Edgar Filing: HALLIBURTON CO

ed10k2007_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, 2007

[ ] 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 is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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 29, 2007, determined using the per share closing price on the New York Stock Exchange Composite tape of $34.50 on that date was approximately $30,691,000,000.

As of February 14, 2008, there were 880,157,300 shares of Halliburton Company Common Stock, $2.50 par value per share, outstanding.

Portions of the Halliburton Company Proxy Statement for our 2008 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, 2007

PART I		PAGE
Item 1.	Business	1
Item 1(a).	Risk Factors	5
Item 1(b).	Unresolved Staff Comments	5
Item 2.	Properties	5
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 Operation	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		45
Reports of Independent Registered Public Accounting Firm		46
Consolidated Statements of Operations		48
Consolidated Balance Sheets		49
Consolidated Statements of Shareholders’ Equity		50
Consolidated Statements of Cash Flows		51
Notes to Consolidated Financial Statements		52
Selected Financial Data (Unaudited)		86
Quarterly Data and Market Price Information (Unaudited)		87
PART III
Item 10.	Directors, Executive Officers, and Corporate Governance	88
Item 11.	Executive Compensation	88
Item 12(a).	Security Ownership of Certain Beneficial Owners	88
Item 12(b).	Security Ownership of Management	88
Item 12(c).	Changes in Control	88
Item 12(d).	Securities Authorized for Issuance Under Equity Compensation Plans	88
Item 13.	Certain Relationships and Related Transactions, and Director
	Independence	88
Item 14.	Principal Accounting Fees and Services	89
PART IV
Item 15.	Exhibits and Financial Statement Schedules	90
SIGNATURES		99

(i)

PART I

Item 1. Business.

General description of business

Halliburton Company’s predecessor was established in 1919 and incorporated under the laws of the State of Delaware in 1924. Halliburton Company provides a variety of services and products to customers in the energy industry.

In November 2006, KBR, Inc. (KBR), which at the time was our wholly owned subsidiary, 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. 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, which is included in income from discontinued operations in the consolidated statements of operations.

See Note 4 to the consolidated financial statements for financial information about our business segments.

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. Additionally, completion tools and services include WellDynamics, an intelligent well completions joint venture, which we consolidate for accounting purposes.

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 precise well-bore placement solutions that enable customers to model, measure, and optimize their well construction activities. This segment consists of Baroid Fluid Services, Sperry Drilling Services, Security DBS Drill Bits, wireline and perforating services, Landmark, and project management.

Baroid 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.

Sperry 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 while providing important measurements about the characteristics of the drill string and geological formations while drilling directional wells. Real-time operating capabilities enable the monitoring of well progress and aid decision-making processes.

Security DBS 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, and 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, and perforating. Perforating services include tubing-conveyed perforating services and products.

Landmark 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 2007, we acquired the entire share capital of PSL Energy Services Limited (PSLES), an 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 approximately $330 million for PSLES, consisting of $326 million in cash and $4 million in debt assumed, subject to adjustment for working capital purposes. As of December 31, 2007, we had recorded goodwill of $163 million and intangible assets of $54 million on a preliminary basis until our analysis of the fair value of assets acquired and liabilities assumed is complete. 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. This investment was reflected in “Other assets” on our consolidated balance sheet at December 31, 2006.

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.

In January 2005, we completed the sale of our 50% interest in Subsea 7, Inc. to our joint venture partner, Siem Offshore (formerly DSND Subsea ASA), for approximately $200 million in cash. As a result of the transaction, we recorded a gain of approximately $110 million during the first quarter of 2005. We accounted for our 50% ownership of Subsea 7, Inc. using the equity method in our Completion and Production 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. In 2007, based on the location of services provided and products sold, 44% of our consolidated revenue was from the United States. In 2006, 45% of our consolidated revenue was from the United States. In 2005, 43% 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 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. Current market conditions have triggered constraints in the supply of certain raw materials, such as sand, cement, and specialty metals. Given high activity levels, particularly in the United States, we are seeking ways to ensure the availability of resources, as well as manage the rising 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 $301 million in 2007, $254 million in 2006, and $218 million in 2005, of which over 97% 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, Landmark 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, 2007, we employed approximately 51,000 people worldwide compared to approximately 45,000 at December 31, 2006. At December 31, 2007, approximately 12% 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.

Web site access

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 are made available free of charge on our internet web site at www.halliburton.com as soon as reasonably practicable after we have electronically filed the material with, or furnished it to, the Securities and Exchange Commission (SEC). The public may read and copy any materials we have filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site that contains our reports, proxy and information statements, and our other SEC filings. The address of that site is www.sec.gov. We have posted on our web site our Code of Business Conduct, which applies to all of our employees and Directors and serves as a code of ethics for our principal executive officer, principal financial officer, principal accounting officer, and other persons performing similar functions. Any amendments to our Code of Business Conduct or any waivers from provisions of our Code of Business Conduct granted to the specified officers above are disclosed on our web site within four business days after the date of any amendment or waiver pertaining to these officers. There have been no waivers from provisions of our Code of Business Conduct during 2007, 2006, or 2005.

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” under “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:
Carrollton, Texas	Owned	Manufacturing facility
Johor, Malaysia	Leased	Manufacturing facility
Monterrey, Mexico	Leased	Manufacturing facility
Sao Jose dos Campos, Brazil	Leased	Manufacturing facility

Drilling and Evaluation segment:
Alvarado, Texas	Owned/Leased	Manufacturing facility
Singapore	Leased	Manufacturing facility
The Woodlands, Texas	Leased	Manufacturing facility

Shared facilities:
Duncan, Oklahoma	Owned	Manufacturing, technology, and camp facilities
Houston, Texas	Owned	Manufacturing and campus facilities
Houston, Texas	Owned/Leased	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 97 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” in “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 2007.

Executive Officers of the Registrant

The following table indicates the names and ages of the executive officers of Halliburton Company as of February 15, 2008, 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 40)	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
	Senior Manager of Ernst & Young, April 1996 to March 2003

Peter C. Bernard	Senior Vice President, Business Development and Marketing of
(Age 46)	Halliburton Company, since June 2006
	Senior Vice President, Digital and Consulting Solutions of Halliburton
	Company, December 2004 to May 2006
	President of Landmark Graphics Corporation, May 2004 to December 2004
	Vice President, Marketing and Managed Accounts of Landmark Graphics
	Corporation, May 2003 to May 2004
	Vice President, Strategic Account Business Development, January 2002
	to May 2003

James S. Brown	President, Western Hemisphere of Halliburton Company, since January 2008
(Age 53)	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
	Vice President, Business Development of Halliburton Company, October 2001
	to October 2003

* Albert O. Cornelison, Jr.	Executive Vice President and General Counsel of Halliburton Company,
(Age 58)	since December 2002
	Director of KBR, Inc., June 2006 to April 2007

C. Christopher Gaut	President, Drilling and Evaluation Division of Halliburton Company,
(Age 51)	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
	Senior Vice President, Chief Financial Officer, and Member – Office of the
	President and Chief Operating Officer of ENSCO International, Inc.,
	January 2002 to February 2003

Name and Age	Offices Held and Term of Office
David S. King	President, Completion and Production Division of Halliburton Company,
(Age 51)	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
	Vice President, Production Enhancement of Halliburton Energy Services Group,
	January 2000 to May 2003

* David J. Lesar	Chairman of the Board, President, and Chief Executive Officer of Halliburton
(Age 54)	Company, since August 2000

Ahmed H. M. Lotfy	President, Eastern Hemisphere of Halliburton Company, since January 2008
(Age 53)	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 48)	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
	Senior Vice President and Chief Financial Officer of Tenneco Automotive, Inc.,
	November 1999 to August 2003

Craig W. Nunez	Senior Vice President and Treasurer of Halliburton Company,
(Age 46)	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 39)	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
	Division Vice President, Human Resources for Halliburton Energy Services Group,
	May 2001 to July 2003

* Timothy J. Probert	Executive Vice President, Strategy and Corporate Development of Halliburton
(Age 56)	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 87 of this annual report. Cash dividends on common stock in the amount of $0.09 per share were paid in June, September, and December of 2007 and $0.075 per share were paid in March of 2007 and March, June, September, and December of 2006. 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 ending December 31, 2007, 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, 2002, and the reinvestment of all dividends. The shareholder return set forth is not necessarily indicative of future performance.

	December 31
	2002		2003		2004		2005		2006		2007
Halliburton	$	100.00	$	142.06	$	217.75	$	347.23	$	351.09	$	432.98
Standard & Poor’s 500 Stock Index		100.00		128.68		142.69		149.70		173.34		182.86
Standard & Poor’s Energy Composite Index		100.00		125.63		165.25		217.08		269.64		362.40

At February 18, 2008, there were 19,110 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, 2007.

					Total Number of
					Shares Purchased
	Total Number of				as Part of
	Shares		Average Price		Publicly Announced
Period	Purchased (a)		Paid per Share		Plans or Programs (b)
October 1-31		36,632	$	38.99		–
November 1-30		1,270,142	$	36.16		1,261,022
December 1-31		640,977	$	36.58		590,253
Total		1,947,751	$	36.35		1,851,275

(a)

Of the 1,947,751 shares purchased during the three-month period ended December 31, 2007, 96,476 shares were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase common shares.

(b)

In July 2007, our Board of Directors approved an additional increase to our existing common share repurchase program of up to $2.0 billion, bringing the entire authorization to $5.0 billion. This additional authorization may be used for open market share purchases or to settle the conversion premium on our 3.125% convertible senior notes, should they be redeemed. From the inception of this program through December 31, 2007, we have repurchased approximately 79 million shares of our common stock for approximately $2.7 billion at an average price per share of $33.91. These numbers include the repurchases of approximately 39 million shares of our common stock for approximately $1.4 billion at an average price per share of $34.93 during 2007. As of December 31, 2007, $2.3 billion remained available under our share repurchase authorization.

Item 6. Selected Financial Data.

Information related to selected financial data is included on page 86 of this annual report.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.

Information related to Management’s Discussion and Analysis of Financial Condition and Results of Operations is included on pages 13 through 44 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 32 of this annual report.

Item 8. Financial Statements and Supplementary Data.

	Page No.
Management’s Report on Internal Control Over Financial Reporting	45
Reports of Independent Registered Public Accounting Firm	46
Consolidated Statements of Operations for the years ended December 31, 2007, 2006, and 2005	48
Consolidated Balance Sheets at December 31, 2007 and 2006	49
Consolidated Statements of Shareholders’ Equity for the years ended
December 31, 2007, 2006, and 2005	50
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006, and 2005	51
Notes to Consolidated Financial Statements	52
Selected Financial Data (Unaudited)	86
Quarterly Data and Market Price Information (Unaudited)	87

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, 2007 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, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

See page 45 for Management’s Report on Internal Control Over Financial Reporting and page 47 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.

Item 9(b). Other Information.

None.

HALLIBURTON COMPANY

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

EXECUTIVE OVERVIEW

During 2007, our continuing operations produced revenue of $15.3 billion and operating income of $3.5 billion, reflecting an operating margin of 23%. Revenue increased $2.3 billion or 18% over 2006, while operating income improved $253 million or 8% over 2006. Internationally, our operations experienced 21% revenue growth and 18% operating income growth in 2007 compared to 2006. Consistent with our initiative to grow our eastern hemisphere operations, revenue from the eastern hemisphere increased 27% to $6.3 billion in 2007 compared to 2006, comprising nearly 90% of the revenue growth derived internationally. Moreover, eastern hemisphere quarterly operating margins consistently remained above 20%.

Business outlook

The outlook for our business remains generally favorable. Despite challenging market conditions in North America, the region realized strong revenue growth in 2007 compared to 2006. However, downward pressure on pricing in the latter half of 2007, particularly in our United States well stimulation land operations, negatively impacted our operating results. Based on price levels that were negotiated on contracts that renewed in the fourth quarter of 2007, we anticipate an average price decline for our United States land stimulation work in the mid- to upper-single digits in the first quarter of 2008 relative to the fourth quarter of 2007. We believe pricing pressure may be partially mitigated by higher levels of asset utilization for our fracturing equipment and our horizontal drilling technologies, as we continue to see increasing demand from our customers due to trends toward production from unconventional reservoirs that were previously not economical. We believe that these factors may contribute to volume increases in the technologically driven segments of the energy services business, even if rig counts remain relatively flat. Also, we believe our ability to offer multiple product lines to our customers helps mitigate the impact of pricing pressures in our well stimulation operations. We have seen North America pricing declines in other product lines as well, including cementing, fluid services, and wireline and perforating, but they continue to be at lower levels than what we have seen in our well stimulation business. While we anticipate improved activity levels in our United States land operations, we do think there is downside risk to our operating margins if pricing continues to erode or if natural gas prices decline significantly. In Canada, while we experienced a moderate seasonal recovery in the second half of 2007, our full-year revenue compared to 2006 declined 22% on a 27% decrease in average Canada rig count for the year. Looking ahead, we are not planning on a significant recovery in Canada in 2008. Where appropriate, we reduced personnel and moved equipment to higher utilization areas.

Outside of North America, our outlook remains positive. Worldwide demand for hydrocarbons continues to grow, and the reservoirs are becoming more complex. The trend toward exploration and exploitation of more complex reservoirs bodes well for the mix of our product line offerings and degree of service intensity on a per rig basis. Therefore, we have been investing and will continue to invest in infrastructure, capital, and technology predominantly in the eastern hemisphere, consistent with our initiative to grow our operations in that part of the world.

In 2008, we will focus on:

maintaining optimal utilization of our equipment and resources;

managing pricing, particularly in our North America operations;

hiring and training additional personnel to meet the increased demand for our services;

continuing the globalization of our manufacturing and supply chain processes;

balancing our United States operations by capitalizing on the trend toward horizontal drilling;

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

maximizing our position to win meaningful international tenders, especially in deepwater fields, complex reservoirs, and high-pressure/high-temperature environments;

cultivating our relationships with national oil companies;

pursuing strategic acquisitions in line with our core products and services to expand our portfolio in key geographic areas; and

directing our capital spending primarily toward eastern hemisphere operations for service equipment additions and infrastructure. Capital spending for 2008 is expected to be approximately $1.7 billion to $1.8 billion.

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

Separation of KBR, Inc.

In November 2006, KBR, Inc. (KBR), which at the time was our wholly owned subsidiary, completed an initial public offering (IPO), in which it sold approximately 32 million shares of KBR common stock. 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. Consequently, KBR operations have been reclassified as discontinued operations in the consolidated financial statements for all periods presented. See Note 2 to our consolidated financial statements for further information.

