months ended December 31, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
See page 37 for Management’s Report on Internal Control Over Financial Reporting and page 39 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.
Item 9(b). Other Information.
None.
18

HALLIBURTON COMPANY
Management’s Discussion and Analysis of Financial Condition and Results of Operations
EXECUTIVE OVERVIEW
Financial results
Our business continued to strengthen during 2017, which was a dynamic year for the oil and gas sector that marked another step on the road to recovery for our industry. We successfully executed our strategy by growing our global market share, moving quickly to reactivate equipment and build new equipment in North America to meet customer demand, continuing to focus on cost efficiencies, and aligning our business with customers in the fastest growing market segments to collaborate and engineer solutions to maximize their asset value. In the beginning of 2017, we made the decision to bring back cold-stacked pressure pumping equipment more rapidly than originally planned because of customer demand and to maintain market share while capturing leading edge pricing. We have successfully executed this plan with the reactivated and new-build equipment enhancing our overall margins during 2017.
Our North American business continued to improve during 2017, with revenue growth of 71% outperforming the growth in average North American rig count of 69%, compared to 2016. We also experienced a significant margin improvement in 2017 and profitability growth in six consecutive quarters as a result of activity and pricing increases. We are diligently working towards optimizing margins and reaching targets we have set for our organization, which we believe are achievable through higher pricing, improved equipment utilization and technology solutions. While the international markets have been slower to recover and continue to face pricing pressure as customers defer new projects and focus on lowering costs, these regions showed signs of recovery in the latter half of 2017, driven primarily by improved performance in the Middle East, the North Sea and Latin America. We are committed to making these markets sustainable and have focused on the use of technology and lowering customer costs during the down cycle. Our product service lines continue to deliver technology driven value propositions to help our customers increase production and lower costs.
We generated total company revenue of $20.6 billion during 2017, a 30% increase from the $15.9 billion of revenue generated in 2016, with our Completion and Production segment improving 47% and our Drilling and Evaluation segment improving 8%. We also reported total company operating income of approximately $1.4 billion in 2017. These results were primarily driven by improved activity, utilization and pricing in the United States land market associated with stimulation, well completion and drilling services. Our operating results also benefited from the structural global cost savings initiatives implemented over the past few years to address challenging market conditions.
Business outlook
While the past few years have been challenging as we navigated through this industry cycle, we believe our financial results in 2017 reflect our successful execution in a dynamic environment and that our strategy has positioned us to take advantage of opportunities ahead. We are benefiting from our improved market share, delivery platform and cost containment strategies, and we are optimistic about the prospects for 2018.
In North America, improved commodity prices and rig counts from 2016 lows have resulted in a rapidly recovering market throughout 2017, particularly in United States unconventionals. At the current North American rig count, we are drilling approximately the same footage as the peak of 2014, but with less equipment in the field as we experience significantly increased completions intensity. As rig count stabilizes, our customers focus on efficiencies, optimization and production. We are continuing to collaborate and engineer solutions to maximize asset value for our customers and will continue to focus on increasing equipment utilization, managing costs and expanding our surface efficiency model.
Additionally, we gained significant North America market share through the downturn by demonstrating to our customers the benefits of our service quality and technology. We have been utilizing this increased market share to drive margin improvement. The historically high level of market share we built in the downturn gives us the ability to focus our work with the most efficient customers, and we continued to execute our strategy of high grading the profitability of our portfolio with customers that value our services.
While the international markets had been more resilient than North America through most of the downturn, we experienced activity reductions and pricing pressure in these markets in 2017 when compared to 2016, particularly in the Eastern Hemisphere. This was driven by stressed customer budgets and economics across deepwater and mature fields. However, the international sector began to show signs of recovery in the latter half of 2017. Heading into 2018, we are encouraged by these markets, with enhanced tender activity and constructive conversations with our international customers. While we expect international activity to gradually improve throughout 2018, we are cognizant that pricing pressure and
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concessions that have been given throughout the cycle need to be unwound. We will continue to collaborate with our customers to create solutions through technology and improved operating efficiency that will overcome challenging project economics.
During 2017, we had approximately $1.4 billion of capital expenditures, an increase of 72% from 2016, which was predominantly made in our Production Enhancement, Sperry Drilling, Production Solutions, Wireline and Perforating, and Baroid product service lines. We successfully executed our deployment strategy to reactivate our cold-stacked pressure pumping equipment to respond to customer demand and converting our hydraulic fracturing fleet to Q10 pumps to support our surface efficiency model. We remain committed to generating industry-leading returns and continue to be focused on achieving leading edge pricing, driving better utilization and continuous cost control.
During 2017, we acquired Summit ESP, Ingrain Inc. and Optimization Petroleum Technology. The additions of these three businesses strengthen our Artificial Lift, Wireline and Perforating, and Landmark portfolios for our customers.
We intend to continue to strengthen our product service lines through a combination of organic growth, investment and selective acquisitions. We plan to continue executing the following strategies in 2018:

- | directing capital and resources into strategic growth markets, including unconventional plays and mature fields;

- | leveraging our broad technology offerings to provide value to our customers and enable them to more efficiently drill and complete their wells;

- | exploring additional opportunities for acquisitions that will enhance or augment our current portfolio of services and products, including those with unique technologies or distribution networks in areas where we do not already have significant operations;

- | investing in technology that will help our customers reduce reservoir uncertainty and increase operational efficiency;

- | improving working capital and managing our balance sheet to maximize our financial flexibility;

- | continuing to seek ways to be one of the most cost-efficient service providers in the industry by maintaining capital discipline and leveraging our scale and breadth of operations;

- collaborating and engineering solutions to maximize asset value for our customers; and

- | striving to achieve superior growth and returns for our shareholders.

Our operating performance and business outlook are described in more detail in “Business Environment and Results of Operations.”
Financial markets, liquidity and capital resources
We believe we have invested our cash balances conservatively and secured sufficient financing to help mitigate any near-term negative impact on our operations from adverse market conditions. We had $2.3 billion of cash and equivalents as of December 31, 2017. We also have $3.0 billion available under our revolving credit facility which, combined with our cash balance, we believe provides us with sufficient liquidity to address the challenges and opportunities of the current market. Given our optimism about the business outlook and projected impact of U.S. tax reform, we are actively evaluating our options and opportunities around uses of cash, which could include debt retirements, funding acquisitions and organic growth projects and return of capital to shareholders. For additional information on market conditions, see “Liquidity and Capital Resources” and “Business Environment and Results of Operations.”
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LIQUIDITY AND CAPITAL RESOURCES
As of December 31, 2017, we had $2.3 billion of cash and equivalents, compared to $4.0 billion at December 31, 2016. Additionally, we held $106 million of investments in fixed income securities at December 31, 2017, compared to $92 million at December 31, 2016. These securities are reflected in "Other current assets" and "Other assets" in our consolidated balance sheets. Approximately $1.9 billion of our total cash position as of December 31, 2017 was held by our foreign subsidiaries, a substantial portion of which is available to be repatriated into the United States to fund our U.S. operations or for general corporate purposes, with a portion subject to certain country-specific restrictions. See Note 8 for further discussion regarding U.S. tax reform and its corresponding impact on foreign cash repatriation.
Significant sources and uses of cash
Sources of cash:

– | Cash flows from operating activities were $2.5 billion in 2017. This includes a United States tax refund of approximately $478 million that we received in the third quarter of 2017, primarily related to the carryback of our net operating losses recognized in 2016.

Uses of cash:

– | We paid an aggregate $1.6 billion on long-term borrowings in 2017. This includes an early redemption of $1.4 billion of senior notes during the first quarter of 2017, which resulted in a payment of approximately $1.5 billion, inclusive of the redemption premium. We also repaid $45 million of notes that matured during the second quarter of 2017. See Note 6 for further information.

– | Capital expenditures were $1.4 billion in 2017 and were predominantly made in our Production Enhancement, Sperry Drilling, Production Solutions, Wireline and Perforating and Baroid product service lines.

– | We paid approximately $630 million in the third quarter of 2017 to acquire Summit ESP, Ingrain Inc. and Optimization Petroleum Technology. The additions of these three businesses strengthen our artificial lift, wireline and Landmark portfolios for our global customers.

– | We paid $626 million of dividends to our shareholders in 2017.

– | Our primary components of net working capital (receivables, inventories and accounts payable) increased during the year by a net $626 million, primarily due to increased business activity.

– | We made the final installment settlement payment of $335 million related to the Macondo well incident, as well as our third and final legal fees payment of $33 million.

Future sources and uses of cash
We manufacture most of our own equipment, which allows us flexibility to increase or decrease our capital expenditures based on market conditions. Capital spending for 2018 is currently expected to be approximately $1.7 billion, an increase of over 25% from 2017. We expect capital spending to be in-line with our expected depreciation and amortization expense. The capital expenditures plan for 2018 is primarily directed towards our industry-leading pressure pumping fleet, the deployment of new Sperry drilling tools and the continued investment in our Artificial Lift and Multi-Chem product service lines.
Currently, our quarterly dividend rate is $0.18 per share, or approximately $156 million per quarter. Subject to Board of Directors approval, our intention is to continue paying dividends at our current rate during 2018. We also have $400 million senior notes that mature in August 2018, which we intend to repay with cash on hand.
Our Board of Directors has authorized a program to repurchase our common stock from time to time. Approximately $5.7 billion remains authorized for repurchases as of December 31, 2017, and may be used for open market and other share purchases. There were no repurchases made under the program during the year ended December 31, 2017.
We had $333 million of gross unrecognized tax benefits at December 31, 2017, of which we estimate $319 million may require a cash payment by us. We estimate that $296 million of the cash payment will not be settled within the next 12 months. We are not able to reasonably estimate in which future periods this amount will ultimately be settled and paid. Additionally, given our current U.S. tax attributes, we currently do not expect to pay any cash tax on our deemed repatriation tax obligations as a result of the recently enacted U.S. tax reform.
Given our optimism about the business outlook and projected impact of U.S. tax reform, we are actively evaluating our options and opportunities around uses of cash, which could include debt retirements, funding acquisitions and organic growth projects and return of capital to shareholders.
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Contractual obligations
The following table summarizes our significant contractual obligations and other long-term liabilities as of December 31, 2017:

| Payments Due |  |
Millions of dollars | 2018 | 2019 | 2020 | 2021 | 2022 | Thereafter | Total
Long-term debt (a) | $ | 440 |  | $ | 30 |  | $ | 26 |  | $ | 709 |  | $ | 14 |  | $ | 9,749 |  | $ | 10,968 |
Interest on debt (b) | 564 |  | 553 |  | 551 |  | 540 |  | 513 |  | 8,438 |  | 11,159 |
Operating leases | 166 |  | 135 |  | 100 |  | 71 |  | 54 |  | 194 |  | 720 |
Purchase obligations (c) | 485 |  | 76 |  | 71 |  | 26 |  | 19 |  | 38 |  | 715 |
Other long-term liabilities (d) | 32 |  | — |  | — |  | — |  | — |  | — |  | 32 |
Total | $ | 1,687 |  | $ | 794 |  | $ | 748 |  | $ | 1,346 |  | $ | 600 |  | $ | 18,419 |  | $ | 23,594 |

(a) | Represents principal amounts of long-term debt, including capital lease obligations and current maturities of debt, which excludes any unamortized debt issuance costs and discounts. See Note 6 to the consolidated financial statements.

(b) | Interest on debt includes 79 years of interest on $300 million of debentures at 7.6% interest that become due in 2096.

(c) | Amount in 2018 primarily represents certain purchase orders for goods and services utilized in the ordinary course of our business.

(d) | Represents pension funding obligations associated with international plans for 2018 only as we are currently not able to reasonably estimate our contributions for years after 2018.

Other factors affecting liquidity
Financial position in current market. As of December 31, 2017, we had $2.3 billion of cash and equivalents, $106 million in fixed income investments and $3.0 billion of available committed bank credit under our revolving credit facility. Furthermore, we have no financial covenants or material adverse change provisions in our bank agreements, and our debt maturities extend over a long period of time. We believe our cash on hand, cash flows generated from operations and our available credit facility will provide sufficient liquidity to address our global cash needs in 2018, including debt retirement, capital expenditures, working capital investments, dividends, if any, and contingent liabilities.
Guarantee agreements. In the normal course of business, we have agreements with financial institutions under which approximately $1.8 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of December 31, 2017. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.
Credit ratings. Our credit ratings with Standard & Poor’s (S&P) remain BBB+ for our long-term debt and A-2 for our short-term debt, with a stable outlook. Our credit ratings with Moody’s Investors Service (Moody's) remain Baa1 for our long-term debt and P-2 for our short-term debt, with a stable outlook.
Customer receivables. In line with industry practice, we bill our customers for our services in arrears and are, therefore, subject to our customers delaying or failing to pay our invoices. In weak economic environments, we may experience increased delays and failures to pay our invoices due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to the credit markets as well as unsettled political conditions. If our customers delay paying or fail to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition. See Part I, Item 1(a), “Risk Factors,” “Business Environment and Results of Operations,” and Note 3 to the consolidated financial statements for further discussion related to receivables from our primary customer in Venezuela.
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BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS
We operate in approximately 70 countries throughout the world to provide a comprehensive range of services and products to the energy industry. A significant amount of our consolidated revenue is derived from the sale of services and products to major, national and independent oil and natural gas companies worldwide. The industry we serve is highly competitive with many competitors in each segment of our business. In 2017, 2016 and 2015, based on the location of services provided and products sold, 53%, 41% and 44%, respectively, of our consolidated revenue was from the United States. No other country accounted for more than 10% of our revenue during these periods.
Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil unrest, force majeure, war or other armed conflict, sanctions, expropriation or other governmental actions, inflation, changes in foreign currency exchange rates, foreign currency exchange restrictions and highly inflationary currencies, as well as other geopolitical factors. We believe the geographic diversification of our business activities reduces the risk that loss of operations in any one country, other than the United States, would be materially adverse to our consolidated results of operations.
Activity within our business segments is significantly impacted by spending on upstream exploration, development and production programs by our customers. Also impacting our activity is the status of the global economy, which impacts oil and natural gas consumption.
Some of the more significant determinants of current and future spending levels of our customers are oil and natural gas prices, global oil supply, completions intensity, the world economy, the availability of credit, government regulation and global stability, which together drive worldwide drilling and completions activity. Lower oil and natural gas prices usually translate into lower exploration and production budgets and lower rig count. Our financial performance is therefore significantly affected by oil and natural gas prices and worldwide rig activity, which are summarized in the tables below.
The following table shows the average oil and natural gas prices for West Texas Intermediate (WTI), United Kingdom Brent crude oil and Henry Hub natural gas:

| 2017 | 2016 | 2015
Oil price - WTI (1) | $ | 50.93 |  | $ | 43.14 |  | $ | 48.69 |
Oil price - Brent (1) | 54.30 |  | 43.55 |  | 52.36 |
Natural gas price - Henry Hub (2) | 3.04 |  | 2.52 |  | 2.63 |
(1) Oil price measured in dollars per barrel (2) Natural gas price measured in dollars per million British thermal units (Btu), or MMBtu

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The historical average rig counts based on the weekly Baker Hughes rig count information were as follows:

Land vs. Offshore | 2017 | 2016 | 2015
United States: |  |  |
Land | 856 |  | 486 |  | 943 |
Offshore (incl. Gulf of Mexico) | 20 |  | 23 |  | 35 |
Total | 876 |  | 509 |  | 978 |
Canada: |  |  |  |  |  |
Land | 205 |  | 128 |  | 189 |
Offshore | 1 |  | 2 |  | 2 |
Total | 206 |  | 130 |  | 191 |
International (excluding Canada): |  |  |
Land | 751 |  | 734 |  | 884 |
Offshore | 198 |  | 221 |  | 283 |
Total | 949 |  | 955 |  | 1,167 |
Worldwide total | 2,031 |  | 1,594 |  | 2,336 |
Land total | 1,812 |  | 1,348 |  | 2,016 |
Offshore total | 219 |  | 246 |  | 320 |
Oil vs. Natural Gas | 2017 | 2016 | 2015
United States (incl. Gulf of Mexico): |  |  |
Oil | 704 |  | 409 |  | 751 |
Natural gas | 172 |  | 100 |  | 227 |
Total | 876 |  | 509 |  | 978 |
Canada: |  |  |
Oil | 109 |  | 63 |  | 84 |
Natural gas | 97 |  | 67 |  | 107 |
Total | 206 |  | 130 |  | 191 |
International (excluding Canada): |  |  |
Oil | 732 |  | 726 |  | 916 |
Natural gas | 217 |  | 229 |  | 251 |
Total | 949 |  | 955 |  | 1,167 |
Worldwide total | 2,031 |  | 1,594 |  | 2,336 |
Oil total | 1,545 |  | 1,198 |  | 1,751 |
Natural gas total | 486 |  | 396 |  | 585 |

Drilling Type | 2017 | 2016 | 2015
United States (incl. Gulf of Mexico): |  |  |
Horizontal | 736 | 400 | 744
Vertical | 70 | 60 | 139
Directional | 70 | 49 | 95
Total | 876 | 509 | 978

