HAL-12.31.2012-10K



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, 2012
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 Common Stock held by nonaffiliates on June 30, 2012, determined using the per share closing price on the New York Stock Exchange Composite tape of $28.39 on that date, was approximately $26,216,000,000.
As of February 1, 2013, there were 931,813,112 shares of Halliburton Company Common Stock, $2.50 par value per share, outstanding.
Portions of the Halliburton Company Proxy Statement for our 2013 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, 2012
 
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

2



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 Halliburton Production Enhancement, Cementing, Completion Tools, Boots & Coots, and Multi-Chem. Effective January 1, 2013, Halliburton Artificial Lift will be included as a product service line within this segment.
-
our Drilling and Evaluation segment provides field and reservoir modeling, drilling, evaluation, and wellbore placement solutions that enable customers to model, measure, and optimize their well construction activities. The segment consists of Halliburton Drill Bits and Services, Wireline and Perforating, Testing and Subsea, Baroid, Sperry Drilling, Landmark Software and Services, and Halliburton 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, Mexico, 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 to our customers that maximize their production and recovery and realize proven reserves from difficult environments. Our objectives are to:
-
create a balanced portfolio of services and products supported by global infrastructure and anchored by technological innovation with a well-integrated digital strategy to further differentiate our company;
-
reach a distinguished level of operational excellence that reduces costs and creates real value from everything we do;
-
preserve a dynamic workforce by being a preferred employer to attract, develop, and retain the best global talent; and
-
uphold the ethical and business standards of the company 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.

1



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 2012, 2011, and 2010, based on the location of services provided and products sold, 53%, 55%, and 46% 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, a meaningful estimate of the total number of competitors cannot be made. 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 be material to the conduct of our operations taken as a whole.
Information regarding our exposure to foreign currency fluctuations, risk concentration, and financial instruments used to minimize risk is included in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financial Instrument Market Risk” and in Note 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 $460 million in 2012, $401 million in 2011, and $366 million in 2010. These expenditures were over 95% company-sponsored 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, 2012, we employed approximately 73,000 people worldwide compared to approximately 68,000 at December 31, 2011. At December 31, 2012, approximately 16% of our employees were subject to collective bargaining agreements. Based upon the geographic diversification of these employees, we do not believe any risk of loss from employee strikes or other collective actions would be material to the conduct of our operations taken as a whole.
Environmental regulation
We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide. For further information related to environmental matters and regulation, see Note 8 to the consolidated financial statements, Item 1(a), “Risk Factors,” and Item 3, “Legal Proceedings.”

2



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.
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 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.

3



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, Room 1580, 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 2012, 2011, or 2010. 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 11, 2013, including all offices and positions held by each in the past five years:
 
Name and Age
Offices Held and Term of Office
 
Evelyn M. Angelle
(Age 45)
Senior Vice President and Chief Accounting Officer of Halliburton Company, since January 2011
 
 
Vice President, Corporate Controller, and Principal Accounting Officer of Halliburton Company, January 2008 to January 2011
 
 
 
 
James S. Brown
(Age 58)
President, Western Hemisphere of Halliburton Company, since January 2008
 
 
 
*
Albert O. Cornelison, Jr.
(Age 63)
Executive Vice President and General Counsel of Halliburton Company, since December 2002
 
 
 
 
Christian A. Garcia
(Age 49)
Senior Vice President and Treasurer of Halliburton Company, since September 2011
 
 
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
 
 
 
*
David J. Lesar
(Age 59)
Chairman of the Board, President, and Chief Executive Officer of Halliburton Company, since August 2000
 
 
 
*
Mark A. McCollum
(Age 53)
Executive Vice President and Chief Financial Officer of Halliburton Company, since January 2008
 
 
 
*
Jeffrey A. Miller
(Age 49)
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

4



 
Name and Age
Offices Held and Term of Office
*
Lawrence J. Pope
(Age 44)
Executive Vice President of Administration and Chief Human Resources Officer of Halliburton Company, since January 2008
 
 
 
*
Timothy J. Probert
(Age 61)
President, Strategy and Corporate Development of Halliburton Company, since January 2011
 
 
President, Global Business Lines and Corporate Development of Halliburton Company, January 2010 to January 2011
 
 
President, Drilling and Evaluation Division and Corporate Development of Halliburton Company, March 2009 to December 2009
 
 
Executive Vice President, Strategy and Corporate Development of Halliburton Company, January 2008 to March 2009
 
 
 
 
Joe D. Rainey
(Age 56)
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
 
 
Vice President, Asia Pacific Region of Halliburton Company, February 2005 to December 2008


* 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.

5



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 & Production, Inc. (BP Exploration), an indirect wholly owned subsidiary of BP p.l.c. (BP p.l.c., BP Exploration, and their affiliates, collectively, BP). There were eleven fatalities and a number of injuries as a result of the Macondo well incident. Crude oil escaping from the Macondo well site spread across thousands of square miles of the Gulf of Mexico and reached the United States Gulf Coast. We performed a variety of services for BP Exploration, including cementing, mud logging, directional drilling, measurement-while-drilling, and rig data acquisition services.
We are named along with other unaffiliated defendants in more than 400 complaints, most of which are alleged class-actions, involving pollution damage claims and at least seven 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. BP Exploration and one of its affiliates have filed claims against us seeking subrogation and contribution, including with respect to liabilities under the Oil Pollution Act of 1990 (OPA), and direct damages, and alleging negligence, gross negligence, fraudulent conduct, and fraudulent concealment. Certain other defendants in the lawsuits have filed claims against us seeking, among other things, indemnification and contribution, including with respect to liabilities under the OPA, and alleging, among other things, negligence and gross negligence. See Item 3, “Legal Proceedings.” Additional lawsuits may be filed against us, including criminal and civil charges under federal and 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, numerous industry participants, governmental agencies, and Congressional committees 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 and ordered us and the BSEE to file notice within 15 days after the conclusion of the multi-district litigation (MDL) and, within 60 days after the MDL court issues a final decision, 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.
In addition, as part of its criminal investigation, the Department of Justice (DOJ) is examining certain aspects of our conduct after the incident, including with respect to record-keeping, record retention, post-incident testing and modeling and the retention thereof, securities filings, and public statements by us or our employees, to evaluate whether there has been any violation of federal law.

6



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 that 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, whether the MDL will proceed to trial, the results of any such 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. At the request of the court, in late February 2012 we participated in a series of discussions with the Magistrate Judge in the MDL relating to whether the MDL could be settled. Although these discussions did not result in a settlement, we recorded a $300 million liability during the first quarter of 2012 for an estimated loss contingency relating to the MDL. This loss contingency, which is included in “Other liabilities” in our consolidated balance sheet as of December 31, 2012 and in “Cost of services” on the consolidated statement of operations for the year ended December 31, 2012, represents a loss contingency that is probable and for which a reasonable estimate of loss or range of loss can be made. 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 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.

7



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. In addition, the BSEE has noted that it may propose regulations to require, among other things, increased employee involvement in certain safety measures and third-party audits of operators’ safety and environmental management systems. The BSEE has also stated 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 has 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 are typically indemnified by our customers 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 existing 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 their 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.


8



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, 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.


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Changes in or interpretation of tax law and currency/repatriation control could impact the determination of our income tax liabilities for a tax year.
We have operations in approximately 80 countries. Consequently, we are subject to the jurisdiction of a significant number of taxing authorities. The income earned in these various jurisdictions is taxed on differing bases, including net income actually earned, net income deemed earned, and revenue-based tax withholding. The final determination of our income tax liabilities involves the interpretation of local tax laws, tax treaties, and related authorities in each jurisdiction, as well as the significant use of estimates and assumptions regarding the scope of future operations and results achieved and the timing and nature of income earned and expenditures incurred. Changes in the operating environment, including changes in or interpretation of tax law and currency/repatriation controls, could impact the determination of our income tax liabilities for a tax year.

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

As an example, we conduct business in countries, such as Venezuela, that have nontraded 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."

Trends in oil and natural gas prices affect the level of exploration, development, and production activity of our customers and the demand for our services and products which could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition.
Demand for our services and products is particularly sensitive to the level of exploration, development, and production activity of, and the corresponding capital spending by, oil and natural gas companies, including national oil companies. The level of exploration, development, and production activity is directly affected by trends in oil and natural gas prices, which historically have been volatile and are likely to continue to be volatile.
Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of other economic factors that are beyond our control. 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:
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the level of supply and demand for oil and natural gas, especially demand for natural gas in the United States;
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governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves;
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weather conditions and natural disasters;
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worldwide political, military, and economic conditions;
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the level of oil production by non-OPEC countries and the available excess production capacity within OPEC;
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oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;
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the cost of producing and delivering oil and natural gas; and
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potential acceleration of development of alternative fuels.


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

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.
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 Fuerte, 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."

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 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.
We are one of several unrelated companies who received a subpoena from the Office of the New York Attorney General, dated June 17, 2011. The subpoena sought information and documents relating to, among other things, natural gas development and hydraulic fracturing. We have provided information in response to the Attorney General's requests.

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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. For any particular federal or state superfund site, because our estimated liability is typically within a range and our accrued liability may be the amount on the low end of that range, our actual liability could eventually be well in excess of the amount accrued. 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.

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.

Doing business with national oil companies exposes us to greater risks of cost overruns, delays, and project losses, as well as unsettled political conditions that can heighten these risks.
Much of the world’s oil and natural gas reserves are controlled by national or state-owned oil companies (NOCs). Several NOCs are among our top 20 customers. Increasingly, NOCs are turning to oilfield services companies like us to provide the services, technologies, and expertise needed to develop their reserves. Reserve estimation is a subjective process that involves estimating location and volumes based on a variety of assumptions and variables that cannot be directly measured. As such, the NOCs may provide us with inaccurate information in relation to their reserves that may result in cost overruns, 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 types of issues may also result in similar cost overruns, delays, and project losses.

A downward trend in estimates of production volumes or commodity prices, or an upward trend in production costs, could have a material adverse effect on our consolidated results of operations and result in impairment of or a change in the depletion rate on our oil and natural gas properties.
We have interests in oil and natural gas properties primarily in North America totaling approximately $78 million, net of accumulated depletion, which we account for under the successful efforts method. These oil and natural gas properties are assessed for impairment whenever changes in facts and circumstances indicate that the properties’ carrying amounts may not be recoverable. The expected future cash flows used for impairment reviews and related fair-value calculations are based on judgmental assessments of future production volumes, prices, and costs, considering all available information at the date of review.
A downward trend in estimates of production volumes or prices, or an upward trend in production costs, could have a material adverse effect on our consolidated results of operations and result in impairment charges or a change in the depletion rate on our oil and natural gas properties.


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Some of our customers require us to enter into long-term, fixed-price contracts that may require us to assume additional risks associated with cost over-runs, operating cost inflation, labor availability and productivity, supplier and contractor pricing and performance, and potential claims for liquidated damages.
Our customers, primarily NOCs, may require integrated, long-term, fixed-price contracts that could require us to provide integrated project management services outside our normal discrete business to act as project managers as well as service providers. Providing services on an integrated basis 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. For example, we generally rely on third-party subcontractors and equipment providers to assist us with the completion of our contracts. To the extent that we cannot engage subcontractors or acquire equipment or materials, our ability to complete a project in a timely fashion 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.

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:
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any acquisitions would result in an increase in income or provide an adequate return of capital or other anticipated benefits;
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any acquisitions would be successfully integrated into our operations and internal controls;
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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;
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any disposition would not result in decreased earnings, revenue, or cash flow;
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use of cash for acquisitions would not adversely affect our cash available for capital expenditures and other uses;
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any dispositions, investments, acquisitions, or integrations would not divert management resources; or
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any dispositions, investments, acquisitions, or integrations would not have a material adverse effect on our liquidity, consolidated results of operations, or consolidated financial condition.

