10-K 1 ed10k2009_final.htm HALLIBURTON COMPANY 12-31-2009 10-K ed10k2009_final.htm
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, 2009

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, 2009, determined using the per share closing price on the New York Stock Exchange Composite tape of $20.70 on that date was approximately $18,573,000,000.

As of February 12, 2010, there were 905,090,232 shares of Halliburton Company Common Stock, $2.50 par value per share, outstanding.

Portions of the Halliburton Company Proxy Statement for our 2010 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, 2009

PART I
 
PAGE
Item 1.
Business
 1
Item 1(a).
Risk Factors
 6
Item 1(b).
Unresolved Staff Comments
 6
Item 2.
Properties
 6
Item 3.
Legal Proceedings
 6
Item 4.
Submission of Matters to a Vote of Security Holders
 6
PART II
   
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters,
 
 
and Issuer Purchases of Equity Securities
 7
Item 6.
Selected Financial Data
 8
Item 7.
Management’s Discussion and Analysis of Financial Condition and
 
 
Results of Operations
 8
Item 7(a).
Quantitative and Qualitative Disclosures About Market Risk
 8
Item 8.
Financial Statements and Supplementary Data
 9
Item 9.
Changes in and Disagreements with Accountants on Accounting and
 
 
Financial Disclosure
 9
Item 9(a).
Controls and Procedures
 9
Item 9(b).
Other Information
 9
MD&A AND FINANCIAL STATEMENTS
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 10
Management’s Report on Internal Control Over Financial Reporting
 46
Reports of Independent Registered Public Accounting Firm
 47
Consolidated Statements of Operations
 49
Consolidated Balance Sheets
 50
Consolidated Statements of Shareholders’ Equity
 51
Consolidated Statements of Cash Flows
 52
Notes to Consolidated Financial Statements
 53
Selected Financial Data (Unaudited)
 86
Quarterly Data and Market Price Information (Unaudited)
 87
PART III
   
Item 10.
Directors, Executive Officers, and Corporate Governance
 88
Item 11.
Executive Compensation
 88
Item 12(a).
Security Ownership of Certain Beneficial Owners
 88
Item 12(b).
Security Ownership of Management
 88
Item 12(c).
Changes in Control
 89
Item 12(d).
Securities Authorized for Issuance Under Equity Compensation Plans
 89
Item 13.
Certain Relationships and Related Transactions, and Director
 
 
Independence
 89
Item 14.
Principal Accounting Fees and Services
 89
PART IV
   
Item 15.
Exhibits
 90
SIGNATURES
 99

(i)

 
 

 

PART I

Item 1.  Business.
General description of business
Halliburton Company’s predecessor was established in 1919 and incorporated under the laws of the State of Delaware in 1924.  We provide a variety of services and products to customers in 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.  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.
Business strategy
Our business strategy is to secure a distinct and sustainable competitive position as an oilfield service company by delivering products and services 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 products and services supported by global infrastructure and anchored by technology 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 of the geological characteristics of the hydrocarbon reservoir;
 
-
product quality;
 
-
warranty; and
 
-
technical proficiency.

 
1

 

We conduct business worldwide in approximately 70 countries.  The business operations of our divisions are organized around four primary geographic regions: North America, Latin America, Europe/Africa/CIS, and Middle East/Asia.  In 2009, based on the location of services provided and products sold, 36% of our consolidated revenue was from the United States.  In 2008 and 2007, 43% and 44% of our consolidated revenue was from the United States.  No other country accounted for more than 10% of our consolidated revenue during these periods.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Business Environment and Results of Operations” and Note 2 to the consolidated financial statements for additional financial information about 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.  Largely, all 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, exchange control problems, and highly inflationary currencies.  We believe the geographic diversification of our business activities reduces the risk that loss of operations in any one country 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 12 to the consolidated financial statements.
Customers
Our revenue from continuing operations during the past three years was derived from the sale of services and products to the energy industry.  No customer represented more than 10% of 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 sand, cement, and specialty metals.  We are always seeking ways to ensure the availability of resources, as well as manage costs of raw materials.  Our procurement department is using our size and buying power through several programs designed to ensure that we have access to key materials at competitive prices.
Research and development costs
We maintain an active research and development program.  The program improves existing products and processes, develops new products and processes, and improves engineering standards and practices that serve the changing needs of our customers, such as those related to high pressure/high temperature environments.  Our expenditures for research and development activities were $325 million in 2009, $326 million in 2008, and $301 million in 2007, of which over 96% was 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 serve to mitigate those effects.  Examples of how weather can impact our business include:

 
2

 

 
-
the severity and duration of the winter in North America can have a significant impact on natural gas storage levels and drilling activity for natural gas;
 
-
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.
In addition, due to higher spending near the end of the year by customers for software and completion tools and services, software and asset solutions and completion tools results of operations are generally stronger in the fourth quarter of the year than at the beginning of the year.
Employees
At December 31, 2009, we employed approximately 51,000 people worldwide compared to approximately 57,000 at December 31, 2008.  At December 31, 2009, approximately 20% of our employees were subject to collective bargaining agreements.  Based upon the geographic diversification of these employees, we believe any risk of loss from employee strikes or other collective actions would not be material to the conduct of our operations taken as a whole.
Environmental regulation
We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide.  For further information related to environmental matters and regulation, see Note 8 to the consolidated financial statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors” under the subheadings “Customers and Business—Environmental requirements.”
Working capital
We fund our business operations through a combination of available cash and equivalents, short-term investments, and cash flow generated from operations.  In addition, our revolving credit facility is available for additional working capital needs.
Web site access
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 are made available free of charge on our internet web site at www.halliburton.com as soon as reasonably practicable after we have electronically filed the material with, or furnished it to, the Securities and Exchange Commission (SEC).  The public may read and copy any materials we have filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, 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 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 2009, 2008, or 2007.

 
3

 

Executive Officers of the Registrant

The following table indicates the names and ages of the executive officers of Halliburton Company as of February 12, 2010, 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
Vice President, Corporate Controller, and Principal Accounting Officer of
(Age 42)
Halliburton Company, since January 2008
 
Vice President, Operations Finance of Halliburton Company,
 
December 2007 to January 2008
 
Vice President, Investor Relations of Halliburton Company,
 
April 2005 to November 2007
 
Assistant Controller of Halliburton Company, April 2003 to March 2005
   
James S. Brown
President, Western Hemisphere of Halliburton Company, since January 2008
(Age 55)
Senior Vice President, Western Hemisphere of Halliburton Company,
 
June 2006 to December 2007
 
Senior Vice President, United States Region of Halliburton Company,
 
December 2003 to June 2006
   
*      Albert O. Cornelison, Jr.
Executive Vice President and General Counsel of Halliburton Company,
(Age 60)
since December 2002
   
David S. King
President, Completion and Production Division of Halliburton Company,
(Age 53)
since January 2008
 
Senior Vice President, Completion and Production Division of Halliburton
 
Company, July 2007 to December 2007
 
Senior Vice President, Production Optimization of Halliburton Company,
 
January 2007 to July 2007
 
Senior Vice President, Eastern Hemisphere of Halliburton Energy Services
 
Group, July 2006 to December 2006
 
Senior Vice President, Global Operations of Halliburton Energy Services
 
Group, July 2004 to July 2006
   
*      David J. Lesar
Chairman of the Board, President, and Chief Executive Officer of Halliburton
(Age 56)
Company, since August 2000
   
   


 
4

 


Name and Age
Offices Held and Term of Office
Ahmed H. M. Lotfy
President, Eastern Hemisphere of Halliburton Company, since January 2008
(Age 55)
Senior Vice President, Eastern Hemisphere of Halliburton Company,
 
January 2007 to December 2007
 
Vice President, Africa Region of Halliburton Company, January 2005 to
 
December 2006
   
*      Mark A. McCollum
Executive Vice President and Chief Financial Officer of Halliburton Company,
(Age 50)
since January 2008
 
Senior Vice President and Chief Accounting Officer of Halliburton Company,
 
August 2003 to December 2007
   
Craig W. Nunez
Senior Vice President and Treasurer of Halliburton Company,
(Age 48)
since January 2007
 
Vice President and Treasurer of Halliburton Company, February 2006
 
to January 2007
 
Treasurer of Colonial Pipeline Company, November 1999 to January 2006
   
*      Lawrence J. Pope
Executive Vice President of Administration and Chief Human Resources Officer
(Age 41)
of Halliburton Company, since January 2008
 
Vice President, Human Resources and Administration of Halliburton
 
Company, January 2006 to December 2007
 
Senior Vice President, Administration of Kellogg Brown & Root, Inc.,
 
August 2004 to January 2006
   
*      Timothy J. Probert
President, Global Business Lines and Corporate Development of
(Age 58)
Halliburton Company, since January 2010
 
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
 
Senior Vice President, Drilling and Evaluation of Halliburton Company,
 
July 2007 to December 2007
 
Senior Vice President, Drilling and Evaluation and Digital Solutions of
 
Halliburton Company, May 2006 to July 2007
 
Vice President, Drilling and Formation Evaluation of Halliburton Company,
 
January 2003 to May 2006

 *      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.
Information related to risk factors is described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Forward-Looking Information and Risk Factors.”

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

Item 2.  Properties.
We own or lease numerous properties in domestic and foreign locations.  The following locations represent our major facilities and corporate offices.

Location
Owned/Leased
Description
     
Completion and Production segment:
   
Arbroath, United Kingdom
Owned
Manufacturing facility
Johor, Malaysia
Leased
Manufacturing facility
Monterrey, Mexico
Leased
Manufacturing facility
Sao Jose dos Campos, Brazil
Leased
Manufacturing facility
Stavanger, Norway
Leased
Research and development laboratory
     
Drilling and Evaluation segment:
   
Alvarado, Texas
Owned/Leased
Manufacturing facility
Nisku, Canada
Owned
Manufacturing facility
Singapore
Leased
Manufacturing and technology facility
The Woodlands, Texas
Leased
Manufacturing facility
     
Shared/corporate facilities:
   
Carrollton, Texas
Owned
Manufacturing facility
Dubai, United Arab Emirates
Leased
Corporate executive offices
Duncan, Oklahoma
Owned
Manufacturing, technology, and campus facilities
Houston, Texas
Owned
Corporate executive offices, manufacturing,
   
technology, and campus facilities
Houston, Texas
Owned
Campus facility
Houston, Texas
Leased
Campus facility
Pune, India
Leased
Technology facility

All of our owned properties are unencumbered.
In addition, we have 133 international and 103 United States field camps from which we deliver our services and products.  We also have numerous small facilities that include sales offices, project offices, and bulk storage facilities throughout the world.
We believe all properties that we currently occupy are suitable for their intended use.

