Halliburton Company Annual Report 2007

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FY2007 Annual Report · Halliburton Company

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713.759.2600

www.halliburton.com

Printed in the USA

H06194

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2 0 0 7 A N N U A L R E P O R T

The Face of Energy

REVENUE in millions

Board of Directors

Corporate Ofﬁ cers

$17,500

$15,000

$12,500

$10,000

$7,500

$5,000

$2,500

’04

’05

’06

’07

OPERATING INCOME in millions

$4,500

$4,000

$3,500

$3,000

$2,500

$2,000

$1,500

$1,000

$500

Comparative Highlights

( M I L L I O N S O F D O L L A R S A N D S H A R E S , E X C E P T P E R S H A R E D ATA )

2007

2006

2005

Revenue

Operating income

Income from continuing operations

Net income

Diluted income per share from

continuing operations

Diluted net income per share

Cash dividends per share

Diluted weighted average common

shares outstanding

Working capital (1)

$ 15,264

$ 12,955

$ 10,100

$ 3,498

$ 3,245

$ 2,164

$ 2,524

$ 2,177

$ 2,107

$ 3,499

$ 2,348

$ 2,358

$ 2.66

$ 2.07

$ 2.03

$ 3.68

$ 2.23

$ 2.27

$ 0.345

$ 0.30

$ 0.25

950

1,054

1,038

$ 5,162

$ 6,456

$ 4,959

RETURN ON E QUITY

’04

’05

’06

’07

Long-term debt (including current maturities)

$ 2,786

$ 2,809

$ 3,139

Debt to total capitalization (2)

Capital expenditures

29%

28%

33%

$ 1,583

$ 834

$ 575

Depreciation, depletion and amortization

$ 583

$ 480

$ 448

(1) Calculated as current assets minus current liabilities.
(2) Calculated as total debt divided by total debt plus shareholders’ equity.

50%

40%

30%

20%

10%

’04

’05

’06

’07

Return on equity is calculated as income from
continuing operations divided by average
shareholders’ equity.

2005 return on equity includes a tax benefit
of $805 million for favorable adjustments to
valuation allowances related to asbestos and
silica liabilities; without this benefit, income
from continuing operations and return on
equity for 2005 would have been $1,302
million and 25.3%, respectively.

In all periods, KBR has been reclassified
as discontinued operations.

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

Albert O. Cornelison, Jr.
Executive Vice President and
General Counsel

Mark A. McCollum
Executive Vice President and
Chief Financial Officer

Lawrence J. Pope
Executive Vice President of
Administration and Chief Human
Resources Officer

Timothy J. Probert
Executive Vice President, Strategy
and Corporate Development

James S. Brown
President, Western Hemisphere

C. Christopher Gaut
President, Drilling and
Evaluation Division

David S. King
President, Completion and
Production Division

Ahmed H. M. Lotfy
President, Eastern Hemisphere

Peter C. Bernard
Senior Vice President, Business
Development and Marketing

Craig W. Nunez
Senior Vice President and Treasurer

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

Christian A. Garcia
Vice President, Investor Relations

Sherry D. Williams
Vice President and
Corporate Secretary

David J. Lesar
Chairman of the Board, President
and Chief Executive Officer
Halliburton Company,
Houston, Texas (2000)

Kathleen M. Bader
Retired Chairman, President and Chief
Executive Officer, Nature Works LLC,
Minnetonka, Minnesota
(2007) (A)(C)

Alan M. Bennett
Interim Chief Executive Officer,
H&R Block,
Kansas City, Missouri
(2006) (A)(D)

James R. Boyd
Retired Chairman of the Board,
Arch Coal, Inc.,
St. Louis, Missouri
(2006) (B)(C)

Milton Carroll
Chairman of the Board,
CenterPoint Energy, Inc.,
Houston, Texas
(2006) (B)(C)

Robert L. Crandall
Chairman Emeritus AMR Corporation/
American Airlines, Inc.,
Irving, Texas
(1986) (A)(B)(D)

Kenneth T. Derr
Retired Chairman of the Board,
Chevron Corporation,
San Francisco, California
(2001) (B)(C)

S. Malcolm Gillis
University Professor,
Rice University,
Houston, Texas
(2005) (C)(D)

W. R. Howell
Chairman Emeritus
J.C. Penney Company, Inc.,
Dallas, Texas
(1991) (B)(D)

J. Landis Martin
Founder and Managing Director,
Platte River Ventures, L.L.C.,
Denver, Colorado
(1998) (A)(D)

Jay A. Precourt
Chairman of the Board,
Hermes Consolidated, Inc.,
Vail, Colorado
(1998) (A)(C)

Debra L. Reed
President and Chief Executive Officer,
Southern California Gas Company and
San Diego Gas & Electric Company,
San Diego, California
(2001) (B)(D)

Shareholder Information

Shares Listed
New York Stock Exchange
Symbol: HAL

Transfer Agent and Registrar
BNY Mellon Shareowner Services
480 Washington Boulevard
Jersey City, New Jersey 07310-1900
Telephone: 800-279-1227
www.bnymellon.com/shareowner/isd

To contact Halliburton Investor Relations,
shareholders may call the Company at
888-669-3920 or 713-759-2688, or via
e-mail at investors@halliburton.com.

The CEO and CFO certifications
required by Section 302 of the Sarbanes-
Oxley Act of 2002 have been filed as
exhibits to Halliburton’s Form 10-K.
Halliburton has also submitted the
Annual CEO Certification to the
New York Stock Exchange.

(A) Member of the Audit Committee
(B) Member of the Compensation

Committee

Environment Committee

(D) Member of the Nominating and

Corporate Governance Committee

Halliburton serves the upstream
oil and gas industry throughout
the life cycle of the reservoir –
from locating hydrocarbons and managing

geological data, to drilling and formation

evaluation, well construction and

completion, and optimizing production

through the life of the ﬁ eld.

Increased service intensity driven by

At a Glance

the exploitation of more complex

reservoirs, accelerated investments

in our people and infrastructure for

international growth, and a well-

integrated technology strategy will

continue to set us apart in the industry.

Revenue grew 18 percent year-over-year to $15.3 billion,
as all of our product service lines posted double-digit
growth. In 2007, international revenue (outside North
America) was 53 percent of the total; in 2006, it was
50 percent.

In 2007, our operating income grew 8 percent to $3.5
billion, led by a very strong 24 percent international
growth. International regions accounted for 49 percent of
our operating income; in 2006, that ﬁ gure was 43 percent.

HALLIBURTON 2007 ANNUAL R EP ORT 1

Dear Fellow Shareholders:

In 2007, Halliburton posted record revenue and earnings

for the third consecutive year.

Our largest source of expansion is and will continue to be in our international markets.
Our ﬁ nancial performance reﬂ ects the execution of a robust growth strategy based on
fundamental factors that are shaping the future. According to Cambridge Energy Research
Associates, the industry produced roughly a trillion barrels of oil in the last century and a half. It
is estimated that the world will use its second trillion barrels during the next 35 years. The next
trillion barrels will be characterized by smaller, more complex reservoirs in more challenging and
remote environments, and hydrocarbons will be increasingly unconventional in nature.

We are well positioned at the forefront of these trends, which will drive our international growth
and at increased levels of service intensity. Our accelerated investments in our people and
infrastructure, along with a well-integrated technology strategy and portfolio, will support our
global growth efforts.

Service intensity grows with reservoir complexity.
Increasing reservoir complexity has created a long-term trend toward greater service intensity
– additional and more complex services applied to each rig drilling or well serviced – and this
trend drove Halliburton’s growth in all regions in 2007.

Internationally, where many of our most advanced technologies – including directional drilling,
logging-while-drilling, completions and wireline – are leading our growth, our revenue per rig
has grown by more than 30 percent in the last two years, giving us the conﬁ dence that strong
international growth will continue in the future.

The most signiﬁ cant development in North America is the trend toward exploitation of
unconventional hydrocarbon resources such as tight gas development. This has translated to
robust growth, not only for our traditional stimulation businesses but also for our directional
drilling and horizontal well-completion technologies, which has resulted in a more balanced U.S.
product and service portfolio.

HALLIBU RTON 2 007 ANNUAL REPO RT

Infrastructure investments support our international
growth strategy.
We have accelerated our investments in people, facilities
and technology to take advantage of international growth
opportunities.

Building a dynamic workforce with the expertise to execute at
Halliburton’s high standard of service quality is critical to our
international expansion. In 2007, this workforce grew to more
than 50,000. It comprises over 100 nationalities, with the majority
working in their home countries. We now have 12 training centers
worldwide, integrating new workers and advancing the skills of our
existing workforce, building upon their professional and technical
competencies.

A comprehensive global supply chain capable of supporting
our planned growth is also a necessity. In 2007, we opened four
new regional manufacturing facilities in Asia and Latin America,
designed to create new regional supply chains to complement
our current worldwide sourcing capability. These new centers
will create a more responsive organization for our international
customers while building regional supply networks that support
local economies.

We are also making our research and development efforts more
geographically diverse. Last year, we opened a technology center
in Pune, India – our ﬁ rst outside of North America and Europe.