Actions of and disputes with our joint venture partners could have a material adverse effect on the business and results of operations of our joint ventures and, in turn, our business and consolidated results of operations.
We conduct some operations through joint ventures, where control may be shared with unaffiliated third parties. As with any joint venture arrangement, differences in views among the joint venture participants may result in delayed decisions or in failures to agree on major issues. We also cannot control the actions of our joint venture partners, including any nonperformance, default, or bankruptcy of our joint venture partners. These factors could have a material adverse effect on the business and results of operations of our joint ventures and, in turn, our business and consolidated results of operations.

Failure on our part to comply with applicable health, safety, and environmental requirements could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.
Our business is subject to a variety of health, safety, and environmental laws, rules, and regulations in the United States and other countries, including those covering hazardous materials and requiring emission performance standards for facilities. For example, our well service operations routinely involve the handling of significant amounts of waste materials, some of which are classified as hazardous substances. We also store, transport, and use radioactive and explosive materials in certain of our operations. Applicable regulatory requirements include, for example, those concerning:
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the containment and disposal of hazardous substances, oilfield waste, and other waste materials;
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the importation and use of radioactive materials;
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the use of underground storage tanks; and
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the use of underground injection wells.

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These and other requirements generally are becoming increasingly strict. Sanctions for failure to comply with the requirements, many of which may be applied retroactively, may include:
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administrative, civil, and criminal penalties;
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revocation of permits to conduct business; and
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corrective action orders, including orders to investigate and/or clean up contamination.

Failure on our part to comply with applicable environmental requirements could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition. We are also exposed to costs arising from regulatory compliance, including compliance with changes in or expansion of applicable regulatory requirements, which could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

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

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.

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.


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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 technology, 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 technology, 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 and 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.

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.

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.

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

Item 1(b). Unresolved Staff Comments.
None.


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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
 
Monterrey, Mexico
 
Sao Jose dos Campos, Brazil
 
Singapore, Singapore
 
Stavanger, Norway
 
 
Drilling and Evaluation segment:
Alvarado, Texas
 
Nisku, Canada
 
Singapore, Singapore
 
The Woodlands, Texas
 
 
Shared/corporate facilities:
Carrollton, Texas
 
Dubai, United Arab Emirates
 
Duncan, Oklahoma
 
Houston, Texas
 
Pune, India

In addition, we have 180 international and 120 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.

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Item 3. Legal Proceedings.
Macondo well incident
Overview. 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 & Production, Inc. (BP Exploration), an indirect wholly owned subsidiary of BP p.l.c. We performed a variety of services for BP Exploration, including cementing, mud logging, directional drilling, measurement-while-drilling, and rig data acquisition services. Crude oil flowing from the well site spread across thousands of square miles of the Gulf of Mexico and reached the United States Gulf Coast. Efforts to contain the flow of hydrocarbons from the well were led by the United States government and by BP p.l.c., BP Exploration, and their affiliates (collectively, BP). The flow of hydrocarbons from the well ceased on July 15, 2010, and the well was permanently capped on September 19, 2010. Numerous attempts at estimating the volume of oil spilled have been made by various groups, and on August 2, 2010 the federal government published an estimate that approximately 4.9 million barrels of oil were discharged from the well. There were eleven fatalities and a number of injuries as a result of the Macondo well incident.
We are currently unable to fully estimate the impact the Macondo well incident will have on us. The beginning of the multi-district litigation (MDL) trial referred to below has been set for February 25, 2013. 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, whether the MDL will proceed to trial, the results of any such 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. At the request of the court, in late February 2012 we participated in a series of discussions with the Magistrate Judge in the MDL relating to whether the MDL could be settled. Although these discussions did not result in a settlement, we recorded a $300 million liability during the first quarter of 2012 for an estimated loss contingency relating to the MDL. This loss contingency, which is included in “Other liabilities” in our consolidated balance sheet as of December 31, 2012 and in “Cost of services” on the consolidated statement of operations for the year ended December 31, 2012, represents a loss contingency that is probable and for which a reasonable estimate of a loss or range of loss can be made. Although we continue to believe that we have substantial legal arguments and defenses against any liability and that BP's indemnity obligation protects us as described below, we cannot conclude that a probable loss associated with the MDL is zero. 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 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.
Investigations and Regulatory Action. The United States Coast Guard, a component of the United States Department of Homeland Security, and the Bureau of Ocean Energy Management, Regulation and Enforcement (formerly known as the Minerals Management Service and which was replaced effective October 1, 2011 by two new, independent bureaus – the Bureau of Safety and Environmental Enforcement (BSEE) and the Bureau of Ocean Energy Management), a bureau of the United States Department of the Interior, shared jurisdiction over the investigation into the Macondo well incident and formed a joint investigation team that reviewed information and held hearings regarding the incident (Marine Board Investigation). We were named as one of the 16 parties-in-interest in the Marine Board Investigation. The Marine Board Investigation, as well as investigations of the incident that were conducted by The National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling (National Commission) and the National Academy of Sciences, have been completed, and 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. The U.S. Chemical Safety and Hazard Investigation Board is also conducting an investigation of the incident.

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In October 2011, the 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 and ordered us and the BSEE to file notice within 15 days after the conclusion of the MDL and, within 60 days after the MDL court issues a final decision, 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.
The Cementing Job and Reaction to Reports. We disagree with the reports referred to above regarding many of their findings and characterizations with respect to our cementing and surface data logging services, as applicable, on the Deepwater Horizon. We have provided information to the National Commission, its staff, and representatives of the joint investigation team for the Marine Board Investigation that we believe has been overlooked or omitted from their reports, as applicable. We intend to continue to vigorously defend ourselves in any investigation relating to our involvement with the Macondo well that we believe inaccurately evaluates or depicts our services on the Deepwater Horizon.
The cement slurry on the Deepwater Horizon was designed and prepared pursuant to well condition data provided by BP. Regardless of whether alleged weaknesses in cement design and testing are or are not ultimately established, and regardless of whether the cement slurry was utilized in similar applications or was prepared consistent with industry standards, we believe that had BP and Transocean properly interpreted a negative-pressure test, this test would have revealed any problems with the cement. In addition, had BP designed the Macondo well to allow a full cement bond log test or if BP had conducted even a partial cement bond log test, the test likely would have revealed any problems with the cement. BP, however, elected not to conduct any cement bond log tests, and with Transocean misinterpreted the negative-pressure test, both of which could have resulted in remedial action, if appropriate, with respect to the cementing services.
At this time we cannot predict the impact of the investigations or reports referred to above, or the conclusions of future investigations or reports. We also cannot predict whether any investigations or reports will have an influence on or result in us being named as a party in any action alleging liability or violation of a statute or regulation, whether federal or state and whether criminal or civil.
We intend to continue to cooperate fully with all hearings, investigations, and requests for information relating to the Macondo well incident. We cannot predict the outcome of, or the costs to be incurred in connection with, any of these hearings or investigations, and therefore we cannot predict the potential impact they may have on us.
DOJ Investigations and Actions. On June 1, 2010, the United States Attorney General announced that the Department of Justice (DOJ) was launching civil and criminal investigations into the Macondo well incident to closely examine the actions of those involved, and that the DOJ was working with attorneys general of states affected by the Macondo well incident. The DOJ announced that it was reviewing, among other traditional criminal statutes, possible violations of and liabilities under The Clean Water Act (CWA), The Oil Pollution Act of 1990 (OPA), The Migratory Bird Treaty Act of 1918 (MBTA), and the Endangered Species Act of 1973 (ESA). As part of its criminal investigation, the DOJ is examining certain aspects of our conduct after the incident, including with respect to record-keeping, record retention, post-incident testing and modeling and the retention thereof, securities filings, and public statements by us or our employees, to evaluate whether there has been any violation of federal law.
The CWA provides authority for civil and criminal penalties for discharges of oil into or upon navigable waters of the United States, adjoining shorelines, or in connection with the Outer Continental Shelf Lands Act (OCSLA) in quantities that are deemed harmful. A single discharge event may result in the assertion of numerous violations under the CWA. Criminal sanctions under the CWA can be assessed for negligent discharges (up to $50,000 per day per violation), for knowing discharges (up to $100,000 per day per violation), and for knowing endangerment (up to $2 million per violation), and federal agencies could be precluded from contracting with a company that is criminally sanctioned under the CWA. Civil proceedings under the CWA can be commenced against an “owner, operator, or person in charge of any vessel, onshore facility, or offshore facility from which oil or a hazardous substance is discharged” in violation of the CWA. The civil penalties that can be imposed against responsible parties range from up to $1,100 per barrel of oil discharged in the case of those found strictly liable to $4,300 per barrel of oil discharged in the case of those found to have been grossly negligent.

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The OPA establishes liability for discharges of oil from vessels, onshore facilities, and offshore facilities into or upon the navigable waters of the United States. Under the OPA, the “responsible party” for the discharging vessel or facility is liable for removal and response costs as well as for damages, including recovery costs to contain and remove discharged oil and damages for injury to natural resources and real or personal property, lost revenues, lost profits, and lost earning capacity. The cap on liability under the OPA is the full cost of removal of the discharged oil plus up to $75 million for damages, except that the $75 million cap does not apply in the event the damage was proximately caused by gross negligence or the violation of certain federal safety, construction or operating standards. The OPA defines the set of responsible parties differently depending on whether the source of the discharge is a vessel or an offshore facility. Liability for vessels is imposed on owners and operators; liability for offshore facilities is imposed on the holder of the permit or lessee of the area in which the facility is located.
The MBTA and the ESA provide penalties for injury and death to wildlife and bird species. The MBTA provides that violators are strictly liable and such violations are misdemeanor crimes subject to fines of up to $15,000 per bird killed and imprisonment of up to six months. The ESA provides for civil penalties for knowing violations that can range up to $25,000 per violation and, in the case of criminal penalties, up to $50,000 per violation.
In addition, federal law provides for a variety of fines and penalties, the most significant of which is the Alternative Fines Act. In lieu of the express amount of the criminal fines that may be imposed under some of the statutes described above, the Alternative Fines Act provides for a fine in the amount of twice the gross economic loss suffered by third parties, which amount, although difficult to estimate, is significant.
On December 15, 2010, the DOJ filed a civil action seeking damages and injunctive relief against BP Exploration, Anadarko Petroleum Corporation and Anadarko E&P Company LP (together, Anadarko), which had an approximate 25% interest in the Macondo well, certain subsidiaries of Transocean Ltd., and others for violations of the CWA and the OPA. The DOJ’s complaint seeks an action declaring that the defendants are strictly liable under the CWA as a result of harmful discharges of oil into the Gulf of Mexico and upon United States shorelines as a result of the Macondo well incident. The complaint also seeks an action declaring that the defendants are strictly liable under the OPA for the discharge of oil that has resulted in, among other things, injury to, loss of, loss of use of, or destruction of natural resources and resource services in and around the Gulf of Mexico and the adjoining United States shorelines and resulting in removal costs and damages to the United States far exceeding $75 million. BP Exploration has been designated, and has accepted the designation, as a responsible party for the pollution under the CWA and the OPA. Others have also been named as responsible parties, and all responsible parties may be held jointly and severally liable for any damages under the OPA. A responsible party may make a claim for contribution against any other responsible party or against third parties it alleges contributed to or caused the oil spill. In connection with the proceedings discussed below under “Litigation,” in April 2011 BP Exploration filed a claim against us for contribution with respect to liabilities incurred by BP Exploration under the OPA or another law, which subsequent court filings have indicated may include the CWA, and requested a judgment that the DOJ assert its claims for OPA financial liability directly against us. We filed a motion to dismiss BP Exploration’s claim, and that motion is pending.
We have not been named as a responsible party under the CWA or the OPA in the DOJ civil action, and we do not believe we are a responsible party under the CWA or the OPA. While we are not included in the DOJ’s civil complaint, there can be no assurance that the DOJ or other federal or state governmental authorities will not bring an action, whether civil or criminal, against us under the CWA, the OPA, and/or other statutes or regulations. In connection with the DOJ’s filing of the civil action, it announced that its criminal and civil investigations are continuing and that it will employ efforts to hold accountable those who are responsible for the incident.
A federal grand jury has been convened in Louisiana to investigate potential criminal conduct in connection with the Macondo well incident. We are cooperating fully with the DOJ’s criminal investigation. As of February 11, 2013, the DOJ has not commenced any criminal proceedings against us. We cannot predict the status or outcome of the DOJ’s criminal investigation or estimate the potential impact the investigation may have on us or our liability assessment, all of which may change as the investigation progresses. We have had and expect to continue to have discussions with the DOJ regarding the Macondo well incident and associated pre-incident and post-incident conduct.
In November 2012, BP announced that it reached an agreement with the DOJ to resolve all federal criminal charges against it stemming from the Macondo well incident. BP agreed to plead guilty to 14 criminal charges, with 13 of those charges based on the negligent misinterpretation of the negative-pressure test conducted on the Deepwater Horizon. BP also agreed to pay $4.0 billion, including approximately $1.3 billion in criminal fines, to take actions to further enhance the safety of drilling operations in the Gulf of Mexico, to a term of five years' probation, and to the appointment of two monitors with four-year terms, one relating to process safety and risk management procedures concerning deepwater drilling in the Gulf of Mexico and one relating to the improvement, implementation, and enforcement of BP's code of conduct.

