10-K 1 hal_12312014-10k.htm DECEMBER 31, 2014 FORM 10-K HAL_12.31.2014-10K



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, 2014
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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer    [X]    Accelerated filer    [   ]
Non-accelerated filer    [   ]    Smaller reporting company    [   ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [   ] No [X]
The aggregate market value of Halliburton Company Common Stock held by nonaffiliates on June 30, 2014, determined using the per share closing price on the New York Stock Exchange Composite tape of $71.01 on that date, was approximately $60,180,000,000.
As of February 17, 2015, there were 849,671,830 shares of Halliburton Company Common Stock, $2.50 par value per share, outstanding.
Portions of the Halliburton Company Proxy Statement for our 2015 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, 2014
 
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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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. We are a leading provider of services and products to the upstream oil and natural gas industry 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 field. 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:
-
our Completion and Production segment delivers cementing, stimulation, intervention, pressure control, specialty chemicals, artificial lift, and completion products and services. The segment consists of Production Enhancement, Cementing, Completion Tools, Boots & Coots, Multi-Chem, and Artificial Lift.
-
our Drilling and Evaluation segment 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 Baroid, Sperry Drilling, Wireline and Perforating, Drill Bits and Services, Landmark Software and Services, Testing and Subsea, and Consulting and Project Management.
See Note 3 to the consolidated financial statements for further financial information related to each of our business segments and a description of the services and products provided by each segment. We have significant manufacturing operations in various locations, including the United States, Canada, China, Malaysia, Singapore, and the United Kingdom.
Pending Acquisition of Baker Hughes
On November 16, 2014, we and Baker Hughes Incorporated ("Baker Hughes") entered into a merger agreement under which, subject to the conditions set forth in the merger agreement, we will acquire all the outstanding shares of Baker Hughes in a stock and cash transaction. Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry. The acquisition is expected to close in the second half of 2015. See Note 2 to the consolidated financial statements for further information about the pending acquisition.
Business strategy
Our business strategy is to secure a distinct and sustainable competitive position as an oilfield service company by delivering services and products that enable our customers to extract proven reserves and maximize recovery. 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.
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 (including the ability to deliver services and products on an “as needed, where needed” basis);
-
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 80 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 2014, 2013, and 2012, based on the location of services provided and products sold, 51%, 49%, and 53% 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 – Business Environment and Results of Operations” and Note 3 to the consolidated financial statements for additional financial information about our geographic operations in the last three years. 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

1



serve are highly competitive, and we have many substantial competitors. Most of our services and products are marketed through our servicing and sales organizations.
Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil unrest, expropriation or other governmental actions, 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 significantly impact the conduct of our operations taken as a whole.
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 14 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.
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, hydrochloric acid, and gels, including guar gum (a blending additive used in our hydraulic fracturing process). 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 $601 million in 2014, $588 million in 2013, and $460 million in 2012. We sponsored over 95% of these expenditures in each year.
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 months normally results in reduced activity levels in the North Sea and Russia.
Additionally, customer spending patterns for software and various other oilfield services and products can result in higher activity in the fourth quarter of the year.
Employees
At December 31, 2014, we employed more than 80,000 people worldwide compared to approximately 77,000 at December 31, 2013. At December 31, 2014, approximately 16% 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 9 to the consolidated financial statements and Item 1(a), “Risk Factors.”
Hydraulic fracturing process
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.

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We sometimes design and generally implement a hydraulic fracturing operation to 'stimulate' the well's production, at the direction of our customer, 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 supply the proppant (often 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 of any materials that are subsequently produced or pumped out of the well, including flowback fluids and produced water.
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. At the request of Congress, the EPA is currently undertaking another study of the relationship between hydraulic fracturing and drinking water resources that will focus on the fracturing of shale natural gas wells.
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.
At the same time, we have invested considerable resources in developing our CleanSuite™ hydraulic fracturing technologies, which offer our customers a variety of especially 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.
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 operations, 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.
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 at 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 that contains our reports, proxy and information statements, and our other SEC filings. The address of that web site is www.sec.gov. 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 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 2014, 2013, or 2012. 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.

3




Executive Officers of the Registrant

The following table indicates the names and ages of the executive officers of Halliburton Company as of February 24, 2015, including all offices and positions held by each in the past five years:
 
Name and Age
Offices Held and Term of Office
 
James S. Brown
(Age 60)
President, Western Hemisphere of Halliburton Company, since January 2008
 
 
 
*
Christian A. Garcia
(Age 51)
Senior Vice President, Finance and Acting Chief Financial Officer of Halliburton Company, since January 2015
 
 
Senior Vice President and Chief Accounting Officer of Halliburton Company, January 2014 to December 2014
 
 
Senior Vice President and Treasurer of Halliburton Company, September 2011 to December 2013
 
 
Senior Vice President, Investor Relations of Halliburton Company, January 2011 to August 2011
 
 
Vice President, Investor Relations of Halliburton Company, December 2007 to December 2010
 
 
 
 
Charles E. Geer, Jr.
(Age 44)
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
 
 
Vice President and Principal Accounting Officer of Weatherford International, June 2010 to March 2011
 
 
Corporate Controller of Weatherford International, September 2007 to May 2010
 
 
 
 
Myrtle L. Jones
(Age 55)
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 61)
Chairman of the Board and Chief Executive Officer of Halliburton Company, since August 2014
 
 
Chairman of the Board, President, and Chief Executive Officer of Halliburton Company, August 2000 to July 2014
 
 
 
 
Mark A. McCollum
(Age 55)
Executive Vice President and Chief Integration Officer of Halliburton Company, since January 2015
 
 
Executive Vice President and Chief Financial Officer of Halliburton Company, January 2008 to December 2014
 
 
 
 
Timothy M. McKeon
(Age 42)
Vice President and Treasurer of Halliburton Company, since January 2014
 
 
Assistant Treasurer of Halliburton Company, September 2011 to December 2013
 
 
Director of Finance, Drilling & Evaluation Division of Halliburton Company, February 2011 to August 2011
 
 
Director of Treasury Operations of Halliburton Company, March 2009 to January 2011
 
 
 
*
Jeffrey A. Miller
(Age 51)
President 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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Senior Vice President, Global Business Development and Marketing of Halliburton Company, January 2011 to August 2012
 
 
Senior Vice President, Gulf of Mexico Region of Halliburton Company, January 2010 to December 2010
 
 
 
*
Lawrence J. Pope
(Age 46)
Executive Vice President of Administration and Chief Human Resources Officer of Halliburton Company, since January 2008
 
 
 
 
Joe D. Rainey
(Age 58)
President, Eastern Hemisphere of Halliburton Company, since January 2011
 
 
Senior Vice President, Eastern Hemisphere of Halliburton Company, January 2010 to December 2010
 
 
 
*
Robb L. Voyles (Age 57)
Executive Vice President and General Counsel of Halliburton Company, since January 2014
 
 
Senior Vice President, Law of Halliburton Company, September 2013 to December 2013
 
 
Partner, Baker Botts L.L.P., January 1989 to August 2013
* Members of the Policy Committee of the registrant.

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.

Our ability to complete the Baker Hughes acquisition is subject to various closing conditions, including the approval of Baker Hughes and our stockholders and the receipt of consents and approvals from governmental authorities, which may impose conditions that could adversely affect us or cause the acquisition to be abandoned.
To complete the acquisition, our stockholders must approve the issuance of shares of our common stock as contemplated by the merger agreement, and Baker Hughes stockholders must adopt the merger agreement. In addition, we and Baker Hughes must also make certain filings with and obtain certain consents and approvals from various governmental and regulatory authorities.
We have not yet obtained the regulatory consents and approvals required to complete the acquisition. Governmental or regulatory agencies could seek to block or challenge the acquisition. Even if these regulatory consents and approvals are obtained, the governmental authorities from which these approvals are required may impose conditions on the completion of the acquisition, including requiring significant divestitures, that could have an adverse effect on the combined company following the acquisition. We will be unable to complete the acquisition until the waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act, as amended, and the rules promulgated thereunder by the Federal Trade Commission have expired or been terminated and consents and approvals are received from the European Commission and various other governmental authorities (jointly, the “Regulatory Clearances”). Additionally, even after the statutory waiting period under the antitrust laws and even after completion of the acquisition, governmental authorities could seek to block or challenge the acquisition as they deem necessary or desirable in the public interest. In addition, in some jurisdictions, a competitor, customer or other third party could initiate a private action under the antitrust laws challenging or seeking to enjoin the acquisition, before or after it is completed. Baker Hughes or Halliburton may not prevail and may incur significant costs in defending or settling any action under the antitrust laws. The merger agreement may require us to accept conditions from these regulators that could adversely impact the combined company. If we agree to undertake divestitures or comply with operating restrictions in order to obtain any approvals required to complete the acquisition, we may be less able to realize anticipated benefits of the acquisition, and the business and results of operations of the combined company after the acquisition may be adversely affected. If the Regulatory Clearances are not received, or they are not received on terms that satisfy the conditions set forth in the merger agreement, then neither we nor Baker Hughes will be obligated to complete the acquisition.
If we and Baker Hughes are unable to complete the acquisition, we would be subject to a number of risks, including the following:
-
we would not realize the anticipated benefits of the acquisition, including, among other things, increased operating efficiencies;
-
the attention of our management may have been diverted to the acquisition rather than to our own operations and the pursuit of other opportunities that could have been beneficial to us;
-
the potential loss of key personnel during the pendency of the acquisition as employees may experience uncertainty about their future roles with the combined company;
-
we will have been subject to certain restrictions on the conduct of our business, which may prevent us from making certain acquisitions or dispositions or pursuing certain business opportunities while the acquisition is pending; and
-
the trading price of our common stock may decline to the extent that the current market prices reflect a market assumption that the acquisition will be completed.
If the acquisition is not completed, our ongoing businesses may be adversely affected. Under the merger agreement, we could be required, under certain circumstances, to pay Baker Hughes a termination fee of $1.5 billion or, in certain circumstances where the termination of the merger agreement is related to failures to obtain the Regulatory Clearances, $3.5 billion. If such a termination fee is payable, the payment of this fee could have material and adverse consequences to the financial condition and operations of Halliburton.
We can provide no assurance that the various closing conditions will be satisfied and that the necessary Regulatory Clearances and other approvals will be obtained, or that any required conditions will not materially adversely affect the combined company following the acquisition. In addition, we can provide no assurance that these conditions will not result in the abandonment or delay of the acquisition. The occurrence of any of these events individually or in combination could have a material adverse effect on our results of operations and the trading price of our common stock.

Pending litigation against us and Baker Hughes could result in an injunction preventing the consummation of the acquisition or may adversely affect our business, financial condition or results of operations following the acquisition.
Following the announcement of the acquisition, various lawsuits have been filed in the Court of Chancery of the State of Delaware and the U.S. District Court for the Southern District of Texas against Baker Hughes, the members of the Baker Hughes Board, and us, alleging breaches of various fiduciary duties by the members of the Baker Hughes Board during the acquisition negotiations and by entering into the merger agreement and approving the acquisition and alleging that we and Baker

6



Hughes aided and abetted such alleged breaches of fiduciary duties. Among other remedies, the plaintiffs seek to enjoin the acquisition and rescind the merger agreement, in addition to certain unspecified damages and reimbursement of costs. While we and Baker Hughes believe these suits are without merit and intend to vigorously defend against such claims, the outcome of any such litigation is inherently uncertain. The defense or settlement of any lawsuit or claim that remains unresolved at the time the acquisition closes may adversely affect the combined company’s business, financial condition or results of operation.