Foreign Corrupt Practices Act investigations

The Securities and Exchange Commission (SEC) is conducting a formal investigation into whether improper payments were made to government officials in Nigeria. The Department of Justice (DOJ) is also conducting a related criminal investigation. See Note 10 to our consolidated financial statements for further information.

Other corporate matters

In May 2007, the Board of Directors increased the quarterly dividend by $0.015 per common share, or 20%, to $0.09 per share.

In February 2006, our Board of Directors approved a share repurchase program of up to $1.0 billion. In September 2006, our Board of Directors approved an increase to our existing common share repurchase program of up to an additional $2.0 billion. In July 2007, our Board of Directors approved an additional increase to our existing common share repurchase program of up to $2.0 billion, bringing the entire authorization to $5.0 billion. This additional authorization may be used for open market share purchases or to settle the conversion premium on our 3.125% convertible senior notes, should they be redeemed. From the inception of this program through December 31, 2007, we have repurchased approximately 79 million shares of our common stock for approximately $2.7 billion at an average price per share of $33.91. These numbers include the repurchases of approximately 39 million shares of our common stock for approximately $1.4 billion at an average price per share of $34.93 during 2007. As of December 31, 2007, $2.3 billion remained available under our share repurchase authorization.

LIQUIDITY AND CAPITAL RESOURCES

We ended 2007 with cash and equivalents of $1.8 billion compared to $2.9 billion at December 31, 2006.

Significant sources of cash

Cash flows from operating activities contributed $2.7 billion to cash in 2007. Growth in revenue and operating income are attributable to higher customer demand and increased service intensity due to a trend toward exploration and exploitation of more complex reservoirs. Cash flows from operating activities included $31 million in cash inflows related to discontinued operations.

In May 2007, we sold our remaining interest in Dresser, Ltd. for $70 million in cash.

Further available sources of cash. On July 9, 2007, we entered into a new unsecured $1.2 billion five-year revolving credit facility that replaced our then existing unsecured $1.2 billion five-year revolving credit facility. The purpose of the new facility is 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, 2007.

Significant uses of cash

Capital expenditures were $1.6 billion in 2007, with increased focus toward building infrastructure and adding service equipment in support of our expanding operations in the eastern hemisphere. Capital expenditures were predominantly made in the drilling services, production enhancement, wireline, and cementing product service lines.

During 2007, we repurchased approximately 39 million shares of our common stock under our share repurchase program at a cost of approximately $1.4 billion at an average price per share of $34.93.

During 2007, we invested in approximately $332 million of marketable securities, consisting of auction-rate securities, variable-rate demand notes, and municipal bonds.

We paid $314 million in dividends to our shareholders in 2007. In May 2007, the Board of Directors authorized a dividend increase of $0.015 per common share, bringing quarterly dividends to $0.09 per common share for the remainder of 2007.

In the third quarter of 2007, we purchased the entire share capital of PSL Energy Services Limited (PSLES), an eastern hemisphere provider of process, pipeline, and well intervention services, for $326 million in cash and $4 million in debt assumed upon acquisition.

In January 2007, we acquired all of the intellectual property, current assets, and existing wireline services business associated with Ultraline Services Corporation, a division of Savanna Energy Services Corp., for approximately $178 million.

Future uses of cash. In July 2007, our Board of Directors approved an increase to our existing common share repurchase program of up to an additional $2.0 billion, bringing the entire authorization to $5.0 billion. This additional authorization may be used for open market share purchases or to settle the conversion premium over the face amount of our 3.125% convertible senior notes, should they be redeemed. As of December 31, 2007, $2.3 billion remained available under our share repurchase authorization.

Capital spending for 2008 is expected to be approximately $1.7 billion to $1.8 billion. The capital expenditures forecast for 2008 is primarily directed toward our drilling services, wireline and perforating, production enhancement, and cementing operations. We will continue to explore 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. Further, as market conditions change, we will continue to evaluate the allocation of our cash between acquisitions and stock buybacks in order to provide good return for our shareholders.

Our 3.125% convertible senior notes become redeemable at our option on or after July 15, 2008. If we choose to redeem the notes prior to their maturity or if the holders choose to convert the notes, we must settle the principal amount of the notes, which totaled $1.2 billion at December 31, 2007, in cash. We have the option to settle any amounts due in excess of the principal, which also totaled approximately $1.2 billion at December 31, 2007, by delivering shares of our common stock, cash, or a combination of common stock and cash.

Subject to Board of Director approval, we expect to pay dividends of approximately $80 million per quarter in 2008.

The following table summarizes our significant contractual obligations and other long-term liabilities as of December 31, 2007:

	Payments Due
Millions of dollars	2008		2009		2010		2011		2012		Thereafter		Total
Long-term debt	$	159	$	12	$	755	$	3	$	3	$	1,854	$	2,786
Interest on debt (a)		138		129		129		87		87		2,582		3,152
Operating leases		180		131		104		74		40		172		701
Purchase obligations		1,292		125		39		11		1		8		1,476
Pension funding obligations		30		–		–		–		–		–		30
Total	$	1,799	$	397	$	1,027	$	175	$	131	$	4,616	$	8,145

(a)

Interest on debt includes 89 years of interest on $300 million of debentures at 7.6% interest that become due in 2096.

With the adoption of Financial Accounting Standards Board (FASB) Interpretation No. 48 (FIN 48), we had $425 million of gross unrecognized tax benefits at December 31, 2007, of which we estimate $189 million may require a cash payment. We estimate that $102 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, 2007, including $1.1 billion 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.

Credit ratings. The credit ratings for our long-term debt are A2 with Moody’s Investors Service and A with Standard & Poor’s. Our Moody’s Investors Service rating became effective May 1, 2007, and was an upward revision from our previous Moody’s Investors Service rating of Baa1, which had been in effect since December 2005. Our Standard & Poor’s rating became effective August 20, 2007, and was an upward revision from our previous Standard & Poor’s rating of BBB+, which had been in effect since May 2006. The credit ratings on our short-term debt are P1 with Moody’s Investors Service and A1 with Standard & Poor’s.

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 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. Our two business segments are the Completion and Production segment and the Drilling and Evaluation segment. The two KBR segments have been reclassified as discontinued operations as a result of the separation of KBR.

The industries we serve are highly competitive with many substantial competitors in each segment. In 2007, based upon the location of the services provided and products sold, 44% of our consolidated revenue was from the United States. In 2006, 45% of our consolidated revenue was from the United States. In 2005, 43% of our consolidated revenue was from the United States. No other country accounted for more than 10% of our revenue during these periods.

Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil unrest, force majeure, war or other armed conflict, expropriation or other governmental actions, inflation, exchange control problems, and highly inflationary currencies. We believe the geographic diversification of our business activities reduces the risk that loss of operations in any one country would be 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 gas consumption.

Some of the more significant barometers of current and future spending levels of oil and gas companies are oil and gas prices, the world economy, and global stability, which together drive worldwide drilling activity. Our financial performance is significantly affected by oil and gas prices and worldwide rig activity, which are summarized in the following tables.

This table shows the average oil and gas prices for West Texas Intermediate (WTI) and United Kingdom Brent crude oil, and Henry Hub natural gas:

Average Oil Prices (dollars per barrel)	2007		2006		2005
West Texas Intermediate	$	71.91	$	66.17	$	56.30
United Kingdom Brent	$	72.21	$	65.35	$	54.45

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

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

Land vs. Offshore	2007		2006		2005
United States:
Land		1,694		1,558		1,287
Offshore		73		90		93
Total		1,767		1,648		1,380
Canada:
Land		341		467		454
Offshore		3		3		4
Total		344		470		458
International (excluding Canada):
Land		719		656		593
Offshore		287		269		258
Total		1,006		925		851
Worldwide total		3,117		3,043		2,689
Land total		2,754		2,681		2,334
Offshore total		363		362		355

Oil vs. Gas	2007		2006		2005
United States:
Oil		297		273		194
Gas		1,470		1,375		1,186
Total		1,767		1,648		1,380
Canada:
Oil		128		110		100
Gas		216		360		358
Total		344		470		458
International (excluding Canada):
Oil		784		709		651
Gas		222		216		200
Total		1,006		925		851
Worldwide total		3,117		3,043		2,689
Oil total		1,209		1,092		945
Gas total		1,908		1,951		1,744

Our customers’ cash flows, in many instances, depend upon the revenue they generate from the sale of oil and gas. Higher oil and gas prices usually translate into higher exploration and production budgets. Higher prices also improve the economic attractiveness of unconventional reservoirs. This promotes additional investment by our customers. The opposite is true for lower oil and gas prices.

After declining from record highs during the third and fourth quarters of 2006, WTI oil spot prices averaged $72.00 per barrel in 2007 and are expected to average $87.00 per barrel in 2008 according to the Energy Information Administration (EIA). Between mid-December 2006 and mid-January 2007, the WTI crude oil price fell about $12 per barrel to a low of $50.51 per barrel, as warm weather reduced demand for heating fuels throughout most of the United States. However, the WTI price recovered to over $66 per barrel by the end of March 2007, as the weather turned colder than normal and geopolitical tensions intensified. Crude oil prices continued to rise to record levels over the $99 per barrel mark throughout 2007 due to a tight world oil supply and demand balance, ending the year at approximately $96 per barrel. We expect that oil prices will remain at levels sufficient to sustain, and likely grow, our customers’ current levels of spending due to a combination of the following factors:

continued growth in worldwide petroleum demand, despite high oil prices;

projected production growth in non-Organization of Petroleum Exporting Countries (non-OPEC) supplies is not expected to accommodate world wide demand growth;

OPEC’s commitment to control production;

modest increases in OPEC’s current and forecasted production capacity; and

geopolitical tensions in major oil-exporting nations.

According to the International Energy Agency’s (IEA) January 2008 “Oil Market Report,” the outlook for world oil demand remains strong, with China, the Middle East, and Europe accounting for approximately 52% of the expected demand growth in 2008. Excess oil production capacity is expected to remain constrained and that, along with increased demand, is expected to keep supplies tight. Thus, any unexpected supply disruption or change in demand could lead to fluctuating prices. The IEA forecasts world petroleum demand growth in 2008 to increase 2% over 2007.

North America operations. Volatility in natural gas prices has the potential to impact our customers' drilling and production activities, particularly in North America. In the first quarter of 2007, we experienced lower than anticipated customer activity in North America, particularly the pressure pumping market in Canada and the United States Rockies. Some of this activity decline was attributable to poor weather, including an early spring break-up season in Canada and severe weather early in 2007 in the United States Rockies and mid-continent regions. In addition, the unusually warm start to the United States 2006/2007 winter caused concern about natural gas storage levels, which negatively impacted the price of natural gas. This uncertainty made many of our customers more cautious about their drilling and production plans in the early part of 2007. The second half of 2007 was characterized by increased activity for our United States customers and recovery in the Gulf of Mexico after the hurricane season. Despite recovery from a traditionally slow second quarter spring break-up season, Canada experienced a significant decline in activity as compared to 2006. Beginning in late 2006, we began moving equipment and personnel from Canada to the United States and Latin America to address the anticipated slowdown. In January 2008, the EIA stated that the Henry Hub spot price averaged $7.17 per thousand cubic feet (mcf) in 2007 and was projected to average $7.78 per mcf in 2008.

It is common practice in the United States oilfield services industry to sell services and products based on a price book and then apply discounts to the price book based upon a variety of factors. The discounts applied typically increase to partially offset price book increases. We experienced increased pricing pressure from our customers in the North American market in 2007, particularly in Canada and in our United States well stimulation operations. In the fourth quarter of 2007, we saw price declines for our fracturing services in the United States in the low- to mid-single digits. While we anticipate improved activity levels in our United States land operations, we do think there is downside risk to our operating margins if pricing continues to erode or if natural gas prices decline significantly.

Focus on international growth. Consistent with our strategy to grow our international operations, we expect to continue to invest capital and increase manufacturing capacity to bring new tools online to serve the high demand for our services. Following is a brief discussion of some of our recent initiatives:

we opened a corporate office in Dubai, United Arab Emirates, allowing us to focus more attention on customer relationships in that part of the world, particularly with national oil companies;

in order to continue to supply our customers with leading-edge services and products, we have increased our technology spending during 2007 as compared to the prior year. Our plans are progressing for new international research and development centers with global technology and training missions. We opened one in Pune, India in the third quarter of 2007, and we expect to open a second facility in Singapore in 2008;

we are expanding our manufacturing capability and capacity to meet the increasing demands for our services and products. In 2007, we opened manufacturing plants in Mexico, Brazil, Malaysia, and Singapore. Having manufacturing facilities closer to our worksites allows us to more efficiently deploy equipment to our field operations, as well as locally source employees and materials;

as our workforce becomes more global, the need for regional training centers increases. To meet the increasing need for technical training, we opened a new training center in Tyumen, Russia during the first quarter of 2007. We have also recently expanded training centers in Malaysia, Egypt, and Mexico; and

part of our growth strategy includes 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;

in January 2007, we acquired Ultraline Services Company, a provider of wireline services in Canada. Prior to this acquisition, we did not have meaningful wireline and perforating operations in Canada;

in May 2007, we acquired the intellectual property, assets, and existing business associated with Vector Magnetics LLC’s active ranging technology for steam-assisted gravity drainage applications;

in July 2007, we acquired PSL Energy Services Limited, an eastern hemisphere provider of process, pipeline, and well intervention services. This acquisition increases our eastern hemisphere production enhancement operations significantly, putting us in a strong position in pipeline processing services both in the eastern hemisphere and globally;

in September 2007, we acquired the intellectual property and substantially all of the assets and existing business of GeoSmith Consulting Group, LLC, a developer of software components for 3-D interpretation and geometric modeling applications; and

in November 2007, we acquired the entire share capital of OOO Burservice, a provider of directional drilling services in Russia.