Crude oil prices have been extremely volatile during the past few years. WTI oil spot prices declined significantly beginning in 2014 from a peak price of $108 per barrel in June 2014 to a low of $26 per barrel in February 2016, a level which had not been experienced since 2003. Brent crude oil spot prices declined from a high of $115 per barrel in June 2014 to $26 per barrel in January 2016. Since the low point experienced in early 2016, oil prices have increased substantially. WTI oil spot prices ranged from a low of $42 per barrel in June 2017 to a high of $60 per barrel in December 2017. Brent crude oil spot prices ranged from a low of $44 in June 2017 to a high of $67 in December 2017. The average full year 2017 WTI and Brent crude oil spot prices of $51 per barrel and $54 per barrel increased 17% and 24% from 2016.
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WTI and Brent crude oil spot prices had a monthly average in December 2017 of $58 per barrel and $64 per barrel, respectively. Prices have increased steadily through the second half of the year, with year-end prices higher than the annual average. Most of the price movement reflects continuing draws on global oil inventory levels, geopolitical tensions, and the announcement from the Organization of the Petroleum Exporting Countries (OPEC) of an extension through the end of 2018 of its crude oil supply reduction agreement. Crude oil production in the United States is projected to average 10.3 million barrels per day in 2018, which will mark the highest annual average production in U.S. history.
In the United States Energy Information Administration (EIA) January 2018 "Short Term Energy Outlook," the EIA projects Brent prices to average $60 per barrel in 2018 and $61 per barrel in 2019, while WTI prices are projected to average about $4 less per barrel in both 2018 and 2019. The International Energy Agency's (IEA) January 2018 "Oil Market Report" forecasts the 2018 global demand to average approximately 99.1 million barrels per day, an increase of 1% from 2017, driven by increases in the Asia Pacific region, while all other regions remain approximately the same.
The Henry Hub natural gas spot price in the United States averaged $2.99 per MMBtu in 2017, an increase of $0.47 per MMBtu, or 19%, from 2016. The EIA January 2018 “Short Term Energy Outlook” projects Henry Hub natural gas prices to average $2.88 per MMBtu in 2018 and $2.92 per MMBtu in 2019, a slight decline over 2017 levels primarily due to strong expected production growth, which is forecast to meet growing domestic consumption and exports.
North America operations
The average North America oil-directed rig count increased 341 rigs, or 72%, for the full year 2017 as compared to 2016, while the average North America natural gas-directed rig count increased 102 rigs, or 61%, during the same period. In the United States land market during 2017, there was a 76% improvement in the average rig count compared to 2016 and completions activity continued to strengthen in this market for drilled but uncompleted wells. As a result of the recent uptick in activity and the structural changes to our delivery platform we made over the past few years, after recording operating losses in North America in 2016, we returned to operating profitability with continued improvements throughout 2017. Rig count has stabilized during the second half of 2017, with customers searching for improved production with an increased focus on efficiency and optimization of wells.
In the Gulf of Mexico, the average offshore rig count for 2017 was down 13% compared to 2016. Low commodity prices have stressed budgets and have impacted economics across the deepwater market, negatively impacting activity and pricing. These headwinds persist today, and we believe there will continue to be challenges in 2018 to deepwater project economics. Activity in the Gulf of Mexico is dependent on governmental approvals for permits, our customers' actions and the entry and exit of deepwater rigs in the market.
International operations
While the average international rig count for 2017 decreased by 1% compared to 2016, the international markets began to show signs of improvement in the second half of the year. This improvement was driven primarily by the Middle East, North Sea and Latin America. Lower sustained crude oil prices have caused many of our customers to reduce their budgets and defer several new projects; however, we have continued to work with our customers to improve project economics through technology and improved operating efficiency. For the Eastern Hemisphere, we believe the first quarter of 2017 represented the bottom of the international rig count. The Middle East remains our most active international market, with the largest part of the work focused on maximizing production in mature fields with the use of technology and expanded reservoir knowledge. While we expect the international markets will continue to gradually improve throughout 2018, there are still headwinds that must be overcome to obtain a full recovery. This includes an over capitalized market, pricing pressure and price concessions that we have taken throughout the down cycle which we need to recapture. We will continue to remain focused on efficiencies in our execution.
Venezuela. Venezuela continues to experience significant political and economic turmoil. At December 31, 2017, the Venezuelan government had a dual-rate foreign exchange system: (i) the DIPRO, which represented a protected rate of 10.0 Bolívares per United States dollar made available for vital imports such as food, medicine and raw materials for production; and (ii) the DICOM, which is intended to be a free floating system that will fluctuate according to market supply and demand. The DICOM foreign exchange rate continues to significantly devalue and had a market rate of 3,345 Bolívares per United States dollar at December 31, 2017, as compared to a market rate of 276 Bolívares per United States dollar in early 2016 when the DICOM was created. On January 29, 2018, the Venezuelan government announced that it has eliminated the DIPRO foreign exchange rate and all future currency transactions will be carried out at the DICOM rate. We are currently evaluating the impact that this change in foreign exchange system will have on our business, consolidated results of operations and consolidated financial condition. This includes potential further write-downs of our net investment in Venezuela, which was approximately $202 million as of December 31, 2017.
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We have continued to experience delays in collecting payments on our receivables from our primary customer in Venezuela. In November 2017, several credit rating agencies downgraded this customer’s credit rating, some as low as a default level. As a result of this credit downgrade, delayed payments on our promissory note and accounts receivable, and deteriorating market conditions in Venezuela, we recognized an aggregate charge of $647 million during 2017, representing a fair market value adjustment on our promissory note and a full reserve against our other accounts receivable with this customer. See Note 3 and Note 12 to the consolidated financial statements for additional information about outstanding receivables from our primary customer in Venezuela and Part I, Item 1(a), “Risk Factors” for additional information on risks associated with our operations in Venezuela, including recent sanctions imposed in Venezuela.
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RESULTS OF OPERATIONS IN 2017 COMPARED TO 2016

REVENUE: |  |  | Favorable | Percentage
Millions of dollars | 2017 | 2016 | (Unfavorable) | Change
Completion and Production | $ | 13,077 |  | $ | 8,882 |  | $ | 4,195 |  | 47 | %
Drilling and Evaluation | 7,543 |  | 7,005 |  | 538 |  | 8 |
Total revenue | $ | 20,620 |  | $ | 15,887 |  | $ | 4,733 |  | 30 | %
By geographic region: |  |  |  |
North America | $ | 11,564 |  | $ | 6,770 |  | $ | 4,794 |  | 71 | %
Latin America | 2,116 |  | 1,860 |  | 256 |  | 14 |
Europe/Africa/CIS | 2,781 |  | 2,993 |  | (212 | ) | (7 | )
Middle East/Asia | 4,159 |  | 4,264 |  | (105 | ) | (2 | )
Total | $ | 20,620 |  | $ | 15,887 |  | $ | 4,733 |  | 30 | %

OPERATING INCOME: |  |  | Favorable | Percentage
Millions of dollars | 2017 | 2016 | (Unfavorable) | Change
Completion and Production | $ | 1,621 |  | $ | 107 |  | $ | 1,514 |  | 1,415 | %
Drilling and Evaluation | 718 |  | 794 |  | (76 | ) | (10 | )
Total | 2,339 |  | 901 |  | 1,438 |  | 160 |
Corporate and other | (330 | ) | (4,322 | ) | 3,992 |  | 92 |
Impairments and other charges | (647 | ) | (3,357 | ) | 2,710 |  | 81 |
Total operating income (loss) | $ | 1,362 |  | $ | (6,778 | ) | $ | 8,140 |  | — |

Consolidated revenue in 2017 increased 30% compared to 2016, associated with improved utilization, pricing and activity, primarily attributable to higher stimulation activity, and well completion and drilling services in North America. Revenue from North America was 56% of consolidated revenue in 2017 and 43% of consolidated revenue in 2016.
We reported consolidated operating income of $1.4 billion in 2017, as compared to an operating loss of $6.8 billion in 2016. Higher consolidated operating results were primarily due to increases in stimulation activity and well completion services in North America. Operating results were also impacted by $647 million and $3.4 billion of impairments and other charges recorded during 2017 and 2016, respectively. Additionally, we incurred $4.1 billion of merger related costs during 2016, primarily due to a $3.5 billion termination fee and $464 million of charges resulting from our reversal of assets held for sale accounting.
OPERATING SEGMENTS
Completion and Production
Completion and Production revenue was $13.1 billion in 2017, an increase of $4.2 billion, or 47%, compared to 2016. Completion and Production operating income was $1.6 billion in 2017 compared to $107 million in 2016. Operating results significantly improved due to increased activity and pricing across the majority of our product service lines, primarily pressure pumping services in North America. International operating results improved slightly as increased pressure pumping services in the Middle East and Latin America were partially offset by reduced completion tool sales in the Eastern Hemisphere.
Drilling and Evaluation
Drilling and Evaluation revenue was $7.5 billion in 2017, an increase of $538 million, or 8%, from 2016. Drilling and Evaluation operating income was $718 million in 2017, a decrease of $76 million, or 10%, compared to 2016. Operating results improved for drilling services in North America as a result of improved pricing, utilization and rig count. These increases were offset by pricing pressure and activity reductions across the majority of our product service lines in the Eastern Hemisphere, particularly drilling and logging services, as well as activity reductions in Venezuela, primarily software sales and testing activity.
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GEOGRAPHIC REGIONS
North America
North America revenue was $11.6 billion in 2017, a 71% improvement compared to 2016. These results were driven by improved customer demand in our United States land sector with increases in both pricing and activity, primarily related to pressure pumping services, drilling activity and completion tool sales.
Latin America
Latin America revenue was $2.1 billion in 2017, a 14% increase compared to 2016, primarily related to higher drilling activity in Brazil and Colombia, as well as increased project management activity in Mexico. These increases were partially offset by reduced activity in the majority of our product service lines in Venezuela and lower completion tool sales in Brazil.
Europe/Africa/CIS
Europe/Africa/CIS revenue was $2.8 billion in 2017, a 7% decline compared to 2016. The decreases were driven by activity reductions and pricing pressure across the region, particularly in Angola and the North Sea, along with reduced completion tools sales and logging services throughout the region.
Middle East/Asia
Middle East/Asia revenue was $4.2 billion in 2017, a 2% decrease compared to 2016, driven by reduced activity and pricing pressure, particularly for drilling and logging services in Thailand, reductions across all of our product service lines in Indonesia and drilling services and completion tool sales across the region. These decreases were partially offset by improved stimulation and well intervention activity in the Middle East, increased project management activity in Iraq and improved activity across the majority of our product service lines in Australia.
OTHER OPERATING ITEMS
Corporate and other expenses were $330 million in 2017, as compared to $4.3 billion in 2016. The decrease was primarily driven by merger-related costs during 2016 of a $3.5 billion termination fee and $464 million of charges resulting from our reversal of assets held for sale accounting.
Impairments and other charges were $647 million in 2017 representing a fair market value adjustment on a promissory note from our primary customer in Venezuela and a full reserve against our other accounts receivable with this customer. See Note 3 to the consolidated financial statements for further information. This compares to $3.4 billion of impairments and other charges recorded in 2016, primarily as a result of the downturn in the energy market, which consisted of fixed asset impairments and write-offs, inventory write-downs, impairments of intangible assets, severance costs, country and facility closures, a loss on exchange for our Venezuela promissory note and other charges.
NONOPERATING ITEMS
Interest expense, net was $593 million in 2017, which includes $104 million in costs related to the early extinguishment of $1.4 billion of senior notes during the first quarter of 2017, offset by additional interest income recognized during the year related to interest receipts and accretion on the promissory note from our primary customer in Venezuela. See Note 3 to the consolidated financial statements for further information on our promissory note in Venezuela, including our decision to discontinue the note accretion beginning in 2018. We recognized $639 million of net interest expense in 2016, which includes $41 million of debt redemption fees and associated expenses related to the $2.5 billion of senior notes mandatorily redeemed in the second quarter of 2016, with the corresponding interest savings from these debt payments reflected in 2017.
Other, net was an $87 million loss in 2017, as compared to a $208 million loss in 2016, driven by foreign currency exchange losses in various countries primarily due to the strengthening U.S. dollar. During 2017, foreign exchange losses were primarily incurred in Brazil and Nigeria. During 2016, foreign exchange losses were primarily incurred in Egypt, Argentina and Brazil, including a $53 million loss for the devaluation of the Egyptian pound.
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Effective tax rate. During 2017, we recorded a total income tax provision of $1.1 billion on pre-tax income of $682 million, resulting in an effective tax rate of 165.8%. This includes $770 million of tax expenses associated with our preliminary estimate of the net impact of the United States tax reform enacted in 2017. During 2016, we recorded a total income tax benefit $1.9 billion on pre-tax losses of $7.6 billion, resulting in an effective tax rate of 24.4%. See Note 8 to the consolidated financial statements for significant drivers of these effective tax rates.
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RESULTS OF OPERATIONS IN 2016 COMPARED TO 2015

REVENUE: |  |  | Favorable | Percentage
Millions of dollars | 2016 | 2015 | (Unfavorable) | Change
Completion and Production | $ | 8,882 |  | $ | 13,682 |  | $ | (4,800 | ) | (35 | )%
Drilling and Evaluation | 7,005 |  | 9,951 |  | (2,946 | ) | (30 | )
Total revenue | $ | 15,887 |  | $ | 23,633 |  | $ | (7,746 | ) | (33 | )%
By geographic region: |  |  |  |
North America | $ | 6,770 |  | $ | 10,856 |  | $ | (4,086 | ) | (38 | )%
Latin America | 1,860 |  | 3,149 |  | (1,289 | ) | (41 | )
Europe/Africa/CIS | 2,993 |  | 4,175 |  | (1,182 | ) | (28 | )
Middle East/Asia | 4,264 |  | 5,453 |  | (1,189 | ) | (22 | )
Total | $ | 15,887 |  | $ | 23,633 |  | $ | (7,746 | ) | (33 | )%

OPERATING INCOME: |  |  | Favorable | Percentage
Millions of dollars | 2016 | 2015 | (Unfavorable) | Change
Completion and Production | $ | 107 |  | $ | 1,069 |  | $ | (962 | ) | (90 | )%
Drilling and Evaluation | 794 |  | 1,519 |  | (725 | ) | (48 | )
Total | 901 |  | 2,588 |  | (1,687 | ) | (65 | )
Corporate and other | (4,322 | ) | (576 | ) | (3,746 | ) | 650 |
Impairments and other charges | (3,357 | ) | (2,177 | ) | (1,180 | ) | 54 |
Total operating loss | $ | (6,778 | ) | $ | (165 | ) | $ | (6,613 | ) | 4,008 | %

Consolidated revenue in 2016 decreased 33% compared to 2015, associated with widespread pricing pressure and activity reductions on a global basis, primarily attributable to stimulation activity, well completion services and pricing declines in North America. Revenue outside of North America was 57% of consolidated revenue in 2016 and 54% of consolidated revenue in 2015.
We reported a consolidated operating loss of $6.8 billion in 2016, as compared to an operating loss of $165 million in 2015. Operating results were negatively impacted by $3.4 billion and $2.2 billion of impairments and other charges recorded during 2016 and 2015, respectively. Additionally, we incurred $4.1 billion of merger related costs during 2016, primarily due to the $3.5 billion termination fee and $464 million of charges resulting from our reversal of assets held for sale accounting, compared to $308 million of merger related costs during 2015. Also impacting consolidated operating results was the impact of the global downturn in the energy market, primarily pricing pressure and activity reductions in North America pressure pumping services and reduced well completion services globally.
OPERATING SEGMENTS
Completion and Production
Completion and Production revenue was $8.9 billion in 2016, a decrease of $4.8 billion, or 35%, compared to 2015, due to a decline in activity and pricing in the majority of our product service lines, particularly North America pressure pumping services which drove the majority of the revenue decline. International revenue declined as a result of reductions in well completion services and stimulation activity in all regions.
Completion and Production operating income was $107 million in 2016, compared to $1.1 billion of operating income in 2015, with decreased profitability across all regions as a result of global activity and pricing reductions, primarily in North America stimulation activity and completion of well services across all regions.
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Drilling and Evaluation
Drilling and Evaluation revenue was $7.0 billion in 2016, a decrease of $2.9 billion, or 30%, from 2015. Reductions were seen across all product service lines due to the low rig count, lower pricing and customer budget constraints worldwide.
Drilling and Evaluation operating income was $794 million in 2016, a decrease of $725 million, or 48%, compared to 2015, driven by a decline in activity and pricing across all regions, particularly drilling and logging activity in Middle East/Asia region and reduced fluid services in Latin America.
GEOGRAPHIC REGIONS
North America
North America revenue was $6.8 billion in 2016, a 38% decline compared to 2015, relative to a 45% decline in average North America rig count. The decline was driven by reduced activity and pricing pressure throughout the United States land market, specifically relating to stimulation and drilling activity.
Latin America
Latin America revenue was $1.9 billion in 2016, a 41% reduction compared to 2015. The reduction was primarily related to our decision to curtail activity in Venezuela and currency weakness in the country, reduced activity across all product service lines in Mexico and lower drilling activity in Brazil and Colombia.
Europe/Africa/CIS
Europe/Africa/CIS revenue was $3.0 billion in 2016, a decline of 28% compared to 2015. The decrease was driven by a reduction of activity in the North Sea, Angola, Nigeria and Congo, along with lower drilling activity, completion tools sales and pressure pumping services throughout the region.
Middle East/Asia
Middle East/Asia revenue was $4.3 billion in 2016, a reduction of 22% compared to 2015. This was the result of pricing concessions across the region, along with reduced activity for pressure pumping services in the Middle East, Indonesia and Australia, and a decline in drilling and logging activity in Indonesia, Malaysia and the Middle East.
OTHER OPERATING ITEMS
Corporate and other expenses increased to $4.3 billion in 2016, as compared to $576 million in 2015, primarily driven by merger related costs. During 2016, we incurred a $3.5 billion termination fee and $464 million of charges resulting from our reversal of assets held for sale accounting, as compared to $308 million of merger related costs during 2015.
Impairments and other charges. Primarily as a result of the downturn in the energy market and its corresponding impact on the company's business outlook, we recorded a total of approximately $3.4 billion in company-wide charges during 2016, which consisted of fixed asset impairments and write-offs, inventory write-downs, impairments of intangible assets, severance costs, country and facility closures, a loss on exchange for a promissory note from our primary customer in Venezuela and other charges. This compares to $2.2 billion of impairments and other charges recorded in 2015 which consisted of fixed asset impairments and write-offs, inventory write-downs, impairments of intangible assets, severance costs, country and facility closures and other charges.
NONOPERATING ITEMS
Interest expense, net increased $192 million in 2016, compared to 2015. This was primarily due to additional interest resulting from the $7.5 billion of senior notes issued in November 2015, coupled with the $41 million of redemption fees and associated costs, which were recorded through interest expense, related to the $2.5 billion of senior notes mandatorily redeemed during the second quarter of 2016. Additionally, we recognized interest income in 2016 related to interest receipts and accretion on the promissory note from our primary customer in Venezuela.
Other, net was a $208 million loss in 2016, as compared to a $324 million loss in 2015, driven by foreign currency exchange losses in various countries primarily due to the strengthening U.S. dollar. These losses included a $53 million loss in 2016 for the devaluation of the Egyptian pound and a $199 million loss in 2015 as a result of utilizing the new currency exchange mechanism in Venezuela. Also impacting both periods were foreign currency exchange losses in Brazil and Argentina. See "Business Environment and Results of Operations" for further information about Venezuela.
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Effective tax rate. During 2016, we recorded a total income tax benefit of $1.9 billion on pre-tax losses of $7.6 billion, resulting in an effective tax rate of 24.4%. During 2015, we recorded a total income tax benefit of $274 million on pre-tax losses of $936 million, resulting in an effective tax rate of 29.3%. See Note 8 to the consolidated financial statements for significant drivers of these effective tax rates.
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CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimations and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex judgments and assessments and is fundamental to our results of operations. We identified our most critical accounting estimates to be:

- | forecasting our effective income tax rate, including our future ability to utilize foreign tax credits and the realizability of deferred tax assets, and providing for uncertain tax positions;

- | legal, environmental and investigation matters;

- | valuations of long-lived assets, including intangible assets and goodwill;

- | purchase price allocation for acquired businesses; and

- | allowance for bad debts, primarily related to receivables in Venezuela.

We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We believe the following are the critical accounting policies used in the preparation of our consolidated financial statements, as well as the significant estimates and judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in this report.
Income tax accounting
We recognize the amount of taxes payable or refundable for the current year and use an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been recognized in our financial statements or tax returns. We apply the following basic principles in accounting for our income taxes:

- | a current tax liability or asset is recognized for the estimated taxes payable or refundable on tax returns for the current year;

- | a deferred tax liability or asset is recognized for the estimated future tax effects attributable to temporary differences and carryforwards;

- | the measurement of current and deferred tax liabilities and assets is based on provisions of the enacted tax law, and the effects of potential future changes in tax laws or rates are not considered; and

- | the value of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that, based on available evidence, are not expected to be realized.