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In January 2013, Transocean announced that it reached an agreement with the DOJ to resolve certain claims for civil penalties and potential criminal claims against it arising from the Macondo well incident. Transocean agreed to plead guilty to one misdemeanor violation of the CWA for negligent discharge of oil into the Gulf of Mexico, to pay $1.0 billion in CWA penalties and $400 million in fines and recoveries, to implement certain measures to prevent a recurrence of an uncontrolled discharge of hydrocarbons, and to a term of five years' probation. Transocean's civil and criminal settlements are subject to court approval, and its civil settlement is also subject to public notice and comment.
Litigation. Since April 21, 2010, plaintiffs have been filing lawsuits relating to the Macondo well incident. Generally, those lawsuits allege either (1) damages arising from the oil spill pollution and contamination (e.g., diminution of property value, lost tax revenue, lost business revenue, lost tourist dollars, inability to engage in recreational or commercial activities) or (2) wrongful death or personal injuries. We are named along with other unaffiliated defendants in more than 400 complaints, most of which are alleged class actions, involving pollution damage claims and at least seven 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. Plaintiffs originally filed the lawsuits described above in federal and state courts throughout the United States. Except for certain lawsuits not yet consolidated, the Judicial Panel on Multi-District Litigation ordered all of the lawsuits against us consolidated in the MDL proceeding before Judge Carl Barbier in the United States Eastern District of Louisiana. The pollution complaints generally allege, among other things, negligence and gross negligence, property damages, taking of protected species, and potential economic losses as a result of environmental pollution and generally seek awards of unspecified economic, compensatory, and punitive damages, as well as injunctive relief. Plaintiffs in these pollution cases have brought suit under various legal provisions, including the OPA, the CWA, the MBTA, the ESA, the OCSLA, the Longshoremen and Harbor Workers Compensation Act, general maritime law, state common law, and various state environmental and products liability statutes.
Furthermore, the pollution complaints include suits brought against us by governmental entities, including the State of Alabama, the State of Louisiana, Plaquemines Parish, the City of Greenville, and three Mexican states. Complaints brought against us by at least seven other parishes in Louisiana were dismissed with prejudice, and the dismissal is being appealed by those parishes. The wrongful death and other personal injury complaints generally allege negligence and gross negligence and seek awards of compensatory damages, including unspecified economic damages, and punitive damages. We have retained counsel and are investigating and evaluating the claims, the theories of recovery, damages asserted, and our respective defenses to all of these claims.
Judge Barbier is also presiding over a separate proceeding filed by Transocean under the Limitation of Liability Act (Limitation Action). In the Limitation Action, Transocean seeks to limit its liability for claims arising out of the Macondo well incident to the value of the rig and its freight. While the Limitation Action has been formally consolidated into the MDL, the court is nonetheless, in some respects, treating the Limitation Action as an associated but separate proceeding. In February 2011, Transocean tendered us, along with all other defendants, into the Limitation Action. As a result of the tender, we and all other defendants will be treated as direct defendants to the plaintiffs’ claims as if the plaintiffs had sued us and the other defendants directly. In the Limitation Action, the judge intends to determine the allocation of liability among all defendants in the hundreds of lawsuits associated with the Macondo well incident, including those in the MDL proceeding that are pending in his court. Specifically, we believe the judge will determine the liability, limitation, exoneration, and fault allocation with regard to all of the defendants in a trial, which is scheduled to occur in at least two phases beginning on February 25, 2013. The first phase of this portion of the trial is scheduled to cover issues arising out of the conduct and degree of culpability of various parties allegedly relevant to the loss of well control, the ensuing fire and explosion on and sinking of the Deepwater Horizon, and the initiation of the release of hydrocarbons from the Macondo well. The MDL court has projected September 2013 for the beginning of the second phase of this portion of the trial, which is scheduled to cover actions relating to attempts to control the flow of hydrocarbons from the well and the quantification of hydrocarbons discharged from the well. Subsequent proceedings would be held to the extent triable issues remain unsolved by the first two phases of the trial, settlements, motion practice, or stipulation. While the DOJ will participate in the first two phases of the trial with regard to BP's conduct and the amount of hydrocarbons discharged from the well, it is anticipated that the DOJ's civil action for the CWA and OPA violations, fines, and penalties will be addressed by the court in a subsequent proceeding. We do not believe that a single apportionment of liability in the Limitation Action is properly applied, particularly with respect to gross negligence and punitive damages, to the hundreds of lawsuits pending in the MDL proceeding.
Damages for the cases tried in the MDL proceeding, including punitive damages, are expected to be tried following the two phases of the trial described above. Under ordinary MDL procedures, such cases would, unless waived by the respective parties, be tried in the courts from which they were transferred into the MDL. It remains unclear, however, what impact the overlay of the Limitation Action will have on where these matters are tried. Document discovery and depositions among the parties to the MDL are ongoing.

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In April and May 2011, certain defendants in the proceedings described above filed numerous cross claims and third party claims against certain other defendants. BP Exploration and BP America Production Company filed claims against us seeking subrogation, contribution, including with respect to liabilities under the OPA, and direct damages, and alleging negligence, gross negligence, fraudulent conduct, and fraudulent concealment. Transocean filed claims against us seeking indemnification, and subrogation and contribution, including with respect to liabilities under the OPA and for the total loss of the Deepwater Horizon, and alleging comparative fault and breach of warranty of workmanlike performance. Anadarko filed claims against us seeking tort indemnity and contribution, and alleging negligence, gross negligence and willful misconduct, and MOEX Offshore 2007 LLC (MOEX), who had an approximate 10% interest in the Macondo well at the time of the incident, filed a claim against us alleging negligence. Cameron International Corporation (Cameron) (the manufacturer and designer of the blowout preventer), M-I Swaco (provider of drilling fluids and services, among other things), Weatherford U.S. L.P. and Weatherford International, Inc. (together, Weatherford) (providers of casing components, including float equipment and centralizers, and services), and Dril-Quip, Inc. (Dril-Quip) (provider of wellhead systems), each filed claims against us seeking indemnification and contribution, including with respect to liabilities under the OPA in the case of Cameron, and alleging negligence. Additional civil lawsuits may be filed against us. In addition to the claims against us, generally the defendants in the proceedings described above filed claims, including for liabilities under the OPA and other claims similar to those described above, against the other defendants described above. BP has since announced that it has settled those claims between it and each of MOEX, Weatherford, Anadarko, and Cameron. Also, BP and M-I Swaco have dismissed all claims between them.
In April 2011, we filed claims against BP Exploration, BP p.l.c. and BP America Production Company (BP Defendants), M-I Swaco, Cameron, Anadarko, MOEX, Weatherford, Dril-Quip, and numerous entities involved in the post-blowout remediation and response efforts, in each case seeking contribution and indemnification and alleging negligence. Our claims also alleged gross negligence and willful misconduct on the part of the BP Defendants, Anadarko, and Weatherford. We also filed claims against M-I Swaco and Weatherford for contractual indemnification, and against Cameron, Weatherford and Dril-Quip for strict products liability, although the court has since issued orders dismissing all claims asserted against Dril-Quip and Weatherford in the MDL and we have dismissed our contractual indemnification claim against M-I Swaco. We filed our answer to Transocean’s Limitation petition denying Transocean’s right to limit its liability, denying all claims and responsibility for the incident, seeking contribution and indemnification, and alleging negligence and gross negligence.
Judge Barbier has issued an order, among others, clarifying certain aspects of law applicable to the lawsuits pending in his court. The court ruled that: (1) general maritime law will apply and therefore dismissed all claims brought under state law causes of action; (2) general maritime law claims may be brought directly against defendants who are non-“responsible parties” under the OPA with the exception of pure economic loss claims by plaintiffs other than commercial fishermen; (3) all claims for damages, including pure economic loss claims, may be brought under the OPA directly against responsible parties; and (4) punitive damage claims can be brought against both responsible and non-responsible parties under general maritime law. As discussed above, with respect to the ruling that claims for damages may be brought under the OPA against responsible parties, we have not been named as a responsible party under the OPA, but BP Exploration has filed a claim against us for contribution with respect to liabilities incurred by BP Exploration under the OPA.
In September 2011, we filed claims in Harris County, Texas against the BP Defendants seeking damages, including lost profits and exemplary damages, and alleging negligence, grossly negligent misrepresentation, defamation, common law libel, slander, and business disparagement. Our claims allege that the BP Defendants knew or should have known about an additional hydrocarbon zone in the well that the BP Defendants failed to disclose to us prior to our designing the cement program for the Macondo well. The location of the hydrocarbon zones is critical information required prior to performing cementing services and is necessary to achieve desired cement placement. We believe that had the BP Defendants disclosed the hydrocarbon zone to us, we would not have proceeded with the cement program unless it was redesigned, which likely would have required a redesign of the production casing. In addition, we believe that the BP Defendants withheld this information from the report of BP's internal investigation team and from the various investigations discussed above. In connection with the foregoing, we also moved to amend our claims against the BP Defendants in the MDL proceeding to include fraud. The BP Defendants have denied all of the allegations relating to the additional hydrocarbon zone and filed a motion to prevent us from adding our fraud claim in the MDL. In October 2011, our motion to add the fraud claim against the BP Defendants in the MDL proceeding was denied. The court’s ruling does not, however, prevent us from using the underlying evidence in our pending claims against the BP Defendants.
In December 2011, BP filed a motion for sanctions against us alleging, among other things, that we destroyed evidence relating to post-incident testing of the foam cement slurry on the Deepwater Horizon and requesting adverse findings against us. The magistrate judge in the MDL proceeding denied BP’s motion. BP appealed that ruling, and Judge Barbier affirmed the magistrate judge’s decision.