Contract wins in 2007 are positioning us to grow our international operations over the coming years. Examples include:

a multiservice contract for work in the Tyumen region of Russia. We will be providing drilling fluids, waste management, cementing, drill bits, directional drilling, and logging-while-drilling services;

a contract to provide acidizing, acid fracturing, water control, and nitrogen stimulation services for a customer in the Bay of Campeche, Mexico;

a contract to provide deepwater sand control completion technology in two offshore fields of India;

a contract to provide completion products and services to a group of energy companies for operations throughout Malaysia for a term of five years;

a contract to provide exploration and development testing services in high pressure, high temperature environments in Brazil;

a five-year contract for sand control completions for over 200 wells in offshore China;

a three-year contract to provide a full range of subsurface services, including drilling and formation evaluation, slickline, fluids, cementing services, and production enhancement in Papua New Guinea;

a contract to provide completion products and services in Indonesia; and

a contract to manage the drilling and completion of 58 land wells in the southern region of Mexico.

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 (LOSS):							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

Note 1

–

All periods presented reflect the new segment structure and the reclassification of certain amounts between the segments/regions and “Corporate and other.”

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 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 joint venture and increased testing activity and 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 stimulation activity in Mexico, and increased testing 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) benefit 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 thought not to be fully utilizable.

Income from discontinued operations, net of income tax provision in 2007 primarily consisted of an approximate $933 million net gain recorded on the disposition of KBR.

RESULTS OF OPERATIONS IN 2006 COMPARED TO 2005

REVENUE:							Percentage
Millions of dollars	2006		2005		Increase		Change
Completion and Production	$	7,221	$	5,495	$	1,726		31	%
Drilling and Evaluation		5,734		4,605		1,129		25
Total revenue	$	12,955	$	10,100	$	2,855		28	%

By geographic region:
Completion and Production:
North America	$	4,275	$	3,118	$	1,157	37	%
Latin America		583		542		41	8
Europe/Africa/CIS		1,436		1,123		313	28
Middle East/Asia		927		712		215	30
Total		7,221		5,495		1,726	31
Drilling and Evaluation:
North America		2,183		1,701		482	28
Latin America		931		802		129	16
Europe/Africa/CIS		1,424		1,151		273	24
Middle East/Asia		1,196		951		245	26
Total		5,734		4,605		1,129	25
Total revenue by region:
North America		6,458		4,819		1,639	34
Latin America		1,514		1,344		170	13
Europe/Africa/CIS		2,860		2,274		586	26
Middle East/Asia		2,123		1,663		460	28

OPERATING INCOME (LOSS):							Increase			Percentage
Millions of dollars	2006			2005			(Decrease)			Change
Completion and Production	$	2,140		$	1,524		$	616			40	%
Drilling and Evaluation		1,328			840			488			58
Corporate and other		(223	)		(200	)		(23	)		(12	)
Total operating income	$	3,245		$	2,164		$	1,081			50	%

By geographic region:
Completion and Production:
North America	$	1,476	$	1,046	$	430	41	%
Latin America		130		126		4	3
Europe/Africa/CIS		324		203		121	60
Middle East/Asia		210		149		61	41
Total		2,140		1,524		616	40
Drilling and Evaluation:
North America		595		365		230	63
Latin America		170		77		93	121
Europe/Africa/CIS		263		207		56	27
Middle East/Asia		300		191		109	57
Total		1,328		840		488	58
Total operating income by region
(excluding Corporate and other):
North America		2,071		1,411		660	47
Latin America		300		203		97	48
Europe/Africa/CIS		587		410		177	43
Middle East/Asia		510		340		170	50

Note 1

–

All periods presented reflect the new segment structure and the reclassification of certain amounts between the segments/regions and “Corporate and other.”

The increase in consolidated revenue in 2006 compared to 2005 predominantly resulted from increased activity, higher utilization of our equipment, and increased pricing due to higher exploration and production spending by our customers. Revenue in 2005 was impacted by an estimated $80 million in lost revenue due to Gulf of Mexico hurricanes. International revenue was 55% of consolidated revenue in 2006 and 57% of consolidated revenue in 2005.

The increase in consolidated operating income was primarily due to improved demand due to increased rig activity and improved pricing and asset utilization. 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. Operating income in 2005 was adversely impacted by an estimated $45 million due to Gulf of Mexico hurricanes.

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

Completion and Production increase in revenue compared to 2005 was derived from all regions. Europe/Africa/CIS revenue grew 28% from increased activity from production enhancement services. Completion tools sales benefited from the addition of Easywell to the completion tool portfolio in Europe and cementing services improved due to increased activity in Russia, the North Sea, and Nigeria and improved pricing and sales in Angola. Middle East/Asia revenue grew 30% from the addition of Easywell to the completion tool portfolio in Asia, increased WellDynamics activity in Asia, a new contract in Oman for production enhancement services, and new contract start-ups and product sales of cementing services in Asia. North America revenue improved 37% largely driven by United States onshore operations due to strong demand for stimulation services, coupled with improved equipment utilization and pricing. Production enhancement services North America revenue also grew due to improved pricing and improved equipment utilization in Canada. Latin America revenue increased 8%. International revenue was 45% of total segment revenue in 2006 compared to 48% in 2005.

The Completion and Production segment operating income improvement spanned all regions. Europe/Africa/CIS operating income improved 60%. The 2006 Europe/Africa/CIS segment operating income was positively impacted by a $48 million gain on the sale of lift boats in west Africa and the North Sea. Cementing services results were also favorable as a result of new contracts and increased activity in Europe. Operating income in 2005 included a $17 million favorable insurance settlement related to a pipe fabrication and laying project in the North Sea. Middle East/Asia operating income grew 41% primarily from improved production enhancement services product mix and increased completion tools sales in Asia, which were partially offset by decreased WellDynamics activity. North America operating income increased 41% largely due to an improved production enhancement services product mix and increased cementing services activity in the United States. The segment received hurricane insurance proceeds of $21 million in 2006 and was negatively impacted by an estimated $24 million in 2005 by hurricanes in the Gulf of Mexico. The 2005 segment operating income included a $110 million gain on the sale in 2005 of our equity interest in the Subsea 7, Inc. joint venture. Latin America operating income increased 3% due primarily to increased sand control tools activity in Brazil.

Drilling and Evaluation revenue increase in 2006 compared to 2005 was derived from all four regions in all product service lines. Europe/Africa/CIS revenue improved 24% from new drilling service contracts in Europe. The fluid services revenue comparison was also favorable, primarily due to increased activity in the region. Middle East/Asia revenue grew 26% from new drilling services contracts in Asia and increased drill bits activity in the region. The region also benefited from increased cased hole activity in Asia and new wireline and perforating contracts. Lower sales of logging equipment and the expiration of a fluid services contract in Asia partially offset the Middle East/Asia revenue improvement. North America revenue grew 28% from improved pricing and increased activity in fluid services, wireline and perforating services, and drilling services and increased sales of fixed cutter bits. Latin America revenue grew 16% with increased fluid services operations, improved wireline and perforating pricing, and increased Landmark consulting services and software sales. The completion of two fixed-price integrated solutions projects in southern Mexico partially offset the Latin America revenue improvement. International revenue was 67% of total segment revenue in 2006 compared to 68% in 2005.

Drilling and Evaluation operating income increase compared to 2005 spanned all geographic regions, with the United States as the predominant contributor due to improved pricing and increased rig activity. Europe/Africa/CIS operating income grew 27% from new drilling service contracts in Europe and stronger software and service sales for Landmark in Europe. Middle East/Asia operating income grew 57% from higher wireline and perforating services activity in the region, new drilling services contracts in Asia, and increased fluid services activity in Asia. Latin America operating income more than doubled. Wireline and perforating results contributed to the Latin America increase due to improved product mix. Included in Latin America 2005 results was $23 million in losses on two fixed-priced integrated solutions projects. The segment received hurricane insurance proceeds of $26 million in 2006. Operating income in 2005 included a $24 million gain related to a patent infringement case settlement, while hurricanes in the Gulf of Mexico negatively impacted segment operating income by an estimated $21 million.

Corporate and other expenses were $223 million in 2006 compared to $200 million in 2005. The increase was primarily due to increased legal costs and costs incurred for the separation of KBR from Halliburton. The 2006 segment results included a gain of $10 million from the sale of an investment accounted for under the cost method.

NONOPERATING ITEMS

Interest expense decreased $31 million in 2006 compared to 2005, primarily due to the redemption in April 2005 of $500 million of our floating rate senior notes, the repayment in October 2005 of $300 million of our floating rate senior notes, and the repayment in August 2006 of $275 million of our medium-term notes.

Interest income increased $75 million in 2006 compared to 2005 due to higher cash investment balances.

Other, net increased $15 million in 2006 compared to 2005. The 2005 year included costs related to our accounts receivable securitization facility, which had no outstanding amounts.

(Provision) benefit for income taxes from continuing operations in 2006 of $1 billion resulted in an effective tax rate of 31%. The tax benefit for 2005 resulted from recording favorable adjustments in 2005 totaling $805 million to our valuation allowance against the deferred tax asset related to asbestos and silica liabilities. Our strong 2005 earnings, coupled with an upward revision in our estimate of future domestic taxable income in 2006, drove these adjustments.

Income from discontinued operations, net of income tax provision in 2006 and 2005 primarily consisted of our results of KBR.

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 policies and estimates to be:

forecasting our effective 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;

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 No. 109 (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 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 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 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 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 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 long-term 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.

Legal and investigation matters

As discussed in Note 10 of our consolidated financial statements, as of December 31, 2007, 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 Foreign Corrupt Practices Act (FCPA) investigations and the Barracuda-Caratinga bolts matter. See Note 2 to the consolidated financial statements for further information. FASB Interpretation No. 45 (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 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. Periodically, a determination will be made as to whether any material changes in facts or circumstances have occurred that would impact assumptions used in the third-party valuation.

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 benefits 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. Expected long-term rates of return on plan assets are determined annually and are based on an evaluation of our plan assets, 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 rate utilized in 2007 to determine the projected benefit obligation at the measurement date for our United States non-terminating pension plans ranged from 6.03% to 6.19%, an increase from the 5.75% discount rate that was utilized in 2006. The discount rate utilized to determine the projected benefit obligation at the measurement date for our United Kingdom pension plan, which constitutes 76% of our international plans and 67% of all plans, increased from 5.0% at September 30, 2006 to 5.7% at September 30, 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 Benefit
	Pension Expense			Obligation
Millions of dollars	in 2007			at December 31, 2007
25-basis-point decrease in discount rate	$	3		$	40
25-basis-point increase in discount rate	$	(3	)	$	(38	)

Our defined benefit plans reduced pretax earnings by $48 million in 2007, $45 million in 2006, and $37 million in 2005. Included in the amounts were earnings from our expected pension returns of $47 million in 2007, $37 million in 2006, and $35 million in 2005. Unrecognized actuarial gains and losses were being recognized over a period of one to 24 years, which represented 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 returns were $68 million in 2007, $65 million in 2006, and $83 million in 2005. 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, 2007 was $46 million. On a pretax basis, $3 million of our net actuarial loss at December 31, 2007 will be recognized as a component of our expected 2008 pension expense. During 2007, we made contributions to fund our defined benefit plans of $41 million, which included $16 million contributed to our United Kingdom plan. We expect to make additional contributions in 2008 of approximately $30 million.

The actuarial assumptions used in determining our pension benefits 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.

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 7.3%. At December 31, 2007, allowance for bad debts totaled $49 million or 1.6% of notes and accounts receivable before the allowance, and at December 31, 2006, allowance for bad debts totaled $40 million or 1.5% 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, 2007 would have resulted in a $31 million adjustment to 2007 total operating costs and expenses.

OFF BALANCE SHEET ARRANGEMENTS

At December 31, 2007, 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 on derivative instruments. See Note 14 to the consolidated financial statements for additional disclosures related to financial instruments.

Interest rate risk

We have exposure to interest rate risk from our long-term debt.

The following table represents principal amounts of our long-term debt at December 31, 2007 and related weighted average interest rates on the repaid amounts by year of maturity for our long-term debt.

Millions of dollars	2008			2009			2010			2011			2012			Thereafter			Total
Fixed-rate debt:
Repayment amount ($US)	$	150		$	3		$	753		$	3		$	4		$	1,856		$	2,769
Weighted average
interest rate on
repaid amount		5.6	%		5.6	%		5.5	%		5.5	%		5.5	%		4.7	%		5.0	%
Variable-rate debt:
Repayment amount ($US)	$	9		$	9		$	3		$	–		$	–		$	–		$	21
Weighted average
interest rate on
repaid amount		8.5	%		8.5	%		8.5	%		–			–			–			8.5	%

The fair market value of long-term debt was $4.1 billion as of December 31, 2007. The excess of the fair value of long-term debt over the carrying amount of long-term debt is primarily due to the impact of the increased value of our common stock on our 3.125% convertible senior notes.

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 $72 million as of December 31, 2007 and $39 million as of December 31, 2006. Our total liability related to environmental matters covers numerous properties, including the property in regard to which Dirt, Inc. has brought suit against Bredero-Shaw (a joint venture in which we formerly held a 50% interest that we sold to the other party in the venture, ShawCor Ltd., in 2002), Halliburton Energy Services, Inc., and ShawCor Ltd. See Note 10 to our consolidated financial statements for further information regarding this matter.

We have subsidiaries that have been named as potentially responsible parties along with other third parties for 9 federal and state superfund sites for which we have established a liability. As of December 31, 2007, those 9 sites accounted for approximately $10 million of our total $72 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

Effective January 1, 2007, we adopted FASB Interpretation No. 48 (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 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.

As a result of the adoption of FIN 48, we recognized a decrease of $4 million in other liabilities to account for a decrease in unrecognized tax benefits and an increase of $34 million for accrued interest and penalties, which were accounted for as a net reduction of $30 million to the January 1, 2007 balance of retained earnings. Of the $30 million reduction to retained earnings, $10 million was attributable to KBR, which is now reported as discontinued operations in the consolidated financial statements. See Note 11 to our consolidated financial statements for further information.

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).” SFAS No. 158 requires an employer to:

recognize on its balance sheet the funded status (measured as the difference between the fair value of plan assets and the benefit obligation) of pension and other postretirement benefit plans;

recognize, through comprehensive income, certain changes in the funded status of a defined benefit and postretirement plan in the year in which the changes occur;

measure plan assets and benefit obligations as of the end of the employer’s fiscal year; and

disclose additional information.

The requirements to recognize the funded status of a benefit plan and the additional disclosure requirements were effective for fiscal years ending after December 15, 2006. Accordingly, we adopted SFAS No. 158 for our fiscal year ending December 31, 2006. See Note 15 to our consolidated financial statements for further information.

The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end is effective for fiscal years ending after December 15, 2008. We did not elect early adoption of these additional SFAS No. 158 requirements and will adopt these requirements for our fiscal year ending December 31, 2008.

