Halliburton 10K 2005 Annual report

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, 2005

[ ] 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 1-3492

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. [ ]

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

Large accelerated filer X

Accelerated filer

Non-accelerated filer

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No X

The aggregate market value of Common Stock held by nonaffiliates on June 30, 2005, determined using the per share closing price on the New York Stock Exchange Composite tape of $47.82 on that date was approximately $21,322,000,000.

As of February 15, 2006, there were 516,240,651 shares of Halliburton Company Common Stock, $2.50 par value per share, outstanding.

Portions of the Halliburton Company Proxy Statement for our 2006 Annual Meeting of Stockholders (File No. 1-3492) are incorporated by reference into Part III of this report.

HALLIBURTON COMPANY

Index to Form 10-K

For the Year Ended December 31, 2005

PART I		PAGE
Item 1.	Business	1
Item 1(a).	Risk Factors	7
Item 1(b).	Unresolved Staff Comments	7
Item 2.	Properties	8
Item 3.	Legal Proceedings	9
Item 4.	Submission of Matters to a Vote of Security Holders	9
EXECUTIVE OFFICERS OF THE REGISTRANT		10
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters
	and Issuer Purchases of Equity Securities	12
Item 6.	Selected Financial Data	12
Item 7.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	12
Item 7(a).	Quantitative and Qualitative Disclosures About Market Risk	12
Item 8.	Financial Statements and Supplementary Data	13
Item 9.	Changes In and Disagreements with Accountants on Accounting and
	Financial Disclosure	13
Item 9(a).	Controls and Procedures	13
Item 9(b).	Other Information	13
MD&A AND FINANCIAL STATEMENTS
Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
Management’s Report on Internal Control Over Financial Reporting		61
Reports of Independent Registered Public Accounting Firm		62
Consolidated Statements of Operations		64
Consolidated Balance Sheets		65
Consolidated Statements of Shareholders’ Equity		66
Consolidated Statements of Cash Flows		67
Notes to Consolidated Financial Statements		68
Selected Financial Data (Unaudited)		114
Quarterly Data and Market Price Information (Unaudited)		115
PART III
Item 10.	Directors and Executive Officers of the Registrant	116
Item 11.	Executive Compensation	116
Item 12(a).	Security Ownership of Certain Beneficial Owners	116
Item 12(b).	Security Ownership of Management	116
Item 12(c).	Changes in Control	116
Item 12(d).	Securities Authorized for Issuance Under Equity Compensation Plans	116
Item 13.	Certain Relationships and Related Transactions	116
Item 14.	Principal Accounting Fees and Services	116
PART IV
Item 15.	Exhibits and Financial Statement Schedules	117
SIGNATURES		126

(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, products, maintenance, engineering, and construction to energy, industrial, and governmental customers.

Our six business segments are organized around how we manage the business: Production Optimization, Fluid Systems, Drilling and Formation Evaluation, Digital and Consulting Solutions, Government and Infrastructure, and Energy and Chemicals. We refer to the combination of Production Optimization, Fluid Systems, Drilling and Formation Evaluation, and Digital and Consulting Solutions segments as our Energy Services Group (ESG) and to the Government and Infrastructure and Energy and Chemicals segments as KBR. 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 through our six business segments. The following summarizes our services and products for each business segment.

ENERGY SERVICES GROUP

The ESG provides a wide range of services and products to customers for the exploration, development, and production of oil and gas. The ESG serves major, national, and independent oil and gas companies throughout the world.

Production Optimization

Our Production Optimization segment primarily tests, measures, and provides means to manage and/or improve well production once a well is drilled and, in some cases, after it has been producing. This segment consists of production enhancement services and completion tools and services.

Production enhancement services include stimulation services, pipeline process services, sand control services, coiled tubing tools and services, and hydraulic workover services. Stimulation services optimize oil and gas reservoir production through a variety of pressure pumping services and chemical processes, commonly known as 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.

Completion tools and services include subsurface safety valves and flow control equipment, surface safety systems, packers and specialty completion equipment, intelligent completion systems, production automation, expandable liner hanger systems, sand control systems, slickline equipment and services, self-elevated workover platforms, tubing-conveyed perforating services and products, well servicing tools, and reservoir performance services. Reservoir performance services include drill stem and other well testing tools and services, underbalanced applications and real-time reservoir analysis, data acquisition services, and production applications.

Also included in this segment is WellDynamics, an intelligent well completions joint venture, which we consolidate for accounting purposes. Additionally, subsea operations conducted by Subsea 7, Inc., of which we formerly owned 50%, were included in this segment. We accounted for our 50% ownership of Subsea 7, Inc. using the equity method until January 2005, when we completed the sale of our interest in this joint venture to our partner, Siem Offshore (formerly DSND Subsea ASA).

Fluid Systems

Our Fluid Systems segment focuses on providing services and technologies to assist in the drilling and construction of oil and gas wells. This segment offers cementing and drilling fluids systems.

Cementing is the process used to bond the well and well casing while isolating fluid zones and maximizing wellbore stability. Cement and chemical additives are pumped to fill the space between the casing and the side of the wellbore. Our cementing service line also provides casing services and equipment.

Baroid Fluid Services provides drilling fluid systems, performance additives, solids control, and waste management services for oil and gas drilling, completion, and workover operations. In addition, Baroid Fluid Services sells products to a wide variety of industrial customers. Drilling fluids usually contain bentonite or barite in a water or oil base. Drilling fluids primarily improve wellbore stability and facilitate the transportation of cuttings from the bottom of a wellbore to the surface. Drilling fluids also help cool the drill bit, seal porous well formations, and assist in pressure control within a wellbore. Drilling fluids are often customized by onsite engineers for optimum stability and enhanced oil production.

Also included in this segment is our investment in Enventure, an expandable casing joint venture, which we account for using the cost method.

Drilling and Formation Evaluation

Our Drilling and Formation Evaluation segment is primarily involved in the drilling and formation evaluation process during bore-hole construction. Major services and products offered include:

drilling systems and services;

drill bits; and

logging services.

Sperry Drilling Services provides drilling systems and services. These services include directional and horizontal drilling, measurement-while-drilling, logging-while-drilling, multilateral systems, 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, and related downhole tools used in drilling oil and gas wells. In addition, coring services and equipment are provided to acquire cores of the formation drilled for evaluation.

Logging services include open-hole wireline services, which provide information on formation evaluation such as resistivity, porosity, and density, rock mechanics, and fluid sampling. Cased-hole services are also offered, which provide cement bond evaluation, reservoir monitoring, pipe evaluation, pipe recovery, and perforating.

Digital and Consulting Solutions

Our Digital and Consulting Solutions segment provides integrated exploration, drilling, and production software information systems, consulting services, real-time operations, and other integrated solutions.

Landmark is a supplier of integrated exploration, drilling, and production software information systems as well as professional and data management services for the upstream oil and gas industry. Landmark software transforms vast quantities of seismic, well log, and other data into detailed computer models of petroleum reservoirs. The models are used by our customers to achieve optimal business and technical decisions in exploration, development, and production activities. Data management services provide efficient storage, browsing, and retrieval of large volumes of exploration and petroleum data. The services and products offered by Landmark integrate data workflows and operational processes across disciplines, including geophysics, geology, drilling, engineering, production, economics, finance, corporate planning, and key partners and suppliers.

This segment also provides value-added 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.

Additionally, this segment holds investments in upstream oil and gas properties, primarily in the North America region, which leverage our technology, knowledge, and access to services and products.

KBR

KBR provides a wide range of services to energy, chemical, and industrial customers and government entities worldwide through two business segments, Government and Infrastructure and Energy and Chemicals.

Government and Infrastructure

Our Government and Infrastructure segment focuses on:

construction, maintenance, and logistics services for government operations, facilities, and installations;

civil engineering, construction, consulting, and project management services for state and local government agencies and private industries;

integrated security solutions, including threat definition assessments, mitigation, and consequence management; design, engineering and program management; construction and delivery; and physical security, operations, and maintenance;

dockyard operation and management through the Devonport Royal Dockyard Limited (DML), which is consolidated for financial reporting purposes, with services that include design, construction, surface/subsurface fleet maintenance, nuclear engineering and refueling, and weapons engineering; and

privately financed initiatives, in which KBR funds the development or provision of an asset, such as a facility, service, or infrastructure for a government client, which we then own, operate and maintain, enabling our clients to utilize new assets at a reasonable cost.

Also included in this segment is our investment in the Alice Springs-Darwin Railroad (ASD). ASD is a privately financed project that was formed in 2001 to build and operate the transcontinental railroad from Alice Springs to Darwin, Australia. ASD has been granted a 50-year concession period by the Australian government. KBR provided engineering, procurement, and construction services for ASD and is the largest equity holder in the project with a 36.7% interest, with the remaining equity held by eleven other participants. We account for this investment under the equity method.

Energy and Chemicals

Our Energy and Chemicals segment is a global engineering, procurement, construction, technology, and services provider for the energy and chemicals industries. Working both upstream and downstream in support of our customers, the Energy and Chemicals segment offers the following:

downstream engineering and construction capabilities, including global engineering execution centers, as well as engineering, construction, and program management of liquefied natural gas (LNG), gas-to-liquids (GTL), ammonia, petrochemicals, crude oil refineries, and natural gas plants;

upstream deepwater engineering, marine technology, and project management;

production services provides plant operations, maintenance, and start-up services for upstream oil and gas facilities worldwide;

in the United States, industrial services provides maintenance services to the petrochemical, forest product, power, and commercial markets;

industry-leading licensed technologies in the areas of fertilizers and synthesis gas, olefins, refining, and chemicals and polymers; and

consulting services in the form of expert technical and management advice that include studies, conceptual and detailed engineering, project management, construction supervision and design, and construction verification or certification in both upstream and downstream markets.

Included in this segment are a number of joint ventures including the following:

TSKJ is a joint venture company formed to design and construct large scale projects in Nigeria. TSKJ’s members are Technip, SA of France, Snamprogetti Netherlands B.V., which is an affiliate of ENI SpA of Italy, JGC Corporation of Japan, and KBR, each of which owns 25%. TSKJ has completed five LNG production facilities on Bonny Island, Nigeria and is currently working on a sixth such facility. We account for this investment under the equity method; and

M. W. Kellogg Limited (MWKL) is a London-based joint venture that provides full engineering, procurement, and construction contractor services for LNG, GTL, and onshore oil and gas projects. MWKL is owned 55% by KBR and 45% by JGC Corporation. We consolidate MWKL for financial reporting purposes.

Business strategy

Our business strategy is to maintain global leadership in providing energy services and products and engineering and construction services. Our ability to be a global leader depends on meeting four key goals:

establishing and maintaining technological leadership;

achieving and continuing operational excellence;

creating and continuing innovative business relationships; and

preserving a dynamic workforce.

We also plan to initiate the separation of KBR from Halliburton in 2006. Our decision to separate KBR arose primarily because we do not believe the full value of KBR is currently reflected in Halliburton’s stock price, and few synergies exist between the two business units. Our current plan is to effect an initial public offering (IPO) of less than 20% of KBR. We believe the IPO market is attractive, and valuation multiples of publicly traded engineering and construction companies are currently favorable. In response to interest we have received, we may consider selling some pieces of KBR, but this is not expected to change our IPO plans for the remainder of KBR. We expect that a Form S-1 for KBR will be filed with the United States Securities and Exchange Commission (SEC) after the 2005 audited financial statements of KBR are complete. Any sale of KBR stock would be registered under the Securities Act of 1933, and such shares of common stock would only be offered and sold by means of a prospectus. This annual report does not constitute an offer to sell or the solicitation of any offer to buy any securities of KBR, and there will not be any sale of any such securities in any state in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of such state.

Markets and competition

We are one of the world’s largest diversified energy services and engineering and construction 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;

product quality;

warranty; and

technical proficiency.

We conduct business worldwide in about 100 countries. In 2005, based on the location of services provided and products sold, 27% of our consolidated revenue was from the United States, 24% of our consolidated revenue was from Iraq, primarily related to our work for the United States Government, and 10% of our consolidated revenue was from the United Kingdom. In 2004, 26% of our consolidated revenue was from Iraq and 22% of our consolidated revenue was from the United States. In 2003, 27% of our consolidated revenue was from the United States and 15% of our consolidated revenue was from Iraq. 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, and exchange control and currency problems. Except for our government services work in Iraq discussed above, 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 17 to the consolidated financial statements.

Customers

Our revenue during the past three years was mainly derived from the sale of services and products to the energy industry, including 61% in 2005, 54% in 2004, and 66% in 2003. Revenue from the United States Government, resulting primarily from work performed in the Middle East by our Government and Infrastructure segment, represented 31% of our 2005 consolidated revenue, 39% of our 2004 consolidated revenue, and 26% of our 2003 consolidated revenue. No other customer represented more than 10% of consolidated revenue in any period presented.

Backlog

Backlog represents the total dollar amount of revenue we expect to realize in the future as a result of performing work under contracts that have been awarded to us. Backlog is not a measure defined by generally accepted accounting principles, and our methodology for determining backlog may not be comparable to the methodology used by other companies in determining their backlog. Backlog may not be indicative of future operating results. Many contracts do not provide for a fixed amount of work to be performed and are subject to modification or termination by the customer. The termination or modification of any one or more sizeable contracts or the addition of other contracts may have a substantial and immediate effect on backlog.

We generally include the full value of contracts in backlog when a contract is awarded and/or the scope is definitized. On our projects related to unconsolidated joint ventures, we include our percentage ownership of the joint venture’s backlog. For long-term contracts, the amount included in backlog is limited to five years. In many instances, arrangements included in backlog are complex, nonrepetitive in nature, and may fluctuate in contract value and timing. Where contract duration is indefinite, projects included in backlog are limited to the estimated value of work to be completed within the following twelve months. Certain contracts provide maximum dollar limits, with actual authorization to perform work under the contract being agreed upon on a periodic basis with the customer. In these arrangements, only the amounts authorized are included in backlog. For projects where we solely act in a project management capacity, we only include our management scope of each project in backlog.

The following table summarizes our project backlog:

	December 31
Millions of dollars	2005		2004
Firm orders:
Government and Infrastructure	$	3,403	$	3,968
Energy and Chemicals - Gas monetization		3,651		443
Energy and Chemicals - Other		2,972		3,200
Energy Services Group segments		180		64
Total firm orders		10,206		7,675
Government orders firm but not yet funded, letters of
intent, and contracts awarded but not signed:
Government and Infrastructure		1,775		816
Total backlog	$	11,981	$	8,491

Gas monetization includes LNG and GTL projects.

We estimate that 76% of the Government and Infrastructure segment backlog and 52% of the Energy and Chemicals segment backlog at December 31, 2005 will be completed during 2006. Approximately 56% of total backlog at December 31, 2005 related to cost-reimbursable contracts with the remaining 44% relating to fixed-price contracts. Our backlog for projects related to unconsolidated joint ventures totaled $3.1 billion at December 31, 2005 and $1.1 billion at December 31, 2004. The increase in the government orders firm but not yet funded, letters of intent, and contracts awarded but not signed related to Task Order No. 89, assigned in the second quarter of 2005 under the LogCAP contract, that replaced several task orders that were nearing completion. Our backlog excludes contracts for recurring hardware and software maintenance and support services offered by Landmark.

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. Given high activity levels, particularly in the United States, we are proactively seeking ways to ensure the availability of resources, as well as manage the rising costs of raw materials. Our procurement department is actively leveraging our size and buying power through several programs designed to ensure that we have access to key materials at the best possible 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 $220 million in 2005, $234 million in 2004, and $221 million in 2003, 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 or group of patents 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, Landmark results of operations are generally stronger in the fourth quarter of the year than at the beginning of the year.

Employees

At December 31, 2005, we employed approximately 106,000 people worldwide compared to 97,000 at December 31, 2004. At December 31, 2005, approximately 9% 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 Resources 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.

Website 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 website at www.halliburton.com as soon as reasonably practicable after we have electronically filed the material with, or furnished it to, the SEC. The public may read and copy any materials our company has filed with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, 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 website 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 website within four business days after the date of any amendment or waiver pertaining to these officers.

Item 1(a). Risk Factors.

Information relating 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.

Location	Owned/Leased	Description
*Energy Services Group*
Production Optimization Segment:

Carrollton, Texas	Owned	Manufacturing facility

Alvarado, Texas	Owned/Leased	Manufacturing facility

Drilling and Formation Evaluation Segment:

The Woodlands, Texas	Leased	Manufacturing facility

Shared Facilities:

Duncan, Oklahoma	Owned	Manufacturing, technology, and
		campus facilities

Houston, Texas	Owned	Manufacturing and campus facilities

Houston, Texas	Owned/Leased	Campus facility

Houston, Texas	Leased	Campus facility

*KBR*
Government and Infrastructure Segment:

Arlington, Virginia	Leased	Campus facility

Energy and Chemicals Segment:

Houston, Texas	Leased	Campus facility

Shared Facilities:

Houston, Texas	Owned	Campus facility

Leatherhead, United Kingdom	Owned	Campus facility

*Corporate*

Houston, Texas	Leased	Corporate executive offices

All of our owned properties are unencumbered.

In addition, we have 145 international and 108 United States field camps from which the ESG delivers its services and products. We also have numerous small facilities that include sales offices, project offices, and bulk storage facilities throughout the world. We own or lease marine fabrication facilities covering approximately 446 acres in Texas, England (primarily related to DML), and Scotland, which are used by KBR. Our marine facilities located in Texas and Scotland are currently for sale.

We have mineral rights to proven and probable reserves of barite and bentonite. These rights include leaseholds, mining claims, and owned property. We process barite and bentonite for use in our Fluid Systems segment in addition to supplying many industrial markets worldwide. Based on the number of tons of bentonite consumed in fiscal year 2005, we estimate that our 20 million tons of proven reserves in areas of active mining are sufficient to fulfill our internal and external needs for the next 14 years. We estimate that our 2.6 million tons of proven reserves of barite in areas of active mining equate to a 12-year supply based on current rates of production. These estimates are subject to change based on periodic updates to reserve estimates, future consumption, mining economics, and changes in environmental legislation.

We believe all properties that we currently occupy are suitable for their intended use.

Item 3. Legal Proceedings.

Information relating 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 Notes 2, 10, 11, and 12 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 2005.

Executive Officers of the Registrant

The following table indicates the names and ages of the executive officers of the registrant as of February 15, 2006, along with a listing of all offices held by each:

Name and Age	Offices Held and Term of Office
* Albert O. Cornelison, Jr.	Executive Vice President and General Counsel of Halliburton Company,
(Age 56)	since December 2002
	Vice President and General Counsel of Halliburton Company, May 2002 to
	December 2002
	Vice President and Associate General Counsel of Halliburton Company,
	October 1998 to May 2002

* C. Christopher Gaut	Executive Vice President and Chief Financial Officer of Halliburton Company,
(Age 49)	since March 2003
	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
	Senior Vice President and Chief Financial Officer of ENSCO International,
	Inc., December 1987 to December 2001

* Andrew R. Lane	Executive Vice President and Chief Operating Officer of Halliburton Company,
(Age 46)	since December 2004
	President and Chief Executive Officer of Kellogg Brown & Root, Inc., July 2004 to
	November 2004
	Senior Vice President, Global Operations of Halliburton Energy Services Group,
	April 2004 to July 2004
	President, Landmark Division of Halliburton Energy Services Group,
	May 2003 to March 2004
	President and Chief Executive Officer of Landmark Graphics, April 2002 to
	April 2003
	Chief Operating Officer of Landmark Graphics, January 2002 to March 2002
	Vice President, Production Enhancement PSL, Completion Products PSL and
	Tools/Testing/TCP of Halliburton Energy Services Group, January 2000
	to December 2001

* David J. Lesar	Chairman of the Board, President and Chief Executive Officer of Halliburton
(Age 52)	Company, since August 2000
	Director of Halliburton Company, since August 2000
	President and Chief Operating Officer of Halliburton Company, May 1997 to
	August 2000
	Chairman of the Board of Kellogg Brown & Root, Inc., January 1999 to
	August 2000
	Executive Vice President and Chief Financial Officer of Halliburton Company,
	August 1995 to May 1997

Mark A. McCollum	Senior Vice President and Chief Accounting Officer of Halliburton Company,
(Age 46)	since August 2003
	Senior Vice President and Chief Financial Officer of Tenneco Automotive, Inc.,
	November 1999 to August 2003

Name and Age	Offices Held and Term of Office
Craig W. Nunez	Vice President and Treasurer of Halliburton Company, since February 2006
(Age 44)	Treasurer of Colonial Pipeline Company, November 1999 to January 2006

* Lawrence J. Pope	Vice President, Human Resources & Administration of Halliburton Company,
(Age 38)	since January 2006
	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
	Director, Human Resources for Halliburton Energy Services Group,
	May 1999 to May 2001

David R. Smith	Vice President, Tax of Halliburton Company, since May 2002
(Age 59)	Vice President, Tax of Halliburton Energy Services, Inc.,
	September 1998 to May 2002

* 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 relating 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 115 of this annual report. Cash dividends on common stock for 2005 and 2004 in the amount of $0.125 per share were paid in March, June, September, and December of each year. 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.

In February 2006, our Board of Directors approved a share repurchase program up to $1.0 billion. The Board of Directors approved a dividend for the first quarter of 2006 to shareholders of record at the close of business on March 2, 2006 of $0.15 per share, payable on March 23, 2006 reflecting a dividend increase of $0.025 per share. The Board of Directors also approved a 2:1 stock split, subject to shareholder approval at the 2006 annual shareholders meeting of a proposal to increase the number of authorized shares of common stock from one billion shares to two billion shares. Each shareholder would receive one additional share for each outstanding share held by the shareholder on the record date for the stock split. The record date will be announced after the approval of the increase in authorized shares of common stock.

At February 15, 2006, there were 20,912 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, 2005.

					Total Number of Shares
					Purchased as Part of Publicly
Period	Total Number of Shares Purchased (a)		Average Price Paid per Share		Announced Plans or Programs
October 1-31		14,775	$	66.57		-
November 1-30		3,551	$	60.32		-
December 1-31		19,162	$	64.16		-
Total		37,488	$	64.75		-

(a) All of the shares repurchased during the three-month period ended December 31, 2005 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 share purchases were not part of a publicly announced program to purchase common shares.

Item 6. Selected Financial Data.

Information relating to selected financial data is included on page 114 of this annual report.

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

Information relating to Management’s Discussion and Analysis of Financial Condition and Results of Operations is included on pages 14 through 60 of this annual report.

Item 7(a). Quantitative and Qualitative Disclosures About Market Risk.

Information relating 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 46 of this annual report.

Item 8. Financial Statements and Supplementary Data.

	Page No.
Management’s Report on Internal Control Over Financial Reporting	61
Reports of Independent Registered Public Accounting Firm	62
Consolidated Statements of Operations for the years ended December 31, 2005, 2004, and 2003	64
Consolidated Balance Sheets at December 31, 2005 and 2004	65
Consolidated Statements of Shareholders’ Equity for the years ended
December 31, 2005, 2004, and 2003	66
Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004, and 2003	67
Notes to Consolidated Financial Statements	68
Selected Financial Data (Unaudited)	114
Quarterly Data and Market Price Information (Unaudited)	115

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, 2005 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, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

See page 61 for Management’s Report on Internal Control Over Financial Reporting and page 63 for Report of Independent Registered Public Accounting Firm on our assessment of internal control over financial reporting and opinion on the effectiveness of the Company’s 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

While 2005 began with the finalization of our asbestos and silica settlements in January, the highlight of the year was the strong operational performance of both of our business units, the Energy Services Group (ESG) and KBR.

ESG improved performance with a 26% increase in revenue and an 80% increase in operating income, compared to 2004. ESG operating margin (defined as operating income divided by revenue) increased nearly seven percentage points to 22.6% from 15.8% in 2004. ESG’s improved operating income and margins in 2005 compared to 2004 are a direct result of:

higher demand for oilfield services, with annual average worldwide rig counts increasing approximately 15%;

improved utilization of equipment, which was evident by an increase in our revenue per fracturing job over 2004;

increased pricing, particularly in areas of high demand and tight supply; and

our continued focus on operating performance and return on capital. Our focus centered on exiting underperforming operations, achieving improved contract terms with our customers, and redeploying resources to more attractive markets.

At KBR, we saw the benefits from restructuring KBR in 2004. KBR delivered $498 million in operating income in 2005, resulting in a 4.6% operating margin. KBR revenue decreased in 2005 as a result of lower revenue on government services projects in the Middle East, while operating income increased $840 million over 2004. These results reflect:

large losses in 2004 on our offshore fixed-price engineering, procurement, installation, and commissioning (EPIC) projects that did not recur in 2005, combined with improved profitability on our cost-reimbursable engineering projects;

award fees received for our work in Iraq and the complete resolution of disputed dining facilities, fuel costs, and other issues, which resulted in the recording of $103 million of operating income related to our LogCAP and RIO contracts; and

profit on newly awarded liquefied natural gas (LNG) and gas-to-liquids (GTL), or gas monetization infrastructure projects, designed to commercialize gas reserves around the world. Our backlog in these gas monetization projects was $3.7 billion at December 31, 2005.

During 2005, our operations were negatively impacted by several hurricanes in the Gulf of Mexico. ESG lost approximately $80 million in estimated revenue and approximately $45 million in estimated operating income primarily due to the temporary suspension of work related to damaged and lost customer rigs. KBR also incurred $5 million in expenses related to the hurricanes.

We achieved our goal of reducing our debt-to-capitalization ratio to the mid-30s. We redeemed $500 million of senior notes in April 2005 and paid off $300 million of floating rate senior notes that matured in October 2005. Our debt-to-capitalization ratio at December 31, 2005 was 33%.

The outlook for our business is positive. Strong commodity prices, a lack of excess oil supply compared to historical up-cycle periods, and continuing strong cash flow are driving increased spending plans for our exploration and production customers. We believe oil and gas prices will fluctuate in the future, but the fundamentals that support increased demand for our services or products are not expected to change significantly in the near term. We also expect continued growth in gas monetization projects, a particular strength for KBR. We believe the North American market will continue to grow in 2006, and we plan to deploy additional capital and labor resources in this market. We also expect regions outside North America to grow, particularly in the Middle East, Northern Africa, Russia, and the deep-water offshore markets, as we execute our international growth and investment strategy.

As such, in 2006 we are focusing on:

improving the utilization of our equipment and deploying additional resources to address the growing demand for our services and products;

increasing pricing (as the market allows) for ESG’s services and products due to expected labor and material cost increases and high demand from customers;

leveraging our technologies to provide our customers with the ability to more efficiently drill wells and to increase the productivity of those wells;

capitalizing on our strengths in the LNG and GTL markets. Forecasted LNG market growth remains strong and is expected to grow further. Significant numbers of new LNG liquefaction plant and LNG receiving terminal projects are proposed worldwide and are in various stages of development. Our experience in providing engineering, design, and construction services in the liquefied natural gas industry, particularly liquefaction facilities, positions us to benefit from the growth we are seeing in this industry; and

diversifying the services of our Government and Infrastructure segment. We expect our work under the LogCAP contract to see a more rapid decline during 2006 than we saw in 2005. As a result, we are focused on diversifying the Government and Infrastructure project portfolio and we continued to expand our work for the United States Navy under the CONCAP construction contingency contract and are positioned for future contingency work for the United States Air Force under the AFCAP contract. In addition, we have strengthened our position with the United Kingdom Ministry of Defence.

We also plan to initiate the separation of KBR from Halliburton in 2006. Our decision to separate KBR arose primarily because we do not believe the full value of KBR is currently reflected in Halliburton’s stock price, and few synergies exist between the two business units. Our current plan is to effect an initial public offering (IPO) of less than 20% of KBR. We believe the IPO market is attractive and valuation multiples of publicly traded engineering and construction companies are currently favorable. In response to interest we have received, we may consider selling some pieces of KBR, but this is not expected to change our IPO plans for the remainder of KBR. We expect that a Form S-1 for KBR will be filed with the United States Securities and Exchange Commission (SEC) after the 2005 audited financial statements of KBR are complete. Any sale of KBR stock would be registered under the Securities Act of 1933, and such shares of common stock would only be offered and sold by means of a prospectus. This annual report does not constitute an offer to sell or the solicitation of any offer to buy any securities of KBR, and there will not be any sale of any such securities in any state in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of such state.

Detailed discussions of our United States government contract work, the Foreign Corrupt Practices Act investigations, and our liquidity and capital resources follow. Our operating performance is described in “Business Environment and Results of Operations” below.

United States Government Contract Work

Given the demands of working in Iraq and elsewhere for the United States government, we expect that from time to time we will have disagreements or experience performance issues with the various government customers for which we work. If performance issues arise under any of our government contracts, the government retains the right to pursue remedies which could include threatened termination or termination, under any affected contract. If any contract were so terminated, we may not receive award fees under the affected contract, and our ability to secure future contracts could be adversely affected, although we would receive payment for amounts owed for our allowable costs under cost-reimbursable contracts. Other remedies that could be sought by our government customers for any improper activities or performance issues include sanctions such as forfeiture of profits, suspension of payments, fines, and suspensions or debarment from doing business with the government. Further, the negative publicity that could arise from disagreements with our customers or sanctions as a result thereof could have an adverse effect on our reputation in the industry, reduce our ability to compete for new contracts, and may also have a material adverse effect on our business, financial condition, results of operations, and cash flow.

DCAA audit issues

Our operations under United States government contracts are regularly reviewed and audited by the Defense Contract Audit Agency (DCAA) and other governmental agencies. The DCAA serves in an advisory role to our customer. When issues are found during the governmental agency audit process, these issues are typically discussed and reviewed with us. The DCAA then issues an audit report with its recommendations to our customer’s contracting officer. In the case of management systems and other contract administrative issues, the contracting officer is generally with the Defense Contract Management Agency (DCMA). We then work with our customer to resolve the issues noted in the audit report. If our customer or a government auditor finds that we improperly charged any costs to a contract, these costs are not reimbursable, or, if already reimbursed, the costs must be refunded to the customer.