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In April 2012, BP announced that it had reached definitive settlement agreements with the PSC to resolve the substantial majority of eligible private economic loss and medical claims stemming from the Macondo well incident. The PSC acts on behalf of individuals and business plaintiffs in the MDL. BP has estimated that the cost of the settlements would be approximately $8.5 billion, including payments to claimants who opt out of the settlements, administration costs, and plaintiffs’ attorneys’ fees and expenses, and has stated that it is possible the actual cost could be higher. According to BP, the settlements do not include claims against BP made by the DOJ or other federal agencies or by states and local governments. In addition, the settlements provide that, to the extent permitted by law, BP will assign to the settlement class certain of its claims, rights, and recoveries against Transocean and us for damages, including BP's alleged direct damages such as damages for clean-up expenses and damage to the well and reservoir. We do not believe that our contract with BP Exploration permits the assignment of certain claims to the settlement class without our consent. In April and May, 2012, BP and the PSC filed two settlement agreements and amendments with the MDL court, one agreement addressing economic claims and one agreement addressing medical claims, as well as numerous supporting documents and motions requesting that the court approve, among other things, the certification of the classes for both settlements and a schedule for holding a fairness hearing and approving the settlements. The MDL court has since confirmed certification of the classes for both settlements and granted final approval of the settlements. We objected to the settlements on the grounds set forth above, among other reasons. The MDL court held, however, that we, as a non-settling defendant, lacked standing to object to the settlements but noted that it did not express any opinion as to the validity of BP's assignment of certain claims to the settlement class and that the settlements do not affect any of our procedural or substantive rights in the MDL. We are unable to predict at this time the effect that the settlements may have on claims against us.
In October 2012, the MDL court issued an order dismissing three types of plaintiff claims: (1) claims by or on behalf of owners, lessors, and lessees of real property that allege to have suffered a reduction in the value of real property even though the property was not physically touched by oil and the property was not sold; (2) claims for economic losses based solely on consumers' decisions not to purchase fuel or goods from BP fuel stations and stores based on consumer animosity toward BP; and (3) claims by or on behalf of recreational fishermen, divers, beachgoers, boaters and others that allege damages such as loss of enjoyment of life from their inability to use portions of the Gulf of Mexico for recreational and amusement purposes. The MDL court also noted that we are not liable with respect to those claims under the OPA because we are not a “responsible party” under OPA.
We intend to vigorously defend any litigation, fines, and/or penalties relating to the Macondo well incident and to vigorously pursue any damages, remedies, or other rights available to us as a result of the Macondo well incident. We have incurred and expect to continue to incur significant legal fees and costs, some of which we expect to be covered by indemnity or insurance, as a result of the numerous investigations and lawsuits relating to the incident.
Macondo derivative case. In February 2011, a shareholder who had previously made a demand on our Board of Directors with respect to another derivative lawsuit filed a shareholder derivative lawsuit relating to the Macondo well incident. In 2012, we settled those lawsuits and the cases were dismissed. See “Shareholder derivative cases” below.
Indemnification and Insurance. 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, including those resulting from pollution or contamination (other than claims by our employees, loss or damage to our property, and any pollution emanating directly from our equipment). Also, under our contract with BP Exploration, we have, among other things, generally agreed to indemnify BP Exploration and other contractors performing work on the well for claims for personal injury of our employees and subcontractors, as well as for damage to our property. In turn, we believe that BP Exploration was obligated to obtain agreement by other contractors performing work on the well to indemnify us for claims for personal injury of their employees or subcontractors, as well as for damages to their property. We have entered into separate indemnity agreements with Transocean and M-I Swaco, under which we have agreed to indemnify those parties for claims for personal injury of our employees and subcontractors and they have agreed to indemnify us for claims for personal injury of their employees and subcontractors.
In April 2011, we filed a lawsuit against BP Exploration in Harris County, Texas to enforce BP Exploration’s contractual indemnity and alleging BP Exploration breached certain terms of the contractual indemnity provision. BP Exploration removed that lawsuit to federal court in the Southern District of Texas, Houston Division. We filed a motion to remand the case to Harris County, Texas, and the lawsuit was transferred to the MDL.
BP Exploration, in connection with filing its claims with respect to the MDL proceeding, asked that 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 discussed above have generally denied any obligation to contribute to any liabilities arising from the Macondo well incident.

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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 did not express an opinion as to whether our conduct amounted to gross negligence, but we do not believe the performance of our services on the Deepwater Horizon constituted gross negligence. The court also held, however, that BP does not owe us indemnity for punitive damages or for civil penalties under the CWA, if any, and that fraud could void the indemnity on public policy grounds, although the court stated that it was mindful that mere failure to perform contractual obligations as promised does not constitute fraud. As discussed above, the DOJ is not seeking civil penalties from us under the CWA. The court in the MDL proceeding deferred ruling on whether our indemnification from BP covers penalties or fines under the OCSLA, 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. We do not believe that we breached our contract with BP Exploration or committed an act that would otherwise invalidate the indemnity. The court’s rulings will be subject to appeal at the appropriate time.
In responding to similar motions for summary judgment between Transocean and BP, the court also held that public policy would not bar Transocean’s claim for indemnification of compensatory damages, even if Transocean was found to be grossly negligent. The court also held, among other things, that Transocean’s contractual right to indemnity does not extend to punitive damages or civil penalties under the CWA.
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.
In addition to the contractual indemnities discussed above, we have a general liability insurance program of $600 million. Our insurance is designed to cover claims by businesses and individuals made against us in the event of property damage, injury, or death and, among other things, claims relating to environmental damage, as well as legal fees incurred in defending against those claims. We have received and expect to continue to receive payments from our insurers with respect to covered legal fees incurred in connection with the Macondo well incident. Through December 31, 2012, we have incurred legal fees and related expenses of approximately $175 million, of which $158 million has been reimbursed under or is expected to be covered by our insurance program. To the extent we incur any losses beyond those covered by indemnification, there can be no assurance that our insurance policies will cover all potential claims and expenses relating to the Macondo well incident. In addition, we may not be insured with respect to civil or criminal fines or penalties, if any, pursuant to the terms of our insurance policies. Insurance coverage can be the subject of uncertainties and, particularly in the event of large claims, potential disputes with insurance carriers, as well as other potential parties claiming insured status under 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 proceedings described above under “Litigation,” 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.
Barracuda-Caratinga arbitration
We agreed to provide indemnification in favor of our former subsidiary, KBR, Inc. (KBR), under the Master Separation Agreement for liabilities KBR may incur after November 20, 2006 as a result of certain allegedly defective subsea flowline bolts installed in connection with the Barracuda-Caratinga project. Prior to that, at the inception of the project, we provided a guarantee to Barracuda & Caratinga Leasing Company BV (BCLC), a subsidiary of our customer, Petrobras, of KBR's obligations with respect to the project. 
In March 2006, BCLC commenced arbitration against KBR claiming $220 million plus interest for the cost of monitoring and replacing the allegedly defective bolts and all related costs and expenses of the arbitration, including the cost of attorneys' fees. During the third quarter of 2011, an arbitration panel issued an award against KBR in the amount of approximately $201 million, plus post-judgment interest. BCLC filed a motion to confirm, and KBR filed a motion to vacate, the arbitration award with the United States District Court for the Southern District of New York. In December 2012, BCLC sent us a demand for payment of the arbitration award under the terms of our guarantee. In January 2013, the matter was resolved by our payment of $219 million to BCLC under the guarantee. BCLC has agreed that our obligations under the guarantee have been satisfied. See Note 7 for further discussion of the Barracuda-Caratinga matter.

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Securities and related litigation
In June 2002, a class action lawsuit was filed against us in federal court alleging violations of the federal securities laws after the SEC initiated an investigation in connection with our change in accounting for revenue on long-term construction projects and related disclosures. In the weeks that followed, approximately twenty similar class actions were filed against us. Several of those lawsuits also named as defendants several of our present or former officers and directors. The class action cases were later consolidated, and the amended consolidated class action complaint, styled Richard Moore, et al. v. Halliburton Company, et al., was filed and served upon us in April 2003. As a result of a substitution of lead plaintiffs, the case was styled Archdiocese of Milwaukee Supporting Fund (AMSF) v. Halliburton Company, et al. AMSF has changed its name to Erica P. John Fund, Inc. (the Fund). We settled with the SEC in the second quarter of 2004.
In June 2003, the lead plaintiffs filed a motion for leave to file a second amended consolidated complaint, which was granted by the court. In addition to restating the original accounting and disclosure claims, the second amended consolidated complaint included claims arising out of our 1998 acquisition of Dresser Industries, Inc., including that we failed to timely disclose the resulting asbestos liability exposure.
In April 2005, the court appointed new co-lead counsel and named the Fund the new lead plaintiff, directing that it file a third consolidated amended complaint and that we file our motion to dismiss. The court held oral arguments on that motion in August 2005. In March 2006, the court entered an order in which it granted the motion to dismiss with respect to claims arising prior to June 1999 and granted the motion with respect to certain other claims while permitting the Fund to re-plead some of those claims to correct deficiencies in its earlier complaint. In April 2006, the Fund filed its fourth amended consolidated complaint. We filed a motion to dismiss those portions of the complaint that had been re-pled. A hearing was held on that motion in July 2006, and in March 2007 the court ordered dismissal of the claims against all individual defendants other than our Chief Executive Officer (CEO). The court ordered that the case proceed against our CEO and us.
In September 2007, the Fund filed a motion for class certification, and our response was filed in November 2007. The district court held a hearing in March 2008, and issued an order November 3, 2008 denying the motion for class certification. The Fund appealed the district court’s order to the Fifth Circuit Court of Appeals. The Fifth Circuit affirmed the district court’s order denying class certification. On May 13, 2010, the Fund filed a writ of certiorari in the United States Supreme Court. In January 2011, the Supreme Court granted the writ of certiorari and accepted the appeal. The Court heard oral arguments in April 2011 and issued its decision in June 2011, reversing the Fifth Circuit ruling that the Fund needed to prove loss causation in order to obtain class certification. The Court’s ruling was limited to the Fifth Circuit’s loss causation requirement, and the case was returned to the Fifth Circuit for further consideration of our other arguments for denying class certification. The Fifth Circuit returned the case to the district court, and in January 2012 the court issued an order certifying the class. We filed a Petition for Leave to Appeal with the Fifth Circuit, which was granted and the case is stayed at the district court pending this appeal. The Fifth Circuit is set to hear oral argument in the appeal in March 2013. In spite of its age, the case is at an early stage, and we cannot predict the outcome or consequences thereof. We intend to vigorously defend this case.
Shareholder derivative cases
In May 2009, two shareholder derivative lawsuits involving us and KBR were filed in Harris County, Texas, naming as defendants various current and retired Halliburton directors and officers and current KBR directors. These cases allege that the individual Halliburton defendants violated their fiduciary duties of good faith and loyalty, to our detriment and the detriment of our shareholders, by failing to properly exercise oversight responsibilities and establish adequate internal controls. The District Court consolidated the two cases, and the plaintiffs filed a consolidated petition against only current and former Halliburton directors and officers containing various allegations of wrongdoing including violations of the FCPA, claimed KBR offenses while acting as a government contractor in Iraq, claimed KBR offenses and fraud under United States government contracts, Halliburton activity in Iran, and illegal kickbacks. Subsequently, a shareholder made a demand that the Board take remedial action respecting the FCPA claims in the pending lawsuit. Our Board of Directors designated a special committee of certain independent and disinterested directors to oversee the investigation of the allegations made in the lawsuits and shareholder demand. Upon receipt of the special committee’s findings and recommendations, the independent and disinterested members of the Board determined that the shareholder claims were without merit and not otherwise in our best interest to pursue. The Board directed our counsel to report its determinations to the plaintiffs and demanding shareholder.
In 2012, we agreed to settle the consolidated lawsuit, and the court approved the settlement and dismissed the case. Pursuant to the settlement, we paid the plaintiffs' legal fees which were not material to our consolidated financial statements, and we have implemented certain changes to our corporate governance policies.

