Edgar Filing: HALLIBURTON CO

December 31, 2006 Form 10-K Final

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, 2006

[ ] 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, 2006, determined using the per share closing price on the New York Stock Exchange Composite tape of $37.10 on that date was approximately $38,102,000,000.

As of February 16, 2007, there were 999,172,145 shares of Halliburton Company Common Stock, $2.50 par value per share, outstanding.

Portions of the Halliburton Company Proxy Statement for our 2007 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, 2006

PART I		PAGE
Item 1.	Business	1
Item 1(a).	Risk Factors	9
Item 1(b).	Unresolved Staff Comments	9
Item 2.	Properties	10
Item 3.	Legal Proceedings	11
Item 4.	Submission of Matters to a Vote of Security Holders	11
EXECUTIVE OFFICERS OF THE REGISTRANT		12
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters,
	and Issuer Purchases of Equity Securities	14
Item 6.	Selected Financial Data	15
Item 7.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operation	15
Item 7(a).	Quantitative and Qualitative Disclosures About Market Risk	15
Item 8.	Financial Statements and Supplementary Data	16
Item 9.	Changes in and Disagreements with Accountants on Accounting and
	Financial Disclosure	16
Item 9(a).	Controls and Procedures	16
Item 9(b).	Other Information	16
MD&A AND FINANCIAL STATEMENTS
Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Management’s Report on Internal Control Over Financial Reporting		69
Reports of Independent Registered Public Accounting Firm		70
Consolidated Statements of Operations		72
Consolidated Balance Sheets		73
Consolidated Statements of Shareholders’ Equity		74
Consolidated Statements of Cash Flows		75
Notes to Consolidated Financial Statements		76
Selected Financial Data (Unaudited)		127
Quarterly Data and Market Price Information (Unaudited)		128
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	129
Item 11.	Executive Compensation	129
Item 12(a).	Security Ownership of Certain Beneficial Owners	129
Item 12(b).	Security Ownership of Management	129
Item 12(c).	Changes in Control	129
Item 12(d).	Securities Authorized for Issuance Under Equity Compensation Plans	129
Item 13.	Certain Relationships and Related Transactions, and Director
	Independence	129
Item 14.	Principal Accounting Fees and Services	130
PART IV
Item 15.	Exhibits and Financial Statement Schedules	131
SIGNATURES		140

(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: Production Optimization, Fluid Systems, Drilling and Formation Evaluation, Digital and Consulting Solutions, Energy and Chemicals, and Government and Infrastructure. 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).

Our Energy and Chemicals and Government and Infrastructure segments are part of KBR, Inc. (KBR), which was formed in March 2006. In November 2006, KBR, Inc. completed the initial public offering (IPO) of approximately 32 million shares of KBR, Inc. common stock at a price of $17.00 per share. We received proceeds of approximately $508 million from the IPO, net of underwriting discounts and commissions and offering expenses. We currently hold an approximate 81% interest in KBR, Inc., which we consolidate for financial reporting purposes. We are working toward the separation of KBR, Inc., which is expected to occur no later than the end of April 2007.

KBR’s Production Services operations were moved into discontinued operations for reporting purposes in the first quarter of 2006. All prior period amounts have been reclassified to discontinued operations.

Within the ESG during the second quarter of 2006, we moved slickline services, tubing conveyed perforating services and products, and underbalanced applications from the Production Optimization segment to the Drilling and Formation Evaluation segment, as these services are more closely aligned with the Drilling and Formation Evaluation segment. Prior period balances have been reclassified to reflect this change. Because of this change, what we previously referred to as “logging services” within the Drilling and Formation Evaluation segment we now refer to as “wireline and perforating services.” In addition, for internal management purposes we combined our Drilling and Formation Evaluation and Digital and Consulting Solutions divisions, forming three Energy Services Group internal divisions. However, we continue to disclose four segments for the Energy Services Group.

See Note 5 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 provides products and services for completion of wells, testing and monitoring performance of wells and reservoirs, and treatments to improve well productivity and increase recoverable reserves. This segment consists of production enhancement services and completion tools and services.

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

Completion tools and services include subsurface safety valves and flow control equipment, surface safety systems, packers and specialty completion equipment, intelligent completion systems, expandable liner hanger systems, sand control systems, well servicing tools, and reservoir performance services. Reservoir performance services include testing tools, real-time reservoir analysis, and data acquisition services. Additionally, completion tools and services include WellDynamics, an intelligent well completions joint venture, which we consolidate for accounting purposes.

Until January 2005 when it was sold, subsea operations conducted by Subsea 7, Inc., of which we formerly owned 50%, were included in this segment. Subsea 7, Inc. was accounted for using the equity method.

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 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 to increase stability and enhance oil production.

Drilling and Formation Evaluation

Our Drilling and Formation Evaluation segment is primarily involved in the drilling and formation evaluation process during bore-hole construction. Services and products offered in this segment include, drilling systems and services, drill bits, and wireline and perforating services.

Sperry Drilling Services provides drilling systems and services. These services include directional and horizontal drilling, measurement-while-drilling, logging-while-drilling, multilateral systems, underbalanced applications, and rig site information systems. Our drilling systems offer directional control while providing 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.

Wireline and perforating 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 and slickline services are also offered, which provide cement bond evaluation, reservoir monitoring, pipe evaluation, pipe recovery, mechanical services, well intervention, and perforating. Perforating services include tubing-conveyed perforating services and products.

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 seismic, well log, and other data into detailed computer models of petroleum reservoirs. The models are used by our customers for business and technical decisions in exploration, development, and production activities. Data management services provide storage, browsing, and retrieval 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 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 direct and indirect 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, Energy and Chemicals and Government and Infrastructure. The nature of these two segments can result in a relatively small number of projects and joint ventures representing a substantial portion of operations. Following is a summary of KBR’s segments.

Energy and Chemicals

Our Energy and Chemicals segment designs and constructs energy and petrochemical projects, including large, technically complex projects in remote locations around the world. The Energy and Chemicals segment includes onshore oil and gas production facilities, offshore oil and gas production facilities, including platforms, floating production and subsea facilities, onshore and offshore pipelines, liquefied natural gas (LNG) and gas-to-liquids (GTL) gas monetization facilities, refineries, petrochemical plants (such as ethylene and propylene), and Syngas, primarily for fertilizer-related facilities. Energy and Chemicals provides a wide range of engineering, procurement, construction, and facility commissioning start-up services, as well as program and project management, consulting, and technology services.

Included in this segment are a number of joint ventures, including the TSKJ joint venture, which was 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.

Also included in this segment is M. W. Kellogg Limited (MWKL), which 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.

Brown & Root-Condor Spa (BRC), a joint venture with Sonatrach and another Algerian company, enhances our ability to operate in Algeria by providing access to local resources. BRC executes work for Algerian and international customers, including Sonatrach. BRC has built oil and gas production facilities and civil infrastructure projects, including hospitals and office buildings. KBR has a 49% interest in the joint venture. We account for this investment using the equity method of accounting. We have recently been notified by a joint venture partner in BRC that it wishes to dissolve the joint venture.

Government and Infrastructure

Our Government and Infrastructure segment delivers on-demand support services across the full military mission cycle from contingency logistics and field support to operations and maintenance on military bases. In the civil infrastructure market, we operate in diverse sectors, including transportation, waste and water treatment, and facilities maintenance. We provide program and project management, contingency logistics, operations and maintenance, construction management, engineering, and other services to military and civilian branches of governments and private customers worldwide. We currently provide these services in the Middle East to support our United States military deployments, as well as in other global locations where military personnel are stationed. A significant portion of the Government and Infrastructure segment’s current operations relate to the support of United States government operations in the Middle East. KBR is also the majority owner of Devonport Management Limited (DML), which owns and operates Devonport Royal Dockyard, Western Europe’s largest naval dockyard complex. The DML shipyard operations are primarily engaged in refueling nuclear submarines and performing maintenance on surface vessels for the United Kingdom Ministry of Defence (MoD), as well as limited commercial projects. DML is consolidated for financial reporting purposes.

This segment includes 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 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.

Also included in this segment is Aspire Defence/Allenby-Connaught, a joint venture between us, Mowlem Plc. and a financial investor formed to contract with the MoD to upgrade and service certain United Kingdom military facilities. In addition to a package of ongoing services to be delivered over 35 years, the project includes a nine-year construction program. KBR indirectly owns a 45% interest in Aspire Defence, the project company that is the holder of the 35-year concession contract. In addition, KBR owns a 50% interest in each of the two joint ventures that provide the construction and related support services to Aspire Defence. We account for this investment using the equity method of accounting.

Acquisitions and dispositions

In January 2007, we acquired all of the intellectual property, current assets, and existing business associated with Calgary-based Ultraline Services Corporation, a division of Savanna Energy Services Corp., for approximately $177 million, subject to adjustment for working capital purposes. Ultraline is a provider of wireline services in Canada. Ultraline will be reported in our Drilling and Formation Evaluation segment.

Business strategy

Our business strategy is to maintain global leadership in providing energy services and products. 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.

In November 2006, KBR, Inc. completed an IPO, in which it sold approximately 32 million shares of KBR, Inc. common stock, at $17.00 per share. We received proceeds of approximately $508 million from the IPO, net of underwriting discounts and commissions and offering expenses. As the IPO was a result of a broader corporate reorganization, the increase in the carrying amount of our investment in KBR, Inc. was recorded in “Paid-in capital in excess of par value” on our consolidated balance sheet at December 31, 2006. We now hold an approximate 81% interest in KBR, Inc., represented by 135.6 million shares of KBR, Inc. common stock, and consolidate KBR, Inc. for financial reporting purposes.

We are now working toward the separation of KBR, Inc., which we expect to complete no later than the end of April 2007.

stock pursuant to the exchange offer will be registered under the Securities Act of 1933, and such shares of common stock will 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, Inc. The exchange offer and any subsequent spin-off will complete the separation of KBR, Inc. from Halliburton and will result in two independent companies. In January 2007, we received a ruling from the Internal Revenue Service that, among other things, no gain or loss will be recognized by Halliburton or its shareholders as a result of a distribution of KBR, Inc. stock by means of a pro rata dividend. We have requested a supplemental ruling from the Internal Revenue Service that no gain or loss will be recognized by Halliburton or its shareholders as a result of a distribution of KBR, Inc. stock by means of an exchange offer whereby holders of Halliburton stock may tender their shares and receive KBR, Inc. shares in exchange, followed by a dividend distribution of any remaining shares of KBR, Inc. stock held by Halliburton to its shareholders. The exchange offer and any subsequent distribution of KBR, Inc. stock will not be conditioned on receipt of such a supplemental ruling from the Internal Revenue Service. We have also obtained an opinion of counsel related to the tax-free nature of the exchange offer and any subsequent spin-off distribution.

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;

knowledge of the reservoir;

product quality;

warranty; and

technical proficiency.

We conduct business worldwide in about 100 countries. In 2006, based on the location of services provided and products sold, 32% of our consolidated revenue was from the United States and 19% of our consolidated revenue was from Iraq, primarily related to our work for the United States Government. In 2005, 28% of our consolidated revenue was from the United States and 25% of our consolidated revenue was from Iraq, primarily related to our work for the United States Government. In 2004, 27% of our consolidated revenue was from Iraq and 22% of our consolidated revenue was from the United States. No other country accounted for more than 10% of our consolidated revenue during these periods. See Note 5 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 68% in 2006, 60% in 2005, and 52% in 2004. Revenue from the United States Government, resulting primarily from work performed in the Middle East by our Government and Infrastructure segment, represented 26% of our 2006 consolidated revenue, 32% of our 2005 consolidated revenue, and 40% of our 2004 consolidated revenue. No other customer represented more than 10% of consolidated revenue in any period presented.

Backlog

Backlog represents the dollar amount of revenue we expect to realize in the future as a result of performing work under multi-period contracts that have been awarded 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. Not all of our revenue is recorded in backlog for a variety of reasons, including the fact that some projects begin and end within a short-term period. 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 total expected revenue in backlog when a contract is awarded and/or the scope is definitized. For our projects related to unconsolidated joint ventures, we have included in the table below our percentage ownership of the joint venture’s backlog. However, because these projects are accounted for under the equity method, only our share of future earnings from these projects will be recorded in our revenue. Our backlog for projects related to unconsolidated joint ventures in our continuing operations totaled $4.4 billion at December 31, 2006 and $3.0 billion at December 31, 2005. We also consolidate joint ventures which are majority-owned and controlled or are variable interest entities in which we are the primary beneficiary. Our backlog included in the table below for projects related to consolidated joint ventures with minority interest includes 100% of the backlog associated with those joint ventures and totaled $3.9 billion at December 31, 2006 and $3.6 billion at December 31, 2005.

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 depending on expected revenue and timing. Where contract duration is indefinite, projects included in backlog are limited to the estimated value of the amount of expected revenue 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 act solely in a project management capacity, we only include our management fee revenue of each project in backlog.

The following table summarizes our project backlog:

	December 31
Millions of dollars	2006		2005
Government and Infrastructure (1)
Middle East operations	$	3,066	$	2,139
DML shipyard operations		1,079		1,305
Other		3,658		1,708
Energy and Chemicals (2)
Gas monetization		3,883		3,651
Offshore projects		130		275
Other		1,700		1,511
Energy Services Group (3)		-		180
Total backlog for continuing operations	$	13,516	$	10,769

(1)

Our Government and Infrastructure segments total backlog from continuing operations attributable to firm orders was $5.7 billion at December 31, 2006 and $3.4 billion at December 31, 2005. Total backlog attributable to unfunded orders was $2.1 billion at December 31, 2006 and $1.8 billion at December 31, 2005.

(2)

The amounts presented represent backlog for continuing operations and do not include backlog associated with KBR’s Production Services operations, which were sold and were accounted for as discontinued operations. Backlog for the Production Services operations was $1.2 billion as of December 31, 2005.

(3)

ESG backlog excludes contracts for recurring hardware and software maintenance and support services offered by Landmark.

We estimate that, at December 31, 2006, 52% of the Energy and Chemicals segment backlog and 64% of the Government and Infrastructure segment backlog will be completed within one year. As of December 31, 2006, 57% of total backlog related to cost-reimbursable contracts with the remaining 43% related to fixed-price contracts. For contracts that contain both fixed-price and cost-reimbursable components, we characterize the entire contract based on the predominant component. We were awarded a task order for approximately $3.5 billion for our continued services in Iraq through September 2007 under the LogCAP III contract. As of December 31, 2006, our backlog under the LogCAP III contract was $3.0 billion.

Raw materials

Raw materials essential to our business are normally readily available. Current market conditions have triggered constraints in the supply of certain raw materials, such as, sand, cement, and specialty metals. Given high activity levels, particularly in the United States, we are seeking ways to ensure the availability of resources, as well as manage the rising costs of raw materials. Our procurement department is using our size and buying power through several programs designed to ensure that we have access to key materials at competitive prices.

Research and development costs

We maintain an active research and development program. The program improves existing products and processes, develops new products and processes, and improves engineering standards and practices that serve the changing needs of our customers. Our expenditures for research and development activities were $256 million in 2006, $220 million in 2005, and $234 million in 2004, of which over 97% was company-sponsored in each year.

Patents

We own a large number of patents and have pending a substantial number of patent applications covering various products and processes. We are also licensed to utilize patents owned by others. We do not consider any particular patent to be material to our business operations.

Seasonality

On an overall basis, our operations are not generally affected by seasonality. Weather and natural phenomena can temporarily affect the performance of our services, but the widespread geographical locations of our operations serve to mitigate those effects. Examples of how weather can impact our business include:

the severity and duration of the winter in North America can have a significant impact on gas storage levels and drilling activity for natural gas;

the timing and duration of the spring thaw in Canada directly affects activity levels due to road restrictions;

typhoons and hurricanes can disrupt coastal and offshore operations; and

severe weather during the winter months normally results in reduced activity levels in the North Sea and Russia.

In addition, due to higher spending near the end of the year by customers for software, 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, 2006, we employed approximately 104,000 people worldwide compared to 100,000 at December 31, 2005. At December 31, 2006, 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 we have filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site that contains our reports, proxy and information statements, and our other SEC filings. The address of that site is www.sec.gov. We have posted on our 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. There have been no waivers from provisions of our Code of Business Conduct during 2006, 2005, or 2004.

Item 1(a). Risk Factors.

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

Item 1(b). Unresolved Staff Comments.

None.

Item 2. Properties.

We own or lease numerous properties in domestic and foreign locations. The following locations represent our major facilities.

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

Carrollton, Texas	Owned	Manufacturing facility

Drilling and Formation Evaluation Segment:

Alvarado, Texas	Owned/Leased	Manufacturing facility

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*
Energy and Chemicals Segment:

Greenford, Middlesex, United Kingdom	Owned (1)	High-rise office facility

Government and Infrastructure Segment:

Arlington, Virginia	Leased	High-rise office facility

Devonport, Plymouth, United Kingdom	Owned (2)	Shipyard facility

Shared Facilities:

Houston, Texas	Owned	Campus facility

Leatherhead, United Kingdom	Owned	Campus facility

Houston, Texas	Leased (3)	High-rise office facility -
		KBR executive offices
*Corporate*
Houston, Texas	Leased	Corporate executive offices

(1) At December 31, 2006, KBR had a 55% interest in a joint venture which owns this office facility.

(2) At December 31, 2006, KBR had a 51% interest in a joint venture which owns this shipyard facility.

(3) At December 31, 2006, KBR had a 50% interest in a joint venture which owns this office facility.

All of our owned properties are unencumbered.

In addition, we have 140 international and 100 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 535 acres in England (primarily related to DML) and Scotland, which are used by KBR. Our marine facility located in Scotland is 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 2006, we estimate that our 18.6 million tons of proven reserves in areas of active mining are sufficient to fulfill our internal and external needs for the next 12 years. We estimate that our 3.8 million tons of proven reserves of barite in areas of active mining equate to a 15-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 related to various commitments and contingencies is described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in “Forward-Looking Information and Risk Factors” and in Notes 3, 11, 12, and 13 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 2006.

Executive Officers of the Registrant

The following table indicates the names and ages of the executive officers of the registrant as of February 15, 2007, 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 57)	since December 2002
	Director of KBR, Inc., since June 2006
	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 50)	since March 2003
	Director of KBR, Inc., since March 2006
	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

* Andrew R. Lane	Executive Vice President and Chief Operating Officer of Halliburton Company,
(Age 47)	since December 2004
	Director of KBR, Inc., since June 2006
	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 53)	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

Name and Age	Offices Held and Term of Office
Mark A. McCollum	Senior Vice President and Chief Accounting Officer of Halliburton Company,
(Age 47)	since August 2003
	Director of KBR, Inc., since June 2006
	Senior Vice President and Chief Financial Officer of Tenneco Automotive, Inc.,
	November 1999 to August 2003

Craig W. Nunez	Senior Vice President and Treasurer of Halliburton Company,
(Age 45)	since January 2007
	Vice President and Treasurer of Halliburton Company, February 2006
	to January 2007
	Treasurer of Colonial Pipeline Company, November 1999 to January 2006

* Lawrence J. Pope	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 60)	Vice President, Tax of Halliburton Energy Services, Inc.,
	September 1998 to May 2002

* William P. Utt	President, Chief Executive Officer and Director of KBR, Inc., since March 2006
(Age 49)	President and Chief Executive Officer of SUEZ Energy North America,
	2000 to March 2006

* Members of the Policy Committee of the registrant.

There are no family relationships between the executive officers of the registrant or between any director and any executive officer of the registrant.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities.

Halliburton Company’s common stock is traded on the New York Stock Exchange. Information related to the high and low market prices of common stock and quarterly dividend payments is included under the caption “Quarterly Data and Market Price Information” on page 128 of this annual report. Cash dividends on common stock in the amount of $0.075 for 2006 and $0.0625 for 2005 were paid in March, June, September, and December. Our Board of Directors intends to consider the payment of quarterly dividends on the outstanding shares of our common stock in the future. The declaration and payment of future dividends, however, will be at the discretion of the Board of Directors and will depend upon, among other things, future earnings, general financial condition and liquidity, success in business activities, capital requirements, and general business conditions.

The following graph and table compare total shareholder return on our common stock for the five-year period ending December 31, 2006, with the Standard & Poor’s 500 Stock Index and the Standard & Poor’s Energy Composite Index over the same period. This comparison assumes the investment of $100 on December 31, 2001, and the reinvestment of all dividends. The shareholder return set forth is not necessarily indicative of future performance.

	December 31
	2001		2002		2003		2004		2005		2006
Halliburton	$	100.00	$	147.23	$	209.15	$	320.59	$	511.22	$	516.89
Standard & Poor’s 500 Stock Index		100.00		77.90		100.25		111.15		116.61		135.03
Standard & Poor’s Energy Composite Index		100.00		88.87		111.65		146.86		192.93		239.63

At February 19, 2007, there were 20,292 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, 2006.

					Total Number of Shares
					Purchased as Part of
	Total Number of		Average Price		Publicly Announced
Period	Shares Purchased (1)		Paid per Share		Plans or Programs (2)
October 1-31		1,910,828	$	32.04		1,866,315
November 1-30		3,688,046	$	32.68		3,670,853
December 1-31		3,072,593	$	33.04		3,026,508
Total		8,671,467	$	32.67		8,563,676

(1) Of the 8,671,467 shares purchased during the three-month period ended December 31, 2006, 107,791 shares were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These share purchases were not part of a publicly announced program to purchase common shares.

(2) In February 2006, our Board of Directors approved a share repurchase program of up to $1.0 billion. In September 2006, our Board of Directors approved an increase to our existing common share repurchase program of up to an additional $2.0 billion. During the fourth quarter of 2006, we repurchased 8,563,676 shares of our common stock at a cost of $280 million, or an average price per share of $32.69. There is $1.7 billion remaining under this program for future repurchases as of December 31, 2006.

Item 6. Selected Financial Data.

Information related to selected financial data is included on page 127 of this annual report.

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

Information related to Management’s Discussion and Analysis of Financial Condition and Results of Operations is included on pages 17 through 68 of this annual report.

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

Information related to market risk is included in Management’s Discussion and Analysis of Financial Condition and Results of Operations under the caption “Financial Instrument Market Risk” on page 49 of this annual report.

Item 8. Financial Statements and Supplementary Data.

	Page No.
Management’s Report on Internal Control Over Financial Reporting	69
Reports of Independent Registered Public Accounting Firm	70
Consolidated Statements of Operations for the years ended December 31, 2006, 2005, and 2004	72
Consolidated Balance Sheets at December 31, 2006 and 2005	73
Consolidated Statements of Shareholders’ Equity for the years ended
December 31, 2006, 2005, and 2004	74
Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005, and 2004	75
Notes to Consolidated Financial Statements	76
Selected Financial Data (Unaudited)	127
Quarterly Data and Market Price Information (Unaudited)	128

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, 2006 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, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

See page 69 for Management’s Report on Internal Control Over Financial Reporting and page 71 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

During 2006, the Energy Services Group (ESG) produced revenue of $13.0 billion and operating income of $3.4 billion, reflecting an operating margin of 26.1%. Revenue increased $2.9 billion or 28% over 2005, primarily driven by higher activity in North America, Asia Pacific, the Middle East, and the North Sea. ESG operating income increased $1.1 billion or 48% compared to 2005. Internationally, ESG experienced 23% revenue growth and 44% operating income growth during 2006 compared to the prior year. Increased customer drilling and production activity, increased demand for our technologies, higher utilization of assets, and continued price increases have allowed us to produce record revenue and operating income throughout the year.

In 2006, KBR revenue was down $519 million to $9.6 billion with operating income decreasing $214 million to $239 million compared to 2005. The revenue decline was primarily due to decreased military support activities in Iraq.

In August 2006, we were awarded a $3.5 billion task order under our LogCAP III contract for additional work through 2007. Backlog related to the LogCAP III contract at December 31, 2006 was $3.0 billion. In 2006, Iraq-related work contributed $4.7 billion to consolidated revenue and $166 million to consolidated operating income, resulting in a 3.5% margin before corporate costs and taxes. We were awarded $120 million in LogCAP award fees during 2006 as a result of our performance rating. During the almost five-year period we have worked under the LogCAP III contract, we have been awarded 64 “excellent” ratings out of 76 total ratings. We expect to complete all open task orders under our LogCAP III contract during the third quarter of 2007.

In August 2006, the United States Department of Defense (DoD) issued a request for proposals on a new competitively bid, multiple service provider LogCAP IV contract to replace the current LogCAP III contract. We are currently the sole service provider under the LogCAP III contract and in October 2006, we submitted the final portion of our bid on the LogCAP IV contract. We expect that the contract will be awarded during the second quarter of 2007. Despite the award of the August 2006 task order under our LogCAP III contract, and the possibility of being awarded a portion of the LogCAP IV contract, we expect our overall volume of work to decline as our customer scales back the amount of services we provide. However, as a result of the recently announced surge of additional troops in Iraq, we expect the decline to occur more slowly than previously expected.

In the second quarter of 2006, we identified a $148 million charge, before income taxes and minority interest, related to KBR’s consolidated 50%-owned gas-to-liquids (GTL) project in Escravos, Nigeria. This charge was primarily attributable to increases in the overall estimated cost to complete the project. The project experienced delays related to civil unrest and security on the Escravos River near the project site, with additional delays resulting from scope changes and engineering and construction modifications. As of September 30, 2006, we had approximately $269 million in unapproved change orders related to this project. In the fourth quarter of 2006, we reached agreement with the project owner to settle $264 million of these change orders. We recorded an additional $9 million loss in the fourth quarter of 2006 related to non-billable engineering services for the Escravos joint venture. As of December 31, 2006, we have recorded $43 million of unapproved change orders, which primarily relates to additional cost increases on this project.

In May 2006, we completed the sale of KBR’s Production Services group, which was part of our Energy and Chemicals segment. In connection with the sale, we received net proceeds of $265 million. The sale of Production Services resulted in a pretax gain, net of post-closing adjustments, of approximately $120 million.

