10-K 1 hal-12312013x10k.htm DECEMBER 31, 2013 FORM 10-K HAL-12.31.2013-10K



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, 2013
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, 2013, determined using the per share closing price on the New York Stock Exchange Composite tape of $41.72 on that date, was approximately $38,003,000,000.
As of January 31, 2014, there were 850,866,860 shares of Halliburton Company Common Stock, $2.50 par value per share, outstanding.
Portions of the Halliburton Company Proxy Statement for our 2014 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, 2013
 
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

i



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 energy industry related to the exploration, development, and production of oil and natural gas. 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 services. The segment consists of Production Enhancement, Cementing, Completion Tools, Halliburton Boots & Coots, Multi-Chem, and Halliburton 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 2 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, Malaysia, Singapore, and the United Kingdom.
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;
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reach a distinguished level of operational excellence that reduces costs and creates real value;
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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 2013, 2012, and 2011, based on the location of services provided and products sold, 49%, 53%, and 55% 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 2 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 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.

1



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 13 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 $588 million in 2013, $460 million in 2012, and $401 million in 2011. 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 patents owned by others. 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, 2013, we employed approximately 77,000 people worldwide compared to approximately 73,000 at December 31, 2012. At December 31, 2013, approximately 15% 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 8 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 through the rock formation to enable natural gas or oil to move more easily through the rock pores to a production well. 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.
We generally design and implement a hydraulic fracturing operation to “stimulate” the well, 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 any 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 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 the surface.

2



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 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 to control the growth of bacteria in hydraulic fracturing fluids that uses ultraviolet light, 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 2013, 2012, or 2011. Except to the extent expressly stated otherwise, information contained on or accessible from our web site or any other web site is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report.

Executive Officers of the Registrant

The following table indicates the names and ages of the executive officers of Halliburton Company as of February 7, 2014, 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 59)
President, Western Hemisphere of Halliburton Company, since January 2008
 
 
 

3



 
Name and Age
Offices Held and Term of Office
 
Christian A. Garcia
(Age 50)
Senior Vice President and Chief Accounting Officer of Halliburton Company, since January 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
 
 
 
 
Myrtle L. Jones
(Age 54)
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 60)
Chairman of the Board, President, and Chief Executive Officer of Halliburton Company, since August 2000
 
 
 
*
Mark A. McCollum
(Age 54)
Executive Vice President and Chief Financial Officer of Halliburton Company, since January 2008
 
 
 
 
Timothy M. McKeon
(Age 41)
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
 
 
Senior Manager, Corporate Finance of Halliburton Company, August 2006 to February 2009
 
 
 
*
Jeffrey A. Miller
(Age 50)
Executive Vice President and Chief Operating Officer of Halliburton Company, since September 2012
 
 
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
 
 
Vice President, Baroid, May 2006 to December 2009
 
 
 
*
Lawrence J. Pope
(Age 45)
Executive Vice President of Administration and Chief Human Resources Officer of Halliburton Company, since January 2008
 
 
 
 
Joe D. Rainey
(Age 57)
President, Eastern Hemisphere of Halliburton Company, since January 2011
 
 
Senior Vice President, Eastern Hemisphere of Halliburton Company, January 2010 to December 2010
 
 
Vice President, Eurasia Pacific Region of Halliburton Company, January 2009 to December 2009
 
 
 
*
Robb L. Voyles (Age 56)
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.

4



Item 1(a). Risk Factors.

The statements in this section describe the known material risks to our business and should be considered carefully.

We, among others, have been named as a defendant in numerous lawsuits and there have been numerous investigations relating to the Macondo well incident that 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 (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.
We are named along with other unaffiliated defendants in more than 1,800 complaints, most of which are alleged class-actions, involving pollution damage claims and at least eight personal injury lawsuits involving four decedents and at least 10 allegedly injured persons who were on the drilling rig at the time of the incident. At least six additional lawsuits naming us and others relate to alleged personal injuries sustained by those responding to the explosion and oil spill. Other defendants in the lawsuits have filed claims against us seeking subrogation, indemnification, including with respect to liabilities under the Oil Pollution Act of 1990 (OPA), contribution and direct damages, and alleging negligence, gross negligence, fraudulent conduct, willful misconduct, and fraudulent concealment. See Note 8 to the consolidated financial statements. Additional lawsuits may be filed against us, including civil actions under federal statutes and regulations, as well as criminal and civil actions under state statutes and regulations. Those statutes and regulations could result in criminal penalties, including fines and imprisonment, as well as civil fines, and the degree of the penalties and fines may depend on the type of conduct and level of culpability, including strict liability, negligence, gross negligence, and knowing violations of the statute or regulation.
In addition to the claims and lawsuits described above, several regulatory agencies and others have investigated or are investigating the cause of the explosion, fire, and resulting oil spill. Reports issued as a result of those investigations have been critical of BP, Transocean, and us, among others. For example, one or more of those reports have concluded that primary cement failure was a direct cause of the blowout, cement testing performed by an independent laboratory “strongly suggests” that the foam cement slurry used on the Macondo well was unstable, and that numerous other oversights and factors caused or contributed to the cause of the incident, including BP's failure to run a cement bond log, BP's and Transocean's failure to properly conduct and interpret a negative-pressure test, the failure of the drilling crew and our surface data logging specialist to recognize that an unplanned influx of oil, natural gas, or fluid into the well was occurring, communication failures among BP, Transocean, and us, and flawed decisions relating to the design, construction, and testing of barriers critical to the temporary abandonment of the well.
In October 2011, the Bureau of Safety and Environmental Enforcement (BSEE) issued a notification of Incidents of Noncompliance (INCs) to us for allegedly violating federal regulations relating to the failure to take measures to prevent the unauthorized release of hydrocarbons, the failure to take precautions to keep the Macondo well under control, the failure to cement the well in a manner that would, among other things, prevent the release of fluids into the Gulf of Mexico, and the failure to protect health, safety, property, and the environment as a result of a failure to perform operations in a safe and workmanlike manner. According to the BSEE's notice, we did not ensure an adequate barrier to hydrocarbon flow after cementing the production casing and did not detect the influx of hydrocarbons until they were above the blowout preventer stack. We understand that the regulations in effect at the time of the alleged violations provide for fines of up to $35,000 per day per violation. We have appealed the INCs to the Interior Board of Land Appeals (IBLA). In January 2012, the IBLA, in response to our and the BSEE's joint request, suspended the appeal pending certain proceedings in the multi-district litigation (MDL) trial. Once the MDL court issues a final decision in the trial, we expect to file a proposal for further action in the appeal. The BSEE has announced that the INCs will be reviewed for possible imposition of civil penalties once the appeal has ended. The BSEE has stated that this is the first time the Department of the Interior has issued INCs directly to a contractor that was not the well's operator.