Our stockholders will have a reduced ownership and voting interest after the Baker Hughes acquisition and will exercise less influence over management of the combined company.
Our stockholders currently have the right to vote for our board of directors and on other matters affecting the company. When the acquisition occurs, each Baker Hughes stockholder that receives shares of our common stock will become a stockholder of ours and correspondingly, each of our stockholders will remain a stockholder of Halliburton Company with a percentage ownership of the combined company that is significantly smaller than the stockholder’s percentage ownership prior to the acquisition. Upon completion of the acquisition, former Baker Hughes stockholders are expected to hold approximately 37% of our common stock. As a result of these reduced ownership percentages, our stockholders will have less influence on the management and policies of the combined company than they now have with respect to Halliburton Company.

We will incur significant transaction, acquisition-related and restructuring costs in connection with the Baker Hughes acquisition and the combined company could incur substantial expenses related to the integration of Baker Hughes.
We expect to incur costs associated with combining our operations and the operations of Baker Hughes, as well as transaction fees and other costs related to the acquisition. Many of these costs will be borne by us even if the acquisition is not completed. We will incur through completion of the acquisition, and the combined company will incur following the completion of the acquisition, substantial expenses in connection with integrating each company’s respective businesses, policies, procedures, operations, technologies and systems. There are a large number of systems that must be integrated, including information management, purchasing, accounting and finance, sales, billing, payroll and benefits, fixed asset and lease administration systems and regulatory compliance. Many of the expenses that will be incurred, by their nature, are difficult to estimate accurately at the present time. These expenses could, particularly in the near term, reduce the savings that we expect to achieve from the elimination of duplicative expenses and the realization of economies of scale and cost savings related to the integration of the businesses following the completion of the acquisition, and accordingly, any net benefits may not be achieved in the near term or at all. These integration expenses may result in significant charges taken against earnings by us prior to completion of the acquisition and by the combined company following the completion of the acquisition.

The market value of our common stock could decline if large amounts of our common stock are sold following the Baker Hughes acquisition.
Following the acquisition, our stockholders and former stockholders of Baker Hughes will own interests in a combined company operating an expanded business with more assets and a different mix of liabilities. Our current stockholders and the current stockholders of Baker Hughes may not wish to continue to invest in the combined company, or may wish to reduce their investment in the combined company, in order to comply with institutional investing guidelines, to increase diversification or to track any rebalancing of stock indices in which our or Baker Hughes common stock is or was included. If, following the acquisition, large amounts of our common stock are sold, the price of our common stock could decline.

The Baker Hughes acquisition may not be accretive, and may be dilutive, to our earnings per share in the near term, which may negatively affect the market price of our common stock.
We anticipate that the acquisition may not be accretive, and may be dilutive, to earnings per share until the end of the second calendar year after closing. This expectation is based on preliminary estimates that may materially change. In addition, future events and conditions could decrease or delay any accretion, result in dilution or cause greater dilution than is currently expected, including:
-
adverse changes in energy market conditions;
-
commodity prices for oil, natural gas and natural gas liquids;
-
production levels;
-
operating results;
-
competitive conditions;
-
laws and regulations affecting the energy business;
-
capital expenditure obligations;
-
higher than expected integration costs;
-
lower than expected synergies; and
-
general economic conditions.
Any dilution of, or decrease or delay of any accretion to, our earnings per share could cause the price of our common stock to decline.

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The combined Halliburton and Baker Hughes company will record goodwill that could become impaired and adversely affect the combined company’s operating results.
The acquisition will be accounted for as an acquisition by us in accordance with accounting principles generally accepted in the United States. Under the acquisition method of accounting, the assets and liabilities of Baker Hughes will be recorded, as of the acquisition closing date, at their respective fair values and added to those of Halliburton. Our reported financial condition and results of operations issued after completion of the acquisition will reflect Baker Hughes balances and results after completion of the acquisition, but will not be restated retroactively to reflect the historical financial position or results of operations of Baker Hughes for periods prior to the acquisition. Under the acquisition method of accounting, the total purchase price will be allocated to Baker Hughes’s tangible assets and liabilities and identifiable intangible assets based on their fair values as of the acquisition closing date. The excess of the purchase price over those fair values will be recorded as goodwill. We and Baker Hughes expect that the acquisition will result in the creation of goodwill based upon the application of the acquisition method of accounting. To the extent the value of goodwill or intangibles becomes impaired, the combined company may be required to incur material charges relating to such impairment. Such a potential impairment charge could have a material adverse impact on the combined company’s operating results.

The pendency of the Baker Hughes acquisition could adversely affect us.
In connection with the pending acquisition, some of our suppliers and customers may delay or defer sales and purchasing decisions, which could negatively impact revenues, earnings and cash flows regardless of whether the acquisition is completed. We have agreed in the merger agreement to refrain from taking certain actions with respect to our business and financial affairs during the pendency of the acquisition, which restrictions could be in place for an extended period of time if completion of the acquisition is delayed and could adversely impact our financial condition, results of operations or cash flows.

The combined Halliburton and Baker Hughes enterprise’s indebtedness following the acquisition will be greater than Halliburton’s existing indebtedness. Therefore, it may be more difficult for the combined enterprise to pay or refinance its debts or take other actions, and the combined enterprise may need to divert its cash flow from operations to debt service payments.
In connection with the acquisition, we will incur additional debt to pay the merger consideration and transaction expenses and the indebtedness of the combined enterprise will increase as a result of Baker Hughes’s outstanding debt. Halliburton’s total liabilities as of December 31, 2014 were approximately $15.9 billion, including $7.8 billion of long-term debt. Baker Hughes’s total liabilities as of December 31, 2014 were approximately $10.1 billion, including $3.9 billion of long-term debt. We currently expect to incur additional debt in connection with financing the cash portion of the merger consideration. See Note 7 to the consolidated financial statements for further information about debt financing for the pending acquisition. The combined enterprise’s debt service obligations with respect to this increased indebtedness could have an adverse impact on its earnings and cash flows, which after the acquisition would include the earnings and cash flows of Baker Hughes, for as long as the indebtedness is outstanding.
The combined enterprise’s increased indebtedness could also have important consequences to holders of our common stock. For example, it could:
-
make it more difficult for the combined enterprise to pay or refinance its debts as they become due during adverse economic and industry conditions because any decrease in revenues could cause the combined enterprise to not have sufficient cash flows from operations to make its scheduled debt payments;
-
limit the combined enterprise’s flexibility to pursue other strategic opportunities or react to changes in its business and the industry in which it operates and, consequently, place the combined enterprise at a competitive disadvantage to its competitors with less debt;
-
require a substantial portion of the combined enterprise’s cash flows from operations to be used for debt service payments, thereby reducing the availability of its cash flow to fund working capital, capital expenditures, acquisitions, dividend payments and other general corporate purposes;
-
result in a downgrade in the rating of our indebtedness, which could limit our ability to borrow additional funds and increase the interest rates applicable to our indebtedness (after the announcement of the acquisition, Standard & Poor’s Ratings Services placed all of our ratings on negative watch, and all of Baker Hughes’s ratings on negative watch);
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result in higher interest expense in the event of increases in interest rates since some of our borrowings are, and will continue to be, at variable rates of interest; or
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require the combined enterprise to repatriate foreign earnings to meet liquidity demands, resulting in a tax payment that may not be accrued for.
Based upon current levels of operations, we expect the combined enterprise to be able to generate sufficient cash on a consolidated basis to make all of the principal and interest payments when such payments are due under our existing credit facilities, indentures and other instruments governing our outstanding indebtedness, and the indebtedness of Baker Hughes that

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may remain outstanding after the acquisition, but there can be no assurance that the combined enterprise will be able to repay or refinance such borrowings and obligations.

Following the Baker Hughes acquisition, the combined company may encounter difficulties in integrating Halliburton's and Baker Hughes's businesses and realizing the anticipated benefits of the acquisition.
The acquisition involves the combination of two companies which currently operate as independent public companies. The combined company will be required to devote management attention and resources to integrating its business practices and operations, and prior to the acquisition, management attention and resources will be required to plan for such integration. Potential difficulties the combined company may encounter in the integration process include the following:
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the inability to successfully integrate the respective businesses of the two companies in a manner that permits the combined company to achieve the cost savings and operating synergies anticipated to result from the acquisition, which could result in the anticipated benefits of the acquisition not being realized partly or wholly in the time frame currently anticipated or at all;
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lost sales and customers as a result of certain customers of either or both of the two companies deciding not to do business with the combined company, or deciding to decrease their amount of business in order to reduce their reliance on a single company;
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integrating personnel from the two companies while maintaining focus on providing consistent, high quality products and services;
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potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated with the acquisition; and
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performance shortfalls at one or both of the two companies as a result of the diversion of management’s attention caused by completing the acquisition and integrating the companies’ operations.

Liabilities arising out of the Macondo well incident could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.
The semisubmersible drilling rig, Deepwater Horizon, sank on April 22, 2010 after an explosion and fire onboard the rig that began on April 20, 2010. The Deepwater Horizon was owned by Transocean Ltd. and had been drilling the Macondo exploration well in Mississippi Canyon Block 252 in the Gulf of Mexico for the lease operator, BP Exploration and Production, Inc. (BP Exploration), an indirect wholly owned subsidiary of BP p.l.c. (BP p.l.c., BP Exploration, and their affiliates, collectively, BP). There were eleven fatalities and a number of injuries as a result of the Macondo well incident. Crude oil escaping from the Macondo well site spread across thousands of square miles of the Gulf of Mexico and reached the United States Gulf Coast. We performed a variety of services for BP Exploration, including cementing, mud logging, directional drilling, measurement-while-drilling, and rig data acquisition services.
Numerous lawsuits relating to the Macondo well incident were filed against us, BP, Transocean and others in federal and state courts throughout the United States, most of which have been consolidated in a Multi-District Litigation (MDL) proceeding, and additional lawsuits may be filed against us. In addition, the Bureau of Safety and Environmental Enforcement has issued a notification of Incidents of Noncompliance (INCs) to us relating to the Macondo well incident. We understand that regulations in effect at the time of the alleged violations provide for fines of up to $35,000 per day per violation.
Our contract with BP relating to the Macondo well generally provides for our indemnification by BP for certain claims and expenses relating to the Macondo well incident. The MDL court has ruled that BP is required to indemnify us for third-party compensatory claims, or actual damages, that arise from pollution or contamination that did not originate from our property or equipment located above the surface of the land or water. The court also held, however, that BP does not owe us indemnity for punitive damages or for civil penalties under the Clean Water Act (CWA), if any.
In September 2014, we reached an agreement, subject to court approval, to settle a substantial portion of the plaintiffs’ claims asserted against us relating to the Macondo well incident (our MDL Settlement). Certain conditions must be satisfied before our MDL Settlement becomes effective, and our MDL Settlement does not cover all claims asserted against us in the MDL. Subsequently in September 2014, the MDL court ruled (Phase One Ruling) that, among other things, (1) in relation to the Macondo well incident, BP’s conduct was reckless, Transocean’s conduct was negligent, and our conduct was negligent, (2) fault for the Macondo blowout, explosion, and spill is apportioned 67% to BP, 30% to Transocean, and 3% to us, and (3) the indemnity and release clauses in our contract with BP are valid and enforceable against BP. The MDL court did not find that our conduct was grossly negligent. In January 2015, the MDL court ruled that, giving effect to the amount of oil collected as a result of BP’s cleanup efforts, a total of 3.19 million barrels of oil were discharged into the Gulf of Mexico for the purposes of determining the maximum penalty under the CWA. Although we have not been charged with any violations under the CWA, BP has filed claims against us, which remain unresolved, for equitable contribution, indemnity and subrogation with respect to its liabilities under the Oil Pollution Act of 1990 and CWA. Under the CWA, civil penalties of up to $1,100 per barrel of oil discharged (or $4,300 per barrel in the case of those found to have been grossly negligent) may be assessed against responsible parties.