HALLIBURTON 2007 ANNUAL R EP ORT 3

There, PhD-level scientists and engineers collaborate
to advance our global expertise by focusing on those
technologies that will advance our production enhancement,
drilling ﬂ uids and cementing product lines.

Integrated technology strategy leads the industry.
We are meeting the challenges of increasing reservoir
recovery with new technologies that address the industry’s
most important needs: reducing uncertainty in developing
the reservoir, providing precise well placement and
optimizing reservoir drainage for improved recovery
rates, and creating new ways of increasing the efﬁ ciency
of the development process.

We are now building on the foundation of RTO expertise
to serve a wider scope of customer challenges, speciﬁ cally
increasing reservoir recovery. We are expanding the RTO
concept into what we call the Digital AssetTM – a real-time
collaborative environment to model, measure and optimize
our customers’ assets. Our consulting expertise and reservoir
knowledge will help customers improve the performance of
their assets.

The evolution of the Digital Asset will become a source of
signiﬁ cant competitive advantage for us in 2008 and beyond
as it transforms the ways in which we anticipate solutions to
industry challenges.

Our Completion and Production Division is continually
expanding its technology portfolio, creating solutions to
address the recovery of conventional and unconventional
hydrocarbons. We are integrating production and completion
services to produce a higher level of control and effectiveness,
enhancing the production from our customers’ new and old
reservoirs. Our innovative approaches in providing solutions
for ultra-deepwater and complex well intervention are
strengthening our completion service market position.

Through our Drilling and Evaluation Division, we are
delivering next-generation reservoir data management
techniques and integrated interpretation and visualization
technologies to provide our customers with enhanced
exploration and development tools. Developments in
our sampling and deep-reading imaging sensors reduce
positional and geological uncertainty and help illuminate
reservoirs for our customers. New drilling systems
are providing improved reliability in complex wells and
high-pressure, high-temperature environments.

Today, we produce and share digital data, communicate
this data in real time, and then use it to create models for
simulation and, ultimately, designing solutions.

The future will bring new sensor technologies and capabilities
that enable better, faster decisions.

Our leadership in Real Time Operations (RTO) services is a
driving force in this strategy. Engineers and geoscientists
monitor and control remote well construction and production
operations from centers that may be located several hundred
miles from the wellsite, offering the ability to send instructions
directly to downhole tools and receive real-time data streams
in return. In 2007, we performed nearly 18,000 real-time jobs
– double the number from 2006 – and we expect this number
to expand signiﬁ cantly as we help transform the way the
industry works.

Growth strategy yields strong ﬁ nancial results.
We are conﬁ dent that our accelerated investments in
our people and infrastructure for international growth,
and our well-integrated technology strategy, will increase
service intensity over time and continue to set us apart
in the industry.

These elements are delivering increasing ﬁ nancial returns
and strong international growth rates. Operating income has
increased 62 percent in the last two years, with 58 percent
of that increase coming from international activity. Return on
shareholders’ equity grew to 35 percent in 2007.

We are well positioned to play a pivotal role in meeting the
increasingly complex needs of the industry, and we look
forward to that work with conﬁ dence and enthusiasm.

Finally, we owe our success to the dedication and creativity of
our employees – our faces of energy – who continue to invent
new technologies, deliver outstanding service quality and
contribute to the life of their communities. It starts with them –
they are our greatest source of competitive advantage.

Sincerely,

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

Albert O. Cornelison, Jr.
Executive Vice President and
General Counsel

Mark A. McCollum
Executive Vice President and
Chief Financial Officer

Timothy J. Probert
Executive Vice President, Strategy
and Corporate Development

HALLIBU RTON 2 007 ANNUAL REPO RT

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K

(Mark One)
[X]

Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2007

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

[ ]
For the transition period from ______ to ______
Commission File Number 001-03492

HALLIBURTON COMPANY
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)

75-2677995
(I.R.S. Employer
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:

Title of each class
Common Stock par value $2.50 per share

Name of each Exchange on
which registered
New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes X No ______

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes No X

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject
to such filing requirements for the past 90 days.
Yes X No ______

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. [X]

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

Large accelerated filer
Non-accelerated filer

[X]
[ ]

Accelerated filer
Smaller reporting company

[ ]
[ ]

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

The aggregate market value of Common Stock held by nonaffiliates on June 29, 2007, determined using the per share closing price on the New
York Stock Exchange Composite tape of $34.50 on that date was approximately $30,691,000,000.

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

Portions of the Halliburton Company Proxy Statement for our 2008 Annual Meeting of Stockholders (File No. 001-03492) are incorporated by
reference into Part III of this report.

2007 ANNUAL REPORT HALLI BURTON

HALLIBURTON 2007 A NNUAL REPORT

HALLIBURTON COMPANY
Index to Form 10-K
For the Year Ended December 31, 2007

Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Submission of Matters to a Vote of Security Holders

PART I
Item 1.
Item 1(a).
Item 1(b).
Item 2.
Item 3.
Item 4.
EXECUTIVE OFFICERS OF THE REGISTRANT
PART II
Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters,

and Issuer Purchases of Equity Securities

Item 6.
Item 7.

Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and

Results of Operation

Item 7(a).
Item 8.
Item 9.

Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and

Financial Disclosure
Controls and Procedures
Other Information

Item 9(a).
Item 9(b).
MD&A AND FINANCIAL STATEMENTS
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Report on Internal Control Over Financial Reporting
Reports of Independent Registered Public Accounting Firm
Consolidated Statements of Operations
Consolidated Balance Sheets
Consolidated Statements of Shareholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Selected Financial Data (Unaudited)
Quarterly Data and Market Price Information (Unaudited)
PART III
Item 10.
Item 11.
Item 12(a).
Item 12(b).
Item 12(c).
Item 12(d).
Item 13.

Directors, Executive Officers, and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners
Security Ownership of Management
Changes in Control
Securities Authorized for Issuance Under Equity Compensation Plans
Certain Relationships and Related Transactions, and Director

Independence

Principal Accounting Fees and Services

Exhibits and Financial Statement Schedules

Item 14.
PART IV
Item 15.
SIGNATURES

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2007 ANNUAL REPORT HALLI BURTON

HALLIBURTON 2007 A NNUAL REPORT

PART I

Item 1. Business.

General description of business
Halliburton Company’s predecessor was established in 1919 and incorporated under the laws of the State of

Delaware in 1924. Halliburton Company provides a variety of services and products to customers in the energy
industry.

In November 2006, KBR, Inc. (KBR), which at the time was our wholly owned subsidiary, completed an
initial public offering (IPO), in which it sold approximately 32 million shares of KBR common stock at $17.00 per
share. Proceeds from the IPO were approximately $508 million, net of underwriting discounts and commissions and
offering expenses. On April 5, 2007, we completed the separation of KBR from us by exchanging the 135.6 million
shares of KBR common stock owned by us on that date for 85.3 million shares of our common stock. In the second
quarter of 2007, we recorded a gain on the disposition of KBR of approximately $933 million, net of tax and the
estimated fair value of the indemnities and guarantees provided to KBR, which is included in income from
discontinued operations in the consolidated statements of operations.

See Note 4 to the consolidated financial statements for financial information about our business segments.
Description of services and products
We offer a broad suite of services and products to customers through our two business segments for the
exploration, development, and production of oil and gas. We serve major, national, and independent oil and gas
companies throughout the world. The following summarizes our services and products for each business segment.

Completion and Production
Our Completion and Production segment delivers cementing, stimulation, intervention, and completion

services. This segment consists of production enhancement services, completion tools and services, and cementing
services.

Production enhancement services include stimulation services, pipeline process services, sand control

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

Completion tools and services include subsurface safety valves and flow control equipment, surface safety

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

Cementing services involve bonding the well and well casing while isolating fluid zones and maximizing

wellbore stability. Our cementing service line also provides casing equipment.

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

2007 ANNUAL REPORT HALLI BURTON

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

Sperry Drilling Services provides drilling systems and services. These services include directional and

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

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

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

Landmark is a supplier of integrated exploration, drilling, and production software information systems, as

well as consulting and data management services for the upstream oil and gas industry.

The Drilling and Evaluation segment also provides oilfield project management and integrated solutions to

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

Acquisitions and dispositions
In July 2007, we acquired the entire share capital of PSL Energy Services Limited (PSLES), an eastern

hemisphere provider of process, pipeline, and well intervention services. PSLES has operational bases in the United
Kingdom, Norway, the Middle East, Azerbaijan, Algeria, and Asia Pacific. We paid approximately $330 million for
PSLES, consisting of $326 million in cash and $4 million in debt assumed, subject to adjustment for working capital
purposes. As of December 31, 2007, we had recorded goodwill of $163 million and intangible assets of $54 million
on a preliminary basis until our analysis of the fair value of assets acquired and liabilities assumed is complete.
Beginning in August 2007, PSLES’s results of operations are included in our Completion and Production segment.