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 November 2007, the FASB deferred for one year the application of the fair value measurement requirements to nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis. 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 liabilities that are not required or permitted to be measured at fair value on a recurring basis, which we do not expect to have a material impact on our consolidated financial statements.

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 December 2007, the FASB issued Statement No. 141(Revised 2007), “Business Combinations” (SFAS No. 141(R)). SFAS No. 141(R) requires an acquiring entity to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition-date fair value with limited exceptions. SFAS No. 141(R) also changes the accounting treatment for certain specific items. 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 and reporting 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 provision of SFAS No. 160 on January 1, 2009 and have not yet determined the impact on our consolidated financial statements.

In December 2007, the FASB ratified the consensus reached on EITF 07-1, “Accounting for Collaborative Arrangements Related to the Development and Commercialization of Intellectual Property.” EITF 07-1 defines collaborative arrangements and establishes reporting requirements for transactions between participants in a collaborative arrangement and between participants in the arrangement and third parties. EITF 07-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. We will adopt EITF 07-1 on January 1, 2009, which we do not expect 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

The SEC is conducting a formal investigation into whether improper payments were made to government officials in Nigeria through the use of agents or subcontractors 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. The Department of Justice (DOJ) is also conducting a related criminal investigation. The SEC has also issued subpoenas seeking information, which we and KBR are furnishing, regarding current and former agents used in connection with multiple projects, including current and prior projects, over the past 20 years located both in and outside of Nigeria in which the Halliburton energy services business, KBR or affiliates, subsidiaries or joint ventures of Halliburton or KBR, are or were participants. In September 2006 and October 2007, the SEC and the DOJ, respectively, each requested that we enter into an agreement to extend the statute of limitations with respect to its investigation. We anticipate that we will enter into appropriate tolling agreements with the SEC and the DOJ.

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).

The SEC and the DOJ have been reviewing these matters in light of the requirements of the FCPA. In addition to performing our own investigation, we have been cooperating with the SEC and the DOJ investigations and with other investigations in France, Nigeria, and Switzerland regarding the Bonny Island project. The government of Nigeria gave notice in 2004 to the French magistrate of a civil claim as an injured party in the French investigation. We also believe that the Serious Fraud Office in the United Kingdom is conducting an investigation relating to the Bonny Island project. Our Board of Directors has appointed a committee of independent directors to oversee and direct the FCPA investigations.

The matters under investigation relating to the Bonny Island project cover an extended period of time (in some cases significantly before our 1998 acquisition of Dresser Industries and continuing through the current time period). We have produced documents to the SEC and the DOJ from the files of numerous officers and employees of Halliburton and KBR, including current and former executives of Halliburton and KBR, both voluntarily and pursuant to company subpoenas from the SEC and a grand jury, and we are making our employees and we understand KBR is making its employees available to the SEC and the DOJ for interviews. In addition, the SEC has issued a subpoena to A. Jack Stanley, who formerly served as a consultant and chairman of Kellogg Brown & Root LLC, and to others, including certain of our and KBR’s current or former executive officers or employees, and at least one subcontractor of KBR. We further understand that the DOJ has issued subpoenas for the purpose of obtaining information abroad, and we understand that other partners in TSKJ have provided information to the DOJ and the SEC with respect to the investigations, either voluntarily or under subpoenas.

The SEC and DOJ investigations include an examination of whether TSKJ’s engagements of Tri-Star Investments as an agent and a Japanese trading company as a subcontractor to provide services to TSKJ were utilized to make improper payments to Nigerian government officials. In connection with the Bonny Island project, TSKJ entered into a series of agency agreements, including with Tri-Star Investments, of which Jeffrey Tesler is a principal, commencing in 1995 and a series of subcontracts with a Japanese trading company commencing in 1996. We understand that a French magistrate has officially placed Mr. Tesler under investigation for corruption of a foreign public official. In Nigeria, a legislative committee of the National Assembly and the Economic and Financial Crimes Commission, which is organized as part of the executive branch of the government, are also investigating these matters. Our representatives have met with the French magistrate and Nigerian officials. In October 2004, representatives of TSKJ voluntarily testified before the Nigerian legislative committee.

TSKJ suspended the receipt of services from and payments to Tri-Star Investments and the Japanese trading company and has considered instituting legal proceedings to declare all agency agreements with Tri-Star Investments terminated and to recover all amounts previously paid under those agreements. In February 2005, TSKJ notified the Attorney General of Nigeria that TSKJ would not oppose the Attorney General’s efforts to have sums of money held on deposit in accounts of Tri-Star Investments in banks in Switzerland transferred to Nigeria and to have the legal ownership of such sums determined in the Nigerian courts.

As a result of these investigations, information has been uncovered suggesting that, commencing at least 10 years ago, members of TSKJ planned payments to Nigerian officials. We have reason to believe that, based on the ongoing investigations, payments may have been made by agents of TSKJ to Nigerian officials. In addition, information uncovered in the summer of 2006 suggests that, prior to 1998, plans may have been made by employees of The M.W. Kellogg Company (a predecessor of a KBR subsidiary) to make payments to government officials in connection with the pursuit of a number of other projects in countries outside of Nigeria. We are reviewing a number of more recently discovered documents related to KBR’s activities in countries outside of Nigeria with respect to agents for projects after 1998. Certain activities discussed in this paragraph involve current or former employees or persons who were or are consultants to KBR, and our investigation is continuing.

In June 2004, all relationships with Mr. Stanley and another consultant and former employee of M.W. Kellogg Limited were terminated. The terminations occurred because of Code of Business Conduct violations that allegedly involved the receipt of improper personal benefits from Mr. Tesler in connection with TSKJ’s construction of the Bonny Island project.

In 2006 and 2007, KBR suspended the services of other agents in and outside of Nigeria, including one agent who, until such suspension, had worked for KBR outside of Nigeria on several current projects and on numerous older projects going back to the early 1980s. Such suspensions have occurred when possible improper conduct has been discovered or alleged or when Halliburton and KBR have been unable to confirm the agent’s compliance with applicable law and the Code of Business Conduct.

The SEC and DOJ are also investigating and have issued subpoenas concerning TSKJ's use of an immigration services provider, apparently managed by a Nigerian immigration official, to which approximately $1.8 million in payments in excess of costs of visas were allegedly made between approximately 1997 and the termination of the provider in December 2004. We understand that TSKJ terminated the immigration services provider after a KBR employee discovered the issue. We reported this matter to the United States government in 2007. The SEC has issued a subpoena requesting documents among other things concerning any payment of anything of value to Nigerian government officials. In response to such subpoena, we have produced and continue to produce additional documents regarding KBR and Halliburton’s energy services business use of immigration and customs service providers, which may result in further inquiries. Furthermore, as a result of these matters, we have expanded our own investigation to consider any matters raised by energy services activities in Nigeria.

If violations of the FCPA were found, a person or entity found in violation could be subject to fines, civil penalties of up to $500,000 per violation, equitable remedies, including disgorgement (if applicable) generally of profits, including prejudgment interest on such profits, causally connected to the violation, and injunctive relief. Criminal penalties could range up to the greater of $2 million per violation or twice the gross pecuniary gain or loss from the violation, which could be substantially greater than $2 million per violation. It is possible that both the SEC and the DOJ could assert that there have been multiple violations, which could lead to multiple fines. The amount of any fines or monetary penalties that could be assessed would depend on, among other factors, the findings regarding the amount, timing, nature, and scope of any improper payments, whether any such payments were authorized by or made with knowledge of us, KBR or our or KBR’s affiliates, the amount of gross pecuniary gain or loss involved, and the level of cooperation provided the government authorities during the investigations. The government has expressed concern regarding the level of our cooperation. Agreed dispositions of these types of violations also frequently result in an acknowledgement of wrongdoing by the entity and the appointment of a monitor on terms negotiated with the SEC and the DOJ to review and monitor current and future business practices, including the retention of agents, with the goal of assuring compliance with the FCPA.

These investigations could also 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. In addition, we could incur costs and expenses for any monitor required by or agreed to with a governmental authority to review our continued compliance with FCPA law.

As of December 31, 2007, we are unable to estimate an amount of probable loss or a range of possible loss related to these matters as it relates to Halliburton directly. However, we provided indemnification in favor of KBR under the master separation agreement for certain contingent liabilities, including Halliburton’s indemnification of KBR and any of its greater than 50%-owned subsidiaries as of November 20, 2006, the date of the master separation agreement, for fines or other monetary penalties or direct monetary damages, including disgorgement, as a result of a claim made or assessed by a governmental authority in the United States, the United Kingdom, France, Nigeria, Switzerland, and/or Algeria, or a settlement thereof, related to alleged or actual violations occurring prior to November 20, 2006 of the FCPA or particular, analogous applicable foreign statutes, laws, rules, and regulations in connection with investigations pending as of that date, including with respect to the construction and subsequent expansion by TSKJ of a natural gas liquefaction complex and related facilities at Bonny Island in Rivers State, Nigeria. We recorded the estimated fair market value of this indemnity regarding FCPA matters described above upon our separation from KBR. See Note 2 to our consolidated financial statements for additional information.

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.

In consideration of our agreement to indemnify KBR for the liabilities referred to above, KBR has agreed that we will at all times, in our sole discretion, have and maintain control over the investigation, defense and/or settlement of these FCPA matters until such time, if any, that KBR exercises its right to assume control of the investigation, defense and/or settlement of the FCPA matters as it relates to KBR. KBR has also agreed, at our expense, to assist with Halliburton’s full cooperation with any governmental authority in our investigation of these FCPA matters and our investigation, defense and/or settlement of any claim made by a governmental authority or court relating to these FCPA matters, in each case even if KBR assumes control of these FCPA matters as it relates to KBR. If KBR takes control over the investigation, defense, and/or settlement of FCPA matters, refuses a settlement of FCPA matters negotiated by us, enters into a settlement of FCPA matters without our consent, or materially breaches its obligation to cooperate with respect to our investigation, defense, and/or settlement of FCPA matters, we may terminate the indemnity.

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 in lieu thereof, 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. 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 $140 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 has set an evidentiary hearing in April 2008.

Impairment of Oil and Gas Properties

At December 31, 2007, we had interests in oil and gas properties totaling $110 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.

In December 2007, we learned that the drilling program in which we were engaged on one of two prospects in Bangladesh was unsuccessful. Consequently, we recorded a $34 million charge for the write-off of our drilling costs and impairment of the leasehold carrying value. This charge is included in our results of operations for 2007. We expect to know the results of the drilling activity on the second prospect by the end of the first quarter of 2008. Depending on the results, we could incur additional charges.

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 a material and 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 56% of our consolidated revenue during 2007 and 55% of our consolidated revenue during 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.

In addition, investigations by governmental authorities (see “Foreign Corrupt Practices Act investigations” above), as well as legal, social, economic, and political issues in Nigeria, could materially and adversely affect our Nigerian 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, 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 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 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

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. Any prolonged reduction in oil and natural gas prices will depress the immediate levels of exploration, development, and production activity, often reflected as changes in rig counts. Perceptions of longer-term lower oil and natural gas prices by oil and gas companies or longer-term higher material and contractor prices impacting facility costs 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. 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;

economic growth in China and India;

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 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 have a significant impact on the activity levels of our businesses. In the current environment where oil and gas demand exceeds supply, the ability to rebalance supply with demand may be constrained by the global availability of rigs. Full utilization of rigs could lead to limited growth in revenue. In addition, the extent of the growth in oilfield services may be limited by the availability of equipment and manpower.

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.

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;

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. Current market conditions have triggered constraints in the supply chain of certain raw materials, such as sand, cement, and specialty metals. The majority of our risk associated with the current 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. The demand for skilled workers is high, and the supply is limited. 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 our 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, 2007 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, 2007, our internal control over financial reporting is effective.

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, 2007 and 2006, 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, 2007. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

As discussed in Notes 11, 12 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, its method of accounting for stock-based compensation plans as of January 1, 2006, 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, 2007, 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 20, 2008 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 20, 2008

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, 2007, 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, 2007, 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, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2007, and our report dated February 20, 2008 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

February 20, 2008

HALLIBURTON COMPANY

Consolidated Statements of Operations

	Year Ended December 31
Millions of dollars and shares except per share data	2007			2006			2005
Revenue:
Services	$	11,256		$	9,643		$	7,513
Product sales		4,008			3,312			2,587
Total revenue		15,264			12,955			10,100
Operating costs and expenses:
Cost of services		8,167			6,751			5,614
Cost of sales		3,358			2,675			2,129
General and administrative		293			342			294
Gain on sale of business assets, net		(52	)		(58	)		(101	)
Total operating costs and expenses		11,766			9,710			7,936
Operating income		3,498			3,245			2,164
Interest expense		(154	)		(165	)		(196	)
Interest income		124			129			54
Other, net		(8	)		(10	)		(25	)
Income from continuing operations before income
taxes and minority interest		3,460			3,199			1,997
(Provision) benefit for income taxes		(907	)		(1,003	)		125
Minority interest in net income of subsidiaries		(29	)		(19	)		(15	)
Income from continuing operations		2,524			2,177			2,107
Income from discontinued operations, net of income
tax provision of $15, $183, and $205		975			171			251
Net income	$	3,499		$	2,348		$	2,358

Basic income per share:
Income from continuing operations	$	2.76		$	2.15		$	2.09
Income from discontinued operations, net		1.07			0.16			0.25
Net income per share	$	3.83		$	2.31		$	2.34

Diluted income per share:
Income from continuing operations	$	2.66		$	2.07		$	2.03
Income from discontinued operations, net		1.02			0.16			0.24
Net income per share	$	3.68		$	2.23		$	2.27

Basic weighted average common shares outstanding		913			1,014			1,010
Diluted weighted average common shares outstanding		950			1,054			1,038

See notes to consolidated financial statements.