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For additional information relating to our MDL Settlement, the status of the MDL and the INCs, see Note 9 to the consolidated financial statements.
As of December 31, 2014, our existing loss contingency liability related to the Macondo well incident was $805 million, consisting of a current portion of $367 million and a non-current portion of $439 million. The $805 million represents a $733 million loss contingency related to our MDL Settlement as well as an additional loss contingency of $72 million unrelated to that settlement. Our loss contingency liability does not include potential recoveries from our insurers or indemnification by BP.
Because our MDL Settlement is subject to court approval and other conditions and the Phase One Ruling and other rulings of the MDL court are subject to appeals, we are unable to predict the ultimate outcome of the many lawsuits, investigations, and other matters relating to the Macondo well incident, including appeals of the Phase One Ruling, further orders and rulings of the MDL court and other courts, and indemnification and insurance arrangements. BP has filed a Notice of Appeal for the Phase One Ruling and the MDL court’s denial of its motion to amend the court’s findings, alter or amend the court’s judgment, or for a new trial. In addition, certain insurance carriers have notified us that they do not intend to reimburse us for any amounts with respect to our MDL Settlement, representing approximately $200 million of insurance coverage. We are unable to predict whether or when the court will approve our MDL Settlement or whether or when the conditions of our MDL Settlement will be satisfied.
As a result of the various potential developments relating to the Macondo well incident, there are additional loss contingencies relating to the Macondo well incident that are reasonably possible but for which we cannot make a reasonable estimate. Accordingly, we may adjust our estimated loss contingency liability and our amounts recoverable from insurance in the future. In addition, applicable accounting rules and guidance may require us to recognize a loss contingency for which we may be fully indemnified, without recognizing a corresponding receivable for the amount of the indemnity payment. Depending on the outcome of the various potential developments relating to the Macondo well incident, liabilities arising out of the incident could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

Our operations are subject to political and economic instability, risk of government actions, and cyber-attacks 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:
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political and economic instability, including:    
civil unrest, acts of terrorism, force majeure, war, other armed conflict, and sanctions;
inflation; and
currency fluctuations, devaluations, and conversion restrictions; and
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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;
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, the effects of 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, 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 becoming 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. In addition, these risks could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition.

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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 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. Allegations of violations of applicable anti-corruption laws may 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 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 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. Any expansion of sanctions against Russia’s oil and gas industry could further hinder our ability to do business in Russia, which could have a material adverse effect on our consolidated results of operations.
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 as well as 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. 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.

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.


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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.
We are a leading provider of hydraulic fracturing services. Various federal legislative and regulatory initiatives have been undertaken which could result in additional requirements or restrictions being imposed on hydraulic fracturing operations. For example, the Department of Interior has issued proposed regulations that would apply to hydraulic fracturing operations on wells that are subject to federal oil and gas leases and that would impose requirements regarding the disclosure of chemicals used in the hydraulic fracturing process as well as requirements to obtain certain federal approvals before proceeding with hydraulic fracturing at a well site. These regulations, if adopted, would establish additional levels of regulation at the federal level that could lead to operational delays and increased operating costs. At the same time, legislation and/or regulations have been adopted in several 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. Two states (New York and Vermont) have banned or are in the process of banning the use of high volume hydraulic fracturing. Local jurisdictions in some states have adopted ordinances that restrict or in certain cases prohibit the use of hydraulic fracturing for oil and gas development. 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 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.

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, for example, those concerning:
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the containment and disposal of hazardous substances, oilfield waste, and other waste materials;
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the importation and use of radioactive materials;
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the use of underground storage tanks;
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the use of underground injection wells; and
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the protection of worker safety both onshore and offshore.
These and other requirements generally are becoming increasingly strict. Sanctions for failure to comply with the requirements, many of which may be applied retroactively, may include:
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administrative, civil, and criminal penalties;

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-
revocation of permits to conduct business; and
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corrective action orders, including orders to investigate and/or clean up contamination.
Failure on our part to comply with applicable environmental requirements could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition. We are also exposed to costs arising from regulatory compliance, including compliance with changes in or expansion of applicable regulatory requirements, which 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, could have a negative impact on our business if such laws, regulations, treaties, or international agreements reduce demand for oil and natural gas. 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.

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, including national oil 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 declined significantly in the second half of 2014, and were negatively affected by a combination of factors, including weakening demand in Europe and Asia, increased production in the United States, and the decision in late November by the Organization of Petroleum Exporting Countries to keep production levels unchanged. Additionally, stronger economic performance in the United States has led to a strengthening in the U.S. dollar relative to most other currencies, contributing further to the fall in the U.S. dollar value of oil. Downward pressure on commodity prices has continued in early 2015 and could continue for the foreseeable future. We anticipate 2015 will be a challenging year for us, as our customers continue to make downward revisions to their operating budgets. Therefore, we expect a drop-off in activity coupled with pricing pressures, and corresponding reductions in revenue and operating margins in 2015. For more information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment and Results of Operations.” Any prolonged reduction in oil and natural gas prices will depress the immediate levels of exploration, development, and production activity which could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition. Additionally, a prolonged reduction in oil and natural gas prices may require us to record asset impairments, including an impairment of the carrying value of our goodwill. Such a potential impairment charge could have a material adverse impact on our operating results. Even the perception of longer-term lower oil and natural gas prices by oil and natural gas companies can similarly reduce or defer major expenditures given the long-term nature of many large-scale development projects. Factors affecting the prices of oil and natural gas include:
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the level of supply and demand for oil and natural gas, especially demand for natural gas in the United States;
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governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves;
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weather conditions and natural disasters;
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worldwide political, military, and economic conditions;
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the level of oil production by non-OPEC countries and the available excess production capacity within OPEC;
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oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;
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the cost of producing and delivering oil and natural gas; and
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potential acceleration of the development of alternative fuels.
    

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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:
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oil and natural gas prices, including volatility of oil and natural gas prices and expectations regarding future prices;
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the inability of our customers to access capital on economically advantageous terms;
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the consolidation of our customers;
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customer personnel changes; and
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adverse developments in the business or operations of our customers, including write-downs of reserves and borrowing base reductions under customer credit facilities.
As a result of recent decreases in commodity prices, many of our customers have announced reduced capital spending budgets for 2015, and we expect that further reductions in commodity prices or prices remaining at current levels for a prolonged period of time may result in further capital budget reductions in the future.

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 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:
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evacuation of personnel and curtailment of services;
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weather-related damage to offshore drilling rigs resulting in suspension of operations;
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weather-related damage to our facilities and project work sites;
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inability to deliver materials to jobsites in accordance with contract schedules;
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decreases in demand for natural gas during unseasonably warm winters; and
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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 80 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 a tax year.

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:
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foreign currency exchange risks resulting from changes in foreign currency exchange rates and the implementation of exchange controls; and
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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, such as Venezuela, that have non-traded or “soft” currencies that, because of their restricted or limited trading markets, may be more difficult to exchange for “hard” currency. We may accumulate cash in soft currencies, and we may be limited in our ability to convert our profits into United States dollars or to repatriate the profits from those countries. In addition, we may accumulate cash in foreign jurisdictions that may be subject to taxation if repatriated to the United States. For further information, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Business Environment and Results of Operations" and Note 10 to the Consolidated Financial Statements, "Income Taxes."


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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.

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 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 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.

Our business in Venezuela subjects us to actions by the Venezuelan government, the risk of delayed payments, and currency risks, which could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.
We believe there are risks associated with our operations in Venezuela, including the possibility that the Venezuelan government could assume control over our operations and assets. Any delays in receiving payment on our receivables from our primary customer in Venezuela or failure to pay us a significant amount of our outstanding receivables could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.
The future results of our Venezuelan operations will be affected by many factors, including our ability to take actions to mitigate the effect of a devaluation of the Bolívar, the foreign currency exchange rate, actions of the Venezuelan government, and general economic conditions such as continued inflation and future customer payments and spending. For further information, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Business Environment and Results of Operations - International operations - Venezuela."

Some of our customers require bids for contracts in the form of long-term, fixed pricing 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.
Some of our customers, primarily NOCs, may require bids for contracts in the form of long-term, fixed pricing contracts that may require us to provide integrated project management services outside our normal discrete business to act 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

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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 are normally readily available. High levels of demand for, or shortage of, raw materials, such as proppants, hydrochloric acid, and gels, including guar gum, 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.

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 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 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;
-
any dispositions, investments, or acquisitions, including integration efforts, would not divert management resources; or
-
any dispositions, investments, or acquisitions would not have a material adverse effect on our liquidity, consolidated results of operations, or consolidated financial condition.

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, where control may be shared with unaffiliated third parties. As with any joint venture arrangement, differences in views among the joint venture participants may result in delayed decisions 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 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 employ and retain technical personnel with the ability to design, utilize, and enhance these services and products. In addition, our ability to expand our operations depends in part on our ability to increase our skilled labor force. 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.


16



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.

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. All of our owned properties are unencumbered.
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 Stavanger, Norway.
In addition, we have 174 international and 117 United States field camps from which we deliver our services and products. We also have numerous small facilities that include sales, project, and support offices and bulk storage facilities throughout the world.
We believe all properties that we currently occupy are suitable for their intended use.

Item 3. Legal Proceedings.
Information related to Item 3. Legal Proceedings is included in Note 9 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.

17



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 75 of this annual report. Quarterly cash dividends on our common stock, which were paid in March, June, September, and December of each year, were $0.125 per share for the first three quarters of 2013, $0.15 per share in the fourth quarter of 2013 and the first three quarters of 2014, and $0.18 per share in the fourth quarter of 2014. 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 pay dividends representing at least 15% to 20% of our net income on an annual basis.
The following graph and table compare total shareholder return on our common stock for the five-year period ended December 31, 2014, 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, 2009, and the reinvestment of all dividends. The shareholder return set forth is not necessarily indicative of future performance.