Item 3.  Legal Proceedings.
Information related to various commitments and contingencies is described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Forward-Looking Information and Risk Factors” and in Note 8 to the consolidated financial statements.

Item 4.  Submission of Matters to a Vote of Security Holders.
There were no matters submitted to a vote of security holders during the fourth quarter of 2009.

 
6

 

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 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 common stock in the amount of $0.09 per share were paid in March, June, September, and December of 2009 and 2008.  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 upon, 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, 2009, with the Standard & Poor’s 500 Stock Index and the Standard & Poor’s Energy Composite Index over the same period.  This comparison assumes the investment of $100 on December 31, 2004, and the reinvestment of all dividends.  The shareholder return set forth is not necessarily indicative of future performance.

 
SP Stockholder Comparison
 
 
   
December 31
 
   
2004
   
2005
   
2006
   
2007
   
2008
   
2009
 
Halliburton
  $ 100.00     $ 159.46     $ 161.23     $ 198.84     $ 96.52     $ 162.37  
Standard & Poor’s 500 Stock Index
    100.00       104.91       121.48       128.16       80.74       102.11  
Standard & Poor’s Energy Composite Index
    100.00       131.37       163.16       219.30       142.83       162.57  

At February 12, 2010, there were 18,101 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.

 
7

 

Following is a summary of repurchases of our common stock during the three-month period ended December 31, 2009.

               
Total Number of Shares
 
               
Purchased as Part of
 
   
Total Number of Shares
   
Average Price Paid per
   
Publicly Announced
 
Period
 
Purchased (a)
   
Share
   
Plans or Programs
 
October 1-31
      36,895     $   28.10        
November 1-30
      39,386     $   30.18        
December 1-31
      73,920     $   28.43        
Total
    150,201     $   28.81        

 
(a)
All of the 150,201 shares purchased during the three-month period ended December 31, 2009 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.

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 Operation.
Information related to Management’s Discussion and Analysis of Financial Condition and Results of Operations is included on pages 10 through 45 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 33 of this annual report.

 
8

 

Item 8.  Financial Statements and Supplementary Data.

 
Page No.
Management’s Report on Internal Control Over Financial Reporting
 46
Reports of Independent Registered Public Accounting Firm
 47
Consolidated Statements of Operations for the years ended December 31, 2009, 2008, and
 49
2007
 
Consolidated Balance Sheets at December 31, 2009 and 2008
 50
Consolidated Statements of Shareholders’ Equity for the years ended
 51
December 31, 2009, 2008, and 2007
 
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008, and
 52
2007
 
Notes to Consolidated Financial Statements
 53
Selected Financial Data (Unaudited)
 86
Quarterly Data and Market Price Information (Unaudited)
 87

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

Item 9(a).  Controls and Procedures.
In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report.  Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2009 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, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
See page 46 for Management’s Report on Internal Control Over Financial Reporting and page 47 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.

Item 9(b).  Other Information.
None.

 
9

 

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

EXECUTIVE OVERVIEW

Organization
We are a leading provider of products and services to the energy industry.  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 through the life of the field.  Activity levels within our operations are significantly impacted by spending on upstream exploration, development, and production programs by major, national, and independent oil and natural gas companies.  We report our results under two segments, Completion and Production and Drilling and Evaluation:
 
-
our Completion and Production segment delivers cementing, stimulation, intervention, and completion services.  The segment consists of production enhancement services, completion tools and services, and cementing services; and
 
-
our Drilling and Evaluation segment provides field and reservoir modeling, drilling, evaluation, and precise wellbore placement solutions that enable customers to model, measure, and optimize their well construction activities.  The segment consists of fluid services, drilling services, drill bits, wireline and perforating services, testing and subsea, software and asset solutions, and integrated project management services.
The business operations of our segments are organized around four primary geographic regions:  North America, Latin America, Europe/Africa/CIS, and Middle East/Asia.  We have significant manufacturing operations in various locations, including, but not limited to, the United States, Canada, the United Kingdom, Malaysia, Mexico, Brazil, and Singapore.  With approximately 51,000 employees, we operate in approximately 70 countries around the world, and our corporate headquarters are in Houston, Texas and Dubai, United Arab Emirates.
Financial results
During 2009, we produced revenue of $14.7 billion and operating income of $2 billion, reflecting an operating margin of 14%.  Revenue decreased $3.6 billion or 20% from 2008, while operating income decreased $2 billion or 50% from 2008.  These decreases were caused by a significant decline in our customers’ capital spending as a result of the global recession and its impact on commodity prices, which resulted in lower activity, lower pricing, and severe margin contraction.
Business outlook
We continue to believe in the strength of the long-term fundamentals of our business.  However, due to the financial crisis that developed in mid-2008, the ensuing negative impact on credit availability and industry activity, and the current excess supply of oil and natural gas, the near-term outlook for our business and the industry remains uncertain.  Forecasting the depth and length of the current cycle is challenging as it is different from past cycles due to the overlay of the financial crisis in combination with broad demand weakness.
In North America, the industry experienced an unprecedented decline in drilling activity during 2009 as rig counts declined approximately 43% from 2008 highs.  This decline, coupled with natural gas storage levels reaching record levels, resulted in severe margin contraction in 2009.  During the fourth quarter of 2009, we saw some rebound in rig activity as conditions began to improve with positive seasonal withdrawals from natural gas storage.  With the trend toward increasing levels of service intensity, our equipment utilization is improving, and prices are stabilizing across many areas.  However, this rebound will require a sustained increase in natural gas drilling activity.  In order for this to occur, we believe it will be important that North America exits the winter heating season with storage levels in line with historical averages and there is increased recovery in industrial demand.

 
10

 

Outside of North America, 2009 rig count declined approximately 8% from 2008 highs.  Margins declined throughout 2009, and we have not yet felt the full impact of pricing concessions that were renegotiated during last year’s contract retendering process.  As such, we believe margins will continue to be under pressure in 2010.  We also believe that 2010 may be a period of transition for this market.  Oil supply/demand fundamentals are showing some improvement as weak hydrocarbon demand shows signs of recovery, but the timing of reinvestment remains uneven across geographies and customers.  Operators remain flexible in their spending patterns and continue to be heavily focused on restraining oilfield price and cost inflation.
Our operating performance and business outlook are described in more detail in “Business Environment and Results of Operations.”
Financial markets, liquidity, and capital resources
Since mid-2008, the global financial markets have been volatile.  While this has created 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.  To provide additional liquidity and flexibility in the current environment, we issued $2 billion in senior notes during the first quarter of 2009 and invested $1.5 billion in United States Treasury securities during the second quarter of 2009.  For additional information, see “Liquidity and Capital Resources,” “Risk Factors,” “Business Environment and Results of Operations,” and Notes 6 and 12 to the consolidated financial statements.

LIQUIDITY AND CAPITAL RESOURCES

We ended 2009 with cash and equivalents of $2.1 billion compared to $1.1 billion at December 31, 2008.  We also held $1.3 billion of short-term, United States Treasury securities at December 31, 2009.
Significant sources of cash
Cash flows from operating activities contributed $2.4 billion to cash in 2009.  Our focus on managing working capital levels during the year helped to offset the significant reduction in income during 2009.
In March 2009, we issued $1 billion of 6.15% senior notes due 2019 and $1 billion of 7.45% senior notes due 2039.
In 2009, we sold approximately $300 million of United States Treasury securities.
We received payments of $90 million for our asbestos-related insurance settlements during 2009.
Further available sources of cash.  We have an unsecured $1.2 billion, five-year revolving credit facility to provide commercial paper support, general working capital, and credit for other corporate purposes.  There were no cash drawings under the facility as of December 31, 2009.  In addition, we have $1.3 billion in United States Treasury securities that will be maturing at various dates through September 2010.
Significant uses of cash
Capital expenditures were $1.9 billion in 2009 and were predominantly made in the production enhancement, drilling services, wireline and perforating, and cementing product service lines.
During 2009, we purchased approximately $1.6 billion in United States Treasury securities, with varying maturity dates.
We paid $417 million to the Department of Justice (DOJ) and Securities and Exchange Commission (SEC) in 2009 related to the settlements with them and under the indemnity provided to KBR, Inc. (KBR) upon separation.
We paid $324 million in dividends to our shareholders in 2009.
We contributed $99 million to fund our defined benefit plans in 2009.

 
11

 

Future uses of cash.  Capital spending for 2010 is expected to be approximately $2.0 billion.  The capital expenditures plan for 2010 is primarily directed toward our production enhancement, drilling services, wireline and perforating, and cementing product service lines and toward retiring old equipment to replace it with new equipment to improve our fleet reliability and efficiency.  We are currently exploring opportunities for acquisitions that will enhance or augment our current portfolio of products and services, including those with unique technologies or distribution networks in areas where we do not already have large operations.
We currently intend to retire our $750 million principal amount of 5.5% senior notes at maturity in October 2010 with available cash and equivalents.
As a result of the resolution of the DOJ and SEC Foreign Corrupt Practices Act (FCPA) investigations, we will pay a total of $142 million in equal installments over the next three quarters for the settlement with the DOJ and under the indemnity provided to KBR upon separation.  See Notes 7 and 8 to our consolidated financial statements for more information.
Subject to Board of Directors approval, we expect to pay quarterly dividends of approximately $80 million during 2010.  We also have approximately $1.8 billion remaining available under our share repurchase authorization, which may be used for open market share purchases.
The following table summarizes our significant contractual obligations and other long-term liabilities as of December 31, 2009:
 

   
Payments Due
       
Millions of dollars
 
2010
   
2011
   
2012
   
2013
   
2014
   
Thereafter
   
Total
 
Long-term debt
  $ 750     $     $     $     $     $ 3,824     $ 4,574  
Interest on debt  (a)
    304       263       263       262       262       5,622       6,976  
Operating leases
    149       112       70       42       29       142       544  
Purchase obligations (b)
    1,022       72       39       15       2       6       1,156  
Pension funding obligations (c)
    38                                     38  
DOJ and SEC settlement and
                                                       
indemnity
    142                                     142  
Other long-term liabilities
    9       9       9       9                   36  
Total
  $ 2,414     $ 456     $ 381     $ 328     $ 293     $ 9,594     $ 13,466  
 
(a)  
Interest on debt includes 87 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)  
Amount based on assumptions that are subject to change.  Also, we may choose to make additional discretionary contributions.  We are currently not able to reasonably estimate our contributions for years after 2010.  See Note 13 to the consolidated financial statements for further information regarding pension contributions.
 