In 2006, KBR recorded $58 million of impairment charges related to an investment in a railway joint venture in Australia. This joint venture has sustained losses since the railway commenced operations in early 2004 and violated the joint venture’s loan covenants by failing to make an interest and principal payment in October 2006. The write-down of our investment in this joint venture in the first and third quarters of 2006 resulted from decreases in anticipated freight volume, a slowdown in the planned expansion of the Port of Darwin, and the joint venture’s unsuccessful efforts to raise additional equity from third parties.

In April 2006, KBR, Petrobras, and the project lenders agreed to technical and operational acceptance of the completed Barracuda and Caratinga production vessels. In March 2006, Petrobras submitted to arbitration a $220 million claim related to the Barracuda-Caratinga project. The submission claimed that certain subsea flowline bolts failed and that the replacement of these bolts was our responsibility. We disagree with the Petrobras claim since the bolts met Petrobras’ design specification, and we do not believe there is any basis for the amount claimed by Petrobras. We have examined possible solutions to the problem and determined the cost would not exceed $140 million. We are defending ourselves in the arbitration process and will pursue recovery of our costs associated with this defense.

Separation of KBR

In November 2006, KBR, Inc. completed an initial public offering (IPO), in which it sold approximately 32 million shares of KBR, Inc. common stock at $17.00 per share. We received proceeds of approximately $508 million from the IPO, net of underwriting discounts and commissions and offering expenses. As the IPO was a result of a broader corporate reorganization, the increase in the carrying amount of our investment in KBR, Inc. was recorded in “Paid-in capital in excess of par value” on our consolidated balance sheet at December 31, 2006. We now hold an approximate 81% interest in KBR, Inc., represented by 135.6 million shares of KBR, Inc. common stock, and consolidate KBR, Inc. for financial reporting purposes.

We entered into various agreements relating to the separation of KBR from us, including, among others, a master separation agreement, a registration rights agreement, a tax sharing agreement, transition services agreements, and an employee matters agreement. The master separation agreement provides for, among other things, KBR’s responsibility for liabilities related to its business and Halliburton’s responsibility for liabilities unrelated to KBR’s business. Halliburton provided indemnification in favor of KBR under the master separation agreement for contingent liabilities, including Halliburton’s indemnification of KBR and any of its greater than 50%-owned subsidiaries as of November 20, 2006, the date of the master separation agreement, for:

fines or other monetary penalties or direct monetary damages, including disgorgement, as a result of a claim made or assessed by a governmental authority in the United States, the United Kingdom, France, Nigeria, Switzerland and/or Algeria, or a settlement thereof, related to alleged or actual violations occurring prior to November 20, 2006 of the United States Foreign Corrupt Practices Act (FCPA) or particular, analogous applicable foreign statutes, laws, rules and regulations in connection with current investigations, including with respect to the construction and subsequent expansion by TSKJ of a natural gas liquefaction complex and related facilities at Bonny Island in Rivers State, Nigeria; and

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

The Halliburton performance guarantees and letter of credit guarantees that are currently in place in favor of KBR’s customers or lenders will continue after the separation of KBR until these guarantees expire at the earlier of: (1) the termination of the underlying project contract or KBR obligations thereunder or (2) the expiration of the relevant credit support instrument in accordance with its terms or release of such instrument by the customer. KBR will compensate Halliburton for these guarantees and indemnify Halliburton if Halliburton is required to perform under any of these guarantees. The tax sharing agreement provides for allocations of United States income tax liabilities and other agreements between us and KBR with respect to tax matters. Under the transition services agreements, we will continue to provide various interim corporate support services to KBR, and KBR continues to provide various interim corporate support services to us. The fees will be determined on a basis generally intended to approximate the fully allocated direct and indirect costs of providing the services, without any profit. Under an employee matters agreement, Halliburton and KBR have allocated liabilities and responsibilities related to current and former employees and their participation in certain benefit plans. KBR’s final prospectus for its initial public offering dated November 15, 2006 contains a more detailed description of these separation agreements.

In conjunction with the closing of the KBR, Inc. IPO, KBR, Inc. granted stock options, restricted stock, and restricted stock unit awards under the KBR, Inc. 2006 Stock and Incentive Plan. See Note 15 to the consolidated financial statements for further detail on KBR, Inc. stock incentive plans.

We are now working toward the separation of KBR, Inc., which we expect to complete no later than the end of April 2007.

On February 26, 2007, our Board of Directors approved a plan under which we will dispose of our remaining interest in KBR, Inc. through a tax-free exchange with Halliburton shareholders pursuant to an exchange offer and, following the completion or termination of the exchange offer, a special pro rata dividend distribution of any and all of our remaining KBR, Inc. shares. In connection with the anticipated exchange offer, KBR, Inc. will file with the Securities and Exchange Commission (SEC) a registration statement on Form S-4 with respect to the offering, and we will file with the SEC a Schedule TO. The exchange offer will be conditioned on a minimum number of shares being tendered. Any exchange of KBR, Inc. stock for outstanding shares of Halliburton company stock pursuant to the exchange offer will be registered under the Securities Act of 1933, and such shares of common stock will 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, Inc. The exchange offer and any subsequent spin-off will complete the separation of KBR, Inc. from Halliburton and will result in two independent companies. In January 2007, we received a ruling from the Internal Revenue Service that, among other things, no gain or loss will be recognized by Halliburton or its shareholders as a result of a distribution of KBR, Inc. stock by means of a pro rata dividend. We have requested a supplemental ruling from the Internal Revenue Service that no gain or loss will be recognized by Halliburton or its shareholders as a result of a distribution of KBR, Inc. stock by means of an exchange offer whereby holders of Halliburton stock may tender their shares and receive KBR, Inc. shares in exchange, followed by a dividend distribution of any remaining shares of KBR, Inc. stock held by Halliburton to its shareholders. The exchange offer and any subsequent distribution of KBR, Inc. stock will not be conditioned on receipt of such a supplemental ruling from the Internal Revenue Service. We have also obtained an opinion of counsel related to the tax-free nature of the exchange offer and any subsequent spin-off distribution.

Other corporate matters

In February 2006, our Board of Directors approved an increase in our quarterly dividend to $0.075 per share, a 20% increase over prior quarters, and subsequently declared equivalent dividends during each quarter of 2006. This increase in the per share dividend amount contributed to an increase of approximately $50 million in our annual dividend payment over prior year. The Board of Directors also finalized the terms of a two-for-one common stock split, following the 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. On July 14, 2006, each shareholder of record as of June 23, 2006, received one additional share for each outstanding share held. All periods presented have been adjusted to reflect the common stock split.

Also in February 2006, our Board of Directors approved a share repurchase program of up to $1.0 billion. In September 2006, our Board of Directors approved an increase to our existing common share repurchase program of up to an additional $2.0 billion. During 2006, we repurchased approximately 40 million shares of our common stock for $1.3 billion or an average price per share of $32.93.

At December 31, 2006, we adopted the recognition provisions of Statement of Financial Accounting Standards No. 158 (SFAS No. 158), “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).” The adoption of SFAS No. 158 impacted our balance sheet at December 31, 2006 as follows: a decrease to total assets of $187 million, an increase to total liabilities of $157 million, a decrease to minority interest of $126 million, and a decrease to shareholders’ equity of $218 million.

In January 2006, we adopted Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123(R)), and began expensing the cost of our employee stock option awards and our employee stock purchase plan. On a pretax basis, these costs totaled approximately $41 million in 2006 and are in addition to $36 million in costs we have historically expensed related to other equity based compensation and $16 million of incremental compensation cost related to modifications of previously granted stock-based awards retained when certain employees left the company. All expense related to stock compensation awards were charged to the segments to which each affected employee is assigned.

Business outlook

The outlook for our business remains generally favorable. Worldwide demand for hydrocarbons continues to grow, and the reservoirs are becoming more complex. Despite some disruption in activity in late 2006 and early 2007 due to adverse weather conditions, at this time we continue to see steady demand for our services in North America. The future trend will depend on natural gas storage levels and the direction of natural gas prices. The Canadian market has softened significantly since mid-2006 with a decrease in year-end rig count of 21% as compared to 2005. If the slowdown in activity continues, we will adjust our allocation of capital in that market as necessary. Despite recent volatility of natural gas prices, we have been able to negotiate price increases, though not as high as in the previous two years, as contracts roll over. Finally, we expect the energy services sector in regions outside North America to grow. Therefore, we have been investing and will continue to invest in infrastructure, capital, and technology predominantly in the Eastern Hemisphere, consistent with our initiative to grow our operations in that part of the world. We expect to realize continued expansion in the Middle East, north Africa, offshore west Africa, and Russia.

In 2007, we will focus on:

maintaining optimal utilization of our equipment and resources;

increasing pricing and reducing discounts, as the market allows, for ESG’s services and products;

leveraging our technologies to provide our customers with the ability to more efficiently drill and complete their wells and to increase their productivity. To that end, we have plans for three international research and development centers with global technology and training missions;

expanding our manufacturing capability and capacity with new manufacturing plants;

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

pursuing strategic acquisitions in line with ESG’s core products and services to expand our portfolio in key geographic areas. Consistent with this objective, we acquired Ultraline Services Corporation, a provider of wireline services in Canada, in January 2007;

increasing capital spending, primarily directed toward Eastern Hemisphere operations for service equipment additions and infrastructure related to recent project wins; and

completing the separation of KBR from Halliburton.

Detailed discussions of 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.

Foreign Corrupt Practices Act investigations

The SEC is conducting a formal investigation into whether improper payments were made to government officials in Nigeria through the use of agents or subcontractors in connection with the construction and subsequent expansion by TSKJ of a multibillion dollar natural gas liquefaction complex and related facilities at Bonny Island in Rivers State, Nigeria. The DOJ is also conducting a related criminal investigation. The SEC has also issued subpoenas seeking information, which we are furnishing, regarding current and former agents used in connection with multiple projects, including current and prior projects, over the past 20 years located both in and outside of Nigeria in which the Halliburton energy services business, The M.W. Kellogg Company, M.W. Kellogg Limited, Kellogg Brown & Root or their or our joint ventures, are or were participants. In September 2006, the SEC requested that we enter into a tolling agreement with respect to its investigation. We anticipate that we will enter into an appropriate tolling agreement with the SEC.

Agip International B.V. (an affiliate of ENI SpA of Italy). M.W. Kellogg Limited is a joint venture in which KBR had a 55% interest at December 31, 2006; and M.W. Kellogg Limited and The M.W. Kellogg Company were subsidiaries of Dresser Industries before our 1998 acquisition of Dresser Industries. The M.W. Kellogg Company was later merged with a subsidiary of ours to form Kellogg Brown & Root, one of our subsidiaries.

The SEC and the DOJ have been reviewing these matters in light of the requirements of the FCPA. In addition to performing our own investigation, we have been cooperating with the SEC and the DOJ investigations and with other investigations into the Bonny Island project in France, Nigeria and Switzerland. We also believe that the Serious Frauds Office in the United Kingdom is conducting an investigation relating to the Bonny Island project. Our Board of Directors has appointed a committee of independent directors to oversee and direct the FCPA investigations. Through our committee of independent directors, we will continue to oversee and direct the investigations, and KBR’s directors who are independent of us and KBR, acting as a committee of KBR’s Board of Directors, will monitor the continuing investigation directed by us.

The matters under investigation relating to the Bonny Island project cover an extended period of time (in some cases significantly before our 1998 acquisition of Dresser Industries and continuing through the current time period). We have produced documents to the SEC and the DOJ both voluntarily and pursuant to company subpoenas from the files of numerous officers and employees of Halliburton and KBR, including current and former executives of Halliburton and KBR, 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 of our and KBR’s current and former employees, former executive officers of KBR, and at least one subcontractor of KBR. We further understand that the DOJ has issued subpoenas for the purpose of obtaining information abroad, and we understand that other partners in TSKJ have provided information to the DOJ and the SEC with respect to the investigations, either voluntarily or under subpoenas.

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

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 February 2005, TSKJ notified the Attorney General of Nigeria that TSKJ would not oppose the Attorney General’s efforts to have sums of money held on deposit in accounts of Tri-Star Investments in banks in Switzerland transferred to Nigeria and to have the legal ownership of such sums determined in the Nigerian courts.

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

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

In 2006, we suspended the services of another agent who, until such suspension, had worked for KBR outside of Nigeria on several current projects and on numerous older projects going back to the early 1980s. The suspension will continue until such time, if ever, as we can satisfy ourselves regarding the agent’s compliance with applicable law and our Code of Business Conduct. In addition, we suspended the services of an additional agent on a separate current Nigerian project with respect to which we have received from a joint venture partner on that project allegations of wrongful payments made by such agent.

If violations of the FCPA were found, a person or entity found in violation could be subject to fines, civil penalties of up to $500,000 per violation, equitable remedies, including disgorgement (if applicable) generally of profit, including prejudgment interest on such profits, causally connected to the violation, and injunctive relief. Criminal penalties could range up to the greater of $2 million per violation or twice the gross pecuniary gain or loss from the violation, which could be substantially greater than $2 million per violation. It is possible that both the SEC and the DOJ could assert that there have been multiple violations, which could lead to multiple fines. The amount of any fines or monetary penalties that could be assessed would depend on, among other factors, the findings regarding the amount, timing, nature, and scope of any improper payments, whether any such payments were authorized by or made with knowledge of us or our affiliates, the amount of gross pecuniary gain or loss involved, and the level of cooperation provided the government authorities during the investigations. Agreed dispositions of these types of violations also frequently result in an acknowledgement of wrongdoing by the entity and the appointment of a monitor on terms negotiated with the SEC and the DOJ to review and monitor current and future business practices, including the retention of agents, with the goal of assuring compliance with the FCPA. Other potential consequences could be significant and include suspension or debarment of our ability to contract with governmental agencies of the United States and of foreign countries. During 2006, KBR and its affiliates had revenue of approximately $5.8 billion from its government contracts work with agencies of the United States or state or local governments. If necessary, we would seek to obtain administrative agreements or waivers from the DoD and other agencies to avoid suspension or debarment. In addition, we may be excluded from bidding on United Kingdom Ministry of Defence (MoD) contracts in the United Kingdom if we are convicted for a corruption offense or if the MoD determines that our actions constituted grave misconduct. During 2006, KBR had revenue of approximately $1.0 billion from its government contracts work with the MoD. Suspension or debarment from the government contracts business would have a material adverse effect on our business, results of operations, and cash flows.

These investigations could also result in third-party claims against us, which may include claims for special, indirect, derivative or consequential damages, damage to our business or reputation, loss of, or adverse effect on, cash flow, assets, goodwill, results of operations, business prospects, profits or business value, adverse consequences on our ability to obtain or continue financing for current or future projects or claims by directors, officers, employees, affiliates, advisors, attorneys, agents, debt holders, or other interest holders or constituents of us or our subsidiaries. In this connection, we understand that the government of Nigeria gave notice in 2004 to the French magistrate of a civil claim as an injured party in that proceeding. We are not aware of any further developments with respect to this claim. In addition, we could incur costs and expenses for any monitor required by or agreed to with a governmental authority to review our continued compliance with FCPA law.

As of December 31, 2006, we are unable to estimate an amount of probable loss or a range of possible loss related to these matters.

Bidding practices investigation

In connection with the investigation into payments relating to the Bonny Island project in Nigeria, 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.

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. Criminal prosecutions under applicable laws of relevant foreign jurisdictions and civil claims by, or relationship issues with customers, are also possible.

As of December 31, 2006, we are unable to estimate an amount of probable loss or a range of possible loss related to these matters.

Possible Algerian investigation

We believe that an investigation by a magistrate or a public prosecutor in Algeria may be pending with respect to sole source contracts awarded to Brown & Root Condor Spa, a joint venture with Kellogg Brown & Root Ltd UK, Centre de Recherche Nuclear de Draria, and Holding Services para Petroliers Spa. KBR had a 49% interest in this joint venture as of December 31, 2006.

LIQUIDITY AND CAPITAL RESOURCES

We ended 2006 with cash and equivalents of $4.4 billion compared to $2.4 billion at December 31, 2005. We ended 2006 with a negative net debt-to-capitalization ratio, with cash and equivalents and short-term investments exceeding our total debt.

Significant sources of cash

Cash flows from operations contributed $3.7 billion to cash in 2006. In the second quarter of 2006, we completed the sale of KBR’s Production Services group, which was part of our Energy and Chemicals segment. In connection with the sale, we received net proceeds of $265 million. In the fourth quarter of 2006, we received approximately $76 million as part of two agreements to sell certain non-core assets, including several lift boats. Our working capital requirements for our Iraq-related work, excluding cash and equivalents, decreased from $495 million at December 31, 2005 to $248 million at December 31, 2006.

We received proceeds of $508 million, net of underwriting fees and commissions and offering expenses, from the initial public offering of KBR, Inc. common stock in November 2006.

In 2006 and January 2007, we received $59 million in insurance proceeds related to fixed asset casualty reimbursement and business interruption from hurricanes Katrina and Rita.

We received approximately $167 million in asbestos- and silica-related insurance proceeds in 2006 and expect to receive additional amounts as follows:

Millions of dollars
2007	$	68
2008		46
2009		131
2010		16
Total	$	261

Further available sources of cash. We have available an unsecured $1.2 billion five-year revolving credit facility for general working capital purposes. There were no cash drawings under this credit facility as of December 31, 2006.

KBR has available an unsecured $850 million five-year revolving credit facility. Letters of credit that totaled $55 million were issued under the KBR revolving credit facility, thus reducing the availability under the credit facility to approximately $795 million at December 31, 2006. There were no cash drawings under the facility as of December 31, 2006.

Significant uses of cash

Capital expenditures of $891 million in 2006 were 37% higher than in 2005. Capital spending in 2006 included $831 million related to ESG, of which $260 million related to non-North American operations. ESG capital expenditures included increased spending on pressure pumping and drilling equipment to accommodate higher activity levels. KBR capital spending in 2006 was $57 million and included spending related to our DML shipyard and the build-out of KBR’s enterprise resource planning system.

During 2006, the company invested approximately $263 million on technology, including $256 million related to research and development costs.

In February 2006, our Board of Directors approved a share repurchase program of up to $1.0 billion. In September 2006, our Board of Directors approved an increase to our existing common share repurchase program of up to an additional $2.0 billion. During 2006, we repurchased approximately 40 million shares of our common stock for $1.3 billion, or an average price per share of $32.93. We paid $306 million in dividends to our shareholders in 2006.

We repurchased $41 million of debt at a total cost of $49 million in 2006. In the third quarter of 2006, we repaid, at par plus accrued interest, our $275 million 6.0% medium-term notes that matured.

In 2006, we contributed a total of $4 million to our domestic pension plans and $186 million to our international pension plans, which included an ESG contribution of $58 million and a KBR contribution of $115 million to their respective United Kingdom pension plans.

Future uses of cash. The following table summarizes our significant contractual obligations and other long-term liabilities as of December 31, 2006:

	Payments Due
Millions of dollars	2007		2008		2009		2010		2011		Thereafter		Total
Long-term debt (1)	$	45	$	164	$	5	$	752	$	3	$	1,862	$	2,831
Interest on debt (2)		140		119		92		85		51		2,202		2,689
Operating leases		188		145		125		110		103		367		1,038
Purchase obligations (3)		1,336		127		96		24		9		11		1,603
Pension funding
obligations		84		-		-		-		-		-		84
Barracuda Caratinga		10		-		-		-		-		-		10
Total	$	1,803	$	555	$	318	$	971	$	166	$	4,442	$	8,255

(1) 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 provided that we would contribute an amount up to $15 million to the silica trust each year for 30 years. 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 annual installment payments beginning in January 2005. In 2004, we accrued $44 million, which represented 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.

(2) Interest on debt includes 90 years of interest on $300 million of debentures at 7.6% interest which become due in 2096.

(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.

Capital spending for 2007 is expected to be approximately $1.3 billion, of which $1.2 billion relates to the ESG. In 2007, the largest increases in capital expenditures will be in the Drilling and Formation Evaluation segment and the Fluid Systems segment. From a geographic perspective, much of the increase in capital spending will be directed toward the Eastern Hemisphere to supply additional service equipment and infrastructure related to recent project wins. We expect our 2007 investment in technology to increase approximately 34% compared to 2006.

There are no debt maturities scheduled in 2007.

In future periods, we expect to make $1.0 billion to $2.0 billion annually in discretionary acquisitions in order to add to our energy service products and technologies. In January 2007, we acquired all of the intellectual property, current assets, and existing wireline services business associated with Ultraline Services Corporation, a division of Savanna Energy Services Corp., for approximately $177 million subject to adjustments for working capital purposes.

We will also continue with our discretionary share repurchase program, which has $1.7 billion of remaining authorization as of December 31, 2006.

Subject to board approval, we expect to pay dividends of approximately $75 million per quarter in 2007.

As of December 31, 2006, we had commitments to fund approximately $156 million to related companies, including $119 million to fund our privately financed projects. These commitments arose primarily during the start-up of these entities or due to losses incurred by them. We expect approximately $13 million of the commitments to be paid during 2007.

Other factors affecting liquidity

KBR indemnifications. We have entered into various agreements relating to the separation of KBR from us, including, among others, a master separation agreement, a registration rights agreement, a tax sharing agreement, transition services agreements, and an employee matters agreement. The master separation agreement provides for, among other things, KBR’s responsibility for liabilities related to its business and Halliburton’s responsibility for liabilities unrelated to KBR’s business. Halliburton provided indemnification in favor of KBR under the master separation agreement for contingent liabilities, including Halliburton’s indemnification of KBR and any of its greater than 50%-owned subsidiaries as of November 20, 2006 the date of the master separation agreement, for:

fines or other monetary penalties or direct monetary damages, including disgorgement, as a result of a claim made or assessed by a governmental authority in the United States, the United Kingdom, France, Nigeria, Switzerland and/or Algeria, or a settlement thereof, related to alleged or actual violations occurring prior to November 20, 2006 of the FCPA or particular, analogous applicable foreign statutes, laws, rules, and regulations in connection with current investigations, including with respect to the construction and subsequent expansion by TSKJ of a natural gas liquefaction complex and related facilities at Bonny Island in Rivers State, Nigeria; and

and other agreements between us and KBR with respect to tax matters. Under the transition services agreements, we will continue to provide various interim corporate support services to KBR, and KBR continues to provide various interim corporate support services to us. The fees will be determined on a basis generally intended to approximate the fully allocated direct and indirect costs of providing the services, without any profit. Under an employee matters agreement, Halliburton and KBR have allocated liabilities and responsibilities related to current and former employees and their participation in certain benefit plans. KBR’s final prospectus for its initial public offering dated November 15, 2006 contains a more detailed description of these separation agreements.

Letters of credit. In the normal course of business, we have agreements with banks under which approximately $1.0 billion of letters of credit or bank guarantees were outstanding as of December 31, 2006, including $676 million that relate to KBR. These KBR letters of credit or bank guarantees include $516 million that relate to their joint ventures’ operations. 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 2006, Moody’s revised its outlook from “stable” to “positive” due to our progress in the KBR separation. In the second quarter of 2006, Standard & Poor’s revised its long-term senior unsecured debt rating from BBB to BBB+ with a “stable” outlook due to the significant improvement in ESG operating performance and the considerable reduction in debt over the past year. Our short-term credit and commercial paper ratings are A-2 for Standard & Poor’s and P-2 for Moody’s Investors Service. We do not anticipate any adverse impact on our credit ratings resulting from the separation of KBR from Halliburton.

Debt covenants. Letters of credit related to our $1.2 billion revolving credit facility contain restrictive covenants, including maintaining a below maximum debt-to-capitalization ratio. At December 31, 2006, we were in compliance with this requirement.

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, 2006, KBR was in compliance with these requirements.

Security. In February 2007, we received a letter from the Department of the Army informing us of their intent to adjust payments under the LogCAP III contract associated with the cost incurred by the subcontractors to provide security to their employees. Based on this letter, the DCAA withheld the Army’s initial assessment of $20 million. The Army based its assessment on one subcontract wherein, based on communications with the subcontractor, the Army estimated 6% of the total subcontract cost related to the private security costs. The Army indicated that not all task orders and subcontracts have been reviewed and that they may make additional adjustments. The Army indicated that, within 60 days, they intend to begin making further adjustments equal to 6% of prior and current subcontractor costs unless we can provide timely information sufficient to show that such action is not necessary to protect the government’s interest. We are working with the Army to provide the additional information they have requested.

The Army indicated that they believe our LogCAP III contract prohibits us from billing costs of privately acquired security. We believe that, while LogCAP III contract anticipates that the Army will provide force protection to KBR employees, it does not prohibit any of our subcontractors from using private security services to provide force protection to subcontractor personnel. In addition, a significant portion of our subcontracts are competitively bid lump sum or fixed price subcontracts. As a result, we do not receive details of the subcontractors’ cost estimate nor are we legally entitled to it. Accordingly, we believe that we are entitled to reimbursement by the Army for the cost of services provided by our subcontractors, even if they incurred costs for private force protection services. Therefore, we believe that the Army’s position that such costs are unallowable and that they are entitled to withhold amounts incurred for such costs is wrong as a matter of law.

If we are unable to demonstrate that such action by the Army is not necessary, a 6% suspension of all subcontractor costs incurred to date could result in suspended costs of approximately $400 million. The Army has asked us to provide information that addresses the use of armed security either directly or indirectly charged to LogCAP III. The actual costs associated with these activities cannot be accurately estimated at this time but we believe that they should be less than 6% of the total subcontractor costs. As of December 31, 2006, no amounts have been accrued for suspended security billings.

BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS

We operate in approximately 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 and processing. Our six business segments are: Production Optimization, Fluid Systems, Drilling and Formation Evaluation, Digital and Consulting Solutions, Energy and Chemicals, and Government and Infrastructure. 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 Energy and Chemicals and Government and Infrastructure as KBR.