 
December 31
 
2009
2010
2011
2012
2013
2014
Halliburton
$
100.00

$
137.25

$
117.09

$
119.04

$
176.17

$
138.12

Philadelphia Oil Service Index (OSX)
100.00

126.92

113.53

117.09

153.76

120.98

Standard & Poor’s 500 ® Index
100.00

115.06

117.49

136.30

180.44

205.14



18



At February 17, 2015, we had 13,919 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, 2014.
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
23,283
$57.36
$5,700,004,373
November 1 - 30
29,642
$53.31
$5,700,004,373
December 1 - 31
170,193
$40.72
$5,700,004,373
Total
223,118
$44.13
 
(a)
All of the 223,118 shares purchased during the three-month period ended December 31, 2014 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 2014, 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 74 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 21 through 39 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” on page 38 of this annual report and Note 14 to the consolidated financial statements on page 68 of this annual report.

Item 8. Financial Statements and Supplementary Data.
 
Page No.
Management’s Report on Internal Control Over Financial Reporting
Reports of Independent Registered Public Accounting Firm
Consolidated Statements of Operations for the years ended December 31, 2014, 2013, and 2012
Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013, and 2012
Consolidated Balance Sheets at December 31, 2014 and 2013
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013, and 2012
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2014, 2013, and 2012
Notes to Consolidated Financial Statements
Selected Financial Data (Unaudited)
Quarterly Data and Market Price Information (Unaudited)

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.


19



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, 2014 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, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
See page 40 for Management’s Report on Internal Control Over Financial Reporting and page 42 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.

Item 9(b). Other Information.
None.


20



HALLIBURTON COMPANY
Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXECUTIVE OVERVIEW

Pending acquisition of Baker Hughes
On November 16, 2014, we and Baker Hughes entered into a merger agreement under which, subject to the conditions set forth in the merger agreement, we will acquire all the outstanding shares of Baker Hughes in a stock and cash transaction. The acquisition is expected to create a leading global oilfield services company and combine the companies’ product and service capabilities to deliver exceptional depth and breadth of solutions to our customers. The closing of the transaction is expected to occur in the second half of 2015. See Note 2 to the consolidated financial statements for further information about the pending acquisition.
Financial results
During 2014, we produced revenue of $32.9 billion, an increase of $3.5 billion, or 12%, from 2013, mainly due to increased stimulation activity in the United States land market and strong growth across the Eastern Hemisphere. Our 2014 revenue in North America comprised 54% of consolidated revenue compared to 46% outside of North America. We set new revenue records this year as a total company in both divisions and in 12 out of 13 product service lines. Operating income of $5.1 billion in 2014, which reflects an operating margin of 16%, was also a total company record and was driven by stimulation activity in the United States land market and improved results in our Middle East/Asia region. As a result of the market decline discussed in further detail below, we incurred $129 million, pre-tax, of restructuring charges in the fourth quarter of 2014, consisting of severance-related costs and asset write-offs. Most of these adjustments related to our Eastern Hemisphere business.
Business outlook
While 2014 was a strong year for our company, the outlook for 2015 is uncertain due to the depressed crude oil pricing environment. We anticipate 2015 will be a challenging year for us, as our customers continue to make downward revisions to their operating budgets. Therefore, we expect a significant drop-off in activity coupled with pricing pressures, and corresponding reductions in revenue and operating margins in 2015. We continue to believe in the strength of the long-term fundamentals of our business. Despite the expected worldwide activity declines in 2015, energy demand is still expected to increase over the long term.
In 2014, North America experienced revenue growth of 16% and operating income growth of 24%, compared to 2013. However, as current market conditions begin to take effect in early 2015, with a corresponding drop in the United States rig count, we expect a decline in activity and additional pricing pressure for the North America land market. Our customers' capital expenditure budgets for 2015 are uncertain, as they adjust their spending in response to a recent significant drop in commodity prices. While the intensity and duration of the current market downturn is uncertain, we intend to remain focused on our key strategies and have taken strategic steps to reduce our underlying cost profile. We have already taken initial steps to address headcount internationally in late 2014, and are in the midst of making further headcount reductions company-wide as we evaluate market conditions. As a result, we anticipate recording further material restructuring charges, including severance costs, in 2015.
In 2014, Eastern Hemisphere revenue and operating income increased 10% and 8%, respectively, compared to 2013. However, internationally, we began to see the impact of lower commodity prices in the fourth quarter of 2014. Declining crude oil prices have caused our customers to reduce their budgets and defer several of their new projects. We expect 2015 to be a challenging year across all of our international regions, as our customers continue to respond to current market conditions.
Although the outlook for 2015 remains uncertain, we will make necessary adjustments as activity dictates. Our intention is to look beyond the down cycle and continue to execute our strategic initiatives. We plan to continue executing the following strategies in 2015:
-
directing capital and resources into strategic growth markets, including unconventional plays, mature fields, and deepwater;
-
leveraging our broad technology offerings to provide value to our customers through integrated solutions and enabling 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; and
-
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.
Our operating performance and business outlook are described in more detail in “Business Environment and Results of Operations.”

21



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 intend to finance the cash portion of the consideration payable in the acquisition of Baker Hughes through a combination of cash on hand and debt, for which we have obtained financing commitments. For additional information on market conditions and the pending acquisition of Baker Hughes, see “Liquidity and Capital Resources,” “Business Environment and Results of Operations,” and Note 2 to the consolidated financial statements.

22



LIQUIDITY AND CAPITAL RESOURCES

We ended 2014 with cash and equivalents of $2.3 billion compared to $2.4 billion at December 31, 2013. Additionally, at December 31, 2014, we held $103 million of investments in fixed income securities compared to $373 million at December 31, 2013. These securities are reflected in "Other current assets" and "Other assets" in our consolidated balance sheets. As of December 31, 2014, approximately $634 million of the $2.3 billion of cash and equivalents was held by our foreign subsidiaries, of which $181 million would be subject to United States tax if repatriated. However, our intent is to permanently reinvest these funds outside of the United States and our current plans do not suggest a need to repatriate them to fund our United States operations.
Significant sources and uses of cash
Cash flows from operating activities were $4.1 billion in 2014.
Capital expenditures were $3.3 billion in 2014. The capital expenditures in 2014 were predominantly made in our Production Enhancement, Sperry Drilling, Wireline and Perforating, Cementing, and Boots & Coots product service lines.
Our primary components of net working capital (receivables, inventories, and accounts payable) increased during the year by a net $1.1 billion, primarily due to increased business activity.
During 2014, we repurchased approximately 13.3 million shares of our common stock under our share repurchase program at a total cost of approximately $800 million.
We paid $533 million of dividends to our shareholders in 2014.
During 2014, we made our first installment payment of $395 million related to the settlement we reached during the year for the Macondo well incident. See Note 9 to the consolidated financial statements for further information.
We sold $338 million of property, plant, and equipment during 2014.
During 2014, we sold $261 million of investment securities, net of investment securities purchased.
We paid $231 million for acquisitions of various businesses during 2014, net of cash acquired, to further enhance our existing product service lines.
Future sources and uses of cash
Subject to receipt of all required approvals, the closing of the acquisition of Baker Hughes is expected to occur in the second half of 2015. We intend to finance the cash portion of the acquisition through a combination of cash on hand and debt financing. We have obtained a commitment letter for an $8.6 billion senior unsecured bridge facility, which is greater than the expected cash consideration required upon closing of the Baker Hughes acquisition. We have not drawn any amounts under this commitment as of December 31, 2014. We may issue debt securities, obtain bank loans or other debt financings, or use cash on hand in lieu of utilizing all or a portion of the bridge facility. See Note 2 to the consolidated financial statements for further information about the pending acquisition.
During 2014, we reached an agreement, subject to court approval, to settle a substantial portion of the plaintiffs' claims asserted against us relating to the Macondo well incident for approximately $1.1 billion, of which $805 million remains payable as of December 31, 2014, with $367 million expected to be paid during 2015. See Note 9 to the consolidated financial statements for further information.
During 2014, we reached a settlement with KBR, Inc. (KBR) under which KBR agreed to pay us $81 million related to amounts owed to us under our Tax Sharing Agreement with KBR. We received $25 million during the fourth quarter of 2014, and $56 million remains recorded as a receivable as of December 31, 2014, most of which we expect to receive during 2015. See Note 8 to the consolidated financial statements for further information.
Capital spending for 2015 is currently expected to be essentially in line with 2014. Although the oil and natural gas markets have weakened dramatically in recent months, our objective is to look beyond the downward cycle and continue to invest in certain strategic technologies. The capital expenditures plan for 2015 is primarily directed towards our Production Enhancement, Sperry Drilling, Boots & Coots, Cementing, and Wireline and Perforating product service lines.
Subject to Board of Directors approval, our intention is to pay dividends representing at least 15% to 20% of our net income on an annual basis. In October 2014, Halliburton’s Board of Directors approved a 20% increase of the quarterly dividend from $0.15 to $0.18 per share, or approximately $153 million per quarter.
In July 2014, our Board of Directors increased the authorization to repurchase our common stock by approximately $4.8 billion. Approximately $5.7 billion remains authorized for repurchases as of December 31, 2014, which may be used for open market and other share purchases.
We had $314 million of gross unrecognized tax benefits at December 31, 2014, of which we estimate $168 million may require a cash payment. We estimate that $162 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.

23



Contractual obligations
The following table summarizes our significant contractual obligations and other long-term liabilities as of December 31, 2014:
 
Payments Due
 
 
Millions of dollars
2015
2016
2017
2018
2019
Thereafter
Total
Long-term debt
$
14

$
610

$
52

$
806

$
1,000

$
5,389

$
7,871

Interest on debt (a)
362

369

371

376

351

6,048

7,877

Operating leases
283

201

115

79

54

237

969

Purchase obligations (b)
1,100

429

289

118

29

68

2,033

Other long-term liabilities (c)
41

3

3

2

2

3

54

Total
$
1,800

$
1,612

$
830

$
1,381

$
1,436

$
11,745

$
18,804

(a)
Interest on debt includes 82 years of interest on $300 million of debentures at 7.6% interest that become due in 2096.
(b)
Amount in 2015 primarily represents certain purchase orders for goods and services utilized in the ordinary course of our business.
(c)
Includes capital lease obligations and pension funding obligations. Amounts for pension funding obligations, which include international plans and are based on assumptions that are subject to change, are only included for 2015 as we are currently not able to reasonably estimate our contributions for years after 2015.

Other factors affecting liquidity
Financial position in current market. As of December 31, 2014, we had $2.3 billion of cash and equivalents, $103 million in fixed income investments, and a total of $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. Although a portion of earnings from our foreign subsidiaries is reinvested outside the United States indefinitely, we do not consider this to have a significant impact on our liquidity. We currently believe that capital expenditures, working capital investments, and dividends, if any, during 2015 can be fully funded through cash from operations.
As a result, we believe we have a reasonable amount of liquidity and, if necessary, additional financing flexibility given the current market environment to fund our potential contingent liabilities, if any. However, as discussed in Note 9 to the consolidated financial statements, there are future developments that may arise as a result of the Macondo well incident that could have a material adverse effect on our liquidity.
Guarantee agreements. In the normal course of business, we have agreements with financial institutions under which approximately $2.4 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of December 31, 2014. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.
Credit ratings. Credit ratings for our long-term debt remain A2 with Moody’s Investors Service and A with Standard & Poor’s. The credit ratings on our short-term debt remain P-1 with Moody’s Investors Service and A-1 with Standard & Poor’s. While these credit ratings remained unchanged during 2014, after the announcement of the pending Baker Hughes acquisition, Standard & Poor’s placed all of our ratings on negative watch.
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 “Business Environment and Results of Operations – International operations – Venezuela” for further discussion related to Venezuela.