We had $292 million of gross unrecognized tax benefits at December 31, 2009, of which we estimate $43 million may require a cash payment.  We estimate that $12 million of the total $43 million may be settled within the next 12 months, although the amounts are not agreed with tax authorities.  We are not able to reasonably estimate in which future periods the remaining amounts will ultimately be settled and paid.

 
12

 

Other factors affecting liquidity
Letters of credit.  In the normal course of business, we have agreements with financial institutions under which approximately $1.8 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of December 31, 2009, including $380 million of surety bonds related to Venezuela.  In addition, $390 million of the total $1.8 billion relates to KBR letters of credit, bank guarantees, or surety bonds that are being guaranteed by us in favor of KBR’s customers and lenders.  KBR has agreed to compensate us for these guarantees and indemnify us if we are required to perform under any of these guarantees.  Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.
Financial position in current market.  Our $2.1 billion of cash and equivalents and $1.3 billion in investments in marketable securities as of December 31, 2009 provide sufficient liquidity and flexibility, given the current market environment.  Our debt maturities extend over a long period of time.  We currently have a total of $1.2 billion of committed bank credit under our revolving credit facility to support our operations and any commercial paper we may issue in the future.  We have no financial covenants or material adverse change provisions in our bank agreements.  Currently, there are no borrowings under the revolving credit facility.  Although a portion of earnings from our foreign subsidiaries is reinvested overseas indefinitely, we do not consider this to have a significant impact on our liquidity.
In addition, we manage our cash investments by investing principally in United States Treasury securities and repurchase agreements collateralized by United States Treasury securities.
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 due to, among other reasons, a reduction in our customer’s cash flow from operations and their access to the credit markets.  For example, we have seen a delay in receiving payment on our receivables from one of our primary customers in Venezuela.  However, during the fourth quarter of 2009, we reached a settlement with this customer and received payment on approximately one-third of our outstanding receivables.  If our customers delay in 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.


 
13

 

BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS

We operate in approximately 70 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 industries we serve are highly competitive with many substantial competitors in each segment.  In 2009, based upon the location of the services provided and products sold, 36% of our consolidated revenue was from the United States.  In 2008, 43% 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, exchange control problems, and highly inflationary currencies.  We believe the geographic diversification of our business activities reduces the risk that loss of operations in any one country 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.  See “Risk Factors—Worldwide recession and effect on exploration and production activity” for further information related to the effect of the current recession.
Some of the more significant barometers 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, 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)
 
2009
   
2008
   
2007
 
West Texas Intermediate
  $ 61.65     $ 99.37     $ 71.91  
United Kingdom Brent
  $ 61.49     $ 96.86     $ 72.21  
                         
Average United States Gas Prices (dollars per thousand cubic
                       
feet, or mcf)
                       
Henry Hub
  $ 4.06     $ 9.13     $ 7.18  


 
14

 

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

Land vs. Offshore
 
2009
   
2008
   
2007
 
United States:
                 
Land
    1,042       1,812       1,694  
Offshore (incl. Gulf of Mexico)
    44       65       73  
Total
    1,086       1,877       1,767  
Canada:
                       
Land
    220       378       341  
Offshore
    1       1       3  
Total
    221       379       344  
International (excluding Canada):
                       
Land
    722       784       719  
Offshore
    275       295       287  
Total
    997       1,079       1,006  
Worldwide total
    2,304       3,335       3,117  
Land total
    1,984       2,974       2,754  
Offshore total
    320       361       363  
                         
Oil vs. Natural Gas
    2009       2008       2007  
United States (incl. Gulf of Mexico):
                       
Oil
    282       384       300  
Natural Gas
    804       1,493       1,467  
Total
    1,086       1,877       1,767  
Canada:
                       
Oil
    102       160       128  
Natural Gas
    119       219       216  
Total
    221       379       344  
International (excluding Canada):
                       
Oil
    776       825       776  
Natural Gas
    221       254       230  
Total
    997       1,079       1,006  
Worldwide total
    2,304       3,335       3,117  
Oil total
    1,160       1,369       1,204  
Natural Gas total
    1,144       1,966       1,913  

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.

 
15

 

WTI oil spot prices fell from a high of approximately $145 per barrel in July 2008 to a low of approximately $30 per barrel in December 2008.  Since then prices have rebounded.  As noted above, during 2009, the WTI spot price averaged $61.65 per barrel.  As of February 12, 2010 the WTI oil spot price was $74.13 per barrel.  According to the International Energy Agency’s (IEA) February 2010 “Oil Market Report,” 2010 world petroleum demand is forecasted to increase 2% over 2009 levels.  Despite the overall decline in oil and natural gas prices from 2008 levels and reduction in our customers’ capital spending, we believe that, over the long term, any major macroeconomic disruptions may ultimately correct themselves as 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.
North America operations
Volatility in natural gas prices can impact our customers' drilling and production activities, particularly in North America.  In 2009, we experienced an unprecedented decline in drilling activity as rig count dropped approximately 43% from 2008 highs.  Correlating with this decline, the Henry Hub spot price decreased from an average of $9.13 per mcf in 2008 to $4.06 per mcf in 2009.  As of February 12, 2010, the Henry Hub spot price was $5.65 per mcf.  Weak domestic natural gas demand, coupled with the productivity of new shale resources, led to natural gas storage reaching record levels in 2009 and severe margin compression.  We saw some rebound in rig activity toward the end of 2009 as conditions began to improve with seasonal withdrawals from natural gas storage.  With the trend toward increasing levels of service intensity, our equipment utilization is improving, and prices are stabilizing across many areas.  However, this rebound will require a sustained increase in natural gas drilling activity.  For activity levels to improve, we believe it will be important that North America exits the winter heating season with storage levels in line with historical averages and there is increased recovery in industrial demand.
International operations
Consistent with our long-term strategy to grow our operations outside of North America, we expect to continue to invest capital in our international operations.  During 2009, international energy services activity declined as well, but not to the extent the North American market fell.  As of December 31, 2009, the international rig count had declined approximately 8% from 2008 highs.  International margins declined throughout 2009, and we have not yet felt the full impact of pricing concessions that were renegotiated during last year’s contract retendering process.  As such, we believe margins will continue to be under pressure in 2010.  We also believe that 2010 may be a period of transition for this market.  Oil supply/demand fundamentals are showing some improvement as weak global hydrocarbon demand shows signs of recovery, but the timing of reinvestment remains uneven across geographies and customers.  Operators are remaining flexible in their spending patterns and continue to be heavily focused on restraining oilfield price and cost inflation.
Venezuela.  In January 2010, the Venezuelan government announced a devaluation of the Bolívar Fuerte under a new two-exchange rate system; one rate for essential products and the other rate for non-essential products.  As a result of the devaluation, we are estimating a loss of approximately $30 million in the first quarter of 2010 based on our current understanding of how the new two-exchange rate system will work for oil services activity.  Our estimate utilizes a 4.3 Bolívar Fuerte to United States dollar exchange rate.

 
16

 

Initiatives and recent contract awards
Following is a brief discussion of some of our recent and current initiatives:
 
-
leveraging our technologies to deploy our packaged-services strategy to provide our customers with the ability to more efficiently drill and complete their wells, especially in service-intensive environments such as deepwater and shale plays;
 
-
retaining key investments in technology and capital to accelerate growth opportunities;
 
-
increasing our market share in unconventional and deepwater markets by enhancing our technological position and leveraging our technical expertise and wide portfolio of products and services;
 
-
lowering our input costs from vendors by negotiating price reductions for both materials used in our operations and those utilized in the manufacturing of capital equipment;
 
-
negotiating with our customers to trade an expansion of scope and a lengthening of contract duration for price concessions;
 
-
optimizing headcount in locations experiencing significant changes in activity;
 
-
improving working capital, operating within our cash flow, and managing our balance sheet to maximize our financial flexibility;
 
-
continuing the globalization of our manufacturing and supply chain processes, preserving work at our lower-cost manufacturing centers, and utilizing our international infrastructure to lower costs from our supply chain through delivery;
 
-
expanding our business with national oil companies; and
 
-
minimizing discretionary spending.
Contract wins positioning us to grow our operations over the long term include:
 
 -
a five-year integrated turnkey drilling contract, with an option for an additional five-year period, which includes drilling and completion activities in South Ghawar, Saudi Arabia;
 
 -
a three-year, $122 million contract, to provide drilling and completion fluid solutions in Indonesia;
 
 -
a three-year technical cooperation agreement by Brazil’s state energy company for research and development in Brazil’s subsalt areas;
 
 -
a two-year, $229 million contract with multiple extension options, to provide drilling fluids and associated services in Norway;
 
 -
a three-year contract renewal for continued access to a broad suite of software technology and petro-technical consulting services for the development, deployment, and ongoing global support of exploration and production technology and workflows;
 
 -
a five-year, $1.5 billion contract to provide a broad base of products and services to an international oil company for its work associated with North America;
 
 -
several wins totaling $1 billion, including $700 million to provide deepwater drilling fluid services in the Gulf of Mexico, Brazil, Indonesia, Angola, and other countries, which solidifies our position in the deepwater drilling fluids market and $300 million for shelf- and land-related work; and
 
 -
a two-year contract extension, estimated to be valued at $450 million, to provide cementing services and completion and drilling fluids for StatoilHydro in offshore fields on the Norwegian continental shelf.


 
17

 


 
 -
a five-year, $190 million contract to provide drilling fluid, completion fluid, and drilling waste management services for Petrobras in the offshore markets of Brazil;
 
 -
a five-year, $100 million contract to provide directional-drilling and logging-while-drilling services in the Middle East;
 
 -
a contract award in Algeria to provide integrated project management services for a number of delineation wells initially with the potential to expand to 120 wells for full field development;
 
 -
a four-year contract to provide directional-drilling, measurement-while-drilling, and logging-while-drilling, along with drilling fluids and cementing services in Russia; and
 
 -
a multi-year contract scheduled to commence in 2010 to provide completion products and services and drilling and completion fluids in the deepwater, offshore fields of Angola.