HALLIBURTON COMPANY

Consolidated Balance Sheets

	December 31
Millions of dollars and shares except per share data	2007			2006
Assets
Current assets:
Cash and equivalents	$	1,847		$	2,918
Receivables (less allowance for bad debts of $49 and $40)		3,093			2,629
Inventories		1,459			1,235
Investments in marketable securities		388			20
Current deferred income taxes		376			205
Current assets of discontinued operations		-			3,898
Other current assets		410			285
Total current assets		7,573			11,190
Property, plant, and equipment, net of accumulated depreciation of $4,126 and $3,793		3,630			2,557
Goodwill		790			486
Noncurrent deferred income taxes		348			448
Noncurrent assets of discontinued operations		-			1,497
Other assets		794			682
Total assets	$	13,135		$	16,860
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	768		$	655
Accrued employee compensation and benefits		575			496
Income tax payable		209			146
Deferred revenue		209			171
Current maturities of long-term debt		159			26
Current liabilities of discontinued operations		-			2,831
Other current liabilities		491			409
Total current liabilities		2,411			4,734
Long-term debt		2,627			2,783
Employee compensation and benefits		403			474
Noncurrent liabilities of discontinued operations		-			981
Other liabilities		734			443
Total liabilities		6,175			9,415
Minority interest in consolidated subsidiaries		94			69
Shareholders’ equity:
Common shares, par value $2.50 per share – authorized 2,000 shares, issued 1,063
and 1,060 shares		2,657			2,650
Paid-in capital in excess of par value		1,741			1,689
Accumulated other comprehensive loss		(104	)		(437	)
Retained earnings		8,202			5,051
		12,496			8,953
Less 183 and 62 shares of treasury stock, at cost		5,630			1,577
Total shareholders’ equity		6,866			7,376
Total liabilities and shareholders’ equity	$	13,135		$	16,860

See notes to consolidated financial statements.

HALLIBURTON COMPANY

Consolidated Statements of Shareholders’ Equity

Millions of dollars and shares	2007			2006			2005
Balance at January 1	$	7,376		$	6,372		$	3,932
Dividends and other transactions with shareholders		(1,499	)		(1,324	)		202
Sale of stock by a subsidiary		–			117			–
Adoption of Statement of Financial Accounting
Standards No. 158		–			(218	)		–
Adoption of Financial Accounting Standards Board
Interpretation No. 48		(30	)		–			–
Shares exchanged in KBR, Inc. exchange offer		(2,809	)		–			–
Other		(4	)		34			–

Comprehensive income:
Net income		3,499			2,348			2,358
Net cumulative translation adjustments		(23	)		34			(41	)
Defined benefit and other postretirement plans adjustments		355			2			(54	)
Net unrealized gains (losses) on investments
and derivatives		1			11			(25	)
Total comprehensive income		3,832			2,395			2,238

Balance at December 31	$	6,866		$	7,376		$	6,372

See notes to consolidated financial statements.

HALLIBURTON COMPANY

Consolidated Statements of Cash Flows

	Year Ended December 31
Millions of dollars	2007			2006			2005
Cash flows from operating activities:
Net income	$	3,499		$	2,348		$	2,358
Adjustments to reconcile net income to net cash from operations:
Income from discontinued operations		(975	)		(171	)		(251	)
Depreciation, depletion, and amortization		583			480			448
Provision (benefit) for deferred income taxes		(111	)		658			(243	)
Gain on sale of business assets		(52	)		(66	)		(102	)
Asbestos and silica liability payment related to Chapter 11 filing		–			–			(2,345	)
Collection of asbestos- and silica-related insurance receivables		29			167			1,032
Other changes:
Receivables		(355	)		(494	)		(314	)
Accounts receivable facilities transactions		–			–			(256	)
Inventories		(218	)		(309	)		(151	)
Accounts payable		77			96			102
Contributions to pension plans		(41	)		(75	)		(39	)
Other		259			712			252
Cash flows from discontinued operations		31			311			210
Total cash flows from operating activities		2,726			3,657			701
Cash flows from investing activities:
Sales of property, plant, and equipment		203			152			106
Dispositions of business assets, net of cash disposed		70			98			212
Investments – restricted cash		56			–			1
Sales (purchases) of short-term investments in marketable securities, net		(332	)		(20	)		891
Acquisitions of business assets, net of cash acquired		(563	)		(27	)		(108	)
Disposal of KBR, Inc. cash upon separation		(1,461	)		–			–
Capital expenditures		(1,583	)		(834	)		(575	)
Other investing activities		(38	)		(20	)		(36	)
Cash flows from discontinued operations		(13	)		225			19
Total cash flows from investing activities		(3,661	)		(426	)		510
Cash flows from financing activities:
Proceeds from exercises of stock options		110			159			342
Tax benefit from exercise of options and restricted stock		29			53			–
Borrowings (repayments) of short-term debt, net		9			(13	)		8
Proceeds from long-term debt, net of offering costs		–			–			23
Payments on long-term debt		(7	)		(324	)		(802	)
Payments of dividends to shareholders		(314	)		(306	)		(254	)
Payments to reacquire common stock		(1,374	)		(1,339	)		(12	)
Other financing activities		(5	)		5			(1	)
Cash flows from discontinued operations		(18	)		485			(24	)
Total cash flows from financing activities		(1,570	)		(1,280	)		(720	)
Effect of exchange rate changes on cash, including $0, $50, and $(3) related to
discontinued operations		(27	)		37			(17	)
Increase (decrease) in cash and equivalents		(2,532	)		1,988			474
Cash and equivalents at beginning of year, including $1,461, $390, and $188
related to discontinued operations		4,379			2,391			1,917
Cash and equivalents at end of year, including $0, $1,461, and $390 related
to discontinued operations	$	1,847		$	4,379		$	2,391
Supplemental disclosure of cash flow information:
Cash payments during the year for:
Interest from continuing operations	$	144		$	164		$	193
Income taxes from continuing operations	$	941		$	289		$	203

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.

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 reclassified as discontinued operations in the consolidated financial statements. See Note 2 for additional information. All prior 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 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, and collectibility is reasonably assured. 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 long-term 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 expenses are charged to income as incurred. Research and development expenses were $301 million in 2007, $254 million in 2006, and $218 million in 2005, of which over 97% was company-sponsored in each year.

Software development costs

Costs of developing software for sale are charged to expense as research and development when incurred until technological feasibility has been established for the product. Once technological feasibility is established, software development costs are capitalized until the software is ready for general release to customers. We capitalized costs related to software developed for resale of $23 million in 2007 and $21 million in both 2006 and 2005. Amortization expense of software development costs was $17 million for 2007, $21 million for 2006, and $22 million for 2005. Once the software is ready for release, amortization of software development costs begins. Capitalized software development costs are amortized over periods not exceeding five years.

Cash equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents, except for cash equivalents of KBR, which are reflected as current assets of discontinued operations at December 31, 2006.

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.

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.

Goodwill

The reported amounts of goodwill for each reporting unit are reviewed for impairment on an annual basis 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. Our annual impairment tests resulted in no goodwill impairment in 2007, 2006, or 2005.

Evaluating impairment of long-lived assets

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

Income taxes

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

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, interest 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; gains or losses on interest rate derivatives are included in interest expense; 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 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 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 No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123(R)), 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. Prior to January 1, 2006, we accounted for these plans under the recognition and measurement provisions of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Under APB No. 25, no compensation expense was recognized for stock options or the ESPP. Compensation expense was recognized for restricted stock awards. As a result of adopting SFAS No. 123(R), the incremental pretax expense related to employee stock option awards and our ESPP totaled approximately $33 million in 2006 or $0.02 per diluted share after tax on continuing operations. The incremental impact to net income related to employee stock option awards and our ESPP in 2006 totaled approximately $26 million.

Total stock-based compensation expense for continuing operations, net of related tax effects, was $62 million in 2007 and $49 million in 2006. Total income tax benefit recognized in continuing operations for stock-based compensation arrangements was $35 million in 2007, $27 million in 2006, and $13 million in 2005. Total incremental compensation cost resulting from modifications of previously granted stock-based awards was $18 million in 2007, $10 million in 2006, and $12 million in 2005. These modifications allowed certain employees to retain their awards after leaving the company.

The following table summarizes the pro forma effect on net income and income per share for 2005 as if we had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation.

	Year ended
Millions of dollars except per share data	December 31, 2005
Net income, as reported	$	2,358
Add:
Stock-based compensation expense included in
continuing operations, net of related tax effects		23
Stock-based compensation expense included in
discontinued operations, net of related tax effects		8
Less:
Stock-based compensation expense for continuing
operations determined under fair-value-based
method for all awards, net of related tax effects		(46	)
Stock-based compensation expense for discontinued
operations determined under fair-value-based
method for all awards, net of related tax effects		(15	)
Net income, pro forma	$	2,328

Basic income per share:
Continuing operations
As reported	$	2.09
Pro forma	$	2.07
Discontinued operations
As reported	$	0.25
Pro forma	$	0.24

Diluted income per share:
Continuing operations
As reported	$	2.03
Pro forma	$	2.01
Discontinued operations
As reported	$	0.24
Pro forma	$	0.24

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 in 2007 and 2006 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 volatility of options granted in 2005 was based upon the historical volatility of our common stock. The expected term of options granted in 2007, 2006, and 2005 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
	2007			2006			2005
Expected term (in years)		5.14			5.24			5.00
Expected volatility		35.70	%		42.20	%		51.06 – 52.79	%
Expected dividend yield		0.89 – 1.14	%		0.76 – 1.06	%		0.73 – 1.16	%
Risk-free interest rate		3.37 – 5.00	%		4.30 – 5.03	%		3.77 – 4.33	%
Weighted average grant-date fair value per share	$	11.35		$	14.20		$	11.42

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
	2007			2006			2005
Expected term (in years)		0.5			0.5			0.5
Expected volatility		29.49	%		37.77	%		30.46	%
Expected dividend yield		1.03	%		0.80	%		0.73	%
Risk-free interest rate		4.98	%		5.29	%		3.89	%
Weighted average grant-date fair value per share	$	7.97		$	9.32		$	5.50

	Offering period January 1 through June 30
	2007			2006			2005
Expected term (in years)		0.5			0.5			0.5
Expected volatility		34.91	%		35.65	%		26.93	%
Expected dividend yield		1.00	%		0.75	%		1.16	%
Risk-free interest rate		5.09	%		4.38	%		3.15	%
Weighted average grant-date fair value per share	$	7.20		$	7.91		$	4.15

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.

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		2005
Revenue	$	2,250		$	9,621	$	10,141
Operating income	$	62		$	239	$	453
Net income	$	23	(a)	$	180	$	250

(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 Halliburton’s responsibility for liabilities unrelated to KBR’s business. Halliburton provides indemnification in favor of KBR under the master separation agreement for certain contingent liabilities, including Halliburton’s 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 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. See Note 10 for further discussion of these matters.

As a result of these agreements, 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. The estimated fair value of these indemnities and guarantees is primarily included in “Other liabilities” on the consolidated balance sheet at December 31, 2007.

Additionally, Halliburton provides 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 thereunder; (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 Halliburton for these guarantees. Halliburton has also provided a limited indemnity, with respect to FCPA governmental and third-party claims, to the lender parties under KBR’s revolving credit agreement expiring in December 2010. KBR has agreed to indemnify Halliburton, other than for the FCPA and Barracuda-Caratinga bolts matter, if Halliburton is 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.

The tax sharing agreement provides for allocations of United States and certain other jurisdiction tax liabilities between us and KBR. Under the transition services agreements, we continue to provide various interim corporate support services to KBR, and KBR continues to provide various interim corporate support services to us. The fees are determined on a basis generally intended to approximate the fully allocated direct and indirect costs of providing the services, without any profit. Under an employee matters agreement, Halliburton and KBR have allocated liabilities and responsibilities related to current and former employees and their participation in certain benefit plans. Among other items, the employee matters agreement provided for the conversion, which occurred upon completion of the separation of KBR, of stock options and restricted stock awards (with restrictions that had not yet lapsed as of the final separation date) granted to KBR employees under our 1993 Stock and Incentive Plan (1993 Plan) to options and restricted stock awards covering KBR common stock. As of April 5, 2007, these awards consisted of 1.2 million options with a weighted average exercise price per share of $15.01 and approximately 600,000 restricted shares with a weighted average grant-date fair value per share of $17.95 under our 1993 Plan.

Note 3. Acquisitions and Dispositions

PSL Energy Services Limited

Dresser, Ltd. interest

Ultraline Services Corporation

Subsea 7, Inc.

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 now 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.” The two KBR segments have been reclassified 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 precise well-bore placement solutions that enable customers to model, measure, and optimize their well construction activities. This segment consists of Baroid Fluid Services, Sperry Drilling Services, Security DBS Drill Bits, wireline and perforating services, Landmark, and project management.

Landmark 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.

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 on 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	2007			2006			2005
Revenue:
Completion and Production	$	8,386		$	7,221		$	5,495
Drilling and Evaluation		6,878			5,734			4,605
Total	$	15,264		$	12,955		$	10,100
Operating income (loss):
Completion and Production	$	2,199		$	2,140		$	1,524
Drilling and Evaluation		1,485			1,328			840
Corporate and other		(186	)		(223	)		(200	)
Total	$	3,498		$	3,245		$	2,164
Capital expenditures:
Completion and Production	$	791		$	441		$	309
Drilling and Evaluation		759			390			266
Corporate and other		33			3			–
Total	$	1,583		$	834		$	575
Depreciation, depletion, and amortization:
Completion and Production	$	288		$	239		$	217
Drilling and Evaluation		295			241			231
Total	$	583		$	480		$	448

	December 31
Millions of dollars	2007		2006
Total assets:
Completion and Production	$	4,842	$	3,636
Drilling and Evaluation		4,606		3,566
Shared assets		672		1,216
Corporate and other		3,015		3,047
Discontinued operations		–		5,395
Total	$	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	2007		2006		2005
Revenue:
United States	$	6,673	$	5,869	$	4,317
Other countries		8,591		7,086		5,783
Total	$	15,264	$	12,955	$	10,100

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

Note 5. Receivables

Our trade receivables are generally not collateralized. At December 31, 2007, 35% of our gross trade receivables were from customers in the United States. As of December 31, 2006, 39% 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 $71 million at December 31, 2007 and $58 million at December 31, 2006. If the average cost method had been used, total inventories would have been $25 million higher than reported at December 31, 2007 and $20 million higher than reported at December 31, 2006. The cost of the remaining inventory was recorded on the average cost method. Inventories consisted of the following:

	December 31
Millions of dollars	2007		2006
Finished products and parts	$	1,042	$	883
Raw materials and supplies		325		256
Work in process		92		96
Total	$	1,459	$	1,235

Finished products and parts are reported net of obsolescence reserves of $65 million at December 31, 2007 and $63 million at December 31, 2006.

Note 7. Investments

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, 2006, our investments in marketable securities were $20 million.