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Our contract with BP Exploration relating to the Macondo well generally provides for our indemnification by BP Exploration for certain potential claims and expenses relating to the Macondo well incident. BP Exploration, in connection with filing its claims with respect to the MDL proceeding, asked the court to declare that it is not liable to us in contribution, indemnification, or otherwise with respect to liabilities arising from the Macondo well incident. Other defendants in the litigation have generally denied any obligation to contribute to any liabilities arising from the Macondo well incident. In January 2012, the court in the MDL proceeding entered an order in response to our and BP's motions for summary judgment regarding certain indemnification matters. The court held 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, even if we are found to be grossly negligent. The court also held that BP does not owe us indemnity for punitive damages or for civil penalties under the Clean Water Act (CWA), if any, and that fraud could void the indemnity on public policy grounds. The court in the MDL proceeding deferred ruling on whether our indemnification from BP covers penalties or fines under the Outer Continental Shelf Lands Act, whether our alleged breach of our contract with BP Exploration would invalidate the indemnity, and whether we committed an act that materially increased the risk to or prejudiced the rights of BP so as to invalidate the indemnity.
The rulings in the MDL proceeding regarding the indemnities are based on maritime law and may not bind the determination of similar issues in lawsuits not comprising a part of the MDL proceeding. Accordingly, it is possible that different conclusions with respect to indemnities will be reached by other courts.
Indemnification for criminal fines or penalties, if any, may not be available if a court were to find such indemnification unenforceable as against public policy. In addition, certain state laws, if deemed to apply, would not allow for enforcement of indemnification for gross negligence, and may not allow for enforcement of indemnification of persons who are found to be negligent with respect to personal injury claims. We may not be insured with respect to civil or criminal fines or penalties, if any, pursuant to the terms of our insurance policies.
BP's public filings indicate that BP has recognized in excess of $40 billion in pre-tax charges, excluding offsets for settlement payments received from certain defendants in the MDL, as a result of the Macondo well incident. BP's public filings also indicate that the amount of, among other things, certain natural resource damages with respect to certain OPA claims, some of which may be included in such charges, cannot be reliably estimated as of the dates of those filings.
We are currently unable to fully estimate the impact the Macondo well incident will have on us. We cannot predict the outcome of the many lawsuits and investigations relating to the Macondo well incident, including orders and rulings of the court that impact the MDL, the results of the MDL trial, the effect that the settlements between BP and the Plaintiffs’ Steering Committee (PSC) in the MDL and other settlements may have on claims against us, or whether we might settle with one or more of the parties to any lawsuit or investigation. The first two phases of the MDL trial have concluded, and the MDL court could begin issuing rulings at any time. A determination that the performance of our services on the Deepwater Horizon constituted gross negligence could result in substantial liability to the numerous plaintiffs for punitive damages and potentially to BP with respect to its direct claims against us.
As of December 31, 2013, our loss contingency reserve for the Macondo well incident, relating to the MDL, remained at $1.3 billion, which represents a loss contingency that is probable and for which a reasonable estimate of loss can be made. We have participated in intermittent discussions with the PSC regarding the potential for a settlement that would resolve a substantial portion of the claims pending in the MDL trial. BP, however, has not participated in any recent settlement discussions with us.
Reaching a settlement involves a complex process, and there can be no assurance as to whether or when we may complete a settlement. In addition, the settlement discussions we have had to date do not cover all parties and claims relating to the Macondo well incident. Accordingly, there are additional loss contingencies relating to the Macondo well incident that are reasonably possible but for which we cannot make a reasonable estimate. Given the numerous potential developments relating to the MDL and other lawsuits and investigations, which could occur at any time, we may adjust our estimated loss contingency reserve in the future. 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.



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Certain matters relating to the Macondo well incident, including increased regulation of the United States offshore drilling industry, and similar catastrophic events could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.
The Macondo well incident and the subsequent oil spill resulted in offshore drilling delays, temporary drilling bans, and increased federal regulation of our and our customers' operations, and more regulations and delays are possible. For example, the BSEE has:
-
issued regulations that provide revised casing and cementing requirements, including integrity testing standards, that mandate independent third-party verifications, that impose blowout preventer capability, testing, and documentation obligations, and that outline standards for specific well control training for deepwater operations, among other requirements;
-
issued revised regulations in 2013 to require, among other things, increased employee involvement in certain safety measures and third-party audits of operators’ safety and environmental management systems;
-
proposed stricter requirements for subsea drilling production equipment;
-
stated that it intends to propose new standards for the design and maintenance of blowout preventers; and
-
stated that it, together with the Bureau of Ocean Energy Management, is drafting new standards governing drilling in the Arctic. 
In addition, the BSEE contends that it has the legal authority to extend its regulatory reach to include contractors, like us, in addition to operators, as evidenced by the INCs.
The increased regulation of the exploration and production industry as a whole that arises out of the Macondo well incident has and could continue to result in higher operating costs for us and our customers, extended permitting and drilling delays, and reduced demand for our services. We cannot predict to what extent increased regulation may be adopted in international or other jurisdictions or whether we and our customers will be required or may elect to implement responsive policies and procedures in jurisdictions where they may not be required.
In addition, the Macondo well incident negatively impacted and could continue to negatively impact the availability and cost of insurance coverage for us, our customers, and our and their service providers. Also, our relationships with BP and others involved in the Macondo well incident could be negatively affected. Our business may be adversely impacted by any negative publicity relating to the incident, any negative perceptions about us by our customers, any increases in insurance premiums or difficulty in obtaining coverage, and the diversion of management's attention from our operations to focus on matters relating to the incident.
As illustrated by the Macondo well incident, the services we provide for our customers are performed in challenging environments that can be dangerous. Catastrophic events such as a well blowout, fire, or explosion can occur, resulting in property damage, personal injury, death, pollution, and environmental damage. While we have agreements with certain customers that require them to indemnify us for these types of events and the resulting damages and injuries (except in some cases, claims by our employees, loss or damage to our property, and any pollution emanating directly from our equipment), we will be exposed to significant potential losses should such catastrophic events occur if adequate indemnification provisions or insurance arrangements are not in place, if indemnity or related release from liability provisions are determined by a court to be unenforceable or otherwise invalid, in whole or in part, or if our customers are unable or unwilling to satisfy any indemnity obligations.
The matters discussed above relating to the Macondo well incident and similar catastrophic events could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.



7



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:
-
political and economic instability, including:    
civil unrest, acts of terrorism, force majeure, war, or other armed conflict;
inflation; and
currency fluctuations, devaluations, and conversion restrictions; and
-
governmental actions that may:    
result in expropriation and nationalization of our assets in that country;
result in confiscatory taxation or other adverse tax policies;
limit or disrupt markets, 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, Argentina, 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 also 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 or damage of intellectual property, proprietary information, or customer data, having our business operations interrupted, and increased costs to prevent, respond to, or mitigate cybersecurity attacks. These risks could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition.

Our operations outside the United States require us to comply with a number of United States and international regulations, violations of which could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition.
Our operations outside the United States require us to comply with a number of United States and international regulations. For example, our operations in countries outside the United States are subject to the United States Foreign Corrupt Practices Act (FCPA), which prohibits United States companies and their agents and employees from providing anything of value to a foreign official for the purposes of influencing any act or decision of these individuals in their official capacity to help obtain or retain business, direct business to any person or corporate entity, or obtain any unfair advantage. Our activities create the risk of unauthorized payments or offers of payments by our employees, agents, or joint venture partners that could be in violation of the FCPA, 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, including the FCPA, may result in internal, independent, or government investigations. Violations of the FCPA 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, 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.


8



Changes in, compliance with, or our failure to comply with laws in the countries in which we conduct business may negatively impact our ability to provide services in, make sales of equipment to, and transfer personnel or equipment among some of those countries and could have a material adverse effect on our business and consolidated results of operations.
In the countries in which we conduct business, we are subject to multiple and, at times, inconsistent regulatory regimes, including those that govern our use of radioactive materials, explosives, and chemicals in the course of our operations. Various national and international regulatory regimes govern the shipment of these items. Many countries, but not all, impose special controls upon the export and import of radioactive materials, explosives, and chemicals. Our ability to do business is subject to maintaining required licenses and complying with these multiple regulatory requirements applicable to these special products. In addition, the various laws governing import and export of both products and technology apply to a wide range of services and products we offer. In turn, this can affect our employment practices of hiring people of different nationalities because these laws may prohibit or limit access to some products or technology by employees of various nationalities. Changes in, compliance with, or our failure to comply with these laws may negatively impact our ability to provide services in, make sales of equipment to, and transfer personnel or equipment among some of the countries in which we operate and could have a material adverse effect on our business and consolidated results of operations.

The adoption of any future federal, state, or local laws or implementing regulations imposing reporting obligations on, or limiting or banning, the hydraulic fracturing process could make it more difficult to complete natural gas and oil wells and could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.
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. 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.

9




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:
-
the containment and disposal of hazardous substances, oilfield waste, and other waste materials;
-
the importation and use of radioactive materials;
-
the use of underground storage tanks; and
-
the use of underground injection wells.
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:
-
administrative, civil, and criminal penalties;
-
revocation of permits to conduct business; and
-
corrective action orders, including orders to investigate and/or clean up contamination.
Failure on our part to comply with applicable environmental requirements 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.

10



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. 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. 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:
-
the level of supply and demand for oil and natural gas, especially demand for natural gas in the United States;
-
governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves;
-
weather conditions and natural disasters;
-
worldwide political, military, and economic conditions;
-
the level of oil production by non-OPEC countries and the available excess production capacity within OPEC;
-
oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;
-
the cost of producing and delivering oil and natural gas; and
-
potential acceleration of the development of alternative fuels.

