Edgar Filing: HALLIBURTON CO

ed10k2008_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, 2008

[ ] 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.)
5 Houston Center
1401 McKinney, Suite 2400
Houston, Texas 77010
(Address of principal executive offices)
Telephone Number – Area code (713) 759-2600

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 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. [ ]

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, 2008, determined using the per share closing price on the New York Stock Exchange Composite tape of $53.07 on that date was approximately $46,371,000,000.

As of February 13, 2009, there were 897,174,201 shares of Halliburton Company Common Stock, $2.50 par value per share, outstanding.

Portions of the Halliburton Company Proxy Statement for our 2009 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, 2008

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
EXECUTIVE OFFICERS OF THE REGISTRANT		7
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters,
	and Issuer Purchases of Equity Securities	10
Item 6.	Selected Financial Data	11
Item 7.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	11
Item 7(a).	Quantitative and Qualitative Disclosures About Market Risk	11
Item 8.	Financial Statements and Supplementary Data	12
Item 9.	Changes in and Disagreements with Accountants on Accounting and
	Financial Disclosure	12
Item 9(a).	Controls and Procedures	12
Item 9(b).	Other Information	12
MD&A AND FINANCIAL STATEMENTS
Management’s Discussion and Analysis of Financial Condition and Results of Operations		13
Management’s Report on Internal Control Over Financial Reporting		52
Reports of Independent Registered Public Accounting Firm		53
Consolidated Statements of Operations		55
Consolidated Balance Sheets		56
Consolidated Statements of Shareholders’ Equity		57
Consolidated Statements of Cash Flows		58
Notes to Consolidated Financial Statements		59
Selected Financial Data (Unaudited)		93
Quarterly Data and Market Price Information (Unaudited)		94
PART III
Item 10.	Directors, Executive Officers, and Corporate Governance	95
Item 11.	Executive Compensation	95
Item 12(a).	Security Ownership of Certain Beneficial Owners	95
Item 12(b).	Security Ownership of Management	95
Item 12(c).	Changes in Control	96
Item 12(d).	Securities Authorized for Issuance Under Equity Compensation Plans	96
Item 13.	Certain Relationships and Related Transactions, and Director
	Independence	96
Item 14.	Principal Accounting Fees and Services	96
PART IV
Item 15.	Exhibits and Financial Statement Schedules	97
SIGNATURES		107

(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. Halliburton Company provides a variety of services and products to customers in the energy industry. We operate under two divisions, which form the basis for the two operating segments we report: the Completion and Production segment and the Drilling and Evaluation segment. See Note 4 to the consolidated financial statements for financial information about our business segments.

In November 2006, KBR, Inc. (KBR) which at the time was our wholly-owned subsidiary, completed an initial public offering. During the second quarter of 2007, we completed the separation of KBR from us and recorded a gain on the disposition of KBR of approximately $933 million, net of tax and the estimated fair value of the indemnities and guarantees provided to KBR, which is included in income from discontinued operations in the consolidated statements of operations for prior years. See Note 2 to the consolidated financial statements for further information relating to the specific indemnities and guarantees provided to KBR upon separation. During 2008, we recorded $420 million, net of tax, as a loss from discontinued operations to reflect the resolution of the Department of Justice (DOJ) and Securities and Exchange Commission (SEC) investigations related to the Foreign Corrupt Practices Act (FCPA) and our most recent assumptions regarding the value of other indemnities and guarantees provided to KBR. See Note 10 to the consolidated financial statements for further information related to the FCPA investigations.

Description of services and products

We offer a broad suite of services and products to customers through our two business segments for the exploration, development, and production of oil and gas. We serve major, national, and independent oil and gas companies throughout the world. The following summarizes our services and products for each business segment.

Completion and Production

Our Completion and Production segment delivers cementing, stimulation, intervention, and completion services. This segment consists of production enhancement services, completion tools and services, and cementing services.

Production enhancement services include stimulation services, pipeline process services, sand control services, and well intervention services. Stimulation services optimize oil and gas reservoir production through a variety of pressure pumping services, nitrogen services, and chemical processes, commonly known as hydraulic fracturing and acidizing. Pipeline process services include pipeline and facility testing, commissioning, and cleaning via pressure pumping, chemical systems, specialty equipment, and nitrogen, which are provided to the midstream and downstream sectors of the energy business. Sand control services include fluid and chemical systems and pumping services for the prevention of formation sand production. Well intervention services enable live well intervention and continuous pipe deployment capabilities through the use of hydraulic workover systems and coiled tubing tools and services.

Completion tools and services include subsurface safety valves and flow control equipment, surface safety systems, packers and specialty completion equipment, intelligent completion systems, expandable liner hanger systems, sand control systems, well servicing tools, and reservoir performance services. Reservoir performance services include testing tools, real-time reservoir analysis, and data acquisition services.

Cementing services involve bonding the well and well casing while isolating fluid zones and maximizing wellbore stability. Our cementing service line also provides casing equipment.

Drilling and Evaluation

Our Drilling and Evaluation segment provides field and reservoir modeling, drilling, evaluation, and well construction solutions that enable customers to model, measure, and optimize their well placement, stability, and reservoir evaluation activities. This segment consists of fluid services, drilling services, drill bits, wireline and perforating services, software and asset solutions, and project management services.

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

Drilling services provides drilling systems and services. These services include directional and horizontal drilling, measurement-while-drilling, logging-while-drilling, surface data logging, multilateral systems, underbalanced applications, and rig site information systems. Our drilling systems offer directional control for precise wellbore placement while providing important measurements about the characteristics of the drill string and geological formations while drilling wells. Real-time operating capabilities enable the monitoring of well progress and aid decision-making processes.

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

Wireline and perforating services include open-hole wireline services that provide information on formation evaluation, including resistivity, porosity, density, rock mechanics, and fluid sampling. Also offered are cased-hole and slickline services, which provide cement bond evaluation, reservoir monitoring, pipe evaluation, pipe recovery, mechanical services, well intervention, perforating, and borehole seismic services. Perforating services include tubing-conveyed perforating services and products. Borehole seismic services include fracture analysis and mapping.

Software and asset solutions is a supplier of integrated exploration, drilling, and production software information systems, as well as consulting and data management services for the upstream oil and gas industry.

The Drilling and Evaluation segment also provides oilfield project management and integrated solutions to independent, integrated, and national oil companies. These offerings make use of all of our oilfield services, products, technologies, and project management capabilities to assist our customers in optimizing the value of their oil and gas assets.

Acquisitions and dispositions

In July 2008, we acquired the remaining 49% equity interest in WellDynamics from Shell Technology Ventures Fund 1 B.V. (STV Fund), resulting in our 100% ownership of WellDynamics. WellDynamics is a provider of intelligent well completion technology and its results of operations are included in our Completion and Production segment.

In July 2007, we acquired the entire share capital of PSL Energy Services Limited (PSLES), a leading eastern hemisphere provider of process, pipeline, and well intervention services. PSLES has operational bases in the United Kingdom, Norway, the Middle East, Azerbaijan, Algeria, and Asia Pacific. We paid $335 million for PSLES, consisting of $331 million in cash and $4 million in debt assumed. We have recorded goodwill of $158 million and intangible assets of $61 million associated with the acquisition. Beginning in August 2007, PSLES’s results of operations are included in our Completion and Production segment.

As a part of our sale of Dresser Equipment Group in 2001, we retained a small equity interest in Dresser Inc.’s Class A common stock. Dresser Inc. was later reorganized as Dresser, Ltd., and we exchanged our shares for shares of Dresser, Ltd. In May 2007, we sold our remaining interest in Dresser, Ltd. We received $70 million in cash from the sale and recorded a $49 million gain.

In January 2007, we acquired all intellectual property, current assets, and existing business associated with Calgary-based Ultraline Services Corporation (Ultraline), a division of Savanna Energy Services Corp. Ultraline is a provider of wireline services in Canada. We paid approximately $178 million for Ultraline and recorded goodwill of $124 million and intangible assets of $41 million. Beginning in February 2007, Ultraline’s results of operations are included in our Drilling and Evaluation segment.

Business strategy

Our business strategy is to secure a distinct and sustainable competitive position as a pure-play 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;

knowledge of the reservoir;

product quality;

warranty; and

technical proficiency.

We conduct business worldwide in approximately 70 countries. The business operations of our divisions are organized around four primary geographic regions: North America, Latin America, Europe/Africa/CIS, and Middle East/Asia. In 2008, based on the location of services provided and products sold, 43% of our consolidated revenue was from the United States. In 2007 and 2006, 44% and 45% 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 4 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 14 to the consolidated financial statements.

Customers

Our revenue from continuing operations during the past three years was derived from the sale of services and products to the energy industry. No customer represented more than 10% of 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. Our expenditures for research and development activities were $326 million in 2008, $301 million in 2007, and $254 million in 2006, 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

On an overall basis, our operations are not generally affected by 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:

the severity and duration of the winter in North America can have a significant impact on 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, 2008, we employed approximately 57,000 people worldwide compared to approximately 51,000 at December 31, 2007. At December 31, 2008, approximately 14% 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. In the United States, these laws and regulations include, among others:

the Comprehensive Environmental Response, Compensation, and Liability Act;

the Resource Conservation and Recovery Act;

the Clean Air Act;

the Federal Water Pollution Control Act; and

the Toxic Substances Control Act.

In addition to the federal laws and regulations, states and other countries where we do business may have numerous environmental, legal, and regulatory requirements by which we must abide. We evaluate and address the environmental impact of our operations by assessing and remediating contaminated properties in order to avoid future liabilities and comply with environmental, legal, and regulatory requirements. On occasion, we are involved in specific environmental litigation and claims, including the remediation of properties we own or have operated, as well as efforts to meet or correct compliance-related matters. Our Health, Safety, and Environment group has several programs in place to maintain environmental leadership and to prevent the occurrence of environmental contamination.

We do not expect costs related to these remediation requirements to have a material adverse effect on our consolidated financial position or our results of operations.

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 facilities are 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 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 presented, 2008, 2007, or 2006. The CEO and CFO certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 have been filed as exhibits to our Form 10-K. We have also submitted the Annual CEO Certification to the New York Stock Exchange.

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
Operations:
Completion and Production segment:
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
Houston, Texas	Owned	Manufacturing, technology, and campus facilities
Singapore	Leased	Manufacturing and technology facility
The Woodlands, Texas	Leased	Manufacturing facility

Shared facilities:
Carrollton, Texas	Owned	Manufacturing facility
Duncan, Oklahoma	Owned	Manufacturing, technology, and campus facilities
Houston, Texas	Owned	Campus facility
Houston, Texas	Leased	Campus facility
Pune, India	Leased	Technology facility

Corporate:
Houston, Texas	Leased	Corporate executive offices
Dubai, United Arab Emirates	Leased	Corporate executive offices

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 10 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 2008.

Executive Officers of the Registrant

The following table indicates the names and ages of the executive officers of Halliburton Company as of February 13, 2009, 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 41)	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 54)	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
	Vice President, Western Area of Halliburton Company, November 2003
	to December 2003

* Albert O. Cornelison, Jr.	Executive Vice President and General Counsel of Halliburton Company,
(Age 59)	since December 2002
	Director of KBR, Inc., June 2006 to April 2007

C. Christopher Gaut	President, Drilling and Evaluation Division of Halliburton Company,
(Age 52)	since January 2008
	Director of KBR, Inc., March 2006 to April 2007
	Executive Vice President and Chief Financial Officer of Halliburton Company,
	March 2003 to December 2007

Name and Age	Offices Held and Term of Office
David S. King	President, Completion and Production Division of Halliburton Company,
(Age 52)	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
	Vice President, Production Optimization of Halliburton Energy Services
	Group, May 2003 to July 2004

* David J. Lesar	Chairman of the Board, President, and Chief Executive Officer of Halliburton
(Age 55)	Company, since August 2000

Ahmed H. M. Lotfy	President, Eastern Hemisphere of Halliburton Company, since January 2008
(Age 54)	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
	Vice President, North Africa Region of Halliburton Company,
	June 2002 to December 2004

* Mark A. McCollum	Executive Vice President and Chief Financial Officer of Halliburton Company,
(Age 49)	since January 2008
	Director of KBR, Inc., June 2006 to April 2007
	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 47)	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

Name and Age	Offices Held and Term of Office
* Lawrence J. Pope	Executive Vice President of Administration and Chief Human Resources Officer
(Age 40)	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
	Director, Finance and Administration for Drilling and Formation Evaluation
	Division of Halliburton Energy Services Group, July 2003 to August 2004

* Timothy J. Probert	Executive Vice President, Strategy and Corporate Development of Halliburton
(Age 57)	Company, since January 2008
	Senior Vice President, Drilling and Evaluation of Halliburton Company,
	July 2007 to December 2007
	Senior Vice President, Drilling 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.

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 94 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 2008 and June, September, and December of 2007. Cash dividends on common stock in the amount of $0.075 per share were paid in March of 2007. 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, 2008, 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, 2003, and the reinvestment of all dividends. The shareholder return set forth is not necessarily indicative of future performance.

	December 31
	2003		2004		2005		2006		2007		2008
Halliburton	$	100.00	$	153.28	$	244.43	$	247.14	$	304.79	$	147.95
Standard & Poor’s 500 Stock Index		100.00		110.88		116.33		134.70		142.10		89.53
Standard & Poor’s Energy Composite Index		100.00		131.54		172.80		214.63		288.47		187.88

At February 13, 2009, there were 18,585 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.

Following is a summary of repurchases of our common stock during the three-month period ended December 31, 2008.

					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		36,642	$	26.20		–
November 1-30		12,264	$	18.46		–
December 1-31		66,986	$	15.32		–
Total		115,892	$	19.09		–

(a)

All of the 115,892 shares purchased during the three-month period ended December 31, 2008 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 93 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 13 through 51 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 under the caption “Financial Instrument Market Risk” on page 37 of this annual report.

Item 8. Financial Statements and Supplementary Data.

	Page No.
Management’s Report on Internal Control Over Financial Reporting	52
Reports of Independent Registered Public Accounting Firm	53
Consolidated Statements of Operations for the years ended December 31, 2008, 2007, and 2006	55
Consolidated Balance Sheets at December 31, 2008 and 2007	56
Consolidated Statements of Shareholders’ Equity for the years ended	57
December 31, 2008, 2007, and 2006
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007, and 2006	58
Notes to Consolidated Financial Statements	59
Selected Financial Data (Unaudited)	93
Quarterly Data and Market Price Information (Unaudited)	94

The related financial statement schedules are included under Part IV, Item 15 of this annual report.

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, 2008 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, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

See page 52 for Management’s Report on Internal Control Over Financial Reporting and page 54 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.

Item 9(b). Other Information.

None.

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 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, software and asset solutions, and 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, Continental Europe, Malaysia, Mexico, Brazil, and Singapore. With approximately 57,000 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 2008, we produced revenue of $18.3 billion and operating income of $4.0 billion, reflecting an operating margin of 22%. Revenue increased $3.0 billion or 20% over 2007, while operating income improved $512 million or 15% over 2007. Consistent with our initiative to grow our non-North America operations, we experienced 22% revenue growth and 26% operating income growth outside of North America in 2008 compared to 2007. Revenue from our Latin America region increased 35% to $2.4 billion, and operating income increased 49% to $521 million in 2008 compared to 2007. Our Middle East/Asia region also returned revenue and operating income growth in excess of 20% in 2008 compared to 2007.

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 the current excess supply of oil and natural gas, the near- and mid-term outlook for our business and the industry remains uncertain. Forecasting the depth and length of the current recession and its impact on the declining demand for energy is challenging due to the many factors involved.

Although prices and margins had started to stabilize in North America during the first nine months of 2008, a significant reduction in activity beginning in December of 2008 and a corresponding drop in the United States rig count from the end of the third quarter of 2008 have reversed this trend. Pricing declines are now occurring due to excess equipment and customer requests for discounts on existing work. In 2009, rig counts have continued to fall and as of February 13, 2009 are approximately 34% below 2008 highs. Capital expenditure adjustments from our customers remain fluid as they adjust their spending in response to a continued drop in commodity price fundamentals and lack of readily available credit. As a result, we are seeing activity declines intensify and expect activity declines for North America land to accelerate in the first quarter of 2009. We also anticipate severe margin contraction to occur worldwide throughout 2009. Outside of North America, declining oil prices have caused our customers to defer many of their new projects. Operators have announced a decline in spending in 2009, and we anticipate severe margin contraction throughout 2009. Several areas have been affected by capital access issues that have constrained the ability of some of our independent, upstream customers to fund their programs. Our larger customers are deferring several platform-based projects until they see commodity price stabilization.

In 2009, we will focus on:

minimizing discretionary spending;

lowering our costs from vendors;

reducing headcount in locations experiencing significant activity declines;

focusing on working capital management and managing our balance sheet to maximize our financial flexibility;

- continuing the globalization of our manufacturing and supply chain processes;

leveraging our technologies to provide our customers with the ability to more efficiently drill and complete their wells. To that end, we opened one international research and development center with global technology and training missions in 2007 and two in 2008;

continuing to deploy our packaged services strategy that creates an efficiency model for our customers in the development of their assets;

expanding our business with national oil companies, including preparing for a shift to increased use of our integrated project management services;

continuing to pursue strategic acquisitions that enhance our technological position and our product and service portfolio in key areas, such as the following acquisitions in 2008:

in October 2008, we acquired the assets of Pinnacle Technologies, Inc. (Pinnacle), including the Pinnacle brand from CARBO Ceramics Inc. Pinnacle is a provider of microseismic fracture mapping services and tiltmeter mapping services;

in July 2008, we acquired the remaining 49% equity interest in WellDynamics B.V. (WellDynamics) from Shell Technology Ventures Fund 1 B.V. (STV Fund). We now own 100% of WellDynamics, a provider of intelligent well completion technology;

in June 2008, we acquired all the intellectual property and assets of Protech Centerform, a provider of casing centralization services; and

in May 2008, we acquired all intellectual property, assets, and existing business of Knowledge Systems Inc. (KSI), a leading provider of combined geopressure and geomechanical analysis software and services.

Our operating performance is described in more detail in “Business Environment and Results of Operations.”

Financial markets, liquidity, and capital resources

In the latter half of 2008 and so far in 2009, the equity, credit, and commodity markets have seen unprecedented volatility. While this has created certain additional risks for our business, we believe we have invested our cash balances conservatively, reduced our leverage, and secured sufficient short-term credit capacity to help mitigate any near-term, negative impact on our operations. During the third quarter of 2008, we issued an aggregate amount of $1.2 billion in senior notes and settled the principal and conversion premium on our 3.125% convertible senior notes. For additional information, see “Liquidity and Capital Resources”, “Risk Factors”, Note 9 to our consolidated financial statements, and “Business Environment and Results of Operations.”

Foreign Corrupt Practices Act (FCPA) investigations

Resolution of the DOJ and SEC FCPA investigations has resulted in additional charges in 2008 to discontinued operations. See Note 10 to our consolidated financial statements and “Risk Factors” for further information.

LIQUIDITY AND CAPITAL RESOURCES

We ended 2008 with cash and equivalents of $1.1 billion compared to $1.8 billion at December 31, 2007.

Significant sources of cash

Cash flows from operating activities contributed $2.7 billion to cash in 2008. Growth in revenue and operating income was attributable to higher customer demand and increased service intensity due to a trend toward exploration and exploitation of more complex reservoirs.

In September 2008, we issued senior notes due 2038 totaling $800 million and senior notes due 2018 totaling $400 million, which were used to pay the principal amount of our 3.125% convertible senior notes.

Early in 2008, we sold approximately $388 million of marketable securities, consisting of auction-rate securities and variable-rate demand notes.

Further available sources of cash. We have an unsecured $1.2 billion five-year revolving credit facility expiring in 2012 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, 2008.