 
18

 


RESULTS OF OPERATIONS IN 2009 COMPARED TO 2008

REVENUE:
       
Increase
   
Percentage
 
Millions of dollars
 
2009
   
2008
   
(Decrease)
   
Change
 
Completion and Production
  $ 7,419     $ 9,610     $ (2,191 )     (23 )%
Drilling and Evaluation
    7,256       8,669       (1,413 )     (16 )
Total revenue
  $ 14,675     $ 18,279     $ (3,604 )     (20 )%

By geographic region:
 
Completion and Production:
                       
North America
  $ 3,589     $ 5,327     $ (1,738 )     (33 )%
Latin America
    887       978       (91 )     (9 )
Europe/Africa/CIS
    1,771       1,938       (167 )     (9 )
Middle East/Asia
    1,172       1,367       (195 )     (14 )
Total
    7,419       9,610       (2,191 )     (23 )
Drilling and Evaluation:
                               
North America
    2,073       3,013       (940 )     (31 )
Latin America
    1,294       1,447       (153 )     (11 )
Europe/Africa/CIS
    2,177       2,408       (231 )     (10 )
Middle East/Asia
    1,712       1,801       (89 )     (5 )
Total
    7,256       8,669       (1,413 )     (16 )
Total revenue by region:
                               
North America
    5,662       8,340       (2,678 )     (32 )
Latin America
    2,181       2,425       (244 )     (10 )
Europe/Africa/CIS
    3,948       4,346       (398 )     (9 )
Middle East/Asia
    2,884       3,168       (284 )     (9 )

 
19

 


OPERATING INCOME:
       
Increase
   
Percentage
 
Millions of dollars
 
2009
   
2008
   
(Decrease)
   
Change
 
Completion and Production
  $ 1,016     $ 2,304     $ (1,288 )     (56 )%
Drilling and Evaluation
    1,183       1,970       (787 )     (40 )
Corporate and other
    (205 )     (264 )     59       22  
Total operating income
  $ 1,994     $ 4,010     $ (2,016 )     (50 )%

By geographic region:
 
Completion and Production:
                       
North America
  $ 272     $ 1,426     $ (1,154 )     (81 )%
Latin America
    172       214       (42 )     (20 )
Europe/Africa/CIS
    315       360       (45 )     (13 )
Middle East/Asia
    257       304       (47 )     (15 )
Total
    1,016       2,304       (1,288 )     (56 )
Drilling and Evaluation:
                               
North America
    178       679       (501 )     (74 )
Latin America
    187       307       (120 )     (39 )
Europe/Africa/CIS
    380       497       (117 )     (24 )
Middle East/Asia
    438       487       (49 )     (10 )
Total
    1,183       1,970       (787 )     (40 )
Total operating income by region
                               
(excluding Corporate and other):
                               
North America
    450       2,105       (1,655 )     (79 )
Latin America
    359       521       (162 )     (31 )
Europe/Africa/CIS
    695       857       (162 )     (19 )
Middle East/Asia
    695       791       (96 )     (12 )
 
 
Note–
 
All periods presented reflect the movement of certain operations from the Completion and Production segment to the Drilling and Evaluation segment during the first quarter of 2009.
 
        The 20% decline in consolidated revenue in 2009 compared to 2008 was primarily due to pricing declines and lower demand for our products and services in North America due to a significant reduction in rig count.  As a result of an approximate 42% reduction in average rig count in North America during 2009 compared to 2008, we experienced a 32% decline in North America revenue from 2008.  Revenue outside of North America was 61% of consolidated revenue in 2009 and 54% of consolidated revenue in 2008.
The decrease in consolidated operating income compared to 2008 primarily stemmed from a 79% decrease in North America due to a decline in rig count and severe margin contraction, a $73 million charge associated with employee separation costs, and a $15 million charge related to the settlement of a customer receivable in Venezuela.  Operating income in 2008 was favorably impacted by a $35 million gain on the sale of a joint venture interest in the United States, a combined $25 million gain related to the sale of two investments in the United States, and a net $5 million gain on the settlement of two patent disputes.  Operating income in 2008 was adversely impacted by approximately $52 million as a result of hurricanes in the Gulf of Mexico, a $23 million impairment charge related to an oil and natural gas property in Bangladesh, and a $22 million acquisition-related charge for WellDynamics.

 
20

 

Following is a discussion of our results of operations by reportable segment.
Completion and Production decrease in revenue compared to 2008 was primarily a result of overall pricing declines and lower demand for our products and services in North America.  More specifically, North America revenue fell 33% as a result of pricing declines and a drop in demand for production enhancement services and cementing services.  Latin America revenue decreased 9% as increased activity for all product service lines in Mexico and Colombia was outweighed by lower activity across all product service lines in Venezuela and Argentina.  Europe/Africa/CIS revenue decreased 9% on lower demand for completion tools and services in Africa.  In addition, production enhancement services in Europe were negatively impacted by job delays in the North Sea.  Middle East/Asia revenue fell 14% due to job delays and a decrease in demand for all products and services in the Middle East.  Revenue outside of North America was 52% of total segment revenue in 2009 and 45% of total segment revenue in 2008.
The Completion and Production segment operating income decrease compared to 2008 was primarily due to the North America region, where operating income fell 81% largely due to pricing declines and significant reductions in rig count resulting in lower demand for our products and services.  Results in 2009 were adversely impacted by $34 million in employee separation costs.  In 2008, North America was negatively impacted by approximately $25 million due to Gulf of Mexico hurricanes but benefited from a $35 million gain on the sale of a joint venture interest.  Latin America operating income decreased 20% driven by lower activity across all product service lines in Venezuela and Argentina.  Europe/Africa/CIS operating income decreased 13% as improved cost management and higher demand for cementing services across the region were outweighed by job delays and lower demand for completion tools and services in Africa and production enhancement services in the North Sea and Angola.   Middle East/Asia operating income decreased 15% primarily due to lower completion tools sales in Saudi Arabia and lower demand for production enhancement services in Oman and Malaysia.
Drilling and Evaluation revenue decrease compared to 2008 was primarily a result of pricing declines and decreased demand for our products and services stemming from a reduction in rig count in North America, where revenue fell 31%.  Latin America revenue fell 11% as increased drilling activity in Brazil was outweighed by lower demand for all product service lines in Venezuela, Argentina, and Colombia.  Europe/Africa/CIS revenue decreased 10% as increases in software sales and consulting services in Algeria were offset by decreased demand for drilling fluids services in Nigeria and Angola and drilling services in Europe.  Pricing pressure also had a significant impact on revenue in Europe and Russia.  Middle East/Asia revenue decreased 5% as increased demand for drilling fluid services and testing and subsea services in Asia Pacific were outweighed by lower drilling activity in the Middle East and declines in software sales and consulting services and wireline and perforating services in Asia Pacific.  Revenue outside of North America was 71% of total segment revenue in 2009 and 65% of total segment revenue in 2008.

 
21

 

The decrease in segment operating income compared to 2008 was primarily due to a 74% decrease in North America operating income related to pricing declines and rig count reductions.  Results in 2009 were also adversely impacted by $34 million in employee separation costs.  In 2008, this segment’s results were negatively impacted by approximately $27 million due to Gulf of Mexico hurricanes and a $23 million impairment charge related to an oil and natural gas property in Bangladesh, but benefited from $25 million of gains related to the sale of two investments in the United States.  Latin America operating income fell 39% primarily due to lower activity across all product service lines in Venezuela and decreased demand and pricing pressure for drilling services and wireline and perforating services in Argentina, Colombia, and Mexico.  The region was also adversely affected by a $12 million charge related to the settlement of a customer receivable in Venezuela.  The Europe/Africa/CIS region operating income fell 24% as increased demand for drilling fluid services in Norway and Kazakhstan and increased software sales and consulting services in Africa were outweighed by pricing pressures and decreased drilling activity in Europe and lower demand for drilling fluid services in Africa.  Middle East/Asia operating income decreased 10% over 2008 as declines in drilling activity in Saudi Arabia and China outweighed an increase in software sales and consulting services in the Middle East and higher demand for testing and subsea services in Asia.  This region was negatively impacted by the impairment charge related to an oil and natural gas property in Bangladesh in 2008.
Corporate and other expenses were $205 million in 2009 compared to $264 million in 2008.  The 2009 results include $5 million in employee separation costs.  The 22% reduction was primarily attributable to our 2009 focus on reducing discretionary spending and optimizing headcount and a $22 million acquisition-related charge for WellDynamics related to employee incentive compensation awards in 2008.  2008 also included a net $5 million gain on the settlement of two patent disputes.

NONOPERATING ITEMS
Interest expense increased $130 million in 2009 compared to 2008 primarily due to the issuance of $2 billion in senior notes during the first quarter of 2009, partially offset by the redemption of our convertible senior notes early in the third quarter of 2008.
Interest income decreased $27 million in 2009 compared to 2008 due to a general decline in market interest rates.
Loss from discontinued operations, net of income tax in 2008 included $420 million in charges reflecting the resolution of the DOJ and SEC FCPA investigations and the impact of our assumption changes during that period regarding the resolution of the Barracuda-Caratinga bolt arbitration matter under the indemnities and guarantees provided to KBR upon separation.
Noncontrolling interest in net income of subsidiaries increased $19 million compared to 2008, primarily related to the impact of a change in effective ownership of a joint venture in 2008.