Our business is dependent on capital spending by our customers, and reductions in capital spending could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition.
Our business is directly affected by changes in capital expenditures by our customers, and reductions in their capital spending could reduce demand for our services and products and have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition. Some of the items that may impact our customer's capital spending include:
-
oil and natural gas prices, including volatility of oil and natural gas prices and expectations regarding future prices;
-
the inability of our customers to access capital on economically advantageous terms;
-
the consolidation of our customers;
-
customer personnel changes; and
-
adverse developments in the business or operations of our customers, including write-downs of reserves and borrowing base reductions under customer credit facilities.

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

Changes in or interpretation of tax law and currency/repatriation control could impact the determination of our income tax liabilities for a tax year.
We have operations in approximately 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.


11



We are subject to foreign exchange risks and limitations on our ability to reinvest earnings from operations in one country to fund the capital needs of our operations in other countries or to repatriate assets from some countries.
A sizable portion of our consolidated revenue and consolidated operating expenses is in foreign currencies. As a result, we are subject to significant risks, including:
-
foreign currency exchange risks resulting from changes in foreign currency exchange rates and the implementation of exchange controls; and
-
limitations on our ability to reinvest earnings from operations in one country to fund the capital needs of our operations in other countries.
As an example, we conduct business in countries, 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 9 to the Consolidated Financial Statements, "Income Taxes."

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 and delays in receiving payments, 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. We also continue to see a delay in receiving payment on our receivables from our primary customer in Venezuela. If our customer further delays paying or fails 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.

12



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


13



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.

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.


14



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 segment:
Arbroath, United Kingdom
 
Johor, Malaysia
 
Lafayette, Louisiana
 
Singapore, Singapore
 
Stavanger, Norway
 
Tianjin, China
 
 
Drilling and Evaluation segment:
Alvarado, Texas
 
Nisku, Canada
 
Singapore, Singapore
 
The Woodlands, Texas
 
 
Shared/corporate facilities:
Al-Khobar, Saudi Arabia
 
Carrollton, Texas
 
Denver, Colorado
 
Dubai, United Arab Emirates
 
Duncan, Oklahoma
 
Houston, Texas
 
Kuala Lumpur, Malaysia
 
Panama City, Panama
 
Pune, India
 
Rio de Janeiro, Brazil
 
San Antonio, Texas

In addition, we have 179 international and 124 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.

15



Item 3. Legal Proceedings.
Information related to Item 3. Legal Proceedings is included in Note 8 to the consolidated financial statements on page 55 of this annual report.

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.

16



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 74 of this annual report. Quarterly cash dividends on our common stock, which were paid in March, June, September, and December of each year, were $0.09 per share throughout 2012, $0.125 per share for the first three quarters of 2013, and $0.15 per share in the fourth quarter of 2013. 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, 2013, 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, 2008, and the reinvestment of all dividends. The shareholder return set forth is not necessarily indicative of future performance.
 
December 31
 
2008
2009
2010
2011
2012
2013
Halliburton
$
100.00

$
168.12

$
230.75

$
196.85

$
200.13

$
296.19

Philadelphia Oil Service Index (OSX)
100.00

162.15

205.80

184.09

189.86

249.32

Standard & Poor’s 500 ® Index
100.00

126.46

145.51

148.59

172.37

228.19



17



At January 31, 2014, there were 14,454 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, 2013.
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
73,993
$49.96
$1,693,971,527
November 1 - 30
80,870
$53.43
$1,693,971,527
December 1 - 31
140,739
$50.41
$1,693,971,527
Total
295,602
$51.12
 
(a)
All of the 295,602 shares purchased during the three-month period ended December 31, 2013 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 2013, 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 $1.7 billion of our common stock.


Item 6. Selected Financial Data.
Information related to selected financial data is included on page 73 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 20 through 38 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 37 of this annual report and Note 13 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, 2013, 2012, and 2011
Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012, and 2011
Consolidated Balance Sheets at December 31, 2013 and 2012
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012, and 2011
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2013, 2012, and 2011
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.


18



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, 2013 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, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
See page 39 for Management’s Report on Internal Control Over Financial Reporting and page 40 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.

Item 9(b). Other Information.
None.


19



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

EXECUTIVE OVERVIEW

Financial results
During 2013, we produced revenue of $29.4 billion and operating income of $3.1 billion, reflecting an operating margin of 11%. Revenue increased $0.9 billion, or 3%, from 2012, mainly due to increased activity in all of our international regions and the Gulf of Mexico. We set new revenue records this year in all of our international regions and in both of our divisions. Additionally, during 2013, our revenue outside of North America comprised 48% of consolidated revenue. The percentage of our revenue that relates to our international operations has been steadily increasing and is representative of our ongoing strategy to grow our international business and balance our geographic mix. Our increase in international activity and revenue was partially offset by lower activity levels and pricing pressure in the United States land market, primarily for production enhancement services. Operating income in 2013 was negatively impacted by a $1.0 billion, pre-tax, Macondo-related loss contingency, as compared to a $300 million, pre-tax, Macondo-related loss contingency in 2012.
Business outlook
We continue to believe in the strength of the long-term fundamentals of our business. Energy demand is expected to increase over the long term driven by economic growth in developing countries despite current underlying downside risks in the industry, such as sluggish growth in developed countries and uncertainties associated with geopolitical tensions in the
Middle East and North Africa. Furthermore, development of new resources is expected to be more complex, resulting in
higher service intensity as our customers move increasingly to horizontal drilling.
In North America, we continue to experience pricing pressures, which have impacted our margins. However, we believe the current environment and our focus on efficient cost structure continues to favor us. As a result of the industry's activity shift from natural gas plays to oil and liquids-rich basins, operators have been allocating their budgets to basins with better economics. In addition, we are observing a meaningful switch to multi-well pad activity among our customer base, which is resulting in increased drilling and completion service efficiency. We believe the incremental efficiency gains provided by multi-well pad drilling will enable us to leverage our operational scale and expertise.
Outside of North America, both revenue and operating income increased in 2013 compared to 2012. We believe that international growth in 2014 will come from volume increases as we deploy resources on our recent contract wins and new projects, continued improvement in markets where we have made strategic investments, the introduction of new technology, and increased pricing and cost recovery on select contracts. We also 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 capitalize on 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. In Latin America, we expect 2014 to be a challenging year due to a decline in existing integrated project management work in Mexico as we begin transitioning to newly-tendered projects, and due to reduced activity in Brazil. However, this does not change our long-term outlook for Latin America, which we expect to contribute significantly to our future growth and profitability.

20



We continued to execute several key initiatives in 2013. These initiatives included increasing manufacturing capacity in the Eastern Hemisphere and repositioning our service delivery platform to lower our delivery costs. We plan to continue to invest in these initiatives in 2014. In addition, we plan to continue executing the following strategies:
-
focusing on unconventional plays, mature fields, and deepwater markets by leveraging our broad technology offerings to provide value to our customers through integrated solutions and the ability to more efficiently drill and complete their wells;
-
exploring 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 large operations;
-
making key investments in technology and infrastructure to maximize growth opportunities. To that end, we are continuing to push our technology and manufacturing capacity, as well as our supply chain, closer to our customers in the Eastern Hemisphere;
-
improving working capital, and managing our balance sheet to maximize our financial flexibility. We are deploying a global project to improve service delivery that we expect to result in, among other things, additional investments in our systems and significant improvements to our current order-to-cash and purchase-to-pay processes;
-
growing our international revenues and margins by continuing to invest capital and resources in these markets;
-
improving our North America margins by leveraging technologies and reducing costs through more efficient operations;
-
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; and
-
expanding our business with national oil companies.
Our operating performance and business outlook are described in more detail in “Business Environment and Results of Operations.”
Financial markets, liquidity, and capital resources
We believe we have invested our cash balances conservatively and secured sufficient financing to help mitigate any near-term negative impact on our operations from adverse market conditions. For additional information, see “Liquidity and Capital Resources” and “Business Environment and Results of Operations.”