The industries we serve are highly competitive with many substantial competitors in each segment. In 2006, based upon the location of the services provided and products sold, 32% of our consolidated revenue was from the United States and 19% of our consolidated revenue was from Iraq. In 2005, 28% of our consolidated revenue was from the United States and 25% of our consolidated revenue was from Iraq. In 2004, 27% of our consolidated revenue was from Iraq and 22% of our consolidated revenue was from the United States. No other country accounted for more than 10% of our revenue during these periods.

Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil unrest, force majeure, war or other armed conflict, expropriation or other governmental actions, inflation, exchange 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, 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 (WTI) and United Kingdom Brent crude oil, and Henry Hub natural gas:

Average Oil Prices (dollars per barrel)	2006		2005		2004
West Texas Intermediate	$	66.17	$	56.30	$	41.31
United Kingdom Brent	$	65.35	$	54.45	$	38.14

Average United States Gas Prices (dollars per million British
thermal units, or mmBtu)
Henry Hub	$	6.81	$	8.79	$	5.85

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

Land vs. Offshore	2006		2005		2004
United States:
Land		1,558		1,287		1,093
Offshore		90		93		97
Total		1,648		1,380		1,190
Canada:
Land		467		454		365
Offshore		3		4		4
Total		470		458		369
International (excluding Canada):
Land		656		593		548
Offshore		269		258		233
Total		925		851		781
Worldwide total		3,043		2,689		2,340
Land total		2,681		2,334		2,006
Offshore total		362		355		334

Oil vs. Gas		2006		2005		2004
United States:
Oil		273		194		165
Gas		1,375		1,186		1,025
Total		1,648		1,380		1,190
Canada:
Oil		110		100		91
Gas		360		358		278
Total		470		458		369
International (excluding Canada):
Oil		709		651		599
Gas		216		200		182
Total		925		851		781
Worldwide total		3,043		2,689		2,340
Oil total		1,092		945		855
Gas total		1,951		1,744		1,485

Heightened energy demand in 2006 contributed to a 13% increase in the average worldwide rig count compared to 2005. This increase was primarily driven by the United States rig count, which grew 19% year-over-year. Our ESG revenue in the United States grew 36% year-over-year with these rig count increases. Average Canadian rig counts increased 3% in 2006 compared to 2005. Outside of North America, average rig counts increased in Latin America, Africa, and the Middle East, with most of the increase related to oil drilling.

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 promotes additional investment by our customers in the sector. The opposite is true for lower oil and gas prices.

United States oil prices experienced record highs in 2006 with WTI and Brent crude average yearly prices increasing 18% and 20% respectively, compared to 2005.

After declining from record highs during the third and fourth quarter of 2006, crude oil prices are expected to remain at these historically high levels due to a combination of the following factors:

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

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

OPEC’s commitment to control production; and

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

According to the International Energy Agency’s January 2007 Oil Market report, the outlook for world oil demand remains strong, with China, the Middle East, and North America accounting for approximately 78% of the expected demand growth in 2007. Excess oil production capacity is expected to remain constrained and that, along with steady 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 2007 to increase 2% over 2006.

Volatility in natural gas prices has the potential to impact our customers' drilling and production activities, particularly in the United States. For example, mild temperatures and minimal hurricane-related disruptions to production on the Gulf of Mexico resulted in high natural gas storage levels and lower natural gas prices during the second half of 2006.

It is common practice in the United States oilfield services industry to sell services and products based on a price book and then apply discounts to the price book based upon a variety of factors. The discounts applied typically increase to partially offset price book increases. The discount applied normally decreases if activity levels are 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.

The price book increases we implemented in 2005 and the first half of 2006 increased revenue and operating income across all segments during 2006. From April 2006 to July 2006, we implemented several United States price book increases ranging from 5% to 12%, led by our pressure pumping services. We will continue to evaluate future United States price book increases and focus on decreasing customer discounts.

Geographic discussion. North America revenue for 2006 grew $1.6 billion compared to 2005. This growth was primarily led by our production enhancement services, 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 have continued 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. As a result, our revenue from the Gulf of Mexico in 2006 was up 32% year-over-year, which contributed to a 152% increase in operating income in the Gulf of Mexico. Revenue from Canada was up 17% year-over-year, primarily driven by the Production Optimization segment. During the third quarter of 2006, our Drilling and Formation Evaluation and Fluid Systems segments were awarded multimillion-dollar contracts for a development project in Alaska.

During 2006, our ESG international revenue increased 23% or $1.3 billion compared to 2005.

In our Middle East/Asia region, Saudi Arabia experienced 49% revenue growth compared to 2005 due to increased activity. In July 2006, we signed a three-year agreement to provide the oilfield services component for the Saudi Aramco Al Khurais project. In the Asia Pacific area, Malaysia and Australia contributed the most to year-over-year revenue growth compared to 2005. In the third quarter of 2006, we were awarded two contracts in Indonesia totaling $110 million to provide cementing and stimulation services.

In our Europe/Africa/CIS region, North Sea activity has continued to grow, accounting for 25% of revenue growth year-over-year, led by the Production Optimization segment. In the second quarter of 2006, we signed a $193 million two-year contract with additional extension options for cementing services, pumping, and drilling and completion fluids in Norway. Also in the second quarter, we signed an estimated $100 million five-year contract with options for five single-year extensions to provide completion products and services for oil and gas operations in the United Kingdom, the Netherlands, Norway, and Ireland. In July 2006, we signed a $150 million contract to provide integrated drilling and well services in Norway for a duration of up to six years. Our operations in Russia experienced strong revenue and operating income growth year-over-year. In the fourth quarter of 2006, we signed a $59 million contract for the provision of hydraulic fracturing services in Russia. In the first quarter of 2007, we signed a $100 million three-year contract with options to renew for three additional one-year periods, for the provision of drilling fluids, waste management services, cementing, drill bits, directional drilling, and logging-while-drilling services in Russia. Activity in Africa grew $197 million, representing a 20% increase compared to 2005. Fluid Systems growth in both Nigeria and Angola, coupled with Production Optimization growth across Africa, accounted for the largest part of the revenue growth in Africa. We are continuing to deploy additional personnel into Libya as this market continues to grow after the elimination of sanctions by the United States.

In Latin America, we experienced 13% revenue growth year-over-year despite a decrease in revenue from Mexico. This came largely from revenue growth of 83% in Ecuador and 29% in Columbia, both aided by the Fluid Systems contract start-ups that began in 2005. Double digit revenue growth in Brazil, Argentina, and Venezuela also contributed to the improvement in Latin America. The revenue decline in Mexico is mostly attributable to the turnkey drilling project, which began in 2004 and was completed in July of 2006. In the fourth quarter of 2006, we signed a $73 million three-year contract to provide stimulation services in Mexico.

Technology is an important aspect of our business, and we continue to focus on the development, introduction, and application of new technologies. Therefore, we expect our 2007 investment in technology to increase approximately 34% compared to 2006. We have plans for three international research and development centers with global technology and training missions. The first will open in Pune, India in the second quarter of 2007, and the second in Singapore is planned for later in 2007.

ESG also has plans on expanding its manufacturing capability and capacity with new manufacturing plants in Mexico and Brazil during the first half of 2007 and in Singapore and Malaysia during the second half of 2007.

ESG hired over 13,000 employees in 2006, and we expect to add a similar number in 2007. To meet the increasing need for technical training, we also plan to open a new training center in Tyumen, Russia in the first quarter of 2007, which follows recent training center expansions in Malaysia, Egypt, and Mexico.

KBR

KBR provides a wide range of services to energy, chemical, and industrial customers and government entities worldwide. At any given time, a relatively few number of projects and joint ventures represent a substantial part of our operations. 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 its customers’ capital expenditures and budgets for construction and defense services. Additionally, the heightened focus on global security and major military force realignments, as well as a global expansion in government outsourcing, have all contributed to increased demand for KBR’s services.

Energy and Chemicals segment. Our Energy and Chemicals segment designs and constructs energy and petrochemical projects throughout the world, including liquefied natural gas (LNG) and GTL gas monetization facilities, refineries, petrochemical plants, offshore oil and gas production platforms, and Syngas facilities. Production companies are investing in development projects that may not have been economically viable when oil and gas price levels were lower than they are today. Our experience in providing engineering, design and construction services in the oil and gas industry positions us to benefit from the growth expected across the various oil and gas sectors. We are positioned to capitalize on the anticipated growth in LNG & GTL infrastructure.

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 engineering, procurement, and construction management opportunities in northern and western Africa, the Caspian area, Asia Pacific, Latin America, and the North Sea. With regard to our energy and chemical projects, worldwide resource constraints, escalating material and equipment prices, and ongoing supply chain pricing pressures are causing delays in awards of and, in some cases, cancellations of major gas monetization and upstream prospects. Certain very large scale projects that KBR has been pursuing for new awards have either been cancelled, awarded to competitors or significantly delayed. These developments may negatively and materially impact KBR’s 2007 and 2008 results on a stand alone basis (excluding consideration of potential offsets such as the slower than expected decline in LogCAP III activity, or work in other areas and overhead reductions that may or may not be realized). It is generally very difficult to predict whether or when we will receive such awards as these contracts frequently involve a lengthy and complex bidding and selection process which is affected by a number of factors, such as market conditions, financing arrangements, governmental approvals and environmental matters.

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.

In the first quarter of 2006, we signed a $400 million contract for the construction of the Egypt Basic Industries Corporation (EBIC) ammonia plant project. We also have an investment in a development corporation that has an indirect interest in the EBIC project. We are performing the EPC work for the project and operations and maintenance services for the facility. In August 2006, the lenders providing the construction financing notified EBIC that it was in default of the terms of its debt agreement, which effectively prevented the project from making additional borrowings until such time as certain security interests in the ammonia plant assets related to the export facilities, could be perfected. Indebtedness under the debt agreement is non-recourse to us. This default was cured on December 8, 2006 subject to EBIC’s submission and the lender’s acceptance of the remaining documents by March 2007. No event of default has occurred pursuant to our EPC contract and we have been paid all amounts due from EBIC. In September 2006, we were instructed by EBIC to cease work on one location of the project on which the ammonia storage tanks were originally planned to be constructed due to a decision to relocate the tanks. The new location has been selected and the client and its lenders have agreed to compensate KBR for approximately $6 million in costs resulting from the relocation of the storage tanks. We resumed work on the ammonia tanks in February 2007.

In July 2006, KBR was awarded, through a 50%-owned consolidated joint venture, a $997 million contract with Qatar Shell GTL Limited to provide project management and cost-reimbursable engineering, procurement and construction management services for the Pearl GTL project in Ras Laffan, Qatar. The project, which is expected to be completed by 2011, consists of gas production facilities and a GTL plant.

Also in July 2006, we were awarded a $194 million fixed-price engineering, procurement, and construction management contract by a Saudi Kayan Petrochemical Company for a 1.35 million ton-per-year ethylene plant in Jubail City, Saudi Arabia.

of 2006, we reached agreement with the project owner to settle $264 million of these change orders. As a result, portions of the remaining work now have a lower risk profile, particularly with respect to security and logistics. Since we completed our first check estimate in the second quarter of 2006, the project has continued to estimate significant additional cost increases. We currently expect to recover these recently identified cost increases through change orders. As of December 31, 2006, we have recorded $43 million of unapproved change orders which primarily relate to these cost increases. Because of the civil unrest and security issues that currently exist in Nigeria, uncertainty regarding soil conditions at the property site and other matters, we could experience substantial additional cost increases on the Escravos project in the future. We believe that future cost increases attributed to civil unrest, security matters and potential differences in actual rather than anticipated soil conditions should ultimately be recoverable through future change orders pursuant to the terms of our contract as amended in 2006. However, should this occur, there could be timing differences between the recognition of cost and recognition of offsetting potential recoveries from our client, if any. We recorded an additional $9 million loss in the fourth quarter of 2006 related to non-billable engineering services for the Escravos joint venture. These services were in excess of the contractual limit of total engineering costs each partner can bill to the joint venture. As of December 31, 2006, the project was approximately 45% complete.

In the second quarter of 2006, we completed the sale of KBR’s Production Services group. Under the terms of the agreement, we received net proceeds of $265 million resulting in a pretax gain, net of post-closing adjustments, of $120 million. As a result of the sale agreement, Production Services operations and assets and liabilities have been classified as discontinued operations for all periods presented.

Government and Infrastructure segment. Our Government and Infrastructure segment provides support services to military and civilian branches of governments throughout the world, many of whom are increasing the use of outsourced service providers in order to focus on core functions and address budgetary constraints. The Government and Infrastructure segment’s most significant contract is the worldwide United States Army logistics contract, known as LogCAP III. We were awarded the competitively bid LogCAP III contract in December 2001 from the Army Materiel Command (AMC) to provide worldwide United States Army logistics services. The initial term of the contract was one-year, with nine one-year renewal options. We are currently in the fifth year of the contract.

In August 2006, the DoD issued a request for proposals on a new competitively bid, multiple service provider LogCAP IV contract to replace the current LogCAP III contract. We are currently the sole service provider under the LogCAP III contract and in October 2006, we submitted the final portion of our bid on the LogCAP IV contract. We expect that the contract will be awarded during the second quarter of 2007. Despite the award of the August 2006 task order under our LogCAP III contract, and the possibility of being awarded a portion of the LogCAP IV contract, we expect our overall volume of work to decline as our customer scales back the amount of services we provide. However, as a result of the recently announced surge of additional troops in Iraq, we expect the decline to occur more slowly than previously expected.

In addition, KBR was awarded the competitively bid Indefinite Delivery/Indefinite Quantity contract in the first quarter of 2006 to support the Department of Homeland Security’s U.S. Immigration and Customs Enforcement facilities in the event of an emergency. With a maximum total value of $385 million, this contract has a five-year term, consisting of a one-year base period and four one-year renewal options.

In the second quarter of 2006, a $13.9 billion private finance initiative contract was signed with the United Kingdom Ministry of Defence for the Allenby and Connaught project. This project is operated by a joint venture in which KBR has a 45% ownership interest. The project is for 35 years and consists of a nine-year construction

project to upgrade the British Army’s garrisons at Aldershot and the Salisbury Plain in the United Kingdom. The contract also includes provisions for additional services to be performed over the 35-year period, including catering, transportation, office services, and maintenance services.

In July 2006, we resumed work under the U.S. Army Europe Support Contract, which was originally awarded in 2005. Under this contract, we will continue to provide support services to U.S. forces deployed in the Balkans. In addition, we will provide camp operations and maintenance, and transportation and maintenance services in support of troops throughout the U.S. Army Europe’s area of responsibility, which includes over 90 countries.

We are also the majority owner of Devonport Management Limited (DML), the owner and operator of Western Europe’s largest naval dockyard complex. Our DML shipyard operations are primarily engaged in refueling nuclear submarines and performing maintenance on surface vessels for the MoD as well as limited commercial projects. We are engaging in discussions with the MoD regarding KBR’s ownership in DML and the possibility of reducing or disposing of our interest. Although no decision has been made with respect to a disposition or reduction of our interest in DML, we are supporting a process to identify potential bidders that may have an interest in acquiring our interest in DML. We do not know at this time if the process will result in a disposition or reduction of our interest in DML.

With respect to the Alice Springs-Darwin railroad project, KBR owns 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 the railway. We account for this investment using the equity method of accounting in our Government and Infrastructure segment. This joint venture has sustained losses since commencing operations due to lower than anticipated freight volume and a slowdown in the planned expansion of the Port of Darwin. At the end of the first quarter of 2006, the joint venture’s revised financial forecast led us to record a $26 million impairment charge. In October 2006, the joint venture incurred an event of default under its loan agreement by failing to make an interest and principal payment. These loans are non-recourse to us. In light of the default, the joint venture’s need for additional financing, and the realization that the joint venture efforts to raise additional equity from third parties were not successful, we recorded an additional $32 million impairment charge in the third quarter of 2006. We will receive no tax benefit as this impairment charge is not deductible for Australian tax purposes. In December 2006, the senior lenders agreed to waive existing defaults and concede certain rights under the existing indenture. Among these were a reduction in the joint venture’s debt service reserve and the relinquishment of the right to receive principal payments for 27 months, through March 2009. In exchange for these concessions, the shareholders of the joint venture committed approximately $12 million of new subordinated financing, of which $6 million was committed by us. At December 31, 2006, our investment in this joint venture was $6 million. Our $6 million additional funding commitment was still outstanding.

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.

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.

RESULTS OF OPERATIONS IN 2006 COMPARED TO 2005

*REVENUE:*					Increase			Percentage
Millions of dollars	2006		2005		(Decrease)			Change
Production Optimization	$	5,360	$	3,990	$	1,370			34	%
Fluid Systems		3,598		2,838		760			27
Drilling and Formation Evaluation		3,221		2,552		669			26
Digital and Consulting Solutions		776		720		56			8
Total Energy Services Group		12,955		10,100		2,855			28
Energy and Chemicals		2,373		2,008		365			18
Government and Infrastructure		7,248		8,132		(884	)		(11	)
Total KBR		9,621		10,140		(519	)		(5	)
Total revenue	$	22,576	$	20,240	$	2,336			12	%

Geographic - Energy Services Group segments only:
Production Optimization:
North America	$	3,229	$	2,317	$	912			39	%
Latin America		410		349		61			17
Europe/Africa/CIS		1,027		802		225			28
Middle East/Asia		694		522		172			33
Subtotal		5,360		3,990		1,370			34
Fluid Systems:
North America		1,871		1,424		447			31
Latin America		417		374		43			11
Europe/Africa/CIS		844		659		185			28
Middle East/Asia		466		381		85			22
Subtotal		3,598		2,838		760			27
Drilling and Formation Evaluation:
North America		1,107		868		239			28
Latin America		474		400		74			19
Europe/Africa/CIS		744		619		125			20
Middle East/Asia		896		665		231			35
Subtotal		3,221		2,552		669			26
Digital and Consulting Solutions:
North America		251		210		41			20
Latin America		213		221		(8	)		(4	)
Europe/Africa/CIS		183		168		15			9
Middle East/Asia		129		121		8			7
Subtotal		776		720		56			8
Total Energy Services Group revenue
by region:
North America		6,458		4,819		1,639			34
Latin America		1,514		1,344		170			13
Europe/Africa/CIS		2,798		2,248		550			24
Middle East/Asia		2,185		1,689		496			29
Total Energy Services Group revenue	$	12,955	$	10,100	$	2,855			28	%

*OPERATING INCOME (LOSS):*							Increase			Percentage
Millions of dollars	2006			2005			(Decrease)			Change
Production Optimization	$	1,530		$	1,053		$	477			45	%
Fluid Systems		795			544			251			46
Drilling and Formation Evaluation		818			536			282			53
Digital and Consulting Solutions		240			146			94			64
Total Energy Services Group		3,383			2,279			1,104			48
Energy and Chemicals		37			124			(87	)		(70	)
Government and Infrastructure		202			329			(127	)		(39	)
Total KBR		239			453			(214	)		(47	)
General corporate		(138	)		(115	)		(23	)		(20	)
Total operating income	$	3,484		$	2,617		$	867			33	%

Geographic - Energy Services Group segments only:
Production Optimization:
North America	$	1,059		$	759		$	300			40	%
Latin America		85			59			26			44
Europe/Africa/CIS		230			128			102			80
Middle East/Asia		156			107			49			46
Subtotal		1,530			1,053			477			45
Fluid Systems:
North America		515			332			183			55
Latin America		70			58			12			21
Europe/Africa/CIS		127			103			24			23
Middle East/Asia		83			51			32			63
Subtotal		795			544			251			46
Drilling and Formation Evaluation:
North America		333			223			110			49
Latin America		90			58			32			55
Europe/Africa/CIS		154			110			44			40
Middle East/Asia		241			145			96			66
Subtotal		818			536			282			53
Digital and Consulting Solutions:
North America		126			62			64			103
Latin America		44			17			27			159
Europe/Africa/CIS		44			46			(2	)		(4	)
Middle East/Asia		26			21			5			24
Subtotal		240			146			94			64
Total Energy Services Group
operating income by region:
North America		2,033			1,376			657			48
Latin America		289			192			97			51
Europe/Africa/CIS		555			387			168			43
Middle East/Asia		506			324			182			56
Total Energy Services Group
operating income	$	3,383		$	2,279		$	1,104			48	%

Note 1 - All periods presented reflect the reclassification of KBR’s Production Services operations to discontinued operations, as well as the reorganization of tubing conveyed perforating, slickline, and underbalanced applications operations from Production Optimization into the Drilling and Formation Evaluation segment.

The increase in consolidated revenue in 2006 compared to 2005 was attributable to increased revenue from our Energy Services Group, predominantly resulting from increased activity, higher utilization of our equipment, and increased pricing due to higher exploration and production spending by our customers. This was partially offset by reduced activity in our Government and Infrastructure segment, primarily in the Middle East. Revenue in 2005 was impacted by an estimated $80 million in lost revenue due to Gulf of Mexico hurricanes. International revenue was 68% of consolidated revenue in 2006 and 72% of consolidated revenue in 2005. Revenue from the United States Government for all geographic areas was approximately $5.8 billion or 26% of consolidated revenue in 2006, compared to $6.6 billion or 32% of consolidated revenue in 2005.

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 declined primarily due to a $157 million loss recorded on the Escravos, Nigeria GTL project and reduced activity on government services projects, particularly in the Middle East. ESG operating income for 2006 included a $48 million gain on the sale of lift boats in west Africa and the North Sea and $47 million of insurance proceeds for business interruptions resulting from the 2005 Gulf of Mexico hurricanes. Operating income in 2005 was adversely impacted by an estimated $50 million due to Gulf of Mexico hurricanes, $45 million of which related to ESG and $5 million of which related to KBR.

In 2006, Iraq-related work contributed approximately $4.7 billion to consolidated revenue and $166 million to consolidated operating income, a 3.5% 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 2005 was derived from all regions. Production enhancement services revenue grew 36%, with improvements in all regions, largely driven by United States onshore operations due to strong demand for stimulation services, coupled with improved equipment utilization and pricing. Also contributing to production enhancement services revenue growth were improved pricing and equipment utilization in Canada, increased activity in Europe, and a new contract in Oman. Revenue from sales of completion tools increased 31% compared to 2005, with improvements in all regions, benefiting from improved completions and perforating sales in the United States and recovery of Gulf of Mexico activity. Additionally impacting the increase in sales of completion tools was the addition of Easywell to the completion tool portfolio in Europe and Asia and increased activity in Asia for WellDynamics. International revenue was 44% of total segment revenue in 2006 compared to 47% in 2005.

The Production Optimization segment operating income improvement spanned all regions. Production enhancement services operating income increased 59% largely due to improved product mix in the United States and Asia. A 41% improvement in completion tools operating income primarily resulted from increased sales in Asia and increased sand control tools activity in Brazil. Partially offsetting the improvements in completion tools was decreased activity in the Middle East for WellDynamics. The 2006 segment operating income was positively impacted by a $48 million gain on the sale of lift boats in west Africa and the North Sea. The Production Optimization segment received hurricane insurance proceeds of $12 million in 2006. The 2005 segment operating income included a $110 million gain on the sale in 2005 of our equity interest in the Subsea 7, Inc. joint venture and was negatively impacted by hurricanes in the Gulf of Mexico by an estimated $14 million.

Fluid Systems revenue increase compared to 2005 was driven by 27% growth in Baroid Fluid Services revenue and 26% growth in cementing services revenue. Both service lines increased primarily in the United States from improved pricing and increased activity. Baroid Fluid Services improvements spanned all regions with increased operations in Venezuela and Russia, new contracts in Norway and Nigeria, and increased activity in Angola and Sakhalin. The expiration of a contract in Indonesia partially offset Baroid Fluid Services revenue increase. Sales of cementing services also improved due to increased activity in Russia, the North Sea, and Nigeria, improved pricing and sales in Angola, and new contract start-ups and product sales in Asia Pacific. Partially offsetting the cementing services revenue increase was decreased activity in Mexico. International revenue was 52% of total segment revenue in 2006 compared to 55% in 2005.

Fluid Systems segment operating income increase compared to 2005 resulted from 54% growth from Baroid Fluid Services and 43% 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 in Asia. Cementing services results increased predominantly in the United States due to increased activity and new contracts along with increased activity in Europe. The Fluid Systems segment received hurricane insurance proceeds of $31 million in 2006, and was negatively impacted by an estimated $25 million in 2005 from hurricanes in the Gulf of Mexico.

Drilling and Formation Evaluation revenue increase in 2006 compared to 2005 was derived from all four regions in all product service lines. The segment improvement was led by a 27% increase in drilling services revenue, particularly in the United States due to improved pricing and increased drilling activity. Increased international activity and new contract start-ups contributed to other region revenue increases, especially evident in Asia and Europe. Drill bits revenue increased 26% compared to 2005, largely benefiting from increased rig counts, improved pricing, and increased sales of fixed cutter bits in the United States and increased drilling activity in the Middle East and Asia. Wireline and perforating services revenue grew 25% primarily due to increased activity and improved pricing in the United States land, new contract awards and increased cased hole activity in Asia, improved pricing in Latin America, and new contracts in the Middle East. Lower sales of logging equipment to Asia in 2006 partially offset the wireline and perforating services revenue improvement. International revenue was 71% of total segment revenue in 2006 compared to 72% in 2005.

Drilling and Formation Evaluation operating income increase compared to 2005 spanned all geographic regions in all product service lines, with the United States as the predominant contributor due to improved pricing and increased rig activity. Drilling services operating income increased 66% from 2005 on increased activity and new contracts in Europe and Asia. Drill bits operating income increased 15% compared to 2005, the majority of which occurred in the Middle East and Asia. Wireline and perforating services results grew 50%, additionally benefiting from higher activity in the Middle East and Asia along with improved product mix in Latin America. Operating income in 2005 included a $24 million gain related to a patent infringement case settlement, while hurricanes in the Gulf of Mexico negatively impacted segment operating income by an estimated $6 million.

Digital and Consulting Solutions revenue increase in 2006 was driven by Landmark, with 17% revenue growth spanning all four regions, largely due to increased consulting services and software sales in Latin America and the United States. Project management revenue decreased 11% in 2006 due to the completion of two fixed-price integrated solutions projects in southern Mexico. International revenue was 70% of total segment revenue in 2006 compared to 73% in 2005.