24



In February 2011, the same shareholder who had made the demand on our Board of Directors in connection with one of the derivative lawsuits discussed above filed a shareholder derivative lawsuit in Harris County, Texas naming us as a nominal defendant and certain of our directors and officers as defendants. This case alleges that these defendants, among other things, breached fiduciary duties of good faith and loyalty by failing to properly exercise oversight responsibilities and establish adequate internal controls, including controls and procedures related to cement testing and the communication of test results, as they relate to the Macondo well incident. Our Board of Directors designated a special committee of certain independent and disinterested directors to oversee the investigation of the allegations made in the lawsuit and shareholder demand. Upon receipt of the special committee’s findings and recommendations, the independent and disinterested members of the Board determined that the shareholder claims were without merit and not otherwise in our best interest to pursue. The Board directed our counsel to report its determinations to the plaintiffs and demanding shareholder.
In 2012, we agreed to settle this lawsuit, and the court approved the settlement and dismissed the case. Pursuant to the settlement, we paid the plaintiffs' legal fees which were not material to our consolidated financial statements, and we have implemented certain changes to our corporate governance and health, safety, and environmental policies.
Investigations
We are conducting internal investigations of certain areas of our operations in Angola and Iraq, focusing on compliance with certain company policies, including our Code of Business Conduct (COBC), and the FCPA and other applicable laws.
In December 2010, we received an anonymous e-mail alleging that certain current and former personnel violated our COBC and the FCPA, principally through the use of an Angolan vendor. The e-mail also alleges conflicts of interest, self-dealing, and the failure to act on alleged violations of our COBC and the FCPA. We contacted the DOJ to advise them that we were initiating an internal investigation.
Since the third quarter of 2011, we have been participating in meetings with the DOJ and the SEC to brief them on the status of our investigation and have been producing documents to them both voluntarily and as a result of SEC subpoenas to the company and certain of our current and former officers and employees.
During the second quarter of 2012, in connection with a meeting with the DOJ and the SEC regarding the above investigation, we advised the DOJ and the SEC that we were initiating unrelated, internal investigations into payments made to a third-party agent relating to certain customs matters in Angola and to third-party agents relating to certain customs and visa matters in Iraq.
We expect to continue to have discussions with the DOJ and the SEC regarding the Angola and Iraq matters described above and have indicated that we would further update them as our investigations progress. We have engaged outside counsel and independent forensic accountants to assist us with the investigations. We intend to continue to cooperate with the DOJ's and the SEC's inquiries and requests in these investigations. Because these investigations are ongoing, we cannot predict their outcome or the consequences thereof.
Environmental
We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide. In the United States, these laws and regulations include, among others:
-
the Comprehensive Environmental Response, Compensation, and Liability Act;
-
the Resource Conservation and Recovery Act;
-
the Clean Air Act;
-
the Federal Water Pollution Control Act;
-
the Toxic Substances Control Act; and
-
the OPA.
In addition to the federal laws and regulations, states and other countries where we do business often have numerous environmental, legal, and regulatory requirements by which we must abide. We evaluate and address the environmental impact of our operations by assessing and remediating contaminated properties in order to avoid future liabilities and comply with environmental, legal, and regulatory requirements. Our Health, Safety and Environment group has several programs in place to maintain environmental leadership and to help prevent the occurrence of environmental contamination. On occasion, in addition to the matters relating to the Macondo well incident described above and the Duncan, Oklahoma matter described below, we are involved in other environmental litigation and claims, including the remediation of properties we own or have operated, as well as efforts to meet or correct compliance-related matters. We do not expect costs related to those claims and remediation requirements to have a material adverse effect on our liquidity, consolidated results of operations, or consolidated financial position. Because our estimated liability is typically within a range and our accrued liability may be the amount on the low end of that range, our actual liability could eventually be well in excess of the amount accrued.

25



In November 2012, the Company received an Enforcement Notice from the Pennsylvania Department of Environmental Protection (PADEP) regarding an alleged improper disposal of oil field acid in or around Homer City, Pennsylvania between 1999 and 2011. We are currently negotiating with the PADEP to resolve this matter in an amicable manner. We expect the PADEP to assess a penalty in excess of $100,000. We do not expect this matter to have a material adverse effect on our liquidity, consolidated results of operations, or consolidated financial position.
Between approximately 1965 and 1991, one or more former Halliburton units performed work (as a contractor or subcontractor) for the U.S. Department of Defense cleaning solid fuel from missile motor casings at a semi-rural facility on the north side of Duncan, Oklahoma. In addition, from approximately November 1983 through December 1985, a discrete portion of the site was used to conduct a recycling project on stainless steel nuclear fuel rod racks from Omaha Public Power District’s Fort Calhoun Station. We closed the site in coordination with the Oklahoma Department of Environmental Quality (DEQ) in the mid-1990s, but continued to monitor the groundwater at the DEQ’s request. A principal component of the missile fuel was ammonium perchlorate, a salt that is highly soluble in water, which has been discovered in the soil and groundwater on our site and in certain residential water wells near our property. In August 2011, we entered into the DEQ’s Voluntary Cleanup Program and executed a voluntary Memorandum of Agreement and Consent Order for Site Characterization and Risk Based Remediation with the DEQ relating to the remediation of this site.
Commencing in October 2011, a number of lawsuits were filed against us, including a putative class action case in federal court in the Western District of Oklahoma and other lawsuits filed in Oklahoma state courts. The lawsuits generally allege, among other things, that operations at our Duncan facility caused releases of pollutants, including ammonium perchlorate and, in the case of the federal lawsuit, nuclear or radioactive waste, into the groundwater, and that we knew about those releases and did not take corrective actions to address them. It is also alleged that the plaintiffs have suffered from certain health conditions, including hypothyroidism, a condition that has been associated with exposure to perchlorate at sufficiently high doses over time. These cases seek, among other things, damages, including punitive damages, and the establishment of a fund for future medical monitoring. The cases allege, among other things, strict liability, trespass, private nuisance, public nuisance, and negligence and, in the case of the federal lawsuit, violations of the U.S. Resource Conservation and Recovery Act (RCRA), resulting in personal injuries, property damage, and diminution of property value.
The lawsuits generally allege that the cleaning of the missile casings at the Duncan facility contaminated the surrounding soils and groundwater, including certain water wells used in a number of residential homes, through the migration of, among other things, ammonium perchlorate. The federal lawsuit also alleges that our processing of radioactive waste from a nuclear power plant over 25 years ago resulted in the release of “nuclear/radioactive” waste into the environment. In April 2012, the judge in the federal lawsuit dismissed the plaintiffs’ RCRA claim. The other claims brought in that lawsuit remain pending.
To date, soil and groundwater sampling relating to the allegations discussed above has confirmed that the alleged nuclear or radioactive material is confined to the soil in a discrete area of the onsite operations and is not presently believed to be in the groundwater onsite or in any areas offsite. The radiological impacts from this discrete area are not believed to present any health risk for offsite exposure. With respect to ammonium perchlorate, we have made arrangements to supply affected residents with bottled drinking water and, if needed, with access to temporary public water supply lines, at no cost to the residents. We have worked with the City of Duncan and the DEQ to expedite expansion of the city water supply to the relevant areas at our expense.
The lawsuits described above are at an early stage, and additional lawsuits and proceedings may be brought against us. We cannot predict their outcome or the consequences thereof. As of December 31, 2012, we had accrued $25 million related to our initial estimate of response efforts, third-party property damage, and remediation related to the Duncan, Oklahoma matter. We intend to vigorously defend the lawsuits and do not believe that these lawsuits will have a material adverse effect on our liquidity, consolidated results of operations, or consolidated financial condition.
Additionally, we have subsidiaries that have been named as potentially responsible parties along with other third parties for nine federal and state superfund sites for which we have established reserves. As of December 31, 2012, those nine sites accounted for approximately $6 million of our $72 million total environmental reserve. Despite attempts to resolve these superfund matters, the relevant regulatory agency may at any time bring suit against us for amounts in excess of the amount accrued. With respect to some superfund sites, we have been named a potentially responsible party by a regulatory agency; however, in each of those cases, we do not believe we have any material liability. We also could be subject to third-party claims with respect to environmental matters for which we have been named as a potentially responsible party.

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.

26



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 87 of this annual report. Cash dividends on our common stock in the amount of $0.09 per share were paid in March, June, September, and December of 2012 and 2011. Our Board of Directors intends to consider the payment of quarterly dividends on the outstanding shares of our common stock in the future. The declaration and payment of future dividends, however, 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.
The following graph and table compare total shareholder return on our common stock for the five-year period ended December 31, 2012, 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, 2007, and the reinvestment of all dividends. The shareholder return set forth is not necessarily indicative of future performance.


 
December 31
 
2007
2008
2009
2010
2011
2012
Halliburton
$
100.00

$
48.54

$
81.66

$
112.12

$
95.54

$
97.11

Philadelphia Oil Service Index (OSX)
100.00

40.53

65.71

83.40

74.61

76.94

Standard & Poor’s 500 ® Index
100.00

63.00

79.68

91.70

93.61

108.59



27



At February 1, 2013, there were 15,458 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, 2012.
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
Maximum
Number (or
Approximate
Dollar Value) of
Shares that may yet
be Purchased Under the Program (b)
October 1 - 31
30,007
$33.44
$—
November 1 - 30
25,503
$31.58
$—
December 1 - 31
123,291
$33.66
$—
Total
178,801
$33.33
$1,731,208,803
(a)
All of the 178,801 shares purchased during the three-month period ended December 31, 2012 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 shares.
(b)
Our Board of Directors has authorized a plan to repurchase our common stock from time to time. During the fourth quarter of 2012, 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 86 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 30 through 49 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 47 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, 2012, 2011, and 2010
Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011, and 2010
Consolidated Balance Sheets at December 31, 2012 and 2011
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011, and 2010
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2012, 2011, and 2010
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.


28



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, 2012 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, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
See page 50 for Management’s Report on Internal Control Over Financial Reporting and page 51 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.

Item 9(b). Other Information.
None.


29



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

EXECUTIVE OVERVIEW

Financial results
During 2012, we produced revenue of $28.5 billion and operating income of $4.2 billion, reflecting an operating margin of 15%. Revenue increased $3.7 billion, or 15%, from 2011, while operating income decreased $578 million, or 12%, from 2011. Overall, revenue improved compared to 2011 due to higher drilling activity in oil and liquids-rich basins in North America, as well as increased activity in all our international regions. However, operating income decreased in 2012 primarily due to the escalating cost of guar gum (a blending additive used in our hydraulic fracturing process), pricing pressure in North America, and a $300 million, pre-tax, loss contingency for the Macondo well incident.
Business outlook
We continue to believe in the strength of the long-term fundamentals of our business. Energy demand is expected to increase in 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 supply uncertainties associated with geopolitical tensions in the Middle East. Furthermore, development of new resources is expected to be more complex, resulting in increasing service intensity.
In North America, the industry has experienced an activity shift from natural gas plays to oil and liquids-rich basins due to low natural gas prices resulting from continued strong natural gas production. As a result, operators have been optimizing their budgets by focusing on basins with better economics. For those customers remaining in natural gas basins, we have continued to provide services, despite lower margins. This has strengthened our relationships with those customers and positions us well for when natural gas activity rebounds. We anticipate further pricing pressure for our production enhancement services in 2013. To adapt, we plan to remain focused on capital and cost discipline for our pressure pumping businesses and currently intend to direct less capital toward the North America market in the coming year.
Our Gulf of Mexico business has reached record levels due to an increase in permit approvals for deepwater drilling and our increased market share. We remain optimistic about activity in the Gulf of Mexico as our customers adapt to new regulations and new permit approvals are issued. Also, additional deepwater rigs are expected to arrive in the Gulf of Mexico in 2013, which will provide us with further growth opportunities.
Outside of North America, revenue and operating income increased in 2012 compared to 2011. We expect to see gradual activity and pricing improvements in those international markets where we anticipate the addition of deepwater rigs and those in which we have made strategic investments in capital and technologies. We also believe that new international unconventional oil and natural gas projects may contribute to activity improvements in 2013.
We executed several key initiatives in 2012. These initiatives included increasing manufacturing production in the Eastern Hemisphere and reinventing our service delivery platform to lower our delivery costs. We plan to continue to invest in these initiatives in 2013. In addition, we plan to continue executing the following strategies:
-
increasing our market share in the more economic, unconventional plays 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 capital to accelerate growth opportunities. To that end, we are continuing to push our technology and manufacturing development, 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. In 2011, we launched a project in North America to redesign our frac of the future service delivery platform for services through the rollout of improved equipment designs and improved field procedures to reduce cost and improve efficiency;
-
expanding capabilities in mature fields to expand our service and consulting capabilities;
-
continuing to seek ways to be one of the most cost efficient service providers in the industry by using 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.”