Dining facilities (DFAC). During 2003, the DCAA raised issues related to our invoicing to the Army Materiel Command (AMC) for food services for soldiers and supporting civilian personnel in Iraq and Kuwait. During 2004, we received notice from the DCAA that it was recommending withholding 19.35% of our DFAC billings relating to subcontracts entered into prior to February 2004 until it completed its audits. Approximately $213 million had been withheld as of March 31, 2005. Subsequent to February 2004, we renegotiated our DFAC subcontracts to address the specific issues raised by the DCAA and advised the AMC and the DCAA of the new terms of the arrangements. We have had no objection by the government to the terms and conditions associated with our new DFAC subcontract agreements. On March 31, 2005, we reached an agreement with the AMC regarding the costs associated with the DFAC subcontractors, which totaled approximately $1.2 billion. Under the terms of the agreement, the AMC agreed to the DFAC subcontractor costs except for $55 million, which it retained from the $213 million previously withheld amount. In the second quarter of 2005, the government released the funds to KBR.

During 2005, we reached settlement agreements with all but one subcontractor, Eurest Support Services (Cyprus) International Limited, or ESS, and resolved $44 million of the $55 million disallowed DFAC subcontractor costs. Accordingly, we paid the amounts due to all subcontractors with whom settlements have been finalized, in accordance with the agreement reached with the government, but withheld the remaining $11 million pending settlement with ESS. On September 30, 2005, ESS filed suit against us alleging various claims associated with its performance as a subcontractor in conjunction with our LogCAP contract in Iraq. The case was settled during the first quarter of 2006 without material impact to us.

Fuel. In December 2003, the DCAA issued a preliminary audit report that alleged that we may have overcharged the Department of Defense by $61 million in importing fuel into Iraq. The DCAA questioned costs associated with fuel purchases made in Kuwait that were more expensive than buying and transporting fuel from Turkey. We responded that we had maintained close coordination of the fuel mission with the Army Corps of Engineers (COE), which was our customer and oversaw the project throughout the life of the task orders, and that the COE had directed us to use the Kuwait sources. After a review, the COE concluded that we obtained a fair price for the fuel. Nonetheless, Department of Defense officials referred the matter to the agency’s inspector general, which we understand commenced an investigation.

The DCAA issued various audit reports related to task orders under the RIO contract that reported $275 million in questioned and unsupported costs. The majority of these costs were associated with the humanitarian fuel mission. In these reports, the DCAA compared fuel costs we incurred during the duration of the RIO contract in 2003 and early 2004 to fuel prices obtained by the Defense Energy Supply Center (DESC) in April 2004 when the fuel mission was transferred to that agency. During the fourth quarter of 2005, we resolved all outstanding issues related to the RIO contract with our customer and settled the remaining questioned costs under this contract.

Laundry. Prior to the fourth quarter of 2005, we received notice from the DCAA that it recommended withholding $18 million of subcontract costs related to the laundry service for one task order in southern Iraq for which it believes we and our subcontractors have not provided adequate levels of documentation supporting the quantity of the services provided. In the fourth quarter of 2005, the DCAA issued a notice to disallow costs totaling approximately $12 million, releasing $6 million of amounts previously withheld. The $12 million has been withheld from the subcontractor. We are working with the DCMA and the subcontractor to resolve this issue.

Containers. In June 2005, the DCAA recommended withholding certain costs associated with providing containerized housing for soldiers and supporting civilian personnel in Iraq. Approximately $55 million has been withheld as of December 31, 2005 (down from $60 million originally reported because some issues have been resolved). The DCAA recommended that the costs be withheld pending receipt of additional explanation or documentation to support the subcontract costs. We have provided information we believe addresses the concerns raised by the DCAA. None of these amounts have been withheld from our subcontractors. We are working with the government and our subcontractors to resolve this issue.

Other issues. The DCAA is continuously performing audits of costs incurred for the foregoing and other services provided by us under our government contracts. During these audits, there are likely to be questions raised by the DCAA about the reasonableness or allowability of certain costs or the quality or quantity of supporting documentation. No assurance can be given that the DCAA might not recommend withholding some portion of the questioned costs while the issues are being resolved with our customer. Because of the intense scrutiny involving our government contracts operations, issues raised by the DCAA may be more difficult to resolve. We do not believe any potential withholding will have a significant or sustained impact on our liquidity.

Investigations

In early 2004, our internal audit function identified a potential $4 million overbilling by La Nouvelle Trading & Contracting Company, W.L.L. (La Nouvelle), one of our subcontractors under the LogCAP contract in Iraq, for services performed during 2003. In accordance with our policy and government regulation, the potential overcharge was reported to the Department of Defense Inspector General’s office as well as to our customer, the AMC. We reimbursed the AMC to cover that potential overbilling while we conducted our own investigation into the matter. We subsequently terminated La Nouvelle’s services under the LogCAP contract. In October 2004, La Nouvelle filed suit against us alleging $224 million in damages as a result of its termination. During the second quarter of 2005, this suit was settled without material impact to us. See Note 12 to the consolidated financial statements for further discussion.

In the first quarter of 2005, the United States Department of Justice (DOJ) issued two indictments associated with these issues against a former KBR procurement manager and a manager of La Nouvelle.

In October 2004, we reported to the Department of Defense Inspector General’s office that two former employees in Kuwait may have had inappropriate contacts with individuals employed by or affiliated with two third-party subcontractors prior to the award of the subcontracts. The Inspector General’s office may investigate whether these two employees may have solicited and/or accepted payments from these third-party subcontractors while they were employed by us.

In October 2004, a civilian contracting official in the COE asked for a review of the process used by the COE for awarding some of the contracts to us. We understand that the Department of Defense Inspector General’s office may review the issues involved.

We understand that the DOJ, an Assistant United States Attorney based in Illinois, and others are investigating these and other individually immaterial matters we have reported relating to our government contract work in Iraq. If criminal wrongdoing were found, criminal penalties could range up to the greater of $500,000 in fines per count for a corporation or twice the gross pecuniary gain or loss. We also understand that current and former employees of KBR have received subpoenas and have given or may give grand jury testimony related to some of these matters.

Withholding of payments

During 2004, the AMC issued a determination that a particular contract clause could cause it to withhold 15% from our invoices until our task orders under the LogCAP contract are definitized. The AMC delayed implementation of this withholding pending further review. During the third quarter of 2004, we and the AMC identified three senior management teams to facilitate negotiation under the LogCAP task orders, and these teams concluded their effort by successfully negotiating the final outstanding task order definitization on March 31, 2005. This made us current with regard to definitization of historical LogCAP task orders and eliminated the potential 15% withholding issue under the LogCAP contract.

Upon the completion of the RIO contract definitization process, the COE released all previously withheld amounts related to this contract in the fourth quarter of 2005.

The PCO Oil South project has definitized substantially all of the task orders, and we have collected a significant portion of the amounts previously withheld. We do not believe the withholding will have a significant or sustained impact on our liquidity because the withholding is temporary, and the definitization process is substantially complete.

We are working diligently with our customers to proceed with significant new work only after we have a fully definitized task order, which should limit withholdings on future task orders for all government contracts.

In addition, we had probable unapproved claims totaling $69 million at December 31, 2005 for the LogCAP and PCO Oil South contracts. These unapproved claims related to contracts where our costs have exceeded the customer’s funded value of the task order.

DCMA system reviews

Report on estimating system. On December 27, 2004, the DCMA granted continued approval of our estimating system, stating that our estimating system is “acceptable with corrective action.” We are in the process of completing these corrective actions. Specifically, based on the unprecedented level of support that our employees are providing the military in Iraq, Kuwait, and Afghanistan, we needed to update our estimating policies and procedures to make them better suited to such contingency situations. Additionally, we have completed our development of a detailed training program and have made it available to all estimating personnel to ensure that employees are adequately prepared to deal with the challenges and unique circumstances associated with a contingency operation.

Report on purchasing system. As a result of a Contractor Purchasing System Review by the DCMA during the fourth quarter of 2005, the DCMA granted the continued approval of our government contract purchasing system. The DCMA’s approval letter, dated October 28, 2005, stated that our purchasing system’s policies and practices are “effective and efficient, and provide adequate protection of the Government’s interest.”

Report on accounting system. We received two draft reports on our accounting system, which raised various issues and questions. We have responded to the points raised by the DCAA, but this review remains open. Once the DCAA finalizes the report, it will be submitted to the DCMA, who will make a determination of the adequacy of our accounting systems for government contracting.

The Balkans

We have had inquiries in the past by the DCAA and the civil fraud division of the DOJ into possible overcharges for work performed during 1996 through 2000 under a contract in the Balkans, for which inquiry has not yet been completed by the DOJ. Based on an internal investigation, we credited our customer approximately $2 million during 2000 and 2001 related to our work in the Balkans as a result of billings for which support was not readily available. We believe that the preliminary DOJ inquiry relates to potential overcharges in connection with a part of the Balkans contract under which approximately $100 million in work was done. We believe that any allegations of overcharges would be without merit. Amounts accrued related to this matter as of December 31, 2005 are not material.

Foreign Corrupt Practices Act investigations

The SEC is conducting a formal investigation into payments made 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 DOJ is also conducting a related criminal investigation. The government has also issued a subpoena to Halliburton seeking information, which we are furnishing, regarding current and former agents used in connection with multiple projects or services over the past 20 years located both in and outside of Nigeria in which The M .W. Kellogg Company, M. W. Kellogg, Ltd., Kellogg Brown & Root or their joint ventures, as well as the Halliburton energy services business, were participants. M. W. Kellogg, Ltd. is a joint venture in which Kellogg Brown & Root has a 55% interest. The M. W. Kellogg Company was a subsidiary of Dresser Industries before our 1998 acquisition of Dresser Industries and was later merged with a subsidiary of ours to form Kellogg Brown & Root.

The SEC and the DOJ have been reviewing these matters in light of the requirements of the United States Foreign Corrupt Practices Act (FCPA). We have been cooperating with the SEC and the DOJ, as well as with investigations into the Bonny Island project in France and Nigeria. 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 (which included M. W. Kellogg, Ltd. and The M .W. Kellogg Company)) and include TSKJ’s use of a Japanese trading company that contracted to provide services to TSKJ. We have produced documents to the SEC and the DOJ both voluntarily and pursuant to subpoenas, and we are making our employees available to the SEC and the DOJ for interviews. In addition, we understand that the SEC has issued a subpoena to A. Jack Stanley, who formerly served as a consultant and chairman of KBR, and to others, including certain current and former KBR employees and at least one subcontractor of KBR. We further understand that the DOJ has invoked its authority under a sitting grand jury to issue 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.

TSKJ is a private limited liability company registered in Madeira, Portugal whose members are Technip SA of France, Snamprogetti Netherlands B.V. (an affiliate of ENI SpA of Italy), JGC Corporation of Japan, and Kellogg Brown & Root (as successor to The M. W. Kellogg Company), each of which owns 25% of 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). Commencing in 1995, TSKJ entered into a series of agency agreements in connection with the Bonny Island project, including with Tri-Star Investments, of which Jeffrey Tesler is a principal. 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.

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, based on the ongoing governmental and other investigations, that payments may have been made to Nigerian officials.

We notified the other owners of TSKJ of information provided by the investigations and asked each of them to conduct their own investigation. TSKJ has 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 June 2004, we terminated all relationships with Mr. Stanley and another consultant and former employee of M. W. Kellogg, Ltd. The terminations occurred because of violations of our Code of Business Conduct that allegedly involved the receipt of improper personal benefits in connection with TSKJ’s construction of the natural gas liquefaction facility in Nigeria.

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 banks in Switzerland transferred to Nigeria and to have the legal ownership of such sums determined in the Nigerian courts.

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, and injunctive relief. Criminal penalties could range up to the greater of $2 million per violation or twice the gross pecuniary gain or loss. Both the SEC and the DOJ could argue that continuing conduct may constitute multiple violations for purposes of assessing the penalty amounts per violation. Often, agreed dispositions for these types of matters result in a monitor being appointed by the SEC and/or the DOJ to review future business and practices with the goal of ensuring compliance with the FCPA. Fines and civil and criminal penalties could be mitigated, in the government’s discretion, depending on the level of the cooperation in the investigations.

Potential consequences of a criminal indictment arising out of these matters could include suspension by the Department of Defense or another federal, state, or local government agency of KBR and its affiliates from their ability to contract with United States, state or local governments, or government agencies and, if a criminal or civil violation were found, KBR and its affiliates could be debarred from future contracts or new orders under current contracts to provide services to any such parties. During 2005, KBR and its affiliates had revenue of approximately $6.6 billion from its government contracts work with agencies of the United States or state or local governments. Consistent with our cooperation with the DOJ and the SEC, we would seek to obtain administrative agreements or waivers to avoid suspension or debarment. Generally, debarments can last up to three years. Suspension or debarment from the government contracts business would have a material adverse effect on the business and results of operations of KBR and Halliburton.

There can be no assurance that any governmental investigation or our investigation of these matters will not conclude that violations of applicable laws have occurred. The results of these investigations could have a material adverse effect on our business, prospects, results of operations, financial condition, and cash flows.

As of December 31, 2005, we have not accrued any amounts related to this investigation other than our current legal expenses.

Bidding practices investigation

In connection with the investigation into payments made in connection with the Nigerian project, information has been uncovered suggesting that Mr. Stanley and other former employees may have engaged in coordinated bidding with one or more competitors on certain foreign construction projects, and that such coordination possibly began as early as the mid-1980s, which was significantly before our 1998 acquisition of Dresser Industries.

On the basis of this information, we and the DOJ have broadened our investigations to determine the nature and extent of any improper bidding practices, whether such conduct violated United States antitrust laws, and whether former employees may have received payments in connection with bidding practices on some foreign projects.

If violations of applicable United States antitrust laws occurred, the range of possible penalties includes criminal fines, which could range up to the greater of $10 million in fines per count for a corporation, or twice the gross pecuniary gain or loss, and treble civil damages in favor of any persons financially injured by such violations. Suspension or debarment from contracting with the United States, state or local governments, or government agencies could also occur. Criminal prosecutions under applicable laws of relevant foreign jurisdictions and civil claims by or relationship issues with customers are also possible.

There can be no assurance that the results of these investigations will not have a material adverse effect on our business and results of operations.

As of December 31, 2005, we had not accrued any amounts related to this investigation other than our current legal expenses.

LIQUIDITY AND CAPITAL RESOURCES

We ended 2005 with cash and equivalents of $2.4 billion compared to $1.9 billion at December 31, 2004.

Significant sources of cash

Cash flows from operations contributed $701 million to cash in 2005. We received approximately $1.032 billion in asbestos- and silica-related insurance proceeds in 2005 and expect to receive additional amounts as follows:

Millions of dollars
2006	$	193
2007		41
2008		46
2009		131
2010		16
Total	$	427

During the first quarter of 2005, we sold $891 million in investments in marketable securities. Our cash flow was supplemented by approximately $200 million from the sale of our 50% interest in Subsea 7, Inc. in January 2005 and $85 million from the sale of an investment in a United States toll road in September 2005.

Our working capital requirements for our Iraq-related work, excluding cash and equivalents, decreased from $700 million at December 31, 2004 to $495 million at December 31, 2005.

Further available sources of cash. In the first quarter of 2005, we entered into an unsecured $1.2 billion five-year revolving credit facility for general working capital purposes. The new credit facility replaced our secured $700 million three-year revolving credit facility and our secured $500 million 364-day revolving credit facility. The letter of credit issued under the previous secured $700 million three-year revolving credit facility is now under our unsecured $1.2 billion revolving facility and has a balance of $107 million as of December 31, 2005. The letter of credit reduces the availability under the revolving credit facility to approximately $1.1 billion. There were no cash drawings under the unsecured $1.2 billion revolving credit facility as of December 31, 2005.

KBR entered into an unsecured $850 million five-year revolving credit facility in the fourth quarter of 2005. Three letters of credit that totaled $25 million were subsequently issued under the KBR revolving credit facility, thus reducing the availability under the credit facility to approximately $825 million at December 31, 2005. There were no cash drawings under the unsecured $850 million revolving credit facility as of December 31, 2005.

Significant uses of cash

In 2005, we used approximately $2.4 billion to fund the asbestos and silica liability trusts and made the following payments:

Millions of dollars
Cash payments related to asbestos and silica made in 2005:
Payment to the asbestos and silica trust in accordance with
the plan of reorganization	$	2,345
One-year non-interest-bearing note for the benefit of
asbestos claimants		31
Cash payment related to insurance partitioning agreement
in October 2004 - first of three installments		16
First installment payment for the silica note		15
Payments related to RHI Refractories agreement		11
Total	$	2,418

On April 26, 2005, we redeemed, at par plus accrued interest, all $500 million of our floating rate senior notes due 2007 that were issued in January 2004. On October 17, 2005, we repaid, at par plus accrued interest, our $300 million floating rate senior notes that matured.

Capital expenditures of $651 million in 2005 were 13% higher than in 2004. Capital spending in 2005 continued to be primarily directed to the Energy Services Group for the Production Optimization, Drilling and Formation Evaluation, and Fluid Systems segments.

We paid $254 million in dividends to our shareholders in 2005.

We also continued to fund operating cash shortfalls on the Barracuda-Caratinga project, a multiyear construction project to develop the Barracuda and Caratinga crude oilfields off the coast of Brazil. During 2005, we funded approximately $169 million, net of revenue received. This amount was net of payments to us of $138 million related to change orders.

Future uses of cash. The following table summarizes our significant contractual obligations and other long-term liabilities as of December 31, 2005:

	Payments due
Millions of dollars	2006		2007		2008		2009		2010		Thereafter		Total
Long-term debt (1) (2)	$	359	$	31	$	152	$	1	$	750	$	1,879	$	3,172
Operating leases		187		148		123		111		100		478		1,147
Purchase obligations (3)		644		30		19		10		4		10		717
Barracuda-Caratinga		12		-		-		-		-		-		12
Pension funding
obligations (4)		164		-		-		-		-		-		164
Total	$	1,366	$	209	$	294	$	122	$	854	$	2,367	$	5,212

(1) Long-term debt excludes the effect of a terminated interest rate swap of approximately $2 million.

(2) Long-term debt includes a silica note contributed to the trust for the benefit of silica personal injury claimants. Subsequent to the initial payment of $15 million, the silica note provides that we will contribute an amount to the silica trust at the end of each year for the next 30 years of up to $15 million. The note also provides for an extension of the note for 20 additional years under certain circumstances. We initially recorded the note at our estimated amount of approximately $24 million, including the initial payment of $15 million paid in January 2005. We will periodically reassess our valuation of this note based upon our projections of the amounts we believe we will be required to fund into the silica trust. Long-term debt also includes an asbestos insurance partitioning agreement that we reached in 2004 with Federal-Mogul, our insurance companies, and another party sharing in the insurance coverage to obtain their consent and support of a partitioning of the insurance policies. As part of the settlement, we agreed to pay $46 million in three installment payments. In 2004, we accrued $44 million, which represents the present value of the $46 million to be paid. The discount is accreted as interest expense (classified as discontinued operations) over the life of the expected future cash payments beginning in the fourth quarter of 2004. The first payment of $16 million was paid in January 2005, and the second payment of $15 million was paid in January 2006. The third and final payment of $15 million will be made in January 2007.

(3) The purchase obligations disclosed above do not include purchase obligations that KBR enters into with its vendors in the normal course of business that support existing contracting arrangements with its customers. The purchase obligations with their vendors can span several years depending on the duration of the projects. In general, the costs associated with the purchase obligations are expensed as the revenue is earned on the related projects.

(4) In order to mitigate a portion of the projected underfunding of our United Kingdom pension plans, ESG contributed $38 million and KBR contributed $74 million in February 2006. These amounts are included in the $164 million 2006 funding obligation.

Capital spending for 2006 is expected to be approximately $875 million. The capital expenditures budget for 2006 includes a steady level of activities related to our DML shipyard and increased spending in the Energy Services Group to accommodate higher activity levels.

In February 2006, our Board of Directors approved a share repurchase program up to $1.0 billion. The Board of Directors also approved a dividend for the first quarter of 2006 to shareholders of record at the close of business on March 2, 2006 of $0.15 per share, payable on March 23, 2006, reflecting a dividend increase of $0.025 per share.

As of December 31, 2005, we had commitments to fund approximately $79 million to related companies. These commitments arose primarily during the start-up of these entities or due to losses incurred by them. We expect approximately $61 million of the commitments to be paid during 2006.

We continue to fund operating cash shortfalls on the Barracuda-Caratinga project and are obligated to fund total shortages over the remaining project life. We expect the remaining project costs, net of revenue to be received, to be approximately $12 million.

Other factors affecting liquidity

Accounts receivable securitization facilities. In May 2004, we entered into an agreement to sell, assign, and transfer the entire title and interest in specified United States government accounts receivable of KBR to a third party. The total amount of receivables outstanding under this agreement as of December 31, 2004 was approximately $263 million. As of December 31, 2005, these receivables were collected, the balance was retired, and the facility was terminated.

In April 2002, we entered into an agreement to sell eligible United States Energy Services Group accounts receivable to a bankruptcy-remote limited-purpose funding subsidiary. As of December 31, 2004, we had sold $256 million of undivided ownership interest to unaffiliated companies. During the fourth quarter of 2005, these receivables were collected and the balance retired. No further receivables were sold, and the facility was terminated subsequent to December 31, 2005.

See “Off Balance Sheet Risk” below for further discussion regarding these facilities.

Letters of credit. In the normal course of business, we have agreements with banks under which approximately $1.2 billion of letters of credit or bank guarantees were outstanding as of December 31, 2005, including $434 million that relate to our joint ventures’ operations. Also included in the letters of credit outstanding as of December 31, 2005 were $183 million of performance letters of credit and $114 million of retainage letters of credit related to the Barracuda-Caratinga project. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.

Credit ratings. Our current ratings are BBB on Standard & Poor’s and Baa1 on Moody’s Investors Service. In the fourth quarter of 2005, Moody’s revised its long-term senior unsecured debt rating from Baa2 to Baa1 with a “stable” outlook. In the third quarter of 2005, Standard & Poor’s revised its credit watch listing for us from “stable” to “positive,” citing improved operating performance and debt reduction as reasons for the upgrade. In the first quarter of 2005, Standard & Poor’s revised its credit watch listing for us from “developing” to “stable” and its short-term credit and commercial paper rating from A-3 to A-2. Our Moody’s Investors Service short-term credit and commercial paper rating is P-2.

Debt covenants. Letters of credit related to our Barracuda-Caratinga project and our $1.2 billion revolving credit facility contain restrictive covenants, including covenants that require us to maintain financial ratios as defined by the agreements. For the letters of credit related to our Barracuda-Caratinga project, we are required to maintain interest coverage and leverage ratios. We are also required to maintain a minimum debt-to-capitalization ratio under our $1.2 billion revolving credit facility. At December 31, 2005, we were in compliance with these requirements.

In addition, the unsecured $850 million five-year revolving credit facility entered into by KBR contains covenants including a limitation on the amount KBR can invest in unconsolidated subsidiaries. KBR must also maintain financial ratios including a debt-to-capitalization ratio, a leverage ratio, and a fixed charge coverage ratio. At December 31, 2005, KBR was in compliance with these requirements.

BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS

We currently operate in about 100 countries throughout the world, where we provide a comprehensive range of discrete and integrated services and products to the energy industry and to other industrial and governmental customers. The majority of our consolidated revenue is derived from the sale of services and products to major, national, and independent oil and gas companies and governments around the world. The services and products provided to major, national, and independent oil and gas companies are used throughout the energy industry from the earliest phases of exploration, development, and production of oil and gas through refining, processing, and marketing. Our six business segments are organized around how we manage the business: Production Optimization, Fluid Systems, Drilling and Formation Evaluation, Digital and Consulting Solutions, Government and Infrastructure, and Energy and Chemicals. We refer to the combination of Production Optimization, Fluid Systems, Drilling and Formation Evaluation, and Digital and Consulting Solutions segments as the ESG, and the combination of Government and Infrastructure and Energy and Chemicals as KBR.

The industries we serve are highly competitive with many substantial competitors for each segment. In 2005, based upon the location of the services provided and products sold, 27% of our consolidated revenue was from the United States, 24% of our consolidated revenue was from Iraq, primarily related to work for the United States Government, and 10% of our consolidated revenue was from the United Kingdom. In 2004, 26% of our consolidated revenue was from Iraq, and 22% of our consolidated revenue was from the United States. In 2003, 27% of our consolidated revenue was from the United States, and 15% of our consolidated revenue was from Iraq. 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 controls, or currency devaluation. Except for our government services work in Iraq discussed above, 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.

Halliburton Company

Activity levels within our business segments are significantly impacted by the following:

spending on upstream exploration, development, and production programs by major, national, and independent oil and gas companies;

capital expenditures for downstream refining, processing, petrochemical, gas monetization, and marketing facilities by major, national, and independent oil and gas companies; and

government spending levels.

Also impacting our activity is the status of the global economy, which impacts oil and gas consumption, demand for petrochemical products, and investment in infrastructure projects.

Energy Services Group

Some of the more significant barometers of current and future spending levels of oil and gas companies are oil and gas prices, exploration and production spending by international and national oil companies, the world economy, and global stability, which together drive worldwide drilling activity. Our ESG 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 crude oil, United Kingdom Brent, and Henry Hub natural gas:

Average Oil Prices (dollars per barrel)	2005		2004		2003
West Texas Intermediate	$	56.30	$	41.31	$	31.14
United Kingdom Brent	$	54.45	$	38.14	$	28.78

Average United States Gas Prices (dollars per million cubic feet)
Henry Hub	$	8.79	$	5.85	$	5.63

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

Land vs. Offshore	2005		2004		2003
United States:
Land	1,287		1,093		924
Offshore	93		97		108
Total	1,380		1,190		1,032
Canada:
Land	454		365		368
Offshore	4		4		4
Total	458		369		372
International (excluding Canada):
Land	643		594		544
Offshore	265		242		226
Total	908		836		770
Worldwide total	2,746		2,395		2,174
Land total	2,384		2,052		1,836
Offshore total	362		343		338

Oil vs. Gas	2005		2004		2003
United States:
Oil	194		165		157
Gas		1,186		1,025		875
Total		1,380		1,190		1,032
* Canada:		458		369		372
International (excluding Canada):
Oil		703		648		576
Gas		205		188		194
Total		908		836		770
Worldwide total		2,746		2,395		2,174

* Canadian rig counts by oil and gas were not available.

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 marginal exploration areas. This drives additional investment by our customers in the sector, which benefits us. The opposite is true for lower oil and gas prices.

Over 2005, United States oil prices continued their upward trend, leveling off in the high-$50 per barrel range by year-end. Recent increases in crude oil prices are due to a combination of the following factors:

growth in worldwide petroleum demand remains robust, despite high oil prices;

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

worldwide spare crude oil production capacity has recently diminished and is projected to remain low;

downstream sectors, such as refining and shipping, are expected to keep the level of uncertainty in world oil markets high as there is limited refining capacity available, particularly in the United States; and

loss of additional capacity due to recent hurricanes in an already tight refining market.

The Energy Information Administration (EIA) forecasts prices for crude oil, petroleum products, and natural gas to remain high through 2006. The EIA projects West Texas Intermediate prices to average $63 per barrel in 2006 and $60 per barrel in 2007.

United States natural gas prices also continued to move higher in 2005. Despite adequate natural gas storage, high natural gas prices are expected to persist through 2006 according to Spears and Associates.

Heightened energy demand coupled with high petroleum and natural gas prices in 2005 contributed to a 15% increase in average worldwide rig count compared to 2004. This increase was primarily driven by the United States rig count, which grew 16% year-over-year. Our ESG revenue in the United States grew 36% year-over-year on this 16% rig count increase. Land gas drilling in the United States rose substantially, as gas prices remained high due to economic demand growth and higher fuel oil prices that discouraged switching to a lower-priced fuel source to minimize cost. Average Canadian rig counts increased 24% in 2005 compared to 2004. Outside of North America, average rig counts primarily increased in Latin America, Asia Pacific, and the Middle East, with most of the increase related to oil drilling.

In December 2005, Spears and Associates predicted that the United States average rig count in 2006 will increase 13% over 2005. Canadian and international average rig counts in 2006 are forecasted to rise 30% and 5%, respectively, over 2005. Many new land rigs are expected to enter the industry, as 2006 spending to drill and complete new wells is projected to increase more than 20% over 2005.

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 or substantially offset price book increases in the weeks immediately following a price increase. The discount applied normally decreases over time if the activity levels remain strong. During periods of reduced activity, discounts normally increase, reducing the revenue for our services and, conversely, during periods of higher activity, discounts normally decline resulting in revenue increasing for our services.

In 2004 and 2005, we implemented several United States price book increases ranging from 5% to 18%, led by our pressure pumping services. We realized some of the benefits of these price book increases in 2005, and we expect further improvements during 2006. In addition, a price book increase of 5% for software products in our Digital and Consulting Solutions segment was implemented in January 2006. We anticipate that further price increases will be needed to offset the impact of inflationary pressures in our cost base.

Overall outlook. The outlook for world oil demand continues to remain strong, with China and North America accounting for approximately 45% of the expected demand growth in 2006. Chinese demand growth has declined recently, although oil demand growth is continuing in other populous countries, including India and Indonesia. Excess oil production capacity is expected to remain constrained and that, along with strong demand, is expected to keep supplies tight. Thus, any unexpected supply disruption or change in demand could lead to fluctuating prices. The International Energy Agency forecasts world petroleum demand growth in 2006 to increase 2% over 2005.