 
22

 

RESULTS OF OPERATIONS IN 2008 COMPARED TO 2007

REVENUE:
             
Percentage
 
Millions of dollars
 
2008
   
2007
   
Increase
   
Change
 
Completion and Production
  $ 9,610     $ 8,138     $ 1,472       18 %
Drilling and Evaluation
    8,669       7,126       1,543       22  
Total revenue
  $ 18,279     $ 15,264     $ 3,015       20 %

By geographic region:
 
Completion and Production:
                       
North America
  $ 5,327     $ 4,632     $ 695       15 %
Latin America
    978       668       310       46  
Europe/Africa/CIS
    1,938       1,689       249       15  
Middle East/Asia
    1,367       1,149       218       19  
Total
    9,610       8,138       1,472       18  
Drilling and Evaluation:
                               
North America
    3,013       2,501       512       20  
Latin America
    1,447       1,130       317       28  
Europe/Africa/CIS
    2,408       2,011       397       20  
Middle East/Asia
    1,801       1,484       317       21  
Total
    8,669       7,126       1,543       22  
Total revenue by region:
                               
North America
    8,340       7,133       1,207       17  
Latin America
    2,425       1,798       627       35  
Europe/Africa/CIS
    4,346       3,700       646       17  
Middle East/Asia
    3,168       2,633       535       20  

 
23

 


OPERATING INCOME:
       
Increase
   
Percentage
 
Millions of dollars
 
2008
   
2007
   
(Decrease)
   
Change
 
Completion and Production
  $ 2,304     $ 2,119     $ 185       9 %
Drilling and Evaluation
    1,970       1,565       405       26  
Corporate and other
    (264 )     (186 )     (78 )     (42 )
Total operating income
  $ 4,010     $ 3,498     $ 512       15 %

By geographic region:
 
Completion and Production:
                       
North America
  $ 1,426     $ 1,418     $ 8       1 %
Latin America
    214       133       81       61  
Europe/Africa/CIS
    360       300       60       20  
Middle East/Asia
    304       268       36       13  
Total
    2,304       2,119       185       9  
Drilling and Evaluation:
                               
North America
    679       538       141       26  
Latin America
    307       216       91       42  
Europe/Africa/CIS
    497       444       53       12  
Middle East/Asia
    487       367       120       33  
Total
    1,970       1,565       405       26  
Total operating income by region
                               
(excluding Corporate and other):
                               
North America
    2,105       1,956       149       8  
Latin America
    521       349       172       49  
Europe/Africa/CIS
    857       744       113       15  
Middle East/Asia
    791       635       156       25  
 
 
Note–
 
All periods presented reflect the movement of certain operations from the Completion and Production segment to the Drilling and Evaluation segment during the first quarter of 2009
 
        The increase in consolidated revenue in 2008 compared to 2007 spanned all four regions and was attributable to higher worldwide activity, particularly in North America, Asia, and Latin America.  Approximately $74 million in revenue was lost during 2008 due to Gulf of Mexico hurricanes.  Revenue outside of North America was 54% of consolidated revenue in 2008 and 53% of consolidated revenue in 2007.
The increase in consolidated operating income in 2008 compared to 2007 was primarily due to a 49% increase in Latin America and a 25% increase in Middle East/Asia resulting from increased customer activity, new contracts, and improved pricing.  Operating income in 2008 was positively impacted by a $35 million gain on the sale of a joint venture interest in the United States, a combined $25 million gain related to the sale of two investments in the United States, and a net $5 million gain on the settlement of two patent disputes.  Operating income in 2008 was adversely impacted by $52 million due to Gulf of Mexico hurricanes, a $23 million impairment charge related to an oil and natural gas property in Bangladesh, and a $22 million acquisition-related charge for WellDynamics related to employee incentive compensation awards.  Operating income in 2007 was positively impacted by a $49 million gain recorded on the sale of our remaining interest in Dresser, Ltd. and negatively impacted by $34 million in charges related to the impairment of an oil and natural gas property in Bangladesh and $32 million in charges for environmental reserves.

 
24

 

Following is a discussion of our results of operations by reportable segments.
Completion and Production increase in revenue compared to 2007 was derived from all regions.  Europe/Africa/CIS revenue grew 15% primarily from increased production enhancement services activity, largely related to the acquisition of PSL Energy Services Limited.  Additionally, completion tools revenue benefited from increased sales and service in Africa.  Middle East/Asia revenue grew 19% from increased completion tools sales and deliveries and new contracts for production enhancement services in the region.  Increased demand for cementing products and services in the Middle East and Australia also contributed to the increase.  North America revenue grew 15% from improved demand for production enhancement services and cementing products and services largely driven by increased capacity and rig count in the United States.  Partially offsetting the improvement in the United States was $34 million in lost revenue due to Gulf of Mexico hurricanes.  Latin America revenue grew 46% as a result of higher activity for all product service lines, particularly in Mexico and Brazil.  Higher demand for production enhancement services, new cementing contracts with more favorable pricing, and improved completion tools sales were large contributors to the increase in revenue.  Revenue outside of North America was 45% of total segment revenue in 2008 and 43% in 2007.
The increase in segment operating income in 2008 compared to 2007 spanned all regions.  Europe/Africa/CIS operating income increased 20% from increased completion tools sales and services in Africa and higher production enhancement activity in Europe.  Middle East/Asia operating income increased 13% primarily due to increased sales and service revenue from completion tools and increased production enhancement activity in the region.  North America operating income was essentially flat, primarily due to a $25 million negative impact from Gulf of Mexico hurricanes and pricing declines and cost increases in the United States for production enhancement, offset by improved completion tools sales and services and a $35 million gain on the sale of a joint venture interest in the United States.  Latin America operating income increased 61% with improved cementing and production enhancement performance primarily in Mexico and Brazil.
Drilling and Evaluation revenue increase compared to 2007 was derived from all regions.  Europe/Africa/CIS revenue grew 20% from increased drilling services activity and higher customer demand for fluid and wireline and perforating services throughout the region.  Middle East/Asia revenue grew 21% primarily due to increased fluid services activity throughout the region and higher customer demand for drilling services in Asia.  North America revenue grew 20% from higher activity across all product service lines in the United States primarily due to increased land rig count and higher demand for new technology.  The region also benefited from higher activity for fluid services in Canada.  Partially offsetting the improvement in the United States was $40 million in lost revenue due to Gulf of Mexico hurricanes.  Latin America revenue grew 28% as a result of increased customer demand for drilling services, increased activity and new contracts for wireline and perforating services, and increased project management services.  Revenue outside of North America was 65% of total segment revenue in 2008 and 2007.

 
25

 

The increase in segment operating income in 2008 compared to 2007 was derived from all regions led by growth in North America, Latin America, and Asia.  Europe/Africa/CIS operating income increased 12% benefiting from higher customer demand for wireline and perforating services in Africa.  Higher demand for software sales and consulting services in Europe also contributed to the increase.  Middle East/Asia operating income grew 33% primarily due to increased fluid services results in the Middle East as well as higher demand for drilling services and improved wireline and perforating services and software sales and consulting services in Asia.  Operating income was impacted by a $23 million impairment charge related to an oil and natural gas property in Bangladesh.  North America operating income increased 26% primarily from increased activity in most of the product service lines including higher demand for fluid services and increased drilling activity.  Negatively impacting the region was a loss of $27 million due to Gulf of Mexico hurricanes.  This region’s results also reflect $25 million of gains related to the sale of two investments in the United States.  Latin America operating income increased 42% primarily due to increased activity in drilling services and wireline and perforating services and improvements in software sales and consulting services.
Corporate and other expenses were $264 million in 2008 compared to $186 million in 2007.  2008 included a $35 million gain in the fourth quarter and a $30 million charge in the second quarter related to patent dispute settlements, a $22 million acquisition-related charge for WellDynamics related to employee incentive compensation awards, higher legal costs, and increased corporate development costs.  2007 was impacted by a $49 million gain on the sale of our remaining interest in Dresser, Ltd. and a $12 million charge for executive separation costs.

NONOPERATING ITEMS
Interest income decreased $85 million in 2008 compared to 2007 due to a decrease of cash and equivalents and marketable securities balances and a general decline in market interest rates.
Other, net in 2008 included a $31 million loss on foreign exchange due to the general weakening of the United States dollar against certain foreign currencies.
Provision for income taxes from continuing operations of $1.2 billion in 2008 resulted in an effective tax rate of 31% compared to an effective tax rate of 26% in 2007.  The lower tax rate in 2007 is primarily related to a $205 million favorable income tax impact from the ability to recognize foreign tax credits previously estimated not to be fully utilizable.
Income (loss) from discontinued operations, net of income tax in 2008 included $420 million in charges reflecting the resolution of the DOJ and SEC FCPA investigations and the impact of our assumption changes during that period regarding the resolution of the Barracuda-Caratinga bolt arbitration matter under the indemnities and guarantees provided to KBR upon separation.  2007 included a $933 million net gain on the disposition of KBR, which included the estimated fair value of the indemnities and guarantees provided to KBR and our 81% share of KBR’s $28 million in net income in the first quarter of 2007.
Noncontrolling interest in net income of subsidiaries decreased $59 million compared to 2007, primarily related to a change in effective ownership of a joint venture in 2008.

 
26

 

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 estimates 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 and investigation matters;
 
-
valuations of indemnities;
 
-
valuations of long-lived assets, including intangible assets;
 
-
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.

 
27

 

We determine deferred taxes separately for each tax-paying component (an entity or a group of entities that is consolidated for tax purposes) in each tax jurisdiction.  That determination includes the following procedures:
 
-
identifying the types and amounts of existing temporary differences;
 
-
measuring the total deferred tax liability for taxable temporary differences using the applicable tax rate;
 
-
measuring the total deferred tax asset for deductible temporary differences and operating loss carryforwards using the applicable tax rate;
 
-
measuring the deferred tax assets for each type of tax credit carryforward; and
 
-
reducing the deferred tax assets by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and estimates.  Additionally, we use forecasts of certain tax elements, such as taxable income and foreign tax credit utilization, as well as evaluate the feasibility of implementing tax planning strategies.  Given the inherent uncertainty involved with the use of such variables, there can be significant variation between anticipated and actual results.  Unforeseen events may significantly impact these variables, and changes to these variables could have a material impact on our income tax accounts related to both continuing and discontinued operations.
We have operations in approximately 70 countries other than the United States.  Consequently, we are subject to the jurisdiction of a significant number of taxing authorities.  The income earned in these various jurisdictions is taxed on differing bases, including income actually earned, income deemed earned, and revenue-based tax withholding.  The final determination of our income tax liabilities involves the interpretation of local tax laws, tax treaties, and related authorities in each jurisdiction.  Changes in the operating environment, including changes in tax law and currency/repatriation controls, could impact the determination of our income tax liabilities for a tax year.
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.  They also provide guidance for derecognition classification, interest and penalties, accounting in interim periods, disclosure, and transition.

 
28

 

Legal and investigation matters
As discussed in Note 8 of our consolidated financial statements, as of December 31, 2009, we have accrued an estimate of the probable and estimable costs for the resolution of some of these legal 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 precision of these estimates is impacted by 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.
Indemnity valuations
We provided indemnification in favor of KBR for certain contingent liabilities related to FCPA investigations and the Barracuda-Caratinga bolts matter.  See Note 7 and 8 to the consolidated financial statements for further information.  Accounting standards require recognition of third-party indemnities at their inception.  Therefore, we recorded our estimate of the fair market value of these indemnities as of the date of KBR’s separation.  The initial amounts recorded for the FCPA and Barracuda-Caratinga indemnities were based upon analyses conducted by a third-party valuation expert.  The valuation models employed a probability-weighted cost analysis, with certain assumptions based upon the accumulation of data and knowledge of the relevant issues.  The accounting standards state that the subsequent measurement of such liabilities should not necessarily be based on fair value.  The standards reference accounting for subsequent adjustments to these types of liabilities as you would under the current accounting guidance for contingent liabilities.  As such, subsequent adjustments to the indemnities provided to KBR upon separation, including the indemnity relating to the FCPA investigations, have been recorded when the loss is both probable and estimable.
Value of long-lived assets, including intangible assets
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 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.