30



Financial markets, liquidity, and capital resources
The global financial markets can potentially create additional risks for our business. We believe we have invested our cash balances conservatively and secured sufficient financing to help mitigate any near-term negative impact on our operations. For additional information, see “Liquidity and Capital Resources” and “Business Environment and Results of Operations.”


31



LIQUIDITY AND CAPITAL RESOURCES

We ended 2012 with cash and equivalents of $2.5 billion compared to $2.7 billion at December 31, 2011. As of December 31, 2012, $470 million of the $2.5 billion of cash and equivalents was held by our foreign subsidiaries that would be subject to tax if repatriated. If these funds are needed for our operations in the United States, we would be required to accrue and pay United States taxes to repatriate these funds. However, our intent is to permanently reinvest these funds outside of the United States and our current plans do not demonstrate a need to repatriate them to fund our United States operations. We also held $398 million of investments in fixed income securities (both short- and long-term) at December 31, 2012, compared to $150 million (short-term) at December 31, 2011, bringing our total cash and investment securities to $2.9 billion at December 31, 2012, which is essentially flat from the prior year.
Significant sources of cash
Cash flows provided by operating activities were $3.7 billion in 2012.
We sold $395 million of property, plant, and equipment during 2012.
Further available sources of cash. We have an unsecured $2.0 billion five-year revolving credit facility expiring in 2016. The purpose of the facility is to provide general working capital and credit for other corporate purposes. The full amount of the revolving credit facility was available as of December 31, 2012.
Significant uses of cash
Capital expenditures were $3.6 billion in 2012. The capital expenditures in 2012 were predominantly made in our production enhancement, drilling, cementing, and wireline and perforating product service lines. We have also invested additional working capital to support the growth of our business.
During 2012, our primary components of net working capital, receivables, inventories and accounts payable, increased by $1.1 billion, primarily due to increased business activity and delays in receiving payment on trade receivables from one of our primary customers in Venezuela. See "Customer receivables" below.
We paid $333 million of dividends to our shareholders in 2012.
During 2012, we purchased $248 million of investment securities, net of investment securities sold.
Future uses of cash. Capital spending for 2013 is currently expected to be approximately $3.0 billion. The capital expenditures plan for 2013 is primarily directed toward our production enhancement, drilling, cementing, Boots and Coots, and wireline and perforating product service lines. We currently intend to direct less capital toward the North America market in 2013 than we did during 2012.
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 large operations.
Subject to Board of Directors approval, we expect to pay quarterly dividends of approximately $83 million during 2013. We also have approximately $1.7 billion remaining available under our share repurchase authorization, which may be used for open market share purchases.
In January 2013, we made a $219 million payment to BCLC under a guarantee we issued for the Barracuda-Caratinga project. See Part I, Item 3, "Legal Proceedings – Barracuda-Caratinga Arbitration."
The following table summarizes our significant contractual obligations and other long-term liabilities as of December 31, 2012:
 
Payments Due
 
 
Millions of dollars
2013
2014
2015
2016
2017
Thereafter
Total
Long-term debt
$

$

$

$

$

$
4,820

$
4,820

Interest on debt (a)
275

276

281

284

288

5,432

6,836

Operating leases
287

214

146

102

48

164

961

Purchase obligations (b)
2,374

389

281

177

152

42

3,415

Pension funding obligations (c)
27






27

Other long-term liabilities
14

4

3

3

3

7

34

Total
$
2,977

$
883

$
711

$
566

$
491

$
10,465

$
16,093

(a)
Interest on debt includes 84 years of interest on $300 million of debentures at 7.6% interest that become due in 2096.
(b)
Primarily represents certain purchase orders for goods and services utilized in the ordinary course of our business.
(c)
Includes international plans and is based on assumptions that are subject to change. We are currently not able to reasonably estimate our contributions for years after 2013.


32



We had $296 million of gross unrecognized tax benefits at December 31, 2012, of which we estimate $124 million may require a cash payment. We estimate that $99 million of the cash payment will not be settled within the next 12 months. We are not able to reasonably estimate in which future periods this amount will ultimately be settled and paid.
Other factors affecting liquidity
Financial position in current market. As of December 31, 2012, we had $2.5 billion of cash and equivalents and $398 million in fixed income securities. We also had $2.0 billion of available committed bank credit under our revolving credit facility. 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 any capital expenditures, working capital investments, and dividends in 2013 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 above in Part I, Item 3, “Legal Proceedings,” 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 $1.9 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of December 31, 2012, including $277 million of surety bonds related to Venezuela. See “Business Environment and Results of Operations – International Operations” for further discussion related to Venezuela. 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. For example, we continue to see delays in receiving payment on our receivables from one of our primary customers in Venezuela. Our total outstanding trade receivables in Venezuela at December 31, 2012 were $491 million, which represents approximately 9% of our gross trade receivables at that date. 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” for further discussion related to Venezuela.



33



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. The majority 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 2012, 2011, and 2010, based on the location of services provided and products sold, 53%, 55%, and 46% 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 major, national, and independent oil and natural gas companies. Also impacting our activity is the status of the global economy, which impacts oil and natural gas consumption.
Some of the more significant measures of current and future spending levels of oil and natural gas companies 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.
This table shows the average oil and natural gas prices for West Texas Intermediate (WTI), United Kingdom Brent crude oil, and Henry Hub natural gas:
Average Oil Prices (dollars per barrel)
2012
2011
2010
West Texas Intermediate
$
94.15

$
95.13

$
79.36

United Kingdom Brent
111.60

111.53

79.66

 
 
 
 
Average United States Natural Gas Prices (dollars per thousand cubic feet, or Mcf)
 
 
 
Henry Hub
$
2.81

$
4.09

$
4.52



34



The historical yearly average rig counts based on the Baker Hughes Incorporated rig count information were as follows:
Land vs. Offshore
2012
2011
2010
United States:
 
 
 
Land
1,872

1,843

1,509

Offshore (incl. Gulf of Mexico)
47

32

32

Total
1,919

1,875

1,541

Canada:
 

 

 

Land
363

422

349

Offshore
1

1

2

Total
364

423

351

International (excluding Canada):
 
 
 
Land
931

863

789

Offshore
303

304

305

Total
1,234

1,167

1,094

Worldwide total
3,517

3,465

2,986

Land total
3,166

3,128

2,647

Offshore total
351

337

339

 
 
 
 
Oil vs. Natural Gas
2012
2011
2010
United States (incl. Gulf of Mexico):
 
 
 
Oil
1,359

984

593

Natural gas
560

891

948

Total
1,919

1,875

1,541

Canada:
 
 
 
Oil
261

282

201

Natural gas
103

141

150

Total
364

423

351

International (excluding Canada):
 
 
 
Oil
984

918

840

Natural gas
250

249

254

Total
1,234

1,167

1,094

Worldwide total
3,517

3,465

2,986

Oil total
2,604

2,184

1,634

Natural gas total
913

1,281

1,352


Drilling Type
2012
2011
2010
United States (incl. Gulf of Mexico):
 
 
 
Horizontal
1,151
1,074
822
Vertical
552
571
501
Directional
216
230
218
Total
1,919
1,875
1,541

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. The opposite is true for higher oil and natural gas prices.

35



WTI oil prices, which generally influence customer spending in North America, have fluctuated throughout 2012, ranging from a high of $109 per barrel in February to a low of $78 per barrel in June. Outside of North America, customer spending is heavily influenced by Brent oil prices, which have fluctuated during 2012 from a high of $128 per barrel in March to a low of $89 per barrel in June. Prices were somewhat volatile as geopolitical tension in the Middle East, global economic uncertainty surrounding the European debt crisis, and slower growth expectations in China and Brazil impacted demand. The outlook for world petroleum demand for 2013 is mixed, with the International Energy Agency’s (IEA) January 2013 “Oil Market Report” forecasting a 1% increase in petroleum demand from 2012 levels. The IEA expects modest declines in mature economies to be more than offset by relatively strong growth in emerging markets, particularly in China.
Henry Hub natural gas prices declined during the first half of 2012 due to a mild winter and strong production levels associated with unconventional drilling activity. During the second half of 2012, decreased natural gas drilling activity resulted in lower natural gas storage injections relative to expectations. This, coupled with increased natural gas demand from the power generation sector due to a warm summer, resulted in higher natural gas prices. Natural gas prices during 2012 ranged from a low of $1.82 per Mcf in April to a high of $3.77 per Mcf in November. Near the end of 2012 and into early-2013, natural gas prices began to decline due to warmer than normal weather. The United States Energy Information Administration (EIA) January 2013 “Short Term Energy Outlook” forecast expects Henry Hub natural gas prices to average $3.74 per Mcf in 2013 compared to $2.81 per Mcf in 2012.
The outlook for activity thus faces some uncertainties as the global economy continues to recover. However, 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. In North America during 2012, the average natural gas directed rig count fell by 369 rigs, or 36%, from 2011, while the average oil directed rig count has increased by 354 rigs, or 28%, over the same period. The curtailment of natural gas drilling activity along with an influx of stimulation equipment into the industry have resulted in overcapacity and pricing pressure for hydraulic fracturing services, which we expect to persist through 2013. In addition, our higher priced guar inventory negatively impacted our margins for our Production Enhancement product service line in 2012.
Going forward, we expect North America rig count to grow from current levels but to average down slightly for the full year 2013 in comparison to the full year 2012. However, 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 2012, we saw average drilling days per horizontal well drop approximately 15% compared to 2011 and we anticipate continued efficiency improvement in 2013. 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, liquids-rich, and natural gas 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, deepwater drilling activity has returned to levels experienced before the Macondo incident. In some cases, the timing of our customers' projects was disrupted during the third quarter of 2012 due to Hurricane Issac. 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 2012, with the average international rig count improving 6% over 2011. These volume increases have led to a meaningful absorption of equipment supply and we are now seeing opportunities for price improvements in select geographies. However, we anticipate moderate margin improvements and gradual activity increases, although the operator spending outlook could be impacted by ongoing macroeconomic concerns.
We believe that international growth in 2013 will come from a combination of several factors, including volume increases as we ramp up on recent wins and new projects, from continued improvement in those markets where we have made strategic investments, from the introduction of new technology, and from 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. In December 2010, the Venezuelan government set the fixed exchange rate at 4.3 Bolívar Fuerte to one United States dollar effective January 1, 2011, eliminating the dual exchange rate scheme implemented in early 2010. This change had no impact on us because we have applied the 4.3 Bolívar Fuerte fixed exchange rate since the previously disclosed January 2010 devaluation.
On May 24, 2011, the United States government imposed sanctions on the state-owned oil company of Venezuela. The sanctions do not, however, apply to that company’s subsidiaries and do not prohibit the export of crude oil to the United States. We do not expect these sanctions to have a material impact on our operations in Venezuela.