In October of 2008, we entered into an additional unsecured, six-month revolving credit facility, with current commitments of $400 million, in order to give us additional liquidity and for other general corporate purposes. There were no cash drawings under the facility as of December 31, 2008.

Significant uses of cash

Capital expenditures were $1.8 billion in 2008, with increased focus toward building infrastructure and adding service equipment in support of our expanding operations outside of North America. Capital expenditures were predominantly made in the drilling services, production enhancement, cementing, and wireline and perforating product service lines.

During 2008, we repurchased approximately 13 million shares of our common stock under our share repurchase program at a cost of approximately $481 million at an average price of $36.61 per share.

We paid $319 million in dividends to our shareholders in 2008.

We repaid $150 million of medium term notes, which matured in December 2008.

Future uses of cash. We have approximately $1.8 billion remaining available under our share repurchase authorization, which may be used for open market share purchases.

In 2009, we believe we will maintain our capital expenditures up to 2008 levels but will monitor our customers' activity and make reductions as necessary. The capital expenditures plan for 2009 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. 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.

As a result of the resolution of the DOJ and SEC FCPA investigations, we will pay a total of $559 million over the next two years under the settlements and indemnities provided to KBR upon separation. See Notes 2 and 10 to our consolidated financial statements for more information.

Subject to Board of Directors approval, we expect to pay dividends of approximately $80 million per quarter in 2009.

The following table summarizes our significant contractual obligations and other long-term liabilities as of December 31, 2008:

	Payments Due
Millions of dollars	2009		2010		2011		2012		2013		Thereafter		Total
Long-term debt	$	26	$	749	$	–	$	–	$	–	$	1,837	$	2,612
Interest on debt (a)		168		168		127		127		126		3,578		4,294
Operating leases		183		161		130		84		66		175		799
Purchase obligations		1,501		65		32		16		5		8		1,627
Pension funding obligations (b)		48		–		–		–		–		–		48
DOJ and SEC settlement and indemnity		373		186		–		–		–		–		559
Other long-term liabilities		9		9		9		9		9		–		45
Total	$	2,308	$	1,338	$	298	$	236	$	206	$	5,598	$	9,984

(a)	Interest on debt includes 88 years of interest on $300 million of debentures at 7.6% interest that become due in 2096.

(b)

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 2009. See Note 15 to the consolidated financial statements for further information regarding pension contributions.

We had $343 million of gross unrecognized tax benefits at December 31, 2008, of which we estimate $79 million may require a cash payment. We estimate that $38 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.

Other factors affecting liquidity

Letters of credit. In the normal course of business, we have agreements with banks under which approximately $2.2 billion of letters of credit, surety bonds, or bank guarantees were outstanding as of December 31, 2008, including approximately $828 million that relate to KBR. These KBR letters of credit, surety bonds, or bank guarantees 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. In recent years, we have reduced our leverage and improved our liquidity by focusing on debt reduction and improvement to our credit profile. Our debt maturities extend over a long period of time. We have no financial covenants or material adverse change provisions in our bank agreements, and we are working to continue to improve our short-term credit capacity. We currently have a total of $1.6 billion of committed bank credit under revolving credit facilities to support our operations and any commercial paper we may issue in the future. Currently, there are no borrowings under these revolving credit facilities.

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 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.

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 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 2008, based upon the location of the services provided and products sold, 43% of our consolidated revenue was from the United States. In 2007 and 2006, 44% and 45% 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, economic recessions, 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 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 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 gas companies are oil and natural gas prices, the world economy, 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 historical average prices for West Texas Intermediate (WTI) and United Kingdom Brent crude oil and Henry Hub natural gas:

Average Oil Prices (dollars per barrel)	2008		2007		2006
West Texas Intermediate	$	99.37	$	71.91	$	66.17
United Kingdom Brent	$	96.86	$	72.21	$	65.35

Average United States Gas Prices (dollars per million British
thermal units, or mmBtu)
Henry Hub	$	8.79	$	6.97	$	6.81

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

Land vs. Offshore	2008		2007		2006
United States:
Land		1,812		1,694		1,558
Offshore (incl. Gulf of Mexico)		128		144		176
Total		1,940		1,838		1,734
Canada:
Land		378		341		467
Offshore		1		3		3
Total		379		344		470
International (excluding Canada):
Land		784		719		656
Offshore		295		287		269
Total		1,079		1,006		925
Worldwide total		3,398		3,188		3,129
Land total		2,974		2,754		2,681
Offshore total		424		434		448

Oil vs. Natural Gas	2008		2007		2006
United States (incl. Gulf of Mexico):
Oil		381		300		278
Natural Gas		1,559		1,538		1,456
Total		1,940		1,838		1,734
Canada:
Oil		160		128		110
Natural Gas		219		216		360
Total		379		344		470
International (excluding Canada):
Oil		825		784		709
Natural Gas		254		222		216
Total		1,079		1,006		925
Worldwide total		3,398		3,188		3,129
Oil total		1,366		1,212		1,097
Natural Gas total		2,032		1,976		2,032

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.

WTI oil spot prices have fallen from a high of $145 per barrel in July to an average of $41 per barrel in the month of December, according to the Energy Information Administration (EIA). As of February 10, 2009, the WTI oil spot price was $37.54 per barrel. According to the International Energy Agency’s (IEA) February 2009 “Oil Market Report,” the outlook for world petroleum demand is expected to contract for the first time since the 1980s, with the decrease in demand of North America and the Pacific only partially offset by the increase in demand in Asia, the Middle East, and Latin America. The IEA forecasts world petroleum demand in 2009 to decrease approximately 1% over 2008, but there are other forecasts that indicate that demand contraction could be more severe. Despite the decline in oil and gas prices 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. As we enter 2009, capital expenditure adjustments from our customers remain fluid as they adjust their spending in response to a continued drop in commodity price fundamentals and lack of readily available credit. In 2009, rig counts have fallen sharply and as of February 13, 2009 are approximately 34% below 2008 highs. Our customers’ capital expenditure cuts have intensified especially related to conventional and shallower drilling activity.

As noted in the table above, the Henry Hub spot price averaged $8.79 per mmBtu in 2008. However, as of February 11, 2009, the Henry Hub spot price had fallen to $4.68 per mmBtu. We began to see signs of pricing weakness in our services beginning in December of 2008 due to excess equipment and customer requests for discounts on existing work. We expect activity declines in United States land to accelerate in the first quarter of 2009. In addition, due to these volume declines and pricing adjustments, we expect severe margin contraction to occur worldwide starting in the first quarter of 2009.

Focus on international operations. Consistent with our long-term strategy to grow our operations outside of North America, we expect to continue to invest capital and increase manufacturing capacity to bring new tools online to serve the need for our services. However, operators have announced a decline in spending in 2009, and we expect to see contraction of our business, at least in the near term. Declining oil prices have caused customers to defer several of their new and platform-based projects and slowdown their existing projects. Several areas have also been affected by capital access issues that have constrained the ability of some of our independent, upstream customers to fund their programs. We continue to believe in the long-term prospects of the international market and will align our business accordingly.

As our customers award work in this environment of declining commodity prices, pricing competition in the international arena has intensified. Following is a brief discussion of some of our recent and current initiatives:

minimizing discretionary spending;

lowering our costs from vendors;

reducing headcount in locations experiencing significant activity declines;

focusing on working capital management and managing our balance sheet to maximize our financial flexibility;

making our research and development efforts more geographically diverse in order to continue to supply our customers with leading-edge services and products and to provide our customers with the ability to more efficiently drill and complete their wells. To that end, we opened a technology center in India in 2007 and in Singapore in the first quarter of 2008 and a research and development laboratory in Norway in the third quarter of 2008;

continuing to deploy our packaged services strategy that creates an efficiency model for our customers in the development of their assets;

continuing the globalization of our manufacturing and supply chain processes. In 2007 and 2008, we opened four new regional manufacturing facilities in Asia and Latin America. These new centers will enable us to be more responsive to our international customers while building regional supply networks that support local economies;

as our workforce becomes more global, the need for regional training centers increases. As a result, we have expanded our number of regional training centers to meet this need. We now have 12 training centers worldwide that integrate new workers and advance the technical skills of our workforce;

expanding our business with national oil companies, including preparing for a shift to increased use of our integrated project management services; and

continuing to pursue strategic acquisitions that enhance our technological position and our product and service portfolio in key areas, such as the following acquisitions in 2008:

in October 2008, we acquired the assets of Pinnacle, including the Pinnacle brand from CARBO Ceramics Inc. Pinnacle is a leading provider of microseismic fracture mapping services and tiltmeter mapping services;

in July 2008, we acquired the remaining 49% equity interest of WellDynamics from STV Fund. We now own 100% of WellDynamics, a provider of intelligent well completion technology;

in June 2008, we acquired all the intellectual property and assets of Protech Centerform in Houston, Ravenna, Italy, and Aberdeen, Scotland. Protech Centerform is a provider of casing centralization service;

in May 2008, we acquired all intellectual property, assets, and existing business of KSI, a leading provider of combined geopressure and geomechanical analysis software and services;

Contract wins positioning us to grow our international operations over the long term include:

a contract to manage the drilling and completion of 58 onshore wells in the southern region of Mexico;

a contract to perform workover and sidetrack services in the United Kingdom;

a contract to provide completion equipment and services, tubing conveyed perforating services and SmartWell® completion technology for numerous oil and natural gas fields on the Norwegian continental shelf. The contract also allows for the provision of other products and services;

a three-year contract to provide directional drilling, logging-while-drilling, cementing, wireline and perforating, coiled tubing, and stimulation services in support of the offshore portion of the Manifa mega-project in Saudi Arabia;

a three-year contract to provide a range of completion equipment for onshore oil and gas wells in Abu Dhabi; and

a three-year contract to provide special cased-hole services in support of our work in Indonesia’s Mahakam Delta.

RESULTS OF OPERATIONS IN 2008 COMPARED TO 2007

REVENUE:							Percentage
Millions of dollars	2008		2007		Increase		Change
Completion and Production	$	9,935	$	8,386	$	1,549		18	%
Drilling and Evaluation		8,344		6,878		1,466		21
Total revenue	$	18,279	$	15,264	$	3,015		20	%

By geographic region:
Completion and Production:
North America	$	5,348	$	4,655	$	693	15	%
Latin America		1,084		756		328	43
Europe/Africa/CIS		2,065		1,767		298	17
Middle East/Asia		1,438		1,208		230	19
Total		9,935		8,386		1,549	18
Drilling and Evaluation:
North America		2,992		2,478		514	21
Latin America		1,341		1,042		299	29
Europe/Africa/CIS		2,281		1,933		348	18
Middle East/Asia		1,730		1,425		305	21
Total		8,344		6,878		1,466	21
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

OPERATING INCOME:							Increase			Percentage
Millions of dollars	2008			2007			(Decrease)			Change
Completion and Production	$	2,409		$	2,199		$	210			10	%
Drilling and Evaluation		1,865			1,485			380			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	$	1,404	$	1,404	$	—	—	%
Latin America		260		170		90	53
Europe/Africa/CIS		409		330		79	24
Middle East/Asia		336		295		41	14
Total		2,409		2,199		210	10
Drilling and Evaluation:
North America		701		552		149	27
Latin America		261		179		82	46
Europe/Africa/CIS		448		414		34	8
Middle East/Asia		455		340		115	34
Total		1,865		1,485		380	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

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. International revenue was 57% of consolidated revenue in 2008 and 56% 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 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 gas property in Bangladesh and $32 million in charges for environmental reserves.

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 17% 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 43% 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. International revenue was 49% of total segment revenue in 2008 and 47% in 2007.

The increase in segment operating income in 2008 compared to 2007 spanned all regions except North America. Europe/Africa/CIS operating income increased 24% from increased completion tools sales and services in Africa and higher production enhancement activity in Europe. Middle East/Asia operating income increased 14% primarily due to increased sales and service revenue from completion tools and increased production enhancement activity in the region. North America operating income was 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 53% 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 18% 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 21% 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 29% 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. International revenue was 68% of total segment revenue in both 2008 and 2007.

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 8% 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 34% 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 gas property in Bangladesh. North America operating income increased 27% 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 46% 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 the loss of $693 million for the portion of the premium paid in cash on the settlement of our convertible senior notes in the third quarter and a $31 million loss on foreign exchange.

Provision for income taxes from continuing operations of $1.2 billion in 2008 resulted in an effective tax rate of 38% compared to an effective tax rate of 26% in 2007. The increase in the effective tax rate from 2007 to 2008 is primarily related to the non-tax deductibility of the $693 million loss on the portion of the premium on our convertible debt that we settled in cash. The provision for income taxes in 2007 included a $205 million favorable income tax impact from the ability to recognize foreign tax credits previously estimated not to be fully utilizable.

Minority interest in net income of subsidiaries decreased $38 million compared to 2007, primarily related to a change in effective ownership of a joint venture in 2008.

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 most recent assumptions 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.

RESULTS OF OPERATIONS IN 2007 COMPARED TO 2006

REVENUE:							Percentage
Millions of dollars	2007		2006		Increase		Change
Completion and Production	$	8,386	$	7,221	$	1,165		16	%
Drilling and Evaluation		6,878		5,734		1,144		20
Total revenue	$	15,264	$	12,955	$	2,309		18	%

By geographic region:
Completion and Production:
North America	$	4,655	$	4,275	$	380	9	%
Latin America		756		583		173	30
Europe/Africa/CIS		1,767		1,436		331	23
Middle East/Asia		1,208		927		281	30
Total		8,386		7,221		1,165	16
Drilling and Evaluation:
North America		2,478		2,183		295	14
Latin America		1,042		931		111	12
Europe/Africa/CIS		1,933		1,424		509	36
Middle East/Asia		1,425		1,196		229	19
Total		6,878		5,734		1,144	20
Total revenue by region:
North America		7,133		6,458		675	10
Latin America		1,798		1,514		284	19
Europe/Africa/CIS		3,700		2,860		840	29
Middle East/Asia		2,633		2,123		510	24

OPERATING INCOME:							Increase		Percentage
Millions of dollars	2007			2006			(Decrease)		Change
Completion and Production	$	2,199		$	2,140		$	59		3	%
Drilling and Evaluation		1,485			1,328			157		12
Corporate and other		(186	)		(223	)		37		17
Total operating income	$	3,498		$	3,245		$	253		8	%

By geographic region:
Completion and Production:
North America	$	1,404	$	1,476	$	(72	)	(5	)%
Latin America		170		130		40		31
Europe/Africa/CIS		330		324		6		2
Middle East/Asia		295		210		85		40
Total		2,199		2,140		59		3
Drilling and Evaluation:
North America		552		595		(43	)	(7	)
Latin America		179		170		9		5
Europe/Africa/CIS		414		263		151		57
Middle East/Asia		340		300		40		13
Total		1,485		1,328		157		12
Total operating income by region
(excluding Corporate and other):
North America		1,956		2,071		(115	)	(6	)
Latin America		349		300		49		16
Europe/Africa/CIS		744		587		157		27
Middle East/Asia		635		510		125		25

The increase in consolidated revenue in 2007 compared to 2006 spanned all four regions in both segments and was attributable to higher worldwide activity, particularly in Europe, Africa, and the United States. Revenue derived from the eastern hemisphere contributed 58% to the total revenue increase. International revenue was 56% of consolidated revenue in 2007 and 55% of consolidated revenue in 2006.

The increase in consolidated operating income was primarily derived from the eastern hemisphere, which increased 26% compared to 2006. Operating income for 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 gas property in Bangladesh and $32 million in charges for environmental reserves. Operating income for 2006 included a $48 million gain on the sale of lift boats in West Africa and the North Sea and $47 million of insurance proceeds for business interruptions resulting from the 2005 Gulf of Mexico hurricanes.

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

Completion and Production increase in revenue compared to 2006 was derived from all regions. Europe/Africa/CIS revenue grew 23% on increased activity from production enhancement services in Europe and Africa. The region also benefited from increased activity in our intelligent well completions sales and increased completion product sales in Africa and improved cementing services pricing in the North Sea and Russia. Middle East/Asia revenue grew 30% from increased completion product sales in Asia, improved completion tools sales in the Middle East, and new cementing services contracts in the Middle East. North America revenue improved 9% largely driven by increased production enhancement services and cementing services activity in the United States. The North America revenue increase was partially offset by lower pricing, particularly in fracturing, and decreased production enhancement services activity in Canada. Latin America revenue increased 30% largely driven by cementing services revenue increasing on new contracts and improved pricing, increased production enhancement activity in Mexico, and increased completion product sales and services activity in Brazil. International revenue was 47% of total segment revenue in 2007 compared to 45% in 2006.

The Completion and Production segment operating income improvement spanned all regions except North America. Europe/Africa/CIS operating income grew 2% from increased activity and improved pricing for cementing services in the North Sea. Europe/Africa/CIS segment operating income in 2006 included a $48 million gain on the sale of lift boats in west Africa and the North Sea. Middle East/Asia operating income grew 40% from improved completion product deliveries in Asia and the Middle East and additional cementing service projects in the Middle East. North America operating income decreased 5% largely because the segment received hurricane insurance proceeds of $21 million in 2006 and due to a decline in production enhancement services pricing. Latin America operating income increased 31% due to new technology and improved pricing for cementing services.

Drilling and Evaluation revenue increase in 2007 compared to 2006 was derived from all four regions. Europe/Africa/CIS revenue improved 36% from increased drilling services activity throughout the region, new fluid services contracts in the North Sea, and increased wireline and perforating services in Africa. Middle East/Asia revenue increased 19% from additional drilling service contract awards and activity in the region, new wireline and perforating services contracts in Asia, and increased fluid sales in the Middle East. North America revenue grew 14% from improvements in all product service lines, particularly wireline and perforating services and drilling services. The United States benefited from increased land rig activity, particularly for horizontally and directionally drilled wells. Latin America revenue improved 12% primarily on increased activity in drilling services, fluid services, and wireline and perforating services. International revenue was 68% of total segment revenue in 2007 compared to 67% in 2006.

Drilling and Evaluation operating income increase compared to 2006 was led by the eastern hemisphere. Europe/Africa/CIS Drilling and Evaluation operating income grew 57% from increased drilling services activity in Europe and Africa. Africa also benefited from improved fluid service product mix and new wireline and perforating projects. Middle East/Asia operating income grew 13% from additional drilling service and wireline and perforating activity in the Middle East and Asia. Included in the region in 2007 was a $34 million charge related to the impairment of an oil and gas property in Bangladesh. Latin America operating income increased 5% from increased wireline and perforating activity. Partially offsetting the improvement was decreased fluid service activity. North America operating income fell 7% largely because the segment received hurricane insurance proceeds of $26 million in 2006 and recorded a $24 million environmental exposure charge in the third quarter of 2007.

Corporate and other expenses were $186 million in 2007 compared to $223 million in 2006. 2007 included a $49 million gain recorded on the sale of our remaining interest in Dresser, Ltd. and a $12 million charge for executive separation costs.

NONOPERATING ITEMS

Interest expense decreased $11 million in 2007 compared to 2006, primarily due to the repayment in August 2006 of $275 million of our medium-term notes.

Interest income decreased $5 million in 2007 compared to 2006 due to lower average cash balances.

Provision for income taxes from continuing operations in 2007 of $907 million resulted in an effective tax rate of 26% compared to an effective tax rate of 31% in 2006. The provision for income taxes in 2007 included a $205 million favorable income tax impact from the ability to recognize foreign tax credits previously estimated not to be fully utilizable.

Minority interest in net income of subsidiaries increased $10 million compared to 2006, primarily related to our joint venture in Saudi Arabia.

Income (loss) from discontinued operations, net of income tax in 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.

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;

percentage-of-completion accounting for long-term, construction-type contracts;

legal and investigation matters;

valuations of indemnities;

valuations of long-lived assets, including intangible assets;

purchase price allocation for acquired businesses;

pensions; and

allowance for bad debts.