24



BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS

We operate in approximately 80 countries throughout the world to provide a comprehensive range of services and products to the upstream oil and natural gas 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 substantial competitors in each segment of our business. In 2014, 2013, and 2012, based on the location of services provided and products sold, 51%, 49%, and 53% 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, 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, the world economy, the availability of credit, government regulation, and global stability, which together drive worldwide drilling activity. Our financial performance is significantly affected by oil and natural gas prices and worldwide rig activity, which are summarized in the following tables. Additionally, due to improved drilling and completion efficiencies as more of our customers move to multi-well pad drilling, our financial performance is impacted by well count in the North America market.
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:
 
2014
2013
2012
Oil price - WTI (1)
$
93.37

$
97.99

$
94.15

Oil price - Brent (1)
99.04

108.71

111.60

Natural gas price - Henry Hub (2)
4.39

3.73

2.81

 
 
 
 
(1) Oil price measured in dollars per barrel
(2) Natural gas price measured in dollars per million British thermal units (Btu), or MMBtu
 
Three Months Ended December 31, 2014
Month Ended
December 31, 2014
Oil price - WTI
$
73.55

$
59.95

Oil price - Brent
76.81

63.07



25



The historical average rig counts based on the weekly Baker Hughes Incorporated rig count information were as follows:
Land vs. Offshore
2014
2013
2012
United States:
 
 
 
Land
1,804

1,705

1,872

Offshore (incl. Gulf of Mexico)
57

56

47

Total
1,861

1,761

1,919

Canada:
 

 

 

Land
378

352

363

Offshore
2

2

1

Total
380

354

364

International (excluding Canada):
 
 
 
Land
1,011

978

931

Offshore
326

318

303

Total
1,337

1,296

1,234

Worldwide total
3,578

3,411

3,517

Land total
3,193

3,035

3,166

Offshore total
385

376

351

 
 
 
 
Oil vs. Natural Gas
2014
2013
2012
United States (incl. Gulf of Mexico):
 
 
 
Oil
1,528

1,375

1,359

Natural gas
333

386

560

Total
1,861

1,761

1,919

Canada:
 
 
 
Oil
218

234

261

Natural gas
162

120

103

Total
380

354

364

International (excluding Canada):
 
 
 
Oil
1,070

1,029

984

Natural gas
267

267

250

Total
1,337

1,296

1,234

Worldwide total
3,578

3,411

3,517

Oil total
2,816

2,638

2,604

Natural gas total
762

773

913


Drilling Type
2014
2013
2012
United States (incl. Gulf of Mexico):
 
 
 
Horizontal
1,274
1,102
1,151
Vertical
376
435
552
Directional
211
224
216
Total
1,861
1,761
1,919

Our customers’ cash flows, in most instances, depend upon the revenue they generate from the sale of oil and natural gas. Lower oil and natural gas prices usually translate into lower exploration and production budgets, while the opposite is true for higher oil and natural gas prices.


26



WTI oil spot prices declined significantly in the second half of 2014, ranging from a high of $108 per barrel in June to a low of $53 per barrel in December, while Brent crude oil spot prices declined from a high of $115 per barrel in June to a low of $55 per barrel in December. Spot crude oil prices were negatively affected by a combination of factors, including weakening demand in Europe and Asia, and increased production in the United States. Additionally, stronger economic performance in the United States has led to a strengthening in the U.S. dollar relative to most other currencies, contributing further to the fall in the U.S dollar value of oil. In addition, the monthly average for Brent crude oil spot prices in December 2014 was $63 per barrel, down $16 per barrel from the November 2014 average, following the decision in late November by the Organization of Petroleum Exporting Countries to keep production levels unchanged.
Demand in the fourth quarter of 2014 for Europe fell by 4% from the prior quarter as curtailments in France and Germany continued to contribute to a particularly uncertain forecasting environment. Crude oil production in the United States averaged an estimated 9.2 million barrels per day in December 2014, an increase of 6% from the September 2014 average. The expansion of export possibilities in the United States contributed to the decreased differential between WTI and Brent crude oil spot prices, which has narrowed from an average of $4 per barrel in the third quarter of 2014 to $3 per barrel in the fourth quarter of 2014.
According to the United States Energy Information Administration (EIA) February 2015 "Short Term Energy Outlook," the EIA projects that Brent prices will average $58 per barrel in 2015, with increases towards the end of the year to an average of $67 per barrel during the fourth quarter. The EIA also noted that price projections reflect a scenario in which supply is expected to continue to exceed demand, leading to inventory surplus through the first three quarters of 2015. Although there are no signs that point to an immediate rebalance of the market, the International Energy Agency's (IEA) February 2015 "Oil Market Report" forecasts the 2015 global demand to average approximately 93.4 million barrels per day, which is up 1% from 2014, driven by an increase in all regions except for Europe and the Commonwealth of Independent States.
The average 2014 full year Henry Hub natural gas price in the United States increased approximately 18% from 2013 as a result of an increase in natural gas storage withdrawals related to an unseasonably harsh winter in the early part of 2014. However, natural gas spot prices declined sharply in December 2014 to a year-low $2.74 per MMBtu as a result of a warmer than normal month, along with robust production that contributed to lower than average storage withdrawals. The EIA February 2015 “Short Term Energy Outlook” projects Henry Hub natural gas prices to average $3.05 per MMBtu in 2015 compared to $4.39 per MMBtu in 2014. Over the long term, the EIA expects natural gas consumption in the power sector to increase as new industrial projects come online, offsetting the decline in residential and commercial consumption.
We believe that, over the long-term, hydrocarbon demand will generally increase, and this, combined with the underlying trends of smaller and more complex reservoirs, high depletion rates, and the need for continual reserve replacement, should drive the long-term need for our services and products.
North America operations
Volatility in oil and natural gas prices can impact our customers’ drilling and production activities. During 2014, the average full year natural gas-directed rig count in North America was flat, while the average full year oil directed rig count increased 137 rigs, or 9%, from 2013. In the United States land market, there was a modest full year increase in rig count from 2013 levels, driven primarily by the continued shift to horizontal rigs in the Permian Basin. The North America rig count and activity levels held up through most of the fourth quarter as customers executed against the remainder of their 2014 budgets.
However, the United States land rig count has fallen sharply into early 2015, and we expect activity declines for the United States land market to accelerate further in the first quarter of 2015, impacting all of the key liquid basins. Current market conditions aside, in the long run, we believe the shift to unconventional oil and liquids-rich basins in the United States land market will continue to drive increased service intensity and will require higher demand in fluid chemistry and other technologies required for these complex reservoirs which will have beneficial implications for our operations.
In the Gulf of Mexico, the average full year offshore rig count was relatively flat in 2014 as compared to 2013. Growth in the Gulf of Mexico is dependent on, among other things, governmental approvals for permits, our customers' actions, and new deepwater rigs entering the market.
International operations
The average international rig count for 2014 modestly increased from 2013, however the total international rig count in December 2014 was down 1% from the prior month. Declining crude oil prices have caused several of our customers to reduce their budgets and defer several new projects. We expect that 2015 will be a challenging year for all of our international regions, primarily in our Europe/Africa/CIS region, with our Middle East/Asia region likely being the most resilient.
Despite the current market environment, we believe that international unconventional oil and natural gas, mature field, and deepwater projects will contribute to activity improvements over the long term, and we plan to leverage our extensive experience in North America to optimize these opportunities. Consistent with our long-term strategy to grow our operations outside of North America, we also expect to continue to invest in capital equipment for our international operations.
Venezuela. As of December 31, 2014, our total net investment in Venezuela was approximately $649 million, including net monetary assets of $162 million denominated in Bolívares. Also, at December 31, 2014 we had $276 million of surety bond guarantees outstanding relating to our Venezuelan operations. Our net investment and surety bond guarantees relating to our Venezuelan operations have increased since December 31, 2013 by 58% and 44%, respectively, corresponding to increased demand for our services in the country.

27



While we are continuing to collect some of our receivables from our primary customer in Venezuela, the amount of outstanding receivables has increased in connection with increased activity.  These receivables are not disputed, and we have not historically had material write-offs relating to this customer. Additionally, we routinely monitor the financial stability of our customers. Our total outstanding trade receivables in Venezuela were $670 million, or approximately 9% of our gross trade receivables, as of December 31, 2014, compared to $486 million, or approximately 8% of our gross trade receivables, as of December 31, 2013. Of the $670 million of receivables in Venezuela as of December 31, 2014, $256 million has been classified as long-term and included within “Other assets” on our consolidated balance sheets. Of the $486 million receivables in Venezuela as of December 31, 2013, $183 million has been classified as long-term and included within “Other assets” on our consolidated balance sheets.
In February 2013, the Venezuelan government devalued the Bolívar, from the preexisting exchange rate of 4.3 Bolívares per United States dollar to 6.3 Bolívares per United States dollar, resulting in us incurring a foreign currency loss.
During 2014, the Venezuelan government made available two new foreign exchange rate mechanisms through which a company may be able to legally convert Bolívares to United States dollars, in addition to the National Center of Foreign Commerce official rate of 6.3 Bolívares per United States dollar: (i) a bid rate established via weekly auctions under the Complementary System of Foreign Currency Acquirement (SICAD I); and (ii) an auction rate which is intended to more closely resemble a market-driven exchange rate (SICAD II).
In February 2015, the Venezuelan government created a new foreign exchange rate mechanism, called the Marginal Currency System. The new mechanism, which is the third system in a three-tier exchange control mechanism, will be driven by the free market and allow for a company to legally convert Bolívares to United States dollars based on supply and demand. The three-tier exchange rate mechanisms are as follows: (i) the official rate of 6.3 discussed above, which remains unchanged; (ii) the SICAD I, which will continue to hold periodic auctions for specific sectors of the economy and begin with a rate of 12 Bolívares per United States dollar; and (iii) the Marginal Currency System, which replaces the SICAD II system and held its initial transaction at approximately 170 Bolívares per United States dollar.
The availability of alternative currency mechanisms had no impact on our results of operations during the year ended December 31, 2014 as we continue to use the official exchange rate to remeasure net assets denominated in Bolívares. We are currently evaluating the newly created Marginal Currency System and expect to utilize this rate starting in the first quarter of 2015. Had we used the Marginal Currency System potential rate of 170 Bolívares per United States dollar to remeasure our net monetary position as of December 31, 2014, we would have incurred a foreign currency loss of $156 million in 2014.
For additional information, see Part I, Item 1(a), “Risk Factors” in this Form 10-K.