We determine deferred taxes separately for each tax-paying component (an entity or a group of entities that is consolidated for tax purposes) in each tax jurisdiction. That determination includes the following procedures:

- | identifying the types and amounts of existing temporary differences;

- | measuring the total deferred tax liability for taxable temporary differences using the applicable tax rate;

- | measuring the total deferred tax asset for deductible temporary differences and operating loss carryforwards using the applicable tax rate;

- | measuring the deferred tax assets for each type of tax credit carryforward; and

- | reducing the deferred tax assets by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and estimates. Additionally, we use forecasts of certain tax elements, such as taxable income and foreign tax credit utilization, as well as evaluate the feasibility of implementing tax planning strategies. Given the inherent uncertainty involved with the use of such variables, there can be significant variation between anticipated and actual results. Unforeseen events may significantly impact these variables, and changes to these variables could have a material impact on our income tax accounts related to both continuing and discontinued operations.
We have operations in approximately 70 countries. Consequently, we are subject to the jurisdiction of a significant number of taxing authorities. The income earned in these various jurisdictions is taxed on differing bases, including income actually earned, income deemed earned and revenue-based tax withholding. The final determination of our income tax liabilities involves the interpretation of local tax laws, tax treaties and related authorities in each jurisdiction. Changes in the operating environment, including changes in tax law and currency/repatriation controls, could impact the determination of our income tax liabilities for a tax year.
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Tax filings of our subsidiaries, unconsolidated affiliates and related entities are routinely examined in the normal course of business by tax authorities. These examinations may result in assessments of additional taxes, which we work to resolve with the tax authorities and through the judicial process. Predicting the outcome of disputed assessments involves some uncertainty. Factors such as the availability of settlement procedures, willingness of tax authorities to negotiate and the operation and impartiality of judicial systems vary across the different tax jurisdictions and may significantly influence the ultimate outcome. We review the facts for each assessment, and then utilize assumptions and estimates to determine the most likely outcome and provide taxes, interest and penalties as needed based on this outcome. We provide for uncertain tax positions pursuant to current accounting standards, which prescribe a minimum recognition threshold and measurement methodology that a tax position taken or expected to be taken in a tax return is required to meet before being recognized in the financial statements. The standards also provide guidance for derecognition classification, interest and penalties, accounting in interim periods, disclosure and transition.
We are currently evaluating provisions of United States tax reform enacted in December 2017. In the fourth quarter of 2017, we recorded a provision to income taxes for our preliminary assessment of the impact of tax reform. As we do not have all the necessary information to analyze all income tax effects of tax reform, this is a provisional amount which we believe represents a reasonable estimate of the accounting implications of this tax reform. We will continue to evaluate tax reform and adjust the provisional amounts as additional information is obtained. The ultimate impact of tax reform may differ from our provisional amounts due to changes in our interpretations and assumptions, as well as additional regulatory guidance that may be issued. We expect to complete our detailed analysis no later than the fourth quarter of 2018. For further information, see Note 8 to the consolidated financial statements.
Legal, environmental and investigation matters
As discussed in Note 7 of our consolidated financial statements, as of December 31, 2017, we have accrued an estimate of the probable and estimable costs for the resolution of some of our legal, environmental and investigation matters. For other matters for which the liability is not probable and reasonably estimable, we have not accrued any amounts. Attorneys in our legal department monitor and manage all claims filed against us and review all pending investigations. Generally, the estimate of probable costs related to these matters is developed in consultation with internal and outside legal counsel representing us. Our estimates are based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. The accuracy of these estimates is impacted by, among other things, the complexity of the issues and the amount of due diligence we have been able to perform. We attempt to resolve these matters through settlements, mediation and arbitration proceedings when possible. If the actual settlement costs, final judgments or fines, after appeals, differ from our estimates, there may be a material adverse effect on our future financial results. We have in the past recorded significant adjustments to our initial estimates of these types of contingencies.
Value of long-lived assets, including intangible assets and goodwill
We carry a variety of long-lived assets on our balance sheet including property, plant and equipment, goodwill and other intangibles. Impairment is the condition that exists when the carrying amount of a long-lived asset exceeds its fair value, and any impairment charge that we record reduces our earnings. Goodwill is the excess of the cost of an acquired entity over the net of the amounts assigned to assets acquired and liabilities assumed. We conduct impairment tests on goodwill annually, during the third quarter, or more frequently whenever events or changes in circumstances indicate an impairment may exist. We conduct impairment tests on long-lived assets, other than goodwill, whenever events or changes in circumstances indicate that the carrying value may not be recoverable.
When conducting an impairment test on long-lived assets, other than goodwill, we first compare estimated future undiscounted cash flows associated with the asset to the asset’s carrying amount. If the undiscounted cash flows are less than the asset’s carrying amount, we then determine the asset's fair value by using a discounted cash flow analysis. These analyses are based on estimates such as management’s short-term and long-term forecast of operating performance, including revenue growth rates and expected profitability margins, estimates of the remaining useful life and service potential of the asset, and a discount rate based on our weighted average cost of capital.
We perform our goodwill impairment assessment for each reporting unit, which is the same as our reportable segments, the Completion and Production division and the Drilling and Evaluation division, comparing the estimated fair value of each reporting unit to the reporting unit’s carrying value, including goodwill. We estimate the fair value for each reporting unit using a discounted cash flow analysis based on management’s short-term and long-term forecast of operating performance. This analysis includes significant assumptions regarding discount rates, revenue growth rates, expected profitability margins, forecasted capital expenditures and the timing of expected future cash flows based on market conditions. If the estimated fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered impaired. If the carrying amount of a reporting unit exceeds its estimated fair value, an impairment loss is measured and recorded.
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The impairment assessments discussed above incorporate inherent uncertainties, including projected commodity pricing, supply and demand for our services and future market conditions, which are difficult to predict in volatile economic environments and could result in impairment charges in future periods if actual results materially differ from the estimated assumptions utilized in our forecasts. If crude oil prices decline significantly and remain at low levels for a sustained period of time, we could be required to record an impairment of the carrying value of our long-lived assets in the future which could have a material adverse impact on our operating results. See Note 1 to the consolidated financial statements for our accounting policies related to long-lived assets as well as the results of our annual goodwill impairment assessment.
Acquisitions-purchase price allocation
We allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. We use all available information to estimate fair values, including quoted market prices, the carrying value of acquired assets and widely accepted valuation techniques such as discounted cash flows. We engage third-party appraisal firms when appropriate to assist in fair value determination of inventories, identifiable intangible assets and any other significant assets or liabilities. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can materially impact our results of operations. Our acquisitions may also include contingent consideration, or earn-out provisions, which provide for additional consideration to be paid to the seller if certain future conditions are met. These earn-out provisions are estimated and recognized at fair value at the acquisition date based on projected earnings or other financial metrics over specified periods after the acquisition date. These estimates are reviewed during the specified period and adjusted based on actual results.
Allowance for bad debts, primarily related to receivables in Venezuela
We evaluate our global accounts receivable through a continuous process of assessing our portfolio on an individual customer and overall basis. This process consists of a thorough review of historical collection experience, current aging status of the customer accounts, financial condition of our customers and whether the receivables involve retainages. We also consider the economic environment of our customers, both from a marketplace and geographic perspective, in evaluating the need for an allowance. Based on our review of these factors, we establish or adjust allowances for specific customers and the accounts receivable portfolio as a whole. This process involves a high degree of judgment and estimation, and frequently involves significant dollar amounts. Accordingly, our results of operations can be affected by adjustments to the allowance due to actual write-offs that differ from estimated amounts. Our estimates of allowances for bad debts have historically been accurate. Over the last five years, our estimates of allowances for bad debts, as a percentage of notes and accounts receivable before the allowance, have ranged from 1.8% to 12.8%. During 2017, we significantly increased our allowance for bad debts related to accounts receivable with our primary customer in Venezuela as a result of delayed payments, deteriorating market conditions in Venezuela and a recent credit downgrade. At December 31, 2017, allowance for bad debts totaled $725 million, or 12.8% of notes and accounts receivable before the allowance. At December 31, 2016, allowance for bad debts totaled $175 million, or 4.3% of notes and accounts receivable before the allowance. A hypothetical 100 basis point change in our estimate of the collectability of our notes and accounts receivable balance as of December 31, 2017 would have resulted in a $57 million adjustment to 2017 total operating costs and expenses. See Note 3 to the consolidated financial statements for further information.
OFF BALANCE SHEET ARRANGEMENTS
At December 31, 2017, we had no material off balance sheet arrangements, except for operating leases. In the normal course of business, we have agreements with financial institutions under which approximately $1.8 billion of letters of credit, bank guarantees or surety bonds were outstanding as of December 31, 2017. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization. None of these off balance sheet arrangements either has, or is likely to have, a material effect on our consolidated financial statements. For information on our contractual obligations related to operating leases, see Note 7 to the consolidated financial statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Contractual obligations.”
FINANCIAL INSTRUMENT MARKET RISK
We are exposed to market risk from changes in foreign currency exchange rates and interest rates. We selectively manage these exposures through the use of derivative instruments, including forward foreign exchange contracts, foreign exchange options and interest rate swaps. The objective of our risk management strategy is to minimize the volatility from fluctuations in foreign currency and interest rates. We do not use derivative instruments for trading purposes. The counterparties to our forward contracts, options and interest rate swaps are global commercial and investment banks.
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We use a sensitivity analysis model to measure the impact of potential adverse movements in foreign currency exchange rates and interest rates. With respect to foreign exchange sensitivity, after consideration of the impact from our foreign exchange hedges, a hypothetical 10% adverse change in the value of all our foreign currency positions relative to the United States dollar as of December 31, 2017 would result in a $55 million, pre-tax, loss for our net monetary assets denominated in currencies other than United States dollars. With respect to interest rates sensitivity, after consideration of the impact from our interest rate swap, a hypothetical 100 basis point increase in the LIBOR rate would result in approximately an additional $1 million of interest charges for the year ended December 31, 2017.
There are certain limitations inherent in the sensitivity analyses presented, primarily due to the assumption that exchange rates and interest rates change instantaneously in an equally adverse fashion. In addition, the analyses are unable to reflect the complex market reactions that normally would arise from the market shifts modeled. While this is our best estimate of the impact of the various scenarios, these estimates should not be viewed as forecasts.
For further information regarding foreign currency exchange risk, interest rate risk and credit risk, see Note 12 to the consolidated financial statements.
ENVIRONMENTAL MATTERS
We are subject to numerous environmental, legal and regulatory requirements related to our operations worldwide. For information related to environmental matters, see Note 7 to the consolidated financial statements and Part I, Item 1(a), “Risk Factors.”
FORWARD-LOOKING INFORMATION
The Private Securities Litigation Reform Act of 1995 provides safe harbor provisions for forward-looking information. Forward-looking information is based on projections and estimates, not historical information. Some statements in this Form 10-K are forward-looking and use words like “may,” “may not,” “believe,” “do not believe,” “plan,” “estimate,” “intend,” “expect,” “do not expect,” “anticipate,” “do not anticipate,” “should,” "would," "could," “likely” and other expressions. We may also provide oral or written forward-looking information in other materials we release to the public. Forward-looking information involves risk and uncertainties and reflects our best judgment based on current information. Our results of operations can be affected by inaccurate assumptions we make or by known or unknown risks and uncertainties. In addition, other factors may affect the accuracy of our forward-looking information. As a result, no forward-looking information can be guaranteed. Actual events and the results of our operations may vary materially.
We do not assume any responsibility to publicly update any of our forward-looking statements regardless of whether factors change as a result of new information, future events or for any other reason. You should review any additional disclosures we make in our press releases and Forms 10-K, 10-Q and 8-K filed with or furnished to the SEC. We also suggest that you listen to our quarterly earnings release conference calls with financial analysts.
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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Halliburton Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in the Securities Exchange Act Rule 13a-15(f).
Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time.
In July 2017, we acquired Summit ESP. For purposes of determining the effectiveness of our internal control over financial reporting, management has excluded Summit ESP from its evaluation. The acquired business represented approximately 2% of our consolidated total assets at December 31, 2017 and less than 1% of our consolidated revenues for the year ended December 31, 2017.
Under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, we conducted an evaluation to assess the effectiveness of our internal control over financial reporting as of December 31, 2017 based upon criteria set forth in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that, as of December 31, 2017, our internal control over financial reporting is effective.
The effectiveness of Halliburton’s internal control over financial reporting as of December 31, 2017 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report that is included herein.
HALLIBURTON COMPANY
by

/s/ Jeffrey A. Miller |  | /s/ Christopher T. Weber
Jeffrey A. Miller |  | Christopher T. Weber
President and |  | Executive Vice President and
Chief Executive Officer |  | Chief Financial Officer

37

Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Halliburton Company:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Halliburton Company and subsidiaries (the “Company”) as of December 31, 2017 and 2016, and the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes (collectively, the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 9, 2018 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Change in Accounting Principle
As discussed in Note 14 to the consolidated financial statements, the Company changed its method of accounting for deferred income taxes related to intra-entity transfers other than inventory effective January 1, 2017 due to the adoption of FASB ASU 2016-16, Intra-Entity Transfers of Assets Other Than Inventory.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Company’s auditor since 2002.
Houston, Texas
February 9, 2018
38

Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Halliburton Company:
Opinion on Internal Control Over Financial Reporting
We have audited Halliburton Company’s (the “Company”) internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2017 and 2016, and the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and related notes (collectively, the “consolidated financial statements”), and our report dated February 9, 2018 expressed an unqualified opinion on those consolidated financial statements.
As described in Management’s Report on Internal Control Over Financial Reporting, management excluded from its assessment the internal control over financial reporting of Summit ESP (“Summit”), which was acquired during 2017 and whose total assets constituted 2% of consolidated total assets and total revenues constituted less than 1% of consolidated total revenue as of and for the year ended December 31, 2017. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Summit.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit 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 audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s 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. 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.
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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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.
/s/ KPMG LLP
Houston, Texas
February 9, 2018
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HALLIBURTON COMPANY Consolidated Statements of Operations
| Year Ended December 31
Millions of dollars and shares except per share data | 2017 | 2016 | 2015
Revenue: |  |  |
Services | $ | 15,408 |  | $ | 11,140 |  | $ | 16,981 |
Product sales | 5,212 |  | 4,747 |  | 6,652 |
Total revenue | 20,620 |  | 15,887 |  | 23,633 |
Operating costs and expenses: |  |  |
Cost of services | 14,213 |  | 11,253 |  | 16,014 |
Cost of sales | 4,142 |  | 3,770 |  | 5,099 |
Merger-related costs and termination fee | — |  | 4,057 |  | 308 |
Impairments and other charges | 647 |  | 3,357 |  | 2,177 |
General and administrative | 256 |  | 228 |  | 200 |
Total operating costs and expenses | 19,258 |  | 22,665 |  | 23,798 |
Operating income (loss) | 1,362 |  | (6,778 | ) | (165 | )
Interest expense, net of interest income of $112, $59 and $16 | (593 | ) | (639 | ) | (447 | )
Other, net | (87 | ) | (208 | ) | (324 | )
Income (loss) from continuing operations before income taxes | 682 |  | (7,625 | ) | (936 | )
Income tax benefit (provision) | (1,131 | ) | 1,858 |  | 274 |
Loss from continuing operations | (449 | ) | (5,767 | ) | (662 | )
Loss from discontinued operations, net | (19 | ) | (2 | ) | (5 | )
Net loss | $ | (468 | ) | $ | (5,769 | ) | $ | (667 | )
Net (income) loss attributable to noncontrolling interest | 5 |  | 6 |  | (4 | )
Net loss attributable to company | $ | (463 | ) | $ | (5,763 | ) | $ | (671 | )
Amounts attributable to company shareholders: |  |  |
Loss from continuing operations | $ | (444 | ) | $ | (5,761 | ) | $ | (666 | )
Loss from discontinued operations, net | (19 | ) | (2 | ) | (5 | )
Net loss attributable to company | $ | (463 | ) | $ | (5,763 | ) | $ | (671 | )
Basic and diluted loss per share attributable to company shareholders: |  |  |
Loss from continuing operations | $ | (0.51 | ) | $ | (6.69 | ) | $ | (0.78 | )
Loss from discontinued operations, net | (0.02 | ) | — |  | (0.01 | )
Net loss per share | $ | (0.53 | ) | $ | (6.69 | ) | $ | (0.79 | )
Basic and diluted weighted average common shares outstanding | 870 |  | 861 |  | 853 |
See notes to consolidated financial statements. |  |  |

41

HALLIBURTON COMPANY Consolidated Statements of Comprehensive Income
| Year Ended December 31
Millions of dollars | 2017 | 2016 | 2015
Net loss | $ | (468 | ) | $ | (5,769 | ) | $ | (667 | )
Other comprehensive income (loss), net of income taxes: |  |  |
Defined benefit and other post retirement plans adjustment | (22 | ) | (92 | ) | 105 |
Unrealized loss on cash flow hedges | — |  | — |  | (67 | )
Other | 7 |  | 1 |  | (2 | )
Other comprehensive income (loss), net of income taxes | (15 | ) | (91 | ) | 36 |
Comprehensive loss | $ | (483 | ) | $ | (5,860 | ) | $ | (631 | )
Comprehensive (income) loss attributable to noncontrolling interest | 5 |  | 6 |  | (4 | )
Comprehensive loss attributable to company shareholders | $ | (478 | ) | $ | (5,854 | ) | $ | (635 | )
See notes to consolidated financial statements. |  |  |

42

HALLIBURTON COMPANY Consolidated Balance Sheets
| December 31
Millions of dollars and shares except per share data | 2017 | 2016
Assets
Current assets: |  |
Cash and equivalents | $ | 2,337 |  | $ | 4,009 |
Receivables (net of allowances for bad debts of $725 and $175) | 5,036 |  | 3,922 |
Inventories | 2,396 |  | 2,275 |
Prepaid income taxes | 133 |  | 585 |
Other current assets | 875 |  | 886 |
Total current assets | 10,777 |  | 11,677 |
Property, plant and equipment (net of accumulated depreciation of $12,249 and $11,198) | 8,521 |  | 8,532 |
Goodwill | 2,693 |  | 2,414 |
Deferred income taxes | 1,230 |  | 1,960 |
Other assets | 1,864 |  | 2,417 |
Total assets | $ | 25,085 |  | $ | 27,000 |
Liabilities and Shareholders’ Equity
Current liabilities: |  |
Accounts payable | $ | 2,554 |  | $ | 1,764 |
Accrued employee compensation and benefits | 746 |  | 544 |
Short-term borrowings and current maturities of long-term debt | 512 |  | 170 |
Deferred revenue | 257 |  | 261 |
Taxes other than income | 231 |  | 218 |
Liabilities for Macondo well incident | — |  | 369 |
Other current liabilities | 562 |  | 697 |
Total current liabilities | 4,862 |  | 4,023 |
Long-term debt | 10,430 |  | 12,214 |
Employee compensation and benefits | 609 |  | 574 |
Other liabilities | 835 |  | 741 |
Total liabilities | 16,736 |  | 17,552 |
Shareholders’ equity: |  |
Common shares, par value $2.50 per share (authorized 2,000 shares, issued 1,069 and 1,070 shares) | 2,673 |  | 2,674 |
Paid-in capital in excess of par value | 207 |  | 201 |
Accumulated other comprehensive loss | (469 | ) | (454 | )
Retained earnings | 12,668 |  | 14,141 |
Treasury stock, at cost (196 and 204 shares) | (6,757 | ) | (7,153 | )
Company shareholders’ equity | 8,322 |  | 9,409 |
Noncontrolling interest in consolidated subsidiaries | 27 |  | 39 |
Total shareholders’ equity | 8,349 |  | 9,448 |
Total liabilities and shareholders’ equity | $ | 25,085 |  | $ | 27,000 |
See notes to consolidated financial statements. |  |