21



LIQUIDITY AND CAPITAL RESOURCES

We ended 2013 with cash and equivalents of $2.4 billion compared to $2.5 billion at December 31, 2012. Additionally, at December 31, 2013, we held $373 million of investments in fixed income securities compared to $398 million at December 31, 2012, These securities are reflected in "Other current assets" and "Other assets" in our consolidated balance sheets. As of December 31, 2013, approximately $306 million of the $2.4 billion of cash and equivalents was held by our foreign subsidiaries, and 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 $4.4 billion in 2013.
In the third quarter of 2013, we issued $3.0 billion aggregate principal amount of senior notes and used the net proceeds, along with cash on hand, to fund the repurchase of approximately 68 million shares of our common stock at an aggregate cost of $3.3 billion pursuant to a modified Dutch auction cash tender offer. During 2013, we repurchased approximately 93 million shares of our common stock under our share repurchase program at a total cost of approximately $4.4 billion.
Capital expenditures were $2.9 billion in 2013. The capital expenditures in 2013 were predominantly made in our Production Enhancement, Sperry Drilling, Boots and Coots, Wireline and Perforating, and Cementing product service lines. We have also invested additional working capital to support the growth of our business.
We paid $465 million of dividends to our shareholders in 2013. We increased our quarterly dividend rate by $0.035 per share in the first quarter of 2013 and an additional $0.025 per share in the fourth quarter of 2013. Our current quarterly dividend rate is $0.15 per share, or approximately $129 million per quarter, which represents a 67% increase over the quarterly dividend rate during 2012.
During 2013, we sold $241 million of property, plant, and equipment.
Our primary components of net working capital (receivables, inventories and accounts payable) increased during the year by a net $229 million, primarily due to increased business activity.
In the first quarter of 2013, we made a $219 million payment under a guarantee we issued for the Barracuda-Caratinga project.
In the second quarter of 2013, we made a $172 million earn-out payment related to a prior year acquisition due to significantly better than expected operating performance.
Future sources and uses of cash
Capital spending for 2014 is currently expected to be approximately $3.0 billion. The capital expenditures plan for 2014 is primarily directed towards our Production Enhancement, Sperry Drilling, Cementing, Boots & Coots, and Wireline and Perforating product service lines, with an increasing amount dedicated to our international operations.
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. We have approximately $1.7 billion remaining available under our share repurchase authorization, which may be used for open market and other share repurchases.
During 2013, the Congressional Joint Committee on Taxation approved a $135 million income tax refund, excluding interest, to us for agreed upon tax items for the tax years 2003 through 2009. We expect to receive the refund in 2014.
In the third quarter of 2013, we were awarded $105 million by an arbitrator regarding amounts owed by KBR, Inc. (KBR) related to our Tax Sharing Agreement with KBR. KBR is contesting the award and, although the arbitrator recently issued a supplemental report that reaffirmed the original award, there is uncertainty as to the ultimate timing and amount of any payment. See Note 7 to the consolidated financial statements for further information.
We are continuing to explore 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.
We had $209 million of gross unrecognized tax benefits at December 31, 2013, of which we estimate $146 million may require a cash payment. We estimate that $141 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 any amounts will ultimately be settled and paid.

22



Contractual obligations
The following table summarizes our significant contractual obligations and other long-term liabilities as of December 31, 2013:
 
Payments Due
 
 
Millions of dollars
2014
2015
2016
2017
2018
Thereafter
Total
Long-term debt
$

$

$
600

$
45

$
800

$
6,389

$
7,834

Interest on debt (a)
362

365

376

385

398

6,422

8,308

Operating leases
282

215

156

83

56

154

946

Purchase obligations (b)
2,382

450

315

225

76

96

3,544

Other long-term liabilities (c)
39

3

3

3

2

4

54

Total
$
3,065

$
1,033

$
1,450

$
741

$
1,332

$
13,065

$
20,686

(a)
Interest on debt includes 83 years of interest on $300 million of debentures at 7.6% interest that become due in 2096.
(b)
Amount in 2014 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 2014 as we are currently not able to reasonably estimate our contributions for years after 2014.

Other factors affecting liquidity
Financial position in current market. As of December 31, 2013, we had $2.4 billion of cash and equivalents, $373 million in fixed income investments, and a total of $3.0 billion of available committed bank credit under our revolving credit facility. Reflecting the growth of our company, we executed an amendment to our revolving credit facility during 2013, which increased the capacity from $2.0 billion to $3.0 billion and extended the maturity to 2018. 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, in 2014 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 8 to the consolidated financial statements, there are numerous 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 $2.1 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of December 31, 2013. 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.
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.



23



BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS

We operate in approximately 80 countries throughout the world to provide a comprehensive range of discrete and integrated services and products to the energy industry. A significant amount of our consolidated revenue is derived from the sale of services and products to major, national, and independent oil and natural gas companies worldwide. We serve 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. Our two business segments are the Completion and Production segment and the Drilling and Evaluation segment. The industry we serve is highly competitive with many substantial competitors in each segment. In 2013, 2012, and 2011, based on the location of services provided and products sold, 49%, 53%, and 55% 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, 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 levels within our business segments are 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, 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:
 
2013
2012
2011
Oil price - WTI (1)
$
97.99

$
94.15

$
95.13

Oil price - Brent (1)
108.71

111.60

111.53

Natural gas price - Henry Hub (2)
3.73

2.81

4.09

 
 
 
 
(1) Oil price measured in dollars per barrel
(2) Natural gas price measured in dollars per thousand cubic feet, or Mcf


24



The historical yearly average rig counts based on the Baker Hughes Incorporated rig count information were as follows:
Land vs. Offshore
2013
2012
2011
United States:
 
 
 
Land
1,705

1,872

1,843

Offshore (incl. Gulf of Mexico)
56

47

32

Total
1,761

1,919

1,875

Canada:
 

 

 

Land
352

363

422

Offshore
2

1

1

Total
354

364

423

International (excluding Canada):
 
 
 
Land
978

931

863

Offshore
318

303

304

Total
1,296

1,234

1,167

Worldwide total
3,411

3,517

3,465

Land total
3,035

3,166

3,128

Offshore total
376

351

337

 
 
 
 
Oil vs. Natural Gas
2013
2012
2011
United States (incl. Gulf of Mexico):
 
 
 
Oil
1,375

1,359

984

Natural gas
386

560

891

Total
1,761

1,919

1,875

Canada:
 
 
 
Oil
234

261

282

Natural gas
120

103

141

Total
354

364

423

International (excluding Canada):
 
 
 
Oil
1,029

984

918

Natural gas
267

250

249

Total
1,296

1,234

1,167

Worldwide total
3,411

3,517

3,465

Oil total
2,638

2,604

2,184

Natural gas total
773

913

1,281


Drilling Type
2013
2012
2011
United States (incl. Gulf of Mexico):
 
 
 
Horizontal
1,102
1,151
1,074
Vertical
435
552
571
Directional
224
216
230
Total
1,761
1,919
1,875

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.