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 account for income taxes in accordance with Statement of Financial Accounting Standards (SFAS) No. 109, “Accounting for Income Taxes,” which requires recognition of the amount of taxes payable or refundable for the current year and an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been recognized in our financial statements or tax returns. We apply the following basic principles in accounting for our income taxes:

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

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

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

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

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

identifying the types and amounts of existing temporary differences;

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

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

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

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

Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and estimates. Additionally, we use forecasts of certain tax elements, such as taxable income and foreign tax credit utilization, as well as evaluate the feasibility of implementing tax planning strategies. Given the inherent uncertainty involved with the use of such variables, there can be significant variation between anticipated and actual results. Unforeseen events may significantly impact these variables, and changes to these variables could have a material impact on our income tax accounts related to both continuing and discontinued operations.

We have operations in approximately 70 countries 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 FASB Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” FIN 48, as amended May 2007 by FASB Staff Position (FSP) FIN 48-1, “Definition of ‘Settlement’ in FASB Interpretation No. 48,” prescribes 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. It also provides guidance for derecognition classification, interest and penalties, accounting in interim periods, disclosure, and transition.

We had recorded a valuation allowance based on the anticipated inability to utilize future foreign tax credits in the United States as of the end of 2006. This valuation allowance is reassessed quarterly based on a number of estimates, including future creditable foreign income taxes and future taxable income. Factors such as actual operating results, material acquisitions or dispositions, and changes to our operating environment could alter the estimates, which could have a material impact on the valuation allowance. Given that we fully utilized the United States net operating loss and began utilizing foreign tax credits in the United States in 2006, the valuation allowance balance has been reduced to zero as of the end of 2007. In addition, the provision for income taxes in 2007 included a favorable income tax adjustment from the ability to recognize foreign tax credits previously generated in 2005 and 2006 thought not to be fully utilizable. We now believe we can utilize these credits currently, because we have generated additional taxable income and expect to continue to generate a higher level of taxable income largely from the growth of our international operations.

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 the American Institute of Certified Public Accountants Statement of Position 81-1, “Accounting for Performance of Construction-Type and Certain Production-Type Contracts.” 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.

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.

Legal and investigation matters

As discussed in Note 10 of our consolidated financial statements, as of December 31, 2008, 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 10 to the consolidated financial statements for further information. FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others – An Interpretation of FASB Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34,” requires recognition of third-party indemnities at their inception. Therefore, in accordance with FIN 45, 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. FSP FIN 45-2, “Whether FASB Interpretation No. 45, ‘Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others’, Provides Support for Subsequently Accounting for a Guarantor’s Liability at Fair Value,” states that the subsequent measurement of FIN 45 liabilities should not necessarily be based on fair value. The FSP references SFAS No. 5, “Accounting for Contingencies” for subsequent adjustments related to 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 under SFAS No. 5.

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, intangible assets, and goodwill. 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 in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Impairment is the condition that exists when the carrying amount of a long-lived asset exceeds its fair value, and any impairment charge that we record reduces our earnings. We review the carrying value of these assets based upon estimated future cash flows while taking into consideration assumptions and estimates including the future use of the asset, remaining useful life of the asset, and service potential of the asset.

Goodwill is the excess of the cost of an acquired entity over the net of the amounts assigned to assets acquired and liabilities assumed. We test goodwill for impairment annually, during the third quarter, or if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” 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 2008, 2007, and 2006. 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. See Note 3 to the consolidated financial statements for further information regarding acquisitions.

Pensions

Our pension benefit obligations and expenses are calculated using actuarial models and methods, in accordance with SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R).” 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 rate of return on plan assets. 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. Considering the recent financial markets downturn, we elected to modify our methodology for selecting discount rates at December 31, 2008 for our United States pension and postretirement plans. This resulted in a lower discount rate and yielded a higher projected benefit obligation than if we had used our previous methodology. Expected long-term rates of return on plan assets are determined annually and are based on an evaluation of our plan assets and historical trends and experience, taking into account current and expected market conditions. Plan assets are comprised primarily of equity and debt securities. As we have both domestic and international plans, these assumptions differ based on varying factors specific to each particular country or economic environment.

The discount rates utilized in 2008 to determine the projected benefit obligation at the measurement date for our qualified United States non-terminating pension plans ranged from 5.72% to 5.77%, a decrease from the range of 6.03% to 6.19% that was utilized in 2007. The discount rate utilized in 2008 to determine the projected benefit obligation at the measurement date for our United Kingdom pension plan, which constitutes 73% of our international plans and 63% of all plans, was 5.75% compared to a discount rate of 5.70% utilized in 2007. The following table illustrates the sensitivity to changes in certain assumptions, holding all other assumptions constant, for the United Kingdom pension plan.

	Effect on
	Pension Expense			Pension Benefit Obligation
Millions of dollars	in 2008			at December 31, 2008
25-basis-point decrease in discount rate	$	4		$	30
25-basis-point increase in discount rate	$	(4	)	$	(28	)

Our defined benefit plans reduced pretax earnings by $48 million in 2008, $48 million in 2007, and $45 million in 2006. Included in the amounts were earnings from our expected pension returns of $51 million in 2008, $47 million in 2007, and $37 million in 2006. Unrecognized actuarial gains and losses are being recognized over a period of five to 24 years, which represents the expected remaining service life of the employee group. Our unrecognized actuarial gains and losses arose from several factors, including experience and assumptions changes in the obligations and the difference between expected returns and actual returns on plan assets. Actual losses on plan assets were $144 million in 2008, compared to actual returns on plan assets of $68 million in 2007 and $65 million in 2006. 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 is deferred and recorded net of tax in other comprehensive income as actuarial gain or loss and is recognized as future pension expense. Our net actuarial loss, net of tax, at December 31, 2008 was $198 million. An estimated $4 million, net of tax, of our net actuarial loss at December 31, 2008 will be recognized as a component of our expected 2009 pension expense. During 2008, we made contributions to fund our defined benefit plans of $52 million, which included $18 million contributed to our United Kingdom plan. We expect to make additional contributions in 2009 of approximately $48 million.

The actuarial assumptions used in determining our pension benefit obligations may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, and longer or shorter life spans of participants. While we believe that the assumptions used are appropriate, differences in actual experience or changes in assumptions may materially affect our financial position or results of operations. See Note 15 to the consolidated financial statements for further information related to defined benefit and other postretirement benefit plans.

Allowance for bad debts

We evaluate our accounts receivable through a continuous process of assessing our portfolio on an individual customer and overall basis. This process consists of a thorough review of historical collection experience, current aging status of the customer accounts, financial condition of our customers, and whether the receivables involve retentions. 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 5.0%. At December 31, 2008, allowance for bad debts totaled $60 million or 1.6% of notes and accounts receivable before the allowance, and at December 31, 2007, allowance for bad debts totaled $49 million or 1.6% of notes and accounts receivable before the allowance. A 1% change in our estimate of the collectibility of our notes and accounts receivable balance as of December 31, 2008 would have resulted in a $37 million adjustment to 2008 total operating costs and expenses.

OFF BALANCE SHEET ARRANGEMENTS

At December 31, 2008, 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 financial instrument market risk from changes in foreign currency exchange rates, interest rates, and, to a limited extent, commodity prices. From time to time, we may selectively manage these exposures through the use of derivative instruments to mitigate our market risk from these exposures. The objective of our risk management program is to protect our cash flows related to sales or purchases of goods or services from market fluctuations in currency rates. We do not use derivative instruments for trading purposes. Our use of derivative instruments includes the following types of market risk:

volatility of the currency rates;

time horizon of the derivative instruments;

market cycles; and

the type of derivative instruments used.

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 14 to the consolidated financial statements for additional disclosures related to financial instruments.

Interest rate risk

We currently have no 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, 2008 and related weighted average interest rates on the repayment amounts by year of maturity for our long-term debt.

Millions of dollars	2009			2010			2011		2012		2013		Thereafter			Total
Repayment amount ($US)	$	26		$	750		$	-	$	-	$	-	$	1,839		$	2,615
Weighted average
interest rate on
repayment amount		5.5	%		5.5	%		-		-		-		6.9	%		6.5	%

The fair market value of long-term debt was $2.8 billion as of December 31, 2008.

ENVIRONMENTAL MATTERS

We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide. In the United States, these laws and regulations include, among others:

the Comprehensive Environmental Response, Compensation, and Liability Act;

the Resource Conservation and Recovery Act;

the Clean Air Act;

the Federal Water Pollution Control Act; and

the Toxic Substances Control Act.

We do not expect costs related to these remediation requirements to have a material adverse effect on our consolidated financial position or our results of operations. Our accrued liabilities for environmental matters were $64 million as of December 31, 2008 and $72 million as of December 31, 2007. Our total liability related to environmental matters covers numerous properties.

We have subsidiaries that have been named as potentially responsible parties along with other third parties for 8 federal and state superfund sites for which we have established a liability. As of December 31, 2008, those 8 sites accounted for approximately $10 million of our total $64 million liability. 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. Despite attempts to resolve these superfund matters, the relevant regulatory agency may at any time bring suit against us for amounts in excess of the amount accrued. With respect to some superfund sites, we have been named a potentially responsible party by a regulatory agency; however, in each of those cases, we do not believe we have any material liability. We also could be subject to third-party claims with respect to environmental matters for which we have been named as a potentially responsible party.

NEW ACCOUNTING PRONOUNCEMENTS

In December 2008, the FASB issued FSP SFAS 132(R)-1 “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This FSP amends the disclosure requirements for employer’s disclosure of plan assets for defined benefit pensions and other postretirement plans. The objective of this FSP is to provide users of financial statements with an understanding of how investment allocation decisions are made, the major categories of plan assets held by the plans, the inputs and valuation techniques used to measure the fair value of plan assets, significant concentration of risk within the company’s plan assets, and for fair value measurements determined using significant unobservable inputs a reconciliation of changes between the beginning and ending balances. FSP SFAS 132(R)-1 is effective for fiscal years ending after December 15, 2009. We will adopt the new disclosure requirements in the 2009 annual reporting period.

In June 2008, the FASB issued FSP Emerging Issues Task Force (EITF) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This FSP provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and shall be included in the computation of both basic and diluted earnings per share. This EITF is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. We will adopt the provisions of FSP EITF 03-6-1 on January 1, 2009, which will require us to recast prior periods’ basic and diluted earnings per share to include outstanding unvested restricted common shares in the weighted average shares outstanding calculation. We estimate that, had we calculated earnings per share under these new provisions during 2008, basic income per share would have decreased by approximately $0.02 for continuing operations and approximately $0.01 for net income and diluted income per share would have decreased by approximately $0.01 for both continuing operations and net income per share.

In May 2008, the FASB issued FSP Accounting Principles Board (APB) 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement).” This FSP clarifies that convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. We will adopt the provisions of FSP APB 14-1 on January 1, 2009 and will be required to retroactively apply its provisions, which means we will restate our consolidated financial statements for prior periods.

In applying this FSP, we estimate approximately $60 million of the carrying value of the convertible notes to be reclassified to equity as of the July 2003 issuance date. This amount represents the equity component of the proceeds from the notes, calculated assuming a 4.3% non-convertible borrowing rate. The discount will be accreted to interest expense over the five-year term of the notes. Accordingly, approximately $13 million of additional non-cash interest expense, or $0.01 per diluted share, will be recorded in 2006 and 2007 and approximately $7 million of additional non-cash interest expense will be recorded in 2008. Furthermore, under this FSP, the $693 million loss to settle our convertible debt in the third quarter of 2008 will be reversed and recorded to additional paid-in capital. We estimate that diluted income per share for 2008 will increase by approximately $0.76.

In December 2007, the FASB issued SFAS No. 141(Revised 2007), “Business Combinations” (SFAS No. 141(R)). SFAS No. 141(R) retains the underlying concepts of SFAS No. 141 in that all business combinations are still required to be accounted for at fair value under the acquisition method of accounting, but SFAS No. 141(R) changes the method of applying the acquisition method in a number of ways. Acquisition costs will generally be expensed as incurred, noncontrolling interests (minority interests) will be valued at fair value at the acquisition date, in-process research and development will be recorded at fair value as an indefinite-lived intangible asset at the acquisition date, restructuring costs associated with a business combination will generally be expensed subsequent to the acquisition date, and changes in deferred tax asset valuation allowances and income tax uncertainties after the acquisition date generally will affect income tax expense. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after December 15, 2008. We will adopt the provisions of SFAS No. 141(R) for business combinations on or after January 1, 2009.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – An Amendment of ARB No. 51.” SFAS No. 160 establishes new accounting, reporting, and disclosure standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement requires the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements and separate from the parent’s equity. SFAS No. 160 is effective for fiscal years and interim periods within those fiscal years beginning on or after December 15, 2008. We will adopt the provisions of SFAS No. 160 on January 1, 2009 and, beginning with our 2009 interim reporting periods and for prior comparative periods, we will present noncontrolling interest (minority interest) as a separate component of shareholders’ equity.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115.” SFAS No. 159 permits entities to measure eligible assets and liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We adopted SFAS No. 159 on January 1, 2008 and did not elect to apply the fair value method to any eligible assets or liabilities at that time.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which is intended to increase consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value, and expanding disclosures about fair value measurements. SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements and is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. In February 2008, the FASB issued FSP SFAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP SFAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In October 2008, the FASB also issued FSP SFAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS No. 157 in an inactive market and illustrates how an entity would determine fair value when the market for a financial asset is not active. On January 1, 2008, we adopted without material impact on our consolidated financial statements the provisions of SFAS No. 157 related to financial assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a recurring basis. Beginning January 1, 2009, we will adopt the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include those measured at fair value in goodwill impairment testing, indefinite-lived intangible assets measured at fair value for impairment assessment, nonfinancial long-lived assets measured at fair value for impairment assessment, asset retirement obligations initially measured at fair value, and those initially measured at fair value in a business combination. We do not expect the provisions of SFAS No. 157 related to these items to 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.

While it is not possible to identify all factors, we continue to face many risks and uncertainties that could cause actual results to differ from our forward-looking statements and potentially materially and adversely affect our financial condition and results of operations.

RISK FACTORS

Foreign Corrupt Practices Act Investigations

In February 2009, the FCPA investigations by the DOJ and the SEC were resolved. 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 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% interest in the venture. 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).

In addition to the DOJ and the SEC investigations, we are aware of other investigations in France, Nigeria, Great Britain, and Switzerland regarding the Bonny Island project.

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 the Bonny Island project.

With respect to the DOJ, in February 2009, a subsidiary of KBR, Inc. pleaded guilty to conspiring to violate the FCPA and to substantive violations of the anti-bribery provisions of the FCPA in connection with 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 does not provide for a monitor for us.

As a result of our indemnity in favor of KBR under the master separation agreement with KBR and the KBR subsidiary’s criminal plea, we have paid $49 million and will pay an additional $333 million in seven installments over the next seven quarters of the $402 million criminal fine payable by KBR as part of the resolution of the DOJ investigation, with KBR consenting to pay the remaining $20 million.

With respect to the SEC, without admitting or denying the allegations in an SEC complaint, we consented to the entry of a final judgment that permanently enjoins us from violating the record-keeping and internal control provisions of the FCPA. KBR also entered into a related settlement with the SEC. As part of our settlement with the SEC, we agreed to be jointly and severally liable with KBR for, and will pay the SEC, $177 million in disgorgement in the first quarter of 2009.

In addition, as part of the resolution of the SEC investigation, we will retain 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 will adopt any necessary anti-bribery and foreign agent internal controls and record-keeping procedures recommended by or agreed upon with the independent consultant. 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.

The 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.

KBR has agreed that Halliburton’s indemnification obligations with respect to the DOJ and SEC FCPA investigations have been fully satisfied. Our indemnity of KBR 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.

To reflect the resolution of the DOJ and SEC FCPA investigations and to reflect other adjustments to the indemnities and guarantees provided to KBR upon separation, we recorded $420 million, net of tax, in 2008 as a loss from discontinued operations. We did not record a tax benefit related to the resolution of the DOJ and SEC FCPA investigations. As of December 31, 2008 and December 31, 2007, $559 million and $142 million are recorded related to our obligations regarding DOJ and SEC FCPA matters in our consolidated balance sheets in “Department of Justice and Securities and Exchange Commission settlement and indemnity, current” and “Other liabilities.” See Note 2 to the consolidated financial statements for additional information.

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. 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, 2008 and December 31, 2007. See Note 2 to our consolidated financial statements for additional information regarding the KBR indemnification.

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. A key issue in the arbitration is which party is responsible for the designation of the material to be used for the bolts. We understand that KBR believes that an instruction to use the particular bolts was issued by Petrobras, and as such, KBR believes the cost resulting from any replacement is not KBR’s responsibility. We understand Petrobras disagrees. We understand KBR believes several possible solutions may exist, including replacement of the bolts. Estimates indicate that costs of these various solutions range 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 and pursuing recovery of the costs incurred to date through the arbitration process and to that end has submitted a counterclaim in the arbitration seeking the recovery of $22 million. The arbitration panel held an evidentiary hearing during the week of March 31, 2008 and took evidence and arguments under advisement.

Impairment of Oil and Gas Properties

At December 31, 2008, we had interests in oil and gas properties totaling $105 million, net of accumulated depletion, which we account for under the successful efforts method. The majority of this amount is related to one property in Bangladesh in which we have a 25% non-operating interest. These oil and 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 result in an impairment of our oil and gas properties, which in turn could have an adverse effect on our results of operations.

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.

Our operations in countries other than the United States accounted for approximately 57% of our consolidated revenue during 2008 and 56% and 55% of our consolidated revenue during 2007 and 2006. 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;

governmental activities that limit or disrupt markets, restrict payments, or limit the movement of funds;

governmental activities that may result in the deprivation of contract rights; and

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, Nigeria, Russia, Venezuela, and Yemen. In addition, military action or continued unrest in the Middle East could impact the supply and pricing for oil and 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 you 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.

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 war and ongoing military action in Iraq, 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:

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

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

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:

adverse movements in foreign exchange rates;

interest rates;

commodity prices; or

the value and time period of the derivative being different than the exposures or cash flows being hedged.

Customers and Business

Worldwide recession and effect on exploration and production activity

The recent worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets have led to a worldwide economic recession that could continue for an extended period of time. The slowdown in economic activity caused by the recession has reduced worldwide demand for energy and resulted in lower oil and natural gas prices. This reduction in demand could continue through 2009 and beyond. Crude oil prices declined from record levels in July 2008 of approximately $145 per barrel to levels as low as $30 per barrel toward the end of 2008. As of February 10, 2009, crude oil prices were $37.54 per barrel. Natural gas spot prices peaked at approximately $13.00 per mmBtu in 2008 and then fell to an average of $5.83 per mmBtu toward the end of 2008. As of February 11, 2009, natural gas spot prices had fallen even further to $4.68 per mmBtu. Demand for our services and products depends on oil and natural gas industry activity and expenditure levels that are directly affected by trends in oil and natural gas prices. 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. 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 gas companies can similarly reduce or defer major expenditures given the long-term nature of many large-scale development projects. Lower levels of activity result in a corresponding decline in the demand for our oil and natural gas well services and products, which could have a material adverse effect on our revenue and profitability.

Exploration and production activity

Demand for our services and products depends on oil and natural gas industry activity and expenditure levels that are directly affected by trends in oil and natural gas prices.

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. 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 factors that are beyond our control. The current low prices for oil and natural gas have depressed the current levels of exploration, development, and production activity, resulting in a corresponding decline in the demand for our oil and natural gas well services and products. Factors affecting the prices of oil and natural gas include:

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

global weather conditions and natural disasters;

worldwide political, military, and economic conditions;

the level of oil production by non-OPEC countries and the available excess production capacity within OPEC;

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

the cost of producing and delivering oil and gas;

potential acceleration of development of alternative fuels; and

the level of supply and demand for oil and natural gas, especially demand for natural gas in the United States.

Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile. Spending on exploration and production activities by large oil and gas companies has a significant impact on the activity levels of our businesses.

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:

the consolidation of our customers, which could:

cause customers to reduce their capital spending, which would in turn reduce the demand for our services and products; and

result in customer personnel changes, which in turn affect the timing of contract negotiations;

adverse developments in the business and operations of our customers in the oil and gas industry, including write-downs of reserves and reductions in capital spending for exploration, development, and production; and

ability of our customers to timely pay the amounts due us.

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, such as Venezuela.

Business with national oil companies

Much of the world’s oil and 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.

Long-term, fixed-price contracts

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, 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:

any acquisitions would result in an increase in income;

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

the due diligence prior to an acquisition would uncover situations that could result in legal exposure or that we will appropriately quantify the exposure from known risks;

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

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

any dispositions, investments, acquisitions, or integrations would not divert management resources; or

any dispositions, investments, acquisitions, or integrations would not have a material adverse effect on our 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.

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:

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

the importation and use of radioactive materials;

the use of underground storage tanks; and

the use of underground injection wells.

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:

administrative, civil, and criminal penalties;

revocation of permits to conduct business; and

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

Failure on our part to comply with applicable environmental requirements could have a material adverse effect on our 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.

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). A decline in exploration and production, in turn, could materially and adversely affect us.

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.

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 gas producers.

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, 2008 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, 2008, our internal control over financial reporting is effective.

The effectiveness of Halliburton’s internal control over financial reporting as of December 31, 2008 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report that is included herein.

HALLIBURTON COMPANY

/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

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, 2008 and 2007, 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, 2008. 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, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in Notes 11 and 15, respectively, to the consolidated financial statements, the Company changed its methods of accounting for uncertainty in income taxes as of January 1, 2007 and its method of accounting for defined benefit and other postretirement plans as of December 31, 2006, respectively.

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, 2008, 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 16, 2009 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 16, 2009

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, 2008, 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, 2008, 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, 2008 and 2007, 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, 2008, and our report dated February 16, 2009 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

February 16, 2009

HALLIBURTON COMPANY

Consolidated Statements of Operations

		Year Ended December 31
Millions of dollars and shares except per share data		2008			2007			2006
Revenue:
Services		$	13,391		$	11,256		$	9,643
Product sales			4,888			4,008			3,312
Total revenue			18,279			15,264			12,955
Operating costs and expenses:
Cost of services			10,079			8,167			6,751
Cost of sales			3,970			3,358			2,675
General and administrative			282			293			342
Gain on sale of business assets, net			(62	)		(52	)		(58	)
Total operating costs and expenses			14,269			11,766			9,710
Operating income			4,010			3,498			3,245
Interest expense			(160	)		(154	)		(165	)
Interest income			39			124			129
Other, net			(726	)		(8	)		(10	)
Income from continuing operations before income
taxes and minority interest			3,163			3,460			3,199
Provision for income taxes			(1,211	)		(907	)		(1,003	)
Minority interest in net income of subsidiaries			9			(29	)		(19	)
Income from continuing operations			1,961			2,524			2,177
Income (loss) from discontinued operations, net of
income tax (provision) benefit of $3, $(15), and
	$(183)		(423	)		975			171
Net income		$	1,538		$	3,499		$	2,348

Basic income (loss) per share:
Income from continuing operations		$	2.24		$	2.76		$	2.15
Income (loss) from discontinued operations, net			(0.49	)		1.07			0.16
Net income per share		$	1.75		$	3.83		$	2.31

Diluted income (loss) per share:
Income from continuing operations		$	2.17		$	2.66		$	2.07
Income (loss) from discontinued operations, net			(0.47	)		1.02			0.16
Net income per share		$	1.70		$	3.68		$	2.23

Basic weighted average common shares outstanding			877			913			1,014
Diluted weighted average common shares outstanding			904			950			1,054

See notes to consolidated financial statements.

HALLIBURTON COMPANY

Consolidated Balance Sheets

	December 31
Millions of dollars and shares except per share data	2008			2007
Assets
Current assets:
Cash and equivalents	$	1,124		$	1,847
Receivables (less allowance for bad debts of $60 and $49)		3,795			3,093
Inventories		1,828			1,459
Current deferred income taxes		246			376
Investments in marketable securities		-			388
Other current assets		418			410
Total current assets		7,411			7,573
Property, plant, and equipment, net of accumulated depreciation of $4,566 and $4,126		4,782			3,630
Goodwill		1,072			790
Noncurrent deferred income taxes		157			348
Other assets		963			794
Total assets	$	14,385		$	13,135
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	898		$	768
Accrued employee compensation and benefits		643			575
Department of Justice and Securities and Exchange Commission settlement
and indemnity, current		373			–
Deferred revenue		231			209
Income tax payable		67			209
Current maturities of long-term debt		26			159
Other current liabilities		543			491
Total current liabilities		2,781			2,411
Long-term debt		2,586			2,627
Employee compensation and benefits		539			403
Other liabilities		735			734
Total liabilities		6,641			6,175
Minority interest in consolidated subsidiaries		19			94
Shareholders’ equity:
Common shares, par value $2.50 per share – authorized 2,000 shares, issued 1,067
and 1,063 shares		2,666			2,657
Paid-in capital in excess of par value		1,114			1,741
Accumulated other comprehensive loss		(215	)		(104	)
Retained earnings		9,411			8,202
Treasury stock, at cost – 172 and 183 shares		(5,251	)		(5,630	)
Total shareholders’ equity		7,725			6,866
Total liabilities and shareholders’ equity	$	14,385		$	13,135

See notes to consolidated financial statements.

HALLIBURTON COMPANY

Consolidated Statements of Shareholders’ Equity

Millions of dollars	2008			2007			2006
Balance at January 1	$	6,866		$	7,376		$	6,372
Dividends and other transactions with shareholders		(558	)		(1,499	)		(1,324	)
Sale of stock by a subsidiary		–			–			117
Adoption of Financial Accounting Standards Board
Interpretation No. 48 and Statement of Financial
Accounting Standard No. 158		(10	)		(30	)		(218	)
Shares exchanged in KBR, Inc. exchange offer		–			(2,809	)		–
Other		–			(4	)		34

Comprehensive income:
Net income		1,538			3,499			2,348
Net cumulative translation adjustments		1			(23	)		34
Defined benefit and other postretirement plans adjustments		(106	)		355			2
Net unrealized gains (losses) on investments
and derivatives		(6	)		1			11
Total comprehensive income		1,427			3,832			2,395

Balance at December 31	$	7,725		$	6,866		$	7,376

See notes to consolidated financial statements.

HALLIBURTON COMPANY

Consolidated Statements of Cash Flows

	Year Ended December 31
Millions of dollars	2008			2007			2006
Cash flows from operating activities:
Net income	$	1,538		$	3,499		$	2,348
Adjustments to reconcile net income to net cash from operations:
Depreciation, depletion, and amortization		738			583			480
Loss on extinguishment of debt		693			–			–
(Income) loss from discontinued operations		423			(975	)		(171	)
Provision (benefit) for deferred income taxes, continuing operations		254			(140	)		714
Gain on sale of business assets, net		(62	)		(52	)		(66	)
Other changes:
Accounts payable		161			77			96
Contributions to pension plans		(52	)		(41	)		(75	)
Inventories		(368	)		(218	)		(309	)
Receivables		(670	)		(326	)		(327	)
Other		19			288			656
Cash flows from discontinued operations		–			31			311
Total cash flows from operating activities		2,674			2,726			3,657
Cash flows from investing activities:
Sales (purchases) of short-term investments in marketable securities, net		388			(332	)		(20	)
Sales of property, plant, and equipment		191			203			152
Dispositions of business assets, net of cash disposed		81			70			98
Disposal of KBR, Inc. cash upon separation		–			(1,461	)		–
Acquisitions of business assets, net of cash acquired		(652	)		(563	)		(27	)
Capital expenditures		(1,824	)		(1,583	)		(834	)
Other investing activities		(40	)		18			(20	)
Cash flows from discontinued operations		–			(13	)		225
Total cash flows from investing activities		(1,856	)		(3,661	)		(426	)
Cash flows from financing activities:
Proceeds from long-term debt, net of offering costs		1,187			–			–
Proceeds from exercises of stock options		120			110			159
Tax benefit from exercise of options and restricted stock		44			29			53
Payments of dividends to shareholders		(319	)		(314	)		(306	)
Payments to reacquire common stock		(507	)		(1,374	)		(1,339	)
Payments on long-term debt		(2,048	)		(7	)		(324	)
Other financing activities		–			4			(8	)
Cash flows from discontinued operations		–			(18	)		485
Total cash flows from financing activities		(1,523	)		(1,570	)		(1,280	)
Effect of exchange rate changes on cash, including $0, $0, and $50 related to
discontinued operations		(18	)		(27	)		37
Increase (decrease) in cash and equivalents		(723	)		(2,532	)		1,988
Cash and equivalents at beginning of year, including $0, $1,461, and $390
related to discontinued operations		1,847			4,379			2,391
Cash and equivalents at end of year, including $0, $0, and $1,461 related
to discontinued operations	$	1,124		$	1,847		$	4,379
Supplemental disclosure of cash flow information for continuing operations:
Cash payments during the year for:
Interest	$	143		$	144		$	164
Income taxes	$	1,057		$	941		$	289

See notes to consolidated financial statements.

HALLIBURTON COMPANY

Notes to Consolidated Financial Statements

Note 1. Description of Company and Significant Accounting Policies

Description of Company

Halliburton Company’s predecessor was established in 1919 and incorporated under the laws of the State of Delaware in 1924. We are one of the world’s largest oilfield services companies. Our two business segments are the Completion and Production segment and the Drilling and Evaluation segment. We provide a comprehensive range of services and products for the exploration, development, and production of oil and gas around the world.

Use of estimates

Our financial statements are prepared in conformity with accounting principles generally accepted in the United States, requiring us to make estimates and assumptions that affect:

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

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

We believe the most significant estimates and assumptions are associated with the valuation of income taxes, percentage-of-completion accounting for long-term contracts, legal and environmental reserves, indemnity valuations, purchase price allocations, pensions, goodwill, other intangible assets, and allowance for bad debts. Ultimate results could differ from those estimates.

Basis of presentation

The consolidated financial statements include the accounts of our company and all of our subsidiaries that we control or variable interest entities for which we have determined that we are the primary beneficiary. All material intercompany accounts and transactions are eliminated. Investments in companies in which we have significant influence are accounted for using the equity method. If we do not have significant influence, we use the cost method.

As the result of realigning our products and services during the third quarter of 2007, we are now reporting two business segments. See Note 4 for further information. Additionally, KBR, Inc. (KBR), formerly a wholly owned subsidiary, is presented as discontinued operations in the consolidated financial statements. See Note 2 for additional information. All periods presented reflect these changes.

Certain other prior year amounts have been reclassified to conform to the current year presentation.

Revenue recognition

Overall. Our services and products are generally sold based upon purchase orders or contracts with our customers that include fixed or determinable prices but do not include right of return provisions or other significant post-delivery obligations. Our products are produced in a standard manufacturing operation, even if produced to our customer’s specifications. We recognize revenue from product sales when title passes to the customer, the customer assumes risks and rewards of ownership, collectibility is reasonably assured, and delivery occurs as directed by our customer. Service revenue, including training and consulting services, is recognized when the services are rendered and collectibility is reasonably assured. Rates for services are typically priced on a per day, per meter, per man-hour, or similar basis.

Software sales. Sales of perpetual software licenses, net of any deferred maintenance and support fees, are recognized as revenue upon shipment. Sales of time-based licenses are recognized as revenue over the license period. Maintenance and support fees are recognized as revenue ratably over the contract period, usually a one-year duration.

Percentage of completion. Revenue from certain long-term, integrated project management contracts to provide well construction and completion services is reported on the percentage-of-completion method of accounting. Progress is generally based upon physical progress related to contractually defined units of work. Physical percent complete is determined as a combination of input and output measures as deemed appropriate by the circumstances. All known or anticipated losses on contracts are provided for when they become evident. Cost adjustments that are in the process of being negotiated with customers for extra work or changes in the scope of work are included in revenue when collection is deemed probable.

Sale of stock by a subsidiary

When, as part of a broader corporate reorganization, a subsidiary or affiliate sells unissued shares in a public offering, we treat the transaction as a capital transaction. Therefore, the increase or decrease in the carrying amount of our subsidiary’s stock is not reflected as a gain or loss on our consolidated statements of operations, but as an increase or decrease to “Paid-in capital in excess of par value.”

Research and development

Research and development costs are expensed as incurred. Research and development costs were $326 million in 2008, $301 million in 2007, and $254 million in 2006, of which over 96% was company sponsored in each year.

Cash equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Inventories

Inventories are stated at the lower of cost or market. Cost represents invoice or production cost for new items and original cost less allowance for condition for used material returned to stock. Production cost includes material, labor, and manufacturing overhead. Some domestic manufacturing and field service finished products and parts inventories for drill bits, completion products, and bulk materials are recorded using the last-in, first-out method. The remaining inventory is recorded on the average cost method. We regularly review inventory quantities on hand and record provisions for excess or obsolete inventory based primarily on historical usage, estimated product demand, and technological developments.

Allowance for bad debts

We establish an allowance for bad debts through a review of several factors, including historical collection experience, current aging status of the customer accounts, and financial condition of our customers.

Property, plant, and equipment

Other than those assets that have been written down to their fair values due to impairment, property, plant, and equipment are reported at cost less accumulated depreciation, which is generally provided on the straight-line method over the estimated useful lives of the assets. Accelerated depreciation methods are also used for tax purposes, wherever permitted. Upon sale or retirement of an asset, the related costs and accumulated depreciation are removed from the accounts and any gain or loss is recognized. Planned major maintenance costs are generally expensed as incurred. Expenditures for additions, modifications, and conversions are capitalized when they increase the value or extend the useful life of the asset.

Goodwill and other intangible assets

We record as goodwill the excess purchase price over the fair value of the tangible and identifiable intangible assets acquired. During the year, we recorded an additional $274 million in goodwill arising from 2008 acquisitions, of which $159 million related to the Completion and Production segment and $115 million related to the Drilling and Evaluation segment. The reported amounts of goodwill for each reporting unit are reviewed for impairment on an annual basis, during the third quarter, and more frequently when negative conditions such as significant current or projected operating losses exist. The annual impairment test for goodwill is a two-step process and involves comparing the estimated fair value of each reporting unit to the reporting unit’s carrying value, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered impaired, and the second step of the impairment test is unnecessary. If the carrying amount of a reporting unit exceeds its fair value, the second step of the goodwill impairment test would be performed to measure the amount of impairment loss to be recorded, if any. 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. Our annual impairment tests resulted in no goodwill impairment in 2008, 2007, or 2006. In addition, there were no negative conditions, or triggering events, that occurred in 2008, 2007, or 2006 requiring us to perform additional impairment reviews.

We amortize other identifiable intangible assets with a finite life on a straight-line basis over the period which the asset is expected to contribute to our future cash flows, ranging from three years to 20 years. The components of these other intangible assets generally consist of patents, license agreements, non-compete agreements, trademarks, and customer lists and contracts.

Evaluating impairment of long-lived assets

When events or changes in circumstances indicate that long-lived assets other than goodwill may be impaired, an evaluation is performed. For an asset classified as held for use, the estimated future undiscounted cash flows associated with the asset are compared to the asset’s carrying amount to determine if a write-down to fair value is required. When an asset is classified as held for sale, the asset’s book value is evaluated and adjusted to the lower of its carrying amount or fair value less cost to sell. In addition, depreciation and amortization is ceased while it is classified as held for sale.

Insurance

The company is self-insured up to certain retention limits for general liability, vehicle liability, group medical, and for workers’ compensation claims for certain of its employees. The amounts in excess of the self-insured levels are fully insured, up to a limit. Self-insurance accruals are based on claims filed and an estimate for significant claims incurred but not reported.

Income taxes

We recognize the amount of taxes payable or refundable for the year. In addition, deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the financial statements or tax returns. A valuation allowance is provided for deferred tax assets if it is more likely than not that these items will not be realized.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that we will realize the benefits of these deductible differences, net of the existing valuation allowances.

We recognize interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing operations in our consolidated statements of operations.

We generally do not provide income taxes on the undistributed earnings of non-United States subsidiaries because such earnings are intended to be reinvested indefinitely to finance foreign activities. These additional foreign earnings could be subject to additional tax if remitted, or deemed remitted, as a dividend; however, it is not practicable to estimate the additional amount, if any, of taxes payable. Taxes are provided as necessary with respect to earnings that are not permanently reinvested.

Derivative instruments

At times, we enter into derivative financial transactions to hedge existing or projected exposures to changing foreign currency exchange rates and commodity prices. We do not enter into derivative transactions for speculative or trading purposes. We recognize all derivatives on the balance sheet at fair value. Derivatives are adjusted to fair value and reflected through the results of operations. Gains or losses on foreign currency derivatives are included in “Other, net” and gains or losses on commodity derivatives are included in operating income. Our derivatives are not designated as hedges for accounting purposes.

Foreign currency translation

Foreign entities whose functional currency is the United States dollar translate monetary assets and liabilities at year-end exchange rates, and nonmonetary items are translated at historical rates. Income and expense accounts are translated at the average rates in effect during the year, except for depreciation, cost of product sales and revenue, and expenses associated with nonmonetary balance sheet accounts, which are translated at historical rates. Gains or losses from changes in exchange rates are recognized in consolidated income in “Other, net” in the year of occurrence. Foreign entities whose functional currency is not the United States dollar translate net assets at year-end rates and income and expense accounts at average exchange rates. Adjustments resulting from these translations are reflected in the consolidated statements of shareholders’ equity as “Net cumulative translation adjustments.”

Stock-based compensation

Effective January 1, 2006, we adopted the fair value recognition provisions of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), “Share-Based Payment”, using the modified prospective application. Accordingly, we are recognizing compensation expense for all newly granted awards and awards modified, repurchased, or cancelled after January 1, 2006. Compensation cost for the unvested portion of awards that were outstanding as of January 1, 2006 is being recognized ratably over the remaining vesting period based on the fair value at date of grant. Also, beginning with the January 1, 2006 purchase period, compensation expense for our 2002 Employee Stock Purchase Plan (ESPP) is being recognized. The cumulative effect of this change in accounting principle related to stock-based awards was immaterial.

Total stock-based compensation expense for continuing operations, net of related tax effects, was $67 million in 2008, $62 million in 2007, and $49 million in 2006. Total income tax benefit recognized in continuing operations for stock-based compensation arrangements was $36 million in 2008, $35 million in 2007, and $27 million in 2006.

The majority of our options are generally issued during the second quarter of the year. The fair value of options at the date of grant was estimated using the Black-Scholes option pricing model. The expected volatility of options granted was a blended rate based upon implied volatility calculated on actively traded options on our common stock and upon the historical volatility of our common stock. The expected term of options granted was based upon historical observation of actual time elapsed between date of grant and exercise of options for all employees. The assumptions and resulting fair values of options granted were as follows:

	Year Ended December 31
	2008			2007			2006
Expected term (in years)		5.20			5.14			5.24
Expected volatility		32.30	%		35.70	%		42.20	%
Expected dividend yield		0.71 – 2.38	%		0.89 – 1.14	%		0.76 – 1.06	%
Risk-free interest rate		1.57 – 3.32	%		3.37 – 5.00	%		4.30 – 5.03	%
Weighted average grant-date fair value per share	$	12.28		$	11.35		$	14.20

The fair value of ESPP shares was estimated using the Black-Scholes option pricing model. The expected volatility was a one-year historical volatility of our common stock. The assumptions and resulting fair values were as follows:

	Offering period July 1 through December 31
	2008			2007			2006
Expected term (in years)		0.5			0.5			0.5
Expected volatility		28.88	%		29.49	%		37.77	%
Expected dividend yield		0.67	%		1.03	%		0.80	%
Risk-free interest rate		2.17	%		4.98	%		5.29	%
Weighted average grant-date fair value per share	$	12.58		$	7.97		$	9.32

	Offering period January 1 through June 30
	2008			2007			2006
Expected term (in years)		0.5			0.5			0.5
Expected volatility		24.69	%		34.91	%		35.65	%
Expected dividend yield		0.93	%		1.00	%		0.75	%
Risk-free interest rate		3.40	%		5.09	%		4.38	%
Weighted average grant-date fair value per share	$	8.64		$	7.20		$	7.91

See Note 12 for further detail on stock incentive plans.