 
29

 

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.  The impairment test consists of a two-step process.  The first step compares the fair value of a reporting unit with its carrying amount, including goodwill, and utilizes a future cash flow analysis based on the estimates and assumptions of our forecasted long-term growth model.  If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not impaired.  If the carrying amount of a reporting unit exceeds its fair value, we perform the second step of the goodwill impairment test to measure the amount of the impairment loss, if any.  The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill.  The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination.  In other words, the estimated fair value of the reporting unit is allocated to all of the assets and liabilities of that unit (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination and the fair value of the reporting unit was the purchase price paid.  If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess.  Any impairment charge that we record reduces our earnings.  The fair value of each of our reporting units exceeded its carrying amount by a significant margin for 2009, 2008, and 2007.  See Note 1 to the consolidated financial statements for accounting policies related to long-lived assets and intangible assets.
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 inventory, identifiable intangible assets, and any other significant assets or liabilities when appropriate.  We adjust the preliminary purchase price allocation, as necessary, as we obtain more information regarding asset valuations and liabilities assumed until the expiration of the measurement period. 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 plan benefit obligations and the expected long-term rate of return on plan assets used in determining net periodic pension expense.  Other critical assumptions and estimates used in determining benefit obligations and plan expenses, 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.

 
30

 

The discount rates utilized in 2009 to determine the projected benefit obligation at the measurement date for our qualified United States continuing pension plans ranged from 5.5% to 6.0%, compared to a range of 5.7% to 5.8% in 2008.  The discount rate utilized in 2009 to determine the projected benefit obligation at the measurement date for our United Kingdom pension plan, which constitutes 74% of our international plans’ pension obligations and 65% of our entire pension obligation, was 5.9%, compared to a discount rate of 5.8% utilized in 2008.  The expected long-term rate of return assumption used for determining 2009 and 2008 net periodic pension expense for our qualified United States pension plans was 8.0%.  The expected long-term rate of return assumption used for our United Kingdom pension plan expense was 6.5% in 2009 and 7.0% in 2008.  The following table illustrates the sensitivity to changes in certain assumptions, holding all other assumptions constant, for the United Kingdom pension plan.

   
Effect on
   
Pretax Pension
   
Pension Benefit Obligation
Millions of dollars
 
Expense in 2009
   
at December 31, 2009
25-basis-point decrease in discount rate
  $      1     $     35  
25-basis-point increase in discount rate
  $     (1)     $    (33)  
25-basis-point decrease in expected long-term rate of return
  $      1    
  NA
25-basis-point increase in expected long-term rate of return
  $     (1)    
      NA

Our defined benefit plans reduced pretax income by $36 million in 2009 and $48 million in both 2008 and 2007.  Included in these amounts was income from our expected pension returns of $45 million in 2009, $51 million in 2008, and $47 million in 2007.  Actual returns on plan assets were $121 million in 2009, compared to actual losses on plan assets of $144 million in 2008.  The decline in value of plan assets in 2008 was largely due to significant deterioration in the financial markets and broadening market decline in the fourth quarter of 2008.  The difference between actual and expected returns and the impact of changes to assumptions affecting the benefit obligations are deferred and recorded net of tax in other comprehensive income as actuarial gain or loss and are recognized as future pension expense.  Our net actuarial loss, net of tax, related to pension plans at December 31, 2009 was $185 million.  In our international plans where employees continue to earn additional benefits for continued service, unrecognized actuarial gains and losses are being recognized over a period of 6 to 19 years, which represents the expected average remaining service of the participant group expected to receive benefits.  In our international plans where benefits are not accrued for continued service, unrecognized actuarial gains and losses are being recognized over a period of 20 to 36 years, which represents the average remaining life expectancy of the participant group expected to receive benefits.
During 2009, we made contributions of $99 million to fund our defined benefit plans.  Of this amount, we contributed $71 million to our United Kingdom plan in 2009, $66 million of which was a discretionary contribution in conjunction with amending the plan to cease benefit accruals for service after June 30, 2009.  We expect to make contributions of approximately $38 million to our defined benefit plans in 2010.
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 13 to the consolidated financial statements for further information related to defined benefit and other postretirement benefit plans.

 
31

 

Allowance for bad debts
We evaluate our accounts receivable through a continuous process of assessing our portfolio on an individual customer and overall basis.  This process consists of a thorough review of historical collection experience, current aging status of the customer accounts, financial condition of our customers, and whether the receivables involve retainages.  We also consider the economic environment of our customers, both from a marketplace and geographic perspective, in evaluating the need for an allowance.  Based on our review of these factors, we establish or adjust allowances for specific customers and the accounts receivable portfolio as a whole.  This process involves a high degree of judgment and estimation, and frequently involves significant dollar amounts.  Accordingly, our results of operations can be affected by adjustments to the allowance due to actual write-offs that differ from estimated amounts.  Our estimates of allowances for bad debts have historically been accurate.  Over the last five years, our estimates of allowances for bad debts, as a percentage of notes and accounts receivable before the allowance, have ranged from 1.5% to 3.0%.  At December 31, 2009, allowance for bad debts totaled $90 million or 3.0% of notes and accounts receivable before the allowance, and at December 31, 2008, allowance for bad debts totaled $60 million or 1.6% of notes and accounts receivable before the allowance.  A 1% change in our estimate of the collectability of our notes and accounts receivable balance as of December 31, 2009 would have resulted in a $30 million adjustment to 2009 total operating costs and expenses.
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.  This method of accounting requires us to calculate job profit to be recognized in each reporting period for each job based upon our projections of future outcomes, which include:
 
-
estimates of the total cost to complete the project;
 
-
estimates of project schedule and completion date;
 
-
estimates of the extent of progress toward completion; and
 
-
amounts of any probable unapproved claims and change orders included in revenue.
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.  Our project personnel periodically evaluate the estimated costs, claims, change orders, and percentage of completion at the project level.  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.
When calculating the amount of total profit or loss on a long-term contract, we include unapproved claims as revenue when the collection is deemed probable based upon the four criteria for recognizing unapproved claims under current accounting standards.  Including probable unapproved claims in this calculation increases the operating income (or reduces the operating loss) that would otherwise be recorded without consideration of the probable unapproved claims.  Probable unapproved claims are recorded to the extent of costs incurred and include no profit element.  In all cases, the probable unapproved claims included in determining contract profit or loss are less than the actual claim that will be or has been presented to the customer.

 
32

 

At least quarterly, significant projects are reviewed in detail by senior management.  There are many factors that impact future costs, including but not limited to weather, inflation, labor and community disruptions, timely availability of materials, productivity, and other factors as outlined in our “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.  However, in the future, we expect our business with national or state-owned oil companies to grow relative to our other business, with these types of contracts likely comprising a more significant portion of our business.  See Note 1 to the consolidated financial statements for further information.

OFF BALANCE SHEET ARRANGEMENTS

At December 31, 2009, 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 – Future uses of cash.”

FINANCIAL INSTRUMENT MARKET RISK

We are exposed to market risk from changes in foreign currency exchange rates, interest rates, and commodity prices.  We selectively manage these exposures through the use of derivative instruments to mitigate our market risk from these exposures.  The objective of our risk management strategy is to minimize the volatility from fluctuations in foreign currency rates.  Our use of derivative instruments entails the following types of market risk:
 
-
volatility of the currency rates;
 
-
counterparty credit risk;
 
-
time horizon of the derivative instruments; and
 
-
the type of derivative instruments used.
We do not use derivative instruments for trading purposes.  We do not consider any of these risk management activities to be material.  See Note 1 to the consolidated financial statements for additional information on our accounting policies related to derivative instruments.  See Note 12 to the consolidated financial statements for additional disclosures related to financial instruments.
Interest rate risk
We currently do not have any variable-rate, long-term debt that exposes us to interest rate risk.
The following table represents principal amounts of our long-term debt at December 31, 2009 and related weighted average interest rates on the repayment amounts by year of maturity for our long-term debt.

         
2017 and
       
Millions of dollars
 
2010
   
Thereafter
   
Total
 
Repayment amount ($US)
  $ 750     $ 3,834     $ 4,584  
Weighted average
                       
interest rate on
                       
repayment amount
    5.5 %     6.9 %     6.6 %

The fair market value of long-term debt was $5.3 billion as of December 31, 2009.


 
33

 

ENVIRONMENTAL MATTERS

We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide.  For information related to environmental matters, see Note 8 to the consolidated financial statements and “Risk Factors—Customers and Business” under the subheading “Environmental requirements.”

NEW ACCOUNTING PRONOUNCEMENTS

In October 2009, the FASB issued an update to existing guidance on revenue recognition for arrangements with multiple deliverables.  This update will allow companies to allocate consideration received for qualified separate deliverables using estimated selling price for both delivered and undelivered items when vendor-specific objective evidence or third-party evidence is unavailable.  Additional disclosures discussing the nature of multiple element arrangements, the types of deliverables under the arrangements, the general timing of their delivery, and significant factors and estimates used to determine estimated selling prices are required.  We will adopt this update for new revenue arrangements entered into or materially modified beginning January 1, 2011.  We have not yet determined the impact on our consolidated financial statements.
In June 2009, the FASB issued a new accounting standard which provides amendments to previous guidance on the consolidation of variable interest entities.   This standard clarifies the characteristics that identify a variable interest entity (VIE) and changes how a reporting entity identifies a primary beneficiary that would consolidate the VIE from a quantitative risk and rewards calculation to a qualitative approach based on which variable interest holder has controlling financial interest and the ability to direct the most significant activities that impact the VIE’s economic performance.  This standard requires the primary beneficiary assessment to be performed on a continuous basis.  It also requires additional disclosures about an entity’s involvement with a VIE, restrictions on the VIE’s assets and liabilities that are included in the reporting entity’s consolidated balance sheet, significant risk exposures due to the entity’s involvement with the VIE, and how its involvement with a VIE impacts the reporting entity’s consolidated financial statements. The standard is effective for fiscal years beginning after November 15, 2009.  We adopted the standard on January 1, 2010, and it will not have a material impact on our consolidated financial statements.