25



WTI oil prices, which generally influence customer spending in North America, fluctuated throughout 2013, ranging from a high of $111 per barrel in September to a low of $87 per barrel in April. Outside of North America, customer spending is heavily influenced by Brent oil prices, which fluctuated during 2013 from a high of $119 per barrel in February to a low of $97 per barrel in April. Oil prices were affected by production disruptions in Libya, Nigeria, and Iraq, offset by growing output by certain OPEC members. Global oil demand growth appears to have gradually gained momentum in the past 18 months and the International Energy Agency’s January 2014 “Oil Market Report” forecasts a 1% increase in global petroleum demand from 2013 levels. This is driven by economic recovery in the developed world and an increase in all regions except for Europe, which is forecasted to remain flat.
Henry Hub natural gas prices in the United States have increased approximately 33% from 2012 as a result of an increase in storage withdrawals due to cooler temperatures in the early part and December of 2013. This, coupled with higher natural gas demand for industrial purposes, resulted in higher natural gas prices. Natural gas prices during 2013 ranged from a low of $3.08 per Mcf in January to a high of $4.52 per Mcf in December. The United States Energy Information Administration (EIA) January 2014 “Short Term Energy Outlook” forecast projects Henry Hub natural gas prices to average $3.89 per Mcf in 2014 compared to $3.73 per Mcf in 2013. Over the long term, the EIA expects natural gas consumption in the power sector to increase to offset the retirement of coal power plants.
There has been an increase in natural gas prices over the past year and the global economy continues to recover. 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 2013, the average natural gas-directed rig count in North America fell by 157 rigs, or 24%, from 2012 levels. The curtailment of natural gas drilling activity along with an influx of stimulation equipment into the industry has resulted in overcapacity and pricing pressure for hydraulic fracturing and other services. Despite the decreased rig count in the United States as compared to 2012, drilling efficiencies and the trend toward multi-well pads are driving a more robust well count. Additionally, operators have been, in some cases, increasing the numbers of hydraulic fracturing stages on horizontal wells.
We expect United States land rig count to modestly increase from 2013 levels, driven primarily by the continued shift to horizontal rigs in the Permian Basin. We are seeing higher well efficiencies due to increased pad drilling, more 24-hour operations, rig fleet upgrades, and significant advancements in drilling and completion technologies. In 2013, we saw average drilling days per horizontal well drop approximately 14% compared to 2012 and we anticipate continued efficiency improvements in 2014. We believe this continued shift towards efficiency will bode well for us in the coming years. In the long run, we believe the shift to unconventional oil and liquids-rich basins in North America 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, improvements in the performance of many of our product service lines was due to a 19% increase in the offshore rig count from 2012, in addition to the efficiencies and integrated solutions we offer that save our customers time and enhance productivity. Over the long term, the continued 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 industry experienced steady volume increases during 2013, with the average international rig count improving 5% over 2012 levels. These volume increases have led to an absorption of equipment supply and we are seeing sporadic opportunities for price improvements in select geographies. We anticipate moderate margin improvements and gradual activity increases in the Eastern Hemisphere, although the operator spending outlook could be impacted by ongoing macroeconomic concerns. We believe 2014 will be a challenging year for Latin America, primarily in Brazil and Mexico. Over the long term, however, we expect both of these countries to be strong contributors to our growth and profitability.
We believe that international growth in 2014 will come from volume increases as we deploy resources on our recent contract and project wins, continued improvement in certain markets where we have made strategic investments, introduction of new technology, and increased pricing and cost recovery on select contracts. We also 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, 2013, our total net investment in Venezuela was approximately $411 million, including net monetary assets of $124 million denominated in Bolívares. Also, at December 31, 2013 we had $192 million of surety bond guarantees outstanding relating to our Venezuelan operations.

26



We continue to experience delays in collecting payment on our receivables from our primary customer in Venezuela. 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 $486 million, or approximately 8% of our gross trade receivables, as of December 31, 2013, compared to $491 million, or approximately 9% of our gross trade receivables, as of December 31, 2012. Of the $486 million of 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. Of the $491 million receivables in Venezuela as of December 31, 2012, $143 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. The net foreign currency impact of Bolívar activity in the first quarter of 2013 was not material, although further devaluation of the Bolívar could impact our operations. For additional information, see Part I, Item 1(a), “Risk Factors” in this Form 10-K.



27



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



28



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.
Following is a discussion of our results of operations by reportable segment.
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 tools 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.

29



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 tools 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.



30



RESULTS OF OPERATIONS IN 2012 COMPARED TO 2011

REVENUE:
 
 
Favorable
Percentage
Millions of dollars
2012
2011
(Unfavorable)
Change
Completion and Production
$
17,380

$
15,143

$
2,237

15
%
Drilling and Evaluation
11,123

9,686

1,437

15

Total revenue
$
28,503

$
24,829

$
3,674

15
%

 
 
 
 
By geographic region:
 
 
 
 
Completion and Production:
 
 
 
 
North America
$
12,157

$
10,907

$
1,250

11
%
Latin America
1,415

1,117

298

27

Europe/Africa/CIS
2,099

1,746

353

20

Middle East/Asia
1,709

1,373

336

24

Total
17,380

15,143

2,237

15

Drilling and Evaluation:
 
 
 
 
North America
3,847

3,506

341

10

Latin America
2,279

1,865

414

22

Europe/Africa/CIS
2,411

2,210

201

9

Middle East/Asia
2,586

2,105

481

23

Total
11,123

9,686

1,437

15

Total revenue by region:
 
 
 
 
North America
16,004

14,413

1,591

11

Latin America
3,694

2,982

712

24

Europe/Africa/CIS
4,510

3,956

554

14

Middle East/Asia
4,295

3,478

817

23



31



OPERATING INCOME:
 
 
Favorable
Percentage
Millions of dollars
2012
2011
(Unfavorable)
Change
Completion and Production
$
3,144

$
3,733

$
(589
)
(16
)%
Drilling and Evaluation
1,675

1,403

272

19

Corporate and other
(660
)
(399
)
(261
)
65

Total operating income
$
4,159

$
4,737

$
(578
)
(12
)%

 
 
 
 
By geographic region:
 
 
 
 
Completion and Production:
 
 
 
 
North America
$
2,260

$
3,341

$
(1,081
)
(32
)%
Latin America
206

159

47

30

Europe/Africa/CIS
347

48

299

623

Middle East/Asia
331

185

146

79

Total
3,144

3,733

(589
)
(16
)
Drilling and Evaluation:
 
 
 
 
North America
680

641

39

6

Latin America
393

305

88

29

Europe/Africa/CIS
246

191

55

29

Middle East/Asia
356

266

90

34

Total
1,675

1,403

272

19

Total operating income by region
 
 
 
 
(excluding Corporate and other):
 
 
 
 
North America
2,940

3,982

(1,042
)
(26
)
Latin America
599

464

135

29

Europe/Africa/CIS
593

239

354

148

Middle East/Asia
687

451

236

52


The 15% increase in consolidated revenue in 2012 compared to 2011 was primarily due to higher activity in Latin America, Middle East/Asia, and North America. On a consolidated basis, all product service lines experienced revenue growth from 2011. Revenue outside of North America was 44% of consolidated revenue in 2012 and 42% of consolidated revenue in 2011.
The 12% decrease in consolidated operating income compared to 2011 was mainly due to higher costs, particularly of guar gum, and pricing pressure for production enhancement services in North America. Operating income in 2012 was negatively impacted by a $300 million, pre-tax, loss contingency related to the Macondo well incident reflected in Corporate and other expenses. Additionally, our results were impacted by a $48 million, pre-tax, charge related to an earn-out adjustment due to significantly better than expected performance of a past acquisition in the Latin America and North America regions as well as a $20 million, pre-tax, gain related to the settlement of a patent infringement lawsuit that was recorded in Corporate and other expense. Operating income in 2011 was adversely impacted by a $25 million, pre-tax, impairment charge on an asset held for sale in the Europe/Africa/CIS region, $11 million, pre-tax, of employee separation costs in the Eastern Hemisphere, and a $59 million, pre-tax, charge in Libya, to reserve for certain doubtful accounts receivable and inventory. During 2012, we received $42 million related to the Libya reserve that was established in 2011 for receivables.
Following is a discussion of our results of operations by reportable segment.
Completion and Production revenue increased in all geographic regions compared to 2011, with strong international growth. North America revenue rose 11%, primarily due to increased cementing services and completions tools sales, as well as higher activity in production enhancement from an increased demand for hydraulic fracturing in the United States. Latin America revenue increased 27% due to improved activity in most product service lines in Mexico, Brazil, and Venezuela. Europe/Africa/CIS revenue increased 20%, driven by strong demand for completion tools across the region and increased cementing services in Mozambique and Nigeria. Middle East/Asia revenue grew 24% due to higher activity in all product service lines in Australia, Malaysia, and Indonesia, partially offset by lower completion tools sales in China and decreased activity in Singapore. Revenue outside of North America was 30% of total segment revenue in 2012 and 28% of total segment revenue in 2011.