Restricted cash

At December 31, 2007, we had restricted cash of $52 million, which primarily consisted of collateral for potential future insurance claim reimbursements, included in “Other assets.” At December 31, 2006, we had restricted cash of $108 million in “Other assets,” which primarily consisted of similar items. The $56 million decrease in restricted cash primarily reflects the release, due to the separation of KBR, of collateral related to potential insurance claim reimbursements.

Note 8. Property, Plant, and Equipment

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

	December 31
Millions of dollars	2007		2006
Land	$	46	$	37
Buildings and property improvements		869		782
Machinery, equipment, and other		6,841		5,531
Total		7,756		6,350
Less accumulated depreciation		4,126		3,793
Net property, plant, and equipment	$	3,630	$	2,557

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
	2007			2006
1 – 10 years		17	%		18	%
11 – 20 years		50	%		49	%
21 – 30 years		13	%		14	%
31 – 40 years		20	%		19	%

	Machinery, Equipment,
	and Other
	2007			2006
1 – 5 years		22	%		26	%
6 – 10 years		72	%		68	%
11 – 20 years		6	%		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	2007		2006
3.125% convertible senior notes due July 2023	$	1,200	$	1,200
5.5% senior notes due October 2010		749		749
7.6% debentures due August 2096		294		294
8.75% debentures due February 2021		185		185
Medium-term notes due 2008 through 2027		299		299
Other		59		82
Total long-term debt		2,786		2,809
Less current portion		159		26
Noncurrent portion of long-term debt	$	2,627	$	2,783

Convertible notes

In June 2003, we issued $1.2 billion of 3.125% convertible senior notes due July 15, 2023, with interest payable semiannually. The notes are our senior unsecured obligations ranking equally with all of our existing and future senior unsecured indebtedness.

The notes are convertible under any of the following circumstances:

during any calendar quarter if the last reported sale price of our common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous quarter is greater than or equal to 120% of the conversion price per share of our common stock on such last trading day;

if the notes have been called for redemption;

upon the occurrence of specified corporate transactions that are described in the indenture governing the notes; or

during any period in which the credit ratings assigned to the notes by both Moody’s Investors Service and Standard & Poor’s are lower than Ba1 and BB+, respectively, or the notes are no longer rated by at least one of these rating services or their successors.

The conversion price is $18.825 per share and is subject to adjustment upon the occurrence of stock dividends in common stock, the issuance of rights or warrants, stock splits and combinations, the distribution of indebtedness, securities, or assets, or excess cash distributions. The stock conversion rate for the notes changed as a result of our July 2006 stock split and periodic increases to our quarterly dividend. The maximum stock conversion rate is 87.6424 shares of common stock per $1,000 principal amount of notes. As of December 31, 2007, the stock conversion rate was 53.3383 shares of common stock per $1,000 principal amount of notes.

Subsequent to issuing the notes, we agreed upon conversion to settle the principal amount of the notes in cash. For any amounts in excess of the aggregate principal amount we have the right to deliver shares of our common stock, cash, or a combination of cash and common stock. See Note 13 for discussion of the impact on diluted earnings per share.

The notes are redeemable for cash at our option on or after July 15, 2008. Holders may require us to repurchase the notes for cash on July 15 of 2008, 2013, or 2018 or, prior to July 15, 2008, in the event of a fundamental change as defined in the underlying indenture.

Other senior debt

We have issued various senior notes, medium-term notes, and debentures, all of which rank equally with our existing and future senior unsecured indebtedness. Our senior notes with an aggregate principal amount of $750 million will mature in October 2010 and bear interest at a rate equal to 5.5%, payable semiannually. They 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. The senior notes were initially offered on a discounted basis at 99.679% of their face value. The discount is being amortized to interest expense over the life of the notes.

We have outstanding notes under our medium-term note program, including $150 million that will mature in December 2008 and bear interest at a rate equal to 5.63%, payable semiannually. They 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 15 basis points. In addition, we have notes issued under the medium-term note program with a principal amount of $45 million that mature in May 2017 and notes with a principal amount of $104 million that mature in February 2027, which bear interest rates equal to 7.53% and 6.75%, respectively, payable semiannually. The 7.53% and 6.75% notes may not be redeemed prior to maturity. The medium-term notes do not have sinking fund requirements.

We have outstanding debentures with an aggregate principal amount of $185 million that will mature in February 2021 and bear interest at a rate equal to 8.75%, payable semiannually. In addition, we have outstanding debentures with an aggregate principal amount of $294 million that will mature in August 2096 and bear interest at a rate equal to 7.6%, payable semiannually. The debentures may not be redeemed prior to maturity and do not have sinking fund requirements.

Revolving credit facilities

On July 9, 2007, we entered into a new unsecured $1.2 billion five-year revolving credit facility that replaced our then existing unsecured $1.2 billion five-year revolving credit facility with generally similar terms and conditions except that the new facility does not contain any financial covenants. The purpose of the facility is to provide commercial paper support, general working capital, and credit for other corporate purposes. There were no cash drawings under the revolving credit facility as of December 31, 2007.

Maturities

Our debt matures as follows: $159 million in 2008; $12 million in 2009; $755 million in 2010; $3 million in 2011; $3 million in 2012; and $1.9 billion thereafter.

Note 10. Commitments and Contingencies

Foreign Corrupt Practices Act investigations

The Securities and Exchange Commission (SEC) is conducting a formal investigation into whether improper payments were made to government officials in Nigeria through the use of agents or subcontractors 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. The Department of Justice (DOJ) is also conducting a related criminal investigation. The SEC has also issued subpoenas seeking information, which we and KBR are furnishing, regarding current and former agents used in connection with multiple projects, including current and prior projects, over the past 20 years located both in and outside of Nigeria in which the Halliburton energy services business, KBR or affiliates, subsidiaries or joint ventures of Halliburton or KBR, are or were participants. In September 2006 and October 2007, the SEC and the DOJ, respectively, each requested that we enter into an agreement to extend the statute of limitations with respect to its investigation. We anticipate that we will enter into appropriate tolling agreements with the SEC and the DOJ.

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 in lieu thereof, 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. 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 early May 2003, we entered into a written memorandum of understanding setting forth the terms upon which the Moore class action would be settled. 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 (the “Dresser claims”). The memorandum of understanding contemplated settlement of the Dresser claims as well as the original claims.

In June 2004, the court entered an order preliminarily approving the settlement. Following the transfer of the case to another district judge, the court held that evidence of the settlement’s fairness was inadequate, denied the motion for final approval of the settlement, and ordered the parties to mediate. The mediation was unsuccessful.

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 CEO. The court ordered that the case proceed against our CEO and Halliburton. In response to a motion by the lead plaintiff, on February 26, 2007, the court ordered the removal and replacement of their co-lead counsel. In June 2007, upon becoming aware of a United States Supreme Court opinion issued in that month, the court allowed further briefing on the motion to dismiss filed on behalf of our CEO. That briefing is complete, but the court has not yet ruled. In September 2007, AMSF filed a motion for class certification, and our response was filed in November 2007. The case is set for trial in July 2009.

As of December 31, 2007, 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, 2007, we had not recorded any liability associated with these indemnifications.

M-I, LLC antitrust litigation

On February 16, 2007, we were informed that M-I, LLC, a competitor of ours in the drilling fluids market, had sued us for allegedly attempting to monopolize the market for invert emulsion drilling fluids used in deep water and/or in cold water temperatures. The claims M-I, LLC asserted are based upon its allegation that the patent issued for our Accolade® drilling fluid was invalid as a result of its allegedly having been procured by fraud on the United States Patent and Trademark Office and that our subsequent prosecution of an infringement action against M-I, LLC amounted to predatory conduct in violation of Section 2 of the Sherman Antitrust Act. In October 2006, a federal court dismissed our infringement action based upon its holding that the claims in our patent were indefinite and the patent was, therefore, invalid. That judgment was affirmed by the appellate court in January 2008. M-I, LLC also alleges that we falsely advertised our Accolade® drilling fluid in violation of the Lanham Act and California law and that our earlier infringement action amounted to malicious prosecution in violation of Texas state law. M-I, LLC seeks compensatory damages, which it claims should be trebled, as well as punitive damages and injunctive relief. We believe that M-I, LLC’s claims are without merit and intend to aggressively defend them. The case is set for trial in September 2008.

As of December 31, 2007, we had not accrued any amounts in connection with 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.

Dirt, Inc. litigation

In April 2005, Dirt, Inc. brought suit in Alabama against Bredero-Shaw (a joint venture in which we formerly held a 50% interest that we sold to the other party in the venture, ShawCor Ltd., in 2002), Halliburton Energy Services, Inc., and ShawCor Ltd., claiming that Bredero-Shaw disposed of hazardous waste in a construction materials landfill owned and operated by Dirt, Inc. Bredero-Shaw has offered to take responsibility for cleanup of the site. The plaintiff did not accept that offer, and the method and cost of such cleanup are disputed, with expert opinions ranging from $6 million to $144 million. On November 1, 2007, the trial court in the above-referenced matter entered a judgment in the total amount of $108 million, of which Halliburton Energy Services, Inc. could be responsible for as much as 50%. We are pursuing an appeal and believe that it is probable that the Alabama Supreme Court will reverse the trial court’s judgment because, among other things:

the trial court misapplied the law on the measure of damages;

Halliburton Energy Services, Inc., as a shareholder, should not have liability for actions of the venture; and

the statute of limitations had run on an issue submitted to the jury.

We have accrued an amount less than $10 million, which represents our 50% portion of what we believe it will cost to remediate the site.

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.

In addition to the federal laws and regulations, states and other countries where we do business often have numerous environmental, legal, and regulatory requirements by which we must abide. We evaluate and address the environmental impact of our operations by assessing and remediating contaminated properties in order to avoid future liabilities and comply with environmental, legal, and regulatory requirements. 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. Our accrued liabilities for environmental matters were $72 million as of December 31, 2007 and $39 million as of December 31, 2006. Our total liability related to environmental matters covers numerous properties, including the property in regard to which Dirt, Inc. has brought suit against Bredero-Shaw (a joint venture in which we formerly held a 50% interest that we sold to the other party in the venture, ShawCor Ltd., in 2002), Halliburton Energy Services, Inc., and ShawCor Ltd. See “Dirt, Inc. litigation” in this note for further information regarding this matter.

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, 2007, including $1.1 billion 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 $487 million in 2007, $402 million in 2006, and $338 million in 2005.

Future total rentals on noncancelable operating leases are as follows: $180 million in 2008; $131 million in 2009; $104 million in 2010; $74 million in 2011; $40 million in 2012; and $172 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	2007			2006			2005
Current income taxes:
Federal	$	(560	)	$	(156	)	$	22
Foreign		(449	)		(122	)		(116	)
State		(38	)		(11	)		(1	)
Total current		(1,047	)		(289	)		(95	)
Deferred income taxes:
Federal		129			(600	)		291
Foreign		7			(95	)		(14	)
State		4			(19	)		(57	)
Total deferred		140			(714	)		220
(Provision) benefit for income taxes	$	(907	)	$	(1,003	)	$	125

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	2007		2006		2005
United States	$	2,219	$	2,280	$	1,399
Foreign		1,241		919		598
Total	$	3,460	$	3,199	$	1,997

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
	2007			2006			2005
United States statutory rate		35.0	%		35.0	%		35.0	%
Impact of foreign income taxed at different rates		(2.3	)		(1.3	)		0.3
Other impact of foreign operations		(3.9	)		3.1			(2.0	)
Valuation allowance		(2.0	)		(3.3	)		(40.3	)
State income taxes, net of federal income tax benefit		0.3			0.7			1.1
Adjustments of prior year taxes		(0.3	)		(2.1	)		0.4
Other items, net		(0.6	)		(0.7	)		(0.8	)
Total effective tax rate on continuing operations		26.2	%		31.4	%		(6.3	)%

The major component of the difference between the 2007 statutory rate compared to the effective rate is the favorable impact of the ability to recognize United States foreign tax credits of approximately $205 million. This amount consists 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. 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. The major component of the difference between the 2005 statutory tax rate compared to the effective tax rate is the release of a valuation allowance for future tax attributes related to United States net operating losses established in prior years. The remaining valuation allowance on future tax attributes related to United States net operating loss was released in 2006. The primary components of our deferred tax assets and liabilities and the related valuation allowances were as follows:

	December 31
Millions of dollars	2007		2006
Gross deferred tax assets:
Employee compensation and benefits	$	262	$	289
Capitalized research and experimentation		94		65
Accrued liabilities		80		64
Foreign tax credit carryforward		61		68
Inventory		63		62
Insurance accruals		46		45
Software revenue recognition		37		57
Net operating loss carryforwards		24		29
Alternative minimum tax credit carryforward		19		66
Other		176		90
Total gross deferred tax assets		862		835
Gross deferred tax liabilities:
Depreciation and amortization		164		135
Joint ventures, partnerships, and unconsolidated affiliates		34		2
Other		55		20
Total gross deferred tax liabilities		253		157
Valuation allowances:
Net operating loss carryforwards		22		29
Foreign tax credit carryforwards		–		68
Other		7		–
Total valuation allowances		29		97
Net deferred income tax asset	$	580	$	581

At December 31, 2007, we had a total of $58 million of foreign net operating loss carryforwards, of which $31 million will expire from 2008 through 2020 and $27 million will not expire due to indefinite expiration dates. At December 31, 2007, we had $27 million of domestic net operating loss carryforwards that will expire from 2021 through 2023 related to a consolidated joint venture. During 2005, our existing deferred tax asset related to asbestos and silica liabilities became a United States net operating loss due to the tax deduction of the related costs in 2005. As a result, a domestic net operating loss carryforward of $2.1 billion was created and was fully utilized in 2006. At December 31, 2007, we had United States foreign tax credit carryforwards of $61 million that are expected to expire in 2016. The federal alternative minimum tax credit carryforwards are available to reduce future United States federal income taxes on an indefinite basis.

We established a valuation allowance on certain domestic and foreign operating loss carryforwards on the basis that we believe these assets will not be utilized in the statutory carryover period.

Effective January 1, 2007, we adopted Financial Accounting Standards Board (FASB) Interpretation No. 48 (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 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 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
Settlements with taxing authorities		(30	)		(1	)
Lapse of statute of limitations		(3	)		–
Balance at December 31, 2007	$	388		$	37

At December 31, 2007, $99 million of tax benefits associated with United States foreign tax credits was included in the balance of unrecognized tax benefits that could be resolved within the next 12 months. A review of foreign tax documentation is currently underway and will likely be significantly progressed within the next 12 months. Also, as of 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, 2007, we estimated that $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 2005. An unrecognized tax benefit of $6 million related to the 2000 through 2002 tax years could be resolved within the next 12 months.