Digital and Consulting Solutions operating income improved both at Landmark where operating income increased 59% due to stronger software and service sales, and project management where results tripled. The 2006 segment results included a gain of $10 million from the sale of an investment accounted for under the cost method and operating income of $12 million from earnings on an equity method investment. Included in 2005 segment results was $23 million in losses on two fixed-priced integrated solutions projects in Mexico and a $17 million favorable insurance settlement related to a pipe fabrication and laying project in the North Sea.

Energy and Chemicals revenue for 2006 increased $365 million compared to 2005. The increase is due to the start-up of several projects awarded in 2005 or early 2006, including the front-end engineering and design work performed on the Pearl project and revenue earned on the Escravos GTL project, which increased $452 million. In addition, revenue from gas monetization projects in Yemen and Algeria increased $109 million. These increases were offset by a $246 million decrease in revenue from a crude oil project in Canada.

Operating income for 2006 was $37 million compared to $124 million in 2005. The decrease is primarily due to a $157 million charge on the Escravos, Nigeria GTL project in 2006. The charge was primarily due to increases in the overall estimated cost to complete the project. The project has experienced delays relating to civil unrest and security on the Escravos River, near the project site. Also negatively impacting operating income were a charge on the Barracuda-Caratinga project and a decrease in operating income from the Belanak project totaling $30 million. The decrease was partially offset by a $60 million increase in operating income from an ammonia project in Egypt and a gas development project in Algeria. In addition, we recorded $50 million of charges in 2005 related to an investment in an unconsolidated Algerian joint venture.

Government and Infrastructure revenue for 2006 totaled $7.2 billion, an $884 million decrease compared to 2005. This decrease was primarily due to a $698 million decrease in revenue from Iraq-related activities, a $151 million decrease in revenue related to hurricane repair efforts for United States naval facilities under the CONCAP III contract, and $58 million of impairment charges related to an equity investment in an Australian railroad operation.

Operating income for 2006 was $202 million compared to $329 million in 2005, a $127 million decrease. The 2006 results were also negatively impacted by $58 million in impairment charges recorded on an equity investment in an Australian railroad operation and a $17 million impairment charge and loss recorded on an equity investment in a joint venture road project in the United Kingdom. These decreases were partially offset by a $24 million increase in operating income from DML shipyard operations. The 2005 results include $96 million in operating income from the sale of and one-time cash distribution from an interest in a United States toll road.

General corporate expenses were $138 million in 2006 compared to $115 million in 2005. The increase was primarily due to increased legal costs and costs incurred for the separation of KBR from Halliburton.

NONOPERATING ITEMS

Interest expense decreased $32 million in 2006 compared to 2005, primarily due to the redemption in April 2005 of $500 million of our floating rate senior notes, the repayment in October 2005 of $300 million of our floating rate senior notes, and the repayment in August 2006 of $275 million of our medium-term notes.

Interest income increased $98 million in 2006 compared to 2005 due to higher cash investment balances.

Foreign currency losses, net grew to $22 million in 2006 from $13 million in 2005. The increase was primarily due to the impact of United States dollar proceeds from the sale of Production Services that were received by our United Kingdom-based subsidiary, which uses British sterling as its functional currency.

Other, net increased $14 million in 2006 compared to 2005. The 2005 year included costs related to our ESG accounts receivable securitization facility and sales of our United States government accounts receivable, neither of which had any outstanding amounts in 2006.

Provision for income taxes from continuing operations in 2006 of $1.1 billion resulted in an effective tax rate of 33%. The lower tax rate of 3% for 2005 resulted from recording favorable adjustments in 2005 totaling $805 million to our valuation allowance against the deferred tax asset related to asbestos and silica liabilities. Our strong 2005 earnings, coupled with an upward revision in our estimate of future domestic taxable income in 2006, drove these adjustments. We expect our 2007 tax rate to be approximately 35%.

Minority interest in net income of subsidiaries decreased $23 million compared to 2005 primarily due to the loss from the consolidated 50%-owned GTL project in Escravos, Nigeria. This is partially offset by earnings growth in our DML Shipyard, M.W. Kellogg Ltd., and our Pearl GTL project and an immaterial amount related to approximately 19% of KBR, Inc. sold in the IPO in November 2006.

Income (loss) from discontinued operations, net of tax in 2006 included a $120 million pretax gain on the sale of KBR’s Production Services group and $14 million of pretax income related to Production Services operations, partially offset by a $13 million legal settlement. Income from discontinued operations in 2005 primarily consisted of $45 million of pretax income related to Production Services operations.

RESULTS OF OPERATIONS IN 2005 COMPARED TO 2004

*REVENUE:*					Increase			Percentage
Millions of dollars	2005		2004		(Decrease)			Change
Production Optimization	$	3,990	$	3,047	$	943			31	%
Fluid Systems		2,838		2,324		514			22
Drilling and Formation Evaluation		2,552		2,038		514			25
Digital and Consulting Solutions		720		589		131			22
Total Energy Services Group		10,100		7,998		2,102			26
Energy and Chemicals		2,008		2,490		(482	)		(19	)
Government and Infrastructure		8,132		9,390		(1,258	)		(13	)
Total KBR		10,140		11,880		(1,740	)		(15	)
Total revenue	$	20,240	$	19,878	$	362			2	%

Geographic - Energy Services Group segments only:
Production Optimization:
North America	$	2,317	$	1,626	$	691			42	%
Latin America		349		315		34			11
Europe/Africa/CIS		802		710		92			13
Middle East/Asia		522		396		126			32
Subtotal		3,990		3,047		943			31
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		868		678		190			28
Latin America		400		301		99			33
Europe/Africa/CIS		619		504		115			23
Middle East/Asia		665		555		110			20
Subtotal		2,552		2,038		514			25
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	$	1,053		$	588		$	465			79	%
Fluid Systems		544			348			196			56
Drilling and Formation Evaluation		536			270			266			99
Digital and Consulting Solutions		146			60			86			143
Total Energy Services Group		2,279			1,266			1,013			80
Energy and Chemicals		124			(443	)		567			NM
Government and Infrastructure		329			84			245			292
Total KBR		453			(359	)		812			NM
General corporate		(115	)		(87	)		(28	)		(32	)
Total operating income (loss)	$	2,617		$	820		$	1,797			219	%

Geographic - Energy Services Group segments only:
Production Optimization:
North America	$	759		$	367		$	392			107	%
Latin America		59			53			6			11
Europe/Africa/CIS		128			96			32			33
Middle East/Asia		107			72			35			49
Subtotal		1,053			588			465			79
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		223			111			112			101
Latin America		58			27			31			115
Europe/Africa/CIS		110			53			57			108
Middle East/Asia		145			79			66			84
Subtotal		536			270			266			99
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

Note 1 - All periods presented reflect the reclassification of KBR’s Production Services operations to

discontinued operations, as well as the reorganization of tubing conveyed perforating, slickline, and

underbalanced applications operations from Production Optimization into the Drilling and Formation

Evaluation segment.

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 72% 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 32% of consolidated revenue in 2005 compared to $8.0 billion or 40% 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 17% compared to 2004, benefiting from improved completions and perforating sales in Angola, the United Kingdom, and the United States, and increased 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, which is included in completion tools, 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 47% of total segment revenue in 2005 compared to 52% 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 73% 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 a breakeven position 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. Wireline and perforating services revenue grew 19% primarily due to increased cased hole activity and improved pricing in the United States, sales of logging equipment in Asia, and new contract awards in West Africa and the Middle East. International revenue was 72% of total segment revenue in 2005 compared to 73% 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 more than 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 Africa also contributed to drilling services operating income increase. Wireline and perforating services results grew 50%, additionally benefiting from higher activity in West Africa and the Middle East and sales of logging equipment in Asia. 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 Africa, increased consulting, and higher sales and services in Algeria, partially offset by nonrecurring sales to Asia 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.

Energy and Chemicals revenue for 2005 decreased $482 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 $124 million in 2005 compared to a $443 million loss in 2004, a $567 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.

Government and Infrastructure revenue for 2005 totaled $8.1 billion, a $1.3 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 $329 million compared to $84 million in 2004, a $245 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.

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 $64 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 the 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.

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 2005 primarily consisted of income related to Production Services operations. In 2004 we incurred a $778 million pretax charge for the revaluation of the 119 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.

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 long-term 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 extent of progress toward completion; and

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

Progress is generally based upon physical progress, man-hours or costs incurred depending on the type of job. Physical percent complete is determined as a combination of input and output measures as deemed appropriate by the circumstances.

At the outset of each contract, we prepare a detailed analysis of our estimated cost to complete the project. Risks related to service delivery, usage, productivity, and other factors are considered in the estimation process. Our project personnel periodically evaluate the estimated costs, claims, change orders, and percentage of completion at the project level. The recording of profits and losses on long-term contracts requires an estimate of the total profit or loss over the life of each contract. This estimate requires consideration of total contract value, change orders, and claims, less costs incurred and estimated costs to complete. Anticipated losses on contracts are recorded in full in the period in which they become evident. Profits are recorded based upon the total estimated contract profit times the current percentage complete for the contract.

When calculating the amount of total profit or loss on a long-term contract, we include unapproved claims as revenue when the collection is deemed probable based upon the four criteria for recognizing unapproved claims under the American Institute of Certified Public Accountants Statement of Position 81-1, “Accounting for Performance of Construction-Type and Certain Production-Type Contracts.” Including probable unapproved claims in this calculation increases the operating income (or reduces the operating loss) that would otherwise be recorded without consideration of the probable unapproved claims. Probable unapproved claims are recorded to the extent of costs incurred and include no profit element. In all cases, the probable unapproved claims included in determining contract profit or loss are less than the actual claim that will be or has been presented to the customer. 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 working 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 3 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 are either in dispute with our customer or have been identified as potentially unallowable per the terms of the contract or the federal acquisition regulations.

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 received 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. The LogCAP IV contract would be an example of a contract in which award fees would be 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 5.9%. At December 31, 2006, allowance for bad debts totaled $97 million or 2.8% of notes and accounts receivable before the allowance, and at December 31, 2005, allowance for bad debts totaled $90 million or 2.8% of notes and accounts receivable before the allowance. A 1% change in our estimate of the collectibility of our notes and accounts receivable balance as of December 31, 2006 would have resulted in a $35 million adjustment to 2006 total operating costs and expenses.

Income tax accounting

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

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

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

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

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

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

identifying the types and amounts of existing temporary differences;

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

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

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

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

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

We have operations in 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 had recorded a valuation allowance based on the anticipated impact of the United States net operating loss generated from asbestos and silica deductions on our ability to utilize future foreign tax credits in the United States. This valuation allowance was reassessed quarterly based on a number of estimates, including future creditable foreign taxes and future taxable income. Factors such as actual operating results, material acquisitions or dispositions, and changes to our operating environment could alter the estimates, which could have a material impact on the valuation allowance. 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. Given that we fully utilized the United States net operating loss in 2006 and expect to begin utilizing foreign tax credits in the United States for 2007, the valuation allowance balance has been reduced to zero as of the end of 2006.

Legal and investigation matters

As discussed in Note 13 of our consolidated financial statements, as of December 31, 2006, 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 Statement of Financial Accounting Standards No. 158 (SFAS No. 158), “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R).” Two of the more critical assumptions and estimates used in the actuarial calculations are the discount rate for determining the current value of plan benefits and the expected rate of return on plan assets. Other critical assumptions and estimates used in determining benefit obligations and plan expenses, including demographic factors such as retirement age, mortality, and turnover, are also evaluated periodically and updated accordingly to reflect our actual experience.

Discount rates are determined annually and are based on 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% from October 31, 2005 to October 31, 2006. 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 92% of all plans, remained flat at 5.0% from September 30, 2005 to September 30, 2006. The following table illustrates the sensitivity to changes in certain assumptions, holding all other assumptions constant, for the United Kingdom pension plans.

	Effect on
	Pension			Pension Benefit Obligation
Millions of dollars	Expense in 2006			at December 31, 2006
25-basis-point decrease in discount rate	$	14		$	187
25-basis-point increase in discount rate	$	(12	)	$	(179	)

Our defined benefit plans reduced pretax earnings by $83 million in 2006, $84 million in 2005, and $91 million in 2004. Included in the amounts were earnings from our expected pension returns of $217 million in 2006, $196 million in 2005, and $184 million in 2004. Unrecognized actuarial gains and losses were being recognized over a period of 3 to 28 years, which represented the expected remaining service life of the employee group. Our unrecognized actuarial gains and losses arose from several factors, including experience and assumptions changes in the obligations and the difference between expected returns and actual returns on plan assets. Actual returns were $318 million in 2006, $553 million in 2005, and $276 million in 2004. The difference between actual and expected

returns is deferred and recorded in other comprehensive income net of tax as actuarial gain or loss and is recognized as future pension expense. Our net actuarial loss, net of tax, at December 31, 2006 was $411 million. On a pretax basis, $43 million of our net actuarial loss at December 31, 2006 will be recognized as a component of our expected 2007 pension expense. During 2006, we made contributions to fund our defined benefit plans of $190 million, which included $174 million contributed in order to mitigate a portion of the projected underfunding of our United Kingdom plans. We expect to make additional contributions in 2007 of approximately $84 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 ARRANGEMENTS

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.

Under our Energy Services Group accounts receivable securitization facility we had the ability to sell up to $300 million in undivided ownership interest in a pool of receivables. During the fourth quarter of 2005, $256 million in undivided ownership interest that had been sold to unaffiliated companies was collected and the balance retired. No further receivables were sold, and the facility was terminated in the first quarter of 2006.

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 financial instruments.

Interest rate risk

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

The following table represents principal amounts of our long-term debt at December 31, 2006 and related weighted average interest rates on the repaid amounts by year of maturity for our long-term debt.

Millions of dollars	2007			2008			2009			2010			2011			Thereafter			Total
Fixed-rate debt:
Repayment amount ($US)	$	2		$	152		$	3		$	753		$	3		$	1,855		$	2,768
Weighted average interest
rate on repaid amount		5.5	%		5.6	%		5.5	%		5.5	%		5.5	%		4.8	%		5.0	%
Variable-rate debt:
Repayment amount ($US)	$	28		$	11		$	2		$	-		$	-		$	-		$	41
Weighted average interest
rate on repaid amount		6.6	%		8.2	%		8.6	%		-			-			-			7.2	%

The fair market value of long-term debt was $3.7 billion as of December 31, 2006.

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 $43 million as of December 31, 2006 and $50 million as of December 31, 2005. The liability covers numerous properties and no individual property accounts for more than $5 million of the liability balance. We have subsidiaries that have been named as potentially responsible parties along with other third parties for 12 federal and state superfund sites for which we have established a liability. As of December 31, 2006, those 12 sites accounted for approximately $10 million of our total $43 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

Effective January 1, 2006, we adopted the provisions of Financial Accounting Standards Board (FASB) issued SFAS No. 123 (revised 2004), “Share-Based Payment,” (SFAS No. 123(R)). SFAS No. 123(R) is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation,” (SFAS No. 123(R)) using the modified prospective application. Accordingly, we are recognizing compensation expense for all newly granted awards and awards modified, repurchased, or cancelled after January 1, 2006. Compensation cost for the unvested portion of awards that are outstanding as of January 1, 2006 is recognized ratably over the remaining vesting period based on the fair value at date of grant as calculated for our pro forma disclosure under SFAS No. 123. Also, beginning with the January 1, 2006 purchase period, compensation costs for our employee stock purchase plan are being expensed. See Note 1 to the consolidated financial statements for further information.

In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” The interpretation prescribes a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. We did not elect early adoption of this interpretation and adopted the provisions of FIN 48 beginning January 1, 2007. We have completed an initial evaluation of the impact of the January 1, 2007, adoption of FIN 48 and determined that such adoption is not expected to have a significant impact on our financial position or results from operations. We expect that any adjustment to reduce beginning-of-year retained earnings will not exceed $40 million.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158 (SFAS No. 158), “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).” SFAS No. 158 requires an employer to:

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

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

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

disclose additional information.

The requirement to recognize the funded status of a benefit plan and the additional disclosure requirements are effective for fiscal years ending after December 15, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end is effective for fiscal years ending after December 15, 2008, and we will adopt these requirements at that time. See Note 18 to the consolidated financial statements for further information.

During September 2006, the SEC issued Staff Accounting Bulletin No. 108 (SAB 108), “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statement”. SAB 108 provides guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. This interpretation was effective for the first fiscal year ending after November 15, 2006. The adoption of this interpretation did not have an impact on our financial position or results of operations.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115 (SFAS 159). SFAS 159 permits entities to measure eligible assets and liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We will adopt SFAS 159 on January 1, 2008, and have not yet determined the impact, if any, on our consolidated financial statements.

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 United States Army Europe. Our government services revenue related to Iraq totaled approximately $4.7 billion in 2006, $5.4 billion in 2005, and $7.1 billion in 2004.

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.

If we are unable to demonstrate that such action by the Army is not necessary, a 6% suspension of all subcontractor costs incurred to date could result in suspended costs of approximately $400 million. The Army has asked us to provide information that addresses the use of armed security either directly or indirectly charged to LogCAP III. The actual costs associated with these activities cannot be accurately estimated at this time. As of December 31, 2006, no amounts have been accrued for suspended security billings.

Containers. In June 2005, the DCAA recommended withholding certain costs associated with providing containerized housing for soldiers and supporting civilian personnel in Iraq. The DCAA recommended that the costs be withheld pending receipt of additional explanation or documentation to support the subcontract costs. During the fourth quarter of 2006, we resolved approximately $25 million of the $55 million withheld as of December 31, 2006 with our contracting officer and received these amounts in the first quarter of 2007. Of the approximately $55 million withheld as of December 31, 2006, $17 million had been withheld from our subcontractors. We will continue working with the government and our subcontractors to resolve the remaining amounts.

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 have been questions raised by the DCAA about the reasonableness or allowability of certain costs or the quality or quantity of supporting documentation. Recently, the DCAA has raised questions regarding $95 million of costs related to dining facilities in Iraq. We have responded to the DCAA that our costs are reasonable. The DCAA might 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

We provided information to the DoD Inspector General’s office in February 2004 about contacts between former employees and our subcontractors. In the first quarter of 2005, the United States Department of Justice (DOJ) issued two indictments associated with overbilling issues we previously reported to the Department of Defense Inspector General’s office as well as to our customer, the Army Materiel Command, against a former KBR procurement manager and a manager of La Nouvelle Trading & Contracting Company, W.L.L. In March 2006, one of these former employees pled guilty to taking money in exchange for awarding work to a Saudi Arabian subcontractor. The Inspector General’s investigation of these matters may continue.

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 Army Corps of Engineers (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 related 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.

The House Oversight and Government Reform Committee has conducted hearings on the United States military's reliance on civilian contractors, including with respect to military operations in Iraq. We have provided testimony and information for these hearings. We expect hearings with respect to operations in Iraq to continue in this and other Congressional committees, including the House Armed Services Committee, and we expect to be asked to testify and provide information for these hearings.

Claims

We had unapproved claims totaling $36 million at December 31, 2006 and $69 million at December 31, 2005 for the LogCAP and PCO Oil South contracts. The unapproved claims outstanding at December 31, 2006, are considered to be probable of collection and have been recognized as revenue. Similarly, of the $69 million of unapproved claims outstanding at December 31, 2005, $57 million were considered to be probable of collection and have been recognized as revenue. The remaining $12 million of unapproved claims were not considered probable of collection and have not been recognized as revenue. These unapproved claims related to contracts where our costs have exceeded the customer’s funded value of the task order.

In addition, as of December 31, 2006, we had incurred approximately $159 million of costs under the LogCAP III contract that could not be billed to the government due to lack of appropriate funding on various task orders. These amounts were associated with task orders that had sufficient funding in total, but the funding was not appropriately allocated within the task order. We are in the process of preparing a request for a reallocation of funding to be submitted to the client for negotiation, and we anticipate the negotiations will result in an appropriate distribution of funding by the client and collection of the full amounts due.

DCMA system reviews

Report on estimating system. In December 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 October 2005 approval letter stated that our purchasing system’s policies and practices are “effective and efficient, and provide adequate protection of the Government’s interest.” During the fourth quarter of 2006, the DCMA granted, again, continued approval of our government contract purchasing system.

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. In the fourth quarter of 2006, the DCAA finalized its report and submitted it to the DCMA, who will make a determination of the adequacy of our accounting systems for government contracting. We have prepared an action plan considering the DCAA recommendations and continue to meet with these agencies to discuss the ultimate resolution. The DCMA continues to approve KBR’s accounting system as acceptable for accumulating costs incurred under United States government contracts.

SIGIR report

In October 2006, the Special Inspector General for Iraq Reconstruction, or SIGIR, issued a report stating that we have improperly labeled reports provided to our customer, AMC, as proprietary data, when data marked does not relate to internal contractor information. We will work with AMC to address the issues raised by the SIGIR report.

Foreign Corrupt Practices Act investigations

TSKJ is a private limited liability company registered in Madeira, Portugal whose members are Technip SA of France, Snamprogetti Netherlands B.V. (a subsidiary of Saipem SpA of Italy), JGC Corporation of Japan, and Kellogg Brown & Root (a subsidiary of ours and successor to The M.W. Kellogg Company), each of which had an approximately 25% interest in the venture at December 31, 2006. TSKJ and other similarly owned entities entered into various contracts to build and expand the liquefied natural gas project for Nigeria LNG Limited, which is owned by the Nigerian National Petroleum Corporation, Shell Gas B.V., Cleag Limited (an affiliate of Total), and Agip International B.V. (an affiliate of ENI SpA of Italy). M.W. Kellogg Limited is a joint venture in which KBR had a 55% interest at December 31, 2006; and M.W. Kellogg Limited and The M.W. Kellogg Company were subsidiaries of Dresser Industries before our 1998 acquisition of Dresser Industries. The M.W. Kellogg Company was later merged with a subsidiary of ours to form Kellogg Brown & Root, one of our subsidiaries.

as a consultant and chairman of KBR, and to others, including certain of our and KBR’s current and former employees, former executive officers of KBR, and at least one subcontractor of KBR. We further understand that the DOJ has issued subpoenas for the purpose of obtaining information abroad, and we understand that other partners in TSKJ have provided information to the DOJ and the SEC with respect to the investigations, either voluntarily or under subpoenas.

amount of any fines or monetary penalties that could be assessed would depend on, among other factors, the findings regarding the amount, timing, nature, and scope of any improper payments, whether any such payments were authorized by or made with knowledge of us or our affiliates, the amount of gross pecuniary gain or loss involved, and the level of cooperation provided the government authorities during the investigations. Agreed dispositions of these types of violations also frequently result in an acknowledgement of wrongdoing by the entity and the appointment of a monitor on terms negotiated with the SEC and the DOJ to review and monitor current and future business practices, including the retention of agents, with the goal of assuring compliance with the FCPA. Other potential consequences could be significant and include suspension or debarment of our ability to contract with governmental agencies of the United States and of foreign countries. During 2006, KBR and its affiliates had revenue of approximately $5.8 billion from its government contracts work with agencies of the United States or state or local governments. In addition, we may be excluded from bidding on MoD contracts in the United Kingdom if we are convicted for a corruption offense or if the MoD determines that our actions constituted grave misconduct. During 2006, KBR had revenue of approximately $1.0 billion from its government contracts work with the MoD. Suspension or debarment from the government contracts business would have a material adverse effect on our business, results of operations, and cash flows.

As of December 31, 2006, we are unable to estimate an amount of probable loss or a range of possible loss related to these matters.

Bidding practices investigation

As of December 31, 2006, we are unable to estimate an amount of probable loss or a range of possible loss related to these matters.

Possible Algerian investigation

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 the first quarter of 2004, we responded to a follow-up letter from OFAC requesting additional information. 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 responded to the subpoena by producing documents in September 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 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 68% of our consolidated revenue during 2006 and 72% of our consolidated revenue during 2005. Based upon the location of services provided and products sold, 19% of our consolidated revenue in 2006 and 25% during 2005 was from Iraq, primarily related to our work for the United States Government. Operations in countries other than the United States are subject to various risks unique to each country. With respect to any particular country, these risks may include:

expropriation and nationalization of our assets in that country;

political and economic instability;

civil unrest, acts of terrorism, force majeure, war, or other armed conflict;

natural disasters, including those related to earthquakes and flooding;

inflation;

currency fluctuations, devaluations, and conversion restrictions;

confiscatory taxation or other adverse tax policies;

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

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

governmental activities that may result in the inability to obtain or retain licenses required for operation.

Due to the unsettled political conditions in many oil-producing countries 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, Venezuela, and Yemen. In addition, military action or continued unrest in the Middle East could impact the supply and pricing for oil and gas, disrupt our operations in the region and elsewhere, and increase our costs for security worldwide.

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

Our facilities and our employees are under threat of attack in some countries where we operate. In addition, the risks related to loss of life of our personnel and our subcontractors in these areas continue.

We are also subject to the risks that our employees, joint venture partners, and agents outside of the United States may fail to comply with applicable laws.

Military action, other armed conflicts, or terrorist attacks

Military action in Iraq, military tension involving North Korea and Iran, as well as the terrorist attacks of September 11, 2001 and subsequent terrorist attacks, threats of attacks, and unrest, have caused instability or uncertainty in the world’s financial and commercial markets and have significantly increased political and economic instability in some of the geographic areas in which we operate. Acts of terrorism and threats of armed conflicts in or around various areas in which we operate, such as the Middle East 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 or longer-term higher material and contractor prices impacting facility costs can similarly reduce or defer major expenditures given the long-term nature of many large-scale development projects. Lower levels of activity result in a corresponding decline in the demand for our oil and natural gas well services and products, which could have a material adverse effect on our revenue and profitability. Factors affecting the prices of oil and natural gas include:

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

global weather conditions and natural disasters;

worldwide political, military, and economic conditions;

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

economic growth in China and India;

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

the cost of producing and delivering oil and gas;

potential acceleration of development of alternative fuels; and

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

Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile. Spending on exploration and production activities 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.