32



The Completion and Production segment operating income decrease compared to 2011 was primarily due to the North America region, where operating income fell $1.1 billion as a result of pricing pressure in the production enhancement product service line and rising costs, particularly related to guar gum. Latin America operating income increased 30% due to higher demand for completion tools in Mexico and Brazil, partially offset by higher costs and pricing adjustments in Argentina and Colombia. Europe/Africa/CIS operating income grew $299 million compared to 2011 due to the recovery from activity disruptions in North Africa, including collections in 2012 of $29 million from the original $36 million Libya-related reserve recognized in 2011 for certain accounts receivable and inventory. Middle East/Asia operating income increased 79% due to cost controls in Iraq, higher activity levels in Oman, and increased demand for production enhancement and cementing services in Australia.
Drilling and Evaluation revenue increased 15% compared to 2011 as drilling activity improved across all regions, especially Middle East/Asia and Latin America. North America revenue grew 10% due to increased demand for drilling fluids. Latin America revenue increased 22% due to higher demand in most product services lines in Brazil, Mexico, Venezuela, and Colombia. Europe/Africa/CIS revenue increased 9% due to improved drilling service in Tanzania, Nigeria, and the United Kingdom, partially offset by service disruptions in Algeria. Middle East/Asia revenue rose 23% primarily due to the ongoing work in Iraq and Saudi Arabia, increased activity in Malaysia, and higher wireline direct sales. Revenue outside North America was 65% of total segment revenue in 2012 and 64% of total segment revenue in 2011.
Segment operating income compared to 2011 increased 19%, primarily due to increased activity in Middle East/Asia and Latin America. North America operating income increased 6% from increased demand for drilling fluids and wireline and perforating, which offset higher consulting and project management costs. Latin America operating income grew 29% as a result of activity increases in Mexico, Venezuela, and Brazil. The Europe/Africa/CIS region operating income grew 29% due to greater activity in Nigeria and the recovery in Libya where $13 million of the original $23 million reserve from 2011 mentioned above was collected in 2012, which more than offset higher costs in Norway. Middle East/Asia operating income increased 34% mainly due to increased activity in Malaysia and Saudi Arabia.
Corporate and other expenses were $660 million in 2012 compared to $399 million in 2011. The 65% increase was primarily due to a $300 million, pre-tax, loss contingency recorded in 2012 related to the Macondo well incident as well as additional expenses in 2012 associated with strategic investments in our operating model and creating competitive advantages by repositioning our technology, supply chain, and manufacturing infrastructure. These items were partially offset by, among other things, a $20 million, pre-tax, gain recorded in 2012 related to the settlement of a patent infringement lawsuit.

NONOPERATING ITEMS
Income (loss) from discontinued operations, net increased $224 million in 2012 compared to 2011, primarily due to a $163 million charge, after-tax, recognized in 2011 for an arbitration award against our former subsidiary, KBR, relating to the Barracuda-Caratinga project, a project for which we had provided a guarantee of KBR's obligations. In 2012, we recorded an $80 million tax benefit in discontinued operations related to the $219 million payment we made to Barracuda & Caratinga Leasing Company BV under that guarantee.



33



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. No single jurisdiction has a disproportionately low tax rate. 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.

34



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 8 of our consolidated financial statements, as of December 31, 2013, 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 test.
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 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. Plan assets are comprised primarily of equity and debt

35



securities. As we have both domestic and international plans, these assumptions differ based on varying factors specific to each particular country or economic environment.
The discount rate utilized in 2013 to determine the projected benefit obligation at the measurement date for our United Kingdom pension plan, which constituted 81% of our international plans’ pension obligations, was 4.5%, compared to a discount rate of 4.6% utilized in 2012. The expected long-term rate of return assumption used for our United Kingdom pension plan expense was 6.5% in 2013, compared to 6.7% in 2012.
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 2013
Pension Benefit Obligation at December 31, 2013
25-basis-point decrease in discount rate
$
1

$
55

25-basis-point increase in discount rate
(1
)
(51
)
25-basis-point decrease in expected long-term rate of return
2

NA

25-basis-point increase in expected long-term rate of return
(2
)
NA


Our international defined benefit plans reduced pretax income by $32 million in 2013, $26 million in 2012, and $27 million in 2011. Included in these amounts was income from expected pension returns of $44 million in 2013, $45 million in 2012, and $47 million in 2011. Actual returns on international plan assets totaled $117 million in 2013, compared to $87 million in 2012. Our net actuarial loss, net of tax, related to international pension plans was $222 million at December 31, 2013 and $208 million at December 31, 2012. 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 three 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 33 years, which represents the estimated average remaining lifetime of the benefit obligations. These ranges reflect varying maturity levels among the plans.
During 2013, we made contributions of $26 million to fund our international defined benefit plans. We expect to make contributions of approximately $17 million to our international defined benefit plans in 2014.
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 14 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 3.0%. At December 31, 2013, allowance for bad debts totaled $117 million, or 1.9% of notes and accounts receivable before the allowance. At December 31, 2012, allowance for bad debts totaled $92 million, or 1.6% 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, 2013 would have resulted in a $62 million adjustment to 2013 total operating costs and expenses. See Note 3 to the consolidated financial statements for further information.

36



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, 2013, 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, 2013 would result in an $89 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 $10 million of interest charges for the year ended December 31, 2013.
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 13 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 8 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,” “believes,” “do not believe,” “plans,” “estimates,” “intends,” “expects,” “do not expect,” “anticipates,” “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.

37



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.


38



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, 2013 based upon criteria set forth in the Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that, as of December 31, 2013, our internal control over financial reporting is effective.
The effectiveness of Halliburton’s internal control over financial reporting as of December 31, 2013 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/ Mark A. McCollum
David J. Lesar
 
Mark A. McCollum
Chairman of the Board,
 
Executive Vice President and
President, and Chief Executive Officer
 
Chief Financial Officer

39




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, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2013, 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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 7, 2014 expressed an unqualified opinion on the effectiveness of Halliburton Company’s internal control over financial reporting.

/s/ KPMG LLP
Houston, Texas
February 7, 2014


40





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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) 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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) 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, 2013 and 2012, 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, 2013, and our report dated February 7, 2014 expressed an unqualified opinion on those consolidated financial statements.



/s/ KPMG LLP
Houston, Texas
February 7, 2014





41



HALLIBURTON COMPANY
Consolidated Statements of Operations

 
Year Ended December 31
Millions of dollars and shares except per share data
2013
2012
2011
Revenue:
 
 
 
Services
$
22,257

$
22,196

$
19,692

Product sales
7,145

6,307

5,137

Total revenue
29,402

28,503

24,829

Operating costs and expenses:
 
 
 
Cost of services
18,959

18,447

15,432

Cost of sales
5,972

5,322

4,379

Loss contingency for Macondo well incident
1,000

300


General and administrative
333

275

281

Total operating costs and expenses
26,264

24,344

20,092

Operating income
3,138

4,159

4,737

Interest expense, net of interest income of $8, $7, and $5
(331
)
(298
)
(263
)
Other, net
(43
)
(39
)
(25
)
Income from continuing operations before income taxes
2,764

3,822

4,449

Provision for income taxes
(648
)
(1,235
)
(1,439
)
Income from continuing operations
2,116

2,587

3,010

Income (loss) from discontinued operations, net of income tax benefit (provision) of $1, $82, and $(18)
19

58

(166
)
Net income
$
2,135

$
2,645

$
2,844

Noncontrolling interest in net income of subsidiaries
(10
)
(10
)
(5
)
Net income attributable to company
$
2,125

$
2,635

$
2,839

Amounts attributable to company shareholders:
 
 
 
Income from continuing operations
$
2,106

$
2,577

$
3,005

Income (loss) from discontinued operations, net
19

58

(166
)
Net income attributable to company
$
2,125

$
2,635

$
2,839

Basic income per share attributable to company shareholders:
 
 
 
Income from continuing operations
$
2.35

$
2.78

$
3.27

Income (loss) from discontinued operations, net
0.02

0.07

(0.18
)
Net income per share
$
2.37

$
2.85

$
3.09

Diluted income per share attributable to company shareholders:
 
 
 
Income from continuing operations
$
2.33

$
2.78

$
3.26

Income (loss) from discontinued operations, net
0.03

0.06

(0.18
)
Net income per share
$
2.36

$
2.84

$
3.08

 
 
 
 
Basic weighted average common shares outstanding
898

926

918

Diluted weighted average common shares outstanding
902

928

922

See notes to consolidated financial statements.
 
 
 


42



HALLIBURTON COMPANY
Consolidated Statements of Comprehensive Income

 
Year Ended December 31
Millions of dollars
2013
2012
2011
Net income
$
2,135

$
2,645

$
2,844

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

(33
)
(34
)
Other
2

(3
)

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

(36
)
(34
)
Comprehensive income
$
2,137

$
2,609

$
2,810

Comprehensive income attributable to noncontrolling interest
(10
)
(10
)
(4
)
Comprehensive income attributable to company shareholders
$
2,127

$
2,599

$
2,806

See notes to consolidated financial statements.
 