28



RESULTS OF OPERATIONS IN 2014 COMPARED TO 2013

REVENUE:
 
 
Favorable
Percentage
Millions of dollars
2014
2013
(Unfavorable)
Change
Completion and Production
$
20,253

$
17,506

$
2,747

16
 %
Drilling and Evaluation
12,617

11,896

721

6

Total revenue
$
32,870

$
29,402

$
3,468

12
 %

 
 
 
 
By geographic region:
 
 
 
 
Completion and Production:
 
 
 
 
North America
$
13,688

$
11,417

$
2,271

20
 %
Latin America
1,633

1,586

47

3

Europe/Africa/CIS
2,595

2,391

204

9

Middle East/Asia
2,337

2,112

225

11

Total
20,253

17,506

2,747

16

Drilling and Evaluation:
 
 
 
 
North America
4,010

3,795

215

6

Latin America
2,242

2,323

(81
)
(3
)
Europe/Africa/CIS
2,895

2,834

61

2

Middle East/Asia
3,470

2,944

526

18

Total
12,617

11,896

721

6

Total revenue by region:
 
 
 
 
North America
17,698

15,212

2,486

16

Latin America
3,875

3,909

(34
)
(1
)
Europe/Africa/CIS
5,490

5,225

265

5

Middle East/Asia
5,807

5,056

751

15



29



OPERATING INCOME:
 
 
Favorable
Percentage
Millions of dollars
2014
2013
(Unfavorable)
Change
Completion and Production
$
3,610

$
2,875

$
735

26
 %
Drilling and Evaluation
1,671

1,770

(99
)
(6
)
Corporate and other
(184
)
(1,507
)
1,323

(88
)
Total operating income
$
5,097

$
3,138

$
1,959

62
 %

 
 
 
 
By geographic region:
 
 
 
 
Completion and Production:
 
 
 
 
North America
$
2,598

$
1,916

$
682

36
 %
Latin America
211

211



Europe/Africa/CIS
371

356

15

4

Middle East/Asia
430

392

38

10

Total
3,610

2,875

735

26

Drilling and Evaluation:
 
 
 
 
North America
588

656

(68
)
(10
)
Latin America
211

307

(96
)
(31
)
Europe/Africa/CIS
259

334

(75
)
(22
)
Middle East/Asia
613

473

140

30

Total
1,671

1,770

(99
)
(6
)
Total operating income by region
 
 
 
 
(excluding Corporate and other):
 
 
 
 
North America
3,186

2,572

614

24

Latin America
422

518

(96
)
(19
)
Europe/Africa/CIS
630

690

(60
)
(9
)
Middle East/Asia
1,043

865

178

21


Consolidated revenue in 2014 increased 12% compared to 2013, primarily as a result of higher stimulation activity in the United States land market and increased activity in almost all of our product service lines in the Eastern Hemisphere, which were partially offset by lower activity in Latin America. Revenue outside of North America was 46% of consolidated revenue in 2014 and 48% of consolidated revenue in 2013.
The $2.0 billion increase in consolidated operating income compared to 2013 was primarily a result of various corporate expense items in 2013 as well as increased stimulation activity in the United States land market and growth in Middle East/Asia in 2014, which more than offset lower activity and margins experienced in Latin America. Operating income in 2014 was positively impacted by $195 million of Macondo-related items as a result of a reduction of our loss contingency liability and an expected insurance recovery, offset by $129 million of restructuring charges related to severance and asset write-offs and $17 million of Baker Hughes acquisition-related costs. Operating income in 2013 was negatively impacted by the following pre-tax items: a $1.0 billion increase in our loss contingency liability related to Macondo, $92 million of restructuring charges related to severance and asset write-offs, and a $55 million charge related to a charitable contribution to the National Fish and Wildlife Foundation, partially offset by a $28 million value-added tax refund receivable in Brazil.
Completion and Production revenue increased 16% compared to 2013, with activity increases across all regions and predominately in North America. North America revenue rose 20% primarily as a result of increased stimulation activity in the United States land market. Latin America revenue improved 3%, as increased activity levels in the majority of our product service lines in Venezuela and Argentina more than offset a decrease in stimulation activity in Mexico and lower pressure pumping activity in Brazil. Europe/Africa/CIS revenue grew 9%, driven by strong growth across most of our product service lines in Angola and the United Kingdom, as well as increased completion tools sales in Nigeria, which were partially offset by lower pressure pumping activity and currency weakness in Norway. Middle East/Asia revenue improved 11% primarily due to increased activity in the majority of our product service lines in Saudi Arabia, higher cementing activity in Thailand, and increased stimulation and artificial lift activity in Australia, which more than offset reduced activity levels in Oman and a decline in completion tools sales in Malaysia. Revenue outside of North America was 32% of total segment revenue in 2014 and 35% of total segment revenue in 2013.

30



Completion and Production operating income increased 26% compared to 2013, driven predominantly by strong growth in North America coupled with modest improvement in the Eastern Hemisphere. North America operating income rose 36% from 2013, primarily due to increased profitability for stimulation activity in the United States land market. Latin America operating income was flat as improved pressure pumping activity in Argentina and increased profitability for well intervention services in Mexico and Venezuela were offset by reduced completion tools sales and profitability in Brazil, Mexico and Trinidad. Europe/Africa/CIS operating income grew 4% compared to 2013, primarily due to higher completion products sales in Nigeria, Angola and the United Kingdom, which were partially offset by decreased well completion activity and currency weakness in Russia and Norway. Middle East/Asia operating income rose by 10% primarily due to increased profitability for the majority of our product services lines in Saudi Arabia, which was partially offset by reduced activity levels in China and Oman.
Drilling and Evaluation revenue increased 6% compared to 2013, primarily due to a strong performance in the Eastern Hemisphere, primarily in Saudi Arabia, which was partially offset by a decrease in drilling activity and consulting services in Latin America. North America revenue rose by 6% due to increased fluids activity in the United States land market and higher activity in the majority of our product service lines in the Gulf of Mexico. Latin America revenue decreased 3%, as reduced activity across all of our product service lines in Mexico and a decline in drilling activity in Brazil more than offset increased activity across all of our product service lines in Venezuela and Argentina. Europe/Africa/CIS revenue was relatively flat as increased testing activity in Angola and Nigeria was offset by decreased drilling and fluids activity in Egypt and Libya. Middle East/Asia revenue rose 18% as a result of increased activity in all of our product services lines in Saudi Arabia and increased demand for drilling services in Thailand and fluids activity in Australia, India and Iraq. Revenue outside of North America was 68% of total segment revenue in both 2014 and 2013.
Drilling and Evaluation operating income decreased 6% compared to 2013, primarily due to lower drilling activity and margins in Latin America and lower profitability in the Europe/Africa/CIS region. This decrease was partially offset by strong activity growth in the Middle East/Asia region. North America operating income was down 10% from 2013 due to a decline in drilling services in Canada and the United States land market. Latin America operating income declined 31% mainly due to reduced activity levels in Mexico and lower drilling activity and pricing in Brazil, which were partially offset by improved activity levels in Argentina. The Europe/Africa/CIS region operating income fell 22% primarily due to lower activity and currency weakness in Russia and Norway. Middle East/Asia operating income increased 30% primarily due to an increase in demand and profitability for drilling activity in Saudi Arabia, as well as improved demand for drilling services in Thailand, which were partially offset by reduced drilling services and logging activity in China.
Corporate and other expenses were $184 million in 2014 compared to $1.5 billion in 2013. The significant decrease was primarily due to Macondo-related items. In 2013, we recorded a $1.0 billion increase to our loss contingency for the Macondo well incident, while in 2014 we recorded a reduction of our loss contingency liability and an expected insurance recovery totaling $195 million. We recorded $17 million of costs in 2014 related to the pending Baker Hughes acquisition and a $55 million charge in 2013 related to a charitable contribution to the National Fish and Wildlife Foundation. See Note 9 to the consolidated financial statements for further information regarding the Macondo well incident.

NONOPERATING ITEMS
Interest expense, net increased $52 million in 2014, compared to 2013, primarily due to higher interest expense as a result of the issuance of $3.0 billion aggregate principal amount of senior notes in August 2013.
Effective tax rate. Our effective tax rate was 27.1% for 2014 and 23.5% for 2013. The effective tax rate for 2014 was positively impacted by a $201 million net operating loss valuation allowance released as a result of a reorganization of our legal entity structure in Brazil, as well as lower tax rates in certain foreign jurisdictions. Partially offsetting these items were tax expenses related to Macondo items recorded during 2014, which was tax-effected at the United States statutory rate, as well as total charges of approximately $150 million for a write-off of certain prepaid tax assets recorded in Iraq, additional tax expenses related to the settlement of a research and development credit with the United States tax authorities, and tax expenses related to other unrecognized tax benefits. Our effective tax rate for 2013 was also positively impacted by lower tax rates in certain foreign jurisdictions; federal tax benefits of approximately $50 million due to the reinstatement of certain tax benefits and credits related to the first quarter of 2013 enactment of the American Taxpayer Relief Act of 2012; and the tax impact related to an increase of our Macondo-related loss contingency recorded during 2013, which was tax-effected at the United States statutory rate. See Note 10 to the consolidated financial statements for further information regarding income taxes.
Income from discontinued operations, net was $64 million in 2014, compared to $19 million in 2013, primarily due to $63 million of income recorded in 2014 related to a settlement we reached with KBR for amounts owed to us under our Tax Sharing Agreement with KBR. See Note 8 to the consolidated financial statements for further information.




31



RESULTS OF OPERATIONS IN 2013 COMPARED TO 2012

REVENUE:
 
 
Favorable
Percentage
Millions of dollars
2013
2012
(Unfavorable)
Change
Completion and Production
$
17,506

$
17,380

$
126

1
 %
Drilling and Evaluation
11,896

11,123

773

7

Total revenue
$
29,402

$
28,503

$
899

3
 %

 
 
 
 
By geographic region:
 
 
 
 
Completion and Production:
 
 
 
 
North America
$
11,417

$
12,157

$
(740
)
(6
)%
Latin America
1,586

1,415

171

12

Europe/Africa/CIS
2,391

2,099

292

14

Middle East/Asia
2,112

1,709

403

24

Total
17,506

17,380

126

1

Drilling and Evaluation:
 
 
 
 
North America
3,795

3,847

(52
)
(1
)
Latin America
2,323

2,279

44

2

Europe/Africa/CIS
2,834

2,411

423

18

Middle East/Asia
2,944

2,586

358

14

Total
11,896

11,123

773

7

Total revenue by region:
 
 
 
 
North America
15,212

16,004

(792
)
(5
)
Latin America
3,909

3,694

215

6

Europe/Africa/CIS
5,225

4,510

715

16

Middle East/Asia
5,056

4,295

761

18



32



OPERATING INCOME:
 
 
Favorable
Percentage
Millions of dollars
2013
2012
(Unfavorable)
Change
Completion and Production
$
2,875

$
3,144

$
(269
)
(9
)%
Drilling and Evaluation
1,770

1,675

95

6

Corporate and other
(1,507
)
(660
)
(847
)
128

Total operating income
$
3,138

$
4,159

$
(1,021
)
(25
)%

 
 
 
 
By geographic region:
 
 
 
 
Completion and Production:
 
 
 
 
North America
$
1,916

$
2,260

$
(344
)
(15
)%
Latin America
211

206

5

2

Europe/Africa/CIS
356

347

9

3

Middle East/Asia
392

331

61

18

Total
2,875

3,144

(269
)
(9
)
Drilling and Evaluation:
 
 
 