Our business is well-positioned in the United States. One of our fastest growing operations in this region is production enhancement, where we help our customers optimize the production rates from the wells by providing stimulation services. Among the other opportunities we expect is the recovery in deepwater drilling. Although overall rigs in the Gulf of Mexico are expected to decrease in 2006, demand for rigs to drill in the deepwater of the Gulf of Mexico is increasing. Despite having downsized our Gulf of Mexico operations due to its downturn in 2002-2003, we continue to have a significant presence in the area and are positioned to meet increasing customer demand. However, the Gulf of Mexico operations have been and can continue to be adversely affected by the hurricane season, which lasts from June through November. In the last half of 2005, four hurricanes adversely affected the Gulf of Mexico operations and some shut-in production remains. We expect customers to continue resuming activity in the Gulf of Mexico into the first half of 2006. These opportunities could be affected by sustained lower gas prices in the United States, which would reduce rig counts and activity in our production enhancement and other services.

In 2005, we were able to leverage our global infrastructure to increase the share of our business that comes from outside of the United States, as evidenced by a 20% increase over 2004 in ESG’s international revenue on a 13% increase in international rig count. Canada experienced tremendous activity growth in the latter half of 2005 and is expected to sustain growth in 2006.

In our Middle East/Asia region, Saudi Arabia is working to increase production and has increased its demand for oil services. Our 51%-owned subsidiary, WellDynamics, is currently supplying intelligent well completions in the region. Our involvement in Oman and Indonesia has expanded as a result of numerous multiyear contracts to provide an array of fluid, drilling, and logging services, as well as cementing, stimulation, and completion tools services. In 2005, our Drilling and Formation Evaluation, Fluid Systems, and Production Optimization segments also had new contract start-ups in Malaysia and Thailand. We have mobilized additional service equipment and personnel to the region to meet the overall rig and exploration and production demand, and we expect to see continued growth in these markets.

In our Europe/Africa/CIS region, strengthening demand in northern and western Africa and the North Sea has improved our asset utilization in all of our oilfield service product lines, and we are positioned to capitalize on this opportunity. In Libya, for example, we were recently awarded a four-well hydraulic fracturing contract that required a sharing of resources with a neighboring operation in Egypt and technical support from Europe. The successful completion of this contract has triggered new opportunities with customers in Libya. Our involvement in Russia is expanding as we believe that the business environment from a risk perspective has improved from a year ago. Landmark was recently awarded a software maintenance and support contract in Russia, and our field development work in Western Siberia was recently expanded to include services from our Fluid Systems and Drilling and Formation Evaluation segments. Awards during 2005 in Azerbaijan in our Drilling and Formation Evaluation segment and in northern Kazakhstan in our Drilling and Formation Evaluation, Fluid Systems, and Production Optimization segments will further improve our position in the Caspian as this area expands its demand for oilfield services. In Angola, where demand is driven by deepwater development, our Fluid Systems and Production Optimization segments were awarded contracts in 2005 and are actively pursuing more.

In Latin America, our overall performance has improved from a year ago. Despite the early problems with our fixed-price, turnkey drilling projects in southern Mexico, margins have improved, and we expect to complete them in the spring of 2006. In 2005, our Fluid Systems segment had new contract start-ups in Colombia and Ecuador, and in Argentina our Drilling and Formation Evaluation segment began work on new logging and drilling services contracts.

Finally, technology is an important aspect of our business, and we continue to focus on the development, introduction, and application of new technologies. See Note 1 to the consolidated financial statements for information about our research and development expense in the last three years. We expect our 2006 investment in new technology to increase compared to our 2005 investment.

KBR

KBR provides a wide range of services to energy, chemical, and industrial customers and government entities worldwide. KBR’s customer base includes leading international oil and gas companies, national oil and gas companies, independent refiners, chemical producers, fertilizer producers, and domestic and foreign government entities. KBR projects are generally longer-term in nature than our ESG work and are impacted by more diverse drivers than short-term fluctuations in oil and gas prices and drilling activities, such as local economic cycles, introduction of new governmental regulation, and governmental outsourcing of services. Demand for KBR’s services depends primarily on customers’ capital expenditures for construction and defense services. KBR is currently benefiting from historically high crude oil and natural gas prices and general global economic expansion, primarily in the petroleum and petrochemical industries. Additionally, the heightened focus on domestic security, increased military operations and maintenance spending, and a global expansion in government outsourcing have all contributed to the growth of our business.

Effective October 1, 2004, we restructured KBR into two segments, Government and Infrastructure and Energy and Chemicals. As a result of the reorganization and in a continued effort to better position KBR for the future, we made several strategic organizational changes. We eliminated certain internal expenditures and took appropriate steps to streamline the entire organization. KBR’s results for 2005 reflect cost savings related to the restructuring.

Our Government and Infrastructure segment provides support services to military and civilian branches of governments throughout the world. Our most significant contract is the worldwide United States Army logistics contract, known as LogCAP. We were awarded the competitively bid LogCAP contract in December 2001 from the AMC to provide worldwide United States Army logistics services. The contract is a one-year contract with nine one-year renewal options. We are currently in year five of the contract. The AMC can terminate, reduce the amount of work, or replace our contract with a new competitively bid contract at any time during the term of the contract.

During the second quarter of 2005, a large task order was assigned for the next phase of work under the LogCAP contract in Iraq and replaces several task orders that are nearing completion. Despite this award, we expect the volume of work under our LogCAP contract to continue to decline into 2006, as our customer scales back the amount of services that we provide. In order to diversify our government services portfolio, we continue to expand our work for the United States Navy under the CONCAP construction contingency contract, the United States Air Force under the AFCAP contract, and the United Kingdom Ministry of Defence. In addition, KBR was recently awarded the competitively bid Indefinite Delivery/Indefinite Quantity contract to support the Department of Homeland Security’s United States Immigration and Customs Enforcement facilities in the event of an emergency. This contract has a five-year term, consisting of a one-year base period and four one-year options.

In the civil infrastructure sector, there has been a general trend of historic under-investment. In particular, infrastructure related to the quality of water, wastewater, roads and transit, airports, and educational facilities has declined while demand for expanded and improved infrastructure continues to outpace funding. As a result, we expect increased opportunities for our engineering and construction services and for our privately financed project activities as our financing structures make us an attractive partner for state and local governments undertaking important infrastructure projects.

Our Energy and Chemicals segment develops energy and chemical projects throughout the world, including LNG and GTL gas monetization facilities, refineries, petrochemical plants, offshore oil and gas production platforms, and synthesis gas facilities. The major focus is on our gas monetization work. Forecasted LNG market growth remains strong and is expected to grow rapidly, with demand projected to double through 2015. Significant numbers of new LNG liquefaction plant and LNG receiving terminal projects are proposed worldwide and are in various stages of development. Committed LNG liquefaction engineering, procurement, and construction (EPC) projects will yield substantial growth in worldwide LNG liquefaction capacity. This trend is expected to continue through 2007 and beyond. Our extensive experience in providing engineering, design, and construction services in the liquefied natural gas industry, particularly liquefaction facilities, positions us to benefit from the growth we are seeing in this industry.

In March 2005, KBR, with a 50% ownership, and its joint venture partners were awarded a gas monetization contract valued at $1.8 billion for the engineering, procurement, construction, and commissioning of the Tangguh LNG facility in Indonesia. In April 2005, KBR, with a 50% ownership, and a joint venture partner were also awarded an EPC contract valued at $1.7 billion for a GTL facility in Escravos, Nigeria. Also in April 2005, KBR and its joint venture partners were awarded a front end engineering and design contract (FEED) encompassing offshore and onshore operations to monetize significant gas resources from fields located offshore Angola. In July 2005, KBR and our joint venture partners were awarded a cost reimbursable FEED contract and an option for a cost reimbursable engineering, procurement, and construction management (EPCM) contract for the greater Gorgon Downstream LNG Project in Western Australia. In August 2005, KBR renewed an alliance with one of its joint venture partners in order to build upon their respective strengths and work together to pursue and execute the engineering and construction of LNG and GTL projects around the world. In September 2005, this joint venture was awarded a project management contract for a GTL project in Qatar. In September 2005, KBR, with a 33% ownership, and its joint venture partners were also awarded a lump-sum turnkey contract valued at more than $2.0 billion to provide engineering, procurement, construction, pre-commissioning, commissioning, start-up, and operations services for Yemen’s first LNG plant. At December 31, 2005, we had $3.7 billion in backlog related to major gas monetization projects.

In order to meet growing energy demands, oil and gas companies are increasing their exploration, production, and transportation spending to increase production capacity and supply. KBR is currently targeting reimbursable EPC and EPCM opportunities in northern and western Africa, the Caspian area, Asia Pacific, Latin America, and the North Sea.

Outsourcing of operations and maintenance work by industrial and energy companies has been increasing worldwide. Opportunities in this area are anticipated as the aging infrastructure in United States refineries and chemical plants requires more maintenance and repairs to minimize production downtime. More stringent industry safety standards and environmental regulations also lead to higher maintenance standards and costs.

Contract structure. Engineering and construction contracts can be broadly categorized as either cost-reimbursable or fixed-price, sometimes referred to as lump sum. Some contracts can involve both fixed-price and cost-reimbursable elements.

Fixed-price contracts are for a fixed sum to cover all costs and any profit element for a defined scope of work. Fixed-price contracts entail more risk to us as we must predetermine both the quantities of work to be performed and the costs associated with executing the work. While fixed-price contracts involve greater risk, they also are potentially more profitable for the contractor, since the owner/customer pays a premium to transfer many risks to the contractor.

Cost-reimbursable contracts include contracts where the price is variable based upon our actual costs incurred for time and materials, or for variable quantities of work priced at defined unit rates. Profit on cost-reimbursable contracts may be based upon a percentage of costs incurred and/or a fixed amount. Cost-reimbursable contracts are generally less risky, since the owner/customer retains many of the risks.

We are continuing with our strategy to move away from offshore fixed-price EPIC contracts within our Energy and Chemicals segment. We have only two remaining major fixed-price EPIC offshore projects. As of December 31, 2005, they were substantially complete.

RESULTS OF OPERATIONS IN 2005 COMPARED TO 2004

*REVENUE:*					Increase			Percentage
Millions of dollars	2005		2004		(Decrease)			Change
Production Optimization	$	4,284	$	3,303	$	981			30	%
Fluid Systems		2,838		2,324		514			22
Drilling and Formation Evaluation		2,258		1,782		476			27
Digital and Consulting Solutions		720		589		131			22
Total Energy Services Group		10,100		7,998		2,102			26
Government and Infrastructure		8,148		9,393		(1,245	)		(13	)
Energy and Chemicals		2,746		3,075		(329	)		(11	)
Total KBR		10,894		12,468		(1,574	)		(13	)
Total revenue	$	20,994	$	20,466	$	528			3	%

Geographic - Energy Services Group segments only:
Production Optimization:
North America	$	2,380	$	1,694	$	686			40	%
Latin America		384		335		49			15
Europe/Africa/CIS		924		802		122			15
Middle East/Asia		596		472		124			26
Subtotal		4,284		3,303		981			30
Fluid Systems:
North America		1,424		1,104		320			29
Latin America		374		338		36			11
Europe/Africa/CIS		659		568		91			16
Middle East/Asia		381		314		67			21
Subtotal		2,838		2,324		514			22
Drilling and Formation Evaluation:
North America		805		610		195			32
Latin America		365		281		84			30
Europe/Africa/CIS		497		412		85			21
Middle East/Asia		591		479		112			23
Subtotal		2,258		1,782		476			27
Digital and Consulting Solutions:
North America		210		201		9			4
Latin America		221		128		93			73
Europe/Africa/CIS		168		142		26			18
Middle East/Asia		121		118		3			3
Subtotal		720		589		131			22
Total Energy Services Group revenue
by region:
North America		4,819		3,609		1,210			34
Latin America		1,344		1,082		262			24
Europe/Africa/CIS		2,248		1,924		324			17
Middle East/Asia		1,689		1,383		306			22
Total Energy Services Group revenue	$	10,100	$	7,998	$	2,102			26	%

*OPERATING INCOME (LOSS):*							Increase			Percentage
Millions of dollars	2005			2004			(Decrease)			Change
Production Optimization	$	1,106		$	633		$	473			75	%
Fluid Systems		544			348			196			56
Drilling and Formation Evaluation		483			225			258			115
Digital and Consulting Solutions		146			60			86			143
Total Energy Services Group		2,279			1,266			1,013			80
Government and Infrastructure		330			84			246			293
Energy and Chemicals		168			(426	)		594			NM
Total KBR		498			(342	)		840			NM
General corporate		(115	)		(87	)		(28	)		(32	)
Total operating income	$	2,662		$	837		$	1,825			218	%

Geographic - Energy Services Group segments only:
Production Optimization:
North America	$	765		$	376		$	389			103	%
Latin America		63			56			7			13
Europe/Africa/CIS		150			110			40			36
Middle East/Asia		128			91			37			41
Subtotal		1,106			633			473			75
Fluid Systems:
North America		332			186			146			78
Latin America		58			55			3			5
Europe/Africa/CIS		103			70			33			47
Middle East/Asia		51			37			14			38
Subtotal		544			348			196			56
Drilling and Formation Evaluation:
North America		217			102			115			113
Latin America		54			24			30			125
Europe/Africa/CIS		88			39			49			126
Middle East/Asia		124			60			64			107
Subtotal		483			225			258			115
Digital and Consulting Solutions:
North America		62			58			4			7
Latin America		17			(5	)		22			NM
Europe/Africa/CIS		46			(5	)		51			NM
Middle East/Asia		21			12			9			75
Subtotal		146			60			86			143
Total Energy Services Group
operating income by region:
North America		1,376			722			654			91
Latin America		192			130			62			48
Europe/Africa/CIS		387			214			173			81
Middle East/Asia		324			200			124			62
Total Energy Services Group
operating income	$	2,279		$	1,266		$	1,013			80	%

NM - Not Meaningful

The increase in consolidated revenue in 2005 compared to 2004 was attributable to increased revenue from our Energy Services Group, predominantly resulting from increased activity, higher utilization of our equipment, and our ability to raise prices due to higher exploration and production spending by our customers. This was partially offset by reduced activity in our government services projects, primarily in the Middle East, the winding down of offshore fixed-price EPIC operations, and other oil and gas projects nearing completion. Additionally, $80 million in estimated revenue was lost during 2005 due to Gulf of Mexico hurricanes. International revenue was 73% of consolidated revenue in 2005 and 78% of consolidated revenue in 2004, with the decrease primarily due to the decline of our government services projects abroad. Revenue from the United States Government for all geographic areas was approximately $6.6 billion or 31% of consolidated revenue in 2005 compared to $8.0 billion or 39% of consolidated revenue in 2004.

The increase in consolidated operating income was primarily due to stronger performance in our Energy Services Group resulting from improved demand due to increased rig activity and improved pricing and asset utilization. KBR’s operating income increased primarily due to the resolution of disputed fuel costs and other issues as a result of favorable settlement of government audits, improved project execution, and savings from KBR’s restructuring plan. Partially offsetting the consolidated operating income increase was an estimated $50 million adverse impact of Gulf of Mexico hurricanes in 2005, $45 million of which related to ESG and $5 million of which related to KBR.

In 2005, Iraq-related work contributed approximately $5.4 billion to consolidated revenue and $172 million to consolidated operating income, a 3.2% margin before corporate costs and taxes.

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

Production Optimization increase in revenue compared to 2004 was derived from all regions. Production enhancement services revenue grew 37% largely driven by United States onshore operations due to strong demand for stimulation services coupled with improved equipment utilization and pricing. Higher rig activity in Canada and offshore Angola and increased equipment sales to China also contributed to production enhancement services revenue growth. Revenue from sales of completion tools increased 12% compared to 2004, benefiting from improved completions and perforating sales in Angola, the United Kingdom, and the United States, and increased underbalanced applications and perforating activity in southern Mexico. These improvements were partially offset by declines in the Caspian where completions, drill stem test, and reservoir information contracts concluded in 2004 and early 2005. WellDynamics revenue more than doubled in 2005 compared to 2004 due to a large contract for intelligent well completions in the Middle East. Our Subsea 7, Inc. joint venture, which was sold in January 2005, contributed $2 million equity income in 2004. International revenue was 49% of total segment revenue in 2005 compared to 54% in 2004.

The increase in segment operating income in 2005 included a $110 million gain on the sale in 2005 of our equity interest in the Subsea 7, Inc. joint venture, partially offset by a $54 million gain on the sale of our surface well testing operations in 2004. The segment operating income improvement spanned all regions. Production enhancement services operating income increased 81% largely due to higher land rig activity and improved utilization of resources in the United States, as well as higher utilization of marine vessels offshore Angola. A 44% improvement in completion tools operating income primarily resulted from a general increase in sales and activity in the United States and higher completions and perforating activity in West Africa and the United Kingdom. WellDynamics had operating income in 2005 compared to breakeven in 2004, primarily due to improved manufacturing efficiencies and improved customer acceptance of its intelligent well completions technology. Subsea 7, Inc. contributed $2 million equity income to segment results in 2004. Hurricanes in the Gulf of Mexico in 2005 negatively impacted Production Optimization operating income by an estimated $14 million.

Fluid Systems revenue increase compared to 2004 was driven by 24% growth in cementing services revenue and 21% growth in Baroid Fluid Services revenue. All geographic regions yielded increased revenue in both product service lines, with the largest increase in the United States due to higher onshore rig activity and higher deepwater rig activity in the Gulf of Mexico, as well as improved utilization and pricing. Sales of cementing services also improved due to increased activity in Canada and the North Sea and new contract start-ups in Indonesia. Baroid Fluid Services further benefited from increased activity in Angola, Indonesia, and the United Kingdom. International revenue was 55% of total segment revenue in 2005 compared to 58% in 2004.

Fluid Systems segment operating income increase compared to 2004 resulted from 62% growth from Baroid Fluid Services and 54% growth in operating income from cementing services. Baroid Fluid Services operating income benefited primarily from increased activity and improved pricing in the United States and increased activity and an improved product mix in Africa. Cementing services results increased predominantly in North America due to increased activity and improved pricing and asset utilization and in all other geographic regions due to generally higher global drilling activity. Hurricanes in the Gulf of Mexico in 2005 negatively impacted Fluid Systems operating income by an estimated $25 million.

Drilling and Formation Evaluation revenue increase in 2005 compared to 2004 was derived from all four regions in every product service line. The segment improvement was led by a 30% increase in drilling services revenue, particularly in North America due to improved pricing, higher rig activity, and new contract awards. Increased international activity, new contract start-ups, and expanded GeoPilot® services contributed to other region revenue increases, especially evident in the North Sea, the Middle East, and Latin America. Drill bits revenue increased 26% compared to 2004, largely benefiting from increased rig counts, improved pricing, and increased sales of fixed cutter bits in the United States. Logging services revenue grew 22% primarily due to increased cased hole activity and improved pricing in the United States, sales to India of logging equipment, and new contract awards in West Africa and the Middle East. Lower sales of logging equipment to China in 2005 partially offset the logging services revenue improvement. International revenue was 71% of total segment revenue in 2005 compared to 72% in 2004.

The segment operating income increase compared to 2004 spanned all geographic regions in all product service lines, with North America as the predominant contributor due to improved pricing, increased rig activity, and growth in higher margin services. Drill bits operating income in 2005 was nearly five times that of 2004, the majority of which occurred in North America. Drilling services operating income doubled from 2004 to 2005, resulting from increased global activity, improved utilization and pricing, and continued customer acceptance of GeoPilot® and other high margin services. Equipment sales in Nigeria also contributed to drilling services operating income increase. Logging services results grew 76%, additionally benefiting from higher activity in West Africa and the Middle East and sales of logging equipment to India. The increase in segment operating income included a $24 million gain related to a patent infringement case settlement. Hurricanes in the Gulf of Mexico in 2005 negatively impacted Drilling and Formation Evaluation operating income by an estimated $6 million.

Digital and Consulting Solutions revenue increase in 2005 was largely driven by project management services, with 40% revenue growth due to increased activity in Mexico and higher commodity prices in the United States, partially offset by the winding down of projects in the Middle East and Russia. Landmark revenue increased 13% in 2005 due to data bank project growth primarily in Nigeria, increased consulting, and higher sales and services in Algeria, partially offset by nonrecurring sales in India in 2004. International revenue was 73% of total segment revenue in 2005 compared to 69% in 2004.

The segment operating income improvement partially resulted from a 77% increase in Landmark operating income due to stronger software and service sales. Included in the 2005 results was a $17 million favorable insurance settlement related to a pipe fabrication and laying project in the North Sea. This was offset by $23 million in losses in 2005 on two fixed-price integrated solutions projects in Mexico, reflecting increased costs to complete the projects and longer drilling times than originally anticipated, chiefly due to unfavorable geologic conditions. Operating income in 2004 included a $13 million release of legal liability accruals in excess of the Anglo-Dutch settlement, offset by $33 million in losses on the fixed-price integrated solutions projects in Mexico and an $11 million charge for an intellectual property settlement.

Government and Infrastructure revenue for 2005 totaled $8.1 billion, a $1.2 billion decrease compared to 2004. Iraq-related activities in the Middle East decreased $1.6 billion primarily due to completion of our RIO contract. Partially offsetting the decrease was $362 million higher revenue earned by the DML shipyard and hurricane repair efforts to United States naval facilities on the Gulf Coast under the CONCAP contract.

Operating income for 2005 was $330 million compared to $84 million in 2004, a $246 million increase. Iraq-related income increased $97 million compared to 2004, primarily due to income from the award fees on definitized LogCAP task orders, settlement of DFAC issues, and resolution of disputed fuel costs and other issues. Increased activities from our DML shipyard positively impacted 2005 operating income by $13 million. In addition, hurricane repair efforts to United States naval facilities on the Gulf Coast under the CONCAP contract contributed to the increase. The 2005 results also included a combined $96 million in operating income from the sale of and one-time cash distribution from an interest in a United States toll road. The operating income comparison was adversely impacted by completion of the RIO contract in 2004. Segment results in 2004 included restructuring charges of $12 million.

Energy and Chemicals revenue for 2005 decreased $329 million compared to 2004. Revenue from offshore EPIC projects decreased $205 million as these projects were substantially completed during 2005. Additionally, revenue from several older LNG and oil and gas projects in Africa and Australia and an olefins project in the United States collectively decreased $424 million as these projects were also completed or substantially completed in 2005. Partially offsetting the decreases were higher activity on an offshore engineering and management project in the Caspian and a crude oil facility project in Canada, totaling $76 million. Additional increases resulted from revenue earned on projects awarded in 2005 located in Australia, Indonesia, and Nigeria, totaling $220 million.

Operating income totaled $168 million in 2005 compared to a $426 million loss in 2004, a $594 million increase. Contributing to improved operating income in 2005 were stronger results on many projects, including joint venture gas projects in Nigeria, offshore engineering and project management projects in Angola and the Caspian, and recently awarded LNG and GTL projects, collectively totaling $44 million. Additionally, 2005 results benefited from $21 million of gains on sales of assets and investments. Conversely, included in 2005 operating income were $30 million of losses on an Algerian gas processing plant project and $50 million of charges related to an unconsolidated Algerian joint venture. Included in the 2004 results were a $407 million loss on the Barracuda-Caratinga project in Brazil, $47 million of losses on the same gas processing plant project in Algeria, $29 million of losses on the Belanak project in Indonesia, and restructuring charges of $28 million.

General corporate expenses were $115 million in 2005 compared to $87 million in 2004. The increase was primarily due to increases to a self-insurance reserve, higher legal and other professional expenses on specific projects, and increased corporate communication costs.

NONOPERATING ITEMS

Interest expense decreased $22 million in 2005 compared to 2004, primarily due to the amortization in 2004 of issue costs related to a master letter of credit facility that expired in the fourth quarter of 2004, the redemption in April 2005 of $500 million of our floating rate senior notes, and interest on tax deficiencies in Indonesia in 2004.

Interest income increased $20 million in 2005 compared to 2004 due to higher cash investment balances.

Foreign currency losses, net grew to $13 million in 2005 from $3 million in 2004. The increase was primarily due to losses on the British pound sterling and the euro, partially offset by gains on the Brazilian real.

Other, net decreased $16 million in 2005 compared to 2004. The 2005 year included higher costs related to our ESG accounts receivable securitization facility and sales of our United States government accounts receivable. “Other, net” in 2004 included a $6 million pretax gain on the sale of our remaining shares of National Oilwell, Inc. common stock received in the January 2003 disposition of Mono Pumps.

Provision for income taxes from continuing operations in 2005 of $79 million resulted in an effective tax rate of 3% compared to an effective tax rate of 37% in 2004. Our 2005 tax rate is lower because we recorded favorable adjustments to our valuation allowance against our deferred tax asset related to asbestos and silica liabilities in 2005 totaling $805 million. Our strong 2005 earnings, coupled with an upward revision in our estimate of future domestic taxable income in 2006 and beyond, drove these adjustments. In 2006 and beyond, we expect our effective tax rate to return to the range of 35% to 37%.

Minority interest in net income of subsidiaries increased $31 million compared to 2004 primarily due to earnings growth from the DML shipyard, our GTL joint venture project in Nigeria, and our WellDynamics joint venture.

Income (loss) from discontinued operations, net of tax in 2004 included a $778 million pretax charge for the revaluation of the 59.5 million shares of Halliburton common stock contributed to the asbestos claimant trust, a $698 million pretax charge related to the write-down of the asbestos and silica insurance receivable, a $44 million accrual related to a partitioning agreement, and an $11 million pretax charge related to a delayed-draw term facility that expired in June 2004. The remaining amount primarily consisted of professional and administrative fees related to various aspects of the asbestos and silica settlement.

RESULTS OF OPERATIONS IN 2004 COMPARED TO 2003

*REVENUE:*					Increase			Percentage
Millions of dollars	2004		2003		(Decrease)			Change
Production Optimization	$	3,303	$	2,758	$	545			20	%
Fluid Systems		2,324		2,039		285			14
Drilling and Formation Evaluation		1,782		1,643		139			8
Digital and Consulting Solutions		589		555		34			6
Total Energy Services Group		7,998		6,995		1,003			14
Government and Infrastructure		9,393		5,417		3,976			73
Energy and Chemicals		3,075		3,859		(784	)		(20	)
Total KBR		12,468		9,276		3,192			34
Total revenue	$	20,466	$	16,271	$	4,195			26	%

Geographic - Energy Services Group segments only:
Production Optimization:
North America	$	1,694	$	1,337	$	357			27	%
Latin America		335		317		18			6
Europe/Africa/CIS		802		643		159			25
Middle East/Asia		472		461		11			2
Subtotal		3,303		2,758		545			20
Fluid Systems:
North America		1,104		990		114			12
Latin America		338		258		80			31
Europe/Africa/CIS		568		516		52			10
Middle East/Asia		314		275		39			14
Subtotal		2,324		2,039		285			14
Drilling and Formation Evaluation:
North America		610		558		52			9
Latin America		281		261		20			8
Europe/Africa/CIS		412		386		26			7
Middle East/Asia		479		438		41			9
Subtotal		1,782		1,643		139			8
Digital and Consulting Solutions:
North America		201		200		1			1
Latin America		128		71		57			80
Europe/Africa/CIS		142		143		(1	)		(1	)
Middle East/Asia		118		141		(23	)		(16	)
Subtotal		589		555		34			6
Total Energy Services Group
revenue by region:
North America		3,609		3,085		524			17
Latin America		1,082		907		175			19
Europe/Africa/CIS		1,924		1,688		236			14
Middle East/Asia		1,383		1,315		68			5
Total Energy Services Group
revenue	$	7,998	$	6,995	$	1,003			14	%

*OPERATING INCOME (LOSS):*							Increase			Percentage
Millions of dollars	2004			2003			(Decrease)			Change
Production Optimization	$	633		$	413		$	220			53	%
Fluid Systems		348			251			97			39
Drilling and Formation Evaluation		225			177			48			27
Digital and Consulting Solutions		60			(15	)		75			NM
Total Energy Services Group		1,266			826			440			53
Government and Infrastructure		84			194			(110	)		(57	)
Energy and Chemicals		(426	)		(225	)		(201	)		(89	)
Shared KBR		-			(5	)		5			100
Total KBR		(342	)		(36	)		(306	)		NM
General corporate		(87	)		(70	)		(17	)		(24	)
Total operating income (loss)	$	837		$	720		$	117			16	%

Geographic - Energy Services Group segments only:
Production Optimization:
North America	$	376		$	194		$	182			94	%
Latin America		56			75			(19	)		(25	)
Europe/Africa/CIS		110			48			62			129
Middle East/Asia		91			96			(5	)		(5	)
Subtotal		633			413			220			53
Fluid Systems:
North America		186			104			82			79
Latin America		55			52			3			6
Europe/Africa/CIS		70			58			12			21
Middle East/Asia		37			37			-			-
Subtotal		348			251			97			39
Drilling and Formation Evaluation:
North America		102			60			42			70
Latin America		24			30			(6	)		(20	)
Europe/Africa/CIS		39			30			9			30
Middle East/Asia		60			57			3			5
Subtotal		225			177			48			27
Digital and Consulting Solutions:
North America		58			(52	)		110			212
Latin America		(5	)		8			(13	)		(163	)
Europe/Africa/CIS		(5	)		16			(21	)		(131	)
Middle East/Asia		12			13			(1	)		(8	)
Subtotal		60			(15	)		75			NM
Total Energy Services Group
operating income by region:
North America		722			306			416			136
Latin America		130			165			(35	)		(21	)
Europe/Africa/CIS		214			152			62			41
Middle East/Asia		200			203			(3	)		(1	)
Total Energy Services Group
operating income	$	1,266		$	826		$	440			53	%

NM - Not Meaningful

The increase in consolidated revenue in 2004 compared to 2003 was largely attributable to activity in our government services projects, primarily in the Middle East, and to increased sales of our Energy Services Group services and products as a result of the overall increase in worldwide rig counts. International revenue was 78% of consolidated revenue in 2004 and 73% of consolidated revenue in 2003, with the increase attributable to our government services projects abroad. Revenue from the United States Government for all geographic areas was approximately $8.0 billion or 39% of consolidated revenue in 2004 compared to $4.2 billion or 26% of consolidated revenue in 2003.