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

Asbestos

Other

Common

of Par

Trust

Treasury

Deferred

Retained

Comprehensive

Millions of dollars

Value

Stock

Compensation

Earnings

Income

Balance at December 31, 2004

2,292

(869

)

2,335

(477

)

(74

)

871

(146

)

Cash dividends paid

–

(254

)

–

Stock plans

258

–

115

(24

)

–

Common shares purchased

–

(12

)

–

Tax benefit from exercise of options

and restricted stock

–

Total dividends and other transactions

with shareholders

333

–

103

(24

)

(254

)

–

Asbestos trust shares

298

2,037

(2,335

)

–

Comprehensive income (loss):

Net income

–

2,358

–

Other comprehensive income:

Cumulative translation

adjustment

–

(48

)

Realization of translation losses

included in net income

–

Defined benefit and other

postretirement plans

adjustments, net of tax

benefit of $23

–

(54

)

Net unrealized losses on

investments and derivatives,

net of tax benefit of $7

–

(12

)

Realization of gains on

investments and derivatives,

net of tax provision of $8

–

(13

)

Total comprehensive income

–

2,358

(120

)

Balance at December 31, 2005

2,634

1,501

–

(374

)

(98

)

2,975

(266

)

Cash dividends paid

–

(306

)

–

Stock plans

116

–

136

–

Common shares purchased

–

(1,339

)

–

Tax benefit from exercise of options

and restricted stock

–

Total dividends and other transactions

with shareholders

169

–

(1,203

)

–

(306

)

–

Sale of stock by a subsidiary

–

117

–

Reclassification of deferred

compensation

–

(98

)

–

Adoption of SFAS No. 158, net of tax

benefit of $146

–

(218

)

Other

–

Comprehensive income (loss):

Net income

–

2,348

–

Other comprehensive income:

Cumulative translation adjustment

–

Realization of translation gains

included in net income

–

(14

)

Defined benefit and other

postretirement plans

adjustments, net of tax benefit

of $16

–

Net unrealized gains on

investments and derivatives, net

of tax benefit of $7

–

Realization of gains on

investments and derivatives,

net of tax provision of $0

–

)

Total comprehensive income

–

2,348

Balance at December 31, 2006

2,650

1,689

–

(1,577

)

–

5,051

(437

)

Paid-in

Capital in

Accumulated

Excess

Asbestos

Other

Common

of Par

Trust

Treasury

Deferred

Retained

Comprehensive

Millions of dollars

Value

Stock

Compensation

Earnings

Income

Balance at December 31, 2006

2,650

1,689

–

(1,577

)

–

5,051

(437

)

Cash dividends paid

–

(314

)

–

Stock plans

–

130

–

Common shares purchased

–

(1,374

)

–

Tax benefit from exercise of options

and restricted stock

–

Total dividends and other transactions

with shareholders

–

(1,244

)

–

(314

)

–

Shares exchanged in KBR, Inc.

exchange offer

–

(2,809

)

–

Adoption of FIN 48

–

(30

)

–

Other

–

)

–

Comprehensive income (loss):

Net income

–

3,499

–

Other comprehensive income:

Cumulative translation

adjustment

–

Realization of translation gains

included in net income

–

(24

)

Defined benefit and other

postretirement plans

adjustments:

Prior service cost:

Plan amendment

–

)

Settlements/curtailments

–

Actuarial gain (loss):

Net gain

–

105

Amortization of net loss

–

Settlements/curtailments

–

Tax effect on defined benefit

and postretirement plans

–

(45

)

KBR, Inc. separation

–

271

Defined benefit and other

postretirement plans, net

–

355

Net unrealized gains on

investments, net of tax

benefit of $0

–

Total comprehensive income

–

3,499

333

Balance at December 31, 2007

2,657

1,741

–

(5,630

)

–

8,202

(104

)

Accumulated other comprehensive loss	December 31
Millions of dollars	2007			2006			2005
Cumulative translation adjustment	$	(61	)	$	(38	)	$	(72	)
Defined benefit and other postretirement liability adjustments		(45	)		(400	)		(184	)
Unrealized gains (losses) on investments and derivatives		2			1			(10	)
Total accumulated other comprehensive loss	$	(104	)	$	(437	)	$	(266	)

Shares of common stock	December 31
Millions of shares	2007			2006			2005
Issued		1,063			1,060			1,054
In treasury		(183	)		(62	)		(26	)
Total shares of common stock outstanding		880			998			1,028

In May 2006, the shareholders increased the number of authorized shares of common stock to two billion. Also in May 2006, our Board of Directors finalized the terms of a two-for-one common stock split, effected in the form of a stock dividend. As a result, the split was effected in the form of a stock dividend paid on July 14, 2006 to shareholders of record on June 23, 2006. The effect on the balance sheet was to reduce “Paid-in capital in excess of par value” by $1.3 billion and to increase “Common shares” by $1.3 billion. All prior period common stock and applicable share and per share amounts were retroactively adjusted to reflect the split.

In February 2006, our Board of Directors approved a share repurchase program up to $1.0 billion, which replaced our previous share repurchase program. In September 2006, our Board of Directors approved an increase to our existing common share repurchase program of up to an additional $2.0 billion. In July 2007, our Board of Directors approved an additional increase to our existing common share repurchase program of up to $2.0 billion, bringing the entire authorization to $5.0 billion. This additional authorization may be used for open market share purchases or to settle the conversion premium on our 3.125% convertible senior notes, should they be redeemed. The stock repurchase 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 through December 31, 2007, we have repurchased approximately 79 million shares of our common stock for approximately $2.7 billion at an average price per share of $33.91. These numbers include the repurchases of approximately 39 million shares of our common stock for approximately $1.4 billion at an average price per share of $34.93 during 2007. As of December 31, 2007, $2.3 billion remained available under our share repurchase authorization.

Preferred Stock

Our preferred stock consists of five million total authorized shares at December 31, 2007, of which none were 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, 2007, approximately 18 million shares were available for future grants under the 1993 Plan, of which approximately 10 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 2007, and includes exercised, forfeited, and expired shares from our acquired companies’ stock plans.

				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, 2007		17.6		$	18.55
Granted		1.9			32.13
Exercised		(3.6	)		17.30
Forfeited/expired		(0.4	)		25.37
Converted to KBR, Inc. stock
options		(1.2	)		15.01
Outstanding at December 31, 2007		14.3		$	20.81		5.72	$	244

Exercisable at December 31, 2007		10.5		$	16.94		4.64	$	219

The total intrinsic value of options exercised was $68 million in 2007, $123 million in 2006, and $194 million in 2005. As of December 31, 2007, there was $32 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 1.7 years.

Cash received from option exercises was $110 million during 2007, $159 million during 2006, and $342 million during 2005. The tax benefit realized from the exercise of stock options was $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 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, 2007, 115,200 shares had been issued to non-employee directors under this plan. There were 8,800 shares, 8,000 shares, and 6,400 shares of restricted stock awarded under the Directors Plan in 2007, 2006, and 2005. In addition, during 2007, our non-employee directors were awarded 22,642 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 2007.

				Weighted Average
	Number of Shares			Grant-Date Fair
Restricted Stock	(in millions)			Value per Share
Nonvested shares at January 1, 2007		7.9		$	22.50
Granted		2.8			32.24
Vested		(2.3	)		21.16
Forfeited		(0.5	)		21.93
Converted to KBR, Inc. restricted stock		(0.6	)		17.95
Nonvested shares at December 31, 2007		7.3		$	27.16

The weighted average grant-date fair value of shares granted during 2006 was $34.39 and during 2005 was $24.28. The total fair value of shares vested during 2007 was $79 million, during 2006 was $64 million, and during 2005 was $49 million. As of December 31, 2007, there was $153 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 4.1 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, 2007, 13.3 million shares have been sold through the ESPP.

Note 13. Income per Share

Basic income 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 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 per share calculation is as follows:

Millions of shares	2007		2006		2005
Basic weighted average common shares outstanding		913		1,014		1,010
Dilutive effect of:
Convertible senior notes premium		29		29		16
Stock options		6		9		10
Restricted stock		2		2		2
Diluted weighted average common shares outstanding		950		1,054		1,038

In December 2004, we entered into a supplemental indenture that requires 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 2007, 2006, and 2005.

Excluded from the computation of diluted income per share were options to purchase three million shares of common stock that were outstanding in 2007 and two million shares of common stock that were outstanding in both 2006 and 2005. 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 forward contracts and option contracts were $272 million at December 31, 2007 and $358 million at December 31, 2006. 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 both December 31, 2007 and December 31, 2006.

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 material outstanding debt instruments have fixed interest rates. As of December 31, 2007 and 2006, we held no material interest rate derivative instruments.

Fair market value of financial instruments. The estimated fair market value of long-term debt was $4.1 billion at December 31, 2007 and $3.7 billion at December 31, 2006, as compared to the carrying amount of $2.8 billion at both December 31, 2007 and December 31, 2006. 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 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 $162 million in 2007, $138 million in 2006, and $115 million in 2005;

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, 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. The 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, for these plans the computed accumulated postretirement benefit obligation amount is not affected by the expected future health care cost inflation rate.

recognize on its balance sheet the funded status (measured as the difference between the fair value of plan assets and the benefit obligation) of pension and other postretirement benefit plans;

recognize, through comprehensive income, certain changes in the funded status of a defined benefit and postretirement plan in the year in which the changes occur;

measure plan assets and benefit obligations as of the end of the employer’s fiscal year; and

disclose additional information.

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 obligation for retirement plans for continuing operations. We use a September 30 measurement date for our international plans and an October 31 measurement date for our domestic plans.

	Pension Benefits												Other
	United						United						Postretirement
Benefit obligation	States			Int’l			States			Int’l			Benefits
Millions of dollars	2007						2006						2007			2006
Change in benefit obligation
Benefit obligation at beginning of period	$	127		$	814		$	127		$	680		$	155		$	158
Service cost		–			26			–			23			1			1
Interest cost		7			44			7			37			8			9
Plan participants’ contributions		–			4			–			4			5			7
Plan amendments		–			2			–			–			(4	)		–
Settlements/curtailments		–			(16	)		–			–			–			–
Currency fluctuations		–			38			–			39			–			–
Actuarial (gain) loss		(9	)		(22	)		–			47			(50	)		(6	)
Transfers		–			1			–			–			–			–
Benefits paid		(15	)		(17	)		(7	)		(16	)		(11	)		(14	)
Benefit obligation at end of period	$	110		$	874		$	127		$	814		$	104		$	155
Accumulated benefit obligation at end of period	$	110		$	678		$	127		$	654		$	–		$	–

	Pension Benefits												Other
	United						United						Postretirement
	States			Int’l			States			Int’l			Benefits
Millions of dollars	2007						2006						2007			2006
Change in plan assets
Fair value of plan assets at beginning of period	$	105		$	622		$	95		$	480		$	–		$	–
Actual return on plan assets		15			53			13			52			–			–
Employer contributions		2			39			4			71			7			7
Settlements		–			(9	)		–			–			–			–
Plan participants’ contributions		–			4			–			4			4			7
Currency fluctuations		–			32			–			31			–			–
Benefits paid		(15	)		(17	)		(7	)		(16	)		(11	)		(14	)
Fair value of plan assets at end of period	$	107		$	724		$	105		$	622		$	–		$	–

Funded status	$	(3	)	$	(150	)	$	(22	)	$	(192	)	$	(104	)	$	(155	)
Employer contribution		–			5			–			4			1			1
Net amount recognized	$	(3	)	$	(145	)	$	(22	)	$	(188	)	$	(103	)	$	(154	)

	Pension Benefits												Other
	United						United						Postretirement
	States			Int’l			States			Int’l			Benefits
Millions of dollars	2007						2006						2007			2006
Amounts recognized on the
consolidated balance sheet
Other assets	$	2		$	9		$	–		$	2		$	–		$	–
Accrued employee compensation
and benefits		(1	)		(11	)		–			(9	)		(10	)		(13	)
Employee compensation and benefits		(4	)		(143	)		(22	)		(181	)		(93	)		(141	)
Pension plans in which accumulated
benefit obligation exceeded plan
assets at December 31
Projected benefit obligation	$	20		$	104		$	127		$	110		$	–		$	–
Accumulated benefit obligation		20			65			127			72			–			–
Fair value of plan assets		15			7			105			15			–			–
Weighted-average assumptions used
to determine benefit obligations
at measurement date
Discount rate		4.61-6.19	%		2.50-8.75	%		5.75	%		2.25-8.75	%		5.77-5.81	%		5.5	%
Rate of compensation increase		4.5	%		2.0-10.0	%		4.5	%		2.0-10.0	%		N/A			N/A
Asset allocation at December 31
Asset categoryTarget allocation 2008
Equity securities 50%-70%		64	%		57	%		63	%		57	%		N/A			N/A
Debt securities 30%-50%		35	%		32	%		36	%		35	%		N/A			N/A
Other 0%-5%		1	%		11	%		1	%		8	%		N/A			N/A
Total 100%		100	%		100	%		100	%		100	%		N/A			N/A

Assumed health care cost trend rates at December 31	2007			2006			2005
Health care cost trend rate assumed for next year		9.0	%		10.0	%		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	2015			2011			2008

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 the Nigerian, Indian, and Indonesian 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. For our United Kingdom pension plan, which constitutes 76% of our international pension plans’ projected benefit obligation, the discount rate increased from 5.0% at September 30, 2006 to 5.7% at September 30, 2007.