 
North America
656

680

(24
)
(4
)
Latin America
307

393

(86
)
(22
)
Europe/Africa/CIS
334

246

88

36

Middle East/Asia
473

356

117

33

Total
1,770

1,675

95

6

Total operating income by region
 
 
 
 
(excluding Corporate and other):
 
 
 
 
North America
2,572

2,940

(368
)
(13
)
Latin America
518

599

(81
)
(14
)
Europe/Africa/CIS
690

593

97

16

Middle East/Asia
865

687

178

26


Consolidated revenue in 2013 increased 3% compared to 2012, primarily driven by activity growth across all international regions. This was partially offset by lower activity levels and pricing pressure in the United States land market. Revenue outside of North America was 48% of consolidated revenue in 2013 and 44% of consolidated revenue in 2012.
The $1.0 billion decrease in consolidated operating income compared to 2012 was primarily related to Macondo-related charges. Operating income in 2013 was impacted by the following pre-tax items: a $1.0 billion Macondo-related loss contingency, $92 million of restructuring charges related to severance and asset write-offs, and a $55 million charge related to a charitable contribution to the National Fish and Wildlife Foundation, partially offset by a $28 million value-added tax refund receivable in Brazil. Operating income in 2012 was impacted by the following pre-tax items: a $300 million Macondo-related loss contingency, along with a $48 million charge related to an earn-out adjustment due to significantly better than expected performance of a past acquisition, partially offset by a $20 million gain related to the settlement of a patent infringement lawsuit.
Completion and Production revenue increased slightly compared to 2012 due to strong international growth, which was partially offset by a decline in North America activity. North America revenue decreased 6%, primarily due to pricing pressures in the United States hydraulic fracturing market and lower activity in Canada. Latin America revenue was up 12% due to increased completion products sales in Brazil and higher activity in most product service lines in Mexico and Argentina. Europe/Africa/CIS revenue grew 14%, driven by strong demand for cementing services in Norway, West Africa, and Russia and completion tools throughout the region. Middle East/Asia revenue improved 24% due to higher activity in most product service lines in Saudi Arabia, Australia, Indonesia, and China, increased completion tools sales in Malaysia, and higher demand for cementing services in Thailand. Revenue outside of North America was 35% of total segment revenue in 2013 and 30% of total segment revenue in 2012.

33



Completion and Production operating income decreased 9% compared to 2012, primarily due to the North America region, where operating income fell 15% due to pricing pressures in the United States hydraulic fracturing market and lower activity in Canada. Latin America operating income was up 2% as a result of higher demand for cementing services in Mexico and Venezuela and production enhancement services in Argentina. Europe/Africa/CIS operating income grew 3% compared to 2012, driven by higher completion products activity in Angola and cementing activity in Norway. Middle East/Asia operating income increased 18% due to higher activity levels in Saudi Arabia and Iraq, higher direct sales in China, and improved profitability in Indonesia.
Drilling and Evaluation revenue increased 7% compared to 2012, driven by strong results in the Eastern Hemisphere. North America revenue was essentially flat, as lower demand for drilling and wireline services was partially offset by fluids activity across the United States land market and higher activity in the Gulf of Mexico. Latin America revenue was also relatively flat, as higher demand for all product lines in Mexico and fluids throughout the region were partially offset by lower drilling services activity in Colombia and wireline activity in Brazil. Europe/Africa/CIS revenue increased 18% due to improved fluids activity in Norway and Angola and higher drilling services activity in Eurasia, Norway, Egypt, and Angola. Middle East/Asia revenue rose 14% primarily due to strong demand in Saudi Arabia and Indonesia, higher drilling activity throughout the region, and higher wireline activity in Asia Pacific. Revenue outside of North America was 68% of total segment revenue in 2013 and 65% of total segment revenue in 2012.
Drilling and Evaluation operating income improved 6% compared to 2012, as increased activity in the Eastern Hemisphere was partially offset by higher costs in Latin America. North America operating income was down 4% from 2012, as a reduction in drilling and wireline services was partially offset by demand for fluids and consulting and project management. Latin America operating income declined 22% due to higher costs in Brazil and Venezuela and lower activity in Colombia. The Europe/Africa/CIS region operating income grew 36%, driven by fluids activity in Angola and Norway and drilling services in Eurasia. Middle East/Asia operating income increased 33% as a result of higher activity in Iraq, Indonesia, and Malaysia.
Corporate and other expenses were $1.5 billion in 2013 compared to $660 million in 2012. The significant increase was primarily due to a $1.0 billion Macondo-related loss contingency that was recorded in the first quarter of 2013, compared to a $300 million Macondo-related loss contingency recorded in the first quarter of 2012. Additionally, a $55 million charitable contribution to the National Fish and Wildlife Foundation was expensed in the second quarter of 2013, reflecting our commitment to making a positive environmental impact in our local communities.

NONOPERATING ITEMS
Effective tax rate. Our effective tax rate on continuing operations was 23.5% for 2013 and 32.3% for 2012. The 2013 effective tax rate on continuing operations was positively impacted by several items during the year, including federal tax benefits of approximately $50 million due to the reinstatement of certain tax benefits and credits related to the first quarter enactment of the American Taxpayer Relief Act of 2012. Also contributing to the lower tax rate in 2013 was a $1.0 billion loss contingency related to the Macondo well incident, which was tax-effected at the United States statutory rate, as well as some favorable tax items in Latin America in the fourth quarter. Additionally, our effective tax rate was positively impacted by lower tax rates in certain foreign jurisdictions, as we continue to reposition our technology, supply chain, and manufacturing infrastructure to more effectively serve our customers internationally.


34



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;
-
pensions;
-
allowance for bad debts; and
-
percentage-of-completion accounting for long-term, integrated project management contracts.
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.
We have discussed the development and selection of these critical accounting policies and estimates with the Audit Committee of our Board of Directors, and the Audit Committee has reviewed the disclosure presented below.
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 80 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.

35



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.
Legal, environmental, and investigation matters
As discussed in Note 9 of our consolidated financial statements, as of December 31, 2014, 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, our future financial results may be adversely affected. 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. We conduct impairment tests on long-lived assets whenever events or changes in circumstances indicate that the carrying value may not be recoverable and on intangible assets quarterly. 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. We review the carrying value of these assets based upon estimated future cash flows while taking into consideration assumptions and estimates including the future use of the asset, remaining useful life of the asset, and service potential of the asset.
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 test goodwill for impairment annually, during the third quarter, or if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. For purposes of performing the goodwill impairment test our reporting units are the same as our reportable segments, the Completion and Production division and the Drilling and Evaluation division. See Note 1 to the consolidated financial statements for our accounting policies related to long-lived assets and intangible assets, as well as the results of our goodwill impairment assessment, including our updated assessment performed as a result of the decline in crude oil prices subsequent to our goodwill impairment assessment date in 2014.
The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted revenue and costs assumptions. If the crude oil market continues to decline and remains at low levels for a sustained period of time, we could record an impairment of the carrying value of our goodwill in the future. If crude oil prices decline further or remain at low levels, to the extent appropriate we expect to perform our goodwill impairment assessment on a more frequent basis to determine whether an impairment is required.
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 to assist in fair value determination of inventories, identifiable intangible assets, and any other significant assets or liabilities when appropriate. 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.
Pensions
Our pension benefit obligations and expenses are calculated using actuarial models and methods. Two of the more critical assumptions and estimates used in the actuarial calculations are the discount rate for determining the current value of

36



benefit obligations and the expected long-term rate of return on plan assets used in determining net periodic benefit cost. Other critical assumptions and estimates used in determining benefit obligations and cost, including demographic factors such as retirement age, mortality, and turnover, are also evaluated periodically and updated accordingly to reflect our actual experience.
Discount rates are determined annually and are based on the prevailing market rate 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 are determined annually and are based on an evaluation of our plan assets and historical trends and experience, taking into account current and expected market conditions. These assumptions differ based on varying factors specific to each particular country or economic environment.
The discount rate utilized in 2014 to determine the projected benefit obligation at the measurement date for our United Kingdom pension plan, which constituted 80% of our international plans’ pension obligations, was 3.75%, compared to a discount rate of 4.5% utilized in 2013. The expected long-term rate of return assumption used for our United Kingdom pension plan expense was 6.5% in 2014 and 2013.
The following table illustrates the sensitivity to changes in certain assumptions, holding all other assumptions constant, for our United Kingdom pension plan.
 
Effect on
Millions of dollars
Pretax Pension Expense in 2014
Pension Benefit Obligation at December 31, 2014
50-basis-point decrease in discount rate
$
3

$
121

50-basis-point increase in discount rate
(3
)
(105
)
50-basis-point decrease in expected long-term rate of return
4

NA

50-basis-point increase in expected long-term rate of return
(4
)
NA


Our international defined benefit plans reduced pretax income by $36 million in 2014, $32 million in 2013, and $26 million in 2012. Included in these amounts was income from expected return on plan assets of $52 million in 2014, $44 million in 2013, and $45 million in 2012. Actual returns on international plan assets totaled $69 million in 2014, compared to $117 million in 2013. Our net actuarial loss, net of tax, related to international pension plans was $298 million at December 31, 2014 and $222 million at December 31, 2013. In our international plans where employees earn additional benefits for continued service, actuarial gains and losses will be recognized in operating income over a period of two to 17 years, which represents the estimated average remaining service of the participant group expected to receive benefits. In our international plans where benefits are not accrued for continued service, actuarial gains and losses will be recognized in operating income over a period of 17 to 32 years, which represents the estimated average remaining lifetime of the benefit obligations. These ranges reflect varying maturity levels among the plans.
During 2014, we made contributions of $16 million to our international defined benefit plans. We expect to make contributions of approximately $14 million to our international defined benefit plans in 2015.
The actuarial assumptions used in determining our pension benefit obligations may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, and longer or shorter life spans of participants. While we believe that the assumptions used are appropriate, differences in actual experience or changes in assumptions may materially affect our financial position or results of operations. See Note 15 to the consolidated financial statements for further information related to defined benefit and other postretirement benefit plans.
Allowance for bad debts
We evaluate our 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 1.6% to 2.7%. At December 31, 2014, allowance for bad debts totaled $137 million, or 1.8% of notes and accounts receivable before the allowance. At December 31, 2013, allowance for bad debts totaled $117 million, or 1.9% 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, 2014 would have resulted in a $76 million adjustment to 2014 total operating costs and expenses. See Note 4 to the consolidated financial statements for further information.

37



Percentage of completion
Revenue from certain long-term, integrated project management contracts to provide well construction and completion services is reported on the percentage-of-completion method of accounting. Progress is generally based upon physical progress related to contractually defined units of work. At the outset of each contract, we prepare a detailed analysis of our estimated cost to complete the project. Risks related to service delivery, usage, productivity, and other factors are considered in the estimation process. The recording of profits and losses on long-term contracts requires an estimate of the total profit or loss over the life of each contract. This estimate requires consideration of total contract value, change orders, and claims, less costs incurred and estimated costs to complete. Anticipated losses on contracts are recorded in full in the period in which they become evident. Profits are recorded based upon the total estimated contract profit times the current percentage complete for the contract.
At least quarterly, significant projects are reviewed in detail by senior management. There are many factors that impact future costs, including weather, inflation, labor and community disruptions, timely availability of materials, productivity, and other factors as outlined in Item 1(a), “Risk Factors.” These factors can affect the accuracy of our estimates and materially impact our future reported earnings. See Note 1 to the consolidated financial statements for further information.