The increase in consolidated operating income was primarily due to stronger performance in our Energy Services Group resulting from favorable changes in oil and gas prices, which increased worldwide rig counts, and pricing improvements in the United States in 2004.

In 2004, Iraq-related work contributed approximately $7.1 billion to consolidated revenue and $78 million to consolidated operating income, a 1.1% margin before corporate costs and taxes.

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

Production Optimization increase in revenue compared to 2003 was largely attributable to production enhancement services, which yielded $430 million in higher revenue. This was driven by a higher average land gas rig count and price increases in the United States, increased activity in Canada and Russia, and increases in pipeline process services and hydraulic workover activity in the United Kingdom. Completion tools and services activities contributed $59 million to the segment revenue increase on improved activity in the Middle East/Asia and Europe/Africa/CIS regions. WellDynamics contributed $49 million to segment revenue, driven by the consolidation of the joint venture during the first quarter of 2004 and increased demand for intelligent well completions services in the Middle East and North America. Prior to 2004, WellDynamics was accounted for under the equity method in the Digital and Consulting Solutions segment. The segment’s improved revenue was partially offset by a significant reduction in sand control and completions activity in Nigeria and a $32 million decline compared to 2003 in revenue from our surface well testing operations sold in the third quarter of 2004. International revenue was 54% of total segment revenue in 2004 compared to 56% in 2003.

The increase in Production Optimization operating income for 2004 compared to 2003 was primarily driven by the higher production enhancement revenue described above, which contributed $155 million. Completion tools and services activities increase of $17 million primarily reflects higher sales of completions and sand control services in the United Kingdom and Norway and a more favorable product mix in Eurasia and Saudi Arabia, offset by a significant reduction in sand control tool sales in Nigeria in 2004. Included in the results were gains of $24 million from the sale of Halliburton Measurement Systems in the second quarter of 2003 and $54 million from the sale of our surface well testing operations in the third and fourth quarters of 2004. Segment results in 2004 also included a $2 million equity income contribution compared to a $9 million equity loss in 2003 from our Subsea 7, Inc. joint venture, largely attributable to changes in estimated project costs and claims recoveries.

Fluid Systems revenue increase in 2004 compared to 2003 was driven by a $177 million improvement in revenue from cementing activities, due primarily to increased land rig count and pricing improvements in the United States and start-up activity on recent contract awards in Mexico and Norway. Baroid Fluid Services contributed $95 million to the segment revenue increase, resulting largely from new land work in Mexico and land rig growth in the United States and Canada. These increases in segment revenue were partially offset by significantly decreased activity in the Gulf of Mexico. International revenue was 58% of total segment revenue in 2004 compared to 56% in 2003.

The Fluid Systems segment operating income increase compared to 2003 resulted from a cementing services increase of $68 million and Baroid Fluid Services increase of $22 million. These improved results occurred primarily in the United States due to increased land rig activity, improved pricing, and better utilization and cost management. Partially offsetting improved segment operating income in 2004 was a $17 million impact of reduced higher margin activity in the Gulf of Mexico. Included in 2003 results were equity losses of $7 million from the Enventure expandable casing joint venture, which did not reoccur in 2004. This joint venture is currently accounted for on a cost basis since reducing our ownership in the first quarter of 2004.

Drilling and Formation Evaluation revenue improvement in 2004 compared to 2003 was driven by a $66 million increase in logging and perforating services due to higher land rig activity and pricing improvements in the United States and equipment sales to China. Drilling services contributed $40 million to the segment revenue increase, resulting principally from new contracts in Norway and Brazil and higher activity in Canada, Venezuela, and Argentina. The increase in drilling services revenue was partially offset by a substantial decline in logging-while-drilling activity in the Gulf of Mexico. Drill bits sales increased $29 million, benefiting from increases in land rig activity, improved pricing, and better market penetration with fixed cutter and roller cone bits primarily in the United States, as well as sales growth in the Caspian Sea region and China. International revenue was 72% of total segment revenue in 2004 and in 2003.

The increase in Drilling and Formation Evaluation segment operating income was due to improved results in drilling services, which benefited from a lower depreciation expense of $35 million in 2004 compared to 2003 primarily due to extending depreciable asset lives in the second quarter of 2004. Logging and perforating services contributed $33 million to the increase, due to improved pricing and land rig activity in the United States and equipment sales in China. Drill bits contributed $12 million to improved segment results on higher revenue in the United States and the Caspian Sea region. Operating income for 2003 included a $36 million gain on the disposition of Mono Pumps in the first quarter of 2003.

Digital and Consulting Solutions revenue increased in 2004 compared to 2003 primarily due to a $27 million increase in Landmark. During 2004, Landmark achieved its highest revenue since we acquired it. Software-related sales in Landmark increased in 2004 due to strong acceptance of the new real-time (drilling) and GeoProbe® offerings. The increase in segment revenue was partially offset by a decline in subsea operations in the first half of 2004 and the absence of $11 million of revenue from Wellstream prior to the sale of this business in the first quarter of 2003. International revenue was 69% of total segment revenue in 2004 compared to 67% in 2003.

Segment operating income increased $75 million from a loss position in 2003. This segment recorded a $77 million charge related to the Anglo-Dutch lawsuit in the third quarter of 2003 and a $15 million loss on the disposition of Wellstream in the first quarter of 2003. For 2004, results were positively impacted by a $13 million release of legal liability accruals in the first quarter of 2004 pertaining to the April 2004 Anglo-Dutch settlement and increased integrated solutions operating income stemming from higher commodity prices. The increase in the segment was partially offset by a $33 million loss recorded in the fourth quarter of 2004 on two integrated solutions projects in Mexico. The loss resulted from operational start-up and subsurface problems on the initial wells, third-party and other cost increases, increased drilling times, and a work stoppage due to community blockage. The charge reflects the estimated total project loss through completion of the drilling program in mid-2006. Segment results for 2004 also included an $11 million charge for an intellectual property settlement.

Government and Infrastructure revenue increased $4.0 billion compared to 2003. The increase was primarily due to $3.7 billion higher revenue from government services contracts in the Middle East. Activities in the DML shipyard projects also contributed $108 million to increased revenue in 2004 compared to 2003.

The Government and Infrastructure operating income decrease resulted from $94 million in write-downs on infrastructure projects in Europe and Africa, a government project in Afghanistan, completion of the construction phase of a rail project in Australia, and reduction in activities in the government project in the Balkans. The 2004 results were also impacted by a restructuring charge of $12 million due to the reorganization of KBR. The charge related to personnel termination benefits. Partially offsetting the decreases was an increase in income of $14 million from Iraq-related activities primarily due to the LogCAP contract.

Energy and Chemicals decrease in revenue compared to 2003 was primarily due to lower revenue of $1.1 billion on the Barracuda-Caratinga project in Brazil, the Belanak project in Indonesia, completion of refining facilities in the United States, gas projects in Africa, offshore projects in Mexico, and a hydrocarbon project in Europe. The decrease was partially offset by higher revenue of $391 million on refining projects in Canada, an olefins project in the United States, operations and maintenance projects in the United States and the United Kingdom, and new offshore program management projects.

The operating loss for the segment in 2004 primarily resulted from $407 million of losses on the Barracuda-Caratinga project in Brazil, $47 million of losses on a gas project in Africa, and $29 million of losses on the Belanak project in Indonesia. The losses recognized on the Barracuda-Caratinga project were primarily due to the agreement with Petrobras, higher cost estimates, schedule delays, and increased contingencies for the balance of the project until completion. Specifically, in the second quarter, with the integration phase of the Barracuda vessel we experienced a significant reduction in productivity and rework required from the vessel conversion. Also included in the 2004 results was a restructuring charge of $28 million due to the reorganization of KBR. The charge related to personnel termination benefits and asset impairments. Operating losses in 2004 were partially offset by a $59 million increase on an LNG project in Egypt, a refining project in Canada, operations and maintenance projects in the United States and United Kingdom, and new offshore program management projects. The operating loss for 2003 included losses recognized on the Barracuda-Caratinga project of $238 million and losses on a hydrocarbon project in Belgium.

General corporate expenses for 2004 increased primarily due to a $7.5 million charge related to a settlement with the SEC, financing fees on outstanding credit facilities, Sarbanes-Oxley compliance expenses, and increased legal fees.

NONOPERATING ITEMS

Interest expense increased $90 million in 2004 compared to 2003, due primarily to interest on $1.2 billion convertible notes issued in June 2003, $1.05 billion senior floating and fixed notes issued in October 2003, $500 million senior floating-rate notes issued in January 2004, and interest on tax deficiencies in Indonesia and Mexico.

Interest income increased $14 million in 2004 compared to the same period in 2003, attributable to higher average daily cash balances during the year and interest on tax refunds in various jurisdictions.

Loss from discontinued operations, net of tax in 2004 included, on a pretax basis, a $778 million charge for the revaluation of 59.5 million shares of Halliburton common stock to be contributed to the asbestos claimant trust as part of the proposed settlement, a $698 million charge related to the write-down of the asbestos and silica insurance receivable, a $44 million charge related to our October 2004 partitioning agreement, and an $11 million charge related to the delayed-draw term facility, which expired in June 2004. The remaining amount primarily consisted of professional and administrative fees related to various aspects of the proposed asbestos and silica settlement, accretion on the asbestos insurance receivables, and our October 2004 partitioning agreement. The loss from discontinued operations was $1.145 billion in 2003. The benefit for income taxes on discontinued operations was $180 million in 2004, compared to a provision of $6 million for 2003. We have established a valuation allowance against the deferred tax asset arising from the asbestos and silica charges to reflect the expected net tax benefit from the future deductions the charges will create. In 2004, we increased the valuation allowance by $449 million to a balance of $1.073 billion. The balance at the end of 2003 was $624 million.

Cumulative effect of change in accounting principle, net for the year ended 2003 was an $8 million after-tax charge, or $0.02 per diluted share, related to our January 1, 2003 adoption of Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 addresses the financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated assets’ retirement costs. The asset retirement obligations primarily relate to the removal of leasehold improvements upon exiting certain lease arrangements and restoration of land associated with the mining of bentonite.

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:

percentage-of-completion accounting for contracts to provide construction, engineering, design, or similar services;

accounting for government contracts;

allowance for bad debts;

forecasting our effective tax rate, including our future ability to utilize foreign tax credits and the realizability of deferred tax assets;

legal and investigation matters; and

pensions.

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.

Percentage of completion

Revenue from contracts to provide construction, engineering, design or similar services, almost all of which relates to KBR, 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 percentage the project is complete; and

amounts of any probable unapproved claims and change orders included in revenue.

At the outset of each contract, we prepare a detailed analysis of our estimated cost to complete the project. Risks relating 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 contract revenue, 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. We are actively engaged in claims negotiations with our customers, and the success of claims negotiations has a direct impact on the profit or loss recorded for any related long-term contract. Unsuccessful claims negotiations could result in decreases in estimated contract profits or additional contract losses, and successful claims negotiations could result in increases in estimated contract profits or recovery of previously recorded contract losses.

At least quarterly, significant projects are reviewed in detail by senior management. We have a long history of dealing with multiple types of projects and in preparing cost estimates. However, 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 “Forward-Looking Information and Risk Factors.” These factors can affect the accuracy of our estimates and materially impact our future reported earnings. In the past, we have incurred substantial losses on projects that were not initially projected, including our Barracuda-Caratinga project (see “Barracuda-Caratinga project” in Note 2 of our consolidated financial statements for further discussion).

Accounting for government contracts

Most of the services provided to the United States government are governed by cost-reimbursable contracts. Services under our LogCAP, PCO Oil South, and Balkans support contracts are examples of these types of arrangements. Generally, these contracts contain both a base fee (a fixed profit percentage applied to our actual costs to complete the work) and an award fee (a variable profit percentage applied to definitized costs, which is subject to our customer’s discretion and tied to the specific performance measures defined in the contract, such as adherence to schedule, health and safety, quality of work, responsiveness, cost performance, and business management).

Base fee revenue is recorded at the time services are performed, based upon actual project costs incurred, and includes a reimbursement fee for general, administrative, and overhead costs. The general, administrative, and overhead cost reimbursement fees are estimated periodically in accordance with government contract accounting regulations and may change based on actual costs incurred or based upon the volume of work performed. Revenue is reduced for our estimate of costs that may be categorized as disputed or unallowable as a result of cost overruns or the audit process.

Award fees are generally evaluated and granted periodically by our customer. For contracts entered into prior to June 30, 2003, award fees are recognized during the term of the contract based on our estimate of amounts to be awarded. Once award fees are granted and task orders underlying the work are definitized, we adjust our estimate of award fees to actual amounts earned. Our estimates are often based on our past award experience for similar types of work. We have been receiving award fees on the Balkans project since 1995, and our estimates for award fees for this project have generally been accurate in the periods presented. During 2005, we began to receive LogCAP award fee scores, and, based on these actual amounts, we adjusted our accrual rate for future awards. The controversial nature of this contract may cause actual awards to vary significantly from past experience.

For contracts containing multiple deliverables entered into subsequent to June 30, 2003 (such as PCO Oil South), we analyze each activity within the contract to ensure that we adhere to the separation guidelines of Emerging Issues Task Force Issue No. 00-21, “Revenue Arrangements with Multiple Deliverables,” and the revenue recognition guidelines of Staff Accounting Bulletin No. 104 “Revenue Recognition.” For service-only contracts and service elements of multiple deliverable arrangements, award fees are recognized only when definitized and awarded by the customer. Award fees on government construction contracts are recognized during the term of the contract based on our estimate of the amount of fees to be awarded.

Similar to many cost-reimbursable contracts, these government contracts are typically subject to audit and adjustment by our customer. Each contract is unique; therefore, the level of confidence in our estimates for audit adjustments varies depending on how much historical data we have with a particular contract. Further, the significant size and controversial nature of our contracts may cause actual awards to vary significantly from past experience.

The estimates employed in our accounting for government contracts affect our Government and Infrastructure segment.

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 2.8% to 6.0%. At December 31, 2005, allowance for bad debts totaled $90 million or 2.8% of notes and accounts receivable before the allowance, and at December 31, 2004, allowance for bad debts totaled $127 million or 4.2% of notes and accounts receivable before the allowance. The 29% decrease in allowance for bad debts is primarily due to improved collection processes as the percentage of receivables outstanding over 90 days decreased from 19%, as of December 31, 2004, to 10% as of December 31, 2005. A 1% change in our estimate of the collectibility of our notes and accounts receivable balance as of December 31, 2005 would have resulted in a $32 million adjustment to 2005 total operating costs and expenses.

Income tax accounting

We account for our income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes,” which requires the 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 about 100 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 have recorded a valuation allowance based on the anticipated impact of the asbestos and silica deductions on our ability to utilize future foreign tax credits in the United States. 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, and such changes could have a material impact on the valuation allowance. For example, as a result of our strong 2005 earnings, coupled with an upward revision in our estimate of future domestic taxable income for 2006 and beyond, we recorded favorable adjustments to this valuation allowance in 2005 totaling $805 million.

Legal and investigation matters

As discussed in Note 12 of our consolidated financial statements, as of December 31, 2005, we have accrued an estimate of the probable and estimable costs for the resolution of some of these 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.

Pensions

Our pension benefit obligations and expenses are calculated using actuarial models and methods, in accordance with SFAS No. 87, “Employers’ Accounting for Pensions.” 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 rates of return of high-quality fixed income investments currently available and expected to be available during the period to maturity of the pension benefits. 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 to determine the projected benefit obligation at the measurement date for our United States pension plans remained flat at 5.75% at December 31, 2005 and 2004. The discount rate utilized to determine the projected benefit obligation at the measurement date for our United Kingdom pension plans, which constitute 95% of our international plans and 91% of all plans, was reduced from 5.50% at December 31, 2004 to 5.00% at December 31, 2005. This decrease in discount rate resulted in increases in the present value of our benefit obligations and plan expenses. An additional future decrease in the discount rate of 50 basis points for our United Kingdom pension plans would increase our projected benefit obligation by an estimated $400 million, while a similar increase in the discount rate would reduce our projected benefit obligation by an estimated $360 million.

Our defined benefit plans reduced pretax earnings by $84 million in 2005, $91 million in 2004, and $75 million in 2003. Included in the amounts were earnings from our expected pension returns of $196 million in 2005, $184 million in 2004, and $148 million in 2003. Unrecognized actuarial gains and losses are being recognized over a period of 4 to 32 years, which represents the expected remaining service life of the employee group. Our unrecognized actuarial gains and losses arise 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 for 2005, 2004, and 2003 were $553 million, $276 million, and $160 million, respectively. The difference between actual and expected returns is deferred as an unrecognized actuarial gain or loss and is recognized as future pension expense. Our unrecognized actuarial loss at December 31, 2005 was $678 million, of which $31 million will be recognized as a component of our expected 2006 pension expense. During 2005, we made contributions to fund our defined benefit plans of $81 million. We expect to make additional contributions in 2006 of approximately $164 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.

OFF BALANCE SHEET RISK

Under an agreement to sell United States Energy Services Group accounts receivable to a bankruptcy-remote limited-purpose funding subsidiary, new receivables were added on a continuous basis to the pool of receivables. Collections reduced previously sold accounts receivable. This funding subsidiary sold an undivided ownership interest in this pool of receivables to entities managed by unaffiliated financial institutions under another agreement. Sales to the funding subsidiary were structured as “true sales” under applicable bankruptcy laws. While the funding subsidiary was wholly owned by us, its assets were not available to pay any creditors of ours or of our subsidiaries or affiliates. The undivided ownership interest in the pool of receivables sold to the unaffiliated companies, therefore, was reflected as a reduction of accounts receivable in our consolidated balance sheets. The funding subsidiary retained the interest in the pool of receivables that were not sold to the unaffiliated companies and was fully consolidated and reported in our financial statements.

The amount of undivided interests which could be sold under the program varied based on the amount of eligible Energy Services Group receivables in the pool at any given time and other factors. The maximum amount that could be sold and outstanding under this agreement at any given time was $300 million. As of December 31, 2004, we had sold $256 million of undivided ownership interest to unaffiliated companies. During the fourth quarter of 2005, these receivables were collected and the balance retired. No further receivables were sold, and the facility was terminated subsequent to December 31, 2005.

In May 2004, we entered into an agreement to sell, assign, and transfer the entire title and interest in specified United States government accounts receivable of KBR to a third party. The face value of the receivables sold to the third party was reflected as a reduction of accounts receivable in our consolidated balance sheets. The amount of receivables that could be sold under the agreement varied based on the amount of eligible receivables at any given time and other factors, and the maximum amount that could be sold and outstanding under this agreement at any given time was $650 million. The total amount of receivables outstanding under this agreement as of December 31, 2004 was approximately $263 million. As of December 31, 2005, these receivables were collected, the balance was retired, and the facility was terminated.

We have exposure to losses in certain unconsolidated variable interest entities. See Note 19 to the consolidated financial statements for more information.

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. We selectively manage these exposures through the use of derivative instruments to mitigate our market risk from these exposures. The objective of our risk management 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 17 to the consolidated financial statements for additional disclosures related to derivative 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, 2005 and related weighted average interest rates on the repaid amounts by year of maturity for our long-term debt.

Millions of dollars	2006			2007			2008			2009		2010			Thereafter			Total
Fixed-rate debt:
Repayment amount ($US)	$	275		$	-		$	150		$	-	$	750		$	1,875		$	3,050
Weighted average interest
rate on repaid amount		6.0	%		-			5.6	%		-		5.5	%		4.8	%		5.1	%
Variable-rate debt:
Repayment amount ($US)	$	68		$	16		$	2		$	-	$	-		$	-		$	86
Weighted average interest
rate on repaid amount		6.9	%		5.7	%		6.0	%		-		-			-			6.7	%

The fair market value of long-term debt was $2.9 billion as of December 31, 2005.

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 Resources 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 $50 million as of December 31, 2005 and $41 million as of December 31, 2004. The liability covers numerous properties and no individual property accounts for more than $10 million of the liability balance. We have subsidiaries that have been named as potentially responsible parties along with other third parties for 14 federal and state superfund sites for which we have established a liability. As of December 31, 2005, those 14 sites accounted for approximately $13 million of our total $50 million liability. In some instances, we have been named a potentially responsible party by a regulatory agency, but in each of those cases, we do not believe we have any material liability.

NEW ACCOUNTING PRONOUNCEMENTS

In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” This statement clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. The provisions of FIN 47 were adopted as of December 31, 2005. The total liability recorded at adoption for asset retirement obligations and the related accretion and depreciation expense for all periods presented is immaterial to our consolidated financial position and results of operations. We own properties where we have below ground storage tanks, test wells, and other items that are required to be removed before we vacate the properties. A liability has not been recorded for these items because the fair value cannot be reasonably estimated. We believe there is an indeterminate settlement date for these obligations because the range of time over which we may settle the obligation is unknown or cannot be estimated.

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R is a revision of SFAS No. 123 and supersedes APB No. 25. In April 2005, the SEC adopted a rule that defers the required effective date of SFAS No. 123R. The SEC rule provides that SFAS No. 123R is now effective for registrants as of the beginning of the first fiscal year beginning after June 15, 2005. We adopted the provisions of SFAS No. 123R on January 1, 2006 using the modified prospective application. Accordingly, we will recognize compensation expense for all newly granted awards and awards modified, repurchased, or cancelled after January 1, 2006. Compensation expense for the unvested portion of awards that were outstanding as of January 1, 2006 will be recognized ratably over the remaining vesting period based on the fair value at date of grant as calculated under the Black-Scholes option pricing model. Compensation expense related to the unvested portion of these awards will be consistent with compensation expense included in our pro forma disclosure under SFAS No. 123. We will recognize compensation expense using the Black-Scholes pricing model for our Employee Stock Purchase Plan (ESPP) beginning with the January 1, 2006 purchase period.

We estimate that the effect on earnings per share in the periods following adoption of SFAS No. 123R will be a reduction of approximately $0.01 to $0.02 in net income per diluted share per quarter. This effect is consistent with our pro forma disclosure under SFAS No. 123 except that estimated forfeitures will be considered in the calculation of compensation expense under SFAS No. 123R. Additionally, the actual effect on net income and earnings per share will vary depending upon the number of options granted in subsequent periods compared to prior years and the number of shares purchased under the ESPP.

FORWARD-LOOKING INFORMATION AND RISK FACTORS

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, including the risks related to:

United States Government Contract Work

We provide substantial work under our government contracts to the United States Department of Defense and other governmental agencies. These contracts include our worldwide United States Army logistics contracts, known as LogCAP, and contracts to rebuild Iraq’s petroleum industry such as PCO Oil South. Our government services revenue related to Iraq totaled approximately $5.4 billion in 2005, $7.1 billion in 2004, and $3.6 billion in 2003. Most of the services provided to the United States government are subject to cost-reimbursable contracts where we have the opportunity to earn an award fee based on our customer’s evaluation of the quality of our performance. These award fees are evaluated and granted by our customer periodically. For the LogCAP and RIO contracts, we recognize award fees based on our estimate of amounts to be awarded. In determining our estimates, we consider, among other things, past award experience for similar types of work. These estimates are adjusted to actual when the task orders are definitized and the award fees have been finalized by our customer.

DCAA audit issues

Our operations under United States government contracts are regularly reviewed and audited by the DCAA and other governmental agencies. The DCAA serves in an advisory role to our customer. When issues are found during the governmental agency audit process, these issues are typically discussed and reviewed with us. The DCAA then issues an audit report with its recommendations to our customer’s contracting officer. In the case of management systems and other contract administrative issues, the contracting officer is generally with the DCMA. We then work with our customer to resolve the issues noted in the audit report. If our customer or a government auditor finds that we improperly charged any costs to a contract, these costs are not reimbursable, or, if already reimbursed, the costs must be refunded to the customer.

Investigations

Withholding of payments

DCMA system reviews

The Balkans

We have had inquiries in the past by the DCAA and the civil fraud division of the DOJ into possible overcharges for work performed during 1996 through 2000 under a contract in the Balkans for which inquiry has not yet been completed by the DOJ. Based on an internal investigation, we credited our customer approximately $2 million during 2000 and 2001 related to our work in the Balkans as a result of billings for which support was not readily available. We believe that the preliminary DOJ inquiry relates to potential overcharges in connection with a part of the Balkans contract under which approximately $100 million in work was done. We believe that any allegations of overcharges would be without merit. Amounts accrued related to this matter as of December 31, 2005 are not material.

Development Fund for Iraq

We have some task orders issued and executed under the PCO Oil contract that are funded under the Development Fund for Iraq (DFI). We received notification in the third quarter of 2005 that United States government personnel have decided to cease all administration of DFI funded contracts after December 31, 2005. In December 2005, we received notification that this deadline was deferred until December 31, 2006. If not deferred again at year end 2006, that could mean that we may be required to obtain payment for all services provided under the affected task orders after that date and for all invoices submitted and not paid prior to that date from the sovereign Republic of Iraq. As our PCO Oil contract is with the United States government, it is unclear what the ramifications of such a change in funding, if implemented, would have or what the financial implications would be.

Foreign Corrupt Practices Act investigations

The SEC and the DOJ have been reviewing these matters in light of the requirements of the FCPA. We have been cooperating with the SEC and the DOJ, as well as with investigations into the Bonny Island project in France and Nigeria. Our Board of Directors has appointed a committee of independent directors to oversee and direct the FCPA investigations.

Until such time, if ever, as we can satisfy ourselves regarding compliance with applicable law and our Code of Business Conduct, we have also suspended the services of another agent who has worked for KBR outside of Nigeria on several current projects and on numerous older projects going back to the early 1980’s. In addition, we are actively reviewing the compliance of an additional agent on a separate current Nigerian project with respect to which we have recently received from a joint venture partner on that project allegations of wrongful payments made by such agent. 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 banks in Switzerland transferred to Nigeria and to have the legal ownership of such sums determined in the Nigerian courts.

In addition, we understand that the actions of some officers and key employees within our KBR Energy and Chemicals segment are of interest to the SEC and the DOJ in the FCPA investigations. If, as a result of these investigations, or as a result of our determining that their conduct was inconsistent with employment by a publicly-held company, one or more of these officers or employees were to take a leave of absence or resign or were temporarily or permanently relieved of their duties, such events could have a material adverse effect on our business.

As of December 31, 2005, we have not accrued any amounts related to this investigation other than our current legal expenses.

Bidding practices investigation

There can be no assurance that the results of these investigations will not have a material adverse effect on our business and results of operations.

As of December 31, 2005, we had not accrued any amounts related to this investigation other than our current legal expenses.

Operations in Iran

We received and responded to an inquiry in mid-2001 from the Office of Foreign Assets Control (OFAC) of the United States Treasury Department with respect to operations in Iran by a Halliburton subsidiary incorporated in the Cayman Islands. The OFAC inquiry requested information with respect to compliance with the Iranian Transaction Regulations. These regulations prohibit United States citizens, including United States corporations and other United States business organizations, from engaging in commercial, financial, or trade transactions with Iran, unless authorized by OFAC or exempted by statute. Our 2001 written response to OFAC stated that we believed that we were in compliance with applicable sanction regulations. In January 2004, we received a follow-up letter from OFAC requesting additional information. We responded to this request on March 19, 2004. We understand this matter has now been referred by OFAC to the DOJ. In July 2004, we received a grand jury subpoena from an Assistant United States District Attorney requesting the production of documents. We are cooperating with the government’s investigation and have responded to the subpoena by producing documents on September 16, 2004.

Separate from the OFAC inquiry, we completed a study in 2003 of our activities in Iran during 2002 and 2003 and concluded that these activities were in compliance with applicable sanction regulations. These sanction regulations require isolation of entities that conduct activities in Iran from contact with United States citizens or managers of United States companies. Notwithstanding our conclusions that our activities in Iran were not in violation of United States laws and regulations, we announced that, after fulfilling our current contractual obligations within Iran, we intend to cease operations within that country and to withdraw from further activities there.

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 73% of our consolidated revenue during 2005, 78% of our consolidated revenue during 2004, and 73% of consolidated revenue in 2003. Based upon the location of services provided and products sold, 24% of our consolidated revenue in 2005, 26% during 2004, and 15% during 2003 was from Iraq, primarily related to our work for the United States Government. Also, 10% of our consolidated revenue during 2005 was from the United Kingdom. Operations in countries other than the United States are subject to various risks peculiar 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 and countries in which we provide governmental logistical support, 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 amounts of political risk include: Afghanistan, Algeria, Indonesia, Iran, Iraq, Nigeria, Russia, and Venezuela. 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. In September 2004, the Federal Republic of Nigeria issued a directive to one of our subsidiaries banning us from receiving new contracts from the Nigerian government or from companies controlled by the Nigerian government. We believe this directive to have been originally issued as a result of an adverse reaction in Nigeria to the theft from us of radioactive material that we used in wireline logging operations, which was subsequently recovered and returned to Nigeria. We received official notification that the contract ban had been lifted on September 7, 2005. Subsequently, by letters dated December 19, 2005, we were notified by the Nigerian Nuclear Regulatory Authority that we had been issued licenses to use radioactive sources.

Our facilities and our employees are under threat of attack in some countries where we operate, including Iraq and Saudi Arabia. In addition, the risk related to loss of life of our personnel and our subcontractors in these areas continues.