Note 2. KBR Separation

In November 2006, KBR completed an initial public offering (IPO), in which it sold approximately 32 million shares of KBR common stock at $17.00 per share. Proceeds from the IPO were approximately $508 million, net of underwriting discounts and commissions and offering expenses. The increase in the carrying amount of our investment in KBR, resulting from the IPO, was recorded in “Paid-in capital in excess of par value” on our consolidated balance sheet at December 31, 2006. On April 5, 2007, we completed the separation of KBR from us by exchanging the 135.6 million shares of KBR common stock owned by us on that date for 85.3 million shares of our common stock. In the second quarter of 2007, we recorded a gain on the disposition of KBR of approximately $933 million, net of tax and the estimated fair value of the indemnities and guarantees provided to KBR as described below, which is included in income from discontinued operations on the consolidated statement of operations. During 2008, adjustments of $420 million, net of tax, to our liability for indemnities and guarantees were reflected as a loss in “Income (loss) from discontinued operations, net of income tax.”

The following table presents the financial results of KBR, which are reflected as discontinued operations in our consolidated statements of operations. For accounting purposes, we ceased including KBR’s operations in our results effective March 31, 2007.

	Year Ended December 31
Millions of dollars	2007			2006
Revenue	$	2,250		$	9,621
Operating income	$	62		$	239
Net income	$	23	(a)	$	180

(a)	Net income for 2007 represents our 81% share of KBR’s results from

January 1, 2007 through March 31, 2007.

We entered into various agreements relating to the separation of KBR, including, among others, a master separation agreement, a registration rights agreement, a tax sharing agreement, transition services agreements, and an employee matters agreement. The master separation agreement provides for, among other things, KBR’s responsibility for liabilities related to its business and our responsibility for liabilities unrelated to KBR’s business. We provide 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 United States Foreign Corrupt Practices Act (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 a consortium of engineering firms comprised of Technip SA of France, Snamprogetti Netherlands B.V., JGC Corporation of Japan, and Kellogg Brown & Root LLC (TSKJ) of a natural gas liquefaction complex and related facilities at Bonny Island in Rivers State, Nigeria; and

all out-of-pocket cash costs and expenses, or cash settlements or cash arbitration awards in lieu thereof, KBR may incur after the effective date of the master separation agreement as a result of the replacement of the subsea flowline bolts installed in connection with the Barracuda-Caratinga project.

Additionally, we provide indemnities, performance guarantees, surety bond guarantees, and letter of credit guarantees that are currently in place in favor of KBR’s customers or lenders under project contract, credit agreements, letters of credit, and other KBR credit instruments. These indemnities and guarantees will continue until they expire at the earlier of: (1) the termination of the underlying project contract or KBR obligations there under; (2) the expiration of the relevant credit support instrument in accordance with its terms or release of such instrument by the customer; or (3) the expiration of the credit agreements. Further, KBR and we have agreed that, until December 31, 2009, we will issue additional guarantees, indemnification, and reimbursement commitments for KBR’s benefit in connection with: (a) letters of credit necessary to comply with KBR’s Egypt Basic Industries Corporation ammonia plant contract, KBR’s Allenby & Connaught project, and all other KBR project contracts that were in place as of December 15, 2005; (b) surety bonds issued to support new task orders pursuant to the Allenby & Connaught project, two job order contracts for KBR’s Government and Infrastructure segment, and all other KBR project contracts that were in place as of December 15, 2005; and (c) performance guarantees in support of these contracts. KBR is compensating us for these guarantees. We have also provided a limited indemnity, with respect to FCPA and anti-trust governmental and third-party claims, to the lender parties under KBR’s revolving credit agreement expiring in December 2010. KBR has agreed to indemnify us, other than for the FCPA and Barracuda-Caratinga bolts matter, if we are required to perform under any of the indemnities or guarantees related to KBR’s revolving credit agreement, letters of credit, surety bonds, or performance guarantees described above.

During the second quarter of 2007, we recorded $190 million, as a reduction of the gain on the disposition of KBR, to reflect the estimated fair value of the above indemnities and guarantees, net of the associated estimated future tax benefit. During 2008, we recorded $420 million, net of tax, as a loss to discontinued operations to reflect the resolution of the Department of Justice (DOJ) and Securities and Exchange Commission (SEC) FCPA investigations and the impact of our most recent assumptions regarding the resolution of the Barracuda-Caratinga bolt arbitration matter under the indemnities and guarantees provided to KBR upon separation. We did not record a tax benefit related to the resolution of the DOJ and SEC investigations. These indemnities and guarantees are primarily included in “Department of Justice and Securities and Exchange Commission settlement and indemnity, current” and “Other liabilities” on the consolidated balance sheets and totaled $631 million at December 31, 2008. Excluding the DOJ and SEC matters noted above, our estimation of the remaining obligation for other indemnities and guarantees provided to KBR upon separation was $72 million at December 31, 2008. See Note 10 for further discussion of the FCPA and Barracuda-Caratinga matters.

The tax sharing agreement provides for allocations of United States and certain other jurisdiction tax liabilities between us and KBR.

Note 3. Acquisitions and Dispositions

We have completed various acquisitions for cash payments in the aggregate of approximately $652 million during 2008, $563 million during 2007, and $27 million during 2006. None of these acquisitions were significant on an individual basis.

WellDynamics B.V.

In July 2008, we acquired the remaining 49% equity interest in WellDynamics B.V. (WellDynamics) from Shell Technology Ventures Fund 1 B.V. (STV Fund), resulting in our 100% ownership of WellDynamics. WellDynamics is a provider of intelligent well completion technology and its results of operations are included in our Completion and Production segment.

PSL Energy Services Limited

Dresser, Ltd. interest

Ultraline Services Corporation

Note 4. Business Segment Information

Subsequent to the KBR separation, in the third quarter of 2007, we realigned our products and services to improve operational and cost management efficiencies, better serve our customers, and become better aligned with the process of exploring for and producing from oil and natural gas wells. We now 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. All periods presented reflect reclassifications related to the change in operating segments and the reclassification of certain amounts between the operating segments and “Corporate and other.” KBR results are presented as discontinued operations as a result of the separation of KBR from us.

Following is a discussion of our operating segments.

Completion and Production delivers cementing, stimulation, intervention, and completion services. This segment consists of production enhancement services, completion tools and services, and cementing services.

Cementing services involve bonding the well and well casing while isolating fluid zones and maximizing wellbore stability. Our cementing service line also provides casing equipment.

Drilling and Evaluation provides field and reservoir modeling, drilling, evaluation, and well construction solutions that enable customers to model, measure, and optimize their well placement, stability, and reservoir evaluation activities. This segment consists of fluid services, drilling services, drill bits, wireline and perforating services, software and asset solutions, and project management services.

Corporate and other includes expenses related to support functions and corporate executives. Also included are certain gains and losses that are not attributable to a particular business segment. “Corporate and other” represents assets not included in a business segment and is primarily composed of cash and equivalents, deferred tax assets, and marketable securities.

Intersegment revenue and revenue between geographic areas are immaterial. Our equity in earnings and losses of unconsolidated affiliates that are accounted for under the equity method is included in revenue and operating income of the applicable segment.

The following tables present information on our business segments.

Operations by business segment
	Year Ended December 31
Millions of dollars	2008			2007			2006
Revenue:
Completion and Production	$	9,935		$	8,386		$	7,221
Drilling and Evaluation		8,344			6,878			5,734
Total	$	18,279		$	15,264		$	12,955
Operating income:
Completion and Production	$	2,409		$	2,199		$	2,140
Drilling and Evaluation		1,865			1,485			1,328
Corporate and other		(264	)		(186	)		(223	)
Total	$	4,010		$	3,498		$	3,245
Capital expenditures:
Completion and Production	$	797		$	791		$	441
Drilling and Evaluation		1,021			759			390
Corporate and other		6			33			3
Total	$	1,824		$	1,583		$	834
Depreciation, depletion, and amortization:
Completion and Production	$	366		$	288		$	239
Drilling and Evaluation		372			295			241
Total	$	738		$	583		$	480

	December 31
Millions of dollars	2008		2007		2006
Total assets:
Completion and Production	$	6,045	$	4,842	$	3,636
Drilling and Evaluation		6,096		4,606		3,566
Shared assets		648		672		1,216
Corporate and other		1,596		3,015		3,047
Discontinued operations		–		–		5,395
Total	$	14,385	$	13,135	$	16,860

Not all assets are associated with specific segments. Those assets specific to segments include receivables, inventories, certain identified property, plant, and equipment (including field service equipment), equity in and advances to related companies, and goodwill. The remaining assets, such as cash, are considered to be shared among the segments.

Revenue by country is determined based on the location of services provided and products sold.

Operations by geographic area
	Year Ended December 31
Millions of dollars	2008		2007		2006
Revenue:
United States	$	7,775	$	6,673	$	5,869
Other countries		10,504		8,591		7,086
Total	$	18,279	$	15,264	$	12,955

	December 31
Millions of dollars	2008		2007		2006
Long-lived assets:
United States	$	3,571	$	2,733	$	2,045
Other countries		3,027		2,263		1,413
Total	$	6,598	$	4,996	$	3,458

Note 5. Receivables

Our trade receivables are generally not collateralized. At December 31, 2008, 34% of our gross trade receivables were from customers in the United States. At December 31, 2007, 35% of our gross trade receivables were from customers in the United States. No other country accounted for more than 10% of our gross trade receivables at these dates.

Note 6. Inventories

Inventories are stated at the lower of cost or market. In the United States we manufacture certain finished products and parts inventories for drill bits, completion products, bulk materials, and other tools that are recorded using the last-in, first-out method, which totaled $92 million at December 31, 2008 and $71 million at December 31, 2007. If the average cost method had been used, total inventories would have been $31 million higher than reported at December 31, 2008 and $25 million higher than reported at December 31, 2007. The cost of the remaining inventory was recorded on the average cost method. Inventories consisted of the following:

	December 31
Millions of dollars	2008		2007
Finished products and parts	$	1,312	$	1,042
Raw materials and supplies		446		325
Work in process		70		92
Total	$	1,828	$	1,459

Finished products and parts are reported net of obsolescence reserves of $81 million at December 31, 2008 and $65 million at December 31, 2007.

Note 7. Investments in marketable securities

At December 31, 2007, we had $388 million invested in marketable securities, consisting of auction-rate securities and variable-rate demand notes which were classified as available-for-sale and recorded at fair value. In January 2008, we sold the entire balance of marketable securities at face value. At December 31, 2008, we held no investments in marketable securities.

Note 8. Property, Plant, and Equipment

Property, plant, and equipment were composed of the following:

	December 31
Millions of dollars	2008		2007
Land	$	58	$	46
Buildings and property improvements		1,082		869
Machinery, equipment, and other		8,208		6,841
Total		9,348		7,756
Less accumulated depreciation		4,566		4,126
Net property, plant, and equipment	$	4,782	$	3,630

The percentages of total buildings and property improvements and total machinery, equipment, and other, excluding oil and gas investments, are depreciated over the following useful lives:

	Buildings and Property
	Improvements
	2008			2007
1 – 10 years		17	%		17	%
11 – 20 years		46	%		50	%
21 – 30 years		12	%		13	%
31 – 40 years		25	%		20	%

	Machinery, Equipment,
	and Other
	2008			2007
1 – 5 years		19	%		22	%
6 – 10 years		74	%		72	%
11 – 20 years		7	%		6	%

Note 9. Debt

Short-term notes payable consist primarily of overdraft and other facilities with varying rates of interest. Long-term debt consisted of the following:

	December 31
Millions of dollars	2008		2007
6.7% senior notes due September 2038	$	800	$	–
5.5% senior notes due October 2010		749		749
5.9% senior notes due September 2018		400		–
7.6% senior debentures due August 2096		294		294
8.75% senior debentures due February 2021		185		185
3.125% convertible senior notes due July 2023		–		1,200
Other		184		358
Total long-term debt		2,612		2,786
Less current portion		26		159
Noncurrent portion of long-term debt	$	2,586	$	2,627

Convertible notes

Our 3.125% convertible senior notes due July 2023 became redeemable at our option on July 15, 2008. On July 30, 2008, we gave notice of redemption on the convertible notes. In lieu of redemption, the holders of the convertible notes could convert each $1,000 principal amount of convertible notes into 53.4069 shares of our common stock. Substantially all of the holders timely elected to convert during the third quarter of 2008. Upon conversion, we settled the principal amount of our convertible notes in cash and the premium on the notes with a combination of $693 million in cash and approximately $840 million, or 20 million shares, of our treasury stock. The settlement of the principal amount was funded with the proceeds from the issuance of 6.7% and 5.9% senior notes. We recorded a non-tax deductible loss of $693 million in the third quarter of 2008, in “Other, net” on our consolidated statement of operations, related to the portion of the premium settled in cash.

Other senior debt

We have issued various senior notes and debentures, all of which rank equally with our existing and future senior unsecured indebtedness, have semiannual interest payments, and no sinking fund requirements. We may redeem some of the 6.7% and 5.9% senior notes from time to time or all of the notes of each series at any time at the redemption prices, plus accrued and unpaid interest. Our 5.5% senior notes are redeemable by us, in whole or in part, at any time, subject to a redemption price equal to the greater of 100% of the principal amount of the notes or the sum of the present values of the remaining scheduled payments of principal and interest due on the notes discounted to the redemption date at the treasury rate plus 25 basis points. Our 7.6% and 8.75% senior debentures may not be redeemed prior to maturity.

Revolving credit facilities

We have an unsecured, $1.2 billion credit facility expiring 2012 whose purpose is to provide commercial paper support, general working capital, and credit for other corporate purposes. On October 10, 2008, we entered into an unsecured, six-month revolving credit facility, with current commitments of $400 million, to give us additional liquidity and for other general corporate purposes. We are able to draw on the facility once we have used all of our existing $1.2 billion, five-year revolving credit facility. There were no cash drawings under the revolving credit facilities as of December 31, 2008.

Maturities

Our debt matures as follows: $26 million in 2009; $749 million in 2010; and $1.8 billion in 2017 and thereafter.

Note 10. Commitments and Contingencies

Foreign Corrupt Practices Act investigations

In addition to the DOJ and the SEC investigations, we are aware of other investigations in France, Nigeria, Great Britain, and Switzerland regarding the Bonny Island project.

Bidding practices investigation

In connection with the investigation into payments relating to the Bonny Island project in Nigeria, information was uncovered suggesting that, possibly beginning as early as the mid-1980s, former Kellogg Brown & Root, Inc. employees may have engaged in coordinated bidding with one or more competitors on certain foreign construction projects. Halliburton’s indemnity to KBR does not extend to liabilities for governmental fines or third-party claims arising out of these activities. The settlement with the DOJ included an agreement by the DOJ not to bring bid coordination-related charges against us.

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. 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, 2008 and December 31, 2007. See Note 2 for additional information regarding the KBR indemnification.

Securities and related litigation

In June 2002, a class action lawsuit was filed against us in federal court alleging violations of the federal securities laws after the SEC initiated an investigation in connection with our change in accounting for revenue on long-term construction projects and related disclosures. In the weeks that followed, approximately twenty similar class actions were filed against us. Several of those lawsuits also named as defendants several of our present or former officers and directors. The class action cases were later consolidated, and the amended consolidated class action complaint, styled Richard Moore, et al. v. Halliburton Company, et al., was filed and served upon us in April 2003. As a result of a substitution of lead plaintiffs, the case is now styled Archdiocese of Milwaukee Supporting Fund (AMSF) v. Halliburton Company, et al. We settled with the SEC in the second quarter of 2004.

In June 2003, the lead plaintiffs filed a motion for leave to file a second amended consolidated complaint, which was granted by the court. In addition to restating the original accounting and disclosure claims, the second amended consolidated complaint included claims arising out of the 1998 acquisition of Dresser Industries, Inc. by Halliburton, including that we failed to timely disclose the resulting asbestos liability exposure.

In April 2005, the court appointed new co-lead counsel and named AMSF the new lead plaintiff, directing that it file a third consolidated amended complaint and that we file our motion to dismiss. The court held oral arguments on that motion in August 2005, at which time the court took the motion under advisement. In March 2006, the court entered an order in which it granted the motion to dismiss with respect to claims arising prior to June 1999 and granted the motion with respect to certain other claims while permitting AMSF to re-plead some of those claims to correct deficiencies in its earlier complaint. In April 2006, AMSF filed its fourth amended consolidated complaint. We filed a motion to dismiss those portions of the complaint that had been re-pled. A hearing was held on that motion in July 2006, and in March 2007 the court ordered dismissal of the claims against all individual defendants other than our Chief Executive Officer (CEO). The court ordered that the case proceed against our CEO and Halliburton.

In September 2007, AMSF filed a motion for class certification, and our response was filed in November 2007. The court held a hearing in March 2008, and issued an order November 3, 2008 denying AMSF’s motion for class certification. AMSF then filed a motion with the Fifth Circuit Court of Appeals requesting permission to appeal the district court’s order denying class certification. The Fifth Circuit granted AMSF’s motion and the order denying class certification is currently on appeal. The case will remain stayed in the district court pending the outcome of the appeal. As of December 31, 2008, we had not accrued any amounts related to this matter because we do not believe that a loss is probable. Further, an estimate of possible loss or range of loss related to this matter cannot be made.

Asbestos insurance settlements

At December 31, 2004, we resolved all open and future asbestos- and silica-related claims in the prepackaged Chapter 11 proceedings of DII Industries LLC, Kellogg Brown & Root LLC, and our other affected subsidiaries that had previously been named as defendants in a large number of asbestos- and silica-related lawsuits. During 2004, we settled insurance disputes with substantially all the insurance companies for asbestos- and silica-related claims and all other claims under the applicable insurance policies and terminated all the applicable insurance policies.

Under the insurance settlements entered into as part of the resolution of our Chapter 11 proceedings, we have agreed to indemnify our insurers under certain historic general liability insurance policies in certain situations. We have concluded that the likelihood of any claims triggering the indemnity obligations is remote, and we believe any potential liability for these indemnifications will be immaterial. Further, an estimate of possible loss or range of loss related to this matter cannot be made. At December 31, 2008, we had not recorded any liability associated with these indemnifications.

Environmental

We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide. In the United States, these laws and regulations include, among others:

the Comprehensive Environmental Response, Compensation, and Liability Act;

the Resource Conservation and Recovery Act;

the Clean Air Act;

the Federal Water Pollution Control Act; and

the Toxic Substances Control Act.

Letters of credit

In the normal course of business, we have agreements with banks under which approximately $2.2 billion of letters of credit, surety bonds, or bank guarantees were outstanding as of December 31, 2008, including approximately $828 million that relate to KBR. These KBR letters of credit, surety bonds, or bank guarantees 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.

Leases

We are obligated under operating leases, principally for the use of land, offices, equipment, manufacturing and field facilities, and warehouses. Total rentals, net of sublease rentals, were $561 million in 2008, $487 million in 2007, and $402 million in 2006.

Future total rentals on noncancellable operating leases are as follows: $183 million in 2009; $161 million in 2010; $130 million in 2011; $84 million in 2012; $66 million in 2013; and $175 million thereafter.