43

HALLIBURTON COMPANY Consolidated Statements of Cash Flows
| Year Ended December 31
Millions of dollars | 2017 | 2016 | 2015
Cash flows from operating activities: |  |  |
Net loss | $ | (468 | ) | $ | (5,769 | ) | $ | (667 | )
Adjustments to reconcile net loss to cash flows from operating activities: |  |  |
Depreciation, depletion and amortization | 1,556 |  | 1,503 |  | 1,835 |
Deferred income tax provision (benefit), continuing operations | 734 |  | (1,501 | ) | (224 | )
Impairments and other charges | 647 |  | 3,357 |  | 2,177 |
U.S. tax refund | 478 |  | 430 |  | — |
Payment related to the Macondo well incident | (368 | ) | (33 | ) | (333 | )
Cash impact of impairments and other charges - severance payments | — |  | (273 | ) | (304 | )
Changes in assets and liabilities: |  |  |
Receivables | (1,350 | ) | 899 |  | 1,468 |
Accounts payable | 753 |  | (219 | ) | (603 | )
Inventories | (29 | ) | 552 |  | 153 |
Other | 515 |  | (649 | ) | (596 | )
Total cash flows provided by (used in) operating activities | 2,468 |  | (1,703 | ) | 2,906 |
Cash flows from investing activities: |  |  |
Capital expenditures | (1,373 | ) | (798 | ) | (2,184 | )
Payments to acquire businesses, net of cash acquired | (628 | ) | (31 | ) | (39 | )
Proceeds from sales of property, plant and equipment | 158 |  | 222 |  | 168 |
Other investing activities | (84 | ) | (103 | ) | (137 | )
Total cash flows used in investing activities | (1,927 | ) | (710 | ) | (2,192 | )
Cash flows from financing activities: |  |  |
Payments on long-term borrowings | (1,641 | ) | (3,171 | ) | (8 | )
Dividends to shareholders | (626 | ) | (620 | ) | (614 | )
Proceeds from issuance of common stock | 158 |  | 186 |  | 167 |
Proceeds from issuance of long-term debt, net | 10 |  | 74 |  | 7,440 |
Other financing activities | (62 | ) | (9 | ) | 96 |
Total cash flows used in financing activities | (2,161 | ) | (3,540 | ) | 7,081 |
Effect of exchange rate changes on cash | (52 | ) | (115 | ) | (9 | )
Increase (decrease) in cash and equivalents | (1,672 | ) | (6,068 | ) | 7,786 |
Cash and equivalents at beginning of year | 4,009 |  | 10,077 |  | 2,291 |
Cash and equivalents at end of year | $ | 2,337 |  | $ | 4,009 |  | $ | 10,077 |
Supplemental disclosure of cash flow information: |  |  |
Cash payments (receipts) during the period for: |  |  |
Interest | $ | 594 |  | $ | 659 |  | $ | 380 |
Income taxes | $ | (178 | ) | $ | (20 | ) | $ | 370 |
See notes to consolidated financial statements. |  |  |

44

HALLIBURTON COMPANY Consolidated Statements of Shareholders' Equity
| Company Shareholders’ Equity |  |
Millions of dollars | Common Shares | Paid-in Capital in Excess of Par Value | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling interest in Consolidated Subsidiaries | Total
Balance at December 31, 2014 | $ | 2,679 |  | $ | 309 |  | $ | (8,131 | ) | $ | 21,809 |  | $ | (399 | ) | $ | 31 |  | $ | 16,298 |
Comprehensive income (loss): |  |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) | — |  | — |  | — |  | (671 | ) | — |  | 4 |  | (667 | )
Other comprehensive income | — |  | — |  | — |  | — |  | 36 |  | — |  | 36 |
Stock plans | (2 | ) | (39 | ) | 481 |  | — |  | — |  | — |  | 440 |
Cash dividends ($0.72 per share) | — |  | — |  | — |  | (614 | ) | — |  | — |  | (614 | )
Other | — |  | 4 |  | — |  | — |  | — |  | (2 | ) | 2 |
Balance at December 31, 2015 | $ | 2,677 |  | $ | 274 |  | $ | (7,650 | ) | $ | 20,524 |  | $ | (363 | ) | $ | 33 |  | $ | 15,495 |
Comprehensive income (loss): |  |  |  |  |  |  |
Net loss | — |  | — |  | — |  | (5,763 | ) | — |  | (6 | ) | (5,769 | )
Other comprehensive loss | — |  | — |  | — |  | — |  | (91 | ) | — |  | (91 | )
Stock plans | (3 | ) | (69 | ) | 497 |  | — |  | — |  | — |  | 425 |
Cash dividends ($0.72 per share) | — |  | — |  | — |  | (620 | ) | — |  | — |  | (620 | )
Other | — |  | (4 | ) | — |  | — |  | — |  | 12 |  | 8 |
Balance at December 31, 2016 | $ | 2,674 |  | $ | 201 |  | $ | (7,153 | ) | $ | 14,141 |  | $ | (454 | ) | $ | 39 |  | $ | 9,448 |
Comprehensive income (loss): |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net loss | — |  | — |  | — |  | (463 | ) | — |  | (5 | ) | (468 | )
Retained earnings adjustment for new accounting standard | — |  | — |  | — |  | (384 | ) | — |  | — |  | (384 | )
Other comprehensive loss | — |  | — |  | — |  | — |  | (15 | ) | — |  | (15 | )
Stock plans | (1 | ) | 6 |  | 396 |  | — |  | — |  | — |  | 401 |
Cash dividends ($0.72 per share) | — |  | — |  | — |  | (626 | ) | — |  | — |  | (626 | )
Other | — |  | — |  | — |  | — |  | — |  | (7 | ) | (7 | )
Balance at December 31, 2017 | $ | 2,673 |  | $ | 207 |  | $ | (6,757 | ) | $ | 12,668 |  | $ | (469 | ) | $ | 27 |  | $ | 8,349 |
See notes to consolidated financial statements. |  |  |  |

45

HALLIBURTON COMPANY
Notes to Consolidated Financial Statements
Note 1. Description of Company and Significant Accounting Policies
Description of Company
Halliburton Company’s predecessor was established in 1919 and incorporated under the laws of the State of Delaware in 1924. We help our customers maximize value throughout the lifecycle of the reservoir - from locating hydrocarbons and managing geological data, to drilling and formation evaluation, well construction and completion and optimizing production throughout the life of the asset. We serve major, national and independent oil and natural gas companies throughout the world and operate under two divisions, which form the basis for the two operating segments we report, the Completion and Production segment and the Drilling and Evaluation segment.
Use of estimates
Our financial statements are prepared in conformity with United States generally accepted accounting principles, requiring us to make estimates and assumptions that affect:

- | the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements; and

- | the reported amounts of revenue and expenses during the reporting period.

We believe the most significant estimates and assumptions are associated with the forecasting of our effective income tax rate and the valuation of deferred taxes, legal and environmental reserves, long-lived asset valuations, purchase price allocations and allowance for bad debts. Ultimate results could differ from our estimates.
Basis of presentation
The consolidated financial statements include the accounts of our company and all of our subsidiaries that we control or variable interest entities for which we have determined that we are the primary beneficiary. All material intercompany accounts and transactions are eliminated. Investments in companies in which we do not have a controlling interest, but over which we do exercise significant influence, are accounted for using the equity method of accounting. If we do not have significant influence, we use the cost method of accounting. In addition, certain reclassifications of prior period balances have been made to conform to the current period presentation.
Revenue recognition
Our services and products are generally sold based upon purchase orders or contracts with our customers that include fixed or determinable prices but do not include right of return provisions or other significant post-delivery obligations. Our products are produced in a standard manufacturing operation, even if produced to our customer’s specifications. We recognize revenue from product sales when title passes to the customer, the customer assumes risks and rewards of ownership, collectability is reasonably assured and delivery occurs as directed by our customer. Service revenue, including training and consulting services, is recognized when the services are rendered and collectability is reasonably assured. Rates for services are typically priced on a per day, per meter, per man-hour or similar basis. We will adopt a new revenue recognition standard effective January 1, 2018 that will supersede existing revenue recognition guidance. See Note 14 for additional information.
Research and development
Research and development costs are expensed as incurred. Research and development costs were $360 million in 2017, $329 million in 2016 and $487 million in 2015.
Cash equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Inventories
Inventories are stated at the lower of cost and net realizable value. Cost represents invoice or production cost for new items and original cost less allowance for condition for used material returned to stock. Production cost includes material, labor and manufacturing overhead. Some domestic manufacturing and field service finished products and parts inventories for drill bits, completion products and bulk materials are recorded using the last-in, first-out method. The remaining inventory is recorded on the average cost method. We regularly review inventory quantities on hand and record provisions for excess or obsolete inventory based primarily on historical usage, estimated product demand and technological developments.
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Allowance for bad debts
We establish an allowance for bad debts through a review of several factors, including historical collection experience, current aging status of the customer accounts and financial condition of our customers. Our policy is to write off bad debts when the customer accounts are determined to be uncollectible.
Property, plant and equipment
Other than those assets that have been written down to their fair values due to impairment, property, plant and equipment are reported at cost less accumulated depreciation, which is generally provided on the straight-line method over the estimated useful lives of the assets. Accelerated depreciation methods are used for tax purposes, wherever permitted. Upon sale or retirement of an asset, the related costs and accumulated depreciation are removed from the accounts and any gain or loss is recognized. Planned major maintenance costs are generally expensed as incurred. Expenditures for additions, modifications and conversions are capitalized when they increase the value or extend the useful life of the asset.
Goodwill and other intangible assets
We record as goodwill the excess purchase price over the fair value of the tangible and identifiable intangible assets acquired in a business acquisition. Changes in the carrying amount of goodwill are detailed below by reportable segment.

Millions of dollars | Completion and Production | Drilling and Evaluation | Total
Balance at December 31, 2015: | $ | 1,634 |  | $ | 751 |  | $ | 2,385 |
Current year acquisitions | 31 |  | — |  | 31 |
Purchase price adjustments for previous acquisitions | (2 | ) | — |  | (2 | )
Other | 16 |  | (16 | ) | — |
Balance at December 31, 2016: | $ | 1,679 |  | $ | 735 |  | $ | 2,414 |
Current year acquisitions | 249 |  | 36 |  | 285 |
Purchase price adjustments for previous acquisitions | (6 | ) | — |  | (6 | )
Balance at December 31, 2017: | $ | 1,922 |  | $ | 771 |  | $ | 2,693 |

During 2017, we acquired three businesses, Summit ESP, Ingrain Inc. and Optimization Petroleum Technology, which resulted in approximately $285 million of additional goodwill based on our preliminary purchase price allocations. The reported amounts of goodwill for each reporting unit are reviewed for impairment on an annual basis, during the third quarter, and more frequently when circumstances indicate an impairment may exist. As a result of our goodwill impairment assessments performed in the years ended December 31, 2017, 2016 and 2015, we determined that the fair value of each reporting unit exceeded its net book value and, therefore, no goodwill impairments were deemed necessary. For further information on our goodwill impairment assessments, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates.”
We amortize other identifiable intangible assets with a finite life on a straight-line basis over the period which the asset is expected to contribute to our future cash flows, ranging from one to fifteen years. The components of these other intangible assets generally consist of patents, license agreements, non-compete agreements, trademarks and customer lists and contracts.
Evaluating impairment of long-lived assets
When events or changes in circumstances indicate that long-lived assets other than goodwill may be impaired, an evaluation is performed. For an asset classified as held for use, the estimated future undiscounted cash flows associated with the asset are compared to the asset’s carrying amount to determine if a write-down to fair value is required. When an asset is classified as held for sale, the asset’s book value is evaluated and adjusted to the lower of its carrying amount or fair value less cost to sell. In addition, depreciation and amortization is ceased while it is classified as held for sale.
Income taxes
We recognize the amount of taxes payable or refundable for the year. In addition, deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the financial statements or tax returns. A valuation allowance is provided for deferred tax assets if it is more likely than not that these items will not be realized.
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In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that we will realize the benefits of these deductible differences, net of the existing valuation allowances.
We recognize interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing operations in our consolidated statements of operations.
During 2017, the President of the United States signed into law what is informally called the Tax Cuts and Jobs Act of 2017, a comprehensive U.S. tax reform package that, effective January 1, 2018, among other things, lowered the corporate income tax rate from 35% to 21% and moved the country towards a territorial tax system with a one-time mandatory tax on previously deferred foreign earnings of foreign subsidiaries. See Note 8 for further information.
Derivative instruments
At times, we enter into derivative financial transactions to hedge existing or projected exposures to changing foreign currency exchange rates and interest rates. We do not enter into derivative transactions for speculative or trading purposes. We recognize all derivatives on the balance sheet at fair value. Derivatives that are not hedges are adjusted to fair value and reflected through the results of operations. If the derivative is designated as a hedge, depending on the nature of the hedge, changes in the fair value of derivatives are either offset against:

- | the change in fair value of the hedged assets, liabilities or firm commitments through earnings; or

- | recognized in other comprehensive income until the hedged item is recognized in earnings.

The ineffective portion of a derivative’s change in fair value is recognized in earnings. Recognized gains or losses on derivatives entered into to manage foreign currency exchange risk are included in “Other, net” on the consolidated statements of operations. Gains or losses on interest rate derivatives are included in “Interest expense, net.”
Foreign currency translation
Foreign entities whose functional currency is the United States dollar translate monetary assets and liabilities at year-end exchange rates, and nonmonetary items are translated at historical rates. Revenue and expense transactions are translated at the average rates in effect during the year, except for those expenses associated with nonmonetary balance sheet accounts, which are translated at historical rates. Gains or losses from remeasurement of monetary assets and liabilities due to changes in exchange rates are recognized in our consolidated statements of operations in “Other, net” in the year of occurrence.
Stock-based compensation
Stock-based compensation cost is measured at the date of grant, based on the calculated fair value of the award and is recognized as expense over the employee’s service period, which is generally the vesting period of the equity grant. Additionally, compensation cost is recognized based on awards ultimately expected to vest, therefore, we have reduced the cost for estimated forfeitures based on historical forfeiture rates. Forfeitures are estimated at the time of grant and revised in subsequent periods to reflect actual forfeitures. See Note 10 and Note 14 for additional information related to stock-based compensation.
Note 2. Business Segment and Geographic Information
We operate under two divisions, which form the basis for the two operating segments we report: the Completion and Production segment and the Drilling and Evaluation segment. For more information about the product service lines included in each segment, see Part I, Item 1, "Business.” Corporate and other includes certain expenses not attributable to a particular business segment such as costs related to support functions and corporate executives. Other items include amortization expense associated with intangible assets recorded as a result of our acquisitions in 2017 and merger-related costs in 2016 and 2015. The balance sheet for Corporate is primarily composed of cash and equivalents, deferred tax assets and investment securities. Intersegment revenue and revenue between geographic areas are immaterial. Our equity in earnings and losses of unconsolidated affiliates that are accounted for using the equity method of accounting are included within cost of services and cost of sales on our statements of operations, which is part of operating income of the applicable segment.
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The following tables present financial information on our business segments.

Operations by business segment |  |  |
| Year Ended December 31
Millions of dollars | 2017 | 2016 | 2015
Revenue: |  |  |
Completion and Production | $ | 13,077 |  | $ | 8,882 |  | $ | 13,682 |
Drilling and Evaluation | 7,543 |  | 7,005 |  | 9,951 |
Total revenue | $ | 20,620 |  | $ | 15,887 |  | $ | 23,633 |
Operating income (loss): |  |  |
Completion and Production | $ | 1,621 |  | $ | 107 |  | $ | 1,069 |
Drilling and Evaluation | 718 |  | 794 |  | 1,519 |
Total operations | 2,339 |  | 901 |  | 2,588 |
Corporate and other (a) | (330 | ) | (4,322 | ) | (576 | )
Impairments and other charges (b) | (647 | ) | (3,357 | ) | (2,177 | )
Total operating income (loss) | $ | 1,362 |  | $ | (6,778 | ) | $ | (165 | )
Interest expense, net of interest income | $ | (593 | ) | $ | (639 | ) | $ | (447 | )
Other, net | (87 | ) | (208 | ) | (324 | )
Income (loss) from continuing operations before income taxes | $ | 682 |  | $ | (7,625 | ) | $ | (936 | )
Capital expenditures: |  |  |
Completion and Production | $ | 1,111 |  | $ | 500 |  | $ | 1,526 |
Drilling and Evaluation | 261 |  | 297 |  | 650 |
Corporate and other | 1 |  | 1 |  | 8 |
Total | $ | 1,373 |  | $ | 798 |  | $ | 2,184 |
Depreciation, depletion and amortization: |  |  |
Completion and Production | $ | 953 |  | $ | 900 |  | $ | 1,160 |
Drilling and Evaluation | 563 |  | 569 |  | 638 |
Corporate and other | 40 |  | 34 |  | 37 |
Total | $ | 1,556 |  | $ | 1,503 |  | $ | 1,835 |

(a) Includes merger-related costs for the periods presented, including a $3.5 billion termination fee and an aggregate $464 million of charges for the reversal of assets held for sale accounting during the year ended December 31, 2016.
(b) Impairments and other charges are as follows:
-For the year ended December 31, 2017, the aggregate charge of $647 million represents a fair market value adjustment on our existing promissory note with our primary customer in Venezuela and a full reserve against our other accounts receivable with this customer.
-For the year ended December 31, 2016, includes $2.1 billion attributable to Completion and Production, $1.2 billion attributable to Drilling and Evaluation and $10 million attributable to Corporate and other.
-For the year ended December 31, 2015, includes $1.1 billion attributable to Completion and Production, $1.0 billion attributable to Drilling and Evaluation and $88 million attributable to Corporate and other.

| December 31
Millions of dollars | 2017 | 2016
Total assets: |  |
Completion and Production | $ | 12,276 |  | $ | 10,349 |
Drilling and Evaluation | 7,837 |  | 8,473 |
Shared assets | 2,913 |  | 3,371 |
Corporate and other | 2,059 |  | 4,807 |
Total | $ | 25,085 |  | $ | 27,000 |

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Not all assets are associated with specific segments. Those assets specific to segments include receivables, inventories, certain identified property, plant and equipment (including field service equipment), equity in and advances to related companies and goodwill. The remaining assets, such as cash and equivalents, are considered to be shared among the segments.
The following tables present information by geographic area. In 2017, 2016 and 2015, based on the location of services provided and products sold, 53%, 41% and 44% of our consolidated revenue was from the United States. As of December 31, 2017 and December 31, 2016, 56% and 50% of our property, plant and equipment was located in the United States. No other country accounted for more than 10% of our revenue or property, plant and equipment during the periods presented.