The overall expected long-term rate of return on assets was determined based upon an evaluation of our plan assets, 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 loss were as follows:

	Pension Benefits								Other
	United				United				Postretirement
	States		Int’l		States		Int’l		Benefits
Millions of dollars	2007				2006				2007			2006
Net actuarial (gain) loss	$	13	$	72	$	29	$	106	$	(39	)	$	(7	)
Prior service cost (benefit)		–		2		–		2		(3	)		(1	)
Total recognized in accumulated other
comprehensive loss	$	13	$	74	$	29	$	108	$	(42	)	$	(8	)

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 $29 million to our international pension plans in 2008. For our domestic plans, we expect our contributions to be no more than $1 million in 2008. We do not have a required minimum contribution for our domestic plans; however, we 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
2008	$	11	$	22	$	10	$	1
2009		7		18		11		1
2010		7		20		11		1
2011		8		22		11		1
2012		8		25		12		1
Years 2013 – 2017		37		181		54		5

Net periodic cost

	Pension Benefits																		Other
	United						United						United						Postretirement
	States			Int’l			States			Int’l			States			Int’l			Benefits
Millions of dollars	2007						2006						2005						2007			2006			2005
Components of net
periodic benefit cost
Service cost	$	–		$	26		$	–		$	23		$	–		$	22		$	1		$	1		$	1
Interest cost		7			45			7			37			7			34			8			9			10
Expected return on plan assets		(7	)		(40	)		(7	)		(30	)		(7	)		(28	)		–			–			–
Amortization of prior service
cost		–			–			–			–			–			–			–			–			(1	)
Settlements/curtailments		2			–			–			1			–			1			–			–			–
Recognized actuarial loss		6			9			6			8			4			4			–			–			–
Net periodic benefit cost	$	8		$	40		$	6		$	39		$	4		$	33		$	9		$	10		$	10

Weighted-average
assumptions used to
determine net periodic
benefit cost for years
ended December 31
Discount rate		5.75	%		2.25-8.75	%		5.75	%		2.25-8.0	%		5.75	%		2.5-8.0	%		5.5	%		5.75	%		5.75	%
Expected return on plan assets		8.25	%		4.0-9.0	%		8.25	%		4.0-7.0	%		8.5	%		5.0-7.0	%		N/A			N/A			N/A
Rate of compensation increase		4.5	%		2.0-10.0	%		4.5	%		2.0-5.0	%		4.5	%		2.0-5.0	%		N/A			N/A			N/A

Estimated amounts that will be amortized from accumulated other comprehensive loss, net of tax, into net periodic benefit cost in 2008 are as follows:

	Pension Benefits				Other Postretirement
Millions of dollars	United States		International		Benefits
Actuarial (gain) loss	$	2	$	4	$	(3	)
Prior service (benefit) cost		–		–		–
Total	$	2	$	4	$	(3	)

The majority of our postretirement benefit plans are not subjected to risk associated with fluctuations in the medical trend rates because the company subsidy is capped. However, for one plan in which the company subsidy is not capped, the assumed health care cost trend rates could have an impact on the amounts reported for the total of such health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	One-Percentage-Point
Millions of dollars	Increase		(Decrease)
Effect on total of service and interest cost components	$	-	$	–
Effect on the postretirement benefit obligation	$	4	$	(3	)

Note 16. Related Companies

We conduct some of our operations through joint ventures that are in partnership, corporate, and other business forms and are principally accounted for using the equity method. Financial information pertaining to related companies for our continuing operations is set out in the following tables. This information includes the total related-company balances and not our proportional interest in those balances.

Combined summarized financial information for all jointly owned operations that are accounted for under the equity method was as follows:

Combined operating results	Year Ended December 31
Millions of dollars	2007		2006		2005
Revenue	$	500	$	435	$	487
Operating income	$	111	$	108	$	100
Net income	$	100	$	122	$	89

Combined financial position	December 31
Millions of dollars	2007		2006
Current assets	$	276	$	195
Noncurrent assets		210		105
Total	$	486	$	300
Current liabilities	$	116	$	73
Noncurrent liabilities		62		31
Shareholders’ equity		308		196
Total	$	486	$	300

Note 17. 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	2007			2006			2005			2004			2003
Total revenue	$	15,264		$	12,955		$	10,100		$	7,998		$	6,995
Total operating income	$	3,498		$	3,245		$	2,164		$	1,179		$	756
Nonoperating expense, net		(38	)		(46	)		(167	)		(189	)		(117	)
Income from continuing operations before
income taxes and minority interest		3,460			3,199			1,997			990			639
(Provision) benefit for income taxes		(907	)		(1,003	)		125			(322	)		(200	)
Minority interest in net (income) loss of
consolidated subsidiaries		(29	)		(19	)		(15	)		3			(14	)
Income from continuing operations	$	2,524		$	2,177		$	2,107		$	671		$	425
Income (loss) from discontinued operations	$	975		$	171		$	251		$	(1,650	)	$	(1,237	)
Net income (loss)	$	3,499		$	2,348		$	2,358		$	(979	)	$	(820	)
Basic income (loss) per share:
Continuing operations	$	2.76		$	2.15		$	2.09		$	0.77		$	0.49
Net income (loss)		3.83			2.31			2.34			(1.12	)		(0.95	)
Diluted income (loss) per share:
Continuing operations		2.66			2.07			2.03			0.76			0.49
Net income (loss)		3.68			2.23			2.27			(1.11	)		(0.94	)
Cash dividends per share		0.35			0.30			0.25			0.25			0.25
Return on average shareholders’ equity		49.14	%		34.16	%		45.76	%		(30.22	)%		(26.86	)%
Financial position:
Net working capital	$	5,162		$	6,456		$	4,959		$	2,898		$	1,355
Total assets		13,135			16,860			15,073			15,883			15,556
Property, plant, and equipment, net		3,630			2,557			2,203			2,075			2,085
Long-term debt (including current maturities)		2,786			2,809			3,139			3,879			3,361
Shareholders’ equity		6,866			7,376			6,372			3,932			2,547
Total capitalization		9,663			10,187			9,525			7,818			5,922
Basic weighted average common shares
outstanding		913			1,014			1,010			874			868
Diluted weighted average common shares
outstanding		950			1,054			1,038			882			874
Other financial data:
Capital expenditures	$	1,583		$	834		$	575		$	498		$	453
Long-term borrowings (repayments), net		(7	)		(324	)		(779	)		493			1,960
Depreciation, depletion, and
amortization expense		583			480			448			456			468
Payroll and employee benefits		4,585			3,853			3,211			2,823			2,561
Number of employees		51,000			45,000			39,000			36,000			35,000

(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
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
2006
Revenue	$	2,938	$	3,116	$	3,392	$	3,509	$	12,955
Operating income		692		760		870		923		3,245
Income from continuing operations		449		498		603		627		2,177
Income from discontinued operations		39		93		8		31		171
Net income		488		591		611		658		2,348
Earnings per share:
Basic income per share:
Income from continuing operations		0.44		0.49		0.60		0.63		2.15
Income from discontinued operations		0.04		0.09		0.01		0.03		0.16
Net income		0.48		0.58		0.61		0.66		2.31
Diluted income per share:
Income from continuing operations		0.42		0.47		0.57		0.61		2.07
Income from discontinued operations		0.04		0.08		0.01		0.03		0.16
Net income		0.46		0.55		0.58		0.64		2.23
Cash dividends paid per share		0.075		0.075		0.075		0.075		0.30
Common stock prices (2)
High		41.19		41.99		37.93		34.30		41.99
Low		31.35		33.92		27.35		26.33		26.33

(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 2008 Annual Meeting of Stockholders (File No. 001-03492), under the caption “Election of Directors.” 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 2008 Annual Meeting of Stockholders (File No. 001-03492), 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 2008 Annual Meeting of Stockholders (File No. 001-03492), under the caption “Corporate Governance.”

Audit Committee financial experts

In the business judgment of the Board of Directors, all five members of the Audit Committee, Kathleen M. Bader, Alan M. Bennett, Robert L. Crandall, J. Landis Martin, 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 2008 Annual Meeting of Stockholders (File No. 001-03492) under the captions “Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table,” “Grants of Plan-Based Awards in Fiscal 2007,” “Outstanding Equity Awards at Fiscal Year End 2007,” “2007 Option Exercises and Stock Vested,” “2007 Nonqualified Deferred Compensation,” “Pension Benefits Table,” “Employment Contracts and Change-in-Control Arrangements,” “Post-Termination Payments,” “Equity Compensation Plan Information,” and “2007 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 2008 Annual Meeting of Stockholders (File No. 001-03492) 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 2008 Annual Meeting of Stockholders (File No. 001-03492) 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 2008 Annual Meeting of Stockholders (File No. 001-03492) under the caption “Certain Relationships and Related Transactions” to the extent any disclosure is required.

Item 14. Principal Accounting Fees and Services.

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2008 Annual Meeting of Stockholders (File No. 001-03492) 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 46 and 47 and pages 48 through 85 of this annual report. See index on page (i).

2.	Financial Statement Schedules:	Page No.

	Report on supplemental schedule of KPMG LLP	97

	Schedule II – Valuation and qualifying accounts for the three
	years ended December 31, 2007	98

Note: All schedules not filed with this report required by Regulation S-X have been omitted 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. 001-03492).

3.2

By-laws of Halliburton revised effective October 19, 2006 (incorporated by reference to Exhibit 3.1 to Halliburton’s Form 8-K filed October 19, 2006, File No. 001-03492).

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. 001-03492).

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. 001-03492).

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. 001-03492).

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. 001-03492).

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. 001-03492).

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. 001-03492).

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. 001-03492).

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. 001-03492).

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. 001-03492).

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, 2007, 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. 001-03492).

4.12

Form of debt security of 5.63% Notes due December 1, 2008 (incorporated by reference to Exhibit 4.1 to Halliburton’s Form 8-K dated as of November 24, 1998, File No. 001-03492).

4.13

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).

4.14

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. 001-03492).

4.15

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. 001-03492).

4.16

Indenture dated as of June 30, 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 June 30, 2003, File No. 001-03492).

4.17

Form of note of 3.125% Convertible Senior Notes due July 15, 2023 (included as Exhibit A to Exhibit 4.16 above).

4.18

First Supplemental Indenture dated as of December 17, 2004 between Halliburton and The Bank of New York Trust Company, N.A. (as successor to JPMorgan Chase Bank), as Trustee, to Indenture dated as of June 30, 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 8-K filed on December 21, 2004, File No. 001-03492).

4.19

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. 001-03492).

4.20

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. 001-03492).

4.21

Form of note of 5.5% senior notes due October 15, 2010 (included as Exhibit B to Exhibit 4.20 above).

4.22

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. 001-03492).

4.23

Form of note of 7.6% debentures due 2096 (included as Exhibit A to Exhibit 4.22 above).

4.24

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. 001-03492).

4.25

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. 001-03492).

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. 001-03492).

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. 001-03492).

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. 001-03492).

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. 001-03492).

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

Supplemental Executive Retirement Plan of Dresser Industries, Inc., as amended and restated effective January 1, 1998 (incorporated by reference to Exhibit 10.9 to Dresser’s Form 10-K for the year ended October 31, 1997, File No. 1-4003).

10.8

Amendment No. 1 to the Supplemental Executive Retirement Plan of Dresser Industries, Inc. (incorporated by reference to Exhibit 10.1 to Dresser’s Form 10-Q for the quarter ended April 30, 1998, File No. 1-4003).

10.9

Dresser Industries, Inc. 1992 Stock Compensation Plan (incorporated by reference to Exhibit A to Dresser’s Proxy Statement dated February 7, 1992, File No. 1-4003).

10.10

Amendments No. 1 and 2 to Dresser Industries, Inc. 1992 Stock Compensation Plan (incorporated by reference to Exhibit A to Dresser’s Proxy Statement dated February 6, 1995, File No. 1-4003).

10.11

Amendment No. 3 to the Dresser Industries, Inc. 1992 Stock Compensation Plan (incorporated by reference to Exhibit 10.25 to Dresser’s Form 10-K for the year ended October 31, 1997, File No. 1-4003).

10.12

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. 001-03492).

10.13

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. 001-03492).

10.14

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. 001-03492).

10.15

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. 001-03492).

10.16

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. 001-03492).

10.17

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. 001-03492).

10.18

Employment Agreement (David R. Smith) (incorporated by reference to Exhibit 10.39 to Halliburton’s Form 10-K for the year ended December 31, 2002, File No. 001-03492).

10.19

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. 001-03492).

10.20

Employment Agreement (Andrew R. Lane) (incorporated by reference to Exhibit 10.3 to Halliburton’s Form 10-Q for the quarter ended September 30, 2004, File No. 001-03492).

10.21

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. 001-03492).

10.22

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. 001-33146).

10.23

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. 001-03492).

10.24

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. 001-03492).

10.25

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. 001-03492).

10.26

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. 001-03492).

10.27

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. 001-03492).

10.28

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. 001-03492).

10.29

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. 001-03492).

10.30

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. 001-03492).

10.31

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. 001-03492).

10.32

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. 001-03492).

10.33

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. 001-03492).

10.34

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. 001-03492).

10.35

Resignation, General Release and Settlement Agreement (Andrew R. Lane).

10.36

Employment Agreement (James S. Brown).

10.37

Employment Agreement (David S. King).

Statement of Computation of Ratio of Earnings to Fixed Charges.

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. 001-03492):

Alan M. Bennett

James R. Boyd

Milton Carroll

Robert L. Crandall

Kenneth T. Derr

S. Malcolm Gillis

W. R. Howell

J. Landis Martin

Jay A. Precourt

Debra L. Reed

24.2

Power of attorney for Kathleen M. Bader signed in February 2008.

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.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ON SUPPLEMENTAL SCHEDULE

The Board of Directors and Shareholders

Halliburton Company:

Under date of February 20, 2008, we reported on the consolidated balance sheets of Halliburton Company and subsidiaries as of December 31, 2007 and 2006, 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, 2007, 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, accounting for stock-based compensation plans as of January 1, 2006, and accounting for defined benefit and other postretirement plans as of December 31, 2006.

/s/ KPMG LLP

Houston, Texas

February 20, 2008

HALLIBURTON COMPANY

Schedule II - Valuation and Qualifying Accounts

(Millions of Dollars)

The table below presents valuation and qualifying accounts for continuing operations.

	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, 2005:	$	90	$	(36	) (a)	$	(16	) (b)	$	38
Year ended December 31, 2006:		38		6			(4	)		40
Year ended December 31, 2007:		40		10			(1	)		49

(a) Amount represents releases of excess reserves.

(b) Includes the write-off of allowance for doubtful accounts related to asbestos receivables.

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 22nd day of February, 2008.


	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 22nd day of February, 2008.

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

Signature	Title

* Kathleen M. Bader	Director
Kathleen M. Bader

* Alan M. Bennett	Director
Alan M. Bennett

* James R. Boyd	Director
James R. Boyd

* Milton Carroll	Director
Milton Carroll

* Robert L. Crandall	Director
Robert L. Crandall

* Kenneth T. Derr	Director
Kenneth T. Derr

* S. Malcolm Gillis	Director
S. Malcolm Gillis

* W. R. Howell	Director
W. R. Howell

* 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

100