Note 11. Income Taxes

The components of the provision for income taxes on continuing operations were:

	Year Ended December 31
Millions of dollars	2008			2007			2006
Current income taxes:
Federal	$	(561	)	$	(560	)	$	(156	)
Foreign		(346	)		(449	)		(122	)
State		(50	)		(38	)		(11	)
Total current		(957	)		(1,047	)		(289	)
Deferred income taxes:
Federal		(303	)		129			(600	)
Foreign		64			7			(95	)
State		(15	)		4			(19	)
Total deferred		(254	)		140			(714	)
Provision for income taxes	$	(1,211	)	$	(907	)	$	(1,003	)

The United States and foreign components of income from continuing operations before income taxes and minority interest were as follows:

	Year Ended December 31
Millions of dollars	2008		2007		2006
United States	$	1,988	$	2,219	$	2,280
Foreign		1,175		1,241		919
Total	$	3,163	$	3,460	$	3,199

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

	Year Ended December 31
	2008			2007			2006
United States statutory rate		35.0	%		35.0	%		35.0	%
Repurchase premium paid in cash to retire debt		8.0			-			-
Adjustments of prior year taxes		(2.3	)		(0.3	)		(2.1	)
Impact of foreign income taxed at different rates		(1.4	)		(2.3	)		(1.3	)
Other impact of foreign operations		(1.3	)		(3.9	)		3.1
Valuation allowance		0.1			(2.0	)		(3.3	)
Other items, net		0.2			(0.3	)		-
Total effective tax rate on continuing operations		38.3	%		26.2	%		31.4	%

The major component of the difference between the 2008 statutory rate compared to the effective rate was related to our inability to recognize a benefit for the $693 million loss on the settlement of our convertible debt, as United States tax law generally prohibits a company from recognizing a tax deduction for a repurchase premium paid to retire debt that is convertible into the stock of the issuing company. The major component of the difference between the 2007 statutory rate compared to the effective rate was the favorable impact of the ability to recognize United States foreign tax credits of approximately $205 million. This amount consisted of approximately $68 million of a change in valuation allowance for credits previously recognized and approximately $137 million reflected in other impact of foreign operations for changes to United States tax filings to claim foreign tax credits rather than deducting foreign taxes. The major component of the difference between the 2006 statutory tax rate compared to the effective tax rate was the release of the remaining valuation allowance for future tax attributes related to United States net operating losses established in prior years, the majority of which was released in 2005.

The primary components of our deferred tax assets and liabilities and the related valuation allowances were as follows:

	December 31
Millions of dollars	2008		2007
Gross deferred tax assets:
Employee compensation and benefits	$	324	$	262
Accrued liabilities		81		80
Foreign tax credit carryforward		79		61
Capitalized research and experimentation		74		94
Net operating loss carryforwards		50		24
Insurance accruals		47		46
Software revenue recognition		31		37
Inventory		26		63
Alternative minimum tax credit carryforward		–		19
Other		49		176
Total gross deferred tax assets		761		862
Gross deferred tax liabilities:
Depreciation and amortization		303		164
Joint ventures, partnerships, and unconsolidated affiliates		25		34
Other		38		55
Total gross deferred tax liabilities		366		253
Valuation allowances:
Net operating loss carryforwards		14		22
Other		–		7
Total valuation allowances		14		29
Net deferred income tax asset	$	381	$	580

At December 31, 2008, we had a total of $137 million of foreign net operating loss carryforwards, of which $66 million will expire from 2009 through 2021 and $71 million will not expire due to indefinite expiration dates. At December 31, 2008, we had $40 million of domestic net operating loss carryforwards that will expire from 2021 through 2028. At December 31, 2008, we had United States foreign tax credit carryforwards of $79 million that are expected to expire beginning in 2018.

We established a valuation allowance on certain foreign operating loss carryforwards on the basis that we believe these assets will not be utilized in the statutory carryover period. The majority of the 2008 valuation allowance change was recorded as an adjustment to goodwill.

Effective January 1, 2007, we adopted FASB Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” FIN 48, as amended May 2007 by FASB Staff Position (FSP) FIN 48-1, “Definition of ‘Settlement’ in FASB Interpretation No. 48,” prescribes 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. It also provides guidance for derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The cumulative effect of this change in accounting principle related to FIN 48 was immaterial.

The following presents a rollforward of our unrecognized tax benefits and associated interest and penalties.

	Unrecognized			Interest
Millions of dollars	Tax Benefits			and Penalties
Balance at January 1, 2007	$	242		$	34
Change in prior year tax positions		145			–
Change in current year tax positions		34			4
Cash settlements with taxing authorities		(30	)		(1	)
Lapse of statute of limitations		(3	)		–
Balance at December 31, 2007	$	388		$	37
Change in prior year tax positions		(98	)		5
Change in current year tax positions		25			2
Cash settlements with taxing authorities		(5	)		–
Lapse of statute of limitations		(10	)		(1	)
Balance at December 31, 2008	$	300		$	43

Tax benefits associated with United States foreign tax credits of $19 million and $99 million as of December 31, 2008 and December 31, 2007 were included in the balance of unrecognized tax benefits that could be resolved within the next 12 months. Tax benefits associated with United States research and development tax credits of $30 million were included in the balance of unrecognized tax benefits that could be resolved within the next 12 months as of December 31, 2008. Also, as of December 31, 2008 and December 31, 2007, a significant portion of our non-United States unrecognized tax benefits, while not individually significant, could be settled within the next 12 months. As of December 31, 2008 and December 31, 2007, we estimated that $163 million and $289 million of the balance of unrecognized tax benefits, if resolved in our favor, would positively impact the effective tax rate and, therefore, be recognized as additional tax benefits in our statement of operations. We file income tax returns in the United States federal jurisdiction and in various states and foreign jurisdictions. In most cases, we are no longer subject to United States federal, state, and local, or non-United States income tax examination by tax authorities for years before 1998. Tax filings of our subsidiaries, unconsolidated affiliates, and related entities are routinely examined in the normal course of business by tax authorities. Currently, our United States federal tax filings are under review for tax years 2000 through 2007.

Note 12. Shareholders’ Equity and Stock Incentive Plans

The following tables summarize our common stock and other shareholders’ equity activity:

			Paid-in
			Capital in												Accumulated
			Excess												Other
	Common		of Par			Treasury			Deferred			Retained			Comprehensive
Millions of dollars	Shares		Value			Stock			Compensation			Earnings			Income			Total
Balance at December 31, 2005	$	2,634	$	1,501		$	(374	)	$	(98	)	$	2,975		$	(266	)	$	6,372
Cash dividends paid		–		–			–			–			(306	)		–			(306	)
Stock plans		16		116			136			–			–			–			268
Common shares purchased		–		–			(1,339	)		–			–			–			(1,339	)
Tax benefit from exercise of options
and restricted stock		–		53			–			–			–			–			53
Total dividends and other transactions
with shareholders		16		169			(1,203	)		–			(306	)		–			(1,324	)
Sale of stock by a subsidiary		–		117			–			–			–			–			117
Reclassification of deferred compensation		–		(98	)		–			98			–			–			–
Adoption of SFAS No. 158, net of tax
benefit of $146		–		–			–			–			–			(218	)		(218	)
Other		–		–			–			–			34			–			34
Comprehensive income (loss):
Net income		–		–			–			–			2,348			–			2,348
Other comprehensive income:
Cumulative translation adjustment		–		–			–			–			–			48			48
Realization of translation gains
included in net income		–		–			–			–			–			(14	)		(14	)
Defined benefit and other
postretirement plans adjustments,
net of tax benefit of $16		–		–			–			–			–			2			2
Net unrealized gains on investments and
derivatives, net of tax provision of $7		–		–			–			–			–			12			12
Realization of gains on investments and
derivatives, net of tax provision of $0		–		–			–			–			–			(1	)		(1	)
Total comprehensive income		–		–			–			–			2,348			47			2,395
Balance at December 31, 2006	$	2,650	$	1,689		$	(1,577	)	$	–		$	5,051		$	(437	)	$	7,376

			Paid-in
			Capital in									Accumulated
			Excess									Other
	Common		of Par			Treasury			Retained			Comprehensive
Millions of dollars	Shares		Value			Stock			Earnings			Income			Total
Balance at December 31, 2006	$	2,650	$	1,689		$	(1,577	)	$	5,051		$	(437	)	$	7,376
Cash dividends paid		–		–			–			(314	)		–			(314	)
Stock plans		7		23			130			–			–			160
Common shares purchased		–		–			(1,374	)		–			–			(1,374	)
Tax benefit from exercise of options
and restricted stock		–		29			–			–			–			29
Total dividends and other transactions
with shareholders		7		52			(1,244	)		(314	)		–			(1,499	)
Shares exchanged in KBR, Inc. exchange offer		–		–			(2,809	)		–			–			(2,809	)
Adoption of FIN 48		–		–			–			(30	)		–			(30	)
Other		–		–			–			(4	)		–			(4	)
Comprehensive income (loss):
Net income		–		–			–			3,499			–			3,499
Other comprehensive income:
Cumulative translation adjustment		–		–			–			–			1			1
Realization of translation gains
included in net income		–		–			–			–			(24	)		(24	)
Defined benefit and other postretirement
plans adjustments:
Prior service cost:
Plan amendment		–		–			–			–			(2	)		(2	)
Settlements/curtailments		–		–			–			–			5			5
Actuarial gain (loss):
Net gain		–		–			–			–			105			105
Amortization of net loss		–		–			–			–			14			14
Settlements/curtailments		–		–			–			–			7			7
Tax effect on defined benefit
and postretirement plans		–		–			–			–			(45	)		(45	)
KBR, Inc. separation		–		–			–			–			271			271
Defined benefit and other
postretirement plans, net		–		–			–			–			355			355
Net unrealized gains on investments, net
of tax provision of $0		–		–			–			–			1			1
Total comprehensive income		–		–			–			3,499			333			3,832
Balance at December 31, 2007	$	2,657	$	1,741		$	(5,630	)	$	8,202		$	(104	)	$	6,866
Cash dividends paid		–		–			–			(319	)		–			(319	)
Stock plans		9		41			173			–			–			223
Common shares purchased		–		–			(507	)		–			–			(507	)
Tax benefit from exercise of options and restricted stock		–		45			–			–			–			45
Total dividends and other transactions with shareholders		9		86			(334	)		(319	)		–			(558	)
Adoption of SFAS No. 158, net of tax benefit of $2		–		–			–			(10	)		–			(10	)
Portion of the convertible debt premium settled in stock, at cost		–		(713	)		713			–			–			–
Comprehensive income (loss):
Net income		–		–			–			1,538			–			1,538
Other comprehensive income:
Cumulative translation adjustment		–		–			–			–			1			1
Defined benefit and other postretirement plans adjustments:
Actuarial net loss		–		–			–			–			(170	)		(170	)
Other		–		–			–			–			18			18
Tax effect on defined benefit and postretirement plans		–		–			–			–			46			46
Defined benefit and other postretirement plans, net		–		–			–			–			(106	)		(106	)
Net unrealized losses on investments, net of tax
benefit of $4		–		–			–			–			(6	)		(6	)
Total comprehensive income		–		–			–			1,538			(111	)		1,427
Balance at December 31, 2008	$	2,666	$	1,114		$	(5,251	)	$	9,411		$	(215	)	$	7,725

Accumulated other comprehensive loss	December 31
Millions of dollars	2008			2007			2006
Cumulative translation adjustment	$	(60	)	$	(61	)	$	(38	)
Defined benefit and other postretirement liability adjustments		(151	)		(45	)		(400	)
Unrealized gains (losses) on investments and derivatives		(4	)		2			1
Total accumulated other comprehensive loss	$	(215	)	$	(104	)	$	(437	)

Shares of common stock	December 31
Millions of shares	2008			2007			2006
Issued		1,067			1,063			1,060
In treasury		(172	)		(183	)		(62	)
Total shares of common stock outstanding		895			880			998

Our stock repurchase program has an authorization of $5.0 billion, of which $1.8 billion remained available at December 31, 2008. The program does not require a specific number of shares to be purchased and the program may be effected through solicited or unsolicited transactions in the market or in privately negotiated transactions. The program may be terminated or suspended at any time. From the inception of this program in February 2006 through December 31, 2008, we have repurchased approximately 92 million shares of our common stock for approximately $3.2 billion at an average price per share of $34.30. These numbers include the repurchases of approximately 13 million shares of our common stock for approximately $481 million at an average price per share of $36.61 during 2008.

Preferred Stock

Our preferred stock consists of five million total authorized shares at December 31, 2008, of which none are issued.

Stock Incentive Plans

Our 1993 Stock and Incentive Plan, as amended (1993 Plan), provides for the grant of any or all of the following types of stock-based awards:

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

restricted stock awards;

restricted stock unit awards;

stock appreciation rights; and

stock value equivalent awards.

There are currently no stock appreciation rights or stock value equivalent awards outstanding.

Under the terms of the 1993 Plan, 98 million shares of common stock have been reserved for issuance to employees and non-employee directors. The plan specifies that no more than 32 million shares can be awarded as restricted stock. At December 31, 2008, approximately 12 million shares were available for future grants under the 1993 Plan, of which approximately 6 million shares remained available for restricted stock awards. The stock to be offered pursuant to the grant of an award under the 1993 Plan may be authorized but unissued common shares or treasury shares.

In addition to the provisions of the 1993 Plan, we also have stock-based compensation provisions under our Restricted Stock Plan for Non-Employee Directors and our ESPP.

Each of the active stock-based compensation arrangements is discussed below.

Stock options

All stock options under the 1993 Plan are granted at the fair market value of our common stock at the grant date. Employee stock options vest ratably over a three- or four-year period and generally expire 10 years from the grant date. Stock options granted to non-employee directors vest after six months. Compensation expense for stock options is generally recognized on a straight line basis over the entire vesting period. No further stock option grants are being made under the stock plans of acquired companies.

The following table represents our stock options activity during 2008.

				Weighted		Weighted
				Average		Average		Aggregate
	Number			Exercise		Remaining		Intrinsic
	of Shares			Price		Contractual		Value
Stock Options	(in millions)			per Share		Term (years)		(in millions)
Outstanding at January 1, 2008		14.3		$	20.81
Granted		2.7			39.43
Exercised		(3.9	)		17.34
Forfeited/expired		(0.3	)		29.61
Outstanding at December 31, 2008		12.8		$	25.65		6.17	$	22

Exercisable at December 31, 2008		8.4		$	19.80		4.72	$	21

The total intrinsic value of options exercised was $106 million in 2008, $68 million in 2007, and $123 million in 2006. As of December 31, 2008, there was $37 million of unrecognized compensation cost, net of estimated forfeitures, related to nonvested stock options, which is expected to be recognized over a weighted average period of approximately 1.8 years.

Cash received from option exercises was $120 million during 2008, $110 million during 2007, and $159 million during 2006. The tax benefit realized from the exercise of stock options was $33 million in 2008, $22 million in 2007, and $42 million in 2006.

Restricted stock

Restricted shares issued under the 1993 Plan are restricted as to sale or disposition. These restrictions lapse periodically over an extended period of time not exceeding 10 years. Restrictions may also lapse for early retirement and other conditions in accordance with our established policies. Upon termination of employment, shares on which restrictions have not lapsed must be returned to us, resulting in restricted stock forfeitures. The fair market value of the stock on the date of grant is amortized and charged to income on a straight-line basis over the requisite service period for the entire award.

Our Restricted Stock Plan for Non-Employee Directors (Directors Plan) allows for each non-employee director to receive an annual award of 800 restricted shares of common stock as a part of their compensation. These awards have a minimum restriction period of six months, and the restrictions lapse upon the earlier of mandatory director retirement at age 72 or early retirement from the Board after four years of service. The fair market value of the stock on the date of grant is amortized over the lesser of the time from the grant date to age 72 or the time from the grant date to completion of four years of service on the Board. We reserved 200,000 shares of common stock for issuance to non-employee directors, which may be authorized but unissued common shares or treasury shares. At December 31, 2008, 122,400 shares had been issued to non-employee directors under this plan. There were 7,200 shares, 8,800 shares, and 8,000 shares of restricted stock awarded under the Directors Plan in 2008, 2007, and 2006. In addition, during 2008, our non-employee directors were awarded 18,416 shares of restricted stock under the 1993 Plan, which are included in the table below.

The following table represents our 1993 Plan and Directors Plan restricted stock awards and restricted stock units granted, vested, and forfeited during 2008.

				Weighted Average
	Number of Shares			Grant-Date Fair
Restricted Stock	(in millions)			Value per Share
Nonvested shares at January 1, 2008		7.3		$	27.16
Granted		4.2			36.78
Vested		(2.1	)		25.02
Forfeited		(0.4	)		33.57
Nonvested shares at December 31, 2008		9.0		$	31.64

The weighted average grant-date fair value of shares granted during 2007 was $32.24 and during 2006 was $34.39. The total fair value of shares vested during 2008 was $81 million, during 2007 was $79 million, and during 2006 was $64 million. As of December 31, 2008, there was $224 million of unrecognized compensation cost, net of estimated forfeitures, related to nonvested restricted stock, which is expected to be recognized over a weighted average period of 4 years.

2002 Employee Stock Purchase Plan

Under the ESPP, eligible employees may have up to 10% of their earnings withheld, subject to some limitations, to be used to purchase shares of our common stock. Unless the Board of Directors shall determine otherwise, each six-month offering period commences on January 1 and July 1 of each year. The price at which common stock may be purchased under the ESPP is equal to 85% of the lower of the fair market value of the common stock on the commencement date or last trading day of each offering period. Under this plan, 24 million shares of common stock have been reserved for issuance. They may be authorized but unissued shares or treasury shares. As of December 31, 2008, 15.9 million shares have been sold through the ESPP.

Note 13. Income (Loss) per Share

Basic income (loss) per share is based on the weighted average number of common shares outstanding during the period. Effective April 5, 2007, common shares outstanding were reduced by the 85.3 million shares of our common stock that we accepted in exchange for the shares of KBR common stock we owned. Diluted income (loss) per share includes additional common shares that would have been outstanding if potential common shares with a dilutive effect had been issued. A reconciliation of the number of shares used for the basic and diluted income (loss) per share calculation is as follows:

Millions of shares	2008		2007		2006
Basic weighted average common shares outstanding		877		913		1,014
Dilutive effect of:
Convertible senior notes premium		22		29		29
Stock options		4		6		9
Restricted stock		1		2		2
Diluted weighted average common shares outstanding		904		950		1,054

In 2004, we entered into a supplemental indenture that required us to satisfy our conversion obligation for our convertible senior notes in cash, rather than in common stock, for at least the aggregate principal amount of the notes. This reduced the resulting potential earnings dilution to only include the conversion premium, which is the difference between the conversion price per share of common stock and the average share price. See the table above for the dilutive effect for 2008, 2007, and 2006. In 2008, we redeemed our 3.125% convertible senior notes. See Note 9 for additional information regarding the redemption of our convertible senior notes.

Excluded from the computation of diluted income per share were options to purchase four million shares of common stock that were outstanding in 2008, three million shares of common stock that were outstanding in 2007, and two million shares of common stock that were outstanding in 2006. These options were outstanding during these years but were excluded because the option exercise price was greater than the average market price of the common shares.

Note 14. Financial Instruments and Risk Management

Foreign exchange risk

Techniques in managing foreign exchange risk include, but are not limited to, foreign currency borrowing and investing and the use of currency derivative instruments. We selectively manage significant exposures to potential foreign exchange losses considering current market conditions, future operating activities, and the associated cost in relation to the perceived risk of loss. The purpose of our foreign currency risk management activities is to protect us from the risk that the eventual dollar cash flows resulting from the sale and purchase of services and products in foreign currencies will be adversely affected by changes in exchange rates.