Operations by geographic region |
| Year Ended December 31
Millions of dollars | 2017 | 2016 | 2015
Revenue: |  |  |
North America | $ | 11,564 |  | $ | 6,770 |  | $ | 10,856 |
Latin America | 2,116 |  | 1,860 |  | 3,149 |
Europe/Africa/CIS | 2,781 |  | 2,993 |  | 4,175 |
Middle East/Asia | 4,159 |  | 4,264 |  | 5,453 |
Total | $ | 20,620 |  | $ | 15,887 |  | $ | 23,633 |

| December 31
Millions of dollars | 2017 | 2016
Net property, plant and equipment: |  |
North America | $ | 4,922 |  | $ | 4,431 |
Latin America | 945 |  | 1,068 |
Europe/Africa/CIS | 1,098 |  | 1,253 |
Middle East/Asia | 1,556 |  | 1,780 |
Total | $ | 8,521 |  | $ | 8,532 |

Note 3. Receivables
As of December 31, 2017, 42% of our net trade receivables were from customers in the United States. As of December 31, 2016, 27% of our net trade receivables were from customers in the United States and 15% were from customers in Venezuela. Other than the United States and Venezuela, no other country or single customer accounted for more than 10% of our trade receivables at these dates.
We routinely monitor the financial stability of our customers, and employ an extensive process to evaluate the collectability of outstanding receivables. This process, which involves a high degree of judgment utilizing significant assumptions, includes analysis of our customers’ historical time to pay, financial condition and various financial metrics, debt structure, credit agency ratings and production profile, as well as political and economic factors in countries of operations and other customer-specific factors.
Venezuela. We continue to experience delays in collecting payments on our receivables from our primary customer in Venezuela. These outstanding receivables are not disputed, and we have not historically had material write-offs relating to this customer. We are actively managing our strategic relationship with this customer, with ongoing dialogue between key executives of both companies, including discussions regarding this customer's intention to pay outstanding receivables. We will continue to vigorously pursue collection as we do business going forward in accordance with applicable U.S. sanctions.
During 2016, we exchanged $200 million of accounts receivables with our primary customer in Venezuela for an interest-bearing promissory note with a par value of the same amount. We recognized a pre-tax loss on the exchange of $148 million at that time and had been accreting the carrying amount of the note to its par value from the third quarter of 2016 through the fourth quarter of 2017. We received our first principal payment in November 2017 and received five scheduled interest payments since the note’s inception, but have not received the principal and interest payments scheduled in December 2017. In November 2017, several credit rating agencies downgraded this customer’s credit rating, some as low as a default level.
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As a result of this credit downgrade, delayed payments, and deteriorating market conditions in Venezuela, we changed our accounting for our promissory note from held-to-maturity to available-for-sale, will no longer accrete the value of the note going forward, and will mark the note to its fair market value on a quarterly basis with any unrealized gains and losses included as a component of accumulated other comprehensive loss. Accordingly, we recognized an aggregate charge of $385 million during the fourth quarter of 2017, consisting of $77 million for a fair market value adjustment of the note and $308 million for a full reserve against our other accounts receivable with this customer. During the second quarter of 2017, we recognized a charge of $262 million in anticipation of completing an additional note exchange with this customer. However, based on recent executive management changes at, and recent conversations with, this customer, we no longer expect this transaction to take place. The aggregate charges of $647 million during 2017 relating to Venezuela are included within "Impairments and other charges" in our consolidated statements of operations.
As of December 31, 2017, we had $117 million in total outstanding net trade receivables in Venezuela, compared to $610 million as of December 31, 2016. The majority of these receivables are United States dollar-denominated. Additionally, the carrying amount of our existing promissory note was $32 million as of December 31, 2017 and classified as “Other assets” on our consolidated balance sheets, compared to its par value of $175 million. We still intend to hold this promissory note to maturity and will continue to vigorously pursue collection on this note and other accounts receivable with this customer.
On January 29, 2018, the Venezuelan government announced that it has changed the existing dual-rate foreign exchange system by eliminating the DIPRO foreign exchange rate. All future currency transactions will now be carried out at the DICOM floating rate. We are currently evaluating the impact that this change in foreign exchange system will have on our business, consolidated results of operations and consolidated financial condition. This includes potential further write-downs of our net investment in Venezuela, which was approximately $202 million as of December 31, 2017. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment and Results of Operations” for additional information about the foreign currency exchange system in Venezuela, Note 12 for additional information about the promissory note and Part I, Item 1(a), “Risk Factors” for additional information on risks associated with our operations in Venezuela, including recent sanctions imposed in the country.
The following table presents a rollforward of our global allowance for bad debts for 2015, 2016 and 2017.

Millions of dollars | Balance at Beginning of Period | Charged to Costs and Expenses | Write-Offs | Balance at End of Period
Year ended December 31, 2015 | $ | 137 |  | $ | 44 |  | $ | (36 | ) | $ | 145 |
Year ended December 31, 2016 | 145 |  | 50 |  | (20 | ) | 175 |
Year ended December 31, 2017 | 175 |  | 568 |  | (18 | ) | 725 |

Note 4. Inventories
Inventories are stated at the lower of cost and net realizable value. In the United States, we manufacture certain finished products and parts inventories for drill bits, completion products, bulk materials and other tools that are recorded using the last-in, first-out method, which totaled $177 million at December 31, 2017 and $133 million at December 31, 2016. If the average cost method had been used, total inventories would have been $31 million higher than reported as of December 31, 2017 and $16 million higher as of December 31, 2016. The cost of the remaining inventory was recorded using the average cost method. Inventories consisted of the following:

| December 31
Millions of dollars | 2017 | 2016
Finished products and parts | $ | 1,547 |  | $ | 1,388 |
Raw materials and supplies | 703 |  | 778 |
Work in process | 146 |  | 109 |
Total | $ | 2,396 |  | $ | 2,275 |

All amounts in the table above are reported net of obsolescence reserves of $276 million at December 31, 2017 and $263 million at December 31, 2016.
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Note 5. Property, Plant and Equipment
Property, plant and equipment were composed of the following:

| December 31
Millions of dollars | 2017 | 2016
Land | $ | 248 |  | $ | 228 |
Buildings and property improvements | 3,460 |  | 3,399 |
Machinery, equipment and other | 17,062 |  | 16,103 |
Total | 20,770 |  | 19,730 |
Less accumulated depreciation | 12,249 |  | 11,198 |
Net property, plant and equipment | $ | 8,521 |  | $ | 8,532 |

Classes of assets are depreciated over the following useful lives:

| Buildings and Property Improvements
| 2017 | 2016
1 - 10 years | 11% | 11%
11 - 20 years | 42% | 42%
21 - 30 years | 22% | 22%
31 - 40 years | 25% | 25%

| Machinery, Equipment and Other
| 2017 | 2016
1 - 5 years | 35% | 34%
6 - 10 years | 56% | 57%
11 - 20 years | 9% | 9%

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Note 6. Debt
Our total debt, including short-term borrowings and current maturities of long-term debt, consisted of the following:

| December 31
Millions of dollars | 2017 | 2016
5.0% senior notes due November 2045 | $ | 2,000 |  | $ | 2,000 |
3.8% senior notes due November 2025 | 2,000 |  | 2,000 |
3.5% senior notes due August 2023 | 1,100 |  | 1,100 |
4.85% senior notes due November 2035 | 1,000 |  | 1,000 |
7.45% senior notes due September 2039 | 1,000 |  | 1,000 |
4.75% senior notes due August 2043 | 900 |  | 900 |
6.7% senior notes due September 2038 | 800 |  | 800 |
3.25% senior notes due November 2021 | 500 |  | 500 |
4.5% senior notes due November 2041 | 500 |  | 500 |
2.0% senior notes due August 2018 | 400 |  | 400 |
7.6% senior debentures due August 2096 | 300 |  | 300 |
8.75% senior debentures due February 2021 | 185 |  | 185 |
6.75% notes due February 2027 | 104 |  | 104 |
6.15% senior notes due September 2019 | — |  | 1,000 |
5.9% senior notes due September 2018 | — |  | 400 |
7.53% notes due May 2017 | — |  | 45 |
Other | 251 |  | 260 |
Unamortized debt issuance costs and discounts | (98 | ) | (110 | )
Total | 10,942 |  | 12,384 |
Short-term borrowings and current maturities of long-term debt | (512 | ) | (170 | )
Total long-term debt | $ | 10,430 |  | $ | 12,214 |

Senior debt
All of our senior notes and debentures rank equally with our existing and future senior unsecured indebtedness, have semiannual interest payments and have no sinking fund requirements. We may redeem all of our senior notes from time to time or all of the notes of each series at any time at the applicable redemption prices, plus accrued and unpaid interest. Our 7.60% and 8.75% senior debentures may not be redeemed prior to maturity.
In March 2017, we used cash on hand to redeem an aggregate principal amount of $1.4 billion of senior notes, which consisted of $400 million of 5.9% senior notes due September 2018 and $1.0 billion of 6.15% senior notes due September 2019. In conjunction with this redemption, we terminated a series of interest rate swaps associated with these senior notes. As a result, we recorded $104 million in costs related to the early extinguishment of debt, which included the redemption premium and a write-off of the remaining original debt issuance costs and debt discount, partially offset by a gain from the termination of the related interest rate swap agreements. These debt extinguishment costs are included in interest expense on our consolidated statement of operations for the year ended December 31, 2017. We also repaid $45 million of notes that matured in May 2017. Our $400 million of 2.0% senior notes will mature in August 2018, which we intend to repay with cash on hand.
Revolving credit facilities
We have a revolving credit facility with a capacity of $3.0 billion which expires in July 2020. The facility is for working capital or general corporate purposes. The full amount of the revolving credit facility was available as of December 31, 2017.
Debt maturities
Our long-term debt matures as follows: $440 million in 2018, $30 million in 2019, $26 million in 2020, $709 million in 2021, $14 million in 2022 and the remainder in 2023 and thereafter.
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Note 7. Commitments and Contingencies
Securities and related litigation
In June 2002, a class action lawsuit was commenced against us in federal court alleging violations of the federal securities laws in connection with our change in accounting for revenue on long-term construction projects and related disclosures. In the weeks that followed, approximately twenty similar class actions were filed against us. The class action cases were later consolidated, and the amended consolidated class action complaint was filed and served upon us in April 2003. In June 2003, the plaintiffs filed a second amended consolidated complaint that included claims arising out of our 1998 acquisition of Dresser Industries, Inc. and our disclosures and reserves relating to our asbestos liability exposure.
In December 2016, we reached an agreement in principle to settle this lawsuit, without any admission of liability and subject to approval by the district court. During the second quarter of 2017, we paid approximately $54 million of the $100 million settlement fund, and our insurer paid the balance. On July 31, 2017, the district court issued final approval of the settlement.
The settlement resolves all pending cases other than Magruder v. Halliburton Co., et. al. (the Magruder case). The allegations arise out of the same general events described above, but for a later class period, December 8, 2001 to May 28, 2002. There has been limited activity in the Magruder case. In March 2009, our motion to dismiss was granted, with leave to re-plead. In March 2012, plaintiffs filed an amended complaint and in May 2012, we filed another motion to dismiss, which remains pending. We cannot predict the outcome or consequences of this case, which we intend to vigorously defend.
Environmental
We are subject to numerous environmental, legal and regulatory requirements related to our operations worldwide. In the United States, these laws and regulations include, among others:

- | the Comprehensive Environmental Response, Compensation and Liability Act;

- | the Resource Conservation and Recovery Act;

- | the Clean Air Act;

- | the Federal Water Pollution Control Act;

- | the Toxic Substances Control Act; and

- | the Oil Pollution Act.

In addition to the federal laws and regulations, states and other countries where we do business often have numerous environmental, legal and regulatory requirements by which we must abide. We evaluate and address the environmental impact of our operations by assessing and remediating contaminated properties in order to avoid future liabilities and comply with environmental, legal and regulatory requirements. Our Health, Safety and Environment group has several programs in place to maintain environmental leadership and to help prevent the occurrence of environmental contamination. On occasion we are involved in environmental litigation and claims, including the remediation of properties we own or have operated, as well as efforts to meet or correct compliance-related matters. We do not expect costs related to those claims and remediation requirements to have a material adverse effect on our liquidity, consolidated results of operations, or consolidated financial position. Our accrued liabilities for environmental matters were $48 million as of December 31, 2017 and $50 million as of December 31, 2016. Because our estimated liability is typically within a range and our accrued liability may be the amount on the low end of that range, our actual liability could eventually be well in excess of the amount accrued. Our total liability related to environmental matters covers numerous properties.
Additionally, we have subsidiaries that have been named as potentially responsible parties along with other third parties for eight federal and state Superfund sites for which we have established reserves. As of December 31, 2017, those eight sites accounted for approximately $5 million of our $48 million total environmental reserve. Despite attempts to resolve these Superfund matters, the relevant regulatory agency may at any time bring suit against us for amounts in excess of the amount accrued. With respect to some Superfund sites, we have been named a potentially responsible party by a regulatory agency; however, in each of those cases, we do not believe we have any material liability. We also could be subject to third-party claims with respect to environmental matters for which we have been named as a potentially responsible party.
Guarantee arrangements
In the normal course of business, we have agreements with financial institutions under which approximately $1.8 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of December 31, 2017. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization. None of these off balance sheet arrangements either has, or is likely to have, a material effect on our consolidated financial statements.
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Leases
We are party to numerous operating leases, primarily related to real estate, transportation and equipment. Total rentals on our operating leases, net of sublease rentals, were $574 million in 2017, $587 million in 2016 and $875 million in 2015.
Future total rentals on our noncancellable operating leases are $720 million in the aggregate, which includes the following: $166 million in 2018; $135 million in 2019; $100 million in 2020; $71 million in 2021; $54 million in 2022; and $194 million thereafter.
Note 8. Income Taxes
The components of the benefit (provision) for income taxes on continuing operations were:

| Year Ended December 31
Millions of dollars | 2017 | 2016 | 2015
Current income taxes: |  |  |
Federal | $ | 40 |  | $ | 737 |  | $ | 635 |
Foreign | (423 | ) | (415 | ) | (636 | )
State | (14 | ) | 35 |  | 51 |
Total current | (397 | ) | 357 |  | 50 |
Deferred income taxes: |  |  |
Federal | (678 | ) | 1,343 |  | (18 | )
Foreign | (31 | ) | 77 |  | 262 |
State | (25 | ) | 81 |  | (20 | )
Total deferred | (734 | ) | 1,501 |  | 224 |
Income tax benefit (provision) | $ | (1,131 | ) | $ | 1,858 |  | $ | 274 |

The United States and foreign components of income (loss) from continuing operations before income taxes were as follows:

| Year Ended December 31
Millions of dollars | 2017 | 2016 | 2015
United States | $ | 694 |  | $ | (6,636 | ) | $ | (1,560 | )
Foreign | (12 | ) | (989 | ) | 624 |
Total | $ | 682 |  | $ | (7,625 | ) | $ | (936 | )

Reconciliations between the actual provision for income taxes on continuing operations and that computed by applying the United States statutory rate to income (loss) from continuing operations before income taxes were as follows:

| Year Ended December 31
| 2017 | 2016 | 2015
United States statutory rate | 35.0 | % | 35.0 | % | 35.0 | %
Impact of U.S. tax reform | 113.0 |  | — |  | — |
Venezuela receivables adjustment | 36.6 |  | — |  | (7.5 | )
Impact of foreign income taxed at different rates | (18.3 | ) | (3.2 | ) | 17.0 |
Valuation allowance against tax assets | (6.2 | ) | (2.1 | ) | (8.3 | )
Undistributed foreign earnings | 3.8 |  | (5.1 | ) | — |
Adjustments of prior year taxes | (2.3 | ) | 0.2 |  | 1.3 |
State income taxes | 1.7 |  | 1.0 |  | 2.0 |
Domestic manufacturing deduction | — |  | (1.3 | ) | — |
Non-deductible acquisition costs | — |  | 0.6 |  | (4.5 | )
Other items, net | 2.5 |  | (0.7 | ) | (5.7 | )
Total effective tax rate on continuing operations | 165.8 | % | 24.4 | % | 29.3 | %

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Our effective tax rate on continuing operations was 165.8% for 2017, 24.4% for 2016 and 29.3% for 2015. For the year ended December 31, 2017, we had the following significant items impacting our effective tax rate:

– | we recorded an aggregate charge of $647 million on Venezuela receivables for which we are not recognizing a corresponding tax benefit. See Note 3 to the consolidated financial statements for further information;

– | we recorded $770 million of tax expenses associated with United States tax reform, as described below; and

– | we recognized income in our foreign operations in which the corresponding tax expenses are applied at lower statutory rates in certain jurisdictions.

On December 22, 2017, the President of the United States signed into law what is informally called the Tax Cuts and Jobs Act of 2017 (the “Act”), a comprehensive U.S. tax reform package that, effective January 1, 2018, among other things, lowered the corporate income tax rate from 35% to 21% and moved the country towards a territorial tax system with a one-time mandatory tax on previously deferred foreign earnings of foreign subsidiaries. Under the accounting rules, companies are required to recognize the effects of changes in tax laws and tax rates on deferred tax assets and liabilities in the period in which the new legislation is enacted. The effects of the Act on Halliburton include three major categories: (i) recognition of liabilities for taxes on mandatory deemed repatriation, (ii) remeasurement of deferred taxes and (iii) reassessment of the realizability of deferred tax assets. As described further below, we recorded a total provision to income taxes of $770 million in the year ended December 31, 2017. As we do not have all the necessary information to analyze all income tax effects of the Act, this is a provisional amount which we believe represents a reasonable estimate of the accounting implications of this tax reform. We will continue to evaluate the Act and adjust the provisional amounts as additional information is obtained. The ultimate impact of tax reform may differ from our provisional amounts due to changes in our interpretations and assumptions, as well as additional regulatory guidance that may be issued.
We expect to complete our detailed analysis no later than the fourth quarter of 2018. Below is a brief description of each of the three categories of effects from U.S. tax reform and its impact on us:

(i) | Liability for taxes due on mandatory deemed repatriation - under the Act, a company’s foreign earnings accumulated under the legacy tax laws are deemed to be repatriated into the United States. We recorded a provisional estimate of federal and state tax related to deemed repatriation in the amount of approximately $305 million. However, we had an existing United States tax liability associated with foreign earnings that were not permanently reinvested outside the United States in the amount of $435 million. It is now expected that these foreign earnings can be repatriated to the United States without any additional United States tax above the amount accrued related to the mandatory deemed repatriation. Accordingly, we released the entire $435 million liability. This $435 million release combined with the provisional amount accrued related to the mandatory deemed repatriation of $305 million resulted in us recognizing a net benefit of approximately $130 million for this item. We are currently analyzing the potential tax liabilities attributable to any additional repatriation, but we have yet to determine whether we plan to change our prior assertion and repatriate any additional earnings. Accordingly, we have not recorded any deferred taxes attributable to other investments in our foreign subsidiaries. We will record the tax effects of any change in our prior assertion in the period that we complete our analysis and are able to make a reasonable estimate, and disclose any unrecognized deferred tax liability for temporary differences related to our foreign investments, if practicable.

(ii) | Remeasurement of deferred taxes - under the Act, the U.S. corporate income tax rate was reduced from 35% to 21%. Accordingly, we remeasured our U.S. deferred tax assets as of December 31, 2017 to a 21% rate, resulting in a tax expense of $283 million.

(iii) | Reassessment of the realizability of deferred tax assets - under the Act, many of the foreign tax credit utilization rules were changed that required us to reassess the realizability of our foreign tax credit deferred tax asset. After review, it was determined that under the new U.S. foreign tax credit rules we would not ultimately realize the full benefit associated with our foreign tax credits at December 31, 2017. Accordingly, we recognized a provisional estimate of a valuation allowance related to our foreign tax credits in the amount of $575 million. In addition, we had recorded foreign tax credit benefits associated with a liability related to uncertain tax benefits recorded on foreign branches of our U.S. subsidiaries. We determined that these foreign tax credits would also ultimately become unrealizable. Accordingly, a provision of approximately $40 million was recognized.