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 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 about 100 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 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 are 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 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 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 and capital expenditures for refining and distribution facilities 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.

Governmental and capital spending

Our business is directly affected by changes in governmental spending and capital expenditures by our customers. Some of the changes that may materially and adversely affect us include:

a decrease in the magnitude of governmental spending and outsourcing for military and logistical support of the type that we provide. For example, the current level of government services being provided in the Middle East will not likely continue for an extended period of time and the current rate of spending has decreased substantially compared to 2005 and 2004. We expect the volume of work under our LogCAP contract to continue to decline in 2006 as our customer scales back the amount of services we provide. The government can terminate, reduce the amount of work, or replace our LogCAP contract with a new competitively bid contract at anytime during the term of the contract;

an increase in the magnitude of governmental spending and outsourcing for military and logistical support, which can materially and adversely affect our liquidity needs as a result of additional or continued working capital requirements to support this work;

a decrease in capital spending by governments for infrastructure projects of the type that we undertake;

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 affects the timing of contract negotiations and settlements of claims and claim negotiations with engineering and construction customers on cost variances and change orders on major projects;

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, production, processing, refining, and pipeline delivery networks; and

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

Customers

Both our Energy Services Group and KBR depend on a limited number of significant customers. While, except for the United States Government, 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;

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.

We own a 36.7% interest in a joint venture that is the holder of a 50-year concession contract with the Australian government to operate and maintain a railway in Australia. We account for this investment on the equity method of accounting. Construction on the railway was completed in late 2003, and operations commenced in early 2004. This joint venture continues to gain new customers and believes that the originally planned customer base will ultimately be developed, although results through December 2005 have been less than planned. As a result, this joint venture has incurred inception-to-date losses, of which our share is $37 million, which have been recorded in our financial statements as a loss and a reduction to our investment balance in this company. As of December 31, 2005, our investment in this joint venture and the related company that performed the construction of the railroad was $87 million. In addition, we have a remaining commitment to purchase an additional $9 million subordinated operating note.

Unless revenue is increased, this joint venture may violate certain loan covenants in the future. Management of this joint venture is currently undertaking a reforecast of the business, which they expect to complete during the first quarter of 2006. The results of this reforecast will be used to review the projected financial status of this joint venture, including the possible need for future financial restructurings, and will be used by us to assess any impairment in our investment.

Risks related to contracts

Our long-term contracts to provide services are either on a cost-reimbursable basis or on a fixed-price basis. Our failure to estimate accurately the resources and time required for a fixed-price project or our failure to complete our contractual obligations within the time frame and costs committed could have a material adverse effect on our business, results of operations, and financial condition. In connection with projects covered by fixed-price contracts, we bear the risk of cost over-runs, operating cost inflation, labor availability and productivity, and supplier and subcontractor pricing and performance. In both our fixed-price contracts and our cost-reimbursable contracts, we generally rely on third parties for many support services, and we are subject to liability for engineering or systems failures. Occasionally we contract to perform work for, as well as take a minority ownership interest in, a developmental entity. We may incur contractually reimbursable costs, make an equity investment prior to this entity achieving operational status or completing its full project financing. Should a developmental project fail to achieve full financial close, we could incur losses including our contractual receivables and our equity investment.

Risks under our fixed-price contracts. Our significant EPC projects may encounter difficulties that may result in additional costs to us, reductions in revenue, claims, or disputes. These projects generally involve complex design and engineering, significant procurement of equipment and supplies, and extensive construction management. Many of these projects involve design and engineering production and construction phases that may occur over extended time periods, often in excess of two years. We could encounter difficulties that may be beyond our control in design, engineering, equipment and supply delivery, schedule changes, and other factors. These factors could impact our ability to complete the project in accordance with the original delivery schedule. For example, the equipment we purchase for a project or that is provided to us by the customer could not perform as expected, and these performance failures may result in delays in completion of the project or additional costs to us or the customer to complete the project and, in some cases, may require us to obtain alternate equipment at additional cost.

In addition, some of our contracts may require that our customers provide us with design or engineering information or with equipment or materials to be used on the project. In some cases, the customer may provide us with deficient design or engineering information or equipment or may provide the information or equipment to us later than required by the project schedule. The customer may also determine, after commencement of the project, to change various elements of the project. Our project contracts generally require the customer to compensate us for additional work or expenses incurred due to customer-requested change orders or failure of the customer to provide us with specified design or engineering information or equipment. Under these circumstances, we generally negotiate with the customer with respect to the amount of additional time required and the compensation to be paid to us. We are subject to the risk that we are unable to obtain, through negotiation, arbitration, litigation, or otherwise, adequate amounts to compensate us for the additional work or expenses incurred by us due to customer-requested change orders or failure by the customer to timely provide required items. A failure to obtain adequate compensation for these matters could require us to record an adjustment to amounts of revenue and gross profit that were recognized in prior periods. Any such adjustments, if substantial, could have a material adverse effect on our results of operations and financial condition.

We may be required to pay liquidated damages upon our failure to meet schedule or performance requirements of our contracts. In certain circumstances, we guarantee facility completion by a scheduled acceptance date or achievement of certain acceptance and performance testing levels. Failure to meet any such schedule or performance requirements could result in additional costs, and the amount of such additional costs could exceed projected profit margins for the project. These additional costs include liquidated damages paid under contractual penalty provisions, which can be substantial and can accrue on a daily basis. In addition, our actual costs could exceed our projections. Performance problems for existing and future contracts could cause actual results of operations to differ materially from those anticipated by us and could cause us to suffer damage to our reputation within our industry and our client base.

Risks under our fixed-price or cost-reimbursable contracts. We generally rely on third-party subcontractors as well as third-party equipment manufacturers to assist us with the completion of our contracts. To the extent that we cannot engage subcontractors or acquire equipment or materials, our ability to complete a project in a timely fashion or at a profit may be impaired. If the amount we are required to pay for these goods and services exceeds the amount we have estimated in bidding for fixed-price work, we could experience losses in the performance of these contracts. Any delay by subcontractors to complete their portion of the project, or any failure by a subcontractor to satisfactorily complete its portion of the project, and other factors beyond our control may result in delays in the overall progress of the project or may cause us to incur additional costs, or both. These delays and additional costs may be substantial, and we may be required to compensate the project customer for these delays. While we may recover these additional costs from the responsible vendor, subcontractor, or other third party, we may not be able to recover all of these costs in all circumstances. In addition, if a subcontractor or a manufacturer is unable to deliver its services, equipment, or materials according to the negotiated terms for any reason, including the deterioration of its financial condition, we may be required to purchase the services, equipment, or materials from another source at a higher price. This may reduce the profit or award fee to be realized or result in a loss on a project for which the services, equipment, or materials were needed.

Our projects expose us to potential professional liability, product liability, warranty, and other claims. We engineer, construct, and perform services in large industrial facilities in which accidents or system failures can be disastrous. Any catastrophic occurrences in excess of insurance limits at locations engineered or constructed by us or where our services are performed could result in significant professional liability, product liability, warranty, and other claims against us. The failure of any systems or facilities that we engineer or construct could result in warranty claims against us for significant replacement or reworking costs. In addition, once our construction is complete, we may face claims with respect to the performance of these facilities.

Barracuda-Caratinga project. The Barracuda and Caratinga vessels are both fully operational. We reached agreement with Petrobras, subject to Lender's consent that enables us to achieve conclusion of the Lenders' Reliability Test and final acceptance of the FPSOs. These acceptances eliminate any further risk of liquidated damages being assessed. Pursuant to the agreed terms, FPSO Final Acceptance will occur during the first quarter of 2006.

In addition, at Petrobras’ direction, we have replaced certain bolts located on the subsea flow-lines that have failed through mid-November 2005, and we understand that additional bolts have failed thereafter, which have been replaced by Petrobras. These failed bolts were identified by Petrobras when it conducted inspections of the bolts. The original design specification for the bolts was issued by Petrobras, and as such, we believe the cost resulting from any replacement is not our responsibility. Petrobras has indicated, however, that they do not agree with our conclusion. We have notified Petrobras that this matter is in dispute. We believe several possible solutions may exist, including replacement of the bolts. Estimates indicate that costs of these variouis solutions range up to $140 million. Should Petrobras instruct us to replace the subsea bolts, the prime contract terms and conditions regarding change orders require that Petrobras make progress payments of our reasonable costs incurred. Petrobras could, however, perform any replacement of the bolts and seek reimbursement from KBR. On March 9, 2006 Petrobras notified KBR that they have submitted this matter to arbitration claiming $220 million plus interest for the cost of monitoring and replacing the defective stud bolts and, in addition, all of the costs and expenses of the arbitration including the cost of attorneys fees. We do not understand the basis for the amount claimed by Petrobras. We intend to vigorously defend ourselves and pursue recovery of the costs we have incurred to date through the arbitration process. See Note 2 to the consolidated financial statements for more information.

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 clean-up 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.

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

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.

Systems

Our business could be materially and adversely affected by problems encountered in the installation of a new SAP financial system to replace the current systems for KBR.

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 businesses 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;

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 Energy Services Group’s United States 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, 2005 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, 2005, our internal control over financial reporting is effective.

Our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by our independent registered public accounting firm, KPMG LLP.

HALLIBURTON COMPANY

/s/ David J. Lesar	/s/ C. Christopher Gaut
David J. Lesar	C. Christopher Gaut
Chairman of the Board,	Executive Vice President and
President, and	Chief Financial Officer
Chief Executive 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, 2005 and December 31, 2004, 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, 2005. 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, 2005 and December 31, 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Halliburton Company’s internal control over financial reporting as of December 31, 2005, 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 March 3, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

March 3, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders

Halliburton Company:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Halliburton Company maintained effective internal control over financial reporting as of December 31, 2005, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and 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, management’s assessment that Halliburton Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control - Integrated Framework issued by COSO. Also, in our opinion, Halliburton Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Halliburton Company and subsidiaries as of December 31, 2005 and 2004, 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, 2005, and our report dated March 3, 2006 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

March 3, 2006

HALLIBURTON COMPANY

Consolidated Statements of Operations

	Years ended December 31
Millions of dollars and shares except per share data	2005			2004			2003
Revenue:
Services	$	18,420		$	18,327		$	14,383
Product sales		2,587			2,137			1,863
Equity in earnings (losses) of unconsolidated affiliates, net		(13	)		2			25
Total revenue		20,994			20,466			16,271
Operating costs and expenses:
Cost of services		16,017			17,441			13,589
Cost of sales		2,129			1,882			1,679
General and administrative		380			361			330
Gain on sale of business assets, net		(194	)		(55	)		(47	)
Total operating costs and expenses		18,332			19,629			15,551
Operating income		2,662			837			720
Interest expense		(207	)		(229	)		(139	)
Interest income		64			44			30
Foreign currency losses, net		(13	)		(3	)		-
Other, net		(14	)		2			1
Income from continuing operations before income taxes, minority
interest, and change in accounting principle		2,492			651			612
Provision for income taxes		(79	)		(241	)		(234	)
Minority interest in net income of subsidiaries		(56	)		(25	)		(39	)
Income from continuing operations before change in accounting
principle		2,357			385			339
Income (loss) from discontinued operations, net of tax (provision) benefit
of $(1), $180, and $(6)		1			(1,364	)		(1,151	)
Cumulative effect of change in accounting principle, net of tax benefit of $5		-			-			(8	)
Net income (loss)	$	2,358		$	(979	)	$	(820	)

Basic income (loss) per share:
Income from continuing operations before change in accounting principle	$	4.67		$	0.88		$	0.78
Income (loss) from discontinued operations, net		-			(3.13	)		(2.65	)
Cumulative effect of change in accounting principle, net		-			-			(0.02	)
Net income (loss)	$	4.67		$	(2.25	)	$	(1.89	)

Diluted income (loss) per share:
Income from continuing operations before change in accounting principle	$	4.54		$	0.87		$	0.78
Income (loss) from discontinued operations, net		-			(3.09	)		(2.64	)
Cumulative effect of change in accounting principle, net		-			-			(0.02	)
Net income (loss)	$	4.54		$	(2.22	)	$	(1.88	)

Basic weighted average common shares outstanding		505			437			434
Diluted weighted average common shares outstanding		519			441			437

See notes to consolidated financial statements.

HALLIBURTON COMPANY

Consolidated Balance Sheets

	December 31
Millions of dollars and shares except per share data	2005			2004
Assets
Current assets:
Cash and equivalents	$	2,391		$	1,917
Investments in marketable securities		-			891
Receivables:
Notes and accounts receivable (less allowance for bad debts of $90 and $127)		3,152			2,873
Unbilled work on uncompleted contracts		1,456			1,812
Insurance for asbestos- and silica-related liabilities		193			1,066
Total receivables		4,801			5,751
Inventories		953			791
Current deferred income taxes		592			301
Other current assets		590			379
Total current assets		9,327			10,030
Property, plant, and equipment, net of accumulated depreciation of $3,838 and $3,674		2,648			2,553
Noncurrent deferred income taxes		838			780
Goodwill		765			795
Equity in and advances to related companies		382			541
Insurance for asbestos- and silica-related liabilities		203			350
Other assets		847			815
Total assets	$	15,010		$	15,864
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	1,967		$	2,339
Advanced billings on uncompleted contracts		661			553
Accrued employee compensation and benefits		648			473
Current maturities of long-term debt		361			347
Short-term notes payable		22			15
Asbestos- and silica-related liabilities		-			2,408
Other current liabilities		778			997
Total current liabilities		4,437			7,132
Long-term debt		2,813			3,593
Employee compensation and benefits		718			635
Other liabilities		525			464
Total liabilities		8,493			11,824
Minority interest in consolidated subsidiaries		145			108
Shareholders’ equity:
Common shares, par value $2.50 per share - authorized 1,000 shares, issued 527 and 458 shares		1,317			1,146
Paid-in capital in excess of par value		2,818			277
Common shares to be contributed to asbestos trust - 59.5 shares		-			2,335
Deferred compensation		(98	)		(74	)
Accumulated other comprehensive income		(266	)		(146	)
Retained earnings		2,975			871
		6,746			4,409
Less 13 and 16 shares of treasury stock, at cost		374			477
Total shareholders’ equity		6,372			3,932
Total liabilities and shareholders’ equity	$	15,010		$	15,864

See notes to consolidated financial statements.

HALLIBURTON COMPANY

Consolidated Statements of Shareholders’ Equity

Millions of dollars and shares	2005			2004			2003
Balance at January 1	$	3,932		$	2,547		$	3,558
Dividends and other transactions with shareholders		202			(123	)		(174	)
Common shares to be contributed to asbestos
trust - 59.5 shares		-			2,335			-

Comprehensive income (loss):
Net income (loss)		2,358			(979	)		(820	)

Cumulative translation adjustments		(48	)		33			43
Realization of (gains) losses included in net
income (loss)		7			(1	)		15
Net cumulative translation adjustments		(41	)		32			58

Pension liability adjustments		(54	)		115			(88	)

Unrealized gains (losses) on investments and
derivatives		(12	)		5			13
Realization of gains on investments and
derivatives		(13	)		-			-
Net unrealized gains (losses) on investments
and derivatives		(25	)		5			13

Total comprehensive income (loss)		2,238			(827	)		(837	)

Balance at December 31	$	6,372		$	3,932		$	2,547

See notes to consolidated financial statements.

HALLIBURTON COMPANY

Consolidated Statements of Cash Flows

	Years ended December 31
Millions of dollars	2005			2004			2003
Cash flows from operating activities:
Net income (loss)	$	2,358		$	(979	)	$	(820	)
Adjustments to reconcile net income (loss) to net cash from operations:
(Income) loss from discontinued operations		(1	)		1,364			1,151
Depreciation, depletion, and amortization		504			509			518
Provision (benefit) for deferred income taxes, including $0, $(167), and $27
related to discontinued operations		(235	)		(176	)		(86	)
Distributions from (advances to) related companies, net of equity in
(earnings) losses		39			(39	)		13
Change in accounting principle, net		-			-			8
Gain on sale of assets		(192	)		(62	)		(52	)
Asbestos and silica liability payment related to Chapter 11 filing		(2,345	)		(119	)		(311	)
Collection of asbestos- and silica-related insurance receivables		1,032			-			-
Other changes:
Receivables and unbilled work on uncompleted contracts		423			(506	)		(1,442	)
Accounts receivable facilities transactions		(519	)		519			(180	)
Inventories		(152	)		(33	)		(50	)
Accounts payable		(317	)		439			733
Other		106			11			(257	)
Total cash flows from operating activities		701			928			(775	)
Cash flows from investing activities:
Capital expenditures		(651	)		(575	)		(515	)
Sales of property, plant, and equipment		132			166			107
Dispositions of business assets, net of cash disposed		299			127			230
Acquisitions of business assets, net of cash acquired		(108	)		(25	)		(6	)
Proceeds from sales of securities		15			22			57
Sales (purchases) of short-term investments in marketable securities, net		891			(180	)		(576	)
Investments - restricted cash		1			89			(18	)
Other investing activities		(69	)		(30	)		(51	)
Total cash flows from investing activities		510			(406	)		(772	)
Cash flows from financing activities:
Proceeds from long-term debt, net of offering costs		24			496			2,192
Proceeds from exercises of stock options		342			63			21
Payments to reacquire common stock		(12	)		(7	)		(6	)
Borrowings (repayments) of short-term debt, net		10			(7	)		(32	)
Payments on long-term debt		(823	)		(20	)		(296	)
Payments of dividends to shareholders		(254	)		(221	)		(219	)
Other financing activities		(7	)		(21	)		(24	)
Total cash flows from financing activities		(720	)		283			1,636
Effect of exchange rate changes on cash		(17	)		8			43
Increase in cash and equivalents		474			813			132
Cash and equivalents at beginning of year		1,917			1,104			972
Cash and equivalents at end of year	$	2,391		$	1,917		$	1,104
Supplemental disclosure of cash flow information:
Cash payments during the year for:
Interest	$	210		$	211		$	114
Income taxes	$	282		$	265		$	173

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 and a leading provider of engineering and construction services. We have six business segments that are organized around how we manage our business: Production Optimization, Fluid Systems, Drilling and Formation Evaluation, and Digital and Consulting Solutions, collectively, the Energy Services Group (ESG); and Government and Infrastructure and Energy and Chemicals, collectively known as KBR. Through the ESG, we provide a comprehensive range of services and products for the exploration, development, and production of oil and gas. We serve major, national, and independent oil and gas companies throughout the world. KBR provides a wide range of services to energy, chemical, and industrial customers and to governmental entities worldwide.

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 (see Note 19). 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.

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

Revenue recognition

Overall. Our service 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 revenues, including training and consulting services, are 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 contracts to provide construction, engineering, design, or similar services, almost all of which relates to KBR, is reported on the percentage-of-completion method of accounting. Progress is generally based upon physical progress, man-hours, or costs incurred, depending on the type of job. All known or anticipated losses on contracts are provided for when they become evident. Claims and change orders 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.

Accounting for government contracts. Most of the services provided to the United States government are governed by cost-reimbursable contracts. Services under our LogCAP, PCO Oil South, and Balkans support contracts are examples of these types of arrangements. Generally, these contracts contain both a base fee (a fixed profit percentage applied to our actual costs to complete the work) and an award fee (a variable profit percentage applied to definitized costs, which is subject to our customer’s discretion and tied to the specific performance measures defined in the contract, such as adherence to schedule, health and safety, quality of work, responsiveness, cost performance, and business management). Similar to many cost-reimbursable contracts, these government contracts are typically subject to audit and adjustment by our customer.

For contracts containing multiple deliverables entered into subsequent to June 30, 2003 (such as PCO Oil South), we analyze each activity within the contract to ensure that we adhere to the separation guidelines of Emerging Issues Task Force Issue No. 00-21, “Revenue Arrangements with Multiple Deliverables,” and the revenue recognition guidelines of Staff Accounting Bulletin No. 104, “Revenue Recognition.” For service-only contracts and service elements of multiple deliverable arrangements, award fees are recognized only when definitized and awarded by the customer. Award fees on government construction contracts are recognized during the term of the contract based on our estimate of the amount of fees to be awarded.

Research and development

Research and development expenses are charged to income as incurred. Research and development expenses were $220 million in 2005, $234 million in 2004, and $221 million in 2003, 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 $21 million in 2005, $16 million in 2004, and $17 million in 2003. Amortization expense of software development costs was $22 million for 2005 and 2004 and $17 million for 2003. 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.

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, financial condition of our customers, and whether the receivables involve retentions.

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. Some assets are depreciated on accelerated methods. 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. We follow the successful efforts method of accounting for oil and gas properties.

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.

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 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. Taxes are provided as necessary with respect to earnings that are not permanently reinvested. The American Job Creations Act of 2004 introduced a special dividends received deduction with respect to the repatriation of certain foreign earnings to a United States taxpayer under certain circumstances. Based on our analysis of the Act, we decided not to utilize the special deduction.

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 that are not hedges are adjusted to fair value and reflected through the results of operations. If the derivative is designated as a hedge, depending on the nature of the hedge, changes in the fair value of derivatives are either offset against:

the change in fair value of the hedged assets, liabilities, or firm commitments through earnings; or

recognized in other comprehensive income until the hedged item is recognized in earnings.

The ineffective portion of a derivative’s change in fair value is recognized in earnings. Recognized gains or losses on derivatives entered into to manage foreign exchange risk are included in foreign currency gains and losses in the consolidated statements of income. Gains or losses on interest rate derivatives are included in interest expense, and gains or losses on commodity derivatives are included in operating income.

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

At December 31, 2005, we have six stock-based employee compensation plans. We account for these plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. No cost for stock options granted is reflected in net income, as all options granted under our plans have an exercise price equal to the market value of the underlying common stock on the date of grant. In addition, no cost for the Employee Stock Purchase Plan (ESPP) is reflected in net income because it is not considered a compensatory plan.

The fair value of options at the date of grant was estimated using the Black-Scholes option pricing model. The weighted average assumptions and resulting fair values of options granted are as follows:

	Assumptions											Weighted Average
				Expected								Fair Value of
	Risk-Free Interest Rate			Dividend Yield			Expected Life (in years)		Expected Volatility			Options Granted
2005		4.3	%		0.8	%		5		51	%	$	22.83
2004		3.7	%		1.3	%		5		54	%	$	13.37
2003		3.2	%		1.9	%		5		59	%	$	12.37

Included in the pro forma compensation table below is the fair value of the ESPP shares. The fair value of these shares was estimated using the Black-Scholes model with the following assumptions for 2005: risk-free interest rate of 4.4%; expected dividend yield of 0.8%; expected life of six months; and expected volatility of 34%.

The following table illustrates the effect on net income (loss) and income (loss) per share had we applied the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation.

	Years ended December 31
Millions of dollars except per share data	2005			2004			2003
Net income (loss), as reported	$	2,358		$	(979	)	$	(820	)
Total stock-based employee compensation
expense determined under fair value
based method for all awards (except
restricted stock), net of related tax
effects		(30	)		(28	)		(30	)
Net income (loss), pro forma	$	2,328		$	(1,007	)	$	(850	)

Basic income (loss) per share:
As reported	$	4.67		$	(2.25	)	$	(1.89	)
Pro forma	$	4.61		$	(2.31	)	$	(1.96	)
Diluted income (loss) per share:
As reported	$	4.54		$	(2.22	)	$	(1.88	)
Pro forma	$	4.49		$	(2.28	)	$	(1.95	)

We also maintain a restricted stock program wherein the fair market value of the stock on the date of grant is amortized and ratably charged to income over the period during which the restrictions lapse. The related expense, net of tax, reflected in net income (loss) as reported was $20 million in 2005, $14 million in 2004, and $13 million in 2003.

See Note 14 for further detail on stock incentive plans.

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R is a revision of SFAS No. 123 and supersedes APB No. 25. In April 2005, the United States Securities and Exchange Commission (SEC) adopted a rule that defers the required effective date of SFAS No. 123R. The SEC rule provides that SFAS No. 123R is now effective for registrants as of the beginning of the first fiscal year beginning after June 15, 2005. We adopted the provisions of SFAS No. 123R on January 1, 2006 using the modified prospective application. Accordingly, we will recognize compensation expense for all newly granted awards and awards modified, repurchased, or cancelled after January 1, 2006. Compensation expense for the unvested portion of awards that were outstanding as of January 1, 2006 will be recognized ratably over the remaining vesting period based on the fair value at date of grant as calculated under the Black-Scholes option pricing model. Compensation expense related to the unvested portion of these awards will be consistent with compensation expense included in our pro forma disclosure under SFAS No. 123. We will recognize compensation expense using the Black-Scholes pricing model for our ESPP beginning with the January 1, 2006 purchase period.

Note 2. Percentage-of-Completion Contracts

Revenue from contracts to provide construction, engineering, design, or similar services is reported on the percentage-of-completion method of accounting using measurements of progress toward completion appropriate for the work performed. Commonly used measurements are physical progress, man-hours, and costs incurred.

Billing practices for these projects are governed by the contract terms of each project based upon costs incurred, achievement of milestones, or pre-agreed schedules. Billings do not necessarily correlate with revenue recognized under the percentage-of-completion method of accounting. Billings in excess of recognized revenue are recorded in “Advance billings on uncompleted contracts.” When billings are less than recognized revenue, the difference is recorded in “Unbilled work on uncompleted contracts.” With the exception of claims and change orders that are in the process of being negotiated with customers, unbilled work is usually billed during normal billing processes following achievement of the contractual requirements.

Recording of profits and losses on percentage-of-completion contracts requires an estimate of the total profit or loss over the life of each contract. This estimate requires consideration of contract revenue, change orders and claims reduced by costs incurred, and estimated costs to complete. Anticipated losses on contracts are recorded in full in the period they become evident. Except in a limited number of projects that have significant uncertainties in the estimation of costs, we do not delay income recognition until projects have reached a specified percentage of completion. Generally, profits are recorded from the commencement date of the contract based upon the total estimated contract profit multiplied by the current percentage complete for the contract.

When calculating the amount of total profit or loss on a percentage-of-completion 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 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.

When recording the revenue and the associated unbilled receivable for unapproved claims, we only accrue an amount equal to the costs incurred related to probable unapproved claims. Therefore, the difference between the probable unapproved claims included in determining contract profit or loss and the probable unapproved claims accrued revenue recorded in unbilled work on uncompleted contracts relates to forecasted costs which have not yet been incurred. The amounts included in determining the profit or loss on contracts and the amounts booked to “Unbilled work on uncompleted contracts” or “Other assets” as of December 31 for each period are as follows:

Millions of dollars	2005		2004		2003
Probable unapproved claims	$	175	$	182	$	233
Probable unapproved claims accrued revenue		172		182		225
Probable unapproved claims from unconsolidated related companies		92		51		10

As of December 31, 2005, the probable unapproved claims, including those from unconsolidated related companies relate to six contracts, most of which are complete or substantially complete. See Note 11 for a discussion of government contract claims, which are not included in the table above.

A significant portion of the probable unapproved claims as of December 31, 2005 ($150 million related to our consolidated entities and $45 million related to our unconsolidated related companies) arose from three completed projects with Petroleos Mexicanos (PEMEX) that are currently subject to arbitration proceedings. In addition, we have “Other assets” of $64 million for previously approved services that are unpaid by PEMEX and have been included in these arbitration proceedings. Actual amounts we are seeking from PEMEX in the arbitration proceedings are in excess of these amounts. The arbitration proceedings are expected to extend through 2007. PEMEX has asserted unspecified counterclaims in each of the three arbitrations; however, it is premature based upon our current understanding of those counterclaims to make any assessment of their merits. As of December 31, 2005, we had not accrued any amounts related to the counterclaims in the arbitrations.

We have contracts with probable unapproved claims that will likely not be settled within one year totaling $172 million at December 31, 2005 and $153 million at December 31, 2004 included in the table above, which are reflected as “Other assets” on the consolidated balance sheets. Other probable unapproved claims that we believe will be settled within one year, included in the table above, have been recorded to “Unbilled work on uncompleted contracts” on the consolidated balance sheets. Our unconsolidated related companies include probable unapproved claims as revenue to determine the amount of profit or loss for their contracts. Probable unapproved claims from our related companies are included in “Equity in and advances to related companies.”

Unapproved change orders

We have other contracts for which we are negotiating change orders to the contract scope and have agreed upon the scope of work but not the price. These change orders amounted to $61 million at December 31, 2005. Unapproved change orders at December 31, 2004 were $43 million. Our share of change orders from unconsolidated related companies totaled $5 million at December 31, 2005 and $37 million at December 31, 2004.

Barracuda-Caratinga project

Following is the status, as of December 31, 2005, of our Barracuda-Caratinga project, a multiyear construction project to develop the Barracuda and Caratinga crude oilfields located off the coast of Brazil:

the project was approximately 98% complete;

we recorded losses on this project of $407 million in 2004 and $238 million in 2003;

the losses recorded include $22 million in liquidated damages paid in 2004 based on our agreement with Petrobras;

the $300 million of advance payments received from our customer have been completely repaid; and

we have received $138 million related to approved change orders.

The Barracuda and Caratinga vessels are both fully operational. We reached agreement with Petrobras, subject to Lender's consent that enables us to achieve conclusion of the Lenders' Reliability Test and final acceptance of the FPSOs. These acceptances eliminate any further risk of liquidated damages being assessed. Pursuant to the agreed terms, FPSO Final Acceptance will occur during the first quarter of 2006.

We continue to fund operating cash shortfalls on this project and estimate that we will pay approximately $12 million during 2006, which represents remaining project costs, net of revenue to be received.