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,” “expects,” “do not expect,” “anticipates,” “do not anticipate,” 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.

 
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RISK FACTORS

While it is not possible to identify all risk factors, we continue to face many risks and uncertainties that could cause actual results to differ from our forward-looking statements and could otherwise have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

Foreign Corrupt Practices Act Investigations
Background.  As a result of an ongoing FCPA investigation at the time of the KBR separation, we provided indemnification in favor of KBR under the master separation agreement for certain contingent liabilities, including our indemnification of KBR and any of its greater than 50%-owned subsidiaries as of November 20, 2006, the date of the master separation agreement, for fines or other monetary penalties or direct monetary damages, including disgorgement, as a result of a claim made or assessed by a governmental authority in the United States, the United Kingdom, France, Nigeria, Switzerland, and/or Algeria, or a settlement thereof, related to alleged or actual violations occurring prior to November 20, 2006 of the FCPA or particular, analogous applicable foreign statutes, laws, rules, and regulations in connection with investigations pending as of that date, including with respect to the construction and subsequent expansion by TSKJ of a multibillion dollar natural gas liquefaction complex and related facilities at Bonny Island in Rivers State, Nigeria.
TSKJ is a private limited liability company registered in Madeira, Portugal whose members are Technip SA of France, Snamprogetti Netherlands B.V. (a subsidiary of Saipem SpA of Italy), JGC Corporation of Japan, and Kellogg Brown & Root LLC (a subsidiary of KBR), each of which had an approximate 25% beneficial interest in the venture.  Part of KBR’s ownership in TSKJ was held through M.W. Kellogg Limited (MWKL), a United Kingdom joint venture and subcontractor on the Bonny Island project, in which KBR beneficially owns a 55% interest.  TSKJ and other similarly owned entities entered into various contracts to build and expand the liquefied natural gas project for Nigeria LNG Limited, which is owned by the Nigerian National Petroleum Corporation, Shell Gas B.V., Cleag Limited (an affiliate of Total), and Agip International B.V. (an affiliate of ENI SpA of Italy).
DOJ and SEC investigations resolved.  In February 2009, the FCPA investigations by the DOJ and the SEC were resolved with respect to KBR and us.  The DOJ and SEC investigations resulted from allegations of improper payments to government officials in Nigeria in connection with the construction and subsequent expansion by TSKJ of the Bonny Island project.
The DOJ investigation was resolved with respect to us with a non-prosecution agreement in which the DOJ agreed not to bring FCPA or bid coordination-related charges against us with respect to the matters under investigation, and in which we agreed to continue to cooperate with the DOJ’s ongoing investigation and to refrain from and self-report certain FCPA violations.  The DOJ agreement did not provide a monitor for us.
As part of the resolution of the SEC investigation, we retained an independent consultant to conduct a 60-day review and evaluation of our internal controls and record-keeping policies as they relate to the FCPA, and we agreed to adopt any necessary anti-bribery and foreign agent internal controls and record-keeping procedures recommended by the independent consultant.  The review and evaluation were completed during the second quarter of 2009, and we have implemented the consultant’s immediate recommendations and will implement the remaining long-term recommendations by mid-year 2010.  As a result of the substantial enhancement of our anti-bribery and foreign agent internal controls and record-keeping procedures prior to the review of the independent consultant, we do not expect the implementation of the consultant’s recommendations to materially impact our long-term strategy to grow our international operations.  In 2010, the independent consultant will perform a 30-day, follow-up review to confirm that we have implemented the recommendations and continued the application of our current policies and procedures and to recommend any additional improvements.

 
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KBR has agreed that our indemnification obligations with respect to the DOJ and SEC FCPA investigations have been fully satisfied.
Other matters.  In addition to the DOJ and the SEC investigations, we are aware of other investigations in France, Nigeria, the United Kingdom, and Switzerland regarding the Bonny Island project.  In the United Kingdom, the Serious Fraud Office (SFO) is considering civil claims or criminal prosecution under various United Kingdom laws and appears to be focused on the actions of MWKL, among others.  Violations of these laws could result in fines, restitution and confiscation of revenues, among other penalties, some of which could be subject to our indemnification obligations under the master separation agreement. Our indemnity for penalties under the master separation agreement with respect to MWKL is limited to 55% of such penalties, which is KBR’s beneficial ownership interest in MWKL.  MWKL is cooperating with the SFO’s investigation.  Whether the SFO pursues civil or criminal claims, and the amount of any fines, restitution, confiscation of revenues or other penalties that could be assessed would depend on, among other factors, the SFO’s findings regarding the amount, timing, nature and scope of any improper payments or other activities, whether any such payments or other activities were authorized by or made with knowledge of MWKL, the amount of revenue involved, and the level of cooperation provided to the SFO during the investigations.  MWKL has informed the SFO that it intends to self-report corporate liability for corruption-related offenses arising out of the Bonny Island project.  Based on discussions with the SFO, MWKL expects to receive confirmation that it will be admitted into the plea negotiation process under the Guidelines on Plea Discussions in Cases of Complex or Serious Fraud, which have been issued by the Attorney General for England and Wales.
The DOJ and SEC settlements and the other ongoing investigations could result in third-party claims against us, which may include claims for special, indirect, derivative or consequential damages, damage to our business or reputation, loss of, or adverse effect on, cash flow, assets, goodwill, results of operations, business prospects, profits or business value or claims by directors, officers, employees, affiliates, advisors, attorneys, agents, debt holders, or other interest holders or constituents of us or our current or former subsidiaries.
Our indemnity of KBR and its majority-owned subsidiaries continues with respect to other investigations within the scope of our indemnity. Our indemnification obligation to KBR does not include losses resulting from third-party claims against KBR, including claims for special, indirect, derivative or consequential damages, nor does our indemnification apply to damage to KBR’s business or reputation, loss of, or adverse effect on, cash flow, assets, goodwill, results of operations, business prospects, profits or business value or claims by directors, officers, employees, affiliates, advisors, attorneys, agents, debt holders, or other interest holders or constituents of KBR or KBR’s current or former subsidiaries.
At this time, other than the claims being considered by the SFO, no claims by governmental authorities in foreign jurisdictions have been asserted against the indemnified parties.  Therefore, we are unable to estimate the maximum potential amount of future payments that could be required to be made under our indemnity to KBR and its majority-owned subsidiaries related to these matters.  An adverse determination or result against us or any party indemnified by us in any investigation or third-party claim related to these FCPA matters could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.  See Note 7 to our consolidated financial statements for additional information.

 
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Barracuda-Caratinga Arbitration
We also provided indemnification in favor of KBR under the master separation agreement for all out-of-pocket cash costs and expenses (except for legal fees and other expenses of the arbitration so long as KBR controls and directs it), or cash settlements or cash arbitration awards, KBR may incur after November 20, 2006 as a result of the replacement of certain subsea flowline bolts installed in connection with the Barracuda-Caratinga project.  Under the master separation agreement, KBR currently controls the defense, counterclaim, and settlement of the subsea flowline bolts matter.  As a condition of our indemnity, for any settlement to be binding upon us, KBR must secure our prior written consent to such settlement’s terms.  We have the right to terminate the indemnity in the event KBR enters into any settlement without our prior written consent.
At Petrobras’ direction, KBR replaced certain bolts located on the subsea flowlines that failed through mid-November 2005, and KBR has informed us that additional bolts have failed thereafter, which were replaced by Petrobras.  These failed bolts were identified by Petrobras when it conducted inspections of the bolts.  We understand KBR believes several possible solutions may exist, including replacement of the bolts.  Initial estimates by KBR indicated that costs of these various solutions ranged up to $148 million.  In March 2006, Petrobras commenced arbitration against KBR claiming $220 million plus interest for the cost of monitoring and replacing the defective bolts and all related costs and expenses of the arbitration, including the cost of attorneys’ fees.  We understand KBR is vigorously defending this matter and has submitted a counterclaim in the arbitration seeking the recovery of $22 million.  The arbitration panel held an evidentiary hearing in March 2008 to determine which party is responsible for the designation of the material used for the bolts.  On May 13, 2009, the arbitration panel held that KBR and not Petrobras selected the material to be used for the bolts.  Accordingly, the arbitration panel held that there is no implied warranty by Petrobras to KBR as to the suitability of the bolt material and that the parties' rights are to be governed by the express terms of their contract.  The arbitration panel set the final hearing on liability and damages for early May 2010.   Our estimation of the indemnity obligation regarding the Barracuda-Caratinga arbitration is recorded as a liability in our consolidated financial statements as of December 31, 2009 and December 31, 2008.  An adverse determination or result against KBR in the arbitration could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.  See Note 7 to our consolidated financial statements for additional information regarding the KBR indemnification.

Impairment of Oil and Natural Gas Properties
We have interests in oil and natural gas properties in Bangladesh and North America totaling approximately $175 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 costs could have an adverse effect on our results of operations and might result in an impairment of or higher depletion rate on our oil and natural gas properties.

Geopolitical and International Environment
International and political events
A significant portion of our revenue is derived from our non-United States operations, which exposes us to risks inherent in doing business in each of the countries in which we transact business.  The occurrence of any of the risks described below could have a material adverse effect on our consolidated results of operations and consolidated financial condition.