OFF BALANCE SHEET ARRANGEMENTS

At December 31, 2014, we had no material off balance sheet arrangements, except for operating leases. For information on our contractual obligations related to operating leases, see “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.
We use a sensitivity analysis model to measure the impact of a 10% adverse movement of foreign currency exchange rates against the United States dollar. A hypothetical 10% adverse change in the value of all our foreign currency positions relative to the United States dollar as of December 31, 2014 would result in a $90 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 the interest rate swaps, a hypothetical 100 basis point increase in the LIBOR rate would result in approximately an additional $15 million of interest charges for the year ended December 31, 2014.
There are certain limitations inherent in the sensitivity analyses presented, primarily due to the assumption that interest rates and exchange 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 14 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 9 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,” “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 results of operations may vary materially.

38



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.


39



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.
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, 2014 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, 2014, our internal control over financial reporting is effective.
The effectiveness of Halliburton’s internal control over financial reporting as of December 31, 2014 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/ David J. Lesar
 
/s/ Christian A. Garcia
David J. Lesar
 
Christian A. Garcia

Chairman of the Board and
 
Senior Vice President, Finance and

Chief Executive Officer
 
Acting Chief Financial Officer


40




Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Halliburton Company:

We have audited the accompanying consolidated balance sheets of Halliburton Company and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of operations, shareholders’ equity, comprehensive income, and cash flows for each of the years in the three‑year period ended December 31, 2014. These consolidated financial statements are the responsibility of Halliburton Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Halliburton Company and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2014, 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), Halliburton Company’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 24, 2015 expressed an unqualified opinion on the effectiveness of Halliburton Company’s internal control over financial reporting.

/s/ KPMG LLP
Houston, Texas
February 24, 2015


41





Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Halliburton Company:

We have audited Halliburton Company’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Halliburton 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 Halliburton Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, 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.

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.

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.

In our opinion, Halliburton Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Halliburton Company and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of operations, shareholders’ equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2014, and our report dated February 24, 2015 expressed an unqualified opinion on those consolidated financial statements.



/s/ KPMG LLP
Houston, Texas
February 24, 2015


42



HALLIBURTON COMPANY
Consolidated Statements of Operations

 
Year Ended December 31
Millions of dollars and shares except per share data
2014
2013
2012
Revenue:
 
 
 
Services
$
25,039

$
22,257

$
22,196

Product sales
7,831

7,145

6,307

Total revenue
32,870

29,402

28,503

Operating costs and expenses:
 
 
 
Cost of services
21,060

18,959

18,447

Cost of sales
6,599

5,972

5,322

Activity related to the Macondo well incident
(195
)
1,000

300

General and administrative
309

333

275

Total operating costs and expenses
27,773

26,264

24,344

Operating income
5,097

3,138

4,159

Interest expense, net of interest income of $13, $8, and $7
(383
)
(331
)
(298
)
Other, net
(2
)
(43
)
(39
)
Income from continuing operations before income taxes
4,712

2,764

3,822

Provision for income taxes
(1,275
)
(648
)
(1,235
)
Income from continuing operations
3,437

2,116

2,587

Income from discontinued operations, net of income tax (provision) benefit of $(9), $1, and $82
64

19

58

Net income
$
3,501

$
2,135

$
2,645

Noncontrolling interest in net income of subsidiaries
(1
)
(10
)
(10
)
Net income attributable to company
$
3,500

$
2,125

$
2,635

Amounts attributable to company shareholders:
 
 
 
Income from continuing operations
$
3,436

$
2,106

$
2,577

Income from discontinued operations, net
64

19

58

Net income attributable to company
$
3,500

$
2,125

$
2,635

Basic income per share attributable to company shareholders:
 
 
 
Income from continuing operations
$
4.05

$
2.35

$
2.78

Income from discontinued operations, net
0.08

0.02

0.07

Net income per share
$
4.13

$
2.37

$
2.85

Diluted income per share attributable to company shareholders:
 
 
 
Income from continuing operations
$
4.03

$
2.33

$
2.78

Income from discontinued operations, net
0.08

0.03

0.06

Net income per share
$
4.11

$
2.36

$
2.84

 
 
 
 
Basic weighted average common shares outstanding
848

898

926

Diluted weighted average common shares outstanding
852

902

928

See notes to consolidated financial statements.
 
 
 


43



HALLIBURTON COMPANY
Consolidated Statements of Comprehensive Income

 
Year Ended December 31
Millions of dollars
2014
2013
2012
Net income
$
3,501

$
2,135

$
2,645

Other comprehensive income, net of income taxes:
 
 
 
Defined benefit and other postretirement plans adjustments
(84
)

(33
)
Other
(7
)
2

(3
)
Other comprehensive income (loss), net of income taxes
(91
)
2

(36
)
Comprehensive income
$
3,410

$
2,137

$
2,609

Comprehensive income attributable to noncontrolling interest
(1
)
(10
)
(10
)
Comprehensive income attributable to company shareholders
$
3,409

$
2,127

$
2,599

See notes to consolidated financial statements.
 
 
 



44



HALLIBURTON COMPANY
Consolidated Balance Sheets

 
December 31
Millions of dollars and shares except per share data
2014
2013
Assets
Current assets:
 
 
Cash and equivalents
$
2,291

$
2,356

Receivables (net of allowances for bad debts of $137 and $117)
7,564

6,181

Inventories
3,571

3,305

Prepaid expenses
658

737

Current deferred income taxes
421

388

Other current assets
563

737

Total current assets
15,068

13,704

Property, plant, and equipment (net of accumulated depreciation of $11,007 and $9,480)
12,475

11,322

Goodwill
2,330

2,168

Other assets
2,367

2,029

Total assets
$
32,240

$
29,223

Liabilities and Shareholders’ Equity
Current liabilities:
 
 
Accounts payable
$
2,814

$
2,365

Accrued employee compensation and benefits
1,033

1,029

Taxes other than income
407

357

Loss contingency for Macondo well incident
367

278

Deferred revenue
349

350

Other current liabilities
913

647

Total current liabilities
5,883

5,026

Long-term debt
7,840

7,816

Employee compensation and benefits
691

584

Loss contingency for Macondo well incident
439

1,022

Other liabilities
1,089

1,160

Total liabilities
15,942

15,608

Shareholders’ equity:
 
 
Common shares, par value $2.50 per share (authorized 2,000 shares,
              issued 1,071 and 1,072 shares)
2,679

2,680

Paid-in capital in excess of par value
309

415

Accumulated other comprehensive loss
(399
)
(307
)
Retained earnings
21,809

18,842

Treasury stock, at cost (223 shares)
(8,131
)
(8,049
)
Company shareholders’ equity
16,267

13,581

Noncontrolling interest in consolidated subsidiaries
31

34

Total shareholders’ equity
16,298

13,615

Total liabilities and shareholders’ equity
$
32,240

$
29,223

See notes to consolidated financial statements.
 
 


45



HALLIBURTON COMPANY
Consolidated Statements of Cash Flows

 
Year Ended December 31
Millions of dollars
2014
2013
2012
Cash flows from operating activities:
 
 
 
Net income
$
3,501

$
2,135

$
2,645

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
Depreciation, depletion, and amortization
2,126

1,900

1,628

Activity related to the Macondo well incident
(569
)
1,000

300

Deferred income tax (benefit) provision, continuing operations
(454
)
(132
)
165

Stock-based compensation cost
298

264

217

Other changes:
 
 
 
Receivables
(1,375
)
(449
)
(682
)
Accounts payable
489

327

200

Inventories
(247
)
(107
)
(611
)
Payment of Barracuda-Caratinga obligation

(219
)

Other
293

(272
)
(208
)
Total cash flows from operating activities
4,062

4,447

3,654

Cash flows from investing activities:
 
 
 
Capital expenditures
(3,283
)
(2,934
)
(3,566
)
Sales of investment securities
444

356

258

Sales of property, plant, and equipment
338

241

395

Payments to acquire businesses, net of cash acquired
(231
)
(94
)
(214
)
Purchases of investment securities
(183
)
(329
)
(506
)
Other investing activities
(223
)
(110
)
(55
)
Total cash flows from investing activities
(3,138
)
(2,870
)
(3,688
)
Cash flows from financing activities:
 
 
 
Payments to reacquire common stock
(800
)
(4,356
)

Proceeds from long-term borrowings, net of offering costs

2,968


Dividends to shareholders
(533
)
(465
)
(333
)
Proceeds from exercises of stock options
332

277

107

Other financing activities
(29
)
(178
)
54

Total cash flows from financing activities
(1,030
)
(1,754
)
(172
)
Effect of exchange rate changes on cash
41

49

(8
)
Decrease in cash and equivalents
(65
)
(128
)
(214
)
Cash and equivalents at beginning of year
2,356

2,484

2,698

Cash and equivalents at end of year
$
2,291

$
2,356

$
2,484

Supplemental disclosure of cash flow information:
 
 
 
Cash payments during the year for:
 
 
 
Interest
$
384

$
293

$
294

Income taxes
$
1,269

$
913

$
1,098

See notes to consolidated financial statements.
 
 
 


46



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, 2011
$
2,683

$
455

$
(4,547
)
$
14,880

$
(273
)
$
18

$
13,216

Comprehensive income (loss):
 

 

 

 

 

 

 
Net income



2,635


10

2,645

Other comprehensive loss




(36
)

(36
)
Cash dividends ($0.36 per share)



(333
)


(333
)
Stock plans
(1
)
25

271




295

Other

6




(3
)
3

Balance at December 31, 2012
$
2,682

$
486

$
(4,276
)
$
17,182

$
(309
)
$
25

$
15,790

Comprehensive income (loss):
 
 
 
 
 
 
 
Net income



2,125


10

2,135

Other comprehensive income




2


2

Common shares repurchased


(4,356
)



(4,356
)
Stock plans
(2
)
(97
)
583




484

Cash dividends ($0.525 per share)



(465
)


(465
)
Other

26




(1
)
25

Balance at December 31, 2013
$
2,680

$
415

$
(8,049
)
$
18,842

$
(307
)
$
34

$
13,615

Comprehensive income (loss):
 

 

 

 

 

 

 

Net income



3,500


1

3,501

Other comprehensive loss




(92
)

(92
)
Common shares repurchased


(800
)



(800
)
Stock plans
(1
)
(161
)
718




556

Cash dividends ($0.63 per share)



(533
)


(533
)
Other

55




(4
)
51

Balance at December 31, 2014
$
2,679

$
309

$
(8,131
)
$
21,809

$
(399
)
$
31

$
16,298

See notes to consolidated financial statements.
 
 
 
 


47



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 are one of the world’s largest oilfield services companies. Our two business segments are the Completion and Production segment and the Drilling and Evaluation segment. We provide a comprehensive range of services and products for the exploration, development, and production of oil and natural gas around the world.
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:
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the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements; and
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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, pensions, allowance for bad debts, and percentage-of-completion accounting for long-term contracts. 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 have 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.
Revenue recognition
Overall. 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.
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