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The primary components of our deferred tax assets and liabilities were as follows:

| December 31
Millions of dollars | 2017 | 2016
Gross deferred tax assets: |  |
Net operating loss carryforwards | $ | 1,370 |  | $ | 1,647 |
Foreign tax credit carryforwards | 828 |  | 648 |
Employee compensation and benefits | 263 |  | 352 |
Accrued liabilities | 97 |  | 325 |
Other | 416 |  | 536 |
Total gross deferred tax assets | 2,974 |  | 3,508 |
Gross deferred tax liabilities: |  |
Depreciation and amortization | 315 |  | 585 |
Undistributed foreign earnings | 242 |  | 406 |
Other | 56 |  | 145 |
Total gross deferred tax liabilities | 613 |  | 1,136 |
Valuation allowances | 1,173 |  | 453 |
Net deferred income tax asset | $ | 1,188 |  | $ | 1,919 |

At December 31, 2017, we had $1.4 billion of domestic and foreign tax-effected net operating loss carryforwards. The ultimate realization of these deferred tax assets depends on the ability to generate sufficient taxable income in the appropriate taxing jurisdiction. $161 million of the net operating loss carryforwards will expire after taxable years ended from 2018 through 2022, $160 million will expire after taxable years ended from 2023 through 2027, and $693 million will expire after taxable years ended from 2028 through 2037. The remaining balance will not expire. Additionally, we had $911 million of foreign tax credit carryforwards that will expire from 2023 through 2027, which are offset by foreign branch deferred activity reflected in the above table, along with $102 million of research and development tax credit carryforwards that will expire from 2028 through 2037.
The following table presents a rollforward of our unrecognized tax benefits and associated interest and penalties.

Millions of dollars | Unrecognized Tax Benefits |  | Interest and Penalties
Balance at January 1, 2015 | $ | 314 |  |  | $ | 56 |
Change in prior year tax positions | (33 | ) |  | 7 |
Change in current year tax positions | 62 |  |  | 1 |
Cash settlements with taxing authorities | (16 | ) |  | (15 | )
Lapse of statute of limitations | (5 | ) |  | (2 | )
Balance at December 31, 2015 | $ | 322 |  |  | $ | 47 |
Change in prior year tax positions | 44 |  |  | 20 |
Change in current year tax positions | 129 |  |  | 3 |
Cash settlements with taxing authorities | (62 | ) |  | (8 | )
Lapse of statute of limitations | (6 | ) |  | (1 | )
Balance at December 31, 2016 | $ | 427 |  | (a) | $ | 61 |
Change in prior year tax positions | (108 | ) |  | — |
Change in current year tax positions | 24 |  |  | 2 |
Cash settlements with taxing authorities | (6 | ) |  | — |
Lapse of statute of limitations | (4 | ) |  | (3 | )
Balance at December 31, 2017 | $ | 333 |  | (a)(b) | $ | 60 |

(a) | Includes $9 million as of December 31, 2017 and $84 million as of December 31, 2016 in foreign unrecognized tax benefits that would give rise to a United States tax credit. As of December 31, 2017 and December 31, 2016, approximately $319 million and $257 million, respectively, of unrecognized tax benefits would positively impact the effective tax rate and be recognized as additional tax benefits in our statement of operations if resolved in our favor.

(b) | Includes $23 million that could be resolved within the next 12 months.

We file income tax returns in the United States federal jurisdiction and in various states and foreign jurisdictions. In most cases, we are no longer subject to state, local, or non-United States income tax examination by tax authorities for years
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before 2009. Tax filings of our subsidiaries, unconsolidated affiliates and related entities are routinely examined in the normal course of business by tax authorities. Currently, our United States federal tax filings for the tax years 2012 through 2015 are under review by the Internal Revenue Service, and the appeal process is closed for the tax years 2010 through 2011.
Note 9. Shareholders’ Equity
Shares of common stock
The following table summarizes total shares of common stock outstanding:

| December 31
Millions of shares | 2017 | 2016
Issued | 1,069 |  | 1,070 |
In treasury | (196 | ) | (204 | )
Total shares of common stock outstanding | 873 |  | 866 |

Our Board of Directors has authorized a program to repurchase our common stock from time to time. The program does not require a specific number of shares to be purchased and the program may be effected through solicited or unsolicited transactions in the market or in privately negotiated transactions. The program may be terminated or suspended at any time. There were no repurchases made under the program during the years ended December 31, 2017 and 2016. Approximately $5.7 billion remains authorized for repurchases as of December 31, 2017. From the inception of this program in February 2006 through December 31, 2017, we repurchased approximately 201 million shares of our common stock for a total cost of approximately $8.4 billion.
Preferred stock
Our preferred stock consists of five million total authorized shares at December 31, 2017, of which none are issued.
Accumulated other comprehensive loss
Accumulated other comprehensive loss consisted of the following:

| December 31
Millions of dollars | 2017 | 2016
Defined benefit and other postretirement liability adjustments (a) | $ | (334 | ) | $ | (313 | )
Cumulative translation adjustment | (80 | ) | (80 | )
Other | (55 | ) | (61 | )
Total accumulated other comprehensive loss | $ | (469 | ) | $ | (454 | )

(a) Included net actuarial losses for our international pension plans of $295 million at December 31, 2017 and $290 million at December 31, 2016.
Note 10. Stock-based Compensation
The following table summarizes stock-based compensation costs for the years ended December 31, 2017, 2016 and 2015.

| Year Ended December 31
Millions of dollars | 2017 | 2016 | 2015
Stock-based compensation cost | $ | 290 |  | $ | 262 |  | $ | 294 |
Tax benefit | (64 | ) | (77 | ) | (99 | )
Stock-based compensation cost, net of tax | $ | 226 |  | $ | 185 |  | $ | 195 |

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Our Stock and Incentive Plan, as amended (Stock Plan), provides for the grant of any or all of the following types of stock-based awards:

- | stock options, including incentive stock options and nonqualified stock options;

- | restricted stock awards;

- | restricted stock unit awards;

- | stock appreciation rights; and

- | stock value equivalent awards.

There are currently no stock appreciation rights, stock value equivalent awards, or incentive stock options outstanding. Under the terms of the Stock Plan, approximately 206 million shares of common stock have been reserved for issuance to employees and non-employee directors. At December 31, 2017, approximately 19 million shares were available for future grants under the Stock Plan. The stock to be offered pursuant to the grant of an award under the Stock Plan may be authorized but unissued common shares or treasury shares.
In addition to the provisions of the Stock Plan, we also have stock-based compensation provisions under our Restricted Stock Plan for Non-Employee Directors and our Employee Stock Purchase Plan (ESPP).
Each of the active stock-based compensation arrangements is discussed below.
Stock options
The majority of our options are generally issued during the second quarter of the year. All stock options under the Stock Plan are granted at the fair market value of our common stock at the grant date. Employee stock options generally vest ratably over a three-year period and expire 10 years from the grant date. Compensation expense for stock options is generally recognized on a straight line basis over the entire vesting period.
The following table represents our stock options activity during 2017.

| Number of Shares (in millions) | Weighted Average Exercise Price per Share | Weighted Average Remaining Contractual Term (years) | Aggregate Intrinsic Value (in millions)
Outstanding at January 1, 2017 | 20.6 |  | $ | 44.01 |  |  |
Granted | 2.5 |  | 48.39 |  |  |
Exercised | (1.4 | ) | 36.60 |  |  |
Forfeited/expired | (0.7 | ) | 47.99 |  |  |
Outstanding at December 31, 2017 | 21.0 |  | $ | 44.92 |  | 6.3 | $ | 138 |
Exercisable at December 31, 2017 | 15.0 |  | $ | 45.04 |  | 5.4 | $ | 105 |

The total intrinsic value of options exercised was $21 million in 2017, $25 million in 2016 and $9 million in 2015. As of December 31, 2017, there was $48 million of unrecognized compensation cost, net of estimated forfeitures, related to nonvested stock options, which is expected to be recognized over a weighted average period of approximately two years.
Cash received from issuance of common stock was $158 million during 2017, $186 million during 2016 and $167 million during 2015, of which $53 million, $80 million and $23 million related to proceeds from exercises of stock options in 2017, 2016 and 2015, respectively. The remainder relates to cash proceeds from the issuance of shares related to our employee stock purchase plan.
The fair value of options at the date of grant was estimated using the Black-Scholes option pricing model. The expected volatility of options granted was a blended rate based upon implied volatility calculated on actively traded options on our common stock and upon the historical volatility of our common stock. The expected term of options granted was based upon historical observation of actual time elapsed between date of grant and exercise of options for all employees. The assumptions and resulting fair values of options granted were as follows:
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| Year Ended December 31
| 2017 | 2016 | 2015
Expected term (in years) | 5.24 | 5.21 | 5.16
Expected volatility | 32% | 37% | 39%
Expected dividend yield | 1.28 - 1.72% | 1.35 - 2.46% | 1.51 - 1.85%
Risk-free interest rate | 1.79 - 2.14% | 1.13 - 1.84% | 1.43 - 1.72%
Weighted average grant-date fair value per share | $13.11 | $12.33 | $13.47

Restricted stock
Restricted shares issued under the Stock Plan are restricted as to sale or disposition. These restrictions lapse periodically generally over a period of five years. Restrictions may also lapse for early retirement and other conditions in accordance with our established policies. Upon termination of employment, shares on which restrictions have not lapsed must be returned to us, resulting in restricted stock forfeitures. The fair market value of the stock on the date of grant is amortized and charged to income on a straight-line basis over the requisite service period for the entire award.
The following table represents our restricted stock awards and restricted stock units granted, vested and forfeited during 2017.

| Number of Shares (in millions) | Weighted Average Grant-Date Fair Value per Share
Nonvested shares at January 1, 2017 | 15.1 |  | $ | 44.96 |
Granted | 5.6 |  | 45.99 |
Vested | (4.5 | ) | 44.40 |
Forfeited | (1.1 | ) | 46.25 |
Nonvested shares at December 31, 2017 | 15.1 |  | $ | 45.42 |

The weighted average grant-date fair value of shares granted was $45.99 during 2017, $42.87 during 2016 and $43.24 during 2015. The total fair value of shares vested was $204 million during 2017, $223 million during 2016, and $211 million during 2015. As of December 31, 2017, there was $448 million of unrecognized compensation cost, net of estimated forfeitures, related to nonvested restricted stock, which is expected to be recognized over a weighted average period of three years.
Employee Stock Purchase Plan
Under the ESPP, eligible employees may have up to 10% of their earnings withheld, subject to some limitations, to be used to purchase shares of our common stock. The ESPP contains four three-month offering periods commencing on January 1, April 1, July 1 and October 1 of each year. The price at which common stock may be purchased under the ESPP is equal to 85% of the lower of the fair market value of the common stock on the commencement date or last trading day of each offering period. Under this plan, 74 million shares of common stock have been reserved for issuance. The stock to be offered may be authorized but unissued common shares or treasury shares. As of December 31, 2017, 46 million shares have been sold through the ESPP since the inception of the plan and 28 million shares are available for future issuance.
The fair value of ESPP shares was estimated using the Black-Scholes option pricing model. The expected volatility was a one-year historical volatility of our common stock. The assumptions and resulting fair values were as follows:

| Year Ended December 31
| 2017 | 2016 | 2015
Expected volatility | 29 | % | 36 | % | 35 | %
Expected dividend yield | 1.51 | % | 1.87 | % | 1.82 | %
Risk-free interest rate | 0.86 | % | 0.25 | % | 0.01 | %
Weighted average grant-date fair value per share | $ | 9.95 |  | $ | 8.61 |  | $ | 8.62 |

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Note 11. Income per Share
Basic income or loss per share is based on the weighted average number of common shares outstanding during the period. Diluted income per share includes additional common shares that would have been outstanding if potential common shares with a dilutive effect had been issued. Antidilutive securities represent potentially dilutive securities which are excluded from the computation of diluted income or loss per share as their impact was antidilutive.
A reconciliation of the number of shares used for the basic and diluted income per share computations is as follows:

| Year Ended December 31
Millions of shares | 2017 | 2016 | 2015
Basic weighted average common shares outstanding | 870 |  | 861 |  | 853 |
Dilutive effect of awards granted under our stock incentive plans | — |  | — |  | — |
Diluted weighted average common shares outstanding | 870 |  | 861 |  | 853 |
Antidilutive shares: |  |  |
Options with exercise price greater than the average market price | 6 |  | 11 |  | 10 |
Options which are antidilutive due to net loss position | 2 |  | 1 |  | 2 |
Total antidilutive shares | 8 |  | 12 |  | 12 |

Note 12. Financial Instruments and Risk Management
At December 31, 2017, we held $106 million of investments in fixed income securities with maturities ranging from less than one year to November 2020, of which $69 million are classified as “Other current assets” and $37 million are classified as “Other assets” on our consolidated balance sheets. At December 31, 2016, we held $92 million of investments in fixed income securities. These securities consist primarily of corporate bonds and other debt instruments, are accounted for as available-for-sale and are recorded at fair value based on quoted prices for identical assets in less active markets, which are categorized within level 2 on the fair value hierarchy.
We have an interest-bearing promissory note with our primary customer in Venezuela. At December 31, 2017, the carrying amount of this note was $32 million compared to its par value of $175 million. At December 31, 2016, the carrying amount of this note was $70 million compared to its par value of $200 million. Fair market value was measured based on pricing data points for similar assets in an illiquid market and categorized within level 3 on the fair value hierarchy. We had been using an effective interest method to accrete the carrying amount to its par value as it matures with accretion income being recorded through “Interest expense, net of interest income” on our consolidated statements of operations. During the fourth quarter of 2017, we changed our accounting for our promissory note from held-to-maturity to available-for-sale and will no longer accrete the value of the note going forward. Instead, we are required to mark the note to its fair market value on a quarterly basis with any unrealized gains and losses included as a component of accumulated other comprehensive loss. See Note 3 for additional information about our promissory note from our primary customer in Venezuela.
The carrying amount of cash and equivalents, receivables and accounts payable, as reflected in the consolidated balance sheets, approximates fair value due to the short maturities of these instruments.
The carrying amount and fair value of our total debt, including short-term borrowings and current maturities of long term debt, is as follows:

| December 31, 2017 |  | December 31, 2016
Millions of dollars | Level 1 | Level 2 | Total fair value | Carrying value |  | Level 1 | Level 2 | Total fair value | Carrying value
Total debt | $ | 3,285 |  | $ | 9,172 |  | $ | 12,457 |  | $ | 10,942 |  |  | $ | 753 |  | $ | 12,812 |  | $ | 13,565 |  | $ | 12,384 |

Our debt categorized within level 1 on the fair value hierarchy is calculated using quoted prices in active markets for identical liabilities with transactions occurring on the last two days of period-end. Our debt categorized within level 2 on the fair value hierarchy is calculated using significant observable inputs for similar liabilities where estimated values are determined from observable data points on our other bonds and on other similarly rated corporate debt or from observable data points of transactions occurring prior to two days from period-end and adjusting for changes in market conditions. Our total fair
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value and carrying value of debt decreased in 2017 compared to 2016 primarily due to the early extinguishment of $1.4 billion of senior notes. Additionally, differences between the periods presented in our level 1 and level 2 classification of our long-term debt relate to the timing of when transactions are executed. We have no debt categorized within level 3 on the fair value hierarchy based on unobservable inputs.
We are exposed to market risk from changes in foreign currency exchange rates and interest rates. We selectively manage these exposures through the use of derivative instruments, including forward foreign exchange contracts, foreign exchange options and interest rate swaps. The objective of our risk management strategy is to minimize the volatility from fluctuations in foreign currency and interest rates. We do not use derivative instruments for trading purposes. The fair value of our forward contracts, options and interest rate swaps was not material as of December 31, 2017 or December 31, 2016. The counterparties to our derivatives are primarily global commercial and investment banks.
Foreign currency exchange risk
We have operations in many international locations and are involved in transactions denominated in currencies other than the United States dollar, our functional currency, which exposes us to foreign currency exchange rate risk. Techniques in managing foreign currency exchange risk include, but are not limited to, foreign currency borrowing and investing and the use of currency exchange instruments. We attempt to selectively manage significant exposures to potential foreign currency exchange losses based on current market conditions, future operating activities and the associated cost in relation to the perceived risk of loss. The purpose of our foreign currency risk management activities is to minimize the risk that our cash flows from the purchase and sale of products and services in foreign currencies will be adversely affected by changes in exchange rates.
We use forward contracts and options to manage our exposure to fluctuations in the currencies of certain countries in which we do business internationally. These instruments are not treated as hedges for accounting purposes, generally have an expiration date of one year or less and are not exchange traded. While these instruments are subject to fluctuations in value, the fluctuations are generally offset by the value of the underlying exposures being managed. The use of some of these instruments may limit our ability to benefit from favorable fluctuations in foreign currency exchange rates.
Derivatives are not utilized to manage exposures in some currencies due primarily to the lack of available markets or cost considerations (non-traded currencies). We attempt to manage our working capital position to minimize foreign currency exposure in non-traded currencies and recognize that pricing for the services and products offered in these countries should account for the cost of exchange rate devaluations. We have historically incurred transaction losses in non-traded currencies.
The notional amounts of open foreign exchange derivatives were $633 million at December 31, 2017 and $603 million at December 31, 2016. The notional amounts of these instruments do not generally represent amounts exchanged by the parties, and thus are not a measure of our exposure or of the cash requirements related to these contracts. As such, cash flows related to these contracts are typically not material. The amounts exchanged are calculated by reference to the notional amounts and by other terms of the contracts, such as exchange rates.
Interest rate risk
We are subject to interest rate risk on our existing long-term debt and some of our long-term investments in fixed income securities. Our short-term borrowings and short-term investments in fixed income securities do not give rise to significant interest rate risk due to their short-term nature. We had fixed rate long-term debt totaling $10.4 billion at December 31, 2017 and $12.2 billion at December 31, 2016. We also had $37 million of long-term investments in fixed income securities at December 31, 2017 with maturities that extend through November 2020.
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We maintain an interest rate management strategy that is intended to mitigate the exposure to changes in interest rates in the aggregate for our debt portfolio. We use interest rate swaps to effectively convert a portion of our fixed rate debt to floating LIBOR-based rates. Our interest rate swaps, which expire when the underlying debt matures, are designated as fair value hedges of the underlying debt and are determined to be highly effective. These derivative instruments are marked to market with gains and losses recognized currently in interest expense to offset the respective gains and losses recognized on changes in the fair value of the hedged debt. During the first quarter of 2017, we terminated a series of our interest rate swaps with a notional amount of $1.4 billion in conjunction with our early redemption of senior notes. We included the gain from the swap termination in our calculation of early debt extinguishment costs. See Note 6 for further information. As of December 31, 2017, we had one remaining interest rate swap relating to one of our debt instruments with a total notional amount of $100 million. The fair value of our interest rate swaps as of December 31, 2017 and December 31, 2016 are included in “Other assets” in our consolidated balance sheets and were immaterial. The fair value of our interest rate swaps are categorized within level 2 on the fair value hierarchy and were determined using an income approach model with inputs, such as the notional amount, LIBOR rate spread and settlement terms that are observable in the market or can be derived from or corroborated by observable data.
Credit risk
Financial instruments that potentially subject us to concentrations of credit risk are primarily cash equivalents, investments in fixed income securities, trade receivables and a promissory note we hold with our primary customer in Venezuela. It is our practice to place our cash equivalents and investments in fixed income securities in high quality investments with various institutions. Our revenue is generated from selling products and providing services to the energy industry. Our trade receivables are from a broad and diverse group of customers and are generally not collateralized. As of December 31, 2017, 42% of our net trade receivables were from customers in the United States. As of December 31, 2016, 27% of our net trade receivables were from customers in the United States and 15% were from customers in Venezuela. We maintain an allowance for bad debts based upon several factors, including historical collection experience, current aging status of the customer accounts and financial condition of our customers. See Note 3 for further information.
We do not have any significant concentrations of credit risk with any individual counterparty to our derivative contracts. We select counterparties to those contracts based on our belief that each counterparty’s profitability, balance sheet and capacity for timely payment of financial commitments is unlikely to be materially adversely affected by foreseeable events.
Note 13. Retirement Plans
Our company and subsidiaries have various plans that cover a significant number of our employees. These plans include defined contribution plans, defined benefit plans and other postretirement plans:

- | our defined contribution plans provide retirement benefits in return for services rendered. These plans provide an individual account for each participant and have terms that specify how contributions to the participant’s account are to be determined rather than the amount of pension benefits the participant is to receive. Contributions to these plans are based on pretax income and/or discretionary amounts determined on an annual basis. Our expense for the defined contribution plans for continuing operations totaled $173 million in 2017, $111 million in 2016 and $288 million in 2015. The increase in 2017 resulted from an increase in the domestic workforce and the reinstatement of discretionary contributions in 2017.