We manage our currency exposure through the use of currency derivative instruments as it relates to the major currencies, which are generally the currencies of the countries in which we do the majority of our international business. These instruments are not treated as hedges for accounting purposes and generally have an expiration date of two years or less. Forward exchange contracts, which are commitments to buy or sell a specified amount of a foreign currency at a specified price and time, are generally used to manage identifiable foreign currency commitments. Forward exchange contracts and foreign exchange option contracts, which convey the right, but not the obligation, to sell or buy a specified amount of foreign currency at a specified price, are generally used to manage exposures related to assets and liabilities denominated in a foreign currency. None of the forward or option contracts are exchange traded. While derivative instruments are subject to fluctuations in value, the fluctuations are generally offset by the value of the underlying exposures being managed. The use of some contracts may limit our ability to benefit from favorable fluctuations in foreign exchange rates.

Foreign currency contracts are not utilized to manage exposures in some currencies due primarily to the lack of available markets or cost considerations (non-traded currencies). We attempt to manage our working capital position to minimize foreign currency commitments in non-traded currencies and recognize that pricing for the services and products offered in these countries should cover the cost of exchange rate devaluations. We have historically incurred transaction losses in non-traded currencies.

Notional amounts and fair market values. The notional amounts of open foreign exchange forward contracts and option contracts were $324 million at December 31, 2008 and $272 million at December 31, 2007. The notional amounts of our foreign exchange contracts do not generally represent amounts exchanged by the parties and, thus, are not a measure of our exposure or of the cash requirements related to these contracts. The amounts exchanged are calculated by reference to the notional amounts and by other terms of the derivatives, such as exchange rates. The estimated fair market value of our foreign exchange contracts was not material at either December 31, 2008 or December 31, 2007.

Credit risk

Financial instruments that potentially subject us to concentrations of credit risk are primarily cash equivalents, investments, and trade receivables. It is our practice to place our cash equivalents and investments in high quality securities with various investment institutions. We derive the majority of our revenue from sales and services to the energy industry. Within the energy industry, trade receivables are generated from a broad and diverse group of customers. There are concentrations of receivables in the United States. We maintain an allowance for losses based upon the expected collectibility of all trade accounts receivable. In addition, see Note 5 for discussion of receivables.

There are no significant concentrations of credit risk with any individual counterparty related to our derivative contracts. We select counterparties based on their profitability, balance sheet, and a capacity for timely payment of financial commitments, which is unlikely to be adversely affected by foreseeable events.

Interest rate risk

Our outstanding debt instruments have fixed interest rates.

Fair market value of financial instruments. The estimated fair market value of long-term debt was $2.8 billion at December 31, 2008 and $4.1 billion at December 31, 2007, as compared to the carrying amount of $2.6 billion at December 31, 2008 and $2.8 billion at December 31, 2007. The fair market value of fixed-rate long-term debt is based on quoted market prices for those or similar instruments. The carrying amount of short-term financial instruments, cash and equivalents, receivables, short-term notes payable, and accounts payable, as reflected in the consolidated balance sheets, approximates fair market value due to the short maturities of these instruments. The foreign currency derivative instruments are carried on the balance sheet at fair value and are based upon third-party quotes.

Note 15. Retirement Plans

Our company and subsidiaries have various plans that cover a significant number of our employees. These plans include defined contribution plans, defined benefit plans, and other postretirement plans:

our defined contribution plans provide retirement benefits in return for services rendered. These plans provide an individual account for each participant and have terms that specify how contributions to the participant’s account are to be determined rather than the amount of pension benefits the participant is to receive. Contributions to these plans are based on pretax income and/or discretionary amounts determined on an annual basis. Our expense for the defined contribution plans for continuing operations totaled $178 million in 2008, $162 million in 2007, and $138 million in 2006;

our defined benefit plans include both funded and unfunded pension plans, which define an amount of pension benefit to be provided, usually as a function of age, years of service, and/or compensation; and

our postretirement medical plans are offered to specific eligible employees. These plans are contributory. For some plans, our liability is limited to a fixed contribution amount for each participant or dependent. Plan participants share the total cost for all benefits provided above our fixed contributions. Participants’ contributions are adjusted as required to cover benefit payments. We have made no commitment to adjust the amount of our contributions; therefore, the computed accumulated postretirement benefit obligation amount for these plans is not affected by the expected future health care cost inflation rate.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).” Effective for our fiscal year ended December 31, 2008, we adopted the requirements to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end. Effective for our fiscal year ended December 31, 2006, we adopted the requirement to recognize the funded status of a benefit plan and the standard’s additional disclosure requirements.

The discontinued operations of KBR have been excluded from all of the following tables and disclosures.

Benefit obligation and plan assets

The following tables present plan assets, expenses, and obligations for retirement plans of our continuing operations.

	Pension Benefits												Other
	United						United						Postretirement
Benefit obligation	States			Int’l			States			Int’l			Benefits
Millions of dollars	2008						2007						2008			2007
Change in benefit obligation
Benefit obligation at beginning of period	$	110		$	874		$	127		$	814		$	104		$	155
Service cost		–			29			–			26			1			1
Interest cost		6			50			7			44			6			8
Plan participants’ contributions		–			5			–			4			5			5
Plan amendments		–			1			–			2			–			(4	)
Settlements/curtailments		–			(42	)		–			(16	)		–			–
Divestitures		–			(1	)		–			–			–			–
Business combinations		–			1			–			–			–			–
Currency fluctuations		–			(201	)		–			38			–			–
Actuarial gain		–			(18	)		(9	)		(22	)		(13	)		(50	)
Transfers		–			–			–			1			–			–
Benefits paid		(9	)		(28	)		(15	)		(17	)		(12	)		(11	)
Retained earnings adjustment – SFAS No. 158
adoption		1			20			–			–			1			–
Projected benefit obligation at end of period	$	108		$	690		$	110		$	874			N/A			N/A
Accumulated benefit obligation at end of period	$	108		$	533		$	110		$	678		$	92		$	104

	Pension Benefits												Other
	United						United						Postretirement
	States			Int’l			States			Int’l			Benefits
Millions of dollars	2008						2007						2008			2007
Change in plan assets
Fair value of plan assets at beginning of period	$	107		$	724		$	105		$	622		$	–		$	–
Actual return on plan assets		(33	)		(111	)		15			53			–			–
Employer contributions		1			51			2			39			7			7
Settlements		–			(42	)		–			(9	)		–			–
Divestitures		–			(1	)		–			–			–			–
Business combinations		–			1			–			–			–			–
Plan participants’ contributions		–			5			–			4			5			4
Currency fluctuations		–			(181	)		–			32			–			–
Benefits paid		(9	)		(28	)		(15	)		(17	)		(12	)		(11	)
Retained earnings adjustment – SFAS No. 158
adoption		–			12			–			–			–			–
Fair value of plan assets at end of period	$	66		$	430		$	107		$	724		$	–		$	–

Funded status	$	(42	)	$	(260	)	$	(3	)	$	(150	)	$	(92	)	$	(104	)
Employer contribution		–			–			–			5			–			1
Net amount recognized	$	(42	)	$	(260	)	$	(3	)	$	(145	)	$	(92	)	$	(103	)

	Pension Benefits												Other
	United						United						Postretirement
	States			Int’l			States			Int’l			Benefits
Millions of dollars	2008						2007						2008			2007
Amounts recognized on the consolidated
balance sheets
Other assets	$	–		$	1		$	2		$	9		$	–		$	–
Accrued employee compensation and benefits		(2	)		(12	)		(1	)		(11	)		(9	)		(10	)
Employee compensation and benefits		(40	)		(249	)		(4	)		(143	)		(83	)		(93	)
Pension plans in which projected benefit
obligation exceeded plan assets at December 31
Projected benefit obligation	$	107		$	675		$	20		$	835			N/A			N/A
Fair value of plan assets		65			414			15			677			N/A			N/A
Pension plans in which accumulated benefit
obligation exceeded plan assets at December 31
Accumulated benefit obligation	$	107		$	477		$	20		$	65			N/A			N/A
Fair value of plan assets		65			360			15			7			N/A			N/A
Weighted-average assumptions used to determine
benefit obligations at measurement date
Discount rate		4.68-5.77	%		2.2-9.0	%		4.61-6.19	%		2.50-8.75	%		5.57-5.61	%		5.77-5.81	%
Rate of compensation increase		N/A			2.0-10.0	%		4.5	%		2.0-10.0	%		N/A			N/A

	Pension Benefits												Other
	United						United						Postretirement
	States			Int’l			States			Int’l			Benefits
	2008						2007						2008		2007
Asset allocation at December 31
Asset category Target Allocation
Equity securities 50%-70%		59	%		49	%		64	%		57	%		N/A		N/A
Debt securities 30%-50%		40	%		35	%		35	%		32	%		N/A		N/A
Other 0%-5%		1	%		16	%		1	%		11	%		N/A		N/A
Total 100%		100	%		100	%		100	%		100	%		N/A		N/A

Assumed health care cost trend rates at December 31	2008			2007			2006
Health care cost trend rate assumed for next year		9.0	%		9.0	%		10.0	%
Rate to which the cost trend rate is assumed to decline
(the ultimate trend rate)		5.0	%		5.0	%		5.0	%
Year that the rate reached the ultimate trend rate	2016			2015			2011

Assumed long-term rates of return on plan assets, discount rates for estimating benefit obligations, and rates of compensation increases vary for the different plans according to the local economic conditions. The weighted average assumptions for certain international plans are not included in the above tables as the plans were immaterial. The discount rates were determined 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. Considering the recent financial markets downturn, we elected to modify our methodology for selecting discount rates at December 31, 2008 for our United States pension and postretirement plans. This resulted in a lower discount rate and yielded a higher projected benefit obligation than if we had used our previous methodology. For our United Kingdom pension plan, which constituted 73% of our international pension plans’ projected benefit obligation at December 31, 2008, the discount rate utilized at the measurement date in 2008 was 5.75%, compared to 5.70% at the measurement date in 2007. The overall expected long-term rate of return on plan assets was determined based upon an evaluation of our plan assets and historical trends and experience, taking into account current and expected market conditions.

Our investment strategy varies by country depending on the circumstances of the underlying plan. Typically, less mature plan benefit obligations are funded by using more equity securities, as they are expected to achieve long-term growth while exceeding inflation. More mature plan benefit obligations are funded using more fixed income securities, as they are expected to produce current income with limited volatility. Risk management practices include the use of multiple asset classes and investment managers within each.

Amounts recognized in accumulated other comprehensive (gain) loss, net of tax, were as follows at December 31:

	Pension Benefits									Other
	United					United				Postretirement
	States		Int’l			States		Int’l		Benefits
Millions of dollars	2008					2007				2008			2007
Net actuarial (gain) loss	$	37	$	161		$	13	$	72	$	(43	)	$	(39	)
Prior service cost (benefit)		–		(2	)		–		2		(2	)		(3	)
Total recognized in accumulated other comprehensive (gain) loss	$	37	$	159		$	13	$	74	$	(45	)	$	(42	)

Expected cash flows

Contributions. Funding requirements for each plan are determined based on the local laws of the country where such plan resides. In certain countries the funding requirements are mandatory, while in other countries they are discretionary. We currently expect to contribute $35 million to our international pension plans in 2009. We do not have a required minimum contribution for our domestic plans; however, we currently expect to contribute $13 million to these plans in 2009 and may make additional discretionary contributions, which will be determined after the actuarial valuations are complete.

Benefit payments. The following table presents the expected benefit payments over the next 10 years.

	Pension Benefits				Other Postretirement Benefits
	United				Gross Benefit		Gross Medicare
Millions of dollars	States		Int’l		Payments		Part D Receipts
2009	$	11	$	21	$	10	$	(1	)
2010		8		17		10		(1	)
2011		8		20		11		(1	)
2012		8		22		11		(1	)
2013		7		26		10		(1	)
Years 2014 – 2018		37		183		45		(5	)

Net periodic cost

	Pension Benefits																		Other
	United						United						United						Postretirement
	States			Int’l			States			Int’l			States			Int’l			Benefits
Millions of dollars	2008						2007						2006						2008			2007			2006
Components of net periodic
benefit cost
Service cost	$	–		$	29		$	–		$	26		$	–		$	23		$	1		$	1		$	1
Interest cost		6			50			7			45			7			37			6			8			9
Expected return on plan assets		(7	)		(44	)		(7	)		(40	)		(7	)		(30	)		–			–			–
Amortization of prior service cost		–			–			–			–			–			–			(1	)		–			–
Settlements/curtailments		–			5			2			–			–			1			–			–			–
Recognized actuarial (gain) loss		3			6			6			9			6			8			(5	)		–			–
Net periodic benefit cost	$	2		$	46		$	8		$	40		$	6		$	39		$	1		$	9		$	10

Weighted-average assumptions used
to determine net periodic benefit
cost for years ended December 31
Discount rate		4.61-6.19	%		2.50-8.75	%		5.75	%		2.25-8.75	%		5.75	%		2.25-8.0	%		5.77-5.81	%		5.5	%		5.75	%
Expected return on plan assets		8.00	%		4.0-9.0	%		8.25	%		4.0-9.0	%		8.25	%		4.0-7.0	%		N/A			N/A			N/A
Rate of compensation increase		4.50	%		2.0-10.0	%		4.5	%		2.0-10.0	%		4.5	%		2.0-5.0	%		N/A			N/A			N/A

Estimated amounts that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2009 are immaterial.

Note 16. New Accounting Standards

HALLIBURTON COMPANY

Selected Financial Data (1)

(Unaudited)

Millions of dollars and shares	Year Ended December 31
except per share and employee data	2008			2007			2006			2005			2004
Total revenue	$	18,279		$	15,264		$	12,955		$	10,100		$	7,998
Total operating income	$	4,010		$	3,498		$	3,245		$	2,164		$	1,179
Nonoperating expense, net		(847	)		(38	)		(46	)		(167	)		(189	)
Income from continuing operations before income
taxes and minority interest		3,163			3,460			3,199			1,997			990
(Provision) benefit for income taxes		(1,211	)		(907	)		(1,003	)		125			(322	)
Minority interest in net (income) loss of
consolidated subsidiaries		9			(29	)		(19	)		(15	)		3
Income from continuing operations	$	1,961		$	2,524		$	2,177		$	2,107		$	671
Income (loss) from discontinued operations	$	(423	)	$	975		$	171		$	251		$	(1,650	)
Net income (loss)	$	1,538		$	3,499		$	2,348		$	2,358		$	(979	)
Basic income (loss) per share:
Continuing operations	$	2.24		$	2.76		$	2.15		$	2.09		$	0.77
Net income (loss)		1.75			3.83			2.31			2.34			(1.12	)
Diluted income (loss) per share:
Continuing operations		2.17			2.66			2.07			2.03			0.76
Net income (loss)		1.70			3.68			2.23			2.27			(1.11	)
Cash dividends per share		0.36			0.35			0.30			0.25			0.25
Return on average shareholders’ equity		21.08	%		49.14	%		34.16	%		45.76	%		(30.22	)%
Financial position:
Net working capital	$	4,630		$	5,162		$	6,456		$	4,959		$	2,898
Total assets		14,385			13,135			16,860			15,073			15,883
Property, plant, and equipment, net		4,782			3,630			2,557			2,203			2,075
Long-term debt (including current maturities)		2,612			2,786			2,809			3,139			3,879
Shareholders’ equity		7,725			6,866			7,376			6,372			3,932
Total capitalization		10,350			9,663			10,187			9,525			7,818
Basic weighted average common shares
outstanding		877			913			1,014			1,010			874
Diluted weighted average common shares
outstanding		904			950			1,054			1,038			882
Other financial data:
Capital expenditures	$	1,824		$	1,583		$	834		$	575		$	498
Long-term borrowings (repayments), net		(861	)		(7	)		(324	)		(779	)		493
Depreciation, depletion, and
amortization expense		738			583			480			448			456
Payroll and employee benefits		5,264			4,585			3,853			3,211			2,823
Number of employees		57,000			51,000			45,000			39,000			36,000

(1)	All periods presented reflect the reclassification of KBR, Inc. to discontinued operations in the first quarter of 2007 and the two-for-one common stock split, effected in the form of a stock dividend, in July 2006.

HALLIBURTON COMPANY

Quarterly Data and Market Price Information (1)

(Unaudited)

	Quarter
Millions of dollars except per share data	First		Second			Third			Fourth			Year
2008
Revenue	$	4,029	$	4,487		$	4,853		$	4,910		$	18,279
Operating income		847		949			1,051			1,163			4,010
Income (loss) from continuing operations		583		623			(21	)		776			1,961
Income (loss) from discontinued operations		1		(116	)		–			(308	)		(423	)
Net income (loss)		584		507			(21	)		468			1,538
Earnings per share:
Basic income (loss) per share:
Income (loss) from continuing operations		0.67		0.72			(0.02	)		0.87			2.24
Loss from discontinued operations		–		(0.14	)		–			(0.34	)		(0.49	)
Net income (loss)		0.67		0.58			(0.02	)		0.53			1.75
Diluted income (loss) per share:
Income (loss) from continuing operations		0.64		0.68			(0.02	)		0.87			2.17
Loss from discontinued operations		–		(0.13	)		–			(0.34	)		(0.47	)
Net income (loss)		0.64		0.55			(0.02	)		0.53			1.70
Cash dividends paid per share		0.09		0.09			0.09			0.09			0.36
Common stock prices (2)
High		39.98		53.97			55.38			32.09			55.38
Low		30.00		38.56			29.00			12.80			12.80
2007
Revenue	$	3,422	$	3,735		$	3,928		$	4,179		$	15,264
Operating income		788		893			910			907			3,498
Income from continuing operations		529		595			726			674			2,524
Income from discontinued operations		23		935			1			16			975
Net income		552		1,530			727			690			3,499
Earnings per share:
Basic income per share:
Income from continuing operations		0.53		0.66			0.83			0.77			2.76
Income from discontinued operations		0.02		1.03			–			0.02			1.07
Net income		0.55		1.69			0.83			0.79			3.83
Diluted income per share:
Income from continuing operations		0.52		0.63			0.79			0.74			2.66
Income from discontinued operations		0.02		0.99			–			0.01			1.02
Net income		0.54		1.62			0.79			0.75			3.68
Cash dividends paid per share		0.075		0.09			0.09			0.09			0.345
Common stock prices (2)
High		32.72		37.20			39.17			41.95			41.95
Low		27.65		30.99			30.81			34.42			27.65

(1)	All periods presented reflect the reclassification of KBR, Inc. to discontinued operations in the first quarter of 2007 and the two-for-one common stock split, effected in the form of a stock dividend, in July 2006.

(2)	New York Stock Exchange – composite transactions high and low intraday price.

PART III

Item 10. Directors, Executive Officers, and Corporate Governance.

The information required for the directors of the Registrant is incorporated by reference to the Halliburton Company Proxy Statement for our 2009 Annual Meeting of Stockholders (File No. 1-3492), under the captions “Election of Directors” and “Involvement in Certain Legal Proceedings.” The information required for the executive officers of the Registrant is included under Part I on pages 7 through 9 of this annual report. The information required for a delinquent form required under Section 16(a) of the Securities Exchange Act of 1934 is incorporated by reference to the Halliburton Company Proxy Statement for our 2009 Annual Meeting of Stockholders (File No. 1-3492), under the caption “Section 16(a) Beneficial Ownership Reporting Compliance,” to the extent any disclosure is required. The information for our code of ethics is incorporated by reference to the Halliburton Company Proxy Statement for our 2009 Annual Meeting of Stockholders (File No. 1-3492), under the caption “Corporate Governance.”

Audit Committee financial experts

In the business judgment of the Board of Directors, all four members of the Audit Committee, Alan M. Bennett, S. Malcolm Gillis, James T. Hackett, and Jay A. Precourt, are independent and have accounting or related financial management experience required under the listing standards and have been designated by the Board of Directors as “audit committee financial experts.”

Item 11. Executive Compensation.