 
 



43



HALLIBURTON COMPANY
Consolidated Balance Sheets

 
December 31
Millions of dollars and shares except per share data
2013
2012
Assets
Current assets:
 
 
Cash and equivalents
$
2,356

$
2,484

Receivables (less allowance for bad debts of $117 and $92)
6,181

5,787

Inventories
3,305

3,186

Prepaid expenses
737

608

Current deferred income taxes
388

351

Other current assets
737

670

Total current assets
13,704

13,086

Property, plant, and equipment, net of accumulated depreciation of $9,480 and $8,056
11,322

10,257

Goodwill
2,168

2,135

Other assets
2,029

1,932

Total assets
$
29,223

$
27,410

Liabilities and Shareholders’ Equity
Current liabilities:
 
 
Accounts payable
$
2,365

$
2,041

Accrued employee compensation and benefits
1,029

930

Deferred revenue
350

307

Loss contingency for Macondo well incident
278


Other current liabilities
1,004

1,474

Total current liabilities
5,026

4,752

Long-term debt
7,816

4,820

Loss contingency for Macondo well incident
1,022

300

Employee compensation and benefits
584

607

Other liabilities
1,160

1,141

Total liabilities
15,608

11,620

Shareholders’ equity:
 
 
Common shares, par value $2.50 per share (authorized 2,000 shares,
              issued 1,072 and 1,073 shares)
2,680

2,682

Paid-in capital in excess of par value
415

486

Accumulated other comprehensive loss
(307
)
(309
)
Retained earnings
18,842

17,182

Treasury stock, at cost (223 and 144 shares)
(8,049
)
(4,276
)
Company shareholders’ equity
13,581

15,765

Noncontrolling interest in consolidated subsidiaries
34

25

Total shareholders’ equity
13,615

15,790

Total liabilities and shareholders’ equity
$
29,223

$
27,410

See notes to consolidated financial statements.
 
 


44



HALLIBURTON COMPANY
Consolidated Statements of Cash Flows

 
Year Ended December 31
Millions of dollars
2013
2012
2011
Cash flows from operating activities:
 
 
 
Net income
$
2,135

$
2,645

$
2,844

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
Depreciation, depletion, and amortization
1,900

1,628

1,359

Loss contingency for Macondo well incident
1,000

300


Provision (benefit) for deferred income taxes, continuing operations
(132
)
165

(30
)
(Income) loss from discontinued operations, net
(19
)
(58
)
166

Other changes:
 
 
 
Receivables
(449
)
(682
)
(1,218
)
Accounts payable
327

200

649

Payment of Barracuda-Caratinga obligation
(219
)


Inventories
(107
)
(611
)
(564
)
Other
11

67

478

Total cash flows from operating activities
4,447

3,654

3,684

Cash flows from investing activities:
 
 
 
Capital expenditures
(2,934
)
(3,566
)
(2,953
)
Sales of investment securities
356

258

1,001

Purchases of investment securities
(329
)
(506
)
(501
)
Sales of property, plant, and equipment
241

395

160

Acquisitions of business assets, net of cash acquired
(94
)
(214
)
(880
)
Other investing activities
(110
)
(55
)
(17
)
Total cash flows from investing activities
(2,870
)
(3,688
)
(3,190
)
Cash flows from financing activities:
 
 
 
Payments to reacquire common stock
(4,356
)


Proceeds from long-term borrowings, net of offering costs
2,968


978

Dividends to shareholders
(465
)
(333
)
(330
)
Proceeds from exercises of stock options
277

107

160

Other financing activities
(178
)
54

25

Total cash flows from financing activities
(1,754
)
(172
)
833

Effect of exchange rate changes on cash
49

(8
)
(27
)
Increase (decrease) in cash and equivalents
(128
)
(214
)
1,300

Cash and equivalents at beginning of year
2,484

2,698

1,398

Cash and equivalents at end of year
$
2,356

$
2,484

$
2,698

Supplemental disclosure of cash flow information:
 
 
 
Cash payments during the period for:
 
 
 
Interest
$
293

$
294

$
261

Income taxes
$
913

$
1,098

$
1,285

See notes to consolidated financial statements.
 
 
 


45



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, 2010
$
2,674

$
339

$
(4,771
)
$
12,371

$
(240
)
$
14

$
10,387

Comprehensive income (loss):
 

 

 

 

 

 

 
Net income



2,839


5

2,844

Other comprehensive loss




(33
)
(1
)
(34
)
Cash dividends ($0.36 per share)



(330
)


(330
)
Stock plans
9

82

224




315

Other

34





34

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:
 

 

 

 

 

 

 

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

See notes to consolidated financial statements.
 
 
 
 


46



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:
-
the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements; and
-
the reported amounts of revenue and expenses during the reporting period.
We believe the most significant estimates and assumptions are associated with the forecasting of our effective income tax rate and the valuation of deferred taxes, legal and environmental reserves, long-lived asset valuations, purchase price allocations, 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.
In 2013, we adopted the provisions of a new accounting standard. See Note 15 for further information. All periods presented reflect these changes.
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.
Software sales. Sales of perpetual software licenses, net of any deferred maintenance and support fees, are recognized as revenue upon shipment. Sales of time-based licenses are recognized as revenue over the license period. Maintenance and support fees are recognized as revenue ratably over the contract period, usually a one-year duration.
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. Physical percent complete is determined as a combination of input and output measures as deemed appropriate by the circumstances. All known or anticipated losses on contracts are provided for when they become evident. Cost adjustments that are in the process of being negotiated with customers for extra work or changes in the scope of work are included in revenue when collection is deemed probable.
Research and development
Research and development costs are expensed as incurred. Research and development costs were $588 million in 2013, $460 million in 2012, and $401 million in 2011.
Cash equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Inventories
Inventories are stated at the lower of cost or market. Cost represents invoice or production cost for new items and original cost less allowance for condition for used material returned to stock. Production cost includes material, labor, and manufacturing overhead. Some domestic manufacturing and field service finished products and parts inventories for drill bits, completion products, and bulk materials are recorded using the last-in, first-out method. The remaining inventory is recorded on the average cost method. We regularly review inventory quantities on hand and record provisions for excess or obsolete inventory based primarily on historical usage, estimated product demand, and technological developments.

47



Allowance for bad debts
We establish an allowance for bad debts through a review of several factors, including historical collection experience, current aging status of the customer accounts, and financial condition of our customers. Our policy is to write off bad debts when the customer accounts are determined to be uncollectible.
Property, plant, and equipment
Other than those assets that have been written down to their fair values due to impairment, property, plant, and equipment are reported at cost less accumulated depreciation, which is generally provided on the straight-line method over the estimated useful lives of the assets. Accelerated depreciation methods are used for tax purposes, wherever permitted. Upon sale or retirement of an asset, the related costs and accumulated depreciation are removed from the accounts and any gain or loss is recognized. Planned major maintenance costs are generally expensed as incurred. Expenditures for additions, modifications, and conversions are capitalized when they increase the value or extend the useful life of the asset.
Goodwill and other intangible assets
We record as goodwill the excess purchase price over the fair value of the tangible and identifiable intangible assets acquired. Changes in the carrying amount of goodwill are detailed below by reportable segment.
Millions of dollars
Completion and Production
Drilling and Evaluation
Total
Balance at December 31, 2011:
$
1,215