As a part of our sale of Dresser Equipment Group in 2001, we retained a small equity interest in Dresser

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

In January 2005, we completed the sale of our 50% interest in Subsea 7, Inc. to our joint venture partner,

Siem Offshore (formerly DSND Subsea ASA), for approximately $200 million in cash. As a result of the
transaction, we recorded a gain of approximately $110 million during the first quarter of 2005. We accounted for
our 50% ownership of Subsea 7, Inc. using the equity method in our Completion and Production segment.

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

service company by delivering products and services to our customers that maximize their production and recovery
and realize proven reserves from difficult environments. Our objectives are to:

HALLIBURTON 2007 A NNUAL REPORT

create a balanced portfolio of products and services supported by global infrastructure and
anchored by technology innovation with a well-integrated digital strategy to further differentiate
our company;
reach a distinguished level of operational excellence that reduces costs and creates real value from
everything we do;
preserve a dynamic workforce by being a preferred employer to attract, develop, and retain the
best global talent; and
uphold the ethical and business standards of the company and maintain the highest standards of
health, safety, and environmental performance.

Markets and competition
We are one of the world’s largest diversified energy services companies. Our services and products are
sold in highly competitive markets throughout the world. Competitive factors impacting sales of our services and
products include:

-
-

price;
service delivery (including the ability to deliver services and products on an “as needed, where
needed” basis);
health, safety, and environmental standards and practices;
service quality;
global talent retention;
knowledge of the reservoir;
product quality;

-
-
-
-
-
- warranty; and
-

technical proficiency.

We conduct business worldwide in approximately 70 countries. In 2007, based on the location of services

provided and products sold, 44% of our consolidated revenue was from the United States. In 2006, 45% of our
consolidated revenue was from the United States. In 2005, 43% of our consolidated revenue was from the United
States. No other country accounted for more than 10% of our consolidated revenue during these periods. See Note
4 to the consolidated financial statements for additional financial information about geographic operations in the last
three years. Because the markets for our services and products are vast and cross numerous geographic lines, a
meaningful estimate of the total number of competitors cannot be made. The industries we serve are highly
competitive, and we have many substantial competitors. Largely all of our services and products are marketed
through our servicing and sales organizations.

Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism,

civil unrest, expropriation or other governmental actions, exchange control problems, and highly inflationary
currencies. We believe the geographic diversification of our business activities reduces the risk that loss of
operations in any one country would be material to the conduct of our operations taken as a whole.

Information regarding our exposure to foreign currency fluctuations, risk concentration, and financial

instruments used to minimize risk is included in Management’s Discussion and Analysis of Financial Condition and
Results of Operations – Financial Instrument Market Risk and in Note 14 to the consolidated financial statements.

Customers
Our revenue from continuing operations during the past three years was derived from the sale of services

and products to the energy industry. No customer represented more than 10% of consolidated revenue in any period
presented.

Raw materials
Raw materials essential to our business are normally readily available. Current market conditions have

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

2007 ANNUAL REPORT HALLI BURTON

Research and development costs
We maintain an active research and development program. The program improves existing products and
processes, develops new products and processes, and improves engineering standards and practices that serve the
changing needs of our customers. Our expenditures for research and development activities were $301 million in
2007, $254 million in 2006, and $218 million in 2005, of which over 97% was company-sponsored in each year.

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

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

-
-

the severity and duration of the winter in North America can have a significant impact on gas
storage levels and drilling activity for natural gas;
the timing and duration of the spring thaw in Canada directly affects activity levels due to road
restrictions;
typhoons and hurricanes can disrupt coastal and offshore operations; and
severe weather during the winter months normally results in reduced activity levels in the North
Sea and Russia.

In addition, due to higher spending near the end of the year by customers for software and completion tools
and services, Landmark and completion tools results of operations are generally stronger in the fourth quarter of the
year than at the beginning of the year.

Employees
At December 31, 2007, we employed approximately 51,000 people worldwide compared to approximately

45,000 at December 31, 2006. At December 31, 2007, approximately 12% of our employees were subject to
collective bargaining agreements. Based upon the geographic diversification of these employees, we believe any
risk of loss from employee strikes or other collective actions would not be material to the conduct of our operations
taken as a whole.

Environmental regulation
We are subject to numerous environmental, legal, and regulatory requirements related to our operations

worldwide. In the United States, these laws and regulations include, among others:

-
-
-
-
-

the Comprehensive Environmental Response, Compensation and Liability Act;
the Resource Conservation and Recovery Act;
the Clean Air Act;
the Federal Water Pollution Control Act; and
the Toxic Substances Control Act.

In addition to the federal laws and regulations, states and other countries where we do business may have

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

We do not expect costs related to these remediation requirements to have a material adverse effect on our

consolidated financial position or our results of operations.

HALLIBURTON 2007 A NNUAL REPORT

Web site access
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and

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

Item 1(a). Risk Factors.

Information related to risk factors is described in “Management’s Discussion and Analysis of Financial

Condition and Results of Operations” under “Forward-Looking Information and Risk Factors.”

Item 1(b). Unresolved Staff Comments.

None.

Item 2. Properties.

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

our major facilities and corporate offices.

Location

Operations:

Owned/Leased Description

Completion and Production segment:

Carrollton, Texas
Johor, Malaysia
Monterrey, Mexico

Sao Jose dos Campos, Brazil

Owned
Leased
Leased
Leased

Manufacturing facility
Manufacturing facility
Manufacturing facility
Manufacturing facility

Drilling and Evaluation segment:
Alvarado, Texas
Singapore
The Woodlands, Texas

Shared facilities:

Owned/Leased Manufacturing facility
Manufacturing facility
Leased
Manufacturing facility
Leased

Duncan, Oklahoma
Houston, Texas
Houston, Texas
Houston, Texas
Pune, India

Manufacturing, technology, and camp facilities
Manufacturing and campus facilities

Owned
Owned
Owned/Leased Campus facility
Campus facility
Leased
Technology facility
Leased

Corporate:

Houston, Texas
Dubai, United Arab Emirates

Leased
Leased

Corporate executive offices
Corporate executive offices

2007 ANNUAL REPORT HALLI BURTON

All of our owned properties are unencumbered.
In addition, we have 133 international and 97 United States field camps from which we deliver our services

and products. We also have numerous small facilities that include sales offices, project offices, and bulk storage
facilities throughout the world.

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

Item 3. Legal Proceedings.

Information related to various commitments and contingencies is described in “Management’s Discussion

and Analysis of Financial Condition and Results of Operations” in “Forward-Looking Information and Risk
Factors” and in Note 10 to the consolidated financial statements.

Item 4. Submission of Matters to a Vote of Security Holders.

There were no matters submitted to a vote of security holders during the fourth quarter of 2007.

HALLIBURTON 2007 A NNUAL REPORT

Executive Officers of the Registrant

The following table indicates the names and ages of the executive officers of Halliburton Company as of

February 15, 2008, including all offices and positions held by each in the past five years:

Name and Age

Evelyn M. Angelle
(Age 40)

Peter C. Bernard
(Age 46)

Offices Held and Term of Office
Vice President, Corporate Controller, and Principal Accounting Officer of
Halliburton Company, since January 2008
Vice President, Operations Finance of Halliburton Company,

December 2007 to January 2008

Vice President, Investor Relations of Halliburton Company,
April 2005 to November 2007
Assistant Controller of Halliburton Company, April 2003 to March 2005
Senior Manager of Ernst & Young, April 1996 to March 2003

Senior Vice President, Business Development and Marketing of
Halliburton Company, since June 2006
Senior Vice President, Digital and Consulting Solutions of Halliburton
Company, December 2004 to May 2006
President of Landmark Graphics Corporation, May 2004 to December 2004
Vice President, Marketing and Managed Accounts of Landmark Graphics
Corporation, May 2003 to May 2004
Vice President, Strategic Account Business Development, January 2002

to May 2003

James S. Brown
(Age 53)

President, Western Hemisphere of Halliburton Company, since January 2008
Senior Vice President, Western Hemisphere of Halliburton Company,

June 2006 to December 2007

Senior Vice President, United States Region of Halliburton Company,
December 2003 to June 2006
Vice President, Western Area of Halliburton Company, November 2003

to December 2003

Vice President, Business Development of Halliburton Company, October 2001

to October 2003

* Albert O. Cornelison, Jr.