- | our defined benefit plans, which include both funded and unfunded pension plans, define an amount of pension benefit to be provided, usually as a function of age, years of service and/or compensation. The unfunded obligations and net periodic benefit cost of our United States defined benefit plans were not material for the periods presented; and

- | our postretirement plans other than pensions are offered to specific eligible employees. The accumulated benefit obligations and net periodic benefit cost for these plans were not material for the periods presented.

Funded status
For our international pension plans, at December 31, 2017, the projected benefit obligation was $1.2 billion and the fair value of plan assets was $940 million, which resulted in an unfunded obligation of $280 million. At December 31, 2016, the projected benefit obligation was $1.1 billion and the fair value of plan assets was $865 million, which resulted in an unfunded obligation of $241 million. The accumulated benefit obligation was approximately the same as the projected benefit obligation for our international plans in both years presented.
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The following table presents additional information about our international pension plans.

| December 31
Millions of dollars | 2017 | 2016
Amounts recognized on the Consolidated Balance Sheets |  |
Accrued employee compensation and benefits | $ | 15 |  | $ | 16 |
Employee compensation and benefits | 267 |  | 227 |
Pension plans in which projected benefit obligation exceeded plan assets |  |
Projected benefit obligation | $ | 1,202 |  | $ | 1,083 |
Fair value of plan assets | 920 |  | 840 |
Pension plans in which accumulated benefit obligation exceeded plan assets |  |
Accumulated benefit obligation | $ | 1,139 |  | $ | 1,037 |
Fair value of plan assets | 920 |  | 840 |

Fair value measurements of plan assets
The fair value of our plan assets categorized within level 1 on the fair value hierarchy is based on quoted prices in active markets for identical assets. The fair value of our plan assets categorized within level 2 on the fair value hierarchy is based on significant observable inputs for similar assets. The fair value of our plan assets categorized within level 3 on the fair value hierarchy is based on significant unobservable inputs.
The following table sets forth the fair values of assets held by our international pension plans by level within the fair value hierarchy.

Millions of dollars | Level 1 | Level 2 | Level 3 | Total
Cash and equivalents | $ | — |  | $ | 11 |  | $ | — |  | $ | 11 |
Common/collective trust funds (a) |  |  |  |
Equity funds (b) | — |  | 204 |  | — |  | 204 |
Bond funds (c) | — |  | 323 |  | 46 |  | 369 |
Alternatives funds (d) | — |  | 184 |  | — |  | 184 |
Real estate funds (e) | — |  | 98 |  | 28 |  | 126 |
Other assets | 7 |  | 22 |  | 17 |  | 46 |
Fair value of plan assets at December 31, 2017 | $ | 7 |  | $ | 842 |  | $ | 91 |  | $ | 940 |
Cash and equivalents | $ | — |  | $ | 49 |  | $ | — |  | $ | 49 |
Common/collective trust funds (a) |  |  |  |
Equity funds (b) | — |  | 197 |  | — |  | 197 |
Bond funds (c) | — |  | 232 |  | 44 |  | 276 |
Alternatives fund (d) | — |  | 221 |  | — |  | 221 |
Real estate funds (e) | — |  | 36 |  | 35 |  | 71 |
Other assets | 5 |  | 20 |  | 26 |  | 51 |
Fair value of plan assets at December 31, 2016 | $ | 5 |  | $ | 755 |  | $ | 105 |  | $ | 865 |

(a) Common/collective trust funds are valued at the net asset value of units held by the plans at year-end.
(b) Strategy is to invest in diversified funds of global common stocks.
(c) Strategy is to invest in diversified funds of fixed income securities of varying geographies and credit quality and whose cash flows approximate the maturities of the benefit obligation.
(d) Strategy is to invest in a fund of diversifying investments, including but not limited to reinsurance, commodities and currencies.
(e) Strategy is to invest in diversified funds of real estate investment trusts and private real estate.
Our investment strategy varies by country depending on the circumstances of the underlying plan. Risk management practices include diversification by issuer, industry and geography, as well as the use of multiple asset classes and investment managers within each asset class. Our investment strategy for our United Kingdom pension plan, which constituted 84% of our international pension plans’ projected benefit obligation at December 31, 2017 and is no longer accruing service benefits, aims to achieve full funding of the benefit obligation, with the plan's assets increasingly composed of investments whose cash flows match the maturities of the obligation.
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Net periodic benefit cost
Net periodic benefit cost for our international pension plans was $30 million in 2017, $30 million in 2016 and $42 million in 2015. Included in net periodic benefit cost were $13 million in 2017 and $8 million in 2016 of net curtailment and settlement cost arising from reductions in workforce during these years.
Actuarial assumptions
Certain weighted-average actuarial assumptions used to determine benefit obligations of our international pension plans at December 31 were as follows:

| 2017 | 2016
Discount rate | 2.8% | 2.9%
Rate of compensation increase | 5.5% | 4.8%

Certain weighted-average actuarial assumptions used to determine net periodic benefit cost of our international pension plans for the years ended December 31 were as follows:

| 2017 | 2016 | 2015
Discount rate | 2.9% | 4.2% | 4.1%
Expected long-term return on plan assets | 4.2% | 5.3% | 5.9%
Rate of compensation increase | 4.8% | 5.4% | 5.3%

Assumed long-term rates of return on plan assets, discount rates for estimating benefit obligations and rates of compensation increases vary by plan according to local economic conditions. Where possible, discount rates were determined based on the prevailing market rates of a portfolio of high-quality debt instruments with maturities matching the expected timing of the payment of the benefit obligations. Expected long-term rates of return on plan assets were determined based upon an evaluation of our plan assets and historical trends and experience, taking into account current and expected market conditions.
Other information
Contributions. Funding requirements for each plan are determined based on the local laws of the country where such plan resides. In certain countries the funding requirements are mandatory, while in other countries they are discretionary. We currently expect to contribute $17 million to our international pension plans in 2018.
Benefit payments. Expected benefit payments over the next 10 years for our international pension plans are as follows: $68 million in 2018, $61 million in 2019, $63 million in 2020, $67 million in 2021, $72 million in 2022 and $424 million in years 2023 through 2027.
Note 14. New Accounting Pronouncements
Standards adopted in 2017
Stock-Based Compensation
On January 1, 2017, we adopted an accounting standards update issued by the Financial Accounting Standards Board (FASB) which simplifies several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and the classification on the statement of cash flows. In addition, the update allows an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur. The element of the update that has the most impact on our financial statements is income tax consequences. Excess tax benefits and tax deficiencies on stock-based compensation awards are now included in our tax provision within our consolidated statement of operations as discrete items in the reporting period in which they occur, rather than previous accounting of recording in additional paid-in capital on our consolidated balance sheets. We have also elected to continue our current policy of estimating forfeitures of stock-based compensation awards at the time of grant and revising in subsequent periods to reflect actual forfeitures. We applied the update prospectively beginning January 1, 2017, and the adoption did not have a material impact on our consolidated financial statements.
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Intra-Entity Transfers of Assets
On January 1, 2017, we adopted an accounting standards update issued by the FASB to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. The update requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs, rather than the previous requirement to defer recognition of current and deferred income taxes for an intra-entity asset transfer until the asset had been sold to an outside party. Two common examples of assets included in the scope of this update are intellectual property and property, plant and equipment. The update was applied on a modified retrospective basis resulting in a cumulative-effect adjustment of $384 million recorded directly to retained earnings as of January 1, 2017.
Inventory
On January 1, 2017, we adopted an accounting standards update issued by the FASB which simplifies the measurement of inventory. The update now requires inventory measured using the first in, first out or average cost methods to be subsequently measured at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable cost of completion, disposal and transportation. The update eliminated the requirement to subsequently measure inventory at the lower of cost or market, which could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. The adoption of this update did not impact our consolidated financial statements.
Standards not yet adopted
Revenue Recognition
In May 2014, the FASB issued a comprehensive new revenue recognition standard that will supersede existing revenue recognition guidance under U.S. GAAP. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The standard creates a five step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements with a cumulative-effect adjustment reflected in retained earnings. The standard also requires 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. This new revenue recognition standard will be effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.
We performed a detailed review of our contract portfolio representative of our different businesses and compared historical accounting policies and practices to the new standard. Because the standard will impact our business processes, systems and controls, we also developed a comprehensive change management project plan to guide the implementation. Over the course of 2017, we have conducted training sessions for those in our global organization that will be impacted by the new standard and have developed a web-based training course providing a detailed overview of the key changes within the new standard. Our services are primarily short-term in nature, and we do not expect the new revenue recognition standard to have a material impact on our financial statements. We adopted the new standard effective January 1, 2018 utilizing the modified retrospective method. The cumulative-effect adjustment to retained earnings upon adoption is not material.
Leases
In February 2016, the FASB issued an accounting standards update related to accounting for leases, which requires the assets and liabilities that arise from leases to be recognized on the balance sheet. Currently only capital leases are recorded on the balance sheet. This update will require the lessee to recognize a lease liability equal to the present value of the lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term for all leases longer than 12 months. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and liabilities and recognize the lease expense for such leases generally on a straight-line basis over the lease term. The new lease standard will be effective for fiscal periods beginning after December 15, 2018, including interim periods within that reporting period. We are currently evaluating the impact that this update will have on our consolidated financial statements.
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HALLIBURTON COMPANY Selected Financial Data (Unaudited)
| Year ended December 31
Millions of dollars except per share | 2017 | 2016 | 2015 | 2014 | 2013
Revenue | $ | 20,620 |  | $ | 15,887 |  | $ | 23,633 |  | $ | 32,870 |  | $ | 29,402 |
Operating income (loss) | 1,362 |  | (6,778 | ) | (165 | ) | 5,097 |  | 3,138 |
Income (loss) from continuing operations | (449 | ) | (5,767 | ) | (662 | ) | 3,437 |  | 2,116 |
Basic income (loss) per share from continuing operations | (0.51 | ) | (6.69 | ) | (0.78 | ) | 4.05 |  | 2.35 |
Diluted income (loss) per share from continuing operations | (0.51 | ) | (6.69 | ) | (0.78 | ) | 4.03 |  | 2.33 |
Cash dividends per share | 0.72 |  | 0.72 |  | 0.72 |  | 0.63 |  | 0.525 |
Net working capital | 5,915 |  | 7,654 |  | 14,733 |  | 8,781 |  | 8,678 |
Total assets | 25,085 |  | 27,000 |  | 36,942 |  | 32,165 |  | 29,223 |
Long-term debt | 10,430 |  | 12,214 |  | 14,687 |  | 7,765 |  | 7,816 |
Total shareholders’ equity | 8,349 |  | 9,448 |  | 15,495 |  | 16,298 |  | 13,615 |
Capital expenditures | 1,373 |  | 798 |  | 2,184 |  | 3,283 |  | 2,934 |

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HALLIBURTON COMPANY Quarterly Data and Market Price Information (Unaudited)
| Quarter |
Millions of dollars except per share data | First | Second | Third | Fourth | Year
2017 |  |  |  |  |
Revenue | $ | 4,279 |  | $ | 4,957 |  | $ | 5,444 |  | $ | 5,940 |  | $ | 20,620 |
Operating income | 203 |  | 146 |  | 634 |  | 379 |  | 1,362 |
Net income (loss) | (32 | ) | 28 |  | 361 |  | (825 | ) | (468 | )
Amounts attributable to company shareholders: |  |  |  |  |
Income (loss) from continuing operations | (32 | ) | 28 |  | 365 |  | (805 | ) | (444 | )
Loss from discontinued operations | — |  | — |  | — |  | (19 | ) | (19 | )
Net income (loss) attributable to company | (32 | ) | 28 |  | 365 |  | (824 | ) | (463 | )
Basic and diluted per share attributable to company shareholders: |  |  |  |  |
Income (loss) from continuing operations | (0.04 | ) | 0.03 |  | 0.42 |  | (0.92 | ) | (0.51 | )
Loss from discontinued operations | — |  | — |  | — |  | (0.02 | ) | (0.02 | )
Net income (loss) | (0.04 | ) | 0.03 |  | 0.42 |  | (0.94 | ) | (0.53 | )
Cash dividends paid per share | 0.18 |  | 0.18 |  | 0.18 |  | 0.18 |  | 0.72 |
Common stock prices (1) |  |  |  |  |
High | 58.78 |  | 51.26 |  | 46.18 |  | 49.29 |  | 58.78 |
Low | 47.52 |  | 41.36 |  | 38.18 |  | 40.72 |  | 38.18 |
2016 |  |  |  |  |
Revenue | $ | 4,198 |  | $ | 3,835 |  | $ | 3,833 |  | $ | 4,021 |  | $ | 15,887 |
Operating income (loss) | (3,079 | ) | (3,880 | ) | 128 |  | 53 |  | (6,778 | )
Net income (loss) | (2,418 | ) | (3,205 | ) | 7 |  | (153 | ) | (5,769 | )
Amounts attributable to company shareholders: |  |  |  |  |
Income (loss) from continuing operations | (2,410 | ) | (3,208 | ) | 6 |  | (149 | ) | (5,761 | )
Loss from discontinued operations | (2 | ) | — |  | — |  | — |  | (2 | )
Net income (loss) attributable to company | (2,412 | ) | (3,208 | ) | 6 |  | (149 | ) | (5,763 | )
Basic and diluted net income (loss) per share | (2.81 | ) | (3.73 | ) | 0.01 |  | (0.17 | ) | (6.69 | )
Cash dividends paid per share | 0.18 |  | 0.18 |  | 0.18 |  | 0.18 |  | 0.72 |
Common stock prices (1) |  |  |  |  |
High | 36.74 |  | 46.69 |  | 46.90 |  | 56.08 |  | 56.08 |
Low | 27.64 |  | 33.26 |  | 40.12 |  | 44.23 |  | 27.64 |
Note: Results for the fourth quarter of 2017 include charges for U.S. tax reform and Venezuela receivables. See Note 8 and Note 3 for further information. Results for 2016 include merger-related costs and termination fee and impairments and other charges.
(1) New York Stock Exchange – composite transactions high and low intraday price.

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PART III
Item 10. Directors, Executive Officers and Corporate Governance.
The information required for the directors of the Registrant is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual Meeting of Stockholders (File No. 001-03492) under the captions “Election of Directors” and “Involvement in Certain Legal Proceedings.” The information required for the executive officers of the Registrant is included under Part I on pages 5 through 6 of this annual report. The information required for a delinquent form required under Section 16(a) of the Securities Exchange Act of 1934 is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual Meeting of Stockholders (File No. 001-03492) under the caption “Section 16(a) Beneficial Ownership Reporting Compliance,” to the extent any disclosure is required. The information for our code of ethics is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual Meeting of Stockholders (File No. 001-03492) under the caption “Corporate Governance.” The information regarding our Audit Committee and the independence of its members, along with information about the audit committee financial expert(s) serving on the Audit Committee, is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual Meeting of Stockholders (File No. 001-03492) under the caption “The Board of Directors and Standing Committees of Directors.”
Item 11. Executive Compensation.
This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual Meeting of Stockholders (File No. 001-03492) under the captions “Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table,” “Grants of Plan-Based Awards in Fiscal 2017,” “Outstanding Equity Awards at Fiscal Year End 2017,” “2017 Option Exercises and Stock Vested,” “2017 Nonqualified Deferred Compensation,” “Employment Contracts and Change-in-Control Arrangements,” “Post-Termination or Change-in-Control Payments,” “Equity Compensation Plan Information” and “Directors’ Compensation.”
Item 12(a). Security Ownership of Certain Beneficial Owners.
This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual Meeting of Stockholders (File No. 001-03492) under the caption “Stock Ownership of Certain Beneficial Owners and Management.”
Item 12(b). Security Ownership of Management.
This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual Meeting of Stockholders (File No. 001-03492) under the caption “Stock Ownership of Certain Beneficial Owners and Management.”
Item 12(c). Changes in Control.
Not applicable.
Item 12(d). Securities Authorized for Issuance Under Equity Compensation Plans.
This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual Meeting of Stockholders (File No. 001-03492) under the caption “Equity Compensation Plan Information.”
Item 13. Certain Relationships and Related Transactions, and Director Independence.
This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual Meeting of Stockholders (File No. 001-03492) under the caption “Corporate Governance” to the extent any disclosure is required and under the caption “The Board of Directors and Standing Committees of Directors.”
Item 14. Principal Accounting Fees and Services.
This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual Meeting of Stockholders (File No. 001-03492) under the caption “Fees Paid to KPMG LLP.”
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PART IV
Item 15. Exhibits.

| 1. | Financial Statements:
|  | The reports of the Independent Registered Public Accounting Firm and the financial statements of Halliburton Company as required by Part II, Item 8, are included on pages 38 through 40 and pages 41 through 66 of this annual report. See index on page (i).
| 2. | Financial Statement Schedules:
|  | The schedules listed in Rule 5-04 of Regulation S-X (17 CFR 210.5-04) have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.
| 3. | Exhibits:

| Exhibit |
| Number | Exhibits
| 3.1 | Restated Certificate of Incorporation of Halliburton Company filed with the Secretary of State of Delaware on May 30, 2006 (incorporated by reference to Exhibit 3.1 to Halliburton’s Form 8-K filed June 5, 2006, File No. 001-03492).
| 3.2 | By-laws of Halliburton Company revised effective December 7, 2017 (incorporated by reference to Exhibit 3.1 to Halliburton’s Form 8-K filed December 12, 2017, File No. 001-03492).
| 4.1 | Form of debt security of 8.75% Debentures due February 12, 2021 (incorporated by reference to Exhibit 4(a) to the Form 8-K of Halliburton Company, now known as Halliburton Energy Services, Inc. (the Predecessor), dated as of February 20, 1991, File No. 001-03492).
| 4.2 | Senior Indenture dated as of January 2, 1991 between the Predecessor and The Bank of New York Trust Company, N.A. (as successor to Texas Commerce Bank National Association), as Trustee (incorporated by reference to Exhibit 4(b) to the Predecessor’s Registration Statement on Form S-3 (Registration No. 33-38394) originally filed with the Securities and Exchange Commission on December 21, 1990), as supplemented and amended by the First Supplemental Indenture dated as of December 12, 1996 among the Predecessor, Halliburton and the Trustee (incorporated by reference to Exhibit 4.1 of Halliburton’s Registration Statement on Form 8-B dated December 12, 1996, File No. 001-03492).
| 4.3 | Resolutions of the Predecessor’s Board of Directors adopted at a meeting held on February 11, 1991 and of the special pricing committee of the Board of Directors of the Predecessor adopted at a meeting held on February 11, 1991 and the special pricing committee’s consent in lieu of meeting dated February 12, 1991 (incorporated by reference to Exhibit 4(c) to the Predecessor’s Form 8-K dated as of February 20, 1991, File No. 001-03492).
| 4.4 | Second Senior Indenture dated as of December 1, 1996 between the Predecessor and The Bank of New York Trust Company, N.A. (as successor to Texas Commerce Bank National Association), as Trustee, as supplemented and amended by the First Supplemental Indenture dated as of December 5, 1996 between the Predecessor and the Trustee and the Second Supplemental Indenture dated as of December 12, 1996 among the Predecessor, Halliburton and the Trustee (incorporated by reference to Exhibit 4.2 of Halliburton’s Registration Statement on Form 8-B dated December 12, 1996, File No. 001-03492).
| 4.5 | Third Supplemental Indenture dated as of August 1, 1997 between Halliburton and The Bank of New York Trust Company, N.A. (as successor to Texas Commerce Bank National Association), as Trustee, to the Second Senior Indenture dated as of December 1, 1996 (incorporated by reference to Exhibit 4.7 to Halliburton’s Form 10-K for the year ended December 31, 1998, File No. 001-03492).