$
561

$
1,776

Current year acquisitions
100

62

162

Purchase price adjustments for previous acquisitions
196

1

197

Balance at December 31, 2012:
$
1,511

$
624

$
2,135

Current year acquisitions
43

10

53

Purchase price adjustments for previous acquisitions
(21
)
1

(20
)
Balance at December 31, 2013:
$
1,533

$
635

$
2,168


The reported amounts of goodwill for each reporting unit are reviewed for impairment on an annual basis, during the third quarter, and more frequently should negative conditions such as significant current or projected operating losses exist. In 2012 and 2011, we elected to perform a qualitative assessment for our annual goodwill impairment test. If a qualitative assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then we would be required to perform a quantitative impairment test for goodwill. In 2013, we elected to bypass the qualitative assessment and perform a quantitative impairment test. This two-step process involves comparing the estimated fair value of each reporting unit to the reporting unit’s carrying value, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered impaired, and the second step of the impairment test is unnecessary. If the carrying amount of a reporting unit exceeds its fair value, the second step of the goodwill impairment test would be performed to measure the amount of impairment loss to be recorded, if any. Our goodwill impairment assessment for 2013 indicated the fair value of each of our reporting units exceeded its carrying amount by a significant margin. Based on our qualitative assessment of goodwill in 2012 and 2011, we concluded that it was more likely than not that the fair value of each of our reporting units was greater than their carrying amount, and therefore no further testing was required. In addition, there were no triggering events that occurred in 2013, 2012, or 2011 requiring us to perform additional impairment reviews. As such, there were no impairments of goodwill recorded in the three-year period ended December 31, 2013.
We amortize other identifiable intangible assets with a finite life on a straight-line basis over the period which the asset is expected to contribute to our future cash flows, ranging from three to twenty years. The components of these other intangible assets generally consist of patents, license agreements, non-compete agreements, trademarks, and customer lists and contracts.
Evaluating impairment of long-lived assets
When events or changes in circumstances indicate that long-lived assets other than goodwill may be impaired, an evaluation is performed. For an asset classified as held for use, the estimated future undiscounted cash flows associated with the asset are compared to the asset’s carrying amount to determine if a write-down to fair value is required. When an asset is classified as held for sale, the asset’s book value is evaluated and adjusted to the lower of its carrying amount or fair value less cost to sell. In addition, depreciation and amortization is ceased while it is classified as held for sale.
Income taxes
We recognize the amount of taxes payable or refundable for the year. In addition, deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the financial statements or tax returns. A valuation allowance is provided for deferred tax assets if it is more likely than not that these items will not be realized.

48



In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that we will realize the benefits of these deductible differences, net of the existing valuation allowances.
We recognize interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing operations in our consolidated statements of operations.
We generally do not provide income taxes on the undistributed earnings of non-United States subsidiaries because such earnings are intended to be reinvested indefinitely to finance foreign activities. These additional foreign earnings could be subject to additional tax if remitted, or deemed remitted, as a dividend; however, it is not practicable to estimate the additional amount, if any, of taxes payable. Taxes are provided as necessary with respect to earnings that are not permanently reinvested.
Derivative instruments
At times, we enter into derivative financial transactions to hedge existing or projected exposures to changing foreign currency exchange rates and interest rates. We do not enter into derivative transactions for speculative or trading purposes. We recognize all derivatives on the balance sheet at fair value. Derivatives that are not hedges are adjusted to fair value and reflected through the results of operations. If the derivative is designated as a hedge, depending on the nature of the hedge, changes in the fair value of derivatives are either offset against:
-
the change in fair value of the hedged assets, liabilities, or firm commitments through earnings; or
-
recognized in other comprehensive income until the hedged item is recognized in earnings.
The ineffective portion of a derivative’s change in fair value is recognized in earnings. Recognized gains or losses on derivatives entered into to manage foreign currency exchange risk are included in “Other, net” on the consolidated statements of operations. Gains or losses on interest rate derivatives are included in “Interest expense, net.”
Foreign currency translation
Foreign entities whose functional currency is the United States dollar translate monetary assets and liabilities at year-end exchange rates, and nonmonetary items are translated at historical rates. Income and expense accounts are translated at the average rates in effect during the year, except for depreciation, cost of product sales and revenue, and expenses associated with nonmonetary balance sheet accounts, which are translated at historical rates. Gains or losses from changes in exchange rates are recognized in our consolidated statements of operations in “Other, net” in the year of occurrence.
Stock-based compensation
Stock-based compensation cost is measured at the date of grant, based on the calculated fair value of the award, and is recognized as expense over the employee’s service period, which is generally the vesting period of the equity grant. Additionally, compensation cost is recognized based on awards ultimately expected to vest, therefore, we have reduced the cost for estimated forfeitures based on historical forfeiture rates. Forfeitures are estimated at the time of grant and revised in subsequent periods to reflect actual forfeitures. See Note 11 for additional information related to stock-based compensation.


49



Note 2. Business Segment and Geographic Information
We operate under two divisions, which form the basis for the two operating segments we report: the Completion and Production segment and the Drilling and Evaluation segment.
Completion and Production delivers cementing, stimulation, intervention, pressure control, specialty chemicals, artificial lift, and completion services. The segment consists of Production Enhancement, Cementing, Completion Tools, Halliburton Boots & Coots, Multi-Chem, and Halliburton Artificial Lift.
Production Enhancement services include stimulation services and sand control services. Stimulation services optimize oil and natural gas reservoir production through a variety of pressure pumping services, nitrogen services, and chemical processes, commonly known as hydraulic fracturing and acidizing. Sand control services include fluid and chemical systems and pumping services for the prevention of formation sand production.
Cementing services involve bonding the well and well casing while isolating fluid zones and maximizing wellbore stability. Our cementing service line also provides casing equipment.
Completion Tools provides downhole solutions and services to our customers to complete their wells, including well completion products and services, intelligent well completions, liner hanger systems, sand control systems, and service tools.
Halliburton Boots & Coots includes well intervention services, pressure control, equipment rental tools and services, and pipeline and process services.
Multi-Chem includes oilfield production and completion chemicals and services that address production, processing, and transportation challenges.
Halliburton Artificial Lift offers electrical submersible pumps, including the associated surface package for power, control, and monitoring of the entire lift system, and provides installation, maintenance, repair, and testing services. The objective of these services is to maximize reservoir and wellbore recovery by applying lifting technology and intelligent field management solutions throughout the life of the well.
Drilling and Evaluation provides field and reservoir modeling, drilling, evaluation, and precise wellbore placement solutions that enable customers to model, measure, drill, and optimize their well construction activities. The segment consists of Drill Bits and Services, Wireline and Perforating, Testing and Subsea, Baroid, Sperry Drilling, Landmark Software and Services, and Consulting and Project Management.
Drill Bits and Services provides roller cone rock bits, fixed cutter bits, hole enlargement, and related downhole tools and services used in drilling oil and natural gas wells. In addition, coring equipment and services are provided to acquire cores of the formation drilled for evaluation.
Wireline and Perforating services include open-hole logging services that provide information on formation evaluation and reservoir fluid analysis, including formation lithology, rock properties, and reservoir fluid properties. Also offered are cased-hole and slickline services, which provide perforating, pipe recovery services, through-casing formation evaluation and reservoir monitoring, casing and cement integrity measurements, and well intervention services. Borehole seismic services include downhole seismic operations check-shots and vertical seismic profiles, and provide the link between surface seismic and the wellbore. Finally, formation and reservoir solutions transform formation evaluation data into reservoir insight through geoscience solutions.
Testing and Subsea services provide acquisition and analysis of dynamic reservoir information and reservoir optimization solutions to the oil and natural gas industry through a broad portfolio of test tools, data acquisition services, fluid sampling, surface well testing, and subsea safety systems.
Baroid provides drilling fluid systems, performance additives, completion fluids, solids control, specialized testing equipment, and waste management services for oil and natural gas drilling, completion, and workover operations.
Sperry Drilling provides drilling systems and services. These services include directional and horizontal drilling, measurement-while-drilling, logging-while-drilling, surface data logging, multilateral systems, underbalanced applications, and rig site information systems. Our drilling systems offer directional control for precise wellbore placement while providing important measurements about the characteristics of the drill string and geological formations while drilling wells. Real-time operating capabilities enable the monitoring of well progress and aid decision-making processes.
Landmark Software and Services is a supplier of integrated exploration, drilling and production software, and related professional and data management services for the upstream oil and natural gas industry.
Consulting and Project Management provides oilfield project management and integrated solutions to independent, integrated, and national oil companies. These offerings make use of all of our oilfield services, products, technologies, and project management capabilities to assist our customers in optimizing the value of their oil and natural gas assets.
Corporate and other includes expenses related to support functions and corporate executives and is primarily composed of cash and equivalents, deferred tax assets, and investment securities. Also included are certain gains, losses and costs not attributable to a particular business segment (such as the loss contingencies related to the Macondo well incident recorded during the first quarters of 2013 and 2012 and the $55 million charitable contribution expensed during the second quarter of 2013).

50



Intersegment revenue and revenue between geographic areas are immaterial. Our equity in earnings and losses of unconsolidated affiliates that are accounted for under the equity method of accounting is included in revenue and operating income of the applicable segment.
The following tables present information on our business segments.