Note 3. Acquisitions and Dispositions

Dulles Greenway Toll Road

As part of our infrastructure projects, we occasionally take an ownership interest in the constructed asset, with a view toward monetization of that ownership interest after the asset has been operating for some period and increases in value. In September 2005, we sold our 13% interest in a joint venture that owned the Dulles Greenway Toll Road in Virginia. We received $85 million in cash from the sale. Because of unfavorable early projections of traffic to support the toll road after it had opened, we wrote down our investment in the toll road in 1996. At the time of the sale, our investment had a net book value of zero, and therefore, we recorded the entire $85 million of cash proceeds to operating income in our Government and Infrastructure segment.

Subsea 7, Inc.

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 Production Optimization segment.

Surface Well Testing

In August 2004, we sold our surface well testing and subsea test tree operations within our Production Optimization segment to Power Well Service Holdings, LLC, an affiliate of First Reserve Corporation, for approximately $129 million, of which we received $126 million in cash. During 2004, we recorded a $54 million gain on the sale.

Enventure and WellDynamics

In the first quarter of 2004, Halliburton and Shell Technology Ventures (Shell, an unrelated party) restructured two joint venture companies, Enventure Global Technology LLC (Enventure) and WellDynamics B.V. (WellDynamics), in an effort to more closely align the ventures with near-term priorities in the core businesses of the venture owners. Prior to this transaction, Enventure (part of our Fluid Systems segment) and WellDynamics (formerly part of our Digital and Consulting Solutions segment) were owned equally by Shell and us. Shell acquired an additional 33.5% of Enventure, leaving us with 16.5% ownership in return for enhanced and extended agreements and licenses with Shell for its Poroflex™ expandable sand screens and a distribution agreement for its Versaflex™ expandable liner hangers. As a result of this transaction, we changed the way we account for our ownership in Enventure from the equity method to the cost method of accounting for investments. We acquired an additional 1% of WellDynamics from Shell, giving us 51% ownership and control of day-to-day operations. In addition, Shell received an option to obtain our remaining interest in Enventure for an additional 14% interest in WellDynamics. No gain or loss resulted from the transaction. Beginning in the first quarter of 2004, WellDynamics was consolidated and is now included in our Production Optimization segment. The consolidation of WellDynamics resulted in an increase to our goodwill of $109 million, which was previously carried as equity method goodwill in “Equity in and advances to related companies.”

Halliburton Measurement Systems

In May 2003, we sold certain assets of Halliburton Measurement Systems, which provides flow measurement and sampling systems, to NuFlo Technologies, Inc. for approximately $33 million in cash. The gain on the sale of Halliburton Measurement Systems’ assets was $24 million and was included in our Production Optimization segment.

Wellstream

In March 2003, we sold the assets relating to our Wellstream business, a global provider of flexible pipe products, systems, and solutions, to Candover Partners Ltd. for $136 million in cash. The assets sold included manufacturing plants in Newcastle upon Tyne, United Kingdom, and Panama City, Florida, as well as assets and contracts in Brazil. Wellstream had $34 million in goodwill recorded at the disposition date. The transaction resulted in a loss of $15 million, which was included in our Digital and Consulting Solutions segment. Included in the loss is the write-off of the cumulative translation adjustment related to Wellstream of approximately $9 million.

Mono Pumps

In January 2003, we sold our Mono Pumps business to National Oilwell, Inc. The sale price of approximately $88 million was paid with $23 million in cash and 3.2 million shares of National Oilwell, Inc. common stock, which were valued at $65 million on January 15, 2003. We recorded a gain of $36 million on the sale in the first quarter of 2003, which was included in our Drilling and Formation Evaluation segment. Included in the gain was the write-off of the cumulative translation adjustment related to Mono Pumps of approximately $5 million. In February 2003, we sold 2.5 million of our 3.2 million shares of National Oilwell, Inc. common stock for $52 million, which resulted in a gain of $2 million, and in February 2004, we sold the remaining shares for $20 million, resulting in a gain of $6 million. The gains related to the sale of the National Oilwell, Inc. common stock were recorded in “Other, net.”

Note 4. Business Segment Information

During the second quarter of 2003, we restructured our Energy Services Group into four segments, and, in the fourth quarter of 2004, we restructured KBR into two segments, which form the basis for the six segments we now report. The segments mirror the way our chief operating decision maker regularly reviews the operating results, assesses performance, and allocates resources.

Energy Services Group

Following is a summary of our Energy Services Group segments.

Production Optimization. The Production Optimization segment primarily tests, measures, and provides means to manage and/or improve well production once a well is drilled and, in some cases, after it has been producing. This segment consists of production enhancement services and completion tools and services.

Also included in the Production Optimization segment are WellDynamics, an intelligent well completions joint venture, which was consolidated beginning in the first quarter of 2004, and, until January 2005, subsea operations conducted by Subsea 7, Inc., of which we formerly owned 50% and accounted for it using the equity method.

Fluid Systems. The Fluid Systems segment focuses on providing services and technologies to assist in the drilling and construction of oil and gas wells. This segment consists of:

cementing services, which involve the process used to bond the well and well casing while isolating fluid zones and maximizing wellbore stability. Our cementing service line also provides casing equipment and services;

Baroid Fluid Services, which provides drilling fluid systems, performance additives, solids control, and waste management services for oil and gas drilling, completion, and workover operations; and

Enventure, an expandable casing joint venture, which we account for using the cost method.

Drilling and Formation Evaluation. The Drilling and Formation Evaluation segment is primarily involved in the drilling and formation evaluation process during bore-hole construction. Major services and products offered include:

Sperry Drilling Services, which provides drilling systems and services. These services include directional and horizontal drilling, measurement-while-drilling, logging-while-drilling, multilateral systems, 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, which provides roller cone rock bits, fixed cutter bits, and related downhole tools used in drilling oil and gas wells. In addition, coring equipment and services are provided to acquire cores of the formation drilled for evaluation; and

logging services, which 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 services, which provide cement bond evaluation, reservoir monitoring, pipe evaluation, pipe recovery, and perforating.

Digital and Consulting Solutions. The Digital and Consulting Solutions segment provides integrated exploration, drilling, and production software information systems, consulting services, real-time operations, value-added oilfield project management, and other integrated solutions. Included in this business segment is Landmark, a supplier of integrated exploration, drilling, and production software information systems, as well as professional and data management services for the upstream oil and gas industry.

KBR

KBR provides a wide range of services to energy, chemical, and industrial customers and government entities worldwide. Following is a summary of KBR’s segments.

Government and Infrastructure. The Government and Infrastructure segment is one of the largest government logistics and services contractors with worldwide civil infrastructure capabilities. This segment provides construction, maintenance, and logistics services for government operations, facilities, and installations. Other major operations include civil engineering, consulting, project management services for state and local governments and private industries, integrated security solutions, dockyard operation and maintenance through the Devonport Royal Dockyard Limited (DML) subsidiary, and privately financed initiatives.

Also included in this segment is the Alice Springs-Darwin Railroad (ASD). ASD is a privately financed project that was formed in 2001 to build and operate the transcontinental railroad from Alice Springs to Darwin, Australia. ASD has been granted a 50-year concession period by the Australian government. KBR provided engineering, procurement, and construction (EPC) services for ASD and is the largest equity holder in the project with a 36.7% interest, with the remaining equity held by eleven other participants. We account for this investment under the equity method.

Energy and Chemicals. The Energy and Chemicals segment is a global engineering, procurement, construction, technology, and services provider for the energy and chemicals industries. Working both upstream and downstream in support of our customers, Energy and Chemicals offers the following:

downstream engineering and construction capabilities, including global engineering execution centers, as well as engineering, construction, and program management of liquefied natural gas, ammonia, petrochemicals, crude oil refineries, and natural gas plants;

upstream deepwater engineering, marine technology, and project management;

plant operations, maintenance, and start-up services for both upstream and downstream oil and gas facilities worldwide, as well as maintenance services for the petrochemical, forest product, power, and commercial markets;

industry-leading licensed technologies in the areas of fertilizers and synthesis gas, olefins, refining, and chemicals and polymers; and

Included in this segment are a number of joint ventures including the following:

M. W. Kellogg Limited (MWKL) is a London-based joint venture that provides full engineering, procurement, and construction contractor services for LNG, gas-to-liquids, and onshore oil and gas projects. MWKL is owned 55% by KBR and 45% by JGC Corporation. We consolidate MWKL for financial reporting purposes.

General corporate. General corporate represents assets not included in a business segment and is primarily composed of cash and cash equivalents, deferred tax assets, and insurance for asbestos and silica litigation claims.

Other. Intersegment revenue and revenue between geographic areas are immaterial. Our equity in pretax 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.

Revenue from the United States Government, which was derived almost entirely from our Government and Infrastructure segment, totaled $6.6 billion or 31% of consolidated revenue in 2005, $8.0 billion or 39% of consolidated revenue in 2004, and $4.2 billion or 26% of consolidated revenue in 2003. No other customer represented more than 10% of consolidated revenue in any period presented.

The tables below present information on our business segments.

*Operations by business segment*
	Years ended December 31
Millions of dollars	2005			2004			2003
Revenue:
Production Optimization	$	4,284		$	3,303		$	2,758
Fluid Systems		2,838			2,324			2,039
Drilling and Formation Evaluation		2,258			1,782			1,643
Digital and Consulting Solutions		720			589			555
Total Energy Services Group		10,100			7,998			6,995
Government and Infrastructure		8,148			9,393			5,417
Energy and Chemicals		2,746			3,075			3,859
Total KBR		10,894			12,468			9,276
Total	$	20,994		$	20,466		$	16,271
Operating income (loss):
Production Optimization	$	1,106		$	633		$	413
Fluid Systems		544			348			251
Drilling and Formation Evaluation		483			225			177
Digital and Consulting Solutions		146			60			(15	)
Total Energy Services Group		2,279			1,266			826
Government and Infrastructure		330			84			194
Energy and Chemicals		168			(426	)		(225	)
Shared KBR		-			-			(5	)
Total KBR		498			(342	)		(36	)
General corporate		(115	)		(87	)		(70	)
Total	$	2,662		$	837		$	720
Capital expenditures:
Production Optimization	$	254		$	220		$	161
Fluid Systems		94			74			96
Drilling and Formation Evaluation		201			172			169
Digital and Consulting Solutions		26			32			27
Total Energy Services Group		575			498			453
Government and Infrastructure		33			41			45
Energy and Chemicals		4			9			5
Shared KBR		39			27			12
Total KBR		76			77			62
Total	$	651		$	575		$	515

Within the Energy Services Group and KBR, 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 within the two groups. For segment operating income presentation, the depreciation expense associated with these shared KBR assets is allocated to the two segments under KBR.

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

*Operations by business segment (continued)*
	Years ended December 31
Millions of dollars	2005		2004		2003
Depreciation, depletion, and amortization:
Production Optimization	$	165	$	159	$	144
Fluid Systems		88		83		77
Drilling and Formation Evaluation		131		139		168
Digital and Consulting Solutions		64		75		78
Total Energy Services Group		448		456		467
Government and Infrastructure		32		27		22
Energy and Chemicals		9		11		16
Shared KBR		15		15		12
Total KBR		56		53		50
General corporate		-		-		1
Total	$	504	$	509	$	518
Total assets:
Production Optimization	$	2,466	$	2,040	$	1,962
Fluid Systems		1,438		1,230		1,248
Drilling and Formation Evaluation		1,328		1,126		1,254
Digital and Consulting Solutions		803		768		794
Shared energy services		494		452		596
Total Energy Services Group		6,529		5,616		5,854
Government and Infrastructure		2,645		3,309		2,758
Energy and Chemicals		1,957		1,656		2,078
Shared KBR		326		198		246
Total KBR		4,928		5,163		5,082
General corporate		3,553		5,085		4,620
Total	$	15,010	$	15,864	$	15,556

Prior year shared energy services assets, capital expenditures, and depreciation, depletion, and amortization have been reclassified due to allocation of fixed assets to the Energy Services Group business segments from shared energy services and to be consistent with the current year presentation.

*Operations by geographic area*
	Years ended December 31
Millions of dollars	2005		2004		2003
Revenue:
United States	$	5,655	$	4,461	$	4,415
Iraq		5,116		5,362		2,399
United Kingdom		2,013		1,646		1,473
Kuwait		416		1,841		856
Other countries		7,794		7,156		7,128
Total	$	20,994	$	20,466	$	16,271
Long-lived assets:
United States	$	2,409	$	2,485	$	4,461
United Kingdom		563		697		630
Other countries		1,300		1,126		917
Total	$	4,272	$	4,308	$	6,008

Note 5. Receivables (Other than “Insurance for asbestos- and silica-related liabilities”)

Our receivables are generally not collateralized. At December 31, 2005, 38% of our consolidated receivables related to our United States government contracts, primarily for projects in the Middle East. Receivables from the United States government at December 31, 2004 represented 39% of consolidated receivables.

Note 6. Inventories

Inventories are stated at the lower of cost or market. We manufacture in the United States 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 $42 million at December 31, 2005 and $37 million at December 31, 2004. If the average cost method had been used, total inventories would have been $21 million higher than reported at December 31, 2005 and $17 million higher than reported at December 31, 2004. The cost of the remaining inventory was recorded on the average cost method. Inventories at December 31, 2005 and December 31, 2004 were composed of the following:

	December 31
Millions of dollars	2005		2004
Finished products and parts	$	715	$	602
Raw materials and supplies		181		156
Work in process		57		33
Total	$	953	$	791

Finished products and parts are reported net of obsolescence reserves of $98 million at December 31, 2005 and $119 million at December 31, 2004.

Note 7. Investments

Investments in marketable securities

Our investments in marketable securities are reported at fair value. At December 31, 2004, our investments in marketable securities consisted of auction rate securities classified as available-for-sale. The 2004 balance of the auction rate securities was previously classified as cash and equivalents due to our intent and ability to quickly liquidate these securities to fund current operations and due to their interest rate reset feature. The auction rate securities were reclassified as investments in marketable securities. There was no impact on net income or cash flow from operating activities as a result of the reclassification. These auction rate securities were liquidated in March 2005.

Restricted cash

At December 31, 2005, we had restricted cash of $123 million in “Other assets,” which consisted of:

$100 million as collateral for potential future insurance claim reimbursements; and

$23 million related to cash collateral agreements for outstanding letters of credit for various construction projects.

At December 31, 2004, we had restricted cash of $121 million in “Other assets” and $17 million in “Other current assets,” which consisted of similar items as above.

Note 8. Property, Plant, and Equipment

Property, plant, and equipment at December 31, 2005 and 2004 were composed of the following:

Millions of dollars	2005		2004
Land	$	66	$	68
Buildings and property improvements		940		1,088
Machinery, equipment, and other		5,480		5,071
Total		6,486		6,227
Less accumulated depreciation		3,838		3,674
Net property, plant, and equipment	$	2,648	$	2,553

Machinery, equipment, and other includes oil and gas properties of $309 million at December 31, 2005 and $308 million at December 31, 2004.

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
	2005			2004
1-10 years		25	%		19	%
11-20 years		45	%		45	%
21-30 years		11	%		16	%
31-40 years		19	%		20	%

	Machinery, Equipment,
	and Other
	2005			2004
1-5 years		25	%		28	%
6-10 years		69	%		63	%
11-20 years		6	%		9	%

In the second quarter of 2004, we implemented a change in accounting estimate to more accurately reflect the useful life of some of the tools of our Drilling and Formation Evaluation segment. This resulted in a combined $35 million reduction in depreciation expense in the last three quarters of 2004, thereby reducing our consolidated net loss by $22 million, or $0.05 per share, for 2004. We extended the useful lives of these tools based on our review of their service lives, technological improvements in the tools, and recent changes to our repair and maintenance practices which helped to extend the lives.

Note 9. Debt

Short-term notes payable consist primarily of overdraft and other facilities with varying rates of interest. Long-term debt at December 31, 2005 and 2004 consisted of the following:

Millions of dollars	2005		2004
3.125% convertible senior notes due July 2023	$	1,200	$	1,200
5.5% senior notes due October 2010		748		748
Medium-term notes due 2006 thru 2027		600		600
7.6% debentures of Halliburton due August 2096		294		294
8.75% debentures due February 2021		200		200
0.75% plus three-month LIBOR senior notes repaid in April 2005		-		500
1.5% plus three-month LIBOR senior notes repaid in October 2005		-		300
Other		132		98
Total long-term debt		3,174		3,940
Less current portion		361		347
Noncurrent portion of long-term debt	$	2,813	$	3,593

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. This circumstance was achieved in the third and fourth quarters of 2005. There were no conversions of these notes as of February 15, 2006;

if the notes have been called for redemption;

upon the occurrence of specified corporate transactions that are described in the indenture relating to the offering; 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 initial conversion price is $37.65 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.

Upon conversion, we must settle the principal amount of the notes in cash, and for any amounts in excess of the aggregate principal we have the right to deliver shares of our common stock, cash, or a combination of cash and common stock.

See Note 16 for discussion of supplemental indenture on these notes.

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.

Senior notes due 2007

In January 2004, we issued $500 million aggregate principal amount of senior notes due 2007 bearing interest at a floating rate equal to three-month LIBOR (London interbank offered rates) plus 0.75%, payable quarterly. In April 2005, we redeemed, at par plus accrued interest, all $500 million of these senior notes.

Floating- and fixed-rate senior notes

In October 2003, we completed an offering of $1.05 billion of floating- and fixed-rate unsecured senior notes. The fixed-rate notes, with an aggregate principal amount of $750 million, will mature on October 15, 2010 and bear interest at a rate equal to 5.5%, payable semiannually. The fixed-rate 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 bonds. The floating-rate notes, with an aggregate principal amount of $300 million and interest at a rate equal to three-month LIBOR plus 1.5%, were repaid at par plus accrued interest in October 2005.

Medium-term notes

We have outstanding notes under our medium-term note program as follows:

				Amount
Due	Rate			(in millions)
08/2006		6.00	%	$	275
12/2008		5.63	%	$	150
05/2017		7.53	%	$	50
02/2027		6.75	%	$	125

At December 31, 2005, the $275 million 6.00% medium-term notes due August 2006 were included in “Current maturities of long-term debt” in the consolidated balance sheet. We may redeem the 6.00% and 5.63% medium-term notes in whole or in part at any time subject to a redemption price equal to the greater of 100% of the principal amount of such notes or the sum of the present values of the remaining scheduled payments of principal and interest thereon discounted to the redemption date at the treasury rate plus 15 basis points. The 7.53% notes may not be redeemed prior to maturity. Each holder of the 6.75% medium-term notes has the right to require us to repay their notes in whole or in part on February 1, 2007. The medium-term notes do not have sinking fund requirements and rank equally with our existing and future senior unsecured indebtedness.

Revolving credit facilities

In March 2005, we entered into a $1.2 billion variable rate, five-year unsecured revolving credit agreement, which replaced a secured $700 million three-year revolving credit facility and a secured $500 million 364-day revolving credit facility. The letter of credit outstanding under the previous $700 million revolving credit facility is now outstanding under our $1.2 billion revolving credit agreement and had a balance of $107 million as of December 31, 2005. As of December 31, 2005, approximately $1.1 billion was available for borrowing under the $1.2 billion revolving credit agreement, but no borrowings had been made.

Debt covenants

Letters of credit related to our Barracuda-Caratinga project and our $1.2 billion revolving credit facility contain restrictive covenants, including covenants that require us to maintain certain financial ratios as defined by the agreements. For the letters of credit related to our Barracuda-Caratinga project, we are required to maintain certain interest coverage and leverage ratios. We are also required to maintain a minimum debt-to-capitalization ratio under our $1.2 billion revolving credit facility. At December 31, 2005, we were in compliance with these requirements.

In addition, the unsecured $850 million five-year revolving letter of credit facility entered into by KBR contains covenants including a limitation on the amount KBR can invest in unconsolidated subsidiaries. KBR must also maintain certain financial ratios including a debt-to-capitalization ratio, a leverage ratio, and a fixed charge coverage ratio. At December 31, 2005, KBR was in compliance with these requirements.

Maturities

Our debt, excluding the effects of our terminated interest rate swaps of $2 million, matures as follows: $359 million in 2006; $31 million in 2007; $152 million in 2008; $1 million in 2009; $750 million in 2010; and $1,879 million thereafter.

Note 10. Asbestos and Silica Obligations and Insurance Recoveries

Several of our subsidiaries, particularly DII Industries and Kellogg Brown & Root, had been named as defendants in a large number of asbestos- and silica-related lawsuits. The plaintiffs’ alleged injuries were primarily a result of exposure to:

asbestos used in products manufactured or sold by former divisions of DII Industries (primarily refractory materials, gaskets, and packing materials used in pumps and other industrial products);

asbestos in materials used in the construction and maintenance projects of Kellogg Brown & Root or its subsidiaries; and

silica related to sandblasting and drilling fluids operations.

Effective December 31, 2004, we resolved all open and future claims in the prepackaged Chapter 11 proceedings of DII Industries, Kellogg Brown & Root, and our other affected subsidiaries (which were filed on December 16, 2003) upon the plan of reorganization becoming final and nonappealable. The following table presents a rollforward of our asbestos- and silica-related liabilities and insurance receivables.

Millions of dollars
Asbestos- and silica-related liabilities:
December 31, 2004 balance (of which $2,408 was current)	$	(2,445	)
Payment to trusts in accordance with the plan of reorganization		2,345
First installment payment of partitioning agreement		16
Cash settlement payment to the silica trust		15
Payment on one-year asbestos note		8
Reclassification of remaining note balances to other current liabilities
and long-term debt		61
Asbestos- and silica-related liabilities - December 31, 2005 balance	$	-
Insurance for asbestos- and silica-related liabilities:
December 31, 2004 balance (of which $1,066 was current)	$	1,416
Payments received		(1,032	)
Accretion		15
Other		(3	)
Insurance for asbestos- and silica-related liabilities - December 31, 2005
balance (of which $193 is current)	$	396

In accordance with the plan of reorganization, in January 2005 we contributed the following to trusts for the benefit of current and future asbestos and silica personal injury claimants:

approximately $2.345 billion in cash, which represents the remaining portion of the $2.775 billion total cash settlement after payments of $311 million in December 2003 and $119 million in June 2004;

59.5 million shares of Halliburton common stock;

a one-year non-interest-bearing note of $31 million for the benefit of asbestos claimants. We prepaid the initial installment on the note of approximately $8 million in January 2005 and paid an additional $15 million during the third quarter of 2005. The final payment on the note of approximately $8 million was made in the fourth quarter of 2005; and

a silica note for the benefit of silica claimants. The note provides that we will contribute an amount to the silica trust at the end of each year for the next 30 years of up to $15 million. The note also provides for an extension of the note for 20 additional years under certain circumstances. As of December 31, 2005, we estimated the value of this note plus the initial cash payment of $15 million, paid in January 2005, to be approximately $24 million. We will periodically reassess our valuation of this note based upon our projections of the amounts we believe we will be required to fund into the silica trust.

Our plan of reorganization called for a portion of our total asbestos liability to be settled by contributing 59.5 million shares of Halliburton common stock to the trust. In 2004, we revalued the 59.5 million shares to $2.335 billion ($39.24 per share) at December 31, 2004 from approximately $1.6 billion ($26.27 per share) at December 31, 2003, resulting in charges to discontinued operations totaling $778 million. Effective December 31, 2004, concurrent with receiving final and nonappealable confirmation of our plan of reorganization, we reclassified from a long-term liability to shareholders’ equity the final value of the 59.5 million shares of Halliburton common stock to be contributed to the asbestos trust. In January 2005, when the 59.5 million shares were actually contributed to the trust, the $2.335 billion value of the common shares was reclassified to common stock and paid-in capital in excess of par value on the consolidated balance sheets.

Insurance settlements

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 terms of our insurance settlements, we would receive cash proceeds with a nominal amount of approximately $1.5 billion and with a then present value of approximately $1.4 billion for our asbestos- and silica-related insurance receivables. The present value was determined by discounting the expected future cash payments with a discount rate implicit in the settlements, which ranged from 4.0% to 5.5%. This discount is being accreted as interest income (classified as discontinued operations) over the life of the expected future cash payments. Cash payments of approximately $1.032 billion related to these receivables were received in 2005. Under the terms of the settlement agreements, we will receive cash payments of the remaining amounts, totaling $427 million at December 31, 2005, in several installments through 2010.

A significant portion of the insurance coverage applicable to Worthington Pump, a former division of DII Industries, was alleged by Federal-Mogul (and others who formerly were associated with Worthington Pump prior to its acquisition by DII Industries) to be shared with them. During 2004, we reached an agreement with Federal-Mogul, our insurance companies, and another party sharing in the insurance coverage to obtain their consent and support of a partitioning of the insurance policies. Under the terms of the agreement, DII Industries was allocated 50% of the limits of any applicable insurance policy, and the remaining 50% of limits of the insurance policies were allocated to the remaining policyholders. As part of the settlement, DII Industries agreed to pay $46 million in three installment payments. In 2004, we accrued $44 million, which represents the present value of the $46 million to be paid. The discount is accreted as interest expense (classified as discontinued operations) over the life of the expected future cash payments beginning in the fourth quarter of 2004. The first payment of $16 million was paid in January 2005, and the second payment of $15 million was paid in January 2006. The third and final payment of $15 million will be made in January 2007.

DII Industries and Federal-Mogul agreed to share equally in recoveries from insolvent London-based insurance companies. To the extent that Federal-Mogul’s recoveries from certain insolvent London-based insurance companies received on or before January 1, 2006 did not equal at least $4.5 million, DII Industries agreed to also pay to Federal-Mogul the difference between their recoveries from the insolvent London-based insurance companies and $4.5 million. Accordingly, DII Industries paid Federal-Mogul $1.6 million in January 2006. This amount is expected to be received back from Federal-Mogul following any recoveries received by Federal-Mogul from the insolvent London-based insurance companies after January 1, 2006.

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. At December 31, 2005, we had not recorded any liability associated with these indemnifications.

Note 11. United States Government Contract Work

DCAA audit issues

Investigations

In the first quarter of 2005, the United States Department of Justice (DOJ) issued two indictments associated with these issues against a former KBR procurement manager and a manager of La Nouvelle.

Withholding of payments

Upon the completion of the RIO contract definitization process, the COE released all previously withheld amounts related to this contract in the fourth quarter of 2005.

DCMA system reviews

The Balkans

Note 12. Other Commitments and Contingencies

Foreign Corrupt Practices Act investigations

As of December 31, 2005, we have not accrued any amounts related to this investigation other than our current legal expenses.

Bidding practices investigation

There can be no assurance that the results of these investigations will not have a material adverse effect on our business and results of operations.

As of December 31, 2005, we had not accrued any amounts related to this investigation other than our current legal expenses.

SEC investigation of change in accounting for revenue on long-term construction projects and related disclosures

In August 2004, we reached a settlement in the investigation by the SEC involving our 1998 and 1999 disclosure of an accounting for the recognition of revenue from unapproved claims on long-term construction projects. Our settlement with the SEC covers a failure to disclose a 1998 change in accounting practice. We disclosed the change in accounting practice in our 1999 Annual Report on Form 10-K and continued to do so in subsequent periods. The SEC did not determine that we departed from generally accepted accounting principles nor did it find errors in accounting or fraud. We neither admitted nor denied the SEC’s findings but paid a $7.5 million civil penalty and recorded a charge of that amount in the second quarter of 2004. As part of the settlement, the Company agreed to cease and desist from committing or causing future securities law violations.

Securities and related litigation

On June 3, 2002, a class action lawsuit was filed against us in federal court on behalf of purchasers of our common stock during the period of approximately May 1998 until approximately May 2002 alleging violations of the federal securities laws in connection with the accounting change and disclosures involved in the SEC investigation discussed above. In addition, the plaintiffs allege that we overstated our revenue from unapproved claims by recognizing amounts not reasonably estimable or probable of collection. In the weeks that followed, approximately twenty similar class actions were filed against us. Several of those lawsuits also named as defendants Arthur Andersen LLP, our independent accountants for the period covered by the lawsuits, and 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 on or about April 11, 2003 (the “Moore class action”). In October 2002 and March 2003, two derivative actions arising out of essentially the same facts and circumstances were filed. Both of those actions have now been dismissed.

In early May 2003, we announced that we had 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 in the Moore class action 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 includes 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 Dresser claims were included in the settlement discussions leading up to the signing of the memorandum of understanding and were among the claims the parties intended to have resolved by the terms of the proposed settlement of the consolidated Moore class action and the derivative action. The memorandum of understanding called for Halliburton to pay $6 million, which would be funded by insurance proceeds.

On June 7, 2004, the court entered an order preliminarily approving the settlement. Following the transfer of the case to another district judge and a final hearing on the fairness of the settlement, on September 9, 2004, the court entered an order holding that evidence of the settlement’s fairness was inadequate, denying the motion for final approval of the settlement in the Moore class action, and ordering the parties, among other things, to mediate. After the court’s denial of the motion to approve the settlement, we withdrew from the settlement as we believe we are entitled to do by its terms. The mediation was held on January 27, 2005 and, at the conclusion of that day, was declared by the mediator to be at an impasse with no settlement having been reached.

After the mediation, the lead plaintiff and lead counsel filed motions to withdraw as lead plaintiff and lead counsel. The court conducted a hearing on those motions on April 29, 2005. At that hearing, the court granted the motions, appointed new co-lead counsel and a new lead plaintiff, directed that they file a third consolidated amended complaint not later than May 9, 2005, and that we file our motion to dismiss not later than June 8, 2005. That motion has now been filed and fully briefed. The court held oral arguments on that motion on August 2, 2005, at which time the court took the motion under advisement. We await the court’s ruling. Should the motion to dismiss be denied, we intend to vigorously defend the action.