Risk related to award of new gas monetization and upstream projects

With regard to our energy and chemical projects, worldwide resource constraints, escalating material and equipment prices, and ongoing supply chain pricing pressures are causing delays in awards of and, in some cases, cancellations of major gas monetization and upstream prospects. Certain very large scale projects that KBR has been pursuing for new awards have either been cancelled, awarded to competitors or significantly delayed. These developments may negatively and materially impact KBR’s 2007 and 2008 results on a stand alone basis (excluding consideration of potential offsets such as the slower than expected decline in LogCAP III activity, or work in other areas and overhead reductions that may or may not be realized). It is generally very difficult to predict whether or when we will receive such awards as these contracts frequently involve a lengthy and complex bidding and selection process which is affected by a number of factors, such as market conditions, financing arrangements, governmental approvals and environmental matters.

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. Our government services revenue related to Iraq under our LogCAP III and other contracts totaled approximately $4.7 billion in 2006, $5.4 billion in 2005, and $7.1 billion in 2004. We expect to complete all open task orders under our LogCAP III contract during the third quarter of 2007. In August 2006, the DoD issued a request for proposals on a new competitively bid, multiple service provider LogCAP IV contract to replace the current LogCAP III contract. We are currently the sole service provider under the LogCAP III contract and in October 2006, we submitted the final portion of our bid on the LogCAP IV contract. We expect that the contract will be awarded during the second quarter of 2007. We may not be awarded any part of the LogCAP IV contract. Despite the award of the August 2006 task order under our LogCAP III contract and the possibility of being awarded a portion of the LogCAP IV contract, we expect our overall volume of work in Iraq to decline as our customer scales back the amount of services we provide. However, as a result of the recently announced surge of additional troops in Iraq, we expect the decline to occur more slowly than previously expected;

on November 13, 2006, the MoD asked us to withdraw our initial public offering pending the MoD’s financial analysis of KBR on a stand-alone basis. The MoD also advised us that if we proceeded with our initial public offering without satisfying the MoD, the MoD would have little option but to take steps to cause the MoD to use its power to safeguard the essential security interests of the United Kingdom with respect to the Devonport Royal Dockyard. If the MoD deems it to be in the essential security interests of the United Kingdom, the MoD has the right to make DML’s interest in the Devonport Royal Dockyard non-voting and may have a right to remove DML’s directors of the Devonport Royal Dockyard, in which case DML would retain its economic interest in the Devonport Royal Dockyard, or the MoD may assume at any time control of the Devonport Royal Dockyard and dispose of DML’s interest on its behalf at fair value. In such a situation, the MoD would appoint an international firm of chartered accountants to determine the fair value for DML’s interest. In such event, there would be a risk that we may not agree with the determined value of DML’s interest in the Devonport Royal Dockyard, and it is unclear if and/or how we could challenge the determination. Any such action by the MoD would be an event of default under the DML shareholders agreement and would permit the other partners in our DML joint venture to acquire our interest in the DML joint venture at the lower of net asset value (generally a shareholder’s initial and subsequent investment and the proportionate share of consolidated capital and revenue reserves) or fair market value, which would be determined by a chartered accountant and would be final and binding absent manifest error. We believe that the net asset value of our investment in our DML joint venture may be significantly less than the fair market value of that investment. Any exercise by our partners in the DML joint venture of their rights to acquire our interest in DML would not prejudice any other rights or remedies available to them under the joint venture agreement or otherwise. Accordingly, KBR’s separation from us without satisfying the MoD, or the loss of DML’s interest in the Devonport Royal Dockyard and the loss of our interest in DML, could have a material adverse effect on our future prospects, business, results of operations and cash flow. We are engaging in discussions with the MoD regarding KBR’s ownership in DML and the possibility of reducing or disposing of our interest. Although no decision has been made with respect to a disposition or reduction of our interest in

DML, we are supporting a process to identify potential bidders that may have an interest in acquiring our interest in DML. We do not know at this time if the process will result in a disposition or reduction of our interest in DML. Revenue from our DML shipyard operations for the years ended December 31, 2006, 2005, and 2004 was $850 million, $863 million and $738 million, respectively;

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.

venture has sustained losses since commencing operations due to lower than anticipated freight volume and a slowdown in the planned expansion of the Port of Darwin. At the end of the first quarter of 2006, the joint venture’s revised financial forecast led us to record a $26 million impairment charge. In October 2006, the joint venture incurred an event of default under its loan agreement by failing to make an interest and principal payment. These loans are non-recourse to us. In light of the default, the joint venture’s need for additional financing, and the realization that the joint venture efforts to raise additional equity from third parties were not successful, we recorded an additional $32 million impairment charge in the third quarter of 2006. We will receive no tax benefit as this impairment charge is not deductible for Australian tax purposes. In December 2006, the senior lenders agreed to waive existing defaults and concede certain rights under the existing indenture. Among these were a reduction in the joint venture’s debt service reserve and the relinquishment of the right to receive principal payments for 27 months, through March 2009. In exchange for these concessions, the shareholders of the joint venture committed approximately $12 million of new subordinated financing, of which $6 million was committed by us. At December 31, 2006, our investment in this joint venture was $6 million. Our $6 million additional funding commitment was still outstanding.

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 and cost estimates. 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. For example, our Tangguh contract provides for substantial liquidated damages should the project not be completed and provisionally accepted by the client by a specified date. The current estimated construction schedule for the Tangguh project indicates that construction will be completed just prior to the date specified in the contract whereby liquidated damages will be reviewed. 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, general and third-party 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, general and third-party 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.

Our contracts generally contain provisions where our customers agree to limitations of our liability resulting from certain events such as damage to underground reservoirs and wells, costs for loss of control of a well, loss of production, damage to existing facilities, and consequential damages. It is also common to have arrangements with the customer and its other contractors that protect us against large exposures for damage to or loss of drilling units and injury to other contractors’ personnel. These contract provisions are standard in our industries, and any erosion of these contractual protections in future contracts could result in significant additional liability and associated cost.

Barracuda-Caratinga project. The Barracuda and Caratinga vessels are both fully operational. In April 2006, we executed an agreement with Petrobras that enabled 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 but do not address the bolt arbitration discussed below.

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 various 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 for our costs incurred. Petrobras could, however, perform any replacement of the bolts and seek reimbursement from KBR. In March 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 all related costs and expenses of the arbitration, including the cost of attorneys fees. We disagree with the Petrobras claim because the bolts met Petrobras’ design specification, and we do not believe there is any 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. The arbitration hearing is not expected to begin until the first quarter of 2008. We agreed to indemnify KBR under the master separation agreement for all out-of-pocket cash costs and expenses, or cash settlements or cash arbitration awards in lieu thereof, KBR may incur after November 20, 2006 as a result of the replacement of the subsea flowline bolts. See Note 3 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 flow.

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

Raw materials essential to our business are normally readily available. Current market conditions have triggered constraints in the supply chain of certain raw materials, such as, sand, cement, and specialty metals. The majority of our risk associated with the current supply chain constraints occurs in those situations where we have a relationship with a single supplier for a particular resource.

Intellectual property rights

We rely on a variety of intellectual property rights that we use in our services and products. We may not be able to successfully preserve these intellectual property rights in the future, and these rights could be invalidated, circumvented, or challenged. In addition, the laws of some foreign countries in which our services and products may be sold do not protect intellectual property rights to the same extent as the laws of the United States. Our failure to protect our proprietary information and any successful intellectual property challenges or infringement proceedings against us could materially and adversely affect our competitive position.

Technology

The market for our services and products is characterized by continual technological developments to provide better and more reliable performance and services. If we are not able to design, develop, and produce commercially competitive products and to implement commercially competitive services in a timely manner in response to changes in technology, our business and revenue could be materially and adversely affected, and the value of our intellectual property may be reduced. Likewise, if our proprietary technologies, equipment and facilities, or work processes become obsolete, we may no longer be competitive, and our business and revenue could be materially and adversely affected.

Systems

Our business could be materially and adversely affected by problems encountered in the installation of a new SAP financial system to replace some of 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 and project work sites;

inability to deliver materials to jobsites in accordance with contract schedules; and

loss of productivity.

Because demand for natural gas in the United States drives a significant amount of our 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.

Other KBR risks

Credit matters. Some customers may require KBR to provide credit enhancements, including bonds, letters of credit or performance or financial guarantees. In line with industry practice, KBR is often required to provide performance and surety bonds to customers. These bonds indemnify the customer should KBR fail to perform their obligations under the contract. KBR has minimal stand-alone bonding capacity and other credit support capacity without Halliburton and, except to the limited extent set forth in the master separation agreement, Halliburton is not obligated to provide credit support. KBR is engaged in discussions with surety companies to obtain additional stand-alone bonding capacity, but they may not be successful. If a bond is required for a particular project and KBR is unable to obtain an appropriate bond, they cannot pursue that project. Moreover, due to events that affect the insurance and bonding markets generally, bonding may be difficult to obtain or may only be available at significant cost. Because of liquidity or other issues, KBR could at times be unable to provide necessary letters of credit. In addition, future projects may require KBR to obtain letters of credit that extend beyond the term of their current credit facility. Further, KBR’s credit facility limits the amount of new letters of credit and other debt they can incur outside of the credit facility to $250 million, which could adversely affect their ability to bid or bid competitively on future projects if the credit facility is not amended or replaced. Prior to KBR, Inc.’s initial public offering, Halliburton has provided guarantees of most of KBR’s surety bonds and letters of credit as well as most other payment and performance guarantees under their contracts. The credit support arrangements in existence at the completion of KBR, Inc.’s initial public offering will remain in effect, but Halliburton is not expected to enter into any new credit support arrangements on KBR’s behalf, except to the limited extent Halliburton is obligated to do so under the master separation agreement. KBR has agreed to indemnify Halliburton for all losses under KBR’s outstanding credit support instruments and any additional credit support instruments for which Halliburton may become obligated following our initial public offering, and under the master separation agreement. KBR has agreed to use their reasonable best efforts to attempt to release or replace Halliburton’s liability thereunder for which such release or replacement is reasonably available. Any inability by KBR to obtain adequate bonding and/or provide letters of credit or other customary credit enhancements and, as a result, to bid on new work could have a material adverse effect on our business prospects and future revenue.

KBR does not expect that Halliburton will provide, and Halliburton has not provided, payment and performance guarantees of KBR’s bonds, letters of credit and contracts entered into after our initial public offering as Halliburton has in the past, except to the extent Halliburton has agreed to do so under the terms of the master separation agreement. KBR’s customers and prospective customers will need assurances that KBR’s financial stability on a stand-alone basis is sufficient to satisfy their requirements for doing or continuing to do business with them. If KBR’s customers or prospective customers are not satisfied with KBR’s financial stability absent the support from Halliburton that KBR has relied on in the past, it could have a material adverse effect on KBR’s ability to bid for and obtain or retain projects, our business prospects and future revenues.

Prior to KBR, Inc.’s initial public offering, they relied upon Halliburton to fund KBR’s working capital demands and assist KBR in meeting their liquidity needs, thereby providing KBR with a reliable source of cash, liquidity and credit support enhancements even in unusual or unexpected circumstances. KBR is no longer able to

rely on Halliburton to meet future needs, except to the extent of credit support instruments outstanding at the completion of KBR, Inc.’s initial public offering and to the limited extent Halliburton has agreed to provide additional guarantees, indemnification and reimbursement commitments for KBR’s benefit in connection with letters of credit, surety bonds and performance guarantees related to certain of KBR’s existing project contracts as provided for in the master separation agreement. KBR has obtained limited surety capacity and is currently engaged in discussions with surety companies to obtain stand-alone bonding capacity without Halliburton or other credit support. KBR’s efforts to obtain this stand-alone bonding capacity may not be successful. KBR can provide no assurance that they will have sufficient working capital or surety support to allow them to secure large-scale contracts or satisfy contract performance specifications.

In December 2005, KBR entered into a five-year, unsecured revolving credit facility that provides up to $850 million of borrowings and letters of credit. This facility serves to assist KBR in providing working capital and letters of credit for their projects. The revolving credit facility contains a number of covenants restricting, among other things, incurrence of additional indebtedness and liens, sales of KBR assets, the amount of investments KBR can make, and dividends. KBR is also subject to certain financial covenants, including maintenance of ratios with respect to consolidated debt to total consolidated capitalization, leverage and fixed charge coverage. If KBR fails to meet the covenants or an event of default occurs, they would not have available the liquidity that the facility provides. In addition, under KBR’s existing revolving credit facility, and potentially under any future credit facility, KBR will be required to incur increased lending fees, costs and interest rates and, if future borrowings were to occur, to dedicate a substantial portion of their cash flow from operations to the repayment of debt and the interest associated with that debt.

Pension matters. Under regulations applicable to pension plans maintained for the benefit of KBR’s employees in the United Kingdom, a disposition of KBR, Inc.’s common stock by Halliburton could constitute an event for which it would be advisable to obtain clearance from the Pensions Regulator in the United Kingdom if it were determined to be a change of control that is financially detrimental to the ability of a United Kingdom pension plan to meet its funding liabilities. In such event, should KBR fail to obtain clearance, the Pensions Regulator could issue a contribution notice, which could impose liability on an employer of an amount equal to the cost of securing all of the pension plan beneficiaries’ benefits by the purchase of annuities. As an alternative to obtaining clearance from the Pensions Regulator, KBR could agree with the trustee of some or all of the pension plans to provide additional security to the plans satisfactory to such trustees, which would not provide the same certainty as obtaining clearance, but may reduce the risk of receiving a contribution notice from the Pensions Regulator. While no determination has been made at this time as to the action, if any, that would be taken, if clearance were sought from the Pensions Regulator or an agreement was negotiated with the trustees for the United Kingdom pension plans, it may be necessary to fund some or all of the deficits under the United Kingdom pension plans, either in a lump sum or over an agreed period. Because the funding status of KBR’s United Kingdom pension plans is dependent on future events and circumstances and actuarial assumptions, we cannot estimate the range of exposure at this time.

Separation matters. Halliburton currently assists KBR in performing various corporate functions, including the following:

information technology and communications;

human resource services such as payroll and benefit plan administration;

legal;

tax;

accounting;

office space and office support;

risk management;

treasury and corporate finance; and

investor services, investor relations and corporate communications.

Following KBR’s anticipated complete separation from Halliburton, Halliburton will have no obligation to provide these functions to KBR other than the interim services that will be provided by Halliburton under a transition services agreement. Also, after the termination of this agreement, KBR may not be able to replace the transition services in a timely manner or on terms and conditions, including costs, as favorable as those KBR receives from Halliburton.

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, 2006 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, 2006, our internal control over financial reporting is effective.

Our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 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, 2006 and 2005, 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, 2006. 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, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

As discussed in Notes 1 and 18, respectively, to the consolidated financial statements, the Company changed its method of accounting for stock-based compensation plans as of January 1, 2006, and its method of accounting for defined benefit and other postretirement plans as of December 31, 2006.

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, 2006, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 26, 2007

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, 2006, 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, 2006, 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, 2006, 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, 2006 and 2005, 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, 2006, and our report dated February 26, 2007 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

February 26, 2007

HALLIBURTON COMPANY

Consolidated Statements of Operations

	Years ended December 31
Millions of dollars and shares except per share data	2006			2005			2004
Revenue:
Services	$	19,192		$	17,679		$	17,747
Product sales		3,312			2,587			2,137
Equity in earnings (losses) of unconsolidated affiliates, net		72			(26	)		(6	)
Total revenue		22,576			20,240			19,878
Operating costs and expenses:
Cost of services		16,031			15,308			16,870
Cost of sales		2,675			2,129			1,882
General and administrative		450			380			361
Gain on sale of business assets, net		(64	)		(194	)		(55	)
Total operating costs and expenses		19,092			17,623			19,058
Operating income		3,484			2,617			820
Interest expense		(175	)		(207	)		(229	)
Interest income		162			64			44
Foreign currency losses, net		(22	)		(13	)		(3	)
Other, net		-			(14	)		2
Income from continuing operations before income taxes and
minority interest		3,449			2,447			634
Provision for income taxes		(1,144	)		(64	)		(235	)
Minority interest in net income of subsidiaries		(33	)		(56	)		(25	)
Income from continuing operations		2,272			2,327			374
Income (loss) from discontinued operations, net of tax (provision) benefit
of $(42), $(16), and $174		76			31			(1,353	)
Net income (loss)	$	2,348		$	2,358		$	(979	)

Basic income (loss) per share:
Income from continuing operations	$	2.24		$	2.31		$	0.43
Income (loss) from discontinued operations, net		0.07			0.03			(1.55	)
Net income (loss) per share	$	2.31		$	2.34		$	(1.12	)

Diluted income (loss) per share:
Income from continuing operations	$	2.16		$	2.24		$	0.42
Income (loss) from discontinued operations, net		0.07			0.03			(1.53	)
Net income (loss) per share	$	2.23		$	2.27		$	(1.11	)

Basic weighted average common shares outstanding		1,014			1,010			874
Diluted weighted average common shares outstanding		1,054			1,038			882

See notes to consolidated financial statements.

HALLIBURTON COMPANY

Consolidated Balance Sheets

	December 31
Millions of dollars and shares except per share data	2006			2005
Assets
Current assets:
Cash and equivalents	$	4,379		$	2,391
Receivables:
Notes and accounts receivable (less allowance for bad debts of $97 and $90)		3,451			3,345
Unbilled work on uncompleted contracts		1,223			1,456
Total receivables		4,674			4,801
Inventories		1,261			953
Current deferred income taxes		319			719
Other current assets		550			522
Total current assets		11,183			9,386
Property, plant, and equipment, net of accumulated depreciation of $4,154 and $3,838		3,048			2,648
Noncurrent deferred income taxes		603			748
Goodwill		775			765
Equity in and advances to related companies		397			382
Other assets		814			1,119
Total assets	$	16,820		$	15,048
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	1,931		$	1,967
Advanced billings on uncompleted contracts		903			661
Accrued employee compensation and benefits		764			648
Current maturities of long-term debt		45			361
Other current liabilities		1,084			790
Total current liabilities		4,727			4,427
Long-term debt		2,786			2,813
Employee compensation and benefits		887			718
Other liabilities		597			573
Total liabilities		8,997			8,531
Minority interest in consolidated subsidiaries		447			145
Shareholders’ equity:
Common shares, par value $2.50 per share - authorized 2,000 shares, issued 1,060 and 1,054 shares		2,650			2,634
Paid-in capital in excess of par value		1,689			1,501
Deferred compensation		-			(98	)
Accumulated other comprehensive income		(437	)		(266	)
Retained earnings		5,051			2,975
		8,953			6,746
Less 62 and 26 shares of treasury stock, at cost		1,577			374
Total shareholders’ equity		7,376			6,372
Total liabilities and shareholders’ equity	$	16,820		$	15,048

See notes to consolidated financial statements.

HALLIBURTON COMPANY

Consolidated Statements of Shareholders’ Equity

Millions of dollars and shares	2006			2005			2004
Balance at January 1	$	6,372		$	3,932		$	2,547
Dividends and other transactions with shareholders		(1	)		202			(123	)
Common share repurchase program		(1,323	)		-			-
Sale of stock by a subsidiary		117			-			-
Common shares to be contributed to asbestos
trust - 119 shares		-			-			2,335
Adoption of SFAS 158		(218	)		-			-
Other		34			-			-

Comprehensive income (loss):
Net income (loss)		2,348			2,358			(979	)

Cumulative translation adjustments		48			(48	)		33
Realization of (gains) losses included in net
income (loss)		(14	)		7			(1	)
Net cumulative translation adjustments		34			(41	)		32

Pension liability adjustments		2			(54	)		115

Unrealized gains (losses) on investments and
derivatives		12			(12	)		5
Realization of gains on investments and
derivatives		(1	)		(13	)		-
Net unrealized gains (losses) on investments
and derivatives		11			(25	)		5

Total comprehensive income (loss)		2,395			2,238			(827	)

Balance at December 31	$	7,376		$	6,372		$	3,932

See notes to consolidated financial statements.

HALLIBURTON COMPANY

Consolidated Statements of Cash Flows

	Years ended December 31
Millions of dollars	2006			2005			2004
Cash flows from operating activities:
Net income (loss)	$	2,348		$	2,358		$	(979	)
Adjustments to reconcile net income (loss) to net cash from operations:
(Income) loss from discontinued operations		10			(1	)		1,364
Depreciation, depletion, and amortization		527			504			509
Provision (benefit) for deferred income taxes, including $21, $0, and $(167) related to discontinued operations		682			(235	)		(176	)
Distributions from (advances to) related companies, net of equity in (earnings) losses		(77	)		39			(39	)
Gain on sale of assets		(123	)		(192	)		(62	)
Asbestos and silica liability payment related to Chapter 11 filing		-			(2,345	)		(119	)
Collection of asbestos- and silica-related insurance receivables		167			1,032			-
Other changes:
Receivables and unbilled work on uncompleted contracts		19			423			(506	)
Accounts receivable facilities transactions		-			(519	)		519
Inventories		(308	)		(152	)		(33	)
Accounts payable		(91	)		(317	)		439
Reserve for loss on contracts		133			(97	)		(77	)
Accrued employee benefits		121			184			73
Contributions to pension plans		(190	)		(81	)		(85	)
Advanced billings		209			113			(209	)
Other		230			(13	)		309
Total cash flows from operating activities		3,657			701			928
Cash flows from investing activities:
Capital expenditures		(891	)		(651	)		(575	)
Sales of property, plant, and equipment		158			132			166
Dispositions of business assets, net of cash disposed		374			299			127
Acquisitions of business assets, net of cash acquired		(27	)		(108	)		(25	)
Proceeds from sales of securities		10			15			22
Sales (purchases) of short-term investments in marketable securities, net		(20	)		891			(180	)
Investments - restricted cash		-			1			89
Other investing activities		(30	)		(69	)		(30	)
Total cash flows from investing activities		(426	)		510			(406	)
Cash flows from financing activities:
Proceeds from the sale of KBR, Inc. common stock, net of offering costs		508			-			-
Proceeds from long-term debt, net of offering costs		8			24			496
Proceeds from exercises of stock options		159			342			63
Payments to reacquire common stock		(1,339	)		(12	)		(7	)
Borrowings (repayments) of short-term debt, net		(16	)		10			(7	)
Payments on long-term debt		(349	)		(823	)		(20	)
Payments of dividends to shareholders		(306	)		(254	)		(221	)
Tax benefit from exercise of options and restricted stock		53			-			-
Other financing activities		2			(7	)		(21	)
Total cash flows from financing activities		(1,280	)		(720	)		283
Effect of exchange rate changes on cash		37			(17	)		8
Increase in cash and equivalents		1,988			474			813
Cash and equivalents at beginning of year		2,391			1,917			1,104
Cash and equivalents at end of year	$	4,379		$	2,391		$	1,917
Supplemental disclosure of cash flow information:
Cash payments during the year for:
Interest	$	175		$	210		$	211
Income taxes	$	345		$	282		$	265

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. Our six business segments are: Production Optimization, Fluid Systems, Drilling and Formation Evaluation, and Digital and Consulting Solutions, collectively, the Energy Services Group (ESG); and Energy and Chemicals and Government and Infrastructure, 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.

Common share and earnings per share amounts have been restated for all periods presented to reflect the increased number of common shares outstanding resulting from the two-for-one common stock split, in the form of a stock dividend, paid on July 14, 2006 to shareholders of record as of June 23, 2006.

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 revenue, 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. Physical percent complete is determined as a combination of input and output measures as deemed appropriate by the circumstances. All known or anticipated losses on contracts are provided for when they become evident. 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.

Sale of stock by a subsidiary

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

Research and development

Research and development expenses are charged to income as incurred. Research and development expenses were $256 million in 2006, $220 million in 2005, and $234 million in 2004, 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 2006, $21 million in 2005, and $16 million in 2004. Amortization expense of software development costs was $21 million for 2006 and $22 million for both 2005 and 2004. 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.

Halliburton stock-based compensation

Effective January 1, 2006, we adopted the fair value recognition provisions of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123(R)), using the modified prospective application. Accordingly, we are recognizing compensation expense for all newly granted awards and awards modified, repurchased, or cancelled after January 1, 2006. Compensation cost for the unvested portion of awards that were outstanding as of January 1, 2006 is being recognized ratably over the remaining vesting period based on the fair value at date of grant. Also, beginning with the January 1, 2006 purchase period, compensation expense for our 2002 Employee Stock Purchase Plan (ESPP) is being recognized. The cumulative effect of this change in accounting principle related to stock-based awards was immaterial. Prior to January 1, 2006, we accounted for these plans under the recognition and measurement provisions of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Under APB No. 25, no compensation expense was recognized for stock options or the ESPP. Compensation expense was recognized for restricted stock awards. As a result of adopting SFAS No. 123(R), the incremental pretax expense related to employee stock option awards and our ESPP totaled approximately $41 million in 2006, or $0.02 per diluted share after tax.

Total stock-based compensation expense, net of related tax effects, was $60 million in 2006. Total income tax benefit recognized in net income for stock-based compensation arrangements was $33 million in 2006, $17 million in 2005, and $9 million in 2004. Total incremental compensation cost resulting from modifications of previously granted stock-based awards was $16 million in 2006, $19 million in 2005, and $12 million in 2004. These modifications allowed certain employees to retain their awards after leaving the company.