36



As of December 31, 2012, our total net investment in Venezuela was approximately $328 million, including net monetary assets of $74 million denominated in Bolívar Fuerte. At December 31, 2012, our total outstanding trade receivables in Venezuela were $491 million, which represented approximately 9% of our gross trade receivables at that date. We continue to see delays in receiving payment on our receivables from our primary customer in Venezuela. In addition, at December 31, 2012 we had $277 million of surety bond guarantees outstanding relating to our Venezuelan operations.
In February 2013, the Venezuelan government announced a devaluation of the Bolívar Fuerte, from the preexisting exchange rate of 4.3 Bolívar Fuertes per United States dollar to 6.3 Bolívar Fuertes per United States dollar. As a result of the devaluation, we are estimating a foreign currency loss of approximately $30 million in the first quarter of 2013. The February devaluation did not impact our 2012 results of operations, financial position, or cash flows. Further devaluation of the Bolívar Fuerte could impact our operations. For additional information, see Part I, Item 1(a), “Risk Factors” in this Form 10-K.



37



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



38



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.

39



Completion and Production increase in revenue compared to 2011 was primarily a result of 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.
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
Interest expense, net of interest income increased $35 million in 2012 compared to 2011 primarily due to higher interest costs incurred resulting from our issuance of $1.0 billion of senior notes in the fourth quarter of 2011.
Other, net increased $14 million from 2011 due primarily to foreign currency fluctuations.
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 a $219 million payment we made to BCLC under that guarantee.


40



RESULTS OF OPERATIONS IN 2011 COMPARED TO 2010

REVENUE:
 
 
Favorable
Percentage
Millions of dollars
2011
2010
(Unfavorable)
Change
Completion and Production
$
15,143

$
9,997

$
5,146

51
 %
Drilling and Evaluation
9,686

7,976

1,710

21

Total revenue
$
24,829

$
17,973

$
6,856

38
 %

 
 
 
 
By geographic region:
 
 
 
 
Completion and Production:
 
 
 
 
North America
$
10,907

$
6,183

$
4,724

76
 %
Latin America
1,117

839

278

33

Europe/Africa/CIS
1,746

1,797

(51
)
(3
)
Middle East/Asia
1,373

1,178

195

17

Total
15,143

9,997

5,146

51

Drilling and Evaluation:
 
 
 
 
North America
3,506

2,644

862

33

Latin America
1,865

1,390

475

34

Europe/Africa/CIS
2,210

2,117

93

4

Middle East/Asia
2,105

1,825

280

15

Total
9,686

7,976

1,710

21

Total revenue by region:
 
 
 
 
North America
14,413

8,827

5,586

63

Latin America
2,982

2,229

753

34

Europe/Africa/CIS
3,956

3,914

42

1

Middle East/Asia
3,478

3,003

475

16



41



OPERATING INCOME:
 
 
Favorable
Percentage
Millions of dollars
2011
2010
(Unfavorable)
Change
Completion and Production
$
3,733

$
2,032

$
1,701

84
 %
Drilling and Evaluation
1,403

1,213

190

16

Corporate and other
(399
)
(236
)
(163
)
69

Total operating income
$
4,737

$
3,009

$
1,728

57
 %

 
 
 
 
By geographic region:
 
 
 
 
Completion and Production:
 
 
 
 
North America
$
3,341

$
1,423

$
1,918

135
 %
Latin America
159

115

44

38

Europe/Africa/CIS
48

301

(253
)
(84
)
Middle East/Asia
185

193

(8
)
(4
)
Total
3,733

2,032

1,701

84

Drilling and Evaluation:
 
 
 
 
North America
641

453

188

42

Latin America
305

175

130

74

Europe/Africa/CIS
191

283

(92
)
(33
)
Middle East/Asia
266

302

(36
)
(12
)
Total
1,403

1,213

190

16

Total operating income by region
 
 
 
 
(excluding Corporate and other):
 
 
 
 
North America
3,982

1,876

2,106

112

Latin America
464

290

174

60

Europe/Africa/CIS
239

584

(345
)
(59
)
Middle East/Asia
451

495

(44
)
(9
)

The 38% increase in consolidated revenue in 2011 compared to 2010 was primarily due to higher rig count and increased demand for our services and products in North America. We experienced a 63% increase in North America revenue compared to an approximate 21% increase in average North America rig count during 2011 compared to 2010. Revenue outside of North America was 42% of consolidated revenue in 2011 and 51% of consolidated revenue in 2010.
The 57% increase in consolidated operating income compared to 2010 was mainly due to improved pricing and increased demand in North America, particularly in our Completion and Production division. 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. Operating income in 2010 was adversely impacted by a $50 million non-cash impairment charge for an oil and natural gas property in Bangladesh.
Following is a discussion of our results of operations by reportable segment.
Completion and Production increase in revenue compared to 2010 was primarily a result of higher activity in North America. North America revenue rose 76%, primarily due to increased cementing services and higher activity in production enhancement from an increased demand for hydraulic fracturing in the United States. Latin America revenue increased 33% due to improved activity in all product service lines across the region. Europe/Africa/CIS revenue decreased 3%, as less activity in North Africa and lower vessel utilization in the North Sea and Nigeria was partially offset by higher activity in our Boots & Coots product service line in Angola and Norway. Middle East/Asia revenue grew 17% due to higher activity in all product service lines in Australia, Malaysia, and Indonesia, partially offset by lower completion tools sales in China. Revenue outside of North America was 28% of total segment revenue in 2011 and 38% of total segment revenue in 2010.

42



The Completion and Production segment operating income increase compared to 2010 was primarily due to the North America region, where operating income grew $1.9 billion on higher demand for production enhancement services in unconventional basins located in the United States land market. Latin America operating income increased 38% due to higher demand for cementing services in Colombia, Brazil, and Argentina, partially offset by higher costs and pricing adjustments in Mexico. Europe/Africa/CIS operating income declined 84% due to an impairment charge on an asset held for sale and activity disruptions in North Africa, including the Libya-related reserve for certain account receivables and inventory. Middle East/Asia operating income decreased 4% due to higher costs across most of the region and higher start-up costs associated with the commencement of work in Iraq, which were partially offset by higher activity levels in Australia, Malaysia, and Indonesia.
Drilling and Evaluation revenue increased 21% compared to 2010 as drilling activity improved across all regions, especially North America and Latin America. North America revenue grew 33% on substantial activity increases in the United States land market. Latin America revenue increased 34% due to higher demand in most product services lines in Brazil, Mexico, Venezuela, and Colombia. Europe/Africa/CIS revenue increased 4% due to improved drilling service in Angola, Nigeria, and Norway and increased fluid demand in Egypt, partially offset by lower activity in Libya. Middle East/Asia revenue rose 15% primarily due to the commencement of work in Iraq, increased fluid demand in Southeast Asia, and higher wireline direct sales. Revenue outside North America was 64% of total segment revenue in 2011 and 67% of total segment revenue in 2010.
Segment operating income compared to 2010 increased 16% due to increased activity in North America and Latin America, partially offset by lower activity associated with the disruptions in North Africa and less favorable pricing in the Eastern Hemisphere. North America operating income increased 42% from improved pricing and increased demand for most of our services and products. Latin America operating income grew 74% as a result of activity increases in Mexico, Venezuela, and Brazil. The Europe/Africa/CIS region operating income fell 33% due to costs associated with activity disruptions in North Africa, including the reserve charge for certain account receivables and inventory, partially offset by improved drilling service in Norway and Nigeria and higher fluid demand in Angola. Middle East/Asia operating income decreased 12% mainly due to start-up costs associated with the commencement of work in Iraq and higher costs in Saudi Arabia. Operating income in 2010 was adversely impacted by a $50 million non-cash impairment charge for an oil and natural gas property in Bangladesh.
Corporate and other expenses were $399 million, including a $37 million environmental-related matter in 2011, compared to $236 million in 2010. The 69% increase was primarily due to higher legal and environmental costs and additional expenses associated with strategic investments in our operating model and creating competitive advantages by repositioning our technology, supply chain, and manufacturing infrastructure.

NONOPERATING ITEMS
Interest expense, net of interest income decreased $34 million in 2011 compared to 2010 primarily due to less interest expense as a result of the retirement of $750 million principal amount of our 5.5% senior notes in October 2010 and lower interest rates on a portion of our debt as a result of our interest rate swaps. This was partially offset by higher interest costs incurred in the fourth quarter of 2011 resulting from our issuance of $1.0 billion of senior notes.
Other, net decreased $32 million from 2010 due to a $31 million loss on foreign currency exchange recognized in 2010 as a result of the devaluation of the Venezuelan Bolívar Fuerte.
Income (loss) from discontinued operations, net decreased $206 million in 2011 compared to 2010 primarily due to a $163 million charge, after-tax, recognized in 2011 related to a ruling in an arbitration proceeding between BCLC and our former subsidiary, KBR, whom we agreed to indemnify.


43



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, construction-type 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.

44



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.
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, 2012, we have accrued an estimate of the probable and estimable costs for the resolution of some of these 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. Beginning in 2011, we elected to perform a qualitative assessment for our annual goodwill impairment test. If the qualitative assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or if we elect to not perform a qualitative assessment, then we would be required to perform a quantitative impairment test for goodwill. 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. 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. Our goodwill impairment assessment for 2010 indicated the fair value of each of our reporting units exceeded its carrying amount by a significant margin. See Note 1 to the consolidated financial statements for accounting policies related to long-lived assets and intangible assets.



45



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.
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 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 weighted-average discount rate utilized in 2012 to determine the projected benefit obligation at the measurement date for our United Kingdom pension plan, which constituted 78% of our international plans’ pension obligations, was 4.6%, compared to a discount rate of 4.9% utilized in 2011. The expected long-term rate of return assumption used for our United Kingdom pension plan expense in 2012 and 2011 was 6.7%. 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 2012
Pension Benefit Obligation at December 31, 2012
25-basis-point decrease in discount rate
$
1

$
45

25-basis-point increase in discount rate
(1
)
(43
)
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 $26 million in 2012, $27 million in 2011, and $28 million in 2010. Included in these amounts was income from expected pension returns of $45 million in 2012, $47 million in 2011, and $43 million in 2010. Actual returns on international plan assets totaled $87 million in 2012, compared to $13 million in 2011. Our net actuarial loss, net of tax, related to international pension plans at December 31, 2012 was $208 million. In our international plans where employees earn additional benefits for continued service, actuarial gains and losses are being recognized in operating income over a period of 12 to 18 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 are being recognized in operating income over a period of one to 35 years, which represents the estimated average remaining lifetime of the benefit obligations. The broad range of one to 35 years reflects varying maturity levels among these plans.
During 2012, we made contributions of $24 million to fund our international defined benefit plans. We expect to make contributions of approximately $16 million to our international defined benefit plans in 2013.
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

46



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, 2012, allowance for bad debts totaled $92 million, or 1.6% of notes and accounts receivable before the allowance. At December 31, 2011, allowance for bad debts totaled $137 million, or 2.7% 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, 2012 would have resulted in a $58 million adjustment to 2012 total operating costs and expenses. See Note 3 to the consolidated financial statements for further information.
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. Currently, long-term contracts accounted for under the percentage-of-completion method of accounting do not comprise a significant portion of our business. See Note 1 to the consolidated financial statements for further information.

OFF BALANCE SHEET ARRANGEMENTS

At December 31, 2012, 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 – Significant uses of cash – Future uses of cash.”

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 exchange contracts 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 exchange contracts and interest rate swaps are global commercial and investment banks.
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.
Foreign currency exchange risk
We have operations in many international locations and are involved in transactions denominated in currencies other than the United States dollar, our functional currency, which exposes us to foreign currency exchange rate risk. Techniques in managing foreign currency exchange risk include, but are not limited to, foreign currency borrowing and investing and the use of currency derivative instruments. We attempt to selectively manage significant exposures to potential foreign currency exchange losses based on current market conditions, future operating activities, and the associated cost in relation to the perceived risk of loss. The purpose of our foreign currency risk management activities is to minimize the risk that our cash flows from the sale and purchase of services and products in foreign currencies will be adversely affected by changes in exchange rates.
We use forward exchange contracts to manage our exposure to fluctuations in the currencies of the countries in which we do the majority of our international business. These forward exchange contracts are not treated as hedges for accounting purposes, generally have an expiration date of one year or less, and are not exchange traded. While forward exchange contracts are subject to fluctuations in value, the fluctuations are generally offset by the value of the underlying exposures being managed. The use of some of these contracts may limit our ability to benefit from favorable fluctuations in foreign currency exchange rates.