Newmont Gold

In July 1998, Newmont Gold, a gold mining and extraction company, filed a lawsuit over the failure of a blower manufactured and supplied to Newmont by Roots, a former division of Dresser Equipment Group. The plaintiff alleges that during the manufacturing process, Roots had reversed the blades of a component of the blower known as the inlet guide vane assembly, resulting in the blower’s failure and the shutdown of the gold extraction mill for a period of approximately one month during 1996. In January 2002, a Nevada trial court granted summary judgment to Roots on all counts, and Newmont appealed. In February 2004, the Nevada Supreme Court reversed the summary judgment and remanded the case to the trial court, holding that fact issues existed requiring a trial. Based on pretrial reports, the damages claimed by the plaintiff are in the range of $33 million to $39 million. We believe that we have valid defenses to Newmont Gold’s claims and intend to vigorously defend the matter. The case was scheduled for trial beginning the last full week of May 2005. At the conclusion of jury selection, we again requested a motion for change of venue we had filed earlier. That motion was denied by the trial court, and the Nevada Supreme Court affirmed. Our present intention is to request that the three judge panel that decided the appeal reconsider its ruling, failing which we may request that the entire Nevada Supreme Court rehear the appeal. Should those efforts be unsuccessful, the case will be returned to the trial court where a new trial setting will be ordered and the case will proceed to trial. As of December 31, 2005, we had not accrued any amounts related to this matter.

Smith International award

In June 2004, a Texas district court jury returned a verdict in our favor in connection with a patent infringement lawsuit we filed against Smith International (Smith). We were awarded $24 million in damages by the jury. We filed the lawsuit in September 2002, seeking damages for Smith’s infringement of our patented Energy Balanced™ roller cone drill bit technology. The jury found that Smith’s competing bits willfully infringed on three of our patents. During the fourth quarter of 2005, this case was settled along with cases dealing with the same and related technology and pending in Tyler and Houston, Texas, the United Kingdom, and Italy.

Improper payments reported to the SEC

During the second quarter of 2002, we reported to the SEC that one of our foreign subsidiaries operating in Nigeria made improper payments of approximately $2.4 million to entities owned by a Nigerian national who held himself out as a tax consultant, when in fact he was an employee of a local tax authority. The payments were made to obtain favorable tax treatment and clearly violated our Code of Business Conduct and our internal control procedures. The payments were discovered during our audit of the foreign subsidiary. We conducted an investigation assisted by outside legal counsel, and, based on the findings of the investigation, we terminated several employees. None of our senior officers were involved. We are cooperating with the SEC in its review of the matter. We took further action to ensure that our foreign subsidiary paid all taxes owed in Nigeria. A preliminary assessment of approximately $4 million was issued by the Nigerian tax authorities in the second quarter of 2003. We are cooperating with the Nigerian tax authorities to determine the total amount due as quickly as possible.

Operations in Iran

Litigation brought by La Nouvelle

In October 2004, La Nouvelle, a subcontractor to us in connection with our government services work in Kuwait and Iraq, filed suit alleging breach of contract and interference with contractual and business relations. The relief sought included $224 million in damages for breach of contract, which included $34 million for wrongful interference and an unspecified sum for consequential and punitive damages. The dispute arose from our termination of a master agreement pursuant to which La Nouvelle operated a number of DFACs in Kuwait and Iraq and the replacement of La Nouvelle with ESS, which, prior to La Nouvelle’s termination, had served as La Nouvelle’s subcontractor. In addition, La Nouvelle alleged that we wrongfully withheld from La Nouvelle certain sums due La Nouvelle under its various subcontracts. During the second quarter of 2005, this litigation was settled without material impact to us.

David Hudak and International Hydrocut Technologies Corp.

On October 12, 2004, David Hudak and International Hydrocut Technologies Corp. (collectively, Hudak) filed suit against us in the United States District Court alleging civil Racketeer Influenced and Corporate Organizations Act violations, fraud, breach of contract, unfair trade practices, and other torts. The action, which seeks unspecified damages, arises out of Hudak’s alleged purchase in early 1994 of certain explosive charges that were later alleged by the DOJ to be military ordnance, the possession of which by persons not possessing the requisite licenses and registrations is unlawful. As a result of that allegation by the government, Hudak was charged with, but later acquitted of, certain criminal offenses in connection with his possession of the explosive charges. As mentioned above, the alleged transaction(s) took place more than 10 years ago. The fact that most of the individuals that may have been involved, as well as the entities themselves, are no longer affiliated with us will complicate our investigation. For those reasons and because the litigation is in its most preliminary stages, it is premature to assess the likelihood of an adverse result. We have filed a motion to dismiss and, alternatively, a motion to transfer venue and are awaiting the court’s decision on those motions. It is, however, our intention to vigorously defend this action. As of December 31, 2005, we had not accrued any amounts related to this matter.

Convoy ambush litigation

Several of the families of truck drivers, employed by KBR and killed when a fuel convoy was ambushed in Iraq on April 9, 2004, have filed suit against us. These suits allege that we are responsible for the deaths of these drivers for a variety of reasons and assert legal claims for fraud, wrongful death, civil rights violations, and violations of the Racketeer Influenced and Corrupt Organizations Act. We deny the allegations of wrongdoing and fully intend to vigorously defend the actions. We believe that our conduct was entirely lawful and that our liability is limited by federal law. On July 1, 2005, the federal court in Houston, Texas denied our motion to dismiss based upon a narrow exception to the Defense Base Act. As of December 31, 2005, we had not accrued any amounts related to these matters.

Iraq overtime litigation

During the fourth quarter of 2005, a group of present and former employees working on the LogCAP contract in Iraq and elsewhere filed a class action lawsuit alleging that KBR wrongfully failed to pay time and a half for hours worked in excess of 40 per work week and that “uplift” pay, consisting of a foreign service bonus, an area differential, and danger pay, was only applied to the first 40 hours worked in any work week. The class alleged by plaintiffs consists of all current and former employees on the LogCAP contract from December 2001 to present. The basis of plaintiffs’ claims is their assertion that they are intended third-party beneficiaries of the LogCAP contract, and that the LogCAP contract obligated KBR to pay time and a half for all overtime hours. We have moved to dismiss the case on a number of bases, and that motion remains pending at this time. In the event the motion to dismiss is denied, we intend to vigorously defend this case. It is premature to assess the probability of an adverse result in this action. However, because the LogCAP contract is cost-reimbursable, we could charge any overtime and “uplift” pay to the customer in the event of an adverse judgment. As of December 31, 2005, we had not accrued any amounts related to this matter.

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 Resources 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 $50 million as of December 31, 2005 and $41 million as of December 31, 2004. The liability covers numerous properties, and no individual property accounts for more than $10 million of the liability balance. We have subsidiaries that have been named as potentially responsible parties along with other third parties for 14 federal and state superfund sites for which we have established a liability. As of December 31, 2005, those 14 sites accounted for approximately $13 million of our total $50 million liability. In some instances, we have been named a potentially responsible party by a regulatory agency, but in each of those cases, we do not believe we have any material liability.

Letters of credit

In the normal course of business, we have agreements with banks under which approximately $1.2 billion of letters of credit or bank guarantees were outstanding as of December 31, 2005, including $434 million that relate to our joint ventures’ operations. Also included in letters of credit outstanding as of December 31, 2005 were $183 million of performance letters of credit and $114 million of retainage letters of credit related to the Barracuda-Caratinga project. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.

Other commitments

Liquidated damages

Many of our engineering and construction contracts have milestone due dates that must be met or we may be subject to penalties for liquidated damages if claims are asserted and we were responsible for the delays. These generally relate to specified activities within a project by a set contractual date or achievement of a specified level of output or throughput of a plant we construct. Each contract defines the conditions under which a customer may make a claim for liquidated damages. However, in most instances, liquidated damages are not asserted by the customer, but the potential to do so is used in negotiating claims and closing out the contract. We had not accrued for liquidated damages of $70 million at December 31, 2005 and $44 million at December 31, 2004 (including amounts related to our share of unconsolidated subsidiaries) that we could incur based upon completing the projects as forecasted.

Leases

We are obligated under operating leases, principally for the use of land, offices, equipment, field facilities, and warehouses. Total rentals, net of sublease rentals, were as follows:

Millions of dollars		2005			2004			2003
Rental expense		$	721		$	693		$	451

Future total rentals on noncancelable operating leases are as follows: $187 million in 2006; $148 million in 2007; $123 million in 2008; $111 million in 2009; $100 million in 2010; and $478 million thereafter.

Note 13. Income Taxes

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

	Years ended December 31
Millions of dollars	2005			2004			2003
Current income taxes:
Federal	$	(106	)	$	(88	)	$	(167	)
Foreign		(199	)		(156	)		(181	)
State		(9	)		(6	)		1
Total current		(314	)		(250	)		(347	)
Deferred income taxes:
Federal		305			3			80
Foreign		(56	)		6			25
State		(14	)		-			8
Total deferred		235			9			113
Provision for income taxes	$	(79	)	$	(241	)	$	(234	)

The United States and foreign components of income from continuing operations before income taxes, minority interest, and change in accounting principle were as follows:

	Years ended December 31
Millions of dollars	2005		2004		2003
United States	$	1,721	$	135	$	254
Foreign		771		516		358
Total	$	2,492	$	651	$	612

The 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, minority interest, and change in accounting principle were as follows:

	Years ended December 31
	2005			2004			2003
United States statutory rate		35.0	%		35.0	%		35.0	%
State income taxes, net of federal
income tax benefit		1.0			0.6			0.9
Impact of foreign operations		(1.2	)		-			0.8
Adjustments of prior year taxes		0.1			(2.1	)		1.6
Dispositions		-			-			(1.6	)
Valuation allowance		(32.3	)		-			-
Other items, net		0.5			3.6			1.5
Total effective tax rate on
continuing operations		3.1	%		37.1	%		38.2	%

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 established in prior years.

The primary components of our deferred tax assets and liabilities and the related valuation allowances, including deferred tax accounts associated with discontinued operations, were as follows:

	December 31
Millions of dollars	2005		2004
Gross deferred tax assets:
Net operating loss carryforwards	$	861	$	115
Employee compensation and benefits		299		263
Foreign tax credit carryforward		146		135
Capitalized research and experimentation		113		85
Accrued liabilities		102		69
Insurance accruals		58		71
Construction contract accounting		41		75
Alternative minimum tax credit carryforward		21		21
Asbestos- and silica-related liabilities		-		1,770
Other		291		261
Total gross deferred tax assets	$	1,932	$	2,865
Gross deferred tax liabilities:
Depreciation and amortization	$	156	$	182
Insurance for asbestos- and silica-related
liabilities		-		318
Other		20		33
Total gross deferred tax liabilities	$	176	$	533
Valuation allowances:
Foreign tax credit limitation	$	146	$	135
Future tax attributes related to United States
net operating loss		137		1,073
Net operating loss carryforwards		43		43
Total valuation allowances	$	326	$	1,251
Net deferred income tax asset	$	1,430	$	1,081

We have $186 million of foreign net operating loss carryforwards that expire from 2006 through 2015 and additional foreign net operating loss carryforwards of $124 million with indefinite expiration dates. 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, which expires in 2025. The federal alternative minimum tax credits are available to reduce future United States federal income taxes on an indefinite basis.

We have established a valuation allowance against foreign tax credit carryovers and certain foreign operating loss carryforwards on the basis that we believe these assets will not be utilized in the statutory carryover period. We continue to carry a valuation allowance against our deferred tax asset related to asbestos and silica liabilities, which are now included in our United States net operating loss, although the amount of the valuation allowance was significantly reduced during 2005. The valuation allowance represents the anticipated impact of the United States net operating loss on our ability to utilize future foreign tax credits. We anticipate that the United States net operating loss will displace future foreign tax credits, and those credits will expire unutilized. Our 2005 tax rate is lower because we recorded favorable adjustments to our valuation allowance against our deferred tax asset related to asbestos and silica liabilities in 2005 totaling $805 million. Our strong 2005 earnings, coupled with an upward revision in our estimate of future domestic taxable income in 2006 and beyond, drove these adjustments.

Note 14. Shareholders’ Equity and Stock Incentive Plans

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

			Capital												Accumulated
			in Excess												Other
	Common		of Par			Treasury			Deferred			Retained			Comprehensive
Millions of dollars	Stock		Value			Stock			Compensation			Earnings			Income
Balance at December 31, 2002	$	1,141	$	293		$	(630	)	$	(75	)	$	3,110		$	(281	)
Cash dividends paid		-		-			-			-			(219	)		-
Stock-based compensation and employee						��
stock purchase, net		1		(19	)		60			11			-			-
Treasury stock purchased		-		-			(7	)		-			-			-
Tax benefit from exercise of options and
restricted stock		-		(1	)		-			-			-			-
Total dividends and other transactions with
shareholders		1		(20	)		53			11			(219	)		-
Comprehensive income (loss):
Net loss		-		-			-			-			(820	)		-
Other comprehensive income:
Cumulative translation adjustment		-		-			-			-			-			43
Realization of losses included in
net income		-		-			-			-			-			15
Minimum pension liability
adjustment, net of tax of $25		-		-			-			-			-			(88	)
Net unrealized gains on
investments and derivatives		-		-			-			-			-			13
Total comprehensive loss		-		-			-			-			(820	)		(17	)
Balance at December 31, 2003	$	1,142	$	273		$	(577	)	$	(64	)	$	2,071		$	(298	)

			Capital
			in															Accumulated
			Excess			Asbestos												Other
	Common		of Par			Trust			Treasury			Deferred			Retained			Comprehensive
Millions of dollars	Stock		Value			Shares			Stock			Compensation			Earnings			Income
Balance at December 31, 2003	$	1,142	$	273		$	-		$	(577	)	$	(64	)	$	2,071		$	(298	)
Cash dividends paid		-		-			-			-			-			(221	)		-
Stock-based compensation and
employee stock purchase, net		4		(3	)		-			107			(10	)		-			-
Treasury stock purchased		-		-			-			(7	)		-			-			-
Tax benefit from exercise of options and
restricted stock		-		7			-			-			-			-			-
Total dividends and other transactions
with shareholders		4		4			-			100			(10	)		(221	)		-
Asbestos trust shares		-		-			2,335			-			-			-			-
Comprehensive income (loss):
Net loss		-		-			-			-			-			(979	)		-
Other comprehensive income:
Cumulative translation
adjustment		-		-			-			-			-			-			33
Realization of gains included
in net income		-		-			-			-			-			-			(1	)
Minimum pension liability
adjustment, net of tax of $49		-		-			-			-			-			-			115
Net unrealized gains on
investments and derivatives
net of tax of $8		-		-			-			-			-			-			5
Total comprehensive loss		-		-			-			-			-			(979	)		152
Balance at December 31, 2004	$	1,146	$	277		$	2,335		$	(477	)	$	(74	)	$	871		$	(146	)
Cash dividends paid		-		-			-			-			-			(254	)		-
Stock-based compensation and
employee stock purchase, net		22		280			-			115			(24	)		-			-
Treasury stock purchased		-		-			-			(12	)		-			-			-
Tax benefit from exercise of options
and restricted stock		-		75			-			-			-			-			-
Total dividends and other transactions
with shareholders		22		355			-			103			(24	)		(254	)		-
Asbestos trust shares		149		2,186			(2,335	)		-			-			-			-
Comprehensive income (loss):
Net income		-		-			-			-			-			2,358			-
Other comprehensive income:
Cumulative translation
adjustment		-		-			-			-			-			-			(48	)
Realization of losses included in
net income		-		-			-			-			-			-			7
Minimum pension liability
adjustment, net of tax benefit
of $23		-		-			-			-			-			-			(54	)
Net unrealized losses on
investments and derivatives,
net of tax benefit of $15		-		-			-			-			-			-			(25	)
Total comprehensive income		-		-			-			-			-			2,358			(120	)
Balance at December 31, 2005	$	1,317	$	2,818		$	-		$	(374	)	$	(98	)	$	2,975		$	(266	)

100

*Accumulated other comprehensive income*	December 31
Millions of dollars	2005			2004			2003
Cumulative translation adjustment	$	(72	)	$	(31	)	$	(63	)
Pension liability adjustments		(184	)		(130	)		(245	)
Unrealized gains (losses) on investments and
derivatives		(10	)		15			10
Total accumulated other comprehensive income	$	(266	)	$	(146	)	$	(298	)

*Shares of common stock*	December 31
Millions of shares		2005			2004			2003
Issued		527			458			457
In treasury		(13	)		(16	)		(18	)
Total shares of common stock outstanding		514			442			439

In February 2006, the Board of Directors approved a 2:1 stock split, subject to shareholder approval at the 2006 annual shareholders meeting of a proposal to increase the number of authorized shares of common stock from one billion shares to two billion shares. Each shareholder would receive one additional share for each outstanding share held by the shareholder on the record date for the stock split. The record date will be announced after the approval of the increase in authorized shares of common stock.

Our 1993 Stock and Incentive Plan provides for the grant of any or all of the following types of awards:

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

stock appreciation rights, in tandem with stock options or freestanding;

restricted stock;

performance share awards; and

stock value equivalent awards.

Under the terms of the 1993 Stock and Incentive Plan, as amended, 49 million shares of common stock have been reserved for issuance to key employees. The plan specifies that no more than 16 million shares can be awarded as restricted stock. At December 31, 2005, 12 million shares were available for future grants under the 1993 Stock and Incentive Plan, of which seven million shares remained available for restricted stock awards.

All stock options under the 1993 Stock and Incentive Plan are granted at the fair market value of the common stock at the grant date. No further stock option grants are being made under the stock plans of acquired companies.

The following table represents our stock options granted, exercised, and forfeited during the past three years, and includes exercised and forfeited shares from our acquired companies’ stock plans.

101

						Weighted
	Number of Shares			Exercise Price		Average Exercise Price
Stock Options	(in millions)			per Share		per Share
Outstanding at December 31, 2002		18.5		$	9.10 - 61.50	$	32.10
Granted		2.4			18.60 - 24.76		23.45
Exercised		(0.4	)		8.28 - 23.52		14.75
Forfeited		(1.0	)		9.10 - 54.50		32.07
Outstanding at December 31. 2003		19.5		$	9.10 - 61.50	$	31.34
Granted		2.2			26.03 - 40.18		29.22
Exercised		(1.5	)		9.10 - 39.55		21.87
Forfeited		(0.8	)		9.10 - 54.50		33.19
Outstanding at December 31, 2004		19.4		$	9.10 - 61.50	$	31.74
Granted		1.4			40.94 - 68.92		49.44
Exercised		(9.1	)		9.10 - 61.50		32.09
Forfeited		(0.5	)		9.10 - 62.71		33.02
Outstanding at December 31, 2005		11.2		$	9.10 - 68.92	$	33.61

Options outstanding at December 31, 2005 were composed of the following:

			Outstanding
					Weighted				Exercisable
					Average		Weighted				Weighted
			Number of		Remaining		Average		Number of		Average
Range of			Shares		Contractual		Exercise		Shares		Exercise
Exercise Prices			(in millions)		Life		Price		(in millions)		Price
	$	9.10 - 23.79		2.5		6.5	$	18.65		1.7	$	17.25
	$	23.80 - 32.40		3.5		5.9		28.78		1.9		28.90
	$	32.41 - 40.93		2.8		4.4		38.76		2.7		38.76
	$	40.94 - 68.92		2.4		6.8		50.61		1.0		52.10
	$	9.10 - 68.92		11.2		5.9	$	33.61		7.3	$	32.92

There were 14.1 million options exercisable with a weighted average exercise price of $34.15 at December 31, 2004 and 13.8 million options exercisable with a weighted average exercise price of $34.59 at December 31, 2003.

Stock options generally expire 10 years from the grant date. Stock options under the 1993 Stock and Incentive Plan vest ratably over a three- or four-year period. Options under the non-employee directors’ plan vest after six months.

Restricted shares awarded under the 1993 Stock and Incentive Plan were 1,141,325 in 2005, 1,177,312 in 2004, and 431,865 in 2003. The shares awarded are net of forfeitures of 260,240 in 2005, 143,908 in 2004, and 248,620 in 2003. The weighted average fair market value per share at the date of grant of shares granted was $47.60 in 2005, $29.80 in 2004, and $22.94 in 2003.

Our Restricted Stock Plan for Non-Employee Directors allows for each non-employee director to receive an annual award of 400 restricted shares of common stock as a part of compensation. We reserved 100,000 shares of common stock for issuance to non-employee directors. Under this plan we issued 3,200 restricted shares in 2005 and 4,000 restricted shares in both 2004 and 2003. At December 31, 2005, 49,200 shares have been issued to non-employee directors under this plan. The weighted average fair market value per share at the date of grant of shares granted was $56.73 in 2005, $31.30 in 2004, and $22.24 in 2003.

102

Our Employees’ Restricted Stock Plan was established for employees who are not officers, for which 200,000 shares of common stock have been reserved. At December 31, 2005, 151,850 shares (net of 43,550 shares forfeited) have been issued. There were no forfeitures in 2005 or 2004. Forfeitures were 800 in 2003. No further grants are being made under this plan.

Under the terms of our Career Executive Incentive Stock Plan, 15 million shares of our common stock were reserved for issuance to officers and key employees at a purchase price not to exceed par value of $2.50 per share. At December 31, 2005, 11.7 million shares (net of 2.2 million shares forfeited) have been issued under the plan. The last grant made under this plan was in December 1992. No further grants will be made under the Career Executive Incentive Stock Plan.

Restricted shares issued under the 1993 Stock and Incentive Plan, Restricted Stock Plan for Non-Employee Directors, Employees’ Restricted Stock Plan, and the Career Executive Incentive Stock Plan are limited 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 in 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 issuance is being amortized and charged to income over the period during which the restrictions lapse, with similar credits to paid-in capital in excess of par value. At December 31, 2005, the unamortized amount is $98 million. We recognized compensation costs of $31 million in 2005, $21 million in 2004, and $20 million in 2003.

During 2002, our Board of Directors approved the 2002 ESPP and reserved 12 million shares for issuance. 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 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. Through the ESPP, there were approximately 1.3 million shares sold in 2005, approximately 1.7 million shares sold in 2004, and approximately 1.3 million shares sold in 2003.

In February 2006, our Board of Directors approved a share repurchase program up to $1.0 billion, which replaces our previous share repurchase program. 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.

Note 15. Preferred Stock

Our preferred stock consists of five million total authorized shares at December 31, 2005. We previously declared a dividend of one preferred stock purchase right on each outstanding share of common stock. The dividend was also applicable to each share of our common stock that was issued subsequent to adoption of the Rights Agreement entered into with Mellon Investor Services LLC. Each preferred stock purchase right entitled its holder to buy one two-hundredth of a share of our Series A Junior Participating Preferred Stock, without par value, at an exercise price of $75. These preferred stock purchase rights were subject to antidilution adjustments, which were described in the Rights Agreement entered into with Mellon. The preferred stock purchase rights did not have any voting rights and were not entitled to dividends. The preferred stock purchase rights expired on December 15, 2005 with the expiration of the Rights Agreement. On December 19, 2005, we filed a Certificate of Elimination, which eliminated all rights and preferences related to shares of our preferred stock.

Note 16. Income (Loss) Per Share

Basic income (loss) per share is based on the weighted average number of common shares outstanding during the period and, effective January 1, 2005, includes the 59.5 million shares that were contributed to the trusts established for the benefit of asbestos claimants. Diluted income (loss) per share includes additional common shares that would have been outstanding if potential common shares with a dilutive effect had been issued. A reconciliation of the number of shares used for the basic and diluted income (loss) per share calculation is as follows:

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Millions of shares	2005		2004		2003
Basic weighted average common shares outstanding		505		437		434
Dilutive effect of:
Stock options		5		2		2
Convertible senior notes premium		8		-		-
Restricted stock		1		1		-
Other		-		1		1
Diluted weighted average common shares outstanding		519		441		437

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 2005. The conversion price of $37.65 per share of common stock was greater than our average share price in 2004 and 2003 and, consequently, did not result in dilution.

Excluded from the computation of diluted income (loss) per share were options to purchase one million shares of common stock that were outstanding in 2005, nine million shares of common stock outstanding in 2004, and 15 million shares of common stock outstanding in 2003. 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 17. 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 contracts 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.

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Assets, liabilities, and forecasted cash flows denominated in foreign currencies. We utilize the derivative instruments described above to manage the foreign currency exposures related to specific assets and liabilities that are denominated in foreign currencies; however, we have not elected to account for these instruments as hedges for accounting purposes. Additionally, we utilize the derivative instruments described above to manage forecasted cash flows denominated in foreign currencies generally related to long-term engineering and construction projects. Beginning in 2003, we designated these contracts related to engineering and construction projects as cash flow hedges. The ineffective portion of these hedges was included in operating income in the accompanying consolidated statement of operations and was not material in 2005, 2004, or 2003. As of December 31, 2005, we had approximately $18 million in unrealized net losses on these cash flow hedges and, as of December 31, 2004, we had approximately $23 million in unrealized net gains on these cash flow hedges and $10 million as of December 31, 2003. We included these unrealized gains and losses on these cash flow hedges in other comprehensive income in the accompanying consolidated balance sheets. We expect approximately $10 million of the unrealized net losses on these cash flow hedges to be reclassified into earnings within a year. Changes in the timing or amount of the future cash flows being hedged could result in hedges becoming ineffective, and, as a result, the amount of unrealized gain or loss associated with those hedges would be reclassified from other comprehensive income into earnings. At December 31, 2005, the maximum length of time over which we are hedging our exposure to the variability in future cash flows associated with foreign currency forecasted transactions is 45 months. The fair value of these contracts was immaterial as of December 31, 2005, $27 million as of December 31, 2004, and immaterial as of December 31, 2003.

Notional amounts and fair market values. The notional amounts of open forward contracts and option contracts were $666 million at December 31, 2005 and $1.4 billion at December 31, 2004. 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.

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 our United States government contracts, primarily for projects in the Middle East, and from sales and services, including engineering and construction, 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 and the United Kingdom. We maintain an allowance for losses based upon the expected collectibility of all trade accounts receivable. In addition, see Note 5 for discussion of United States government 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

We have several debt instruments outstanding that have both fixed and variable interest rates. We manage our ratio of fixed-rate to variable-rate debt through the use of different types of debt instruments and derivative instruments. As of December 31, 2005, we held no material interest rate derivative instruments.

Fair market value of financial instruments. The estimated fair market value of long-term debt was $2.9 billion at December 31, 2005 and $3.7 billion at December 31, 2004, as compared to the carrying amount of $3.2 billion at December 31, 2005 and $3.9 billion at December 31, 2004. 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 variable-rate long-term debt approximates fair market value because these instruments reflect market changes to interest rates. 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.

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Note 18. 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 both continuing and discontinued operations totaled $164 million in 2005, $147 million in 2004, and $87 million in 2003. Additionally, we participate in a Canadian multi-employer plan to which we contributed $24 million and $20 million in 2005 and 2004, respectively. For 2004, we amended certain defined contribution plans to allow for a non-elective contribution, which resulted in an increase of $53 million over the 2003 expense;

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

Dresser Retiree Medical

Through 2003, we were responsible for the majority of the costs for the Dresser Retiree Medical Plan. An amendment was made to this plan at the end of 2003 to limit our share of the costs and eventually eliminate the plan in 2005. We presented the impact of this amendment in our 2003 notes to consolidated financial statements, which reduced our projected benefit obligation by $86 million and increased our unrecognized prior service benefit by the same amount, with no impact to our balance sheet or statement of operations. In December 2004, the United States District Court ruled that we must continue to maintain the Dresser Retiree Medical Plan as we had in the past. We revised our 2003 presentation of the projected benefit obligation and unrecognized prior service benefit to reflect the plan at its pre-amendment amounts. We also adjusted our annual postretirement benefit expense by $13 million in the fourth quarter of 2004.

Benefit obligation and plan assets

Plan assets, expenses, and obligation for retirement plans in the following tables include both continuing and discontinued operations. We use a September 30 measurement date for our international plans and an October 31 measurement date for our domestic plans.

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	Pension Benefits												Other
	United						United						Postretirement
*Benefit obligation*	States			Int’l			States			Int’l			Benefits
Millions of dollars	2005						2004						2005			2004
Change in benefit obligation
Benefit obligation at beginning of period	$	166		$	3,127		$	160		$	2,501		$	175		$	188
Service cost		1			72			1			92			1			1
Interest cost		9			172			10			155			10			11
Plan participants’ contributions		-			16			-			22			9			12
Effect of business combinations and new plans		-			1			-			14			-			-
Amendments		-			-			-			(1	)		-			-
Settlements/curtailments		-			(69	)		-			(9	)		-			-
Currency fluctuations		-			(41	)		-			371			-			-
Actuarial (gain) loss		8			416			8			72			(19	)		(16	)
Benefits paid		(11	)		(94	)		(13	)		(90	)		(17	)		(21	)
Benefit obligation at end of period	$	173		$	3,600		$	166		$	3,127		$	159		$	175
Accumulated benefit obligation at end of period	$	172		$	3,014		$	165		$	2,451		$	-		$	-

	Pension Benefits												Other
	United						United						Postretirement
*Plan assets*	States			Int’l			States			Int’l			Benefits
Millions of dollars	2005						2004						2005			2004
Change in plan assets
Fair value of plan assets at beginning of
period	$	125		$	2,576		$	113		$	2,003		$	-		$	-
Actual return on plan assets		12			541			17			259			-			-
Employer contributions		7			74			8			77			8			9
Settlements and transfers		-			(1	)		-			(8	)		-			-
Plan participants’ contributions		-			16			-			22			9			12
Effect of business combinations and new
plans		-			-			-			9			-			-
Currency fluctuations		-			(35	)		-			304			-			-
Benefits paid		(11	)		(94	)		(13	)		(90	)		(17	)		(21	)
Fair value of plan assets at end of period	$	133		$	3,077		$	125		$	2,576		$	-		$	-

Our target allocations for 2006 by asset category and our pension plan asset allocations at December 31, 2005 and 2004 were as follows:

				Percentage of Plan Assets at Year-End
	Target Allocation			United States			Int’l			United States			Int’l
	2006			2005						2004
Asset category
Equity securities		55% - 70	%		63	%		62	%		63	%		64	%
Debt securities		25% - 45	%		36	%		30	%		33	%		34	%
Real estate		0	%		0	%		0	%		0	%		0	%
Other		0% - 10	%		1	%		8	%		4	%		2	%
Total		100	%		100	%		100	%		100	%		100	%

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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 asset class for diversification purposes. Specific guidelines for each asset class and investment manager are implemented and monitored.