The following table summarizes the pro forma effect on net income (loss) and income (loss) per share for 2005 and 2004 as if we had applied the fair value recognition provisions of 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
Net income (loss), as reported	$	2,358		$	(979	)
Add: Total stock-based compensation expense included
in net income, net of related tax effects		31			16
Less: Total stock-based compensation expense
determined under fair-value-based method for all
awards, net of related tax effects		(61	)		(44	)
Net income (loss), pro forma	$	2,328		$	(1,007	)

Basic income (loss) per share:
As reported	$	2.34		$	(1.12	)
Pro forma	$	2.31		$	(1.16	)
Diluted income (loss) per share:
As reported	$	2.27		$	(1.11	)
Pro forma	$	2.25		$	(1.14	)

The fair value of options at the date of grant was estimated using the Black-Scholes option pricing model. The expected volatility of options granted in 2006 was a blended rate based upon implied volatility calculated on actively traded options on our common stock and upon the historical volatility of our common stock. The expected volatility of options granted in 2005 and 2004 was based upon the historical volatility of our common stock. The expected term of options granted in 2006, 2005, and 2004 was based upon historical observation of actual time elapsed between date of grant and exercise of options for all employees. The assumptions and resulting fair values of options granted were as follows:

	Years ended December 31
	2006			2005			2004
Expected term (in years)		5.24			5.00			5.00
Expected volatility		42.20	%		51.06 - 52.79	%		54.30 - 57.47	%
Expected dividend yield		0.76 - 1.06	%		0.73 - 1.16	%		1.27 - 1.65	%
Risk-free interest rate		4.30 - 5.03	%		3.77 - 4.33	%		2.71 - 3.89	%
Weighted average grant-date fair value per share	$	14.20		$	11.42		$	6.69

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

	Offering period July 1 through December 31
	2006			2005			2004
Expected term (in years)		0.5			0.5			0.5
Expected volatility		37.77	%		30.46	%		55.50	%
Expected dividend yield		0.80	%		0.73	%		1.48	%
Risk-free interest rate		5.29	%		3.89	%		3.29	%
Weighted average grant-date fair value per share	$	9.32		$	5.50		$	4.31

	Offering period January 1 through June 30
	2006			2005			2004
Expected term (in years)		0.5			0.5			0.5
Expected volatility		35.65	%		26.93	%		57.47
Expected dividend yield		0.75	%		1.16	%		1.65
Risk-free interest rate		4.38	%		3.15	%		2.71
Weighted average grant-date fair value per share	$	7.91		$	4.15		$	3.74

KBR, Inc. stock-based compensation

For KBR, Inc. options granted in 2006, the fair value of options at the date of grant was estimated using the Black-Scholes option pricing model. The expected volatility of KBR, Inc. options granted in 2006 is based upon a blended rate that uses the historical and implied volatility of common stock for selected peers. The expected term of KBR, Inc. options granted in 2006 is based upon the average of the life of the option and the vesting period of the option. The assumptions and resulting fair values of options granted were as follows:

	2006
Expected term (in years)		6
Expected volatility		35.0	%
Expected dividend yield		0.0	%
Risk-free interest rate		4.6	%
Weighted average grant-date fair value per share	$	9.34

The KBR, Inc. stock-based compensation expense relating to restricted stock and stock option awards under the KBR, Inc. 2006 Stock and Incentive Plan was immaterial.

See Note 15 for further detail on stock incentive plans.

Note 2. KBR, Inc. Initial Public Offering

Our Energy and Chemicals and Government and Infrastructure segments are part of KBR, Inc. (KBR), which was formed in March 2006. In November 2006, KBR, Inc. completed an initial public offering (IPO), in which it sold approximately 32 million shares of KBR, Inc. common stock, at $17.00 per share. We received proceeds of approximately $508 million from the IPO, net of underwriting discounts and commissions and offering expenses. As the IPO was a result of a broader corporate reorganization, the increase in the carrying amount of our investment in KBR, Inc. was recorded in “Paid-in capital in excess of par value” in our consolidated balance sheet as of December 31, 2006. We now hold an approximate 81% interest in KBR, Inc., which we consolidate for financial reporting purposes, represented by 135.6 million shares of KBR, Inc. common stock.

We have entered into various agreements relating to the separation of KBR from us, including, among others, a master separation agreement, a registration rights agreement, a tax sharing agreement, transition services agreements, and an employee matters agreement. The master separation agreement provides for, among other things, KBR’s responsibility for liabilities related to its business and Halliburton’s responsibility for liabilities unrelated to KBR’s business. Halliburton provided indemnification in favor of KBR under the master separation agreement for contingent liabilities, including Halliburton’s indemnification of KBR and any of its greater than 50%-owned subsidiaries as of November 20, 2006, the date of the master separation agreement, for:

fines or other monetary penalties or direct monetary damages, including disgorgement, as a result of a claim made or assessed by a governmental authority in the United States, the United Kingdom, France, Nigeria, Switzerland and/or Algeria, or a settlement thereof, related to alleged or actual violations occurring prior to November 20, 2006 of the United States Foreign Corrupt Practices Act (FCPA) or particular, analogous applicable foreign statutes, laws, rules, and regulations in connection with current investigations, including with respect to the construction and subsequent expansion by TSKJ of a natural gas liquefaction complex and related facilities at Bonny Island in Rivers State, Nigeria; and

In conjunction with the closing of the KBR, Inc. IPO, KBR, Inc. granted stock options, restricted stock, and restricted stock unit awards under the KBR, Inc. 2006 Stock and Incentive Plan. See Note 15 for further detail on KBR, Inc. stock incentive plans.

We are now working toward the separation of KBR, Inc. which we expect to complete no later than the end of April 2007.

Note 3. 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 value, 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 in total estimated contract value 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	2006		2005		2004
Probable unapproved claims	$	189	$	175	$	182
Probable unapproved claims accrued revenue		187		172		182
Probable unapproved claims from unconsolidated related companies		78		92		51

As of December 31, 2006, the probable unapproved claims, including those from unconsolidated related companies relate to eight contracts, most of which are complete or substantially complete. See Note 12 for a discussion of United States government contract claims, which are not included in the table above.

A significant portion of the probable unapproved claims as of December 31, 2006 ($148 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, 2006, 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 $175 million at December 31, 2006 and $172 million at December 31, 2005 included in the table above, which are reflected as “Other assets” on the consolidated balance sheets. The remaining $12 million at December 31, 2006 is included in “Unbilled work on uncompleted contracts” since the contracts are expected to be settled within one year. 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 $81 million at December 31, 2006. Unapproved change orders at December 31, 2005 were $61 million. Our share of change orders from unconsolidated related companies totaled $3 million at December 31, 2006 and $5 million at December 31, 2005.

In the second quarter of 2006, we identified a $148 million charge, before income taxes and minority interest, related to KBR’s consolidated 50%-owned GTL project in Escravos, Nigeria. This charge was primarily attributable to increases in the overall estimated cost to complete the project. The project, which was awarded in April 2005, has experienced delays relating to civil unrest and security on the Escravos River, near the project site. Further delays have resulted from scope changes, engineering and construction modifications due to necessary front-end engineering design changes and increases in procurement costs due to project delays. As of September 30, 2006, we had approximately $269 million in unapproved change orders related to this project. In the fourth quarter of 2006, we reached agreement with the project owner to settle $264 million of these change orders. As a result, portions of the remaining work now have a lower risk profile, particularly with respect to security and logistics. Since we completed our first check estimate in the second quarter of 2006, the project has continued to estimate significant additional cost increases. We currently expect to recover these recently identified cost increases through change orders. As of December 31, 2006, we have recorded $43 million of unapproved change orders which primarily relate to these cost increases. Because of the civil unrest and security issues that currently exist in Nigeria, uncertainty regarding soil conditions at the property site and other matters, we could experience substantial additional cost increases on the Escravos project in the future. We believe that future cost increases attributed to civil unrest, security matters and potential differences in actual rather than anticipated soil conditions should ultimately be recoverable through future change orders pursuant to the terms of our contract as amended in 2006. However, should this occur, there could be timing differences between the recognition of cost and recognition of offsetting potential recoveries from our client, if any. We recorded an additional $9 million loss in the fourth quarter of 2006 related to non-billable engineering services for the Escravos joint venture. These services were in excess of the contractual limit of total engineering costs each partner can bill to the joint venture.

Barracuda-Caratinga project

Following is the status, as of December 31, 2006, of our Barracuda-Caratinga project, a multiyear construction project to develop the Barracuda and Caratinga crude oilfields located off the coast of Brazil:

the Barracuda and Caratinga vessels are both fully operational. In April 2006, we executed an agreement with Petrobras that enabled 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 but do not address the bolt arbitration discussed below;

in the first quarter of 2006, we recorded a loss of $15 million related to additional costs to finalize the project and warranty matters. We have recorded inception-to-date losses on this project of approximately $785 million; and

our remaining obligation under the April 2006 agreement is primarily for warranty on the two vessels.

In addition, at Petrobras’ direction, we have replaced certain bolts located on the subsea flowlines that failed through mid-November 2005, and we understand that additional bolts have failed thereafter, which were replaced by Petrobras. These failed bolts were identified by Petrobras when it conducted inspections of the bolts. 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 various 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 for our costs incurred. Petrobras could, however, perform any replacement of the bolts and seek reimbursement from KBR. In March 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 all related costs and expenses of the arbitration, including the cost of attorneys fees. We disagree with the Petrobras claim because the bolts met Petrobras’ design specification, and we do not believe there is any 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. The arbitration hearing is not expected to begin until the first quarter of 2008. We agreed to indemnify KBR under the master separation agreement for all out-of-pocket cash costs and expenses, or cash settlements or cash arbitration awards in lieu thereof, KBR may incur after November 20, 2006 as a result of the replacement of the subsea flowline bolts. As of December 31, 2006, we have not accrued any amounts related to this arbitration.

Note 4. Acquisitions and Dispositions

Ultraline Services Corporation

In January 2007, we acquired all intellectual property, current assets, and existing business associated with Calgary-based Ultraline Services Corporation, a division of Savanna Energy Services Corp. Ultraline is a provider of wireline services in Canada. We paid approximately $177 million, subject to adjustment for working capital purposes. Ultraline will be included in our Drilling and Formation Evaluation segment.

Production Services

In the second quarter of 2006, we completed the sale of KBR’s Production Services group, which was part of our Energy and Chemicals segment. In connection with the sale, we received net proceeds of $265 million. The sale of Production Services resulted in an adjusted pretax gain, net of post-closing adjustments, of $120 million, which is reflected in discontinued operations. Production Services operations and assets and liabilities are classified as discontinued operations for all periods presented. At December 31, 2005, Production Services assets were $207 million, of which $140 million were classified as current, and liabilities were $64 million, of which $54 million were classified as current.

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, KBR sold its 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.

Note 5. Business Segment Information

We have six business segments: Production Optimization, Fluid Systems, Drilling and Formation Evaluation, Digital and Consulting Solutions, Energy and Chemicals, and Government and Infrastructure. The segments mirror the way our chief operating decision maker regularly reviews the operating results, assesses performance, and allocates resources.

During the second quarter of 2006, we moved slickline services, tubing conveyed perforating, and underbalanced applications from the Production Optimization segment to the Drilling and Formation Evaluation segment, as these services are more closely aligned with the Drilling and Formation Evaluation segment. Prior period balances were reclassified to reflect this change. Because of this change, what we previously referred to as “logging services” within the Drilling and Formation Evaluation segment we now refer to as “wireline and perforating services.” In addition, for internal management purposes we combined our Drilling and Formation Evaluation and Digital and Consulting Solutions divisions, resulting in three Energy Services Group internal divisions. However, we continue to disclose four segments for the Energy Services Group.

KBR’s Production Services operations were moved into discontinued operations for reporting purposes in the first quarter of 2006. All prior period amounts were reclassified to discontinued operations.

Energy Services Group

Following is a summary of our Energy Services Group segments.

Production Optimization. The Production Optimization segment provides products and services for completion of wells, testing and monitoring performance of wells and reservoirs, and treatments to improve well productivity and increase recoverable reserves. This segment consists of production enhancement services and completion tools and services.

Until January 2005 when it was sold, subsea operations conducted by Subsea 7, Inc., of which we formerly owned 50%, were included in this segment. Subsea 7, Inc. was accounted for by 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 and Baroid Fluid Services.

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

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

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, Security DBS Drill Bits, and wireline and perforating services.

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

Security DBS Drill Bits provide 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.

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

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. Management focuses on major projects within its two reportable segments, Energy and Chemicals and Government and Infrastructure. The nature of these two segments can result in a relatively small number of projects and joint ventures representing a substantial portion of operations. Following is a summary of our KBR segments.

Energy and Chemicals. The Energy and Chemicals segment designs and constructs energy and petrochemical projects, including large, technically complex projects in remote locations around the world. Our expertise includes onshore and offshore oil and gas production facilities (including platforms, floating production and subsea facilities), onshore and offshore pipelines, LNG and GTL gas monetization facilities, refineries, and petrochemical plants and Syngas. We provide a complete range of engineering, procurement, construction, and commissioning start-up (EPC-CS) services, as well as program and project management, consulting, and technology services.

TSKJ is a joint venture formed to design and construct large-scale projects in Nigeria. TSKJ’s members are Technip, SA of France, Snamprogetti Netherlands B.V., which is a subsidiary of Saipem SpA of Italy, JGC Corporation of Japan, and us, each of which has a 25% ownership interest. 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 using the equity method of accounting.

M.W. Kellogg Limited (MWKL) is a London-based joint venture that provides full EPC-CS related 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 accounting purposes.

Government and Infrastructure. The Government and Infrastructure segment delivers on-demand support services across the full military cycle from contingency logistics and field support to operations and maintenance on military bases. The civil infrastructure market operates in diverse sectors, including transportation, waste and water treatment, and facilities maintenance. It provides program and project management, contingency logistics, operations and maintenance, construction management, engineering, and other services to military and civilian branches of governments and private clients worldwide. KBR is the majority owner of DML, which owns and operates Devonport Royal Dockyard, Western Europe’s largest naval dockyard complex. We consolidate DML for financial accounting purposes.

In addition, this segment includes the Alice-Springs-Darwin railroad. The Alice Springs-Darwin railroad is a privately financed project that was formed in 2001 to build, operate and own transcontinental railroad from Alice Springs to Darwin. Australia was granted a 50-year concession period by the Australian government. Government and Infrastructure provides engineering, procurement, and construction (EPC) services for the project and are 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 using the equity method of accounting.

Also included in this segment is Aspire Defence/Allenby-Connaught a joint venture between us, Mowlem Plc. and a financial investor formed to contract with the MoD to upgrade and service certain United Kingdom military facilities. In addition to a package of ongoing services to be delivered over 35 years, the project includes a nine-year construction program. KBR indirectly owns a 45% interest in Aspire Defence, the project company that is the holder of the 35-year concession contract. In addition, KBR owns a 50% interest in each of the two joint ventures that provide the construction and related support services to Aspire Defence. We account for this investment using the equity method of accounting.

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 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 $5.8 billion or 26% of consolidated revenue in 2006, $6.6 billion or 32% of consolidated revenue in 2005, and $8.0 billion or 40% of consolidated revenue in 2004. 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	2006			2005			2004
Revenue:
Production Optimization	$	5,360		$	3,990		$	3,047
Fluid Systems		3,598			2,838			2,324
Drilling and Formation Evaluation		3,221			2,552			2,038
Digital and Consulting Solutions		776			720			589
Total Energy Services Group		12,955			10,100			7,998
Energy and Chemicals		2,373			2,008			2,490
Government and Infrastructure		7,248			8,132			9,390
Total KBR		9,621			10,140			11,880
Total	$	22,576		$	20,240		$	19,878
Operating income (loss):
Production Optimization	$	1,530		$	1,053		$	588
Fluid Systems		795			544			348
Drilling and Formation Evaluation		818			536			270
Digital and Consulting Solutions		240			146			60
Total Energy Services Group		3,383			2,279			1,266
Energy and Chemicals		37			124			(443	)
Government and Infrastructure		202			329			84
Total KBR		239			453			(359	)
General corporate		(138	)		(115	)		(87	)
Total	$	3,484		$	2,617		$	820
Capital expenditures:
Production Optimization	$	324		$	245		$	203
Fluid Systems		175			94			74
Drilling and Formation Evaluation		313			210			189
Digital and Consulting Solutions		19			26			32
Total Energy Services Group		831			575			498
Energy and Chemicals		12			4			9
Government and Infrastructure		18			33			41
Shared KBR		27			39			27
Total KBR		57			76			77
General corporate		3			-			-
Total	$	891		$	651		$	575

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	2006		2005		2004
Depreciation, depletion, and amortization:
Production Optimization	$	180	$	158	$	153
Fluid Systems		86		88		83
Drilling and Formation Evaluation		165		138		145
Digital and Consulting Solutions		49		64		75
Total Energy Services Group		480		448		456
Energy and Chemicals		7		9		11
Government and Infrastructure		22		32		27
Shared KBR		18		15		15
Total KBR		47		56		53
Total	$	527	$	504	$	509
Total assets:
Production Optimization	$	2,812	$	2,349	$	1,945
Fluid Systems		1,834		1,438		1,230
Drilling and Formation Evaluation		1,854		1,445		1,221
Digital and Consulting Solutions		726		803		768
Shared energy services		1,216		494		452
Total Energy Services Group		8,442		6,529		5,616
Energy and Chemicals		1,906		1,967		1,709
Government and Infrastructure		2,071		2,643		3,261
Shared KBR		1,330		318		193
Total KBR		5,307		4,928		5,163
General corporate		3,071		3,591		5,085
Total	$	16,820	$	15,048	$	15,864

*Operations by geographic area*
	Years ended December 31
Millions of dollars	2006		2005		2004
Revenue:
United States	$	7,216	$	5,590	$	4,395
Iraq		4,331		5,116		5,362
United Kingdom		1,594		1,440		1,239
Kuwait		330		416		1,841
Other countries		9,105		7,678		7,041
Total	$	22,576	$	20,240	$	19,878
Long-lived assets:
United States	$	2,340	$	2,409	$	2,485
United Kingdom		539		563		697
Other countries		1,597		1,300		1,126
Total	$	4,476	$	4,272	$	4,308

Note 6. Receivables (Other than “Insurance for asbestos- and silica-related liabilities”)

Our receivables are generally not collateralized. At December 31, 2006, 27% 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, 2005 represented 38% of consolidated receivables.

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.

Note 7. Inventories

Inventories are stated at the lower of cost or market. In the United States we manufacture certain finished products and parts inventories for drill bits, completion products, bulk materials, and other tools that are recorded using the last-in, first-out method, which totaled $58 million at December 31, 2006 and $42 million at December 31, 2005. If the average cost method had been used, total inventories would have been $20 million higher than reported at December 31, 2006 and $21 million higher than reported at December 31, 2005. The cost of the remaining inventory was recorded on the average cost method. Inventories consisted of the following:

	December 31
Millions of dollars	2006		2005
Finished products and parts	$	909	$	715
Raw materials and supplies		256		181
Work in process		96		57
Total	$	1,261	$	953

Finished products and parts are reported net of obsolescence reserves of $80 million at December 31, 2006 and $98 million at December 31, 2005.

Note 8. 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 subsequently 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 and committed cash

At December 31, 2006 we had restricted cash of $132 million, which primarily consisted of:

$105 million as collateral for potential future insurance claim reimbursements included in “Other assets”; and

$24 million related to cash collateral agreements for outstanding letters of credit for various construction projects included in “Other current assets”.

At December 31, 2005, we had restricted cash of $123 million in “Other assets,” which primarily consisted of similar items as above.

Cash and equivalents include cash from advanced payments related to contracts in progress held by ourselves or our joint ventures that we consolidate for accounting purposes. The use of these cash balances is limited to the specific projects or joint venture activities and is not available for other projects, general cash needs, or distribution to us without approval of the board of directors of the respective joint venture or subsidiary. At December 31, 2006 and December 31, 2005, cash and equivalents included approximately $527 million and $223 million, respectively, in cash from advanced payments held by ourselves or our joint ventures that we consolidate for accounting purposes.

Note 9. Property, Plant, and Equipment

Property, plant, and equipment at December 31, 2006 and 2005 were composed of the following:

Millions of dollars	2006		2005
Land	$	70	$	66
Buildings and property improvements		1,027		940
Machinery, equipment, and other		6,105		5,480
Total		7,202		6,486
Less accumulated depreciation		4,154		3,838
Net property, plant, and equipment	$	3,048	$	2,648

Machinery, equipment, and other included oil and gas properties of $302 million at December 31, 2006 and $309 million at December 31, 2005.

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
	2006			2005
1-10 years		24	%		25	%
11-20 years		43	%		45	%
21-30 years		15	%		11	%
31-40 years		18	%		19	%

	Machinery, Equipment,
	and Other
	2006			2005
1-5 years		25	%		25	%
6-10 years		70	%		69	%
11-20 years		5	%		6	%

Note 10. Debt

Short-term notes payable consist primarily of overdraft and other facilities with varying rates of interest. Long-term debt at December 31, 2006 and 2005 consisted of the following:

Millions of dollars	2006		2005
3.125% convertible senior notes due July 2023	$	1,200	$	1,200
5.5% senior notes due October 2010		749		748
Medium-term notes due 2008 thru 2027		299		600
7.6% debentures of Halliburton due August 2096		294		294
8.75% debentures due February 2021		185		200
Other		104		132
Total long-term debt		2,831		3,174
Less current portion		45		361
Noncurrent portion of long-term debt	$	2,786	$	2,813

Convertible notes

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

The notes are convertible under any of the following circumstances:

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

if the notes have been called for redemption;

upon the occurrence of specified corporate transactions that are described in the indenture related 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 conversion price is $18.825 per share and is subject to adjustment upon the occurrence of stock dividends in common stock, the issuance of rights or warrants, stock splits and combinations, the distribution of indebtedness, securities, or assets, or excess cash distributions. The stock conversion rate for the notes changed as a result of the July 2006 stock split and an increase to our quarterly dividend. As of December 31, 2006, the stock conversion rate was 53.20 shares of common stock per $1,000 principal amount of notes. The distribution of KBR, Inc. stock to our shareholders, if in the form of a spin-off, would cause the conversion rate to change. The amount of such change would be based on the relative valuation of KBR, Inc. at the time of distribution.

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)
12/2008		5.63	%	$	150
05/2017		7.53	%	$	45
02/2027		6.75	%	$	104

In August 2006, we repaid, at par plus accrued interest, our $275 million 6.0% medium-term notes that matured. During 2006 we have repurchased $41 million of our medium-term notes at a total cost of $49 million. The 5.63% medium-term notes are redeemable by us, in whole or in part, at any time subject to a redemption price equal to the greater of 100% of the principal amount of 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. 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. There were no cash drawings under the unsecured $1.2 billion revolving credit facility as of December 31, 2006.

KBR entered into an unsecured $850 million five-year revolving credit facility in the fourth quarter of 2005. Letters of credit that totaled $55 million were issued under the KBR revolving credit facility, thus reducing the availability under the credit facility to approximately $795 million at December 31, 2006. There were no cash drawings under the unsecured $850 million revolving credit facility as of December 31, 2006.

Debt covenants

Letters of credit related to our $1.2 billion revolving credit facility contain restrictive covenants, including covenants that require us to maintain a minimum debt-to-capitalization ratio under our $1.2 billion revolving credit facility. At December 31, 2006, we were in compliance with this requirement.

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, 2006, KBR was in compliance with these requirements.

Maturities

Our debt matures as follows: $45 million in 2007; $164 million in 2008; $5 million in 2009; $752 million in 2010; $3 million in 2011; and $1,862 million thereafter.

Note 11. Asbestos 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. 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) when the plan of reorganization became final and nonappealable.

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 $167 million related to these receivables were received in 2006. Under the terms of the settlement agreements, we will receive cash payments of the remaining amounts, totaling $261 million at December 31, 2006, in several installments through 2010.

The following table presents a rollforward of our asbestos- and silica-related insurance receivables.

Millions of dollars
Insurance for asbestos- and silica-related liabilities:
December 31, 2005 balance (of which $193 was current)	$	396
Payments received		(167	)
Accretion		11
Insurance for asbestos- and silica-related liabilities - December 31,
2006 balance (of which $68 is current)	$	240

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 annual installment payments beginning in January 2005. 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.

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. In the fourth quarter of 2006, we received a portion of this amount, and the remaining $1.3 million is expected to be received back from Federal-Mogul following recoveries received by Federal-Mogul from the insolvent London-based insurance companies.

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, 2006, we had not recorded any liability associated with these indemnifications.

Note 12. United States Government Contract Work

DCAA audit issues

competitively bid lump sum or fixed price subcontracts. As a result, we do not receive details of the subcontractors’ cost estimate nor are we legally entitled to it. Accordingly, we believe that we are entitled to reimbursement by the Army for the cost of services provided by our subcontractors, even if they incurred costs for private force protection services. Therefore, we believe that the Army’s position that such costs are unallowable and that they are entitled to withhold amounts incurred for such costs is wrong as a matter of law.

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 believed we and our subcontractors did not provide 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. In the second quarter of 2006, we successfully resolved this matter with the DCAA and received payment of the remaining $12 million.

Dining facilities. In September 2005, Eurest Support Services (Cyprus) International Limited, or 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.

In the third quarter of 2006, the DCAA has raised questions regarding $95 million of costs related to dining facilities in Iraq. We have responded to the DCAA that our costs are reasonable.

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 have been questions raised by the DCAA about the reasonableness or allowability of certain costs or the quality or quantity of supporting documentation. The DCAA might 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

The House Oversight and Government Reform Committee has conducted hearings on the U.S. military's reliance on civilian contractors, including with respect to military operations in Iraq. We have provided testimony and information for these hearings. We expect hearings with respect to operations in Iraq to continue in this and other Congressional committees, including the House Armed Services Committee, and we expect to be asked to testify and provide information for these hearings.

Claims

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 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. In the fourth quarter 2006, we reached a negotiated settlement with the DOJ. KBR was not accused of any wrongdoing and did not admit to any wrongdoing. The company is not suspended or debarred from bidding for or performing work for the US government. The settlement did not have a material impact on our results of operations.