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2009 Annual Meeting of Stockholders (File No. 1-3492) under the captions “Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table,” “Grants of Plan-Based Awards in Fiscal 2008,” “Outstanding Equity Awards at Fiscal Year End 2008,” “2008 Option Exercises and Stock Vested,” “2008 Nonqualified Deferred Compensation,” “Pension Benefits Table,” “Employment Contracts and Change-in-Control Arrangements,” “Post-Termination Payments,” “Equity Compensation Plan Information,” and “2008 Director Compensation.”

Item 12(a). Security Ownership of Certain Beneficial Owners.

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2009 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Stock Ownership of Certain Beneficial Owners and Management.”

Item 12(b). Security Ownership of Management.

Item 12(c). Changes in Control.

Not applicable.

Item 12(d). Securities Authorized for Issuance Under Equity Compensation Plans.

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2009 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Equity Compensation Plan Information.”

Item 13. Certain Relationships and Related Transactions, and Director Independence.

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2009 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Corporate Governance” to the extent any disclosure is required and under the caption “The Board of Directors and Standing Committees of Directors.”

Item 14. Principal Accounting Fees and Services.

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2009 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Fees Paid to KPMG LLP.”

PART IV

Item 15. Exhibits and Financial Statement Schedules.

Financial Statements:

The reports of the Independent Registered Public Accounting Firm and the financial statements of the Company as required by Part II, Item 8, are included on pages 53 and 54 and pages 55 through 92 of this annual report. See index on page (i).

2.	Financial Statement Schedules:	Page No.

	Report on supplemental schedule of KPMG LLP	105

	Schedule II – Valuation and qualifying accounts for the three
	years ended December 31, 2008	106
	Note: All schedules not filed with this report required by Regulation S-X have been ommitted as not applicable or
	not required, or the information required has been included in the notes to financial statements.

Exhibits:

Exhibit

Number

Exhibits

3.1

Restated Certificate of Incorporation of Halliburton Company filed with the Secretary of State of Delaware on May 30, 2006 (incorporated by reference to Exhibit 3.1 to Halliburton’s Form 8-K filed June 5, 2006, File No. 1-3492).

3.2

By-laws of Halliburton revised effective December 3, 2008 (incorporated by reference to Exhibit 3.1 to Halliburton’s Form 8-K filed December 5, 2008, File No. 1-3492).

4.1

Form of debt security of 8.75% Debentures due February 12, 2021 (incorporated by reference to Exhibit 4(a) to the Form 8-K of Halliburton Company, now known as Halliburton Energy Services, Inc. (the Predecessor) dated as of February 20, 1991, File No. 1-3492).

4.2

Senior Indenture dated as of January 2, 1991 between the Predecessor and The Bank of New York Trust Company, N.A. (as successor to Texas Commerce Bank National Association), as Trustee (incorporated by reference to Exhibit 4(b) to the Predecessor’s Registration Statement on Form S-3 (Registration No. 33-38394) originally filed with the Securities and Exchange Commission on December 21, 1990), as supplemented and amended by the First Supplemental Indenture dated as of December 12, 1996 among the Predecessor, Halliburton and the Trustee (incorporated by reference to Exhibit 4.1 of Halliburton’s Registration Statement on Form 8-B dated December 12, 1996, File No. 1-3492).

4.3

Resolutions of the Predecessor’s Board of Directors adopted at a meeting held on February 11, 1991 and of the special pricing committee of the Board of Directors of the Predecessor adopted at a meeting held on February 11, 1991 and the special pricing committee’s consent in lieu of meeting dated February 12, 1991 (incorporated by reference to Exhibit 4(c) to the Predecessor’s Form 8-K dated as of February 20, 1991, File No. 1-3492).

4.4

Second Senior Indenture dated as of December 1, 1996 between the Predecessor and The Bank of New York Trust Company, N.A. (as successor to Texas Commerce Bank National Association), as Trustee, as supplemented and amended by the First Supplemental Indenture dated as of December 5, 1996 between the Predecessor and the Trustee and the Second Supplemental Indenture dated as of December 12, 1996 among the Predecessor, Halliburton and the Trustee (incorporated by reference to Exhibit 4.2 of Halliburton’s Registration Statement on Form 8-B dated December 12, 1996, File No. 1-3492).

4.5

Third Supplemental Indenture dated as of August 1, 1997 between Halliburton and The Bank of New York Trust Company, N.A. (as successor to Texas Commerce Bank National Association), as Trustee, to the Second Senior Indenture dated as of December 1, 1996 (incorporated by reference to Exhibit 4.7 to Halliburton’s Form 10-K for the year ended December 31, 1998, File No. 1-3492).

4.6

Fourth Supplemental Indenture dated as of September 29, 1998 between Halliburton and The Bank of New York Trust Company, N.A. (as successor to Texas Commerce Bank National Association), as Trustee, to the Second Senior Indenture dated as of December 1, 1996 (incorporated by reference to Exhibit 4.8 to Halliburton’s Form 10-K for the year ended December 31, 1998, File No. 1-3492).

4.7

Resolutions of Halliburton’s Board of Directors adopted by unanimous consent dated December 5, 1996 (incorporated by reference to Exhibit 4(g) of Halliburton’s Form 10-K for the year ended December 31, 1996, File No. 1-3492).

4.8

Form of debt security of 6.75% Notes due February 1, 2027 (incorporated by reference to Exhibit 4.1 to Halliburton’s Form 8-K dated as of February 11, 1997, File No. 1-3492).

4.9

Resolutions of Halliburton’s Board of Directors adopted at a special meeting held on September 28, 1998 (incorporated by reference to Exhibit 4.10 to Halliburton’s Form 10-K for the year ended December 31, 1998, File No. 1-3492).

4.10

Copies of instruments that define the rights of holders of miscellaneous long-term notes of Halliburton and its subsidiaries, totaling $9 million in the aggregate at December 31, 2008, have not been filed with the Commission. Halliburton agrees to furnish copies of these instruments upon request.

4.11

Form of debt security of 7.53% Notes due May 12, 2017 (incorporated by reference to Exhibit 4.4 to Halliburton’s Form 10-Q for the quarter ended March 31, 1997, File No. 1-3492)

4.12

Form of Indenture, between Dresser and The Bank of New York Trust Company, N.A. (as successor to Texas Commerce Bank National Association), as Trustee, for 7.60% Debentures due 2096 (incorporated by reference to Exhibit 4 to the Registration Statement on Form S-3 filed by Dresser as amended, Registration No. 333-01303), as supplemented and amended by Form of Supplemental Indenture, between Dresser and The Bank of New York Trust Company, N.A. (as successor to Texas Commerce Bank National Association), Trustee, for 7.60% Debentures due 2096 (incorporated by reference to Exhibit 4.1 to Dresser’s Form 8-K filed on August 9, 1996, File No. 1-4003).

4.13

Second Supplemental Indenture dated as of October 27, 2003 between DII Industries, LLC and The Bank of New York Trust Company, N.A. (as successor to JPMorgan Chase Bank), as Trustee, to the Indenture dated as of April 18, 1996, as supplemented by the First Supplemental Indenture dated as of August 6, 1996 (incorporated by reference to Exhibit 4.15 to Halliburton’s Form 10-K for the year ended December 31, 2003, File No. 1-3492).

4.14

Third Supplemental Indenture dated as of December 12, 2003 among DII Industries, LLC, Halliburton and The Bank of New York Trust Company, N.A. (as successor to JPMorgan Chase Bank), as Trustee, to the Indenture dated as of April 18, 1996, as supplemented by the First Supplemental Indenture dated as of August 6, 1996 and the Second Supplemental Indenture dated as of October 27, 2003 (incorporated by reference to Exhibit 4.16 to Halliburton’s Form 10-K for the year ended December 31, 2003, File No. 1-3492).

4.15

Indenture dated as of October 17, 2003 between Halliburton and The Bank of New York Trust Company, N.A. (as successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.1 to Halliburton’s Form 10-Q for the quarter ended September 30, 2003, File No. 1-3492).

4.16

First Supplemental Indenture dated as of October 17, 2003 between Halliburton and The Bank of New York Trust Company, N.A. (as successor to JPMorgan Chase Bank), as Trustee, to the Senior Indenture dated as of October 17, 2003 (incorporated by reference to Exhibit 4.2 to Halliburton’s Form 10-Q for the quarter ended September 30, 2003, File No. 1-3492).

4.17

Form of note of 5.5% senior notes due October 15, 2010 (included as Exhibit B to Exhibit 4.16 above).

4.18

Second Supplemental Indenture dated as of December 15, 2003 between Halliburton and The Bank of New York Trust Company, N.A. (as successor to JPMorgan Chase Bank), as Trustee, to the Senior Indenture dated as of October 17, 2003, as supplemented by the First Supplemental Indenture dated as of October 17, 2003 (incorporated by reference to Exhibit 4.27 to Halliburton’s Form 10-K for the year ended December 31, 2003, File No. 1-3492).

4.19

Form of note of 7.6% debentures due 2096 (included as Exhibit A to Exhibit 4.18 above).

4.20

Stockholder Agreement between Halliburton and the DII Industries, LLC Asbestos PI Trust dated January 20, 2005 (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed January 25, 2005, File No. 1-3492).

4.21

Amendment to Stockholder Agreement dated March 17, 2005 between Halliburton Company and DII Industries, LLC Asbestos PI Trust (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed March 18, 2005, File No. 1-3492).

4.22

Fourth Supplemental Indenture, dated as of September 12, 2008, between Halliburton and The Bank of New York Mellon Trust Company, N.A., as successor trustee to JPMorgan Chase Bank, to the Senior Indenture dated as of October 17, 2003 (incorporated by reference to Exhibit 4.2 to Halliburton’s Form 8-K filed September 12, 2008, File No. 1-3492).

4.23

Form of Global Note for Halliburton’s 5.90% Senior Notes due 2018 (included as part of Exhibit 4.22).

4.24

Form of Global Note for Halliburton’s 6.70% Senior Notes due 2038 (included as part of Exhibit 4.22).

10.1

Halliburton Company Career Executive Incentive Stock Plan as amended November 15, 1990 (incorporated by reference to Exhibit 10(a) to the Predecessor’s Form 10-K for the year ended December 31, 1992, File No. 1-3492).

10.2

Halliburton Company 1993 Stock and Incentive Plan, as amended and restated effective February 16, 2006 (incorporated by reference to Exhibit 10.3 to Halliburton’s Form 10-K for the year ended December 31, 2005, File No. 1-3492).

10.3

Halliburton Company Restricted Stock Plan for Non-Employee Directors (incorporated by reference to Appendix B of the Predecessor’s proxy statement dated March 23, 1993, File No. 1-3492).

10.4

Dresser Industries, Inc. Deferred Compensation Plan, as amended and restated effective January 1, 2000 (incorporated by reference to Exhibit 10.16 to Halliburton’s Form 10-K for the year ended December 31, 2000, File No. 1-3492).

100

10.5

ERISA Excess Benefit Plan for Dresser Industries, Inc., as amended and restated effective June 1, 1995 (incorporated by reference to Exhibit 10.7 to Dresser’s Form 10-K for the year ended October 31, 1995, File No. 1-4003).

10.6

ERISA Compensation Limit Benefit Plan for Dresser Industries, Inc., as amended and restated effective June 1, 1995 (incorporated by reference to Exhibit 10.8 to Dresser’s Form 10-K for the year ended October 31, 1995, File No. 1-4003).

10.7

Employment Agreement (David J. Lesar) (incorporated by reference to Exhibit 10(n) to the Predecessor’s Form 10-K for the year ended December 31, 1995, File No. 1-3492).

10.8

Employment Agreement (Mark A. McCollum) (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 10-Q for the quarter ended September 30, 2003, File No. 1-3492).

10.9

Halliburton Company Performance Unit Program (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 10-Q for the quarter ended September 30, 2001, File No. 1-3492).

10.10

Form of Nonstatutory Stock Option Agreement for Non-Employee Directors (incorporated by reference to Exhibit 10.3 to Halliburton’s Form 10-Q for the quarter ended September 30, 2000, File No. 1-3492).

10.11

Halliburton Company 2002 Employee Stock Purchase Plan, as amended and restated May 17, 2005 (incorporated by reference to Exhibit 10.21 to Halliburton’s Form 10-K for the year ended December 31, 2005, File No. 1-3492).

10.12

Employment Agreement (Albert O. Cornelison) (incorporated by reference to Exhibit 10.3 to Halliburton’s Form 10-Q for the quarter ended June 30, 2002, File No. 1-3492).

10.13

Employment Agreement (C. Christopher Gaut) (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 10-Q for the quarter ended March 31, 2003, File No. 1-3492).

10.14

Master Separation Agreement between Halliburton Company and KBR, Inc. dated as of November 20, 2006 (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed November 27, 2006, File No. 1-3492).

10.15

Tax Sharing Agreement, effective as of January 1, 2006, by and between Halliburton Company, KBR Holdings, LLC and KBR, Inc., as amended effective February 26, 2007 (incorporated by reference to Exhibit 10.2 to KBR’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-33146).

101

10.16

Five Year Revolving Credit Agreement among Halliburton, as Borrower, the Banks party thereto, and Citicorp North America, Inc., as Administrative Agent (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed July 13, 2007, File No. 1-3492).

10.17

Form of Indemnification Agreement for Officers (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed August 3, 2007, File No. 1-3492).

10.18

Form of Indemnification Agreement for Directors (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 8-K filed August 3, 2007, File No. 1-3492).

10.19

2008 Halliburton Elective Deferral Plan, as amended and restated effective January 1, 2008 (incorporated by reference to Exhibit 10.3 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No. 1-3492).

10.20

Halliburton Company Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2008 (incorporated by reference to Exhibit 10.4 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No. 1-3492).

10.21

Halliburton Company Benefit Restoration Plan, as amended and restated effective January 1, 2008 (incorporated by reference to Exhibit 10.5 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No. 1-3492).

10.22

Halliburton Annual Performance Pay Plan, as amended and restated effective January 1, 2007 (incorporated by reference to Exhibit 10.6 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No. 1-3492).

10.23

Halliburton Management Performance Plan, as amended and restated effective January 1, 2007 (incorporated by reference to Exhibit 10.7 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No. 1-3492).

10.24

Halliburton Company Pension Equalizer Plan, as amended and restated effective March 1, 2007 (incorporated by reference to Exhibit 10.8 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No. 1-3492).

10.25

Halliburton Company Directors’ Deferred Compensation Plan, as amended and restated effective January 1, 2007 (incorporated by reference to Exhibit 10.9 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No. 1-3492).

10.26

Retirement Plan for the Directors of Halliburton Company, as amended and restated effective July 1, 2007 (incorporated by reference to Exhibit 10.10 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No. 1-3492).

102

10.27

First Amendment to the Retirement Plan for the Directors of Halliburton Company, effective September 1, 2007 (incorporated by reference to Exhibit 10.11 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No. 1-3492).

10.28

Revolving Bridge Facility Credit Agreement among Halliburton, as Borrower, the Banks party thereto, and Citibank, N.A., as Agent (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 10-Q for the quarter ended June 30, 2008, File No. 1-3492).

10.29

Underwriting Agreement, dated September 9, 2008, among Halliburton and Citigroup Global Markets Inc., Greenwich Capital Markets, Inc. and HSBC Securities (USA) Inc., as representatives of the several underwriters identified therein (incorporated by reference to Exhibit 1.1 to Halliburton’s Form 8-K filed September 12, 2008, File No. 1-3492).

10.30

Six Month Revolving Credit Agreement among Halliburton, as Borrower, the Banks party thereto, and HSBC Bank (USA) N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed October 16, 2008, File No. 1-3492).

10.31

Employment Agreement (James S. Brown) (incorporated by reference to Exhibit 10.36 to Halliburton’s Form 10-K for the year ended December 31, 2007, File No. 1-3492).

10.32

Employment Agreement (David S. King) (incorporated by reference to Exhibit 10.37 to Halliburton’s Form 10-K for the year ended December 31, 2007, File No. 1-3492).

10.33

Executive Agreement (Lawrence J. Pope) (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed December 12, 2008, File No. 1-3492).

10.34

Executive Agreement (Evelyn M. Angelle).

10.35

Executive Agreement (Ahmed H. Lotfy).

10.36

Executive Agreement (Timothy J. Probert).

10.37

Executive Agreement (Craig W. Nunez).

10.38

Amendment to Executive Employment Agreement (David S. King).

10.39

Amendment to Executive Employment Agreement (James S. Brown).

10.40

Amendment to Executive Employment Agreement (Albert O. Cornelison).

10.41

Amendment to Executive Employment Agreement (C. Christopher Gaut).

10.42

Amendment to Executive Employment Agreement (David S. King).

103

10.43

Amendment to Executive Employment Agreement (Mark A. McCollum).

12.1

Statement of Computation of Ratio of Earnings to Fixed Charges.

21.1

Subsidiaries of the Registrant.

23.1

Consent of KPMG LLP.

24.1

Powers of attorney for the following directors signed in January 2007 (incorporated by reference to Exhibit 24.1 to Halliburton’s Form 10-K for the year ended December 31, 2006, File No. 1-3492):

Alan M. Bennett

James R. Boyd

Milton Carroll

Kenneth T. Derr

S. Malcolm Gillis

J. Landis Martin

Jay A. Precourt

Debra L. Reed

24.2

Power of attorney for James T. Hackett signed in January 2009.

31.1

Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Filed with this Form 10-K.

Furnished with this Form 10-K.

104

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ON SUPPLEMENTAL SCHEDULE

The Board of Directors and Shareholders

Halliburton Company:

Under date of February 16, 2009, we reported on the consolidated balance sheets of Halliburton Company and subsidiaries as of December 31, 2008 and 2007, 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, 2008, which are included in the Company’s Annual Report on Form 10-K. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related consolidated financial statement schedule (Schedule II) in the Company’s Annual Report on Form 10-K. The financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement schedule based on our audits.

In our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

Our report on the financial statements referred to above, refers to a change in the methods of accounting for uncertainty in income taxes as of January 1, 2007 and accounting for defined benefit and other postretirement plans as of December 31, 2006.

/s/ KPMG LLP

Houston, Texas

February 16, 2009

105

HALLIBURTON COMPANY

Schedule II - Valuation and Qualifying Accounts

(Millions of Dollars)

The table below presents valuation and qualifying accounts:

	Balance at		Charged to					Balance at
Allowance for Doubtful Accounts	Beginning of Period		Costs and Expenses		Write-Offs			End of Period
Year ended December 31, 2006:	$	38	$	6	$	(4	)	$	40
Year ended December 31, 2007:		40		10		(1	)		49
Year ended December 31, 2008:		49		14		(3	)		60

106

SIGNATURES

As required by Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has authorized this report to be signed on its behalf by the undersigned authorized individuals on this 18th day of February, 2009.


	HALLIBURTON COMPANY




By	/s/ David J. Lesar
	David J. Lesar
	Chairman of the Board,
	President, and Chief Executive Officer

As required by the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities indicated on this 18th day of February, 2009.

Signature	Title




/s/ David J. Lesar	Chairman of the Board, President,
David J. Lesar	Chief Executive Officer, and Director




/s/ Mark A. McCollum	Executive Vice President and
Mark A. McCollum	Chief Financial Officer




/s/ Evelyn M. Angelle	Vice President, Corporate Controller, and
Evelyn M. Angelle	Principal Accounting Officer

107

Signature	Title

* Alan M. Bennett	Director
Alan M. Bennett

* James R. Boyd	Director
James R. Boyd

* Milton Carroll	Director
Milton Carroll

* Kenneth T. Derr	Director
Kenneth T. Derr

* S. Malcolm Gillis	Director
S. Malcolm Gillis

* James T. Hackett	Director
James T. Hackett

* J. Landis Martin	Director
J. Landis Martin

* Jay A. Precourt	Director
Jay A. Precourt

* Debra L. Reed	Director
Debra L. Reed




* /s/ Sherry D. Williams
Sherry D. Williams, Attorney-in-fact