Funded status

The funded status of the plans, reconciled to the amount reported on the consolidated balance sheets, was as follows:

	Pension Benefits												Other
	United						United						Postretirement
	States			Int’l			States			Int’l			Benefits
Millions of dollars	2005						2004						2005			2004
Fair value of plan assets at end of period	$	133		$	3,077		$	125		$	2,576		$	-		$	-
Benefit obligation at end of period		173			3,600			166			3,127			159			175

Funded status	$	(40	)	$	(523	)	$	(41	)	$	(551	)	$	(159	)	$	(175	)
Employer contribution		-			21			-			19			1			1
Unrecognized transition asset		(1	)		-			(1	)		-			-			-
Unrecognized actuarial loss (gain)		76			602			74			632			(7	)		12
Unrecognized prior service benefit		-			(8	)		-			(3	)		(3	)		(4	)
Purchase accounting adjustment		-			(78	)		-			(82	)		-			-
Net amount recognized	$	35		$	14		$	32		$	15		$	(168	)	$	(166	)

Amounts recognized in the consolidated balance sheets were as follows:

	Pension Benefits												Other
	United						United						Postretirement
	States			Int’l			States			Int’l			Benefits
Millions of dollars	2005						2004						2005			2004
Prepaid benefit cost	$	37		$	115		$	34		$	103		$	-		$	-
Accrued benefit liability, including additional
minimum liability		(77	)		(295	)		(74	)		(214	)		(168	)		(166	)
Intangible asset		-			2			-			8			-			-
Accumulated other comprehensive income,
net of tax		49			135			47			83			-			-
Deferred tax asset		26			57			25			35			-			-
Net amount recognized	$	35		$	14		$	32		$	15		$	(168	)	$	(166	)

We recognized an additional minimum pension liability for the underfunded defined benefit plans of $72 million in 2005, of which $54 million was recorded as “other comprehensive income.” We reduced our additional minimum pension liability by $164 million in 2004, of which $115 million was recorded as “Other comprehensive income.” The additional minimum liability is equal to the excess of the accumulated benefit obligation over plan assets and accrued liabilities. A corresponding amount is recognized as either an intangible asset or a change to accumulated other comprehensive income.

The projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets as of December 31, 2005 and 2004 were as follows:

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	Pension Benefits
Millions of dollars	2005		2004
Projected benefit obligation	$	2,170	$	1,942
Accumulated benefit obligation	$	1,952	$	1,629
Fair value of plan assets	$	1,756	$	1,503

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 $160 million to our international pension plans in 2006. For our domestic plans, we expect our contributions to be no more than $4 million in 2006. In order to mitigate a portion of the projected underfunding of our United Kingdom pension plans, ESG contributed $38 million and KBR contributed $74 million in February 2006. These amounts are included in the $160 million 2006 funding obligation. 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
	United				Postretirement
Millions of dollars	States		Int’l		Benefits
2006	$	13	$	96	$	14
2007		11		99		15
2008		11		105		15
2009		11		107		15
2010		11		111		15
Years 2011 - 2015		58		380		72

Net periodic cost

	Pension Benefits																		Other
	United						United						United						Postretirement
	States			Int’l			States			Int’l			States			Int’l			Benefits
Millions of dollars	2005						2004						2003						2005			2004			2003
Components of net
periodic benefit cost
Service cost	$	1		$	72		$	1		$	92		$	1		$	72		$	1		$	1		$	1
Interest cost		9			172			10			155			10			120			10			11			12
Expected return on plan
assets		(10	)		(186	)		(11	)		(173	)		(12	)		(136	)		-			-			-
Transition amount		-			-			-			(1	)		-			(1	)		-			-			-
Amortization of prior service
cost		-			-			-			-			-			-			(1	)		(1	)		-
Settlements/curtailments		-			5			1			(2	)		2			-			-			-			-
Recognized actuarial loss		4			17			3			16			1			18			-			1			1
Net periodic benefit cost	$	4		$	80		$	4		$	87		$	2		$	73		$	10		$	12		$	14

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Assumptions

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 rates used were as follows:

Weighted-average
assumptions used to	Pension Benefits
determine benefit	United						United						United						Other Postretirement
obligations at	States			Int’l			States			Int’l			States			Int’l			Benefits
measurement date	2005						2004						2003						2005			2004			2003
Discount rate		5.75	%		2.25-8.0	%		5.75	%		2.5-8.0	%		6.25	%		2.5-9.0	%		5.75	%		5.75	%		6.25	%
Rate of compensation
increase		4.5	%		2.0-5.0	%		4.5	%		2.0-5.0	%		4.5	%		2.0-6.5	%		N/A			N/A			N/A

Weighted-average
assumptions used to
determine net	Pension Benefits
periodic benefit cost	United						United						United						Other Postretirement
for years ended	States			Int’l			States			Int’l			States			Int’l			Benefits
December 31	2005						2004						2003						2005			2004			2003
Discount rate		5.75	%		2.5-8.0	%		6.25	%		2.5-9.0	%		7.0	%		2.5-7.5	%		5.75	%		6.25	%		7.0	%
Expected return on plan assets		8.5	%		5.0-7.0	%		8.5	%		5.25-7.5	%		8.75	%		5.5-8.0	%		N/A			N/A			N/A
Rate of compensation
increase		4.5	%		2.0-5.0	%		4.5	%		2.0-6.5	%		4.5	%		2.0-7.0	%		N/A			N/A			N/A

The weighted average assumptions for the Nigerian and Indonesian plans are not included in the above tables as the plans were immaterial. The discount rate was determined based on the rates of return of high-quality fixed income investments as of the measurement date. Our discount rate assumption for the United States domestic pension plans was based on the weighted average annualized yield of the Moody Baa-Aaa corporate bonds. For our United Kingdom pension plans, which constitute 95% of our international pension plans’ projected benefit obligation, the discount rate was based on the annualized yield of the iBoxx AA corporate bonds, and was reduced from 5.5% at December 31, 2004 to 5.0% at December 31, 2005. This decrease in the discount rate resulted in increases in the present value of our benefit obligations.

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.

Assumed health care cost trend rates at
December 31	2005			2004			2003
Health care cost trend rate assumed for next year		10.0	%		11.5	%		13.0	%
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		2008			2008			2008

Assumed health care cost trend rates are not expected to have a significant impact on the amounts reported for the total of the 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	$	8	$	(7	)

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Note 19. 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*	Years ended December 31
Millions of dollars	2005			2004			2003
Revenue	$	3,626		$	3,887		$	3,708
Operating income (loss)	$	(25	)	$	7		$	201
Net income (loss)	$	(7	)	$	(12	)	$	175

*Combined financial position*	December 31
Millions of dollars	2005		2004
Current assets	$	2,421	$	2,339
Noncurrent assets		2,760		2,723
Total	$	5,181	$	5,062
Current liabilities	$	2,226	$	1,950
Noncurrent liabilities		2,400		2,394
Shareholders’ equity		555		718
Total	$	5,181	$	5,062

The FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (FIN 46), in January 2003. In December 2003, the FASB issued FIN 46R, a revision that supersedes the original interpretation. We adopted FIN 46R effective January 1, 2004.

FIN 46R requires the consolidation of entities in which a company absorbs a majority of another entity’s expected losses, receives a majority of the other entity’s expected residual returns, or both, as a result of ownership, contractual, or other financial interests in the other entity. Previously, entities were generally consolidated based upon a controlling financial interest through ownership of a majority voting interest in the entity.

The following details our variable interests in variable interest entities by business segment.

Production Optimization segment:

during the second quarter of 2001, we formed a joint venture, WellDynamics, with Shell in which we held a 50% equity interest and accounted for the investment using the equity method in our Digital and Consulting Solutions segment. The joint venture was established for the further development and deployment of new technologies related to completions and well intervention services and products. In the first quarter of 2004, Halliburton and Shell restructured WellDynamics whereby Halliburton acquired an additional 1% of WellDynamics from Shell, giving Halliburton 51% ownership and control of day-to-day operations. The joint venture is considered a variable interest entity under FIN 46, and we have determined that we are the primary beneficiary of the entity. Beginning in the first quarter of 2004, WellDynamics was consolidated. The consolidation of WellDynamics resulted in an increase to our goodwill of $109 million, which was previously carried as equity method goodwill in our investment balance, and an increase in long-term debt of $27 million. There are no assets of WellDynamics that collateralize its obligations;

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Government and Infrastructure segment:

during 2001, we formed a joint venture that owns and operates heavy equipment transport vehicles in the United Kingdom and in which we own a 50% equity interest with an unrelated partner. This variable interest entity was formed to construct, operate, and service certain assets for a third party and was funded with third-party debt. The construction of the assets was completed in the second quarter of 2004, and the operating and service contract related to the assets extends through 2023. The proceeds from the debt financing were used to construct the assets and will be paid down with cash flows generated during the operation and service phase of the contract with the third party. As of December 31, 2005, the joint venture had total assets of $147 million and total liabilities of $152 million. Our aggregate exposure to loss as a result of our involvement with this joint venture is limited to our equity investment and subordinated debt of $7 million and any future losses related to the operation of the assets. We are not the primary beneficiary. The joint venture is accounted for under the equity method of accounting;

we are involved in three privately funded initiatives executed through joint ventures to design, build, operate, and maintain roadways for certain government agencies in the United Kingdom. We have a 25% ownership interest in these joint ventures and account for them under the equity method. The joint ventures have obtained financing through third parties that is not guaranteed by us. These joint ventures are considered variable interest entities. We are not the primary beneficiary of these joint ventures and, therefore, account for them using the equity method. As of December 31, 2005, these joint ventures had total assets of $1.4 billion and total liabilities of $1.5 billion. Our maximum exposure to loss is limited to our equity investments in and loans to the joint ventures, which totaled $35 million at December 31, 2005;

we participate in a privately funded initiative executed through an unincorporated joint venture and operating company formed for operating and maintaining a railroad freight business in Australia. We own 36.7% of the joint venture and operating company and we are accounting for these investments using the equity method. This joint venture is considered a variable interest entity. The joint venture is funded through senior and subordinated debt and equity contributions from the joint venture partners. We are not the primary beneficiary of the joint venture. As of December 31, 2005, the joint venture had total assets of $796 million and total liabilities of $672 million. Our maximum exposure to loss is limited to our equity investments and senior operating notes in the joint venture and the operating company totaling $81 million and our commit to fund an additional $9 million of notes to the operating company as of December 31, 2005; and

we participate in a privately funded initiative executed through certain joint ventures formed to design, build, operate, and maintain a viaduct and several bridges in southern Ireland. The joint ventures were funded through debt and were formed with very little equity. We have up to a 25% ownership interest in the project’s joint ventures, and we are accounting for this interest under the equity method. These joint ventures are considered variable interest entities. We are not the primary beneficiary of the joint ventures. As of December 31, 2005, the joint ventures had total assets of $239 million and total liabilities of $226 million. Our maximum exposure to loss is limited to our equity investments in and loan to the joint venture, totaling $4 million at December 31, 2005, and our share of any future losses resulting from the project.

Energy and Chemicals segment:

We perform many of our long-term energy-related construction projects through incorporated or unincorporated joint ventures. Typically, these ventures are dissolved upon completion of the project. Many of these ventures are funded by advances from the project owner and, accordingly, require no equity investment by the joint venture partners or shareholders. Occasionally, a venture incurs losses, which then requires funding by the joint venture partners or shareholders in proportion to their interest percentages. The ventures with little or no initial equity investment are considered variable interest entities. Our significant variable interest entities are:

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during 2005, we formed a joint venture to engineer and construct a gas monetization facility. We own a 50% equity interest and determined that we are the primary beneficiary of the joint venture. The joint venture is consolidated. At December 31, 2005, the joint venture’s had $324 million in total assets and $311 million in total liabilities. There are no consolidated assets that collateralize the joint venture obligations, however at December 31, 2005, the joint venture had approximately $173 million of cash which relates to advance billings in connection with the joint venture’s obligations under the EPC contract; and

we also have equity ownership in three joint ventures to execute EPC projects. Our equity ownership ranges from 33% to 50%, and these joint ventures are considered variable interest entities. We are not the primary beneficiary, and we account for these joint ventures under the equity method. At December 31, 2005, these joint ventures had aggregate assets of $861 million and aggregate liabilities of $912 million.

Note 20. Reorganization of Business Operations

Effective October 1, 2004, we restructured KBR into two segments, Government and Infrastructure and Energy and Chemicals. In 2004, we recorded restructuring and related costs of $40 million related to the reorganization. The total restructuring charges consisted of $31 million in personnel termination benefits and $9 million in impairment charges on technology-related assets. For the year ended December 31, 2004, $32 million of the restructuring charge was included in “Cost of services” and $8 million was included in “General and administrative” on the consolidated statements of operations. As of December 31, 2005, all amounts related to the 2004 restructuring have been paid and the balance in the restructuring reserve account has been reduced to zero.

Note 21. New Accounting Pronouncements

In March 2005, the FASB issued FASB Interpretation No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” This statement clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. The provisions of FIN 47 were adopted as of December 31, 2005. The total liability recorded at adoption for asset retirement obligations and the related accretion and depreciation expense for all periods presented is immaterial to our consolidated financial position and results of operations. We own properties where we have below ground storage tanks, test wells, and other items that are required to be removed before we vacate the properties. A liability has not been recorded for these items because the fair value cannot be reasonably estimated. We believe there is an indeterminate settlement date for these obligations because the range of time over which we may settle the obligation is unknown or cannot be estimated.

113

HALLIBURTON COMPANY

Selected Financial Data

(Unaudited)

Millions of dollars and shares	Years ended December 31
except per share and employee data	2005			2004			2003			2002			2001
Total revenue	$	20,994		$	20,466		$	16,271		$	12,572		$	13,046
Total operating income (loss)	$	2,662		$	837		$	720		$	(112	)	$	1,084
Nonoperating expense, net		(170	)		(186	)		(108	)		(116	)		(130	)
Income (loss) from continuing
operations before income taxes
and minority interest		2,492			651			612			(228	)		954
Provision for income taxes		(79	)		(241	)		(234	)		(80	)		(384	)
Minority interest in net income of
consolidated subsidiaries		(56	)		(25	)		(39	)		(38	)		(19	)
Income (loss) from continuing operations	$	2,357		$	385		$	339		$	(346	)	$	551
Income (loss) from discontinued operations	$	1		$	(1,364	)	$	(1,151	)	$	(652	)	$	257
Net income (loss)	$	2,358		$	(979	)	$	(820	)	$	(998	)	$	809
Basic income (loss) per share:
Continuing operations	$	4.67		$	0.88		$	0.78		$	(0.80	)	$	1.29
Net income (loss)		4.67			(2.25	)		(1.89	)		(2.31	)		1.89
Diluted income (loss) per share:
Continuing operations		4.54			0.87			0.78			(0.80	)		1.28
Net income (loss)		4.54			(2.22	)		(1.88	)		(2.31	)		1.88
Cash dividends per share		0.50			0.50			0.50			0.50			0.50
Return on average shareholders’ equity		45.76	%		(30.22	)%		(26.86	)%		(24.02	)%		18.64	%
Financial position:
Net working capital	$	4,890		$	2,898		$	1,355		$	2,288		$	2,665
Total assets		15,010			15,864			15,556			12,844			10,966
Property, plant, and equipment, net		2,648			2,553			2,526			2,629			2,669
Long-term debt (including current maturities)		3,174			3,940			3,437			1,476			1,484
Shareholders’ equity		6,372			3,932			2,547			3,558			4,752
Total capitalization		9,568			7,887			6,002			5,083			6,280
Shareholders’ equity per share		12.40			8.90			5.80			8.16			10.95
Basic weighted average common shares
outstanding		505			437			434			432			428
Diluted weighted average common shares
outstanding		519			441			437			432			430
Other financial data:
Capital expenditures	$	(651	)	$	(575	)	$	(515	)	$	(764	)	$	(797	)
Long-term borrowings (repayments), net		(799	)		476			1,896			(15	)		412
Depreciation, depletion, and
amortization expense		504			509			518			505			531
Goodwill amortization included in
depreciation, depletion, and
amortization expense		-			-			-			-			42
Payroll and employee benefits		(5,888	)		(5,608	)		(5,154	)		(4,875	)		(4,818	)
Number of employees		106,000			97,000			101,000			83,000			85,000

114

HALLIBURTON COMPANY

Quarterly Data and Market Price Information

(Unaudited)

Millions of dollars except per	Quarter
share data	First			Second			Third			Fourth			Year
2005
Revenue	$	4,938		$	5,163		$	5,095		$	5,798		$	20,994
Operating income		586			607			690			779			2,662
Income from continuing operations		367			391			499			1,100			2,357
Income (loss) from discontinued operations		(2	)		1			-			2			1
Net income		365			392			499			1,102			2,358
Earnings per share:
Basic income per share:
Income from continuing operations		0.73			0.78			0.99			2.16			4.67
Income (loss) from discontinued
operations		-			-			-			-			-
Net income		0.73			0.78			0.99			2.16			4.67
Diluted income per share:
Income from continuing operations		0.72			0.76			0.95			2.08			4.54
Income (loss) from discontinued
operations		-			-			-			-			-
Net income		0.72			0.76			0.95			2.08			4.54
Cash dividends paid per share		0.125			0.125			0.125			0.125			0.50
Common stock prices (1)
High		45.29			49.39			69.78			69.37			69.78
Low		37.18			39.65			45.76			54.70			37.18
2004
Revenue	$	5,519		$	4,956		$	4,790		$	5,201		$	20,466
Operating income (loss)		175			(26	)		342			346			837
Income (loss) from continuing operations		76			(58	)		186			181			385
Loss from discontinued operations		(141	)		(609	)		(230	)		(384	)		(1,364	)
Net loss		(65	)		(667	)		(44	)		(203	)		(979	)
Earnings per share:
Basic income (loss) per share:
Income (loss) from continuing operations		0.17			(0.13	)		0.43			0.41			0.88
Loss from discontinued operations		(0.32	)		(1.39	)		(0.54	)		(0.88	)		(3.13	)
Net loss		(0.15	)		(1.52	)		(0.11	)		(0.47	)		(2.25	)
Diluted income (loss) per share:
Income (loss) from continuing operations		0.17			(0.13	)		0.42			0.40			0.87
Loss from discontinued operations		(0.32	)		(1.39	)		(0.51	)		(0.86	)		(3.09	)
Net loss		(0.15	)		(1.52	)		(0.09	)		(0.46	)		(2.22	)
Cash dividends paid per share		0.125			0.125			0.125			0.125			0.50
Common stock prices (1)
High		32.70			32.35			33.98			41.69			41.69
Low		25.80			27.35			26.45			33.08			25.80

(1) New York Stock Exchange - composite transactions high and low intraday price.

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PART III

Item 10. Directors and Executive Officers of the Registrant.

The information required for the directors of the Registrant is incorporated by reference to the Halliburton Company Proxy Statement for our 2006 Annual Meeting of Stockholders (File No. 1-3492), under the caption “Election of Directors.” The information required for the executive officers of the Registrant is included under Part I on pages 10 and 11 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 2006 Annual Meeting of Stockholders (File No. 1-3492), under the caption “Section 16(a) Beneficial Ownership Reporting Compliance.”

Audit Committee financial experts

In the business judgment of the Board of Directors, all four members of the Audit Committee, Robert L. Crandall, J. Landis Martin, Jay A. Precourt, and Debra L. Reed 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 2006 Annual Meeting of Stockholders (File No. 1-3492) under the captions “Compensation Committee Report on Executive Compensation,” “Comparison of Cumulative Total Return,” “Summary Compensation Table,” “Option Grants for Fiscal 2005,” “Aggregated Option Exercises in Fiscal 2005 and December 31, 2005 Option Values,” “Long-Term Incentive Plans - Awards in Fiscal 2005,” “Employment Contracts and Change-in-Control Arrangements,” and “Directors’ Compensation.”

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

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2006 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Stock Ownership of Certain Beneficial Owners and Management.”

Item 12(b). Security Ownership of Management.

Item 12(c). Changes in Control.

Not applicable.

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

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2006 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Equity Compensation Plan Information.”

Item 13. Certain Relationships and Related Transactions.

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2006 Annual Meeting of Stockholders (File No. 1-3492) 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 2006 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Fees Paid to KPMG LLP.”

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PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) 1. 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 62 and 63 and pages 64 through 113 of this annual report. See index on page 13.

2.	Financial Statement Schedules:	Page No.

	Report on supplemental schedule of KPMG LLP	124

	Schedule II - Valuation and qualifying accounts for the three
	years ended December 31, 2005	125

	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.

3. Exhibits:

Exhibit

Number Exhibits

3.1 Restated Certificate of Incorporation of Halliburton Company filed with the Secretary of State of Delaware on May 21, 2004 (incorporated by reference to Exhibit 3.1 to Halliburton’s Registration Statement on Form S-4 filed on July 19, 2004, Registration No. 333-112977).

3.2 By-laws of Halliburton revised effective February 12, 2003 (incorporated by reference to Exhibit 3.2 to Halliburton’s Form 10-K for the year ended December 31, 2002, File No. 1-3492).

3.3 Certificate of Elimination with respect to Series A Junior Participating Preferred Stock (incorporated by reference to Exhibit 4.1 to Halliburton’s Form 8-K filed December 19, 2005, File No. 1-3492).

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

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

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

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

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

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

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

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

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

4.10 Copies of instruments that define the rights of holders of miscellaneous long-term notes of Halliburton and its subsidiaries, totaling $10 million in the aggregate at December 31, 2005, have not been filed with the Commission. Halliburton agrees to furnish copies of these instruments upon request.

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

4.12 Form of 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. 1-3492).

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4.13 Form of Indenture, between Dresser and 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 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 JPMorgan Chase Bank, as Trustee, to the Indenture dated as of April 18, 1996, as supplemented by the First Supplemental Indenture dated as of August 6, 1996 (incorporated by reference to Exhibit 4.15 to Halliburton’s Form 10-K for the year ended December 31, 2003, File No. 1-3492).

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

4.16 Form of debt security of 6% Notes due August 1, 2006 (incorporated by reference to Exhibit 4.2 to Halliburton’s Form 8-K dated January 8, 2002, File No. 1-3492).

4.17 Credit Facility in the amount of £80 million dated November 29, 2002 between Devonport Royal Dockyard Limited and Devonport Management Limited and The Governor and Company of the Bank of Scotland, HSBC Bank Plc and The Royal Bank of Scotland Plc (incorporated by reference to Exhibit 4.22 to Halliburton’s Form 10-K for the year ended December 31, 2002, File No. 1-3492).

4.18 Senior Indenture dated as of June 30, 2003 between Halliburton and 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. 1-3492).

4.19 Form of note of 3.125% Convertible Senior Notes due July 15, 2023 (included as Exhibit A to Exhibit 4.18 above).

4.20 First Supplemental Indenture dated as of December 17, 2004 between Halliburton and JPMorgan Chase Bank, National Association (formerly JPMorgan Chase Bank), as trustee, to Indenture dated as of June 30, 2003, between Halliburton and JPMorgan Chase Bank, National Association (formerly 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. 1-3492).

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

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

119

4.23 Form of note of 5.5% senior notes due October 15, 2010 (included as Exhibit B to Exhibit 4.22 above).

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

4.25 Form of note of 7.6% debentures due 2096 (included as Exhibit A to Exhibit 4.24 above).

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

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

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

10.2 Retirement Plan for the Directors of Halliburton Company, as amended and restated effective May 16, 2000 (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 10-Q for the quarter ended September 30, 2000, File No. 1-3492).

* 10.3 Halliburton Company 1993 Stock and Incentive Plan, as amended and restated effective February 16, 2006.

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

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

10.6 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).

10.7 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).

10.8 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).

120

10.9 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).

10.10 Dresser Industries, Inc. Deferred Compensation Plan for Non-Employee Directors, as restated and amended effective November 1, 1997 (incorporated by reference to Exhibit 4.5 to Dresser’s Registration Statement on Form S-8, Registration No. 333-40829).

10.11 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).

10.12 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).

10.13 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).

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

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

10.16 Halliburton Company Benefit Restoration Plan, as amended and restated effective January 1, 2004 (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 10-Q for the quarter ended September 30, 2004, File No. 1-3492).

* 10.17 Halliburton Annual Performance Pay Plan, as amended and restated effective January 26, 2006.

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

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

10.20 Halliburton Elective Deferral Plan as amended and restated effective May 1, 2002 (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 10-Q for the quarter ended June 30, 2002, File No. 1-3492).

* 10.21 Halliburton Company 2002 Employee Stock Purchase Plan, as amended and restated May 17, 2005.

10.22 Halliburton Company Directors’ Deferred Compensation Plan as amended and restated effective as of October 22, 2002 (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 10-Q for the quarter ended September 30, 2002, File No. 1-3492).

121

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

10.24 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. 1-3492).

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

10.26 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. 1-3492).

10.27 Five Year Revolving Credit Agreement dated as of March 10, 2005, among Halliburton, as Borrower, the Banks and the Issuing Banks party thereto, Citicorp North America, Inc. (“CNAI”), as Paying Agent, and CNAI and JPMorgan Chase Bank, N.A., as Co-Administrative Agents (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed March 10, 2005, File No. 1-3492).

10.28 Underwriting Agreement dated March 17, 2005 among Halliburton Company, DII Industries, LLC Asbestos PI Trust, J.P. Morgan Securities Inc., Goldman, Sachs & Co., and Citigroup Global Markets Inc. (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 8-K filed March 18, 2005, File No. 1-3492).

* 10.29 Halliburton Company Supplemental Executive Retirement Plan as amended and restated effective December 7, 2005.

* 10.30 Five Year Revolving Credit Agreement, dated as of December 16, 2005, among KBR Holdings, LLC, a Delaware limited liability company, as Borrower, the Banks and the Issuing Banks party thereto, Citibank, N.A. (“Citibank”), as Paying Agent, and Citibank and HSBC Bank USA, National Association, as Co-Administrative Agents.

* 12 Statement of Computation of Ratio of Earnings to Fixed Charges.

* 21 Subsidiaries of the Registrant.

* 23.1 Consent of KPMG LLP.

24.1 Powers of attorney for the following directors signed in January 2004 (incorporated by reference to Exhibit 24.1 to Halliburton’s Form 10-K for the year ended December 31, 2003, File No. 1-3492):

Robert L. Crandall

Kenneth T. Derr

W. R. Howell

Ray L. Hunt

J. Landis Martin

Jay A. Precourt

Debra L. Reed

* 24.2 Power of attorney for S. Malcolm Gillis signed in July 2005.

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* 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.

123

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ON SUPPLEMENTAL SCHEDULE

The Board of Directors and Shareholders

Halliburton Company:

Under date of March 3, 2006, we reported on the consolidated balance sheets of Halliburton Company and subsidiaries as of December 31, 2005 and 2004, 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, 2005, 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) included 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 the consolidated financial statement schedule based on our audits.

In our opinion, such 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.

/s/ KPMG LLP

Houston, Texas

March 3, 2006

124

HALLIBURTON COMPANY

Schedule II - Valuation and Qualifying Accounts

(Millions of Dollars)

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

			Additions
	Balance at		Charged to		Charged to						Balance at
	Beginning		Costs and		Other						End of
Descriptions	of Period		Expenses		Accounts			Deductions			Period
Year ended December 31, 2003:
Deducted from accounts and notes receivable:
Allowance for bad debts	$	157	$	44	$	4		$	(30) (a	)	$	175
Accrued reorganization charges	$	10	$	-	$	-		$	(9	)	$	1
Reserve for disputed and unallowable costs
incurred under government contracts	$	13	$	-	$	36 (b	)	$	(1	)	$	48

Year ended December 31, 2004:
Deducted from accounts and notes receivable:
Allowance for bad debts	$	175	$	22	$	2		$	(72) (a	)	$	127
Accrued reorganization charges	$	1	$	40	$	-		$	(22	)	$	19
Reserve for disputed and unallowable costs
incurred under government contracts	$	48	$	-	$	83 (b	)	$	-		$	131

Year ended December 31, 2005:
Deducted from accounts and notes receivable:
Allowance for bad debts	$	127	$	64	$	-		$	(101) (a	)	$	90
Accrued reorganization charges	$	19	$	-	$	-		$	(19	)	$	-
Reserve for disputed and unallowable costs
incurred under government contracts	$	131	$	-	$	11 (b	)	$	(9	)	$	133

(a) Receivable write-offs, net of recoveries, and reclassifications.

(b) Reserves have been recorded as reductions of revenue, net of reserves no longer required.

125

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 10th day of March, 2006.


	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 10th day of March, 2006.

Signature	Title




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




/s/ C. Christopher Gaut	Executive Vice President and
C. Christopher Gaut	Chief Financial Officer




/s/ Mark A. McCollum	Senior Vice President and
Mark A. McCollum	Chief Accounting Officer

126

Signature	Title

* 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

* Ray L. Hunt	Director
Ray L. Hunt

* J. Landis Martin	Director
J. Landis Martin

* Jay A. Precourt	Director
Jay A. Precourt

* Debra L. Reed	Director
Debra L. Reed




* /s/ Margaret E. Carriere
Margaret E. Carriere, Attorney-in-fact

127

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Halliburton (HAL) 10-K2005 FY Annual report

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