Note 13. Other Commitments and Contingencies

Foreign Corrupt Practices Act investigations

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amount of any fines or monetary penalties that could be assessed would depend on, among other factors, the findings regarding the amount, timing, nature, and scope of any improper payments, whether any such payments were authorized by or made with knowledge of us or our affiliates, the amount of gross pecuniary gain or loss involved, and the level of cooperation provided the government authorities during the investigations. Agreed dispositions of these types of violations also frequently result in an acknowledgement of wrongdoing by the entity and the appointment of a monitor on terms negotiated with the SEC and the DOJ to review and monitor current and future business practices, including the retention of agents, with the goal of assuring compliance with the FCPA. Other potential consequences could be significant and include suspension or debarment of our ability to contract with governmental agencies of the United States and of foreign countries. During 2006, KBR and its affiliates had revenue of approximately $5.8 billion from its government contracts work with agencies of the United States or state or local governments. If necessary, we would seek to obtain administrative agreements or waivers from the United States Department of Defense (DoD) and other agencies to avoid suspension or debarment. In addition, we may be excluded from bidding on United Kingdom Ministry of Defence (MoD) contracts in the United Kingdom if we are convicted for a corruption offense or if the MoD determines that our actions constituted grave misconduct. During 2006, KBR had revenue of approximately $1.0 billion from its government contracts work with the MoD. Suspension or debarment from the government contracts business would have a material adverse effect on our business, results of operations, and cash flows.

As of December 31, 2006, we are unable to estimate an amount of probable loss or a range of possible loss related to these matters.

Bidding practices investigation

As of December 31, 2006, we are unable to estimate an amount of probable loss or a range of possible loss related to these matters.

Possible Algerian investigation

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Securities and related litigation

In June 2002, a class action lawsuit was filed against us in federal court on behalf of purchasers of our common stock during the approximate period of May 1998 until May 2002 alleging violations of the federal securities laws in connection with the accounting change and disclosures involved in the SEC investigation related to a change in accounting for revenue on long-term construction projects and related disclosures, which we settled with the SEC in the second quarter of 2004. 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 in April 2003 (the “Moore class action”).

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 included claims arising out of the 1998 acquisition of Dresser Industries, Inc. by Halliburton, including that we failed to timely disclose the resulting asbestos liability exposure (the “Dresser claims”). The 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.

In June 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 the court entered an order in September 2004 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 were entitled to do by its terms. The mediation was held in January 2005, but was declared by the mediator to be at an impasse with no settlement reached.

In April 2005, the court appointed new co-lead counsel and a new lead plaintiff, directing that they file a third consolidated amended complaint and that we file our motion to dismiss. The court held oral arguments on that motion in August 2005, at which time the court took the motion under advisement. In March 2006, the court entered an order in which it granted the motion to dismiss with respect to claims arising prior to June 1999 and granted the motion with respect to certain other claims while permitting the plaintiffs to repled those claims to correct deficiencies in their earlier complaint. In April 2006, the plaintiffs filed their fourth amended consolidated complaint. We filed a motion to dismiss those portions of the complaint that had been repled. A hearing was held on that motion in July 2006, and we await the court’s ruling. The lead plaintiff has filed a motion to discharge and replace co-lead counsel. That motion was granted on February 26, 2007.

As of December 31, 2006, we had not accrued any amounts related to this matter.

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 alleged 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 were in the range of $33 million to $39 million, and trial was scheduled for February 2007. During the fourth quarter of 2006, the case was settled with no material impact on us.

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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

As of December 31, 2006, we had not accrued any amounts related to this investigation.

David Hudak and International Hydrocut Technologies Corp.

In October 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 from us 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 filed a motion to dismiss and, alternatively, a motion to transfer venue. Those motions were denied during the first quarter of 2006. It is our intention to vigorously defend this action.

Amounts accrued related to this matter as of December 31, 2006 were not material.

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

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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 moved to dismiss the case on a number of bases. On September 26, 2006, the court granted the motion to dismiss insofar as claims for overtime pay and “uplift” pay are concerned, leaving only a contractual claim for miscalculation of employees’ pay. That claim remains open. It is premature to assess the probability of an adverse result on that remaining claim. However, because the LogCAP contract is cost-reimbursable, we believe that we could charge any adverse award to the customer. It is our intention to continue to vigorously defend the remaining claim.

As of December 31, 2006, we had not accrued any amounts related to this matter.

McBride qui tam suit

In September 2006, we became aware of a qui tam action filed against us by a former employee alleging various wrongdoings in the form of overbillings of our customer on the LogCAP III contract. This case was originally filed pending the government’s decision whether or not to participate in the suit. In June 2006, the government formally declined to participate. The principal allegations are that our compensation for the provision of Morale, Welfare and Recreation (MWR) facilities under LogCAP III is based on the volume of usage of those facilities and that we deliberately overstated that usage. In accordance with the contract, we charged our customer based on actual cost, not based on the number of users. It was also alleged that during the period from November 2004 into mid-December 2004, we continued to bill the customer for lunches, although the dining facility was closed and not serving lunches. There are also allegations regarding housing containers and KBR’s provision of services to its own employees and contractors. Our investigation is ongoing. However, we believe the allegations to be without merit, and we intend to vigorously defend this action.

As of December 31, 2006, we had not accrued any amounts in connection with this matter.

Wilson and Warren qui tam suit

During November 2006, we became aware of a qui tam action filed against us alleging that we overcharged the military $30 million by failing to adequately maintain trucks used to move supplies in convoys and by sending empty trucks in convoys. It was alleged that the purpose of these acts was to cause the trucks to break down more frequently than they would if properly maintained and to unnecessarily expose them to the risk of insurgent attacks, for the purpose of necessitating their replacement thus increasing our revenue. The suit also alleges that in order to silence the plaintiffs, who allegedly were attempting to report those allegations and other alleged wrongdoing, we unlawfully terminated them. On February 6, 2007, the court granted our motion to dismiss the plaintiffs’ qui tam claims as legally insufficient and ordered the plaintiffs to arbitrate their claims that they were unlawfully discharged.

As of December 31, 2006, we had not accrued any amounts in connection with this matter.

M-I, LLC antitrust litigation

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

As of December 31, 2006, we had not accrued any amounts in connection with this matter.

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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.

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

Letters of credit

In the normal course of business, we have agreements with banks under which approximately $1.0 billion of letters of credit or bank guarantees were outstanding as of December 31, 2006, including $676 million that relate to KBR. These KBR letters of credit or bank guarantees include $516 million that relate to their joint ventures’ operations. Some of the outstanding letters of credit have triggering events which would entitle a bank to require cash collateralization.

Other commitments

As of December 31, 2006, we had commitments to fund approximately $156 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 $13 million of the commitments to be paid during the next twelve months.

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 $43 million at December 31, 2006 and $70 million at December 31, 2005 (including our share of amounts related to 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		2006			2005			2004
Rental expense		$	580		$	721		$	693

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Future total rentals on noncancelable operating leases are as follows: $188 million in 2007; $145 million in 2008; $125 million in 2009; $110 million in 2010; $103 million in 2011; and $367 million thereafter.

Note 14. Income Taxes

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

	Years ended December 31
Millions of dollars	2006			2005			2004
Current income taxes:
Federal	$	(182	)	$	(100	)	$	(85	)
Foreign		(289	)		(190	)		(153	)
State		(12	)		(9	)		(6	)
Total current		(483	)		(299	)		(244	)
Deferred income taxes:
Federal		(577	)		305			3
Foreign		(64	)		(56	)		6
State		(20	)		(14	)		-
Total deferred		(661	)		235			9
Provision for income taxes	$	(1,144	)	$	(64	)	$	(235	)

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

	Years ended December 31
Millions of dollars	2006		2005		2004
United States	$	2,381	$	1,713	$	135
Foreign		1,068		734		499
Total	$	3,449	$	2,447	$	634

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
	2006			2005			2004
United States statutory rate		35.0	%		35.0	%		35.0	%
State income taxes, net of federal
income tax benefit		0.6			1.0			0.6
Impact of foreign operations		(1.3	)		(1.4	)		-
Adjustments of prior year taxes		(0.8	)		0.1			(2.1	)
Valuation allowance		(0.6	)		(32.3	)		-
Other items, net		0.3			0.2			3.6
Total effective tax rate on
continuing operations		33.2	%		2.6	%		37.1	%

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 remaining valuation allowance was released in 2006.

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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	2006		2005
Gross deferred tax assets:
Employee compensation and benefits	$	455	$	299
Foreign tax credit carryforward		146		146
Construction contract accounting		88		41
Accrued liabilities		85		102
Net operating loss carryforwards		84		926
Alternative minimum tax credit carryforward		69		21
Capitalized research and experimentation		65		113
Insurance accruals		60		58
Other		204		264
Total gross deferred tax assets	$	1,256	$	1,970
Gross deferred tax liabilities:
Depreciation and amortization	$	182	$	194
Other		27		20
Total gross deferred tax liabilities	$	209	$	214
Valuation allowances:
Foreign tax credit carryforward	$	146	$	146
Future tax attributes related to United States
net operating loss		-		137
Net operating loss carryforwards		50		43
Total valuation allowances	$	196	$	326
Net deferred income tax asset	$	851	$	1,430

We have $187 million of foreign net operating loss carryforwards that expire from 2007 through 2016 and additional foreign net operating loss carryforwards of $65 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 and was fully utilized in 2006. 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.

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dispositions, and changes to our operating environment could alter the estimates, which 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. Given that we fully utilized the United States net operating loss in 2006 and expect to begin utilizing foreign tax credits in the United States for 2007, the valuation allowance balance has been reduced to zero as of the end of 2006.

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Note 15. Shareholders’ Equity and Stock Incentive Plans

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

			Paid-in
			Capital in															Accumulated
			Excess			Asbestos												Other
	Common		of Par			Trust			Treasury			Deferred			Retained			Comprehensive
Millions of dollars	Shares		Value			Shares			Stock			Compensation			Earnings			Income
Balance at December 31, 2003	$	2,284	$	(869	)	$	-		$	(577	)	$	(64	)	$	2,071		$	(298	)
Cash dividends paid		-		-			-			-			-			(221	)		-
Stock-based compensation and
employee stock purchase, net		8		(7	)		-			107			(10	)		-			-
Treasury stock purchased		-		-			-			(7	)		-			-			-
Tax benefit from exercise of options and
restricted stock		-		7			-			-			-			-			-
Total dividends and other transactions
with shareholders		8		-			-			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	$	2,292	$	(869	)	$	2,335		$	(477	)	$	(74	)	$	871		$	(146	)
Cash dividends paid		-		-			-			-			-			(254	)		-
Stock-based compensation and
employee stock purchase, net		44		258			-			115			(24	)		-			-
Treasury stock purchased		-		-			-			(12	)		-			-			-
Tax benefit from exercise of options
and restricted stock		-		75			-			-			-			-			-
Total dividends and other transactions
with shareholders		44		333			-			103			(24	)		(254	)		-
Asbestos trust shares		298		2,037			(2,335	)		-			-			-			-
Comprehensive income (loss):
Net income		-		-			-			-			-			2,358			-
Other comprehensive income:
Cumulative translation
adjustment		-		-			-			-			-			-			(48	)
Realization of 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	$	2,634	$	1,501		$	-		$	(374	)	$	(98	)	$	2,975		$	(266	)
Cash dividends paid		-		-			-			-			-			(306	)		-
Stock-based compensation and
employee stock purchase, net		16		116			-			136			-			-			-
Treasury stock purchased		-		-			-			(16	)		-			-			-
Tax benefit from exercise of options
and restricted stock		-		53			-			-			-			-			-
Total dividends and other transactions
with shareholders		16		169			-			120			-			(306	)		-

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			Paid-in
			Capital in												Accumulated
			Excess			Asbestos									Other
	Common		of Par			Trust		Treasury			Deferred		Retained		Comprehensive
Millions of dollars	Shares		Value			Shares		Stock			Compensation		Earnings		Income
Common share repurchase program		-		-			-		(1,323	)		-		-		-
Sale of stock by a subsidiary		-		117			-		-			-		-		-
Reclassification of deferred
compensation		-		(98	)		-		-			98		-		-
Adoption of SFAS 158, net of tax
benefit of $146		-		-			-		-			-		-		(218	)
Other		-		-			-		-			-		34		-
Comprehensive income (loss):
Net income		-		-			-		-			-		2,348		-
Other comprehensive income:
Cumulative translation adjustment		-		-			-		-			-		-		48
Realization of losses included in
net income		-		-			-		-			-		-		(14	)
Pension liability adjustment, net
of tax benefit of $16		-		-			-		-			-		-		2
Net unrealized losses on
investments and derivatives, net
of tax of $7		-		-			-		-			-		-		11
Total comprehensive income		-		-			-		-			-		2,348		47
Balance at December 31, 2006	$	2,650	$	1,689		$	-	$	(1,577	)	$	-	$	5,051	$	(437	)

*Accumulated other comprehensive income*	December 31
Millions of dollars	2006			2005			2004
Cumulative translation adjustment	$	(38	)	$	(72	)	$	(31	)
Pension liability adjustments		(400	)		(184	)		(130	)
Unrealized gains (losses) on investments and
derivatives		1			(10	)		15
Total accumulated other comprehensive income	$	(437	)	$	(266	)	$	(146	)

*Shares of common stock*	December 31
Millions of shares		2006			2005			2004
Issued		1,060			1,054			916
In treasury		(62	)		(26	)		(32	)
Total shares of common stock outstanding		998			1,028			884

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

In February 2006, our Board of Directors approved a share repurchase program up to $1.0 billion, which replaced our previous share repurchase program. In September 2006, our Board of Directors approved an increase to our existing common share repurchase program of up to an additional $2.0 billion. 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. During 2006, we repurchased approximately 40 million shares of our common stock for approximately $1.3 billion or an average price per share of $32.93.

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Preferred Stock

Our preferred stock consists of five million total authorized shares at December 31, 2006, of which none were issued.

Halliburton Stock Incentive Plans

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

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

restricted stock awards;

restricted stock unit awards;

stock appreciation rights; and

stock value equivalent awards.

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

Under the terms of the 1993 Plan, 98 million shares of common stock have been reserved for issuance to employees and non-employee directors. The plan specifies that no more than 32 million shares can be awarded as restricted stock. At December 31, 2006, approximately 20 million shares were available for future grants under the 1993 Plan, of which approximately 11 million shares remained available for restricted stock awards. The stock to be offered pursuant to the grant of an award under the 1993 Plan may be authorized but unissued common shares or treasury shares.

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

Once Halliburton's ownership interest in KBR, Inc. is 20% or less, outstanding awards to KBR, Inc. employees of options to purchase Halliburton stock and unvested Halliburton restricted stock under the 1993 Plan will be converted into similar KBR, Inc. awards under its new Transitional Stock Adjustment Plan, with the intention of preserving approximately the equivalent value of the previous awards under the 1993 Plan.

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

Stock options

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

The following table represents our stock options activity during 2006, and includes exercised, forfeited, and expired shares from our acquired companies’ stock plans.

				Weighted		Weighted
				Average		Average		Aggregate
	Number			Exercise		Remaining		Intrinsic
	of Shares			Price		Contractual		Value
Stock Options	(in millions)			per Share		Term (years)		(in millions)
Outstanding at January 1, 2006		22.4		$	16.81
Granted		1.9			34.32
Exercised		(6.3	)		17.35
Forfeited		(0.3	)		19.78
Expired		(0.1	)		15.45
Outstanding at December 31, 2006		17.6		$	18.55		5.79	$	227

Exercisable at December 31, 2006		12.7		$	15.66		4.73	$	196

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The total intrinsic value of options exercised was $123 million in 2006, $194 million in 2005, and $19 million in 2004. As of December 31, 2006, there was $37 million of unrecognized compensation cost, net of estimated forfeitures, related to nonvested stock options, which is expected to be recognized over a weighted average period of approximately 1.8 years.

Cash received from option exercises was $159 million during 2006, $342 million during 2005, and $63 million during 2004. The tax benefit realized from the exercise of stock options was $42 million in 2006.

Restricted stock

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

Our Restricted Stock Plan for Non-Employee Directors (Directors Plan) allows for each non-employee director to receive an annual award of 800 restricted shares of common stock as a part of compensation. These awards have a minimum restriction period of six months and the restrictions lapse upon termination of Board service. The fair market value of the stock on the date of grant is amortized. We reserved 200,000 shares of common stock for issuance to non-employee directors, which may be authorized but unissued common shares or treasury shares. At December 31, 2006, 106,400 shares had been issued to non-employee directors under this plan. There were 8,000 shares, 6,400 shares, and 8,000 shares of restricted stock awarded under the Directors Plan in 2006, 2005, and 2004. In addition, during 2006, our non-employee directors were awarded 30,168 shares of restricted stock under the 1993 Plan, which are included in the table below.

The following table represents our 1993 Plan and Directors Plan restricted stock awards and restricted stock units granted, vested, and forfeited during 2006.

				Weighted
	Number of Shares			Average Grant-Date Fair
Restricted Stock	(in millions)			Value per Share
Nonvested shares at January 1, 2006		7.5		$	17.07
Granted		2.5			34.39
Vested		(1.8	)		17.04
Forfeited		(0.3	)		20.70
Nonvested shares at December 31, 2006		7.9		$	22.50

The weighted average grant-date fair value of shares granted during 2005 was $24.28 and during 2004 was $14.86. The total fair value of shares vested during 2006 was $64 million, during 2005 was $49 million, and during 2004 was $24 million. As of December 31, 2006, there was $139 million of unrecognized compensation cost, net of estimated forfeitures, related to nonvested restricted stock, which is expected to be recognized over a weighted average period of 4.3 years.

2002 Employee Stock Purchase Plan

Under the ESPP, eligible employees may have up to 10% of their earnings withheld, subject to some limitations, to be used to purchase shares of our common stock. Unless the Board of Directors shall determine otherwise, each six-month offering period commences on January 1 and July 1 of each year. The price at which common stock may be purchased under the ESPP is equal to 85% of the lower of the fair market value of the common stock on the commencement date or last trading day of each offering period. Under this plan, 24 million shares of common stock have been reserved for issuance. They may be authorized but unissued shares or treasury shares. As of December 31, 2006, 11.7 million shares have been sold through the ESPP.

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KBR, Inc. Stock Incentive Plans

In November 2006, KBR, Inc. established the KBR 2006 Stock and Incentive Plan (KBR 2006 Plan) which provides for the grant of any or all of the following types of KBR, Inc. stock-based awards:

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

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

restricted stock;

restricted stock units;

performance awards; and

stock value equivalent awards.

Under the terms of the KBR 2006 Plan, 10 million shares of KBR, Inc. common stock have been reserved for issuance to KBR, Inc. employees and non-employee directors. The plan specifies that no more than 3.5 million KBR, Inc. shares can be awarded as restricted stock or restricted stock units or pursuant to performance awards. At December 31, 2006, approximately 8 million KBR, Inc. shares were available for future grants under the KBR 2006 Plan, of which approximately 2.5 million KBR, Inc. shares remained available for restricted stock awards or restricted stock unit awards.

Stock Options

Under the KBR 2006 Plan, effective as of the closing date of the KBR, Inc. initial public offering, stock options are granted with an exercise price not less than the fair market value of the common stock on the date of the grant and a term no greater than 10 years. The term and vesting periods are established at the discretion of the Compensation Committee at the time of each grant.

The following table represents KBR, Inc. stock option activity during 2006.

			Weighted
	Number of Shares		Average Exercise Price
Stock Options	(in millions)		per Share
Outstanding at January 1, 2006		-		-
Granted		1.0	$	21.81
Exercised		-		-
Forfeited		-		-
Expired		-		-
Outstanding at December 31, 2006		1.0	$	21.81

KBR, Inc. options outstanding at December 31, 2006 had a weighted average remaining contractual life of 9.9 years. None of the options outstanding were exercisable at December 31, 2006. As of December 31, 2006, net of estimated forfeitures, there was $8 million of unrecognized compensation cost related to nonvested KBR, Inc. stock options, expected to be recognized over a weighted average period of approximately 2.9 years. The aggregate intrinsic value attributable to these options was $4 million as of December 31, 2006.

Restricted stock and restricted stock units

Restricted shares issued under the KBR 2006 Plan are restricted as to sale or disposition. These restrictions lapse periodically over a period not exceeding 10 years. Restrictions may also lapse for early retirement and other conditions in accordance with our established policies. Upon termination of employment, shares on which restrictions have not lapsed must be returned to KBR, Inc. resulting in restricted stock forfeitures. 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.

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The following table presents the restricted stock awards and restricted stock units granted, vested, and forfeited during 2006 under the KBR 2006 Plan.

			Weighted
	Number of Shares		Average Grant-Date Fair
Restricted Stock	(in millions)		Value per Share
Nonvested shares at January 1, 2006		-		-
Granted		1.0	$	21.16
Vested		-		-
Forfeited		-		-
Nonvested shares at December 31, 2006		1.0	$	21.16

As of December 31, 2006, there was $19 million of unrecognized compensation cost, net of estimated forfeitures, related to KBR, Inc. nonvested restricted stock and restricted stock units, which is expected to be recognized over a weighted average period of 4.9 years.

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 119 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:

Millions of shares	2006		2005		2004
Basic weighted average common shares outstanding		1,014		1,010		874
Dilutive effect of:
Convertible senior notes premium		29		16		-
Stock options		9		10		4
Restricted stock		2		2		2
Other		-		-		2
Diluted weighted average common shares outstanding		1,054		1,038		882

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 2006 and 2005. The conversion price of $18.825 per share of common stock was greater than our average share price in 2004 and, consequently, did not result in dilution.

Excluded from the computation of diluted income (loss) per share were options to purchase two million shares of common stock that were outstanding in 2006, two million shares of common stock that were outstanding in 2005, and 18 million shares of common stock outstanding in 2004. 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.

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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.

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 statements of operations and was not material in 2006, 2005, or 2004. As of December 31, 2006, we had unrealized gains and unrealized losses on these cash flow hedges that were not material, and as of December 31, 2005, we had approximately $18 million in unrealized net losses on these cash flow hedges. We included these unrealized gains and losses on these cash flow hedges in other comprehensive income in the accompanying consolidated balance sheets. We expect the unrealized net gains 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, 2006, 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 12 months. The fair value of these contracts was not material as of December 31, 2006 and December 31, 2005, and was $27 million as of December 31, 2004.

Notional amounts and fair market values. The notional amounts of open forward contracts and option contracts were $489 million at December 31, 2006 and $666 million at December 31, 2005. 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.

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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 6 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, 2006, we held no material interest rate derivative instruments.

Fair market value of financial instruments. The estimated fair market value of long-term debt was $3.7 billion at December 31, 2006 and $4.2 billion at December 31, 2005, as compared to the carrying amount of $2.8 billion at December 31, 2006 and $3.2 billion at December 31, 2005. The $4.2 billion fair value at December 31, 2005 was previously reported as $2.9 billion. In prior years, we did not consider the fair value of the conversion option in our convertible debentures. 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.

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 $184 million in 2006, $164 million in 2005, and $147 million in 2004. Additionally, we participate in a Canadian multi-employer plan to which we contributed $7 million, $24 million, and $20 million in 2006, 2005, and 2004, respectively. The decrease in 2006 was attributable to a decrease in the number of employees due to the completion of a major project at the end of 2005;

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

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

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

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

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

disclose additional information.

We adopted the requirement to recognize the funded status of a benefit plan and the additional disclosure requirements as of December 31, 2006.

The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end is effective for fiscal years ending after December 15, 2008 and we will adopt these requirements at that time.

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.

	Pension Benefits												Other
	United						United						Postretirement
*Benefit obligation*	States			Int’l			States			Int’l			Benefits
Millions of dollars	2006						2005						2006			2005
Change in benefit obligation
Benefit obligation at beginning of period	$	173		$	3,600		$	166		$	3,127		$	159		$	175
Service cost		-			73			1			72			1			1
Interest cost		9			184			9			172			9			10
Plan participants’ contributions		-			10			-			16			7			9
Effect of business combinations and new plans		-			-			-			1			-			-
Settlements/curtailments		-			-			-			(69	)		-			-
Currency fluctuations		-			204			-			(41	)		-			-
Actuarial (gain) loss		1			252			8			416			(6	)		(19	)
Transfers		-			3			-			-			-			-
Other		-			8			-			-			-			-
Benefits paid		(9	)		(103	)		(11	)		(94	)		(14	)		(17	)
Benefit obligation at end of period	$	174		$	4,231		$	173		$	3,600		$	156		$	159
Accumulated benefit obligation at end of period	$	174		$	3,583		$	172		$	3,014		$	-		$	-

117

	Pension Benefits												Other
	United						United						Postretirement
	States			Int’l			States			Int’l			Benefits
Millions of dollars	2006						2005						2006			2005
Change in plan assets
Fair value of plan assets at beginning of period	$	133		$	3,077		$	125		$	2,576		$	-		$	-
Actual return on plan assets		17			301			12			541			-			-
Employer contributions		4			186			7			74			7			8
Settlements and transfers		-			-			-			(1	)		-			-
Plan participants’ contributions		-			10			-			16			7			9
Effect of business combinations and new plans		-			-			-			-			-			-
Currency fluctuations		-			178			-			(35	)		-			-
Transfers		-			3			-			-			-			-
Other		-			10			-			-			-			-
Benefits paid		(9	)		(103	)		(11	)		(94	)		(14	)		(17	)
Fair value of plan assets at end of period	$	145		$	3,662		$	133		$	3,077		$	-		$	-

Funded status	$	(29	)	$	(569	)	$	(40	)	$	(523	)	$	(156	)	$	(159	)
Amounts not yet recognized		-			-			-			-			-			-
Employer contribution		-			27			-			21			1			1
Unrecognized transition asset		-			-			(1	)		-			-			-
Unrecognized actuarial loss (gain)		-			-			76			602			-			(7	)
Unrecognized prior service benefit		-			-			-			(8	)		-			(3	)
Purchase accounting adjustment		-			-			-			(78	)		-			-
Net amount recognized	$	(29	)	$	(542	)	$	35		$	14		$	(155	)	$	(168	)

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	Pension Benefits												Other
	United						United						Postretirement
	States			Int’l			States			Int’l			Benefits
Millions of dollars	2006						2005						2006			2005
Amounts recognized on the
consolidated balance sheet
Other assets	$	-		$	2		$	37		$	115		$	-		$	-
Accrued employee compensation
and benefits		-			(9	)		-			(6	)		(13	)		(9	)
Employee compensation and benefits		(29	)		(535	)		(77	)		(289	)		(142	)		(159	)
Intangible asset		-			-			-			2			-			-
Accumulated other comprehensive
income, net of tax		-			-			49			135			-			-
Noncurrent deferred tax asset		-			-			26			57			-			-
Net amount recognized	$	(29	)	$	(542	)	$	35		$	14		$	(155	)	$	(168	)

Pension plans in which accumulated
benefit obligation exceeds plan
assets at December 31
Projected benefit obligation	$	174		$	1,767		$	173		$	1,997		$	-		$	-
Accumulated benefit obligation		174			1,630			173			1,779			-			-
Fair value of plan assets		145			1,506			133			1,623			-			-
Weighted-average assumptions used
to determine benefit obligations
at measurement date
Discount rate		5.75	%		2.25-8.75	%		5.75	%		2.25-8.0	%		5.5	%		5.75	%
Rate of compensation increase		4.5	%		2.0-10.0	%		4.5	%		2.0-5.0	%		N/A			N/A
Assumed health care cost trend
rates at December 31
Health care cost trend rate assumed
for next year		N/A			N/A			N/A			N/A			10.0	%		10.0	%
Rate to which the cost trend rate is
assumed to decline (the ultimate
trend rate)		N/A			N/A			N/A			N/A			5.0	%		5.0	%
Year that the rate reached the ultimate
trend rate		N/A			N/A			N/A			N/A			2011			2008
Asset allocation at December 31

Asset category Target allocation 2007

Equity securities 50%-70%		63	%		63	%		63	%		62	%		N/A			N/A
Debt securities 30%-50%		36	%		35	%		36	%		30	%		N/A			N/A
Other 0%-5%		1	%		2	%		1	%		8	%		N/A			N/A
Total 100%		100	%		100	%		100	%		100	%		N/A			N/A

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Assumed long-term rates of return on plan assets, discount rates for estimating benefit obligations, and rates of compensation increases vary for the different plans according to the local economic conditions. The weighted average assumptions for the Nigerian 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. For our United Kingdom pension plans, which constitute 95% of our international pension plans’ projected benefit obligation, the discount rate was determined by comparing the terms of the plans to the yield curve of a portfolio of high quality debt instruments at the measurement date, and was 5.0% at September 30, 2006. The discount rate for 2005 was based on the annualized yield of the iBoxx AA corporate bonds, and was 5.0% at September 30, 2005.