 
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Our operations in countries other than the United States accounted for approximately 64% of our consolidated revenue during 2009, 57% of our consolidated revenue in 2008, and 56% of our consolidated revenue in 2007.  Operations in countries other than the United States are subject to various risks unique to each country.  With respect to any particular country, these risks may include:
 
-
expropriation and nationalization of our assets in that country;
 
-
political and economic instability;
 
-
civil unrest, acts of terrorism, force majeure, war, or other armed conflict;
 
-
natural disasters, including those related to earthquakes and flooding;
 
-
inflation;
 
-
currency fluctuations, devaluations, and conversion restrictions;
 
-
confiscatory taxation or other adverse tax policies;
 
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governmental activities that limit or disrupt markets, restrict payments, or limit the movement of funds;
 
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governmental activities that may result in the deprivation of contract rights; and
 
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governmental activities that may result in the inability to obtain or retain licenses required for operation.
Due to the unsettled political conditions in many oil-producing countries, our revenue and profits are subject to the adverse consequences of war, the effects of terrorism, civil unrest, strikes, currency controls, and governmental actions.  Countries where we operate that have significant political risk include:  Algeria, Indonesia, Iraq, Nigeria, Russia, Kazakhstan, Venezuela, and Yemen.  In addition, military action or continued unrest in the Middle East could impact the supply and pricing for oil and natural gas, disrupt our operations in the region and elsewhere, and increase our costs for security worldwide.
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 FCPA, which prohibits United States companies or 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 in countries outside the United States create the risk of unauthorized payments or offers of payments by one of our employees or agents that could be in violation of the FCPA, even though these parties are not always 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. In the event that we believe or have reason to believe that our employees or agents have or may have violated applicable anti-corruption laws, including the FCPA, we may be required to investigate or have outside counsel investigate the relevant facts and circumstances.  Violations of the FCPA may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could negatively affect our business, operating results and financial condition.
In addition, investigations by governmental authorities as well as legal, social, economic, and political issues in these countries could materially and adversely affect our business and operations.
Our facilities and our employees are under threat of attack in some countries where we operate.  In addition, the risks related to loss of life of our personnel and our subcontractors in these areas continue.
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 applicable laws.

 
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Military action, other armed conflicts, or terrorist attacks
Military action in Iraq and the Middle East, military tension involving North Korea and Iran, as well as the terrorist attacks of September 11, 2001 and subsequent terrorist attacks, threats of attacks, and unrest, have caused instability or uncertainty in the world’s financial and commercial markets and have significantly increased political and economic instability in some of the geographic areas in which we operate.  Acts of terrorism and threats of armed conflicts in or around various areas in which we operate, such as the Middle East, Nigeria, and Indonesia, could limit or disrupt markets and our operations, including disruptions resulting from the evacuation of personnel, cancellation of contracts, or the loss of personnel or assets.
Such events may cause further disruption to financial and commercial markets and may generate greater political and economic instability in some of the geographic areas in which we operate.  In addition, any possible reprisals as a consequence of the wars and ongoing military action in the Middle East, such as acts of terrorism in the United States or elsewhere, could materially and adversely affect us in ways we cannot predict at this time.
Income taxes
We have operations in approximately 70 countries other than the United States.  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.
Foreign exchange and currency risks
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 exchange risks resulting from changes in foreign 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.
We conduct business in countries, such as Venezuela, that have nontraded or “soft” currencies which, 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.
We selectively use hedging transactions to limit our exposure to risks from doing business in foreign currencies.  For those currencies that are not readily convertible, our ability to hedge our exposure is limited because financial hedge instruments for those currencies are nonexistent or limited.  Our ability to hedge is also limited because pricing of hedging instruments, where they exist, is often volatile and not necessarily efficient.
In addition, the value of the derivative instruments could be impacted by:
 
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adverse movements in foreign exchange rates;
 
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interest rates;
 
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commodity prices; or
 
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the value and time period of the derivative being different than the exposures or cash flows being hedged.

 
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Customers and Business
Exploration and production activity
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.  Demand 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.  Perceptions 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.
The recent worldwide recession has reduced the levels of economic activity and the expansion of industrial business operations.  This has negatively impacted worldwide demand for energy, resulting in lower oil and natural gas prices, a lowering of the level of exploration, development, and production activity, and a corresponding decline in the demand for our well services and products.  This reduction in demand could continue through 2010 and beyond, which could have an adverse effect on revenue and profitability.
Factors affecting the prices of oil and natural gas include:
 
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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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global 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;
 
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potential acceleration of development of alternative fuels; and
 
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the level of supply and demand for oil and natural gas, especially demand for natural gas in the United States.
Capital spending
Our business is directly affected by changes in capital expenditures by our customers.  Some of the changes that may materially and adversely affect us include:
 
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the consolidation of our customers, which could:
 
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cause customers to reduce their capital spending, which would in turn reduce the demand for our services and products; and
 
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result in customer personnel changes, which in turn affect the timing of contract negotiations;
 
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adverse developments in the business and operations of our customers in the oil and natural gas industry, including write-downs of reserves and reductions in capital spending for exploration, development, and production; and
 
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ability of our customers to timely pay the amounts due us.

 
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Customers
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 customer’s cash flow from operations and their access to the credit markets.  If our customers delay in 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.
In addition, there is an increased risk in doing business with customers in countries that have significant political risk or significant exposure to falling oil and natural gas prices.
Risks related to our business in Venezuela
We believe there are risks associated with our operations in Venezuela.  For example, the Venezuela National Assembly enacted legislation that allows the Venezuelan government, directly or through its state-owned oil company, to assume control over the operations and assets of certain oil service providers in exchange for reimbursement of the book value of the assets adjusted for certain liabilities. Venezuelan government officials have stated this legislation is not applicable to our company.
However, we continue to see a delay in receiving payment on our receivables from our primary customer in Venezuela.  If our customer further delays in 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.
As of December 31, 2009, our total net investment in Venezuela was approximately $236 million.  In addition to this amount, we also have $380 million of surety bond guarantees outstanding relating to our Venezuelan operations.
We historically have remeasured our net Bolívar Fuerte-denominated monetary asset position at the official exchange rate.  In January 2010, the Venezuelan government announced a devaluation of the Bolívar Fuerte under a new two-exchange rate system: one rate for essential products and the other rate for non-essential products.
The future results of our Venezuelan operations will be affected by many factors, including our ability to take actions to mitigate the effect of the devaluation, further actions of the Venezuelan government, and general economic conditions such as continued inflation and future customer payments and spending.
Business with national oil companies
Much of the world’s oil and natural gas reserves are controlled by national or state-owned oil companies (NOCs).  Several of the 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, losses, and contract delays.

 
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Long-term, fixed-price contracts
Customers, primarily NOCs, often 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 the NOCs for these delays.  This may reduce the profit to be realized or result in a loss on a project.  Currently, long-term, fixed price contracts with NOCs do not comprise a significant portion of our business.  However, in the future, based on the anticipated growth of NOCs, we expect our business with NOCs to grow relative to our other business, with these types of contracts likely comprising a more significant portion of our business.
Acquisitions, dispositions, investments, and joint ventures
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 result in the realization of savings, the creation of efficiencies, 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 consolidated results of operations.
These transactions also involve risks, and we cannot ensure that:
 
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any acquisitions would result in an increase in income;
 
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any acquisitions would be successfully integrated into our operations and internal controls;
 
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the due diligence prior to an acquisition would uncover situations that could result in 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 results of operations or financial condition.
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 potentially materially and adversely affect the business and operations of the joint venture and, in turn, our business and operations.

 
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Environmental requirements
Our businesses are subject to a variety of 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.  Environmental 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.
Environmental and other similar requirements generally are becoming increasingly strict.  Sanctions for failure to comply with these 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 consolidated financial condition.  We are also exposed to costs arising from environmental compliance, including compliance with changes in or expansion of environmental requirements, which could have a material adverse effect on our business, financial condition, operating results, or cash flows.
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 consolidated results of operations.
We are periodically notified of potential liabilities at state and federal 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, since 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.

 
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Changes in environmental requirements 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, and use of carbon dioxide that could have an adverse effect on our results of operations, liquidity, and financial condition.
We are a leading provider of hydraulic fracturing services, 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.  Bills pending in the United States House and Senate have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies.  The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process.  This legislation, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays and increased operating costs. The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas and oil wells and could have an adverse impact on our future results of operations, liquidity, and financial condition.
Law and regulatory requirements
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 affect on the results of operations.
Raw materials
Raw materials essential to our business are normally readily available.  Market conditions can trigger constraints in the supply chain of certain raw materials, such as sand, cement, and specialty metals.  The majority of our risk associated with supply chain constraints occurs in those situations where we have a relationship with a single supplier for a particular resource.
Intellectual property rights
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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Technology
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 revenue 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 revenue could be materially and adversely affected.
Reliance on management
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.
Technical personnel
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.
Weather
Our business could be materially and adversely affected by severe weather, particularly in the Gulf of Mexico where we have operations.  Repercussions of severe weather conditions may include:
 
-
evacuation of personnel and curtailment of services;
 
-
weather-related damage to offshore drilling rigs resulting in suspension of operations;
 
-
weather-related damage to our facilities and project work sites;
 
-
inability to deliver materials to jobsites in accordance with contract schedules; and
 
-
loss of productivity.
Because demand for natural gas in the United States drives a significant amount of our business, warmer than normal winters in the United States are detrimental to the demand for our services to natural gas producers.

 
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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Halliburton Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in the Securities Exchange Act Rule 13a-15(f).
Internal control over financial reporting, no matter how well designed, has inherent limitations.  Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.  Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time.
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, 2009 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, 2009, our internal control over financial reporting is effective.
The effectiveness of Halliburton’s internal control over financial reporting as of December 31, 2009 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

 
46

 

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, 2009 and 2008, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2009. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We 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, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 14, to the consolidated financial statements, the Company changed its method of accounting for instruments granted in share-based payment transactions as participating securities, its method of accounting for convertible debt, and its method of accounting for non-controlling interests beginning on January 1, 2009.

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, 2009, 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 17, 2010 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.



/s/  KPMG LLP
Houston, Texas
February 17, 2010

 
47

 

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, 2009, 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 the 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, 2009, 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 as of December 31, 2009 and 2008, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2009, and our report dated February 17, 2010 expressed an unqualified opinion on those consolidated financial statements.



/s/  KPMG LLP
Houston, Texas
February 17, 2010

 
48

 

HALLIBURTON COMPANY
Consolidated Statements of Operations

   
Year Ended December 31
 
Millions of dollars and shares except per share data
 
2009
   
2008
   
2007
 
Revenue:
                 
Services
  $ 10,832     $ 13,391     $ 11,256  
Product sales
    3,843       4,888       4,008  
Total revenue
    14,675       18,279       15,264  
Operating costs and expenses:
                       
Cost of services
    9,224       10,079       8,167  
Cost of sales
    3,255       3,970       3,358  
General and administrative
    207       282       293  
Gain on sale of assets, net
    (5 )     (62 )     (52 )
Total operating costs and expenses
    12,681       14,269       11,766  
Operating income
    1,994       4,010       3,498  
Interest expense
    (297 )     (167 )     (168 )
Interest income
    12       39       124  
Other, net
    (27 )     (33 )     (7 )
Income from continuing operations before
                       
income taxes
    1,682       3,849       3,447  
Provision for income taxes
    (518 )     (1,211 )     (907 )
Income from continuing operations
    1,164