Executive Vice President and General Counsel of Halliburton Company,

(Age 58)

since December 2002

Director of KBR, Inc., June 2006 to April 2007

C. Christopher Gaut
(Age 51)

President, Drilling and Evaluation Division of Halliburton Company,

since January 2008

Director of KBR, Inc., March 2006 to April 2007
Executive Vice President and Chief Financial Officer of Halliburton Company,
March 2003 to December 2007
Senior Vice President, Chief Financial Officer, and Member – Office of the
President and Chief Operating Officer of ENSCO International, Inc.,
January 2002 to February 2003

2007 ANNUAL REPORT HALLI BURTON

Name and Age

David S. King
(Age 51)

Offices Held and Term of Office
President, Completion and Production Division of Halliburton Company,

since January 2008

Senior Vice President, Completion and Production Division of Halliburton
Company, July 2007 to December 2007
Senior Vice President, Production Optimization of Halliburton Company,

January 2007 to July 2007

Senior Vice President, Eastern Hemisphere of Halliburton Energy Services
Group, July 2006 to December 2006
Senior Vice President, Global Operations of Halliburton Energy Services Group,

July 2004 to July 2006

Vice President, Production Optimization of Halliburton Energy Services Group,
May 2003 to July 2004
Vice President, Production Enhancement of Halliburton Energy Services Group,

January 2000 to May 2003

* David J. Lesar
(Age 54)

Chairman of the Board, President, and Chief Executive Officer of Halliburton
Company, since August 2000

Ahmed H. M. Lotfy
(Age 53)

President, Eastern Hemisphere of Halliburton Company, since January 2008
Senior Vice President, Eastern Hemisphere of Halliburton Company,

January 2007 to December 2007

Vice President, Africa Region of Halliburton Company, January 2005 to

December 2006

Vice President, North Africa Region of Halliburton Company,

June 2002 to December 2004

* Mark A. McCollum

Executive Vice President and Chief Financial Officer of Halliburton Company,

(Age 48)

since January 2008

Director of KBR, Inc., June 2006 to April 2007
Senior Vice President and Chief Accounting Officer of Halliburton Company,
August 2003 to December 2007
Senior Vice President and Chief Financial Officer of Tenneco Automotive, Inc.,
November 1999 to August 2003

Craig W. Nunez
(Age 46)

Senior Vice President and Treasurer of Halliburton Company,

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

HALLIBURTON 2007 A NNUAL REPORT

Name and Age
* Lawrence J. Pope

(Age 39)

Offices Held and Term of Office
Executive Vice President of Administration and Chief Human Resources Officer

of Halliburton Company, since January 2008

Vice President, Human Resources and Administration of Halliburton Company,

January 2006 to December 2007

Senior Vice President, Administration of Kellogg Brown & Root, Inc.,
August 2004 to January 2006
Director, Finance and Administration for Drilling and Formation Evaluation
Division of Halliburton Energy Services Group, July 2003 to August 2004
Division Vice President, Human Resources for Halliburton Energy Services Group,
May 2001 to July 2003

* Timothy J. Probert

(Age 56)

Executive Vice President, Strategy and Corporate Development of Halliburton
Company, since January 2008
Senior Vice President, Drilling and Evaluation of Halliburton Company,

July 2007 to December 2007

Senior Vice President, Drilling Evaluation and Digital Solutions of Halliburton
Company, May 2006 to July 2007
Vice President, Drilling and Formation Evaluation of Halliburton Company,

January 2003 to May 2006

* Members of the Policy Committee of the registrant.

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

and any executive officer of the registrant.

2007 ANNUAL REPORT HALLI BURTON

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 88 of this annual report. Cash dividends on common stock
in the amount of $0.09 per share were paid in June, September, and December of 2007 and $0.075 per share were
paid in March of 2007 and March, June, September, and December of 2006. Our Board of Directors intends to
consider the payment of quarterly dividends on the outstanding shares of our common stock in the future. The
declaration and payment of future dividends, however, will be at the discretion of the Board of Directors and will
depend upon, among other things, future earnings, general financial condition and liquidity, success in business
activities, capital requirements, and general business conditions.

The following graph and table compare total shareholder return on our common stock for the five-year

period ending December 31, 2007, with the Standard & Poor’s 500 Stock Index and the Standard & Poor’s Energy
Composite Index over the same period. This comparison assumes the investment of $100 on December 31, 2002,
and the reinvestment of all dividends. The shareholder return set forth is not necessarily indicative of future
performance.

Halliburton

S&P 500

S&P Energy

500

450

400

350

300

250

200

150

100

0
12/02

12/03

12/04

12/05

12/06

12/07

2002

2003

2004

2005

2006

2007

December 31

Halliburton
Standard & Poor’s 500 Stock Index
Standard & Poor’s Energy Composite Index

$100.00
100.00
100.00

$142.06
128.68
125.63

$217.75
142.69
165.25

$347.23
149.70
217.08

$351.09
173.34
269.64

$432.98
182.86
362.40

At February 18, 2008, there were 19,110 shareholders of record. In calculating the number of shareholders,

we consider clearing agencies and security position listings as one shareholder for each agency or listing.

HALLIBURTON 2007 A NNUAL REPORT

Following is a summary of repurchases of our common stock during the three-month period ended

December 31, 2007.

Total Number of Shares Average Price Paid per

Period
October 1-31
November 1-30
December 1-31
Total

Purchased (a)
36,632
1,270,142
640,977
1,947,751

Share
$ 38.99
$ 36.16
$ 36.58
$ 36.35

Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs (b)

–
1,261,022
590,253
1,851,275

(a) Of the 1,947,751 shares purchased during the three-month period ended December 31, 2007, 96,476 shares were

acquired from employees in connection with the settlement of income tax and related benefit withholding obligations

arising from vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase

common shares.

(b)

In July 2007, our Board of Directors approved an additional increase to our existing common share repurchase program

of up to $2.0 billion, bringing the entire authorization to $5.0 billion. This additional authorization may be used for

open market share purchases or to settle the conversion premium on our 3.125% convertible senior notes, should they be

redeemed. From the inception of this program through December 31, 2007, we have repurchased approximately 79

million shares of our common stock for approximately $2.7 billion at an average price per share of $33.91. These

numbers include the repurchases of approximately 39 million shares of our common stock for approximately $1.4

billion at an average price per share of $34.93 during 2007. As of December 31, 2007, $2.3 billion remained available

under our share repurchase authorization.

Item 6. Selected Financial Data.

Information related to selected financial data is included on page 87 of this annual report.

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

Information related to Management’s Discussion and Analysis of Financial Condition and Results of

Operations is included on pages 13 through 44 of this annual report.

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

Information related to market risk is included in Management’s Discussion and Analysis of Financial
Condition and Results of Operations under the caption “Financial Instrument Market Risk” on page 32 of this annual
report.

2007 ANNUAL REPORT HALLI BURTON

Item 8. Financial Statements and Supplementary Data.

Management’s Report on Internal Control Over Financial Reporting
Reports of Independent Registered Public Accounting Firm
Consolidated Statements of Operations for the years ended December 31, 2007, 2006, and 2005
Consolidated Balance Sheets at December 31, 2007 and 2006
Consolidated Statements of Shareholders’ Equity for the years ended

December 31, 2007, 2006, and 2005

Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006, and 2005
Notes to Consolidated Financial Statements
Selected Financial Data (Unaudited)
Quarterly Data and Market Price Information (Unaudited)

Page No.
45
46
48
49

50
51
52
87
88

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

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9(a). Controls and Procedures.

In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an

evaluation, under the supervision and with the participation of management, including our Chief Executive Officer
and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period
covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded
that our disclosure controls and procedures were effective as of December 31, 2007 to provide reasonable assurance
that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded,
processed, summarized, and reported within the time periods specified in the Securities and Exchange
Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to
ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated
and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as
appropriate, to allow timely decisions regarding required disclosure.

There has been no change in our internal control over financial reporting that occurred during the three

months ended December 31, 2007 that has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.

See page 45 for Management’s Report on Internal Control Over Financial Reporting and page 47 for

Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial
reporting.

Item 9(b). Other Information.

None.

HALLIBURTON 2007 A NNUAL REPORT

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

EXECUTIVE OVERVIEW

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

Business outlook
The outlook for our business remains generally favorable. Despite challenging market conditions in North

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

Outside of North America, our outlook remains positive. Worldwide demand for hydrocarbons continues

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

In 2008, we will focus on:

- maintaining optimal utilization of our equipment and resources;
- managing pricing, particularly in our North America operations;
-
-
-
-

hiring and training additional personnel to meet the increased demand for our services;
continuing the globalization of our manufacturing and supply chain processes;
balancing our United States operations by capitalizing on the trend toward horizontal drilling;
leveraging our technologies to provide our customers with the ability to more efficiently drill and
complete their wells and to increase their productivity. To that end, we opened one international
research and development center with global technology and training missions in 2007 and expect
to open the second in 2008;

- maximizing our position to win meaningful international tenders, especially in deepwater fields,

complex reservoirs, and high-pressure/high-temperature environments;
cultivating our relationships with national oil companies;

2007 ANNUAL REPORT HALLI BURTON

pursuing strategic acquisitions in line with our core products and services to expand our portfolio
in key geographic areas; and
directing our capital spending primarily toward eastern hemisphere operations for service
equipment additions and infrastructure. Capital spending for 2008 is expected to be
approximately $1.7 billion to $1.8 billion.

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

Operations.”

Separation of KBR, Inc.
In November 2006, KBR, Inc. (KBR), which at the time was our wholly owned subsidiary, completed an
initial public offering (IPO), in which it sold approximately 32 million shares of KBR common stock. On April 5,
2007, we completed the separation of KBR from us by exchanging the 135.6 million shares of KBR common stock
owned by us on that date for 85.3 million shares of our common stock. Consequently, KBR operations have been
reclassified as discontinued operations in the consolidated financial statements for all periods presented. See Note 2
to our consolidated financial statements for further information.
Foreign Corrupt Practices Act investigations
The Securities and Exchange Commission (SEC) is conducting a formal investigation into whether
improper payments were made to government officials in Nigeria. The Department of Justice (DOJ) is also
conducting a related criminal investigation. See Note 10 to our consolidated financial statements for further
information.

Other corporate matters
Subsequent to the KBR separation, in the third quarter of 2007, we realigned our products and services to
improve operational and cost management efficiencies, better serve our customers, and become better aligned with
the process of exploring for and producing from oil and natural gas wells. We now operate under two divisions,
which form the basis for the two operating segments we now report: the Completion and Production segment and
the Drilling and Evaluation segment.

In May 2007, the Board of Directors increased the quarterly dividend by $0.015 per common share, or

20%, to $0.09 per share.

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

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

LIQUIDITY AND CAPITAL RESOURCES

We ended 2007 with cash and equivalents of $1.8 billion compared to $2.9 billion at December 31, 2006.
Significant sources of cash
Cash flows from operating activities contributed $2.7 billion to cash in 2007. Growth in revenue and

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

In May 2007, we sold our remaining interest in Dresser, Ltd. for $70 million in cash.
Further available sources of cash. On July 9, 2007, we entered into a new unsecured $1.2 billion five-year

revolving credit facility that replaced our then existing unsecured $1.2 billion five-year revolving credit facility.
The purpose of the new facility is to provide commercial paper support, general working capital, and credit for other
corporate purposes. There were no cash drawings under the facility as of December 31, 2007.

HALLIBURTON 2007 A NNUAL REPORT

Significant uses of cash
Capital expenditures were $1.6 billion in 2007, with increased focus toward building infrastructure and

adding service equipment in support of our expanding operations in the eastern hemisphere. Capital expenditures
were predominantly made in the drilling services, production enhancement, wireline, and cementing product service
lines.

During 2007, we repurchased approximately 39 million shares of our common stock under our share

repurchase program at a cost of approximately $1.4 billion at an average price per share of $34.93.

During 2007, we invested in approximately $332 million of marketable securities, consisting of auction-

rate securities, variable-rate demand notes, and municipal bonds.

We paid $314 million in dividends to our shareholders in 2007. In May 2007, the Board of Directors

authorized a dividend increase of $0.015 per common share, bringing quarterly dividends to $0.09 per common
share for the remainder of 2007.

In the third quarter of 2007, we purchased the entire share capital of PSL Energy Services Limited

(PSLES), an eastern hemisphere provider of process, pipeline, and well intervention services, for $326 million in
cash and $4 million in debt assumed upon acquisition.

In January 2007, we acquired all of the intellectual property, current assets, and existing wireline services

business associated with Ultraline Services Corporation, a division of Savanna Energy Services Corp., for
approximately $178 million.

Future uses of cash. In July 2007, our Board of Directors approved an increase to our existing common

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

Capital spending for 2008 is expected to be approximately $1.7 billion to $1.8 billion. The capital

expenditures forecast for 2008 is primarily directed toward our drilling services, wireline and perforating,
production enhancement, and cementing operations. We will continue to explore opportunities for acquisitions that
will enhance or augment our current portfolio of products and services, including those with unique technologies or
distribution networks in areas where we do not already have large operations. Further, as market conditions change,
we will continue to evaluate the allocation of our cash between acquisitions and stock buybacks in order to provide
good return for our shareholders.

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

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

in 2008.

The following table summarizes our significant contractual obligations and other long-term liabilities as of

December 31, 2007:

Millions of dollars
Long-term debt
Interest on debt (a)
Operating leases
Purchase obligations
Pension funding obligations
Total

2008
$ 159
138
180
1,292
30
$ 1,799

2009
$ 12
129
131
125
–
$ 397

Payments Due
2010
$ 755
129
104
39
–
$ 1,027

2011
3
87
74
11
–
$ 175

2012
3
87
40
1
–
$ 131

Thereafter
$ 1,854
2,582
172
8
–
$ 4,616

Total
$ 2,786
3,152
701
1,476
30
$ 8,145

(a)

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

2007 ANNUAL REPORT HALLI BURTON

With the adoption of Financial Accounting Standards Board (FASB) Interpretation No. 48 (FIN 48), we

had $425 million of gross unrecognized tax benefits at December 31, 2007, of which we estimate $189 million may
require a cash payment. We estimate that $102 million may be settled within the next 12 months, although the
amounts are not agreed with tax authorities. We are not able to reasonably estimate in which future periods the
remaining amounts will ultimately be settled and paid.

Other factors affecting liquidity
Letters of credit. In the normal course of business, we have agreements with banks under which

approximately $2.2 billion of letters of credit, surety bonds, or bank guarantees were outstanding as of December 31,
2007, including $1.1 billion that relate to KBR. These KBR letters of credit, surety bonds, or bank guarantees are
being guaranteed by us in favor of KBR’s customers and lenders. KBR has agreed to compensate us for these
guarantees and indemnify us if we are required to perform under any of these guarantees. Some of the outstanding
letters of credit have triggering events that would entitle a bank to require cash collateralization.

Credit ratings. The credit ratings for our long-term debt are A2 with Moody’s Investors Service and A

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

BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS

We operate in approximately 70 countries throughout the world to provide a comprehensive range of

discrete and integrated services and products to the energy industry. The majority of our consolidated revenue is
derived from the sale of services and products to major, national, and independent oil and gas companies worldwide.
We serve the upstream oil and gas industry throughout the lifecycle of the reservoir: from locating hydrocarbons
and managing geological data, to drilling and formation evaluation, well construction and completion, and
optimizing production through the life of the field. Our two business segments are the Completion and Production
segment and the Drilling and Evaluation segment. The two KBR segments have been reclassified as discontinued
operations as a result of the separation of KBR.

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

Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism,

civil unrest, force majeure, war or other armed conflict, expropriation or other governmental actions, inflation,
exchange control problems, and highly inflationary currencies. We believe the geographic diversification of our
business activities reduces the risk that loss of operations in any one country would be material to our consolidated
results of operations.

Activity levels within our business segments are significantly impacted by spending on upstream
exploration, development, and production programs by major, national, and independent oil and gas companies.
Also impacting our activity is the status of the global economy, which impacts oil and gas consumption.

Some of the more significant barometers of current and future spending levels of oil and gas companies are

oil and gas prices, the world economy, and global stability, which together drive worldwide drilling activity. Our
financial performance is significantly affected by oil and gas prices and worldwide rig activity, which are
summarized in the following tables.

HALLIBURTON 2007 A NNUAL REPORT

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)
West Texas Intermediate
United Kingdom Brent

2007
$ 71.91
$ 72.21

2006
$ 66.17
$ 65.35

2005
$ 56.30
$ 54.45

Average United States Gas Prices (dollars per million British

thermal units, or mmBtu)

Henry Hub

$ 6.97

$ 6.81

$ 8.79

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

follows:

Land vs. Offshore
United States:
Land
Offshore
Total

Canada:

Land
Offshore
Total

International (excluding Canada):

Land
Offshore
Total
Worldwide total
Land total
Offshore total

Oil vs. Gas
United States:
Oil
Gas
Total

Canada:
Oil
Gas
Total

International (excluding Canada):

Oil
Gas
Total
Worldwide total
Oil total
Gas total

2007

2006

2005

1,694
73
1,767

341
3
344

719
287
1,006
3,117
2,754
363

1,558
90
1,648

467
3
470

656
269
925
3,043
2,681
362

1,287
93
1,380

454
4
458

593
258
851
2,689
2,334
355

2007

2006

2005

297
1,470
1,767

128
216
344

784
222
1,006
3,117
1,209
1,908

273
1,375
1,648

110
360
470

709
216
925
3,043
1,092
1,951

194
1,186
1,380

100
358
458

651
200
851
2,689
945
1,744

2007 ANNUAL REPORT HALLI BURTON

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

After declining from record highs during the third and fourth quarters of 2006, WTI oil spot prices

averaged $72.00 per barrel in 2007 and are expected to average $87.00 per barrel in 2008 according to the Energy
Information Administration (EIA). Between mid-December 2006 and mid-January 2007, the WTI crude oil price
fell about $12 per barrel to a low of $50.51 per barrel, as warm weather reduced demand for heating fuels
throughout most of the United States. However, the WTI price recovered to over $66 per barrel by the end of March
2007, as the weather turned colder than normal and geopolitical tensions intensified. Crude oil prices continued to
rise to record levels over the $99 per barrel mark throughout 2007 due to a tight world oil supply and demand
balance, ending the year at approximately $96 per barrel. We expect that oil prices will remain at levels sufficient to
sustain, and likely grow, our customers’ current levels of spending due to a combination of the following factors:
continued growth in worldwide petroleum demand, despite high oil prices;
projected production growth in non-Organization of Petroleum Exporting Countries (non-OPEC)
supplies is not expected to accommodate world wide demand growth;

-
-

- OPEC’s commitment to control production;
- modest increases in OPEC’s current and forecasted production capacity; and
-

geopolitical tensions in major oil-exporting nations.

According to the International Energy Agency’s (IEA) January 2008 “Oil Market Report,” the outlook for

world oil demand remains strong, with China, the Middle East, and Europe accounting for approximately 52% of the
expected demand growth in 2008. Excess oil production capacity is expected to remain constrained and that, along
with increased demand, is expected to keep supplies tight. Thus, any unexpected supply disruption or change in
demand could lead to fluctuating prices. The IEA forecasts world petroleum demand growth in 2008 to increase 2%
over 2007.

North America operations. Volatility in natural gas prices has the potential to impact our customers'

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

It is common practice in the United States oilfield services industry to sell services and products based on a

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

HALLIBURTON 2007 A NNUAL REPORT

Focus on international growth. Consistent with our strategy to grow our international operations, we

expect to continue to invest capital and increase manufacturing capacity to bring new tools online to serve the high
demand for our services. Following is a brief discussion of some of our recent initiatives:

- we opened a corporate office in Dubai, United Arab Emirates, allowing us to focus more attention
on customer relationships in that part of the world, particularly with national oil companies;
in order to continue to supply our customers with leading-edge services and products, we have
increased our technology spending during 2007 as compared to the prior year. Our plans are
progressing for new international research and development centers with global technology and
training missions. We opened one in Pune, India in the third quarter of 2007, and we expect to
open a second facility in Singapore in 2008;

- we are expanding our manufacturing capability and capacity to meet the increasing demands for

our services and products. In 2007, we opened manufacturing plants in Mexico, Brazil, Malaysia,
and Singapore. Having manufacturing facilities closer to our worksites allows us to more
efficiently deploy equipment to our field operations, as well as locally source employees and
materials;
as our workforce becomes more global, the need for regional training centers increases. To meet
the increasing need for technical training, we opened a new training center in Tyumen, Russia
during the first quarter of 2007. We have also recently expanded training centers in Malaysia,
Egypt, and Mexico; and
part of our growth strategy includes acquisitions that will enhance or augment our current
portfolio of products and services, including those with unique technologies or distribution
networks in areas where we do not already have large operations;

in January 2007, we acquired Ultraline Services Company, a provider of wireline services
in Canada. Prior to this acquisition, we did not have meaningful wireline and perforating
operations in Canada;
in May 2007, we acquired the intellectual property, assets, and existing business
associated with Vector Magnetics LLC’s active ranging technology for steam-assisted
gravity drainage applications;
in July 2007, we acquired PSL Energy Services Limited, an eastern hemisphere provider
of process, pipeline, and well intervention services. This acquisition increases our
eastern hemisphere production enhancement operations significantly, putting us in a
strong position in pipeline processing services both in the eastern hemisphere and
globally;
in September 2007, we acquired the intellectual property and substantially all of the
assets and existing business of GeoSmith Consulting Group, LLC, a developer of
software components for 3-D interpretation and geometric modeling applications; and
in November 2007, we acquired the entire share capital of OOO Burservice, a provider of
directional drilling services in Russia.

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

Examples include:

a multiservice contract for work in the Tyumen region of Russia. We will be providing drilling
fluids, waste management, cementing, drill bits, directional drilling, and logging-while-drilling
services;
a contract to provide acidizing, acid fracturing, water control, and nitrogen stimulation services for
a customer in the Bay of Campeche, Mexico;
a contract to provide deepwater sand control completion technology in two offshore fields of
India;
a contract to provide completion products and services to a group of energy companies for
operations throughout Malaysia for a term of five years;

2007 ANNUAL REPORT HALLI BURTON

-
-

a contract to provide exploration and development testing services in high pressure, high
temperature environments in Brazil;
a five-year contract for sand control completions for over 200 wells in offshore China;
a three-year contract to provide a full range of subsurface services, including drilling and
formation evaluation, slickline, fluids, cementing services, and production enhancement in Papua
New Guinea;
a contract to provide completion products and services in Indonesia; and
a contract to manage the drilling and completion of 58 land wells in the southern region of
Mexico.

HALLIBURTON 2007 A NNUAL REPORT

RESULTS OF OPERATIONS IN 2007 COMPARED TO 2006

REVENUE:
Millions of dollars
Completion and Production
Drilling and Evaluation
Total revenue

By geographic region:
Completion and Production:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia

Total
Drilling and Evaluation:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia

Total
Total revenue by region:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia

2007

$ 8,386
6,878
$ 15,264

2006

$ 7,221
5,734
$ 12,955

Increase
$ 1,165
1,144
$ 2,309

Percentage
Change

16%
20
18%

$ 4,655
756
1,767
1,208
8,386

$ 4,275
583
1,436
927
7,221

2,478
1,042
1,933
1,425
6,878

7,133
1,798
3,700
2,633

2,183
931
1,424
1,196
5,734

6,458
1,514
2,860
2,123

380
173
331
281
1,165

295
111
509
229
1,144

675
284
840
510

9%
30
23
30
16

14
12
36
19
20

10
19
29
24

2007 ANNUAL REPORT HALLI BURTON

OPERATING INCOME (LOSS):
Millions of dollars
Completion and Production
Drilling and Evaluation
Corporate and other
Total operating income

2007
$ 2,199
1,485
(186)
$ 3,498

2006
$ 2,140
1,328
(223)
$ 3,245

Increase
(Decrease)
59
$
157
37
253

Percentage
Change
3%

12
17

By geographic region:
Completion and Production:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia

Total
Drilling and Evaluation:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia

Total

Total operating income by region:

$ 1,404
170
330
295
2,199

$ 1,476
130
324
210
2,140

552
179
414
340
1,485

595
170
263
300
1,328

(72)
40
6
85
59

(43)
9
151
40
157

(5)%
31
2
40
3

(7)
5
57
13
12

(excluding Corporate and other):
North America
Latin America
Europe/Africa/CIS
Middle East/Asia

(6)
16
27
25
All periods presented reflect the new segment structure and the reclassification of certain amounts between the
segments/regions and “Corporate and other.”

2,071
300
587
510

1,956
349
744
635

(115)
49
157
125

Note 1

–

The increase in consolidated revenue in 2007 compared to 2006 spanned all four regions in both segments

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

The increase in consolidated operating income was primarily derived from the eastern hemisphere, which

increased 26% compared to 2006. Operating income for 2007 was positively impacted by a $49 million gain
recorded on the sale of our remaining interest in Dresser, Ltd. and negatively impacted by $34 million in charges
related to the impairment of an oil and gas property and $32 million in charges for environmental reserves.
Operating income for 2006 included a $48 million gain on the sale of lift boats in west Africa and the North Sea and
$47 million of insurance proceeds for business interruptions resulting from the 2005 Gulf of Mexico hurricanes.

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

HALLIBURTON 2007 A NNUAL REPORT

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

The Completion and Production segment operating income improvement spanned all regions except North

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

Drilling and Evaluation revenue increase in 2007 compared to 2006 was derived from all four regions.

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

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

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

NONOPERATING ITEMS

Interest expense decreased $11 million in 2007 compared to 2006, primarily due to the repayment in

August 2006 of $275 million of our medium-term notes.

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

2007 ANNUAL REPORT HALLI BURTON

(Provision) benefit for income taxes from continuing operations in 2007 of $907 million resulted in an

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

Income from discontinued operations, net of income tax provision in 2007 primarily consisted of an

approximate $933 million net gain recorded on the disposition of KBR.

HALLIBURTON 2007 A NNUAL REPORT

RESULTS OF OPERATIONS IN 2006 COMPARED TO 2005

REVENUE:
Millions of dollars
Completion and Production
Drilling and Evaluation
Total revenue

By geographic region:
Completion and Production:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia

Total
Drilling and Evaluation:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia

Total
Total revenue by region:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia

2006

$ 7,221
5,734
$ 12,955

2005

$ 5,495
4,605
$ 10,100

Increase
$ 1,726
1,129
$ 2,855

Percentage
Change
31%
25
28%

$ 4,275
583
1,436
927
7,221

$ 3,118
542
1,123
712
5,495

$ 1,157
41
313
215
1,726

2,183
931
1,424
1,196
5,734

6,458
1,514
2,860
2,123

1,701
802
1,151
951
4,605

4,819
1,344
2,274
1,663

482
129
273
245
1,129

1,639
170
586
460

37%
8
28
30
31

28
16
24
26
25

34
13
26
28

2007 ANNUAL REPORT HALLI BURTON

OPERATING INCOME (LOSS):
Millions of dollars
Completion and Production
Drilling and Evaluation
Corporate and other
Total operating income

2006
$ 2,140
1,328
(223)
$ 3,245

2005
$ 1,524
840
(200)
$ 2,164

Increase
(Decrease)
616
$
488
(23)
$ 1,081

Percentage
Change

40%
58
(12)
50%

By geographic region:
Completion and Production:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia

Total
Drilling and Evaluation:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia

Total

Total operating income by region

$ 1,476
130
324
210
2,140

$ 1,046
126
203
149
1,524

595
170
263
300
1,328

365
77
207
191
840

430
4
121
61
616

230
93
56
109
488

41%
3
60
41
40

63
121
27
57
58

(excluding Corporate and other):
North America
Latin America
Europe/Africa/CIS
Middle East/Asia

47
48
43
50
All periods presented reflect the new segment structure and the reclassification of certain amounts between the
segments/regions and “Corporate and other.”

1,411
203
410
340

2,071
300
587
510

660
97
177
170

Note 1 –

The increase in consolidated revenue in 2006 compared to 2005 predominantly resulted from increased

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

The increase in consolidated operating income was primarily due to improved demand due to increased rig

activity and improved pricing and asset utilization. Operating income for 2006 included a $48 million gain on the
sale of lift boats in west Africa and the North Sea and $47 million of insurance proceeds for business interruptions
resulting from the 2005 Gulf of Mexico hurricanes. Operating income in 2005 was adversely impacted by an
estimated $45 million due to Gulf of Mexico hurricanes.

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

HALLIBURTON 2007 A NNUAL REPORT

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

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

Drilling and Evaluation revenue increase in 2006 compared to 2005 was derived from all four regions in all

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

Drilling and Evaluation operating income increase compared to 2005 spanned all geographic regions, with

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

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

2007 ANNUAL REPORT HALLI BURTON

NONOPERATING ITEMS

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

Interest income increased $75 million in 2006 compared to 2005 due to higher cash investment balances.
Other, net increased $15 million in 2006 compared to 2005. The 2005 year included costs related to our

accounts receivable securitization facility, which had no outstanding amounts.

(Provision) benefit for income taxes from continuing operations in 2006 of $1 billion resulted in an

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

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

our results of KBR.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements requires the use of judgments and estimates. Our critical
accounting policies are described below to provide a better understanding of how we develop our assumptions and
judgments about future events and related estimations and how they can impact our financial statements. A critical
accounting estimate is one that requires our most difficult, subjective, or complex estimates and assessments and is
fundamental to our results of operations. We identified our most critical accounting policies and estimates to be:

-
-
-
-
-

forecasting our effective tax rate, including our future ability to utilize foreign tax credits and the
realizability of deferred tax assets, and providing for uncertain tax positions;
percentage-of-completion accounting for long-term, construction-type contracts;
legal and investigation matters;
valuations of indemnities;
pensions; and
allowance for bad debts.

We base our estimates on historical experience and on various other assumptions we believe to be
reasonable according to the current facts and circumstances, the results of which form the basis for making
judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We
believe the following are the critical accounting policies used in the preparation of our consolidated financial
statements, as well as the significant estimates and judgments affecting the application of these policies. This
discussion and analysis should be read in conjunction with our consolidated financial statements and related notes
included in this report.

We have discussed the development and selection of these critical accounting policies and estimates with

the Audit Committee of our Board of Directors, and the Audit Committee has reviewed the disclosure presented
below.

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

a current tax liability or asset is recognized for the estimated taxes payable or refundable on tax
returns for the current year;
a deferred tax liability or asset is recognized for the estimated future tax effects attributable to
temporary differences and carryforwards;

HALLIBURTON 2007 A NNUAL REPORT

the measurement of current and deferred tax liabilities and assets is based on provisions of the
enacted tax law, and the effects of potential future changes in tax laws or rates are not considered;
and
the value of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that,
based on available evidence, are not expected to be realized.

We determine deferred taxes separately for each tax-paying component (an entity or a group of entities that

is consolidated for tax purposes) in each tax jurisdiction. That determination includes the following procedures:

identifying the types and amounts of existing temporary differences;

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

rate;

- measuring the total deferred tax asset for deductible temporary differences and operating loss

carryforwards using the applicable tax rate;

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

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

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

We have operations in approximately 70 countries other than the United States. Consequently, we are

subject to the jurisdiction of a significant number of taxing authorities. The income earned in these various
jurisdictions is taxed on differing bases, including income actually earned, income deemed earned, and revenue-
based tax withholding. The final determination of our tax liabilities involves the interpretation of local tax laws, tax
treaties, and related authorities in each jurisdiction. Changes in the operating environment, including changes in tax
law and currency/repatriation controls, could impact the determination of our tax liabilities for a tax year.

Tax filings of our subsidiaries, unconsolidated affiliates, and related entities are routinely examined in the

normal course of business by tax authorities. These examinations may result in assessments of additional taxes,
which we work to resolve with the tax authorities and through the judicial process. Predicting the outcome of
disputed assessments involves some uncertainty. Factors such as the availability of settlement procedures,
willingness of tax authorities to negotiate, and the operation and impartiality of judicial systems vary across the
different tax jurisdictions and may significantly influence the ultimate outcome. We review the facts for each
assessment, and then utilize assumptions and estimates to determine the most likely outcome and provide taxes,
interest, and penalties as needed based on this outcome. We provide for uncertain tax positions pursuant to FIN 48,
“Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” FIN 48, as amended
May 2007 by FASB Staff Position FIN 48-1, “Definition of ‘Settlement’ in FASB Interpretation No. 48,” prescribes
a minimum recognition threshold and measurement methodology that a tax position taken or expected to be taken in
a tax return is required to meet before being recognized in the financial statements. It also provides guidance for
derecognition classification, interest and penalties, accounting in interim periods, disclosure, and transition.

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

2007 ANNUAL REPORT HALLI BURTON

Percentage of completion
Revenue from long-term contracts to provide well construction and completion services is reported on the
percentage-of-completion method of accounting. This method of accounting requires us to calculate job profit to be
recognized in each reporting period for each job based upon our projections of future outcomes, which include:

-
-
-
-

estimates of the total cost to complete the project;
estimates of project schedule and completion date;
estimates of the extent of progress toward completion; and
amounts of any probable unapproved claims and change orders included in revenue.

Progress is generally based upon physical progress related to contractually defined units of work. At the

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

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

At least quarterly, significant projects are reviewed in detail by senior management. There are many

factors that impact future costs, including but not limited to weather, inflation, labor and community disruptions,
timely availability of materials, productivity, and other factors as outlined in our “Risk Factors.” These factors can
affect the accuracy of our estimates and materially impact our future reported earnings.

Legal and investigation matters
As discussed in Note 10 of our consolidated financial statements, as of December 31, 2007, we have

accrued an estimate of the probable and estimable costs for the resolution of some of these legal and investigation
matters. For other matters for which the liability is not probable and reasonably estimable, we have not accrued any
amounts. Attorneys in our legal department monitor and manage all claims filed against us and review all pending
investigations. Generally, the estimate of probable costs related to these matters is developed in consultation with
internal and outside legal counsel representing us. Our estimates are based upon an analysis of potential results,
assuming a combination of litigation and settlement strategies. The precision of these estimates is impacted by the
amount of due diligence we have been able to perform. We attempt to resolve these matters through settlements,
mediation, and arbitration proceedings when possible. If the actual settlement costs, final judgments, or fines, after
appeals, differ from our estimates, our future financial results may be adversely affected. We have in the past
recorded significant adjustments to our initial estimates of these types of contingencies.

HALLIBURTON 2007 A NNUAL REPORT

Indemnity valuations
We provided indemnification in favor of KBR for certain contingent liabilities related to Foreign Corrupt

Practices Act (FCPA) investigations and the Barracuda-Caratinga bolts matter. See Note 2 to the consolidated
financial statements for further information. FASB Interpretation No. 45 (FIN 45), “Guarantor’s Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others – An
Interpretation of FASB Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34,” requires
recognition of third-party indemnities at their inception. Therefore, in accordance with FIN 45, we recorded our
estimate of the fair market value of these indemnities as of the date of KBR’s separation. The amounts recorded for
the FCPA and Barracuda-Caratinga indemnities were based upon analyses conducted by a third-party valuation
expert. The valuation models employed a probability-weighted cost analysis, with certain assumptions based upon
the accumulation of data and knowledge of the relevant issues. Periodically, a determination will be made as to
whether any material changes in facts or circumstances have occurred that would impact assumptions used in the
third-party valuation.

Pensions
Our pension benefit obligations and expenses are calculated using actuarial models and methods, in

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

Discount rates are determined annually and are based on the prevailing market rate of a portfolio of high-
quality debt instruments with maturities matching the expected timing of the payment of the benefit obligations.
Expected long-term rates of return on plan assets are determined annually and are based on an evaluation of our plan
assets, historical trends, and experience, taking into account current and expected market conditions. Plan assets are
comprised primarily of equity and debt securities. As we have both domestic and international plans, these
assumptions differ based on varying factors specific to each particular country or economic environment.

The discount rate utilized in 2007 to determine the projected benefit obligation at the measurement date for
our United States non-terminating pension plans ranged from 6.03% to 6.19%, an increase from the 5.75% discount
rate that was utilized in 2006. The discount rate utilized to determine the projected benefit obligation at the
measurement date for our United Kingdom pension plan, which constitutes 76% of our international plans and 67%
of all plans, increased from 5.0% at September 30, 2006 to 5.7% at September 30, 2007. The following table
illustrates the sensitivity to changes in certain assumptions, holding all other assumptions constant, for the United
Kingdom pension plan.

Millions of dollars
25-basis-point decrease in discount rate
25-basis-point increase in discount rate

Pension Expense
in 2007
$ 3
$ (3)

Effect on

Pension Benefit Obligation
at December 31, 2007

$
$

40
(38)

2007 ANNUAL REPORT HALLI BURTON

Our defined benefit plans reduced pretax earnings by $48 million in 2007, $45 million in 2006, and $37

million in 2005. Included in the amounts were earnings from our expected pension returns of $47 million in 2007,
$37 million in 2006, and $35 million in 2005. Unrecognized actuarial gains and losses were being recognized over a
period of one to 24 years, which represented the expected remaining service life of the employee group. Our
unrecognized actuarial gains and losses arose from several factors, including experience and assumptions changes in
the obligations and the difference between expected returns and actual returns on plan assets. Actual returns were
$68 million in 2007, $65 million in 2006, and $83 million in 2005. The difference between actual and expected
returns is deferred and recorded net of tax in other comprehensive income as actuarial gain or loss and is recognized
as future pension expense. Our net actuarial loss, net of tax, at December 31, 2007 was $46 million. On a pretax
basis, $3 million of our net actuarial loss at December 31, 2007 will be recognized as a component of our expected
2008 pension expense. During 2007, we made contributions to fund our defined benefit plans of $41 million, which
included $16 million contributed to our United Kingdom plan. We expect to make additional contributions in 2008
of approximately $30 million.

The actuarial assumptions used in determining our pension benefits may differ materially from actual

results due to changing market and economic conditions, higher or lower withdrawal rates, and longer or shorter life
spans of participants. While we believe that the assumptions used are appropriate, differences in actual experience
or changes in assumptions may materially affect our financial position or results of operations.

Allowance for bad debts
We evaluate our accounts receivable through a continuous process of assessing our portfolio on an

individual customer and overall basis. This process consists of a thorough review of historical collection
experience, current aging status of the customer accounts, financial condition of our customers, and whether the
receivables involve retentions. We also consider the economic environment of our customers, both from a
marketplace and geographic perspective, in evaluating the need for an allowance. Based on our review of these
factors, we establish or adjust allowances for specific customers and the accounts receivable portfolio as a whole.
This process involves a high degree of judgment and estimation, and frequently involves significant dollar amounts.
Accordingly, our results of operations can be affected by adjustments to the allowance due to actual write-offs that
differ from estimated amounts. Our estimates of allowances for bad debts have historically been accurate. Over the
last five years, our estimates of allowances for bad debts, as a percentage of notes and accounts receivable before the
allowance, have ranged from 1.5% to 7.3%. At December 31, 2007, allowance for bad debts totaled $49 million or
1.6% of notes and accounts receivable before the allowance, and at December 31, 2006, allowance for bad debts
totaled $40 million or 1.5% of notes and accounts receivable before the allowance. A 1% change in our estimate of
the collectibility of our notes and accounts receivable balance as of December 31, 2007 would have resulted in a $31
million adjustment to 2007 total operating costs and expenses.

OFF BALANCE SHEET ARRANGEMENTS

At December 31, 2007, we had no material off balance sheet arrangements, except for operating leases.

For information on our contractual obligations related to operating leases, see “Management’s Discussion and
Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Future uses of cash.”

FINANCIAL INSTRUMENT MARKET RISK

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

-
-

HALLIBURTON 2007 A NNUAL REPORT

- market cycles; and
-

the type of derivative instruments used.

We do not consider any of these risk management activities to be material. See Note 1 to the consolidated
financial statements for additional information on our accounting policies on derivative instruments. See Note 14 to
the consolidated financial statements for additional disclosures related to financial instruments.

Interest rate risk
We have exposure to interest rate risk from our long-term debt.
The following table represents principal amounts of our long-term debt at December 31, 2007 and related

weighted average interest rates on the repaid amounts by year of maturity for our long-term debt.

Millions of dollars
Fixed-rate debt:
Repayment amount ($US)
Weighted average
interest rate on
repaid amount

Variable-rate debt:
Repayment amount ($US)
Weighted average
interest rate on
repaid amount

2008

2009

2010

2011

2012

Thereafter

Total

$ 150

$ 3

$ 753

$ 1,856

$ 2,769

5.6%

5.5% 5.5%

5.5%

4.7%

5.0%

$ 9

–

8.5%

–

8.5%

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

ENVIRONMENTAL MATTERS

We are subject to numerous environmental, legal, and regulatory requirements related to our operations

worldwide. In the United States, these laws and regulations include, among others:

-
-
-
-
-

the Comprehensive Environmental Response, Compensation, and Liability Act;
the Resource Conservation and Recovery Act;
the Clean Air Act;
the Federal Water Pollution Control Act; and
the Toxic Substances Control Act.

In addition to the federal laws and regulations, states and other countries where we do business may have

We do not expect costs related to these remediation requirements to have a material adverse effect on our
consolidated financial position or our results of operations. Our accrued liabilities for environmental matters were
$72 million as of December 31, 2007 and $39 million as of December 31, 2006. Our total liability related to
environmental matters covers numerous properties, including the property in regard to which Dirt, Inc. has brought
suit against Bredero-Shaw (a joint venture in which we formerly held a 50% interest that we sold to the other party
in the venture, ShawCor Ltd., in 2002), Halliburton Energy Services, Inc., and ShawCor Ltd. See Note 10 to our
consolidated financial statements for further information regarding this matter.

2007 ANNUAL REPORT HALLI BURTON

We have subsidiaries that have been named as potentially responsible parties along with other third parties
for 9 federal and state superfund sites for which we have established a liability. As of December 31, 2007, those 9
sites accounted for approximately $10 million of our total $72 million liability. For any particular federal or state
superfund site, since our estimated liability is typically within a range and our accrued liability may be the amount
on the low end of that range, our actual liability could eventually be well in excess of the amount accrued. Despite
attempts to resolve these superfund matters, the relevant regulatory agency may at any time bring suit against us for
amounts in excess of the amount accrued. With respect to some superfund sites, we have been named a potentially
responsible party by a regulatory agency; however, in each of those cases, we do not believe we have any material
liability. We also could be subject to third-party claims with respect to environmental matters for which we have
been named as a potentially responsible party.

NEW ACCOUNTING PRONOUNCEMENTS

Effective January 1, 2007, we adopted FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty

in Income Taxes, an interpretation of FASB Statement No. 109.” FIN 48, as amended May 2007 by FASB Staff
Position FIN 48-1, “Definition of ‘settlement’ in FASB Interpretation No. 48,” prescribes a minimum recognition
threshold and measurement methodology that a tax position taken or expected to be taken in a tax return is required
to meet before being recognized in the financial statements. It also provides guidance for derecognition,
classification, interest and penalties, accounting in interim periods, disclosure, and transition.

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

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension

and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).” SFAS No. 158
requires an employer to:

recognize on its balance sheet the funded status (measured as the difference between the fair value
of plan assets and the benefit obligation) of pension and other postretirement benefit plans;
recognize, through comprehensive income, certain changes in the funded status of a defined
benefit and postretirement plan in the year in which the changes occur;

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

disclose additional information.

The requirements to recognize the funded status of a benefit plan and the additional disclosure requirements

were effective for fiscal years ending after December 15, 2006. Accordingly, we adopted SFAS No. 158 for our
fiscal year ending December 31, 2006. See Note 15 to our consolidated financial statements for further information.
The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-
end is effective for fiscal years ending after December 15, 2008. We did not elect early adoption of these additional
SFAS No. 158 requirements and will adopt these requirements for our fiscal year ending December 31, 2008.

HALLIBURTON 2007 A NNUAL REPORT

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which is intended to

increase consistency and comparability in fair value measurements by defining fair value, establishing a framework
for measuring fair value, and expanding disclosures about fair value measurements. SFAS No. 157 applies to other
accounting pronouncements that require or permit fair value measurements and is effective for financial statements
issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. In
November 2007, the FASB deferred for one year the application of the fair value measurement requirements to
nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis.
On January 1, 2008, we adopted without material impact on our consolidated financial statements the provisions of
SFAS No. 157 related to financial assets and liabilities and to nonfinancial assets and liabilities measured at fair
value on a recurring basis. Beginning January 1, 2009, we will adopt the provisions for nonfinancial assets and
liabilities that are not required or permitted to be measured at fair value on a recurring basis, which we do not expect
to have a material impact on our consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and

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

In December 2007, the FASB issued Statement No. 141(Revised 2007), “Business Combinations” (SFAS

No. 141(R)). SFAS No. 141(R) requires an acquiring entity to recognize all the assets acquired and liabilities
assumed in a transaction at the acquisition-date fair value with limited exceptions. SFAS No. 141(R) also changes
the accounting treatment for certain specific items. SFAS No. 141(R) applies prospectively to business
combinations for which the acquisition date is on or after the first annual reporting period beginning on or after
December 15, 2008. We will adopt the provisions of SFAS No. 141(R) for business combinations on or after
January 1, 2009.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial
Statements – An Amendment of ARB No. 51.” SFAS No. 160 establishes new accounting and reporting standards
for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement requires
the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements and
separate