The overall expected long-term rate of return on assets was determined based upon an evaluation of our plan assets, historical trends, and experience, taking into account current and expected market conditions.

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

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

The impact of adopting SFAS No. 158 on our consolidated balance sheet was to increase (decrease) certain accounts, as it relates to pension and other postretirement benefits, as follows:

	December 31, 2006
	Before						After
	Application of						Application of
Millions of dollars	SFAS No. 158			Adjustments			SFAS No. 158
Noncurrent deferred income taxes	$	82		$	146		$	228
Other assets		335			(333	)		2
Employee compensation and benefits		550			157			707
Minority interest in consolidated subsidiaries		(36	)		(126	)		(162	)
Accumulated other comprehensive income		(182	)		(218	)		(400	)

Amounts recognized in accumulated other comprehensive income were as follows:

	Pension Benefits					Other
	United					Postretirement
	States		Int’l			Benefits
Millions of dollars	2006					2006
Net actuarial loss (gain)	$	38	$	373		$	(8	)
Prior service benefit		-		(1	)		(2	)
Total recognized in accumulated other
comprehensive income	$	38	$	372		$	(10	)

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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 $80 million to our international pension plans in 2007. For our domestic plans, we expect our contributions to be no more than $4 million in 2007. We do not have a required minimum contribution for our domestic plans; however, we may make additional discretionary contributions, which will be determined after the actuarial valuations are complete.

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

	Pension Benefits				Other Postretirement Benefits
	United				Gross Benefit		Gross Medicare
Millions of dollars	States		Int’l		Payments		Part D Receipts
2007	$	23	$	113	$	13	$	1
2008		10		113		14		1
2009		10		118		14		1
2010		10		125		15		1
2011		11		129		15		1
Years 2012 - 2016		56		774		72		2

Net periodic cost

	Pension Benefits																		Other
	United						United						United						Postretirement
	States			Int’l			States			Int’l			States			Int’l			Benefits
Millions of dollars	2006						2005						2004						2006			2005			2004
Components of net
periodic benefit cost
Service cost	$	-		$	73		$	1		$	72		$	1		$	92		$	1		$	1		$	1
Interest cost		9			184			9			172			10			155			9			10			11
Expected return on plan
assets		(10	)		(207	)		(10	)		(186	)		(11	)		(173	)		-			-			-
Transition amount		-			-			-			-			-			(1	)		-			-			-
Amortization of prior service
cost		-			(1	)		-			-			-			-			(1	)		(1	)		(1	)
Settlements/curtailments		-			1			-			5			1			(2	)		-			-			-
Recognized actuarial loss		7			27			4			17			3			16			-			-			1
Net periodic benefit cost	$	6		$	77		$	4		$	80		$	4		$	87		$	9		$	10		$	12
Weighted-average
assumptions used to
determine net periodic
benefit cost for years
ended December 31
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	%
Expected return on plan assets		8.25	%		4.0-7.0	%		8.5	%		5.0-7.0	%		8.5	%		5.25-7.5	%		N/A			N/A			N/A
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

Estimated amounts that will be amortized from accumulated other comprehensive income, net of tax, into net periodic benefit cost in 2007 are as follows:

	Pension Benefits				Other Postretirement
Millions of dollars	United States		International		Benefits
Actuarial (gain) loss	$	4	$	20	$	-
Prior service (benefit) cost		-		-		-
Total	$	4	$	20	$	-

121

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

	One-Percentage-Point
Millions of dollars	Increase		(Decrease)
Effect on total of service and interest cost components	$	0	$	0
Effect on the postretirement benefit obligation	$	8	$	(7	)

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	2006		2005			2004
Revenue	$	4,428	$	3,230		$	3,616
Operating income (loss)	$	252	$	(51	)	$	(16	)
Net income (loss)	$	276	$	(33	)	$	(35	)

*Combined financial position*	December 31
Millions of dollars	2006		2005
Current assets	$	6,174	$	2,430
Noncurrent assets		3,593		3,262
Total	$	9,767	$	5,692
Current liabilities	$	2,775	$	2,251
Noncurrent liabilities		6,234		2,902
Shareholders’ equity		758		539
Total	$	9,767	$	5,692

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.

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:

122

Energy and Chemicals segment:

during 2005, we formed a joint venture to engineer and construct a gas monetization facility. KBR owns a 50% equity interest and determined that we are the primary beneficiary of the joint venture which is consolidated for financial reporting purposes. At December 31, 2006 and December 31, 2005, the joint venture had $756 million and $324 million in total assets and $877 million and $311 million in total liabilities, respectively. There are no consolidated assets that collateralize the joint venture’s obligations. However, at December 31, 2006 and December 31, 2005, the joint venture had approximately $413 million and $173 million of cash, respectively, which mainly relate to advanced billings in connection with the joint venture’s obligations under the EPC contract;

KBR has equity ownership in three joint ventures to execute EPC projects. KBR’s equity ownership ranges from 33% to 50%, and these joint ventures are considered variable interest entities. We are not the primary beneficiary and thus account for these joint ventures using the equity method of accounting. At December 31, 2006 and December 31, 2005, these joint ventures had aggregate assets of $1 billion and $863 million and aggregate liabilities of $1.1 billion and $914 million, respectively. Our aggregate maximum exposure to loss related to these entities was $77 million and $28 million at December 31, 2006 and December 31, 2005 and is comprised of our equity investments in and advances to the joint ventures in addition to our commitment to fund any future losses;

we have an investment in a development corporation that has an indirect interest in the new Egypt Basic Industries Corporation (EBIC) ammonia plant project located in Egypt. We are performing the engineering, procurement, and construction (EPC) work for the project and operations and maintenance services for the facility. KBR owns 60% of this development company and consolidate it for financial reporting purposes within our Energy and Chemicals segment. The development corporation owns a 25% ownership interest in a company that consolidates the ammonia plant, which is considered a variable interest entity. The development corporation accounts for its investment in the company using the equity method of accounting. The variable interest entity is funded through debt and equity. We are not the primary beneficiary of the variable interest entity. As of December 31, 2006, the variable interest entity had total assets of $347 million and total liabilities of $199 million. Our maximum exposure to loss on our equity investments at December 31, 2006 is limited to our investment of $15 million and our commitment to fund an additional $3 million of stand-by equity. In August 2006, the lenders providing the construction financing notified EBIC that it was in default of the terms of its debt agreement, which effectively prevented the project from making additional borrowings until such time as certain security interests in the ammonia plant assets related to the export facilities, could be perfected. This default was cured on December 8, 2006 subject to submitting the remaining documentation in March 2007. Indebtedness under the agreement is non-recourse to us. No event of default has occurred pursuant to our EPC contract and we have been paid all amounts due from EBIC. In September 2006, we were instructed by EBIC to cease work on one location of the project on which the ammonia storage tanks were originally planned to be constructed due to a decision to relocate the tanks. The new location has been selected and the client and its lenders have agreed to compensate KBR for approximately $6 million in costs resulting from the relocation of the storage tanks. We resumed work on the ammonia tanks in February 2007; and

in July 2006, KBR was awarded, through a 50%-owned joint venture, a contract with Qatar Shell GTL Limited to provide project management and cost-reimbursable engineering, procurement, and construction management services for the Pearl GTL project in Ras Laffan, Qatar. The project, which is expected to be completed by 2011, consists of gas production facilities and a GTL plant. The joint venture is considered a variable interest entity. We consolidate the joint venture for financial reporting purposes within our Energy and Chemicals segment because we are the primary beneficiary. As of December 31, 2006, the Pearl joint venture had total assets of $66 million and total liabilities of $56 million.

123

Government and Infrastructure segment:

during 2001, we formed a joint venture, in which KBR owns a 50% equity interest with an unrelated partner, that owns and operates heavy equipment transport vehicles in the United Kingdom. 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 flow generated during the operation and service phase of the contract. As of December 31, 2006 and December 31, 2005, the joint venture had total assets of $161 million and $149 million and total liabilities of $147 million and $154 million, respectively. Our aggregate maximum exposure to loss as a result of our involvement with this joint venture is limited to our equity investment which was zero at December 31, 2006 and any future losses related to the operation of the assets. We are not the primary beneficiary. The joint venture is accounted for using the equity method of accounting;

KBR are involved in four privately financed projects, executed through joint ventures, to design, build, operate, and maintain roadways for certain government agencies in the United Kingdom. KBR has a 25% ownership interest in these joint ventures and account for them using the equity method of accounting. The joint ventures have obtained financing through third parties that is not guaranteed by us. These joint ventures are considered variable interest entities; however, we are not the primary beneficiary of these joint ventures and, therefore, account for them using the equity method of accounting. As of December 31, 2006, these joint ventures had total assets of $2.2 billion and total liabilities of $2.1 billion. As of December 31, 2005, these joint ventures had total assets of $1.9 billion and total liabilities of $1.9 billion. Our maximum exposure to loss was $24 million at December 31, 2006. With respect to one of these roadways, we received a revised financial forecast during the second quarter of 2006, which takes into account sustained projected losses due to lower than anticipated long vehicle traffic and higher than forecasted lane availability deductions, which reduce project revenue. Because of this new information, we recorded an impairment charge of $10 million during the second quarter of 2006 in our equity investment in this roadway. As of December 31, 2006, our investment in this joint venture and the related company that performed the construction of the road was zero. In addition, at December 31, 2006, we had no additional funding commitments;

we participate in a privately financed project formed for operating and maintaining a railroad freight business in Australia. KBR owns 36.7% of the joint venture and operating company and we account for these investments using the equity method of accounting. These joint ventures are funded through senior and subordinated debt and equity contributions from the joint ventures’ partners. This joint venture has sustained losses since commencing operations due to lower than anticipated freight volume and a slowdown in the planned expansion of the Port of Darwin. At the end of the first quarter of 2006, the joint venture’s revised financial forecast led us to record a $26 million impairment charge. In October 2006, the joint venture incurred an event of default under its loan agreement by failing to make an interest and principal payment. These loans are non-recourse to us. In light of the default, the joint venture’s need for additional financing, and the realization that the joint venture efforts to raise additional equity from third parties were not successful, we recorded an additional $32 million impairment charge in the third quarter of 2006. We will receive no tax benefit as this impairment charge is not deductible for Australian tax purposes. In December 2006, the senior lenders agreed to waive existing defaults and concede certain rights under the existing indenture. Among these were a reduction in the joint venture’s debt service reserve and the relinquishment of the right to receive principal payments for 27 months, through March 2009. In exchange for these concessions, the shareholders of the joint

124

venture committed approximately $12 million of new subordinated financing, of which $6 million was committed by us. These joint ventures are considered variable interest entities; however, we are not the primary beneficiary of the joint ventures. As of December 31, 2006 and December 31, 2005, the joint venture had total assets of $874 million and $796 million and total liabilities of $790 million and $672 million, respectively. At December 31, 2006, our maximum exposure to loss totaling $12 million is limited to our equity investments, senior operating notes, and equity owner notes;

we participate in a privately financed project 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 minimal equity. These joint ventures are considered variable interest entities; however, we are not the primary beneficiary of the joint ventures. KBR has up to a 25% ownership interest in the project’s joint ventures, and we are accounting for this interest using the equity method of accounting. As of December 31, 2006 and December 31, 2005, the joint ventures had total assets of $301 million and $240 million and total liabilities of $293 million and $227 million, respectively. Our maximum exposure to loss was $8 million at December 31, 2006, and our share of any future losses resulting from the project. In addition, at December 31, 2006, we had remaining funding commitments of approximately $4 million; and

in April 2006, Aspire Defence, a joint venture between us, Mowlem Plc. and a financial investor, was awarded a privately financed project contract, the Allenby & Connaught project, by the MoD to upgrade and provide a range of services to the British Army’s garrisons at Aldershot and around Salisbury Plain in the United Kingdom. In addition to a package of ongoing services to be delivered over 35 years, the project includes a nine-year construction program to improve soldiers’ single living, technical and administrative accommodations, along with leisure and recreational facilities. Aspire Defence will manage the existing properties and will be responsible for design, refurbishment, construction and integration of new and modernized facilities. KBR indirectly owns a 45% interest in Aspire Defence, the project company that is the holder of the 35-year concession contract. In addition, KBR owns a 50% interest in each of two joint ventures that provide the construction and the related support services to Aspire Defence. KBR’s performance through the construction phase is supported by $159 million in letters of credit and surety bonds totaling approximately $209 million as of December 31, 2006, both of which have been guaranteed by us. Furthermore, our financial and performance guarantees are joint and several, subject to certain limitations, with our joint venture partners. The project is funded through equity and subordinated debt provided by the project sponsors and the issuance of publicly held senior bonds. The entities we hold an interest in are considered variable interest entities; however, we are not the primary beneficiary of these entities. We account for our interests in each of the entities using the equity method of accounting. As of December 31, 2006, the aggregate total assets and total liabilities of the variable interest entities were $3.2 billion and $3.3 billion, respectively. Our maximum exposure to project company losses as of December 31, 2006 was $59 million. Our maximum exposure to construction and operating joint venture losses is limited to the funding of any future losses incurred by those entities.

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 had been paid and the balance in the restructuring reserve account had been reduced to zero.

125

Note 21. New Accounting Standards

In June 2006, the FASB issued FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” The interpretation prescribes a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. We did not elect early adoption of this interpretation and adopted the provisions of FIN 48 beginning January 1, 2007. We have completed an initial evaluation of the impact of the January 1, 2007, adoption of FIN 48 and determined that such adoption is not expected to have a significant impact on our financial position or results from operations. We expect that any adjustment to reduce beginning-of-year retained earnings will not exceed $40 million.

126

HALLIBURTON COMPANY

Selected Financial Data (1)

(Unaudited)

Millions of dollars and shares	Years ended December 31
except per share and employee data	2006			2005			2004			2003			2002
Total revenue	$	22,576		$	20,240		$	19,878		$	15,797		$	11,956
Total operating income (loss)	$	3,484		$	2,617		$	820		$	705		$	(137	)
Nonoperating expense, net		(35	)		(170	)		(186	)		(108	)		(116	)
Income (loss) from continuing
operations before income taxes
and minority interest		3,449			2,447			634			597			(253	)
Provision for income taxes		(1,144	)		(64	)		(235	)		(229	)		(70	)
Minority interest in net income of
consolidated subsidiaries		(33	)		(56	)		(25	)		(39	)		(38	)
Income (loss) from continuing operations	$	2,272		$	2,327		$	374		$	329		$	(361	)
Income (loss) from discontinued operations	$	76		$	31		$	(1,353	)	$	(1,141	)	$	(637	)
Net income (loss)	$	2,348		$	2,358		$	(979	)	$	(820	)	$	(998	)
Basic income (loss) per share:
Continuing operations	$	2.24		$	2.31		$	0.43		$	0.38		$	(0.42	)
Net income (loss)		2.31			2.34			(1.12	)		(0.95	)		(1.16	)
Diluted income (loss) per share:
Continuing operations		2.16			2.24			0.42			0.38			(0.42	)
Net income (loss)		2.23			2.27			(1.11	)		(0.94	)		(1.16	)
Cash dividends per share		0.30			0.25			0.25			0.25			0.25
Return on average shareholders’ equity		34.16	%		45.76	%		(30.22	)%		(26.86	)%		(24.02	)%
Financial position:
Net working capital	$	6,456		$	4,959		$	2,898		$	1,355		$	2,288
Total assets		16,820			15,048			15,864			15,556			12,844
Property, plant, and equipment, net		3,048			2,648			2,545			2,518			2,619
Long-term debt (including current maturities)		2,831			3,174			3,940			3,437			1,476
Shareholders’ equity		7,376			6,372			3,932			2,547			3,558
Total capitalization		10,208			9,568			7,887			6,002			5,083
Basic weighted average common shares
outstanding		1,014			1,010			874			868			864
Diluted weighted average common shares
outstanding		1,054			1,038			882			874			864
Other financial data:
Capital expenditures	$	(891	)	$	(651	)	$	(575	)	$	(515	)	$	(764	)
Long-term borrowings (repayments), net		(341	)		(799	)		476			1,896			(15	)
Depreciation, depletion, and
amortization expense		527			504			509			518			505
Payroll and employee benefits		(6,172	)		(5,536	)		(5,311	)		(4,912	)		(4,624	)
Number of employees		104,000			100,000			94,000			99,000			82,000

(1)

All periods presented reflect the reclassification of KBR’s Production Services operations to discontinued operations, as well as the two-for-one common stock split, effected in the form of a stock dividend.

127

HALLIBURTON COMPANY

Quarterly Data and Market Price Information (1)

(Unaudited)

	Quarter
Millions of dollars except per share data	First		Second		Third			Fourth			Year
2006
Revenue	$	5,184	$	5,545	$	5,831		$	6,016		$	22,576
Operating income		755		718		968			1,043			3,484
Income from continuing operations		481		509		615			667			2,272
Income (loss) from discontinued operations		7		82		(4	)		(9	)		76
Net income		488		591		611			658			2,348
Earnings per share:
Basic income (loss) per share:
Income from continuing operations		0.47		0.50		0.61			0.67			2.24
Income (loss) from discontinued
operations		0.01		0.08		-			(0.01	)		0.07
Net income		0.48		0.58		0.61			0.66			2.31
Diluted income (loss) per share:
Income from continuing operations		0.45		0.48		0.58			0.65			2.16
Income (loss) from discontinued
operations		0.01		0.07		-			(0.01	)		0.07
Net income		0.46		0.55		0.58			0.64			2.23
Cash dividends paid per share		0.075		0.075		0.075			0.075			0.30
Common stock prices (2)
High		41.19		41.99		37.93			34.30			41.99
Low		31.35		33.92		27.35			26.33			26.33
2005
Revenue	$	4,783	$	4,973	$	4,912		$	5,572		$	20,240
Operating income		575		596		680			766			2,617
Income from continuing operations		359		384		492			1,092			2,327
Income from discontinued operations		6		8		7			10			31
Net income		365		392		499			1,102			2,358
Earnings per share:
Basic income per share:
Income from continuing operations		0.36		0.38		0.49			1.07			2.31
Income from discontinued operations		0.01		0.01		0.01			0.01			0.03
Net income		0.37		0.39		0.50			1.08			2.34
Diluted income per share:
Income from continuing operations		0.36		0.37		0.47			1.03			2.24
Income from discontinued operations		-		0.01		0.01			0.01			0.03
Net income		0.36		0.38		0.48			1.04			2.27
Cash dividends paid per share		0.0625		0.0625		0.0625			0.0625			0.25
Common stock prices (2)
High		22.65		24.70		34.89			34.69			34.89
Low		18.59		19.83		22.88			27.35			18.59

(1)

(2)

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

128

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

The information required for the directors of the Registrant is incorporated by reference to the Halliburton Company Proxy Statement for our 2007 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 12 and 13 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 2007 Annual Meeting of Stockholders (File No. 1-3492), under the caption “Section 16(a) Beneficial Ownership Reporting Compliance.” The information for our code of ethics is incorporated by reference to the Halliburton Company Proxy Statement for our 2007 Annual Meeting of Stockholders (File No. 1-3492), under the caption “Corporate Governance.”

Audit Committee financial experts

In the business judgment of the Board of Directors, all five members of the Audit Committee, Alan M. Bennett, 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 2007 Annual Meeting of Stockholders (File No. 1-3492) under the captions “Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table,” “Grants of Plan-Based Awards in Fiscal 2006,” “Outstanding Equity Awards at Fiscal Year End (2006),” “2006 Option Exercises and Stock Vested,” “2006 Nonqualified Deferred Compensation,” “Pension Benefits Table,” “Employment Contracts and Change-in-Control Arrangements,” “Post-Termination Payments,” “Equity Compensation Plan Information,” 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 2007 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 2007 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Equity Compensation Plan Information.”

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

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2007 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Certain Relationships and Related Transactions” to the extent any disclosure is required.

129

Item 14. Principal Accounting Fees and Services.

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2007 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.

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 70 and 71 and pages 72 through 126 of this annual report. See index on page (i).

2.	Financial Statement Schedules:	Page No.

	Report on supplemental schedule of KPMG LLP	138

	Schedule II - Valuation and qualifying accounts for the three
	years ended December 31, 2006	139

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 30, 2006 (incorporated by reference to Exhibit 3.1 to Halliburton’s Form 8-K filed June 5, 2006, File No. 1-3492).

3.2 By-laws of Halliburton revised effective October 19, 2006 (incorporated by reference to Exhibit 3.1 to Halliburton’s Form 8-K filed October 19, 2006, 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).

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).

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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 $9 million in the aggregate at December 31, 2006, 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).

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).

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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 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).

4.17 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).

4.18 Form of note of 3.125% Convertible Senior Notes due July 15, 2023 (included as Exhibit A to Exhibit 4.17 above).

4.19 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).

4.20 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).

4.21 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).

4.22 Form of note of 5.5% senior notes due October 15, 2010 (included as Exhibit B to Exhibit 4.21 above).

4.23 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).

133

4.24 Form of note of 7.6% debentures due 2096 (included as Exhibit A to Exhibit 4.23 above).

4.25 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).

4.26 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 (incorporated by reference to Exhibit 10.3 to Halliburton’s Form 10-K for the year ended December 31, 2005, File No. 1-3492).

10.4 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).

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

134

10.11 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).

10.12 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).

10.13 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).

10.14 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).

10.15 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).

10.16 Halliburton Annual Performance Pay Plan, as amended and restated effective January 26, 2006 (incorporated by reference to Exhibit 10.17 to Halliburton’s Form 10-K for the year ended December 31, 2005, File No. 1-3492).

10.17 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).

10.18 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).

10.19 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).

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

10.21 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).

10.22 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).

10.23 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).

10.24 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).

135

10.25 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).

10.26 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).

10.27 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).

10.28 Halliburton Company Supplemental Executive Retirement Plan as amended and restated effective December 7, 2005 (incorporated by reference to Exhibit 10.29 to Halliburton’s Form 10-K for the year ended December 31, 2005, File No. 1-3492).

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

10.30 Tax Sharing Agreement, dated as of January 1 , 2006, by and between Halliburton Company, KBR Holdings LLC, and KBR, Inc. (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 8-K filed November 27, 2006, File No. 1-3492).

* 10.31 Employment Agreement (William P. Utt).

* 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 2007:

Alan M. Bennett

James R. Boyd

Milton Carroll

Robert L. Crandall

Kenneth T. Derr

S. Malcolm Gillis

W. R. Howell

Ray L. Hunt

J. Landis Martin

Jay A. Precourt

Debra L. Reed

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

136

* 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.

137

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ON SUPPLEMENTAL SCHEDULE

The Board of Directors and Shareholders

Halliburton Company:

Under date of February 26, 2007, we reported on the consolidated balance sheets of Halliburton Company and subsidiaries as of December 31, 2006 and 2005, 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, 2006, 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 this consolidated financial statement schedule based on our audits.

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

/s/ KPMG LLP

Houston, Texas

February 26, 2007

138

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, 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

Year ended December 31, 2006:
Deducted from accounts and notes receivable:
Allowance for bad debts	$	90	$	104	$	2		$	(99) (a	)	$	97
Reserve for disputed and unallowable costs
incurred under government contracts	$	133	$	-	$	51 (b	)	$	(107	)	$	77

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

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

139

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 27th day of February, 2007.


	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 27th day of February, 2007.

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

140

Signature	Title

* Alan M. Bennett	Director
Alan M. Bennett

* James R. Boyd	Director
James R. Boyd

* Milton Carroll	Director
Milton Carroll

* Robert L. Crandall	Director
Robert L. Crandall

* Kenneth T. Derr	Director
Kenneth T. Derr

* S. Malcolm Gillis	Director
S. Malcolm Gillis

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

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

141