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| 4.6 | Fourth Supplemental Indenture dated as of September 29, 1998 between Halliburton and The Bank of New York Trust Company, N.A. (as successor to Texas Commerce Bank National Association), as Trustee, to the Second Senior Indenture dated as of December 1, 1996 (incorporated by reference to Exhibit 4.8 to Halliburton’s Form 10-K for the year ended December 31, 1998, File No. 001-03492).
| 4.7 | Resolutions of Halliburton’s Board of Directors adopted by unanimous consent dated December 5, 1996 (incorporated by reference to Exhibit 4(g) of Halliburton’s Form 10-K for the year ended December 31, 1996, File No. 001-03492).
| 4.8 | Form of debt security of 6.75% Notes due February 1, 2027 (incorporated by reference to Exhibit 4.1 to Halliburton’s Form 8-K dated as of February 11, 1997, File No. 001-03492).
| 4.9 | Copies of instruments that define the rights of holders of miscellaneous long-term notes of Halliburton Company and its subsidiaries have not been filed with the Commission. Halliburton Company agrees to furnish copies of these instruments upon request.
| 4.10 | Form of Indenture dated as of April 18, 1996 between Dresser and The Bank of New York Trust Company, N.A. (as successor to Texas Commerce Bank National Association), as Trustee (incorporated by reference to Exhibit 4 to Dresser’s Registration Statement on Form S-3/A filed on April 19, 1996, Registration No. 333-01303), as supplemented and amended by Form of First Supplemental Indenture dated as of August 6, 1996 between Dresser and The Bank of New York Trust Company, N.A. (as successor to Texas Commerce Bank National Association), Trustee, for 7.60% Debentures due 2096 (incorporated by reference to Exhibit 4.1 to Dresser’s Form 8-K filed on August 9, 1996, File No. 1-4003).
| 4.11 | Second Supplemental Indenture dated as of October 27, 2003 between DII Industries, LLC and The Bank of New York Trust Company, N.A. (as successor to JPMorgan Chase Bank), as Trustee, to the Indenture dated as of April 18, 1996 (incorporated by reference to Exhibit 4.15 to Halliburton’s Form 10-K for the year ended December 31, 2003, File No. 001-03492).
| 4.12 | Third Supplemental Indenture dated as of December 12, 2003 among DII Industries, LLC, Halliburton Company and The Bank of New York Trust Company, N.A. (as successor to JPMorgan Chase Bank), as Trustee, to the Indenture dated as of April 18, 1996, (incorporated by reference to Exhibit 4.16 to Halliburton’s Form 10-K for the year ended December 31, 2003, File No. 001-03492).
| 4.13 | Indenture dated as of October 17, 2003 between Halliburton Company and The Bank of New York Trust Company, N.A. (as successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.1 to Halliburton’s Form 10-Q for the quarter ended September 30, 2003, File No. 001-03492).
| 4.14 | Second Supplemental Indenture dated as of December 15, 2003 between Halliburton Company and The Bank of New York Trust Company, N.A. (as successor to JPMorgan Chase Bank), as Trustee, to the Senior Indenture dated as of October 17, 2003 (incorporated by reference to Exhibit 4.27 to Halliburton’s Form 10-K for the year ended December 31, 2003, File No. 001-03492).
| 4.15 | Form of note of 7.6% debentures due 2096 (included as Exhibit A to Exhibit 4.14 above).
| 4.16 | Fourth Supplemental Indenture, dated as of September 12, 2008, between Halliburton Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee to JPMorgan Chase Bank, to the Senior Indenture dated as of October 17, 2003 (incorporated by reference to Exhibit 4.2 to Halliburton’s Form 8-K filed September 12, 2008, File No. 001-03492).
| 4.17 | Form of Global Note for Halliburton’s 6.70% Senior Notes due 2038 (included as part of Exhibit 4.16).
| 4.18 | Fifth Supplemental Indenture, dated as of March 13, 2009, between Halliburton Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee to JPMorgan Chase Bank, to the Senior Indenture dated as of October 17, 2003 (incorporated by reference to Exhibit 4.2 to Halliburton’s Form 8-K filed March 13, 2009, File No. 001-03492).

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| 4.19 | Form of Global Note for Halliburton’s 7.45% Senior Notes due 2039 (included as part of Exhibit 4.18).
| 4.20 | Sixth Supplemental Indenture, dated as of November 14, 2011, between Halliburton Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee to JPMorgan Chase Bank, to the Senior Indenture dated as of October 17, 2003 (incorporated by reference to Exhibit 4.2 to Halliburton’s Form 8-K filed November 14, 2011, File No. 001-03492).
| 4.21 | Form of Global Note for Halliburton’s 3.25% Senior Notes due 2021 (included as part of Exhibit 4.20).
| 4.22 | Form of Global Note for Halliburton’s 4.50% Senior Notes due 2041 (included as part of Exhibit 4.20).
| 4.23 | Seventh Supplemental Indenture, dated as of August 5, 2013, between Halliburton Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee to JPMorgan Chase Bank (incorporated by reference to Exhibit 4.2 of Halliburton’s Form 8-K filed August 5, 2013, File No. 001-03492).
| 4.24 | Form of Global Note for Halliburton’s 2.00% Senior Notes due 2018 (included as part of Exhibit 4.23).
| 4.25 | Form of Global Note for Halliburton’s 3.50% Senior Notes due 2023 (included as part of Exhibit 4.23).
| 4.26 | Form of Global Note for Halliburton’s 4.75% Senior Notes due 2043 (included as part of Exhibit 4.23).
| 4.27 | Eighth Supplemental Indenture, dated as of November 13, 2015, between Halliburton Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee to JPMorgan Chase Bank (incorporated by reference to Exhibit 4.2 to Halliburton’s Form 8-K filed November 13, 2015, File No. 001-03492).
| 4.28 | Form of Global Note for Halliburton’s 3.800% Senior Notes due 2025 (included as part of Exhibit 4.27).
| 4.29 | Form of Global Note for Halliburton’s 4.850% Senior Notes due 2035 (included as part of Exhibit 4.27).
| 4.30 | Form of Global Note for Halliburton’s 5.000% Senior Notes due 2045 (included as part of Exhibit 4.27).
† | 10.1 | Halliburton Company Restricted Stock Plan for Non-Employee Directors (incorporated by reference to Appendix B of the Predecessor’s proxy statement dated March 23, 1993, File No. 001-03492).
† | 10.2 | Dresser Industries, Inc. Deferred Compensation Plan, as amended and restated effective January 1, 2000 (incorporated by reference to Exhibit 10.16 to Halliburton’s Form 10-K for the year ended December 31, 2000, File No. 001-03492).
† | 10.3 | ERISA Excess Benefit Plan for Dresser Industries, Inc., as amended and restated effective June 1, 1995 (incorporated by reference to Exhibit 10.7 to Dresser’s Form 10-K for the year ended October 31, 1995, File No. 1-4003).
| 10.4 | Form of Indemnification Agreement for Officers (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed August 3, 2007, File No. 001-03492).
| 10.5 | Form of Indemnification Agreement for Directors (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 8-K filed August 3, 2007, File No. 001-03492).

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| 10.6 | Form of Indemnification Agreement for Officers (first elected after January 1, 2013) (incorporated by reference to Exhibit 10.2 to Halliburton's Form 10-Q for the quarter ended March 31, 2013, File No. 001-03492).
| 10.7 | Form of Indemnification Agreement for Directors (first elected after January 1, 2013) (incorporated by reference to Exhibit 10.1 of Halliburton’s Form 8-K filed March 22, 2013, File No. 001-03492).
† | 10.8 | 2008 Halliburton Elective Deferral Plan, as amended and restated effective January 1, 2008 (incorporated by reference to Exhibit 10.3 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No. 001-03492).
† | 10.9 | Halliburton Company Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2008 (incorporated by reference to Exhibit 10.4 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No. 001-03492).
† | 10.10 | Halliburton Company Benefit Restoration Plan, as amended and restated effective January 1, 2008 (incorporated by reference to Exhibit 10.5 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No. 001-03492).
† | 10.11 | Halliburton Company Pension Equalizer Plan, as amended and restated effective March 1, 2007 (incorporated by reference to Exhibit 10.8 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No. 001-03492).
† | 10.12 | Halliburton Company Directors' Deferred Compensation Plan, as amended and restated effective as of May 16, 2012 (incorporated by reference to Exhibit 10.5 to Halliburton's Form 10-Q for the quarter ended June 30, 2012, File No. 001-03492).
† | 10.13 | Retirement Plan for the Directors of Halliburton Company, as amended and restated effective July 1, 2007 (incorporated by reference to Exhibit 10.10 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No. 001-03492).
† | 10.14 | Halliburton Company Employee Stock Purchase Plan, as amended and restated effective February 24, 2015 (incorporated by reference to Appendix C of Halliburton’s proxy statement filed April 7, 2015, File No. 001-03492).
† | 10.15 | First Amendment to Halliburton Company Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2008 (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed September 21, 2009, File No. 001-03492).
† | 10.16 | Amendment No. 1 to Halliburton Company Benefit Restoration Plan, as amended and restated effective January 1, 2008 (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 8-K filed September 21, 2009, File No. 001-03492).
† | 10.17 | Amendment No. 1 to 2008 Halliburton Elective Deferral Plan, as amended and restated effective January 1, 2008 (incorporated by reference to Exhibit 10.41 to Halliburton’s Form 10-K for the year ended December 31, 2010, File No. 001-03492).
| 10.18 | U.S. $3,000,000,000 Five Year Revolving Credit Agreement among Halliburton Company, as Borrower, the Banks party thereto, and Citibank, N.A., as Agent, effective July 21, 2015 (incorporated by reference to Exhibit 10.1 to Halliburton's Form 10-Q for the quarter ended June 30, 2015, File No. 001-03492).
† | 10.19 | First Amendment to the Retirement Plan for the Directors of Halliburton Company, effective September 1, 2007 (incorporated by reference to Exhibit 10.3 to Halliburton’s Form 10-Q for the quarter ended March 31, 2011, File No. 001-03492).

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† | 10.20 | First Amendment to Halliburton Company Restricted Stock Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.41 to Halliburton’s Form 10-K for the year ended December 31, 2011, File No. 001-03492).
† | 10.21 | Second Amendment to Restricted Stock Plan for Non-Employee Directors of Halliburton Company (incorporated by reference to Exhibit 10.4 to Halliburton's Form 10-Q for the quarter ended June 30, 2012, File No. 001-03492).
† | 10.22 | Third Amendment to Restricted Stock Plan for Non-Employee Directors of Halliburton Company effective December 1, 2012 (incorporated by reference to Exhibit 10.44 to Halliburton’s Form 10-K for the year ended December 31, 2012, File No. 001-03492).
† | 10.23 | First Amendment dated December 1, 2012 to Halliburton Company Directors' Deferred Compensation Plan, as amended and restated effective May 16, 2012 (incorporated by reference to Exhibit 10.45 to Halliburton’s Form 10-K for the year ended December 31, 2012, File No. 001-03492).
† | 10.24 | Executive Agreement (Myrtle L. Jones) (incorporated by reference to Exhibit 10.1 to Halliburton's Form 10-Q for the quarter ended March 31, 2013, File No. 001-03492).
† | 10.25 | Executive Agreement (Timothy McKeon) (incorporated by reference to Exhibit 10.49 to Halliburton’s Form 10-K filed February 7, 2014, File No. 001-03492).
† | 10.26 | Executive Agreement (Charles E. Geer, Jr.) (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 8-K filed December 9, 2014, File No. 001-03492).
| 10.27 | HESI Punitive Damages and Assigned Claims Settlement Agreement dated September 2, 2014, entered into between Halliburton Company and Halliburton Energy Services, Inc. and counsel for The Plaintiffs Steering Committee in MDL 2179 and the Deepwater Horizon Economic and Property Damages Settlement Class (incorporated by reference to Exhibit 10.1 to Halliburton's Form 10-Q for the quarter ended September 30, 2014, File No. 001-03492).
† | 10.28 | Form of Non-Employee Director Restricted Stock Agreement (Directors Plan) (incorporated by reference as Exhibit 99.5 of Halliburton's Form S-8 filed May 21, 2009, Registration No. 333-159394).
† | 10.29 | Form of Non-Employee Director Restricted Stock Agreement (Stock and Incentive Plan) (incorporated by reference to Exhibit 10.43 to Halliburton's Form 10-K for the year ended December 31, 2011, Registration No. 001-03492).
| 10.30 | Termination Agreement, dated as of April 30, 2016, between the Company and Baker Hughes (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed May 4, 2016, File No. 001-03492).
† | 10.31 | Amendment No. 2 to Halliburton Company Benefit Restoration Plan, as amended and restated effective January 1, 2008 (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 10-Q for the quarter ended September 30, 2016, File No. 001-03492).
† | 10.32 | Second Amendment to Halliburton Company Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2008 (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 10-Q for the quarter ended September 30, 2016, File No. 001-03492).
† | 10.33 | Executive Agreement (Joe D. Rainey) (incorporated by reference to Exhibit 10.1 to Halliburton's Form 8-K filed December 12, 2017, File No. 001-03492).
† | 10.34 | Executive Agreement (Anne Lyn Beaty) (incorporated by reference to Exhibit 10.1 to Halliburton's Form 10-Q filed April 28, 2017, File No. 001-03492).

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† | 10.35 | Executive Agreement (David J. Lesar) (incorporated by reference to Exhibit 10.1 to Halliburton's Form 8-K filed May 23, 2017, File No. 001-03492).
† | 10.36 | Executive Agreement (James S. Brown) (incorporated by reference to Exhibit 10.2 to Halliburton's Form 8-K filed May 23, 2017, File No. 001-03492).
† | 10.37 | Executive Agreement (Jeffrey A. Miller) (incorporated by reference to Exhibit 10.1 to Halliburton's Form 8-K filed June 5, 2017, File No. 001-03492).
† | 10.38 | Halliburton Company Stock and Incentive Plan, as amended and restated effective February 8, 2017 (incorporated by reference to Appendix B of Halliburton's proxy statement filed April 7, 2017, File No. 001-03492).
† | 10.39 | Form of Nonstatutory Stock Option Agreement (U.S.) (incorporated by reference as Exhibit 99.2 of Halliburton's Form S-8 filed June 7, 2017, Registration No. 333-218568).
† | 10.40 | Form of Nonstatutory Stock Option Agreement (International) (incorporated by reference as Exhibit 99.3 of Halliburton's Form S-8 filed June 7, 2017, Registration No. 333-218568).
† | 10.41 | Form of Restricted Stock Agreement (incorporated by reference as Exhibit 99.4 of Halliburton's Form S-8 filed June 7, 2017, Registration No. 333-218568).
† | 10.42 | Form of Restricted Stock Unit Agreement (International) (incorporated by reference as Exhibit 99.5 of Halliburton's Form S-8 filed June 7, 2017, Registration No. 333-218568).
† | 10.43 | Form of Restricted Stock Unit Agreement (U.S. Expat) (incorporated by reference as Exhibit 99.6 of Halliburton's Form S-8 filed June 7, 2017, Registration No. 333-218568).
† | 10.44 | Executive Agreement (Christopher T. Weber) (incorporated by reference to Exhibit 10.1 to Halliburton's Form 8-K filed June 13, 2017, File No. 001-03492).
† | 10.45 | Form of Non-Management Director Restricted Stock Unit Agreement (Stock and Incentive Plan) (incorporated by reference as Exhibit 10.1 of Halliburton's Form 10-Q filed October 27, 2017, File No. 001-03492).
*† | 10.46 | Executive Agreement (Eric J. Carre).
*† | 10.47 | Executive Agreement (Lawrence J. Pope).
*† | 10.48 | Executive Agreement (Robb L. Voyles).
* | 12.1 | Statement of Computation of Ratio of Earnings to Fixed Charges.
* | 21.1 | Subsidiaries of the Registrant.
* | 23.1 | Consent of KPMG LLP.
* | 24.1 | Powers of attorney for the following directors signed in January 2018:
|  | Abdulaziz F. Al Khayyal
|  | William E. Albrecht

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|  | Alan M. Bennett
|  | James R. Boyd
|  | Milton Carroll
|  | Nance K. Dicciani
|  | Murry S. Gerber
|  | José C. Grubisich
|  | David J. Lesar
|  | Robert A. Malone
|  | J. Landis Martin
|  | Debra L. Reed
* | 31.1 | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
* | 31.2 | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
** | 32.1 | Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
** | 32.2 | Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
* | 95 | Mine Safety Disclosures.
* | 101.INS | XBRL Instance Document
* | 101.SCH | XBRL Taxonomy Extension Schema Document
* | 101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document
* | 101.LAB | XBRL Taxonomy Extension Label Linkbase Document
* | 101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document
* | 101.DEF | XBRL Taxonomy Extension Definition Linkbase Document
| * Filed with this Form 10-K.
| ** Furnished with this Form 10-K.
| † Management contracts or compensatory plans or arrangements.

Item 16. Form 10-K Summary.
None.
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SIGNATURES
As required by Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has authorized this report to be signed on its behalf by the undersigned authorized individuals on this 9th day of February, 2018.

| HALLIBURTON COMPANY
By | /s/ Jeffrey A. Miller
| Jeffrey A. Miller
| President and Chief Executive Officer

As required by the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities indicated on this 9th day of February, 2018.

Signature | Title
/s/ Jeffrey A. Miller | President, Director and
Jeffrey A. Miller | Chief Executive Officer
/s/ Christopher T. Weber | Executive Vice President and
Christopher T. Weber | Chief Financial Officer
/s/ Charles E. Geer, Jr. | Vice President and
Charles E. Geer, Jr. | Corporate Controller

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Signature | Title
* Abdulaziz F. Al Khayyal | Director
Abdulaziz F. Al Khayyal |
* William E. Albrecht | Director
William E. Albrecht |
* Alan M. Bennett | Director
Alan M. Bennett |
* James R. Boyd | Director
James R. Boyd |
* Milton Carroll | Director
Milton Carroll |
* Nance K. Dicciani | Director
Nance K. Dicciani |
* Murry S. Gerber | Director
Murry S. Gerber |
* José C. Grubisich | Director
José C. Grubisich |
* David J. Lesar | Executive Chairman of the Board and Director
David J. Lesar |
* Robert A. Malone | Director
Robert A. Malone |
* J. Landis Martin | Director
J. Landis Martin |
* Debra L. Reed | Director
Debra L. Reed |
/s/ Robb L. Voyles |
*By Robb L. Voyles, Attorney-in-fact |

78