47



Forward exchange contracts are not utilized to manage exposures in some currencies due primarily to the lack of available markets or cost considerations (non-traded currencies). We attempt to manage our working capital position to minimize foreign currency exposure in non-traded currencies and recognize that pricing for the services and products offered in these countries should account for the cost of exchange rate devaluations. We have historically incurred transaction losses in non-traded currencies.
The notional amounts of open forward exchange contracts were $324 million at December 31, 2012 and $268 million at December 31, 2011. The notional amounts of our forward exchange contracts do not generally represent amounts exchanged by the parties, and thus are not a measure of our exposure or of the cash requirements related to these contracts. As such, cash flows related to these contracts are typically not material. The amounts exchanged are calculated by reference to the notional amounts and by other terms of the contracts, such as exchange rates.
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, 2012 would result in a $75 million, pre-tax, loss for our net monetary assets denominated in currencies other than United States dollars.
Interest rate risk
We are subject to interest rate risk on our long-term debt and some of our long-term investments in fixed income securities. Our short-term investments in fixed income securities and short-term borrowings do not give rise to significant interest rate risk due to their short-term nature. We had fixed rate long-term debt totaling $4.8 billion at both December 31, 2012 and December 31, 2011, with none maturing before May 2017. We also had $128 million of long-term investments in fixed income securities at December 31, 2012 with maturities that extend through December 2015.
We maintain an interest rate management strategy that is intended to mitigate the exposure to changes in interest rates in the aggregate for our investment portfolio. We hold a series of interest rate swaps relating to two of our debt instruments with a total notional amount of $1.0 billion at a weighted-average, LIBOR-based, floating rate of 3.3% as of December 31, 2012. We utilize interest rate swaps to effectively convert a portion of our fixed rate debt to floating rates. These interest rate swaps, which expire when the underlying debt matures, are designated as fair value hedges of the underlying debt and are determined to be highly effective. The fair value of our interest rate swaps is included in “Other assets” in our consolidated balance sheets as of December 31, 2012 and December 31, 2011. The fair value of our interest rate swaps was determined using an income approach model with inputs, such as the notional amount, LIBOR rate spread, and settlement terms that are observable in the market or can be derived from or corroborated by observable data (Level 2). These derivative instruments are marked to market with gains and losses recognized currently in interest expense to offset the respective gains and losses recognized on changes in the fair value of the hedged debt. At December 31, 2012, we had fixed rate debt aggregating $3.8 billion and variable rate debt aggregating $1.0 billion, after taking into account the effects of the interest rate swaps. The fair value of our interest rate swaps was not material as of December 31, 2012 or December 31, 2011.
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, 2012.
Credit risk
Financial instruments that potentially subject us to concentrations of credit risk are primarily cash equivalents, investments in fixed income securities, and trade receivables. It is our practice to place our cash equivalents and investments in fixed income securities in high quality investments with various institutions. We derive the majority of our revenue from selling products and providing services to the energy industry. Within the energy industry, our trade receivables are generated from a broad and diverse group of customers, although a significant amount of our trade receivables are generated in the United States. We maintain an allowance for losses based upon the expected collectability of all trade accounts receivable.
We do not have any significant concentrations of credit risk with any individual counterparty to our derivative contracts. We select counterparties to those contracts based on our belief that each counterparty’s profitability, balance sheet, and capacity for timely payment of financial commitments is unlikely to be materially adversely affected by foreseeable events.

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, Part I, Item 1(a), “Risk Factors,” and Item 3, “Legal Proceedings – Environmental.”


48



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 the results of operations may vary materially.
We do not assume any responsibility to publicly update any of our forward-looking statements regardless of whether factors change as a result of new information, future events, or for any other reason. You should review any additional disclosures we make in our press releases and Forms 10-K, 10-Q, and 8-K filed with or furnished to the SEC. We also suggest that you listen to our quarterly earnings release conference calls with financial analysts.


49



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, 2012 based upon criteria set forth in the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that, as of December 31, 2012, our internal control over financial reporting is effective.
The effectiveness of Halliburton’s internal control over financial reporting as of December 31, 2012 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

50



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, 2012 and 2011, 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, 2012. 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, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2012, 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, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 11, 2013 expressed an unqualified opinion on the effectiveness of Halliburton Company's internal control over financial reporting.


/s/ KPMG LLP
Houston, Texas
February 11, 2013

51



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, 2012, based on criteria established in Internal Control - Integrated Framework 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, 2012, based on criteria established in Internal Control - Integrated Framework 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, 2012 and 2011, 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, 2012, and our report dated February 11, 2013 expressed an unqualified opinion on those consolidated financial statements.


/s/ KPMG LLP
Houston, Texas
February 11, 2013


52



HALLIBURTON COMPANY
Consolidated Statements of Operations

 
Year Ended December 31
Millions of dollars and shares except per share data
2012
2011
2010
Revenue:
 
 
 
Services
$
22,196

$
19,692

$
13,779

Product sales
6,307

5,137

4,194

Total revenue
28,503

24,829

17,973

Operating costs and expenses:
 
 
 
Cost of services
18,747

15,432

11,227

Cost of sales
5,322

4,379

3,508

General and administrative
275

281

229

Total operating costs and expenses
24,344

20,092

14,964

Operating income
4,159

4,737

3,009

Interest expense, net of interest income of $7, $5, and $11
(298
)
(263
)
(297
)
Other, net
(39
)
(25
)
(57
)
Income from continuing operations before income taxes
3,822

4,449

2,655

Provision for income taxes
(1,235
)
(1,439
)
(853
)
Income from continuing operations
2,587

3,010

1,802

Income (loss) from discontinued operations, net of income tax (provision) benefit of $82, $(18), and $75
58

(166
)
40

Net income
$
2,645

$
2,844

$
1,842

Noncontrolling interest in net income of subsidiaries
(10
)
(5
)
(7
)
Net income attributable to company
$
2,635

$
2,839

$
1,835

Amounts attributable to company shareholders:
 
 
 
Income from continuing operations
$
2,577

$
3,005

$
1,795

Income (loss) from discontinued operations, net
58

(166
)
40

Net income attributable to company
$
2,635

$
2,839

$
1,835

Basic income per share attributable to company shareholders:
 
 
 
Income from continuing operations
$
2.78

$
3.27

$
1.98

Income (loss) from discontinued operations, net
0.07

(0.18
)
0.04

Net income per share
$
2.85

$
3.09

$
2.02

Diluted income per share attributable to company shareholders:
 
 
 
Income from continuing operations
$
2.78

$
3.26

$
1.97

Income (loss) from discontinued operations, net
0.06

(0.18
)
0.04

Net income per share
$
2.84

$
3.08

$
2.01

 
 
 
 
Basic weighted average common shares outstanding
926

918

908

Diluted weighted average common shares outstanding
928

922

911

See notes to consolidated financial statements.
 
 
 


53



HALLIBURTON COMPANY
Consolidated Statements of Comprehensive Income

 
Year Ended December 31
Millions of dollars
2012
2011
2010
Net income
$
2,645

$
2,844

$
1,842

Other comprehensive income, net of income taxes:
 
 
 
Defined benefit and other postretirement plans adjustments
(33
)
(34
)
(27
)
Other
(3
)

(1
)
Other comprehensive loss, net of income taxes
(36
)
(34
)
(28
)
Comprehensive income
$
2,609

$
2,810

$
1,814

Comprehensive loss attributable to noncontrolling interest
(10
)
(4
)
(6
)
Comprehensive income attributable to company shareholders
$
2,599

$
2,806

$
1,808

See notes to consolidated financial statements.
 
 
 



54



HALLIBURTON COMPANY
Consolidated Balance Sheets

 
December 31
Millions of dollars and shares except per share data
2012
2011
Assets
Current assets:
 
 
Cash and equivalents
$
2,484

$
2,698

Receivables (less allowance for bad debts of $92 and $137)
5,787

5,084

Inventories
3,186

2,570

Current deferred income taxes
351

321

Other current assets
1,278

904

Total current assets
13,086

11,577

Property, plant, and equipment, net of accumulated depreciation of $8,056 and $7,096
10,257

8,492

Goodwill
2,135

1,776

Other assets
1,932

1,832

Total assets
$
27,410

$
23,677

Liabilities and Shareholders’ Equity
Current liabilities:
 
 
Accounts payable
$
2,041

$
1,826

Accrued employee compensation and benefits
930

862

Deferred revenue
307

309

Other current liabilities
1,474

1,124

Total current liabilities
4,752

4,121

Long-term debt
4,820

4,820

Employee compensation and benefits
607

534

Other liabilities
1,441

986

Total liabilities
11,620

10,461

Shareholders’ equity:
 
 
Common shares, par value $2.50 per share – authorized 2,000 shares,
issued 1,073 and 1,073 shares
2,682

2,683

Paid-in capital in excess of par value
486

455

Accumulated other comprehensive loss
(309
)
(273
)
Retained earnings
17,182

14,880

Treasury stock, at cost – 144 and 152 shares
(4,276
)
(4,547
)
Company shareholders’ equity
15,765

13,198

Noncontrolling interest in consolidated subsidiaries
25

18

Total shareholders’ equity
15,790

13,216

Total liabilities and shareholders’ equity
$
27,410

$
23,677

See notes to consolidated financial statements.
 
 


55



HALLIBURTON COMPANY
Consolidated Statements of Cash Flows

 
Year Ended December 31
Millions of dollars
2012
2011
2010
Cash flows from operating activities:
 
 
 
Net income
$
2,645

$
2,844

$
1,842

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
Depreciation, depletion, and amortization
1,628

1,359

1,119

Loss contingency for Macondo well incident
300



(Benefit) provision for deferred income taxes, continuing operations
165

(30
)
124

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

(40
)
Other changes:
 
 
 
Receivables
(682
)
(1,218
)
(902
)
Inventories
(611
)
(564
)
(331
)
Accounts payable
200

649

330

Other
67

478

70

Total cash flows from operating activities
3,654

3,684

2,212

Cash flows from investing activities:
 
 
 
Capital expenditures
(3,566
)
(2,953
)
(2,069
)
Purchases of investment securities
(506
)
(501
)
(1,282
)
Sales of property, plant, and equipment
395

160

227

Sales of investment securities
258

1,001

1,925

Acquisitions of business assets, net of cash acquired
(214
)
(880
)
(523
)
Other investing activities
(55
)
(17
)
(33
)
Total cash flows from investing activities
(3,688
)
(3,190
)
(1,755
)
Cash flows from financing activities:
 
 
 
Dividends to shareholders
(333
)
(330
)
(327
)
Proceeds from exercises of stock options
107

160

102

Payments to reacquire common stock
(33
)
(43
)
(141
)
Proceeds from long-term borrowings, net of offering costs

978


Payments on long-term borrowings


(790
)
Other financing activities
87

68

42

Total cash flows from financing activities
(172
)
833

(1,114
)
Effect of exchange rate changes on cash
(8
)
(27
)
(27
)
Increase (decrease) in cash and equivalents
(214
)
1,300

(684
)
Cash and equivalents at beginning of year
2,698

1,398

2,082

Cash and equivalents at end of year
$
2,484

$
2,698

$
1,398

Supplemental disclosure of cash flow information:
 
 
 
Cash payments during the period for:
 
 
 
Interest
$
294

$
261

$
310

Income taxes
$
1,098

$
1,285

$
804

See notes to consolidated financial statements.
 
 
 


56



HALLIBURTON COMPANY
Consolidated Statements of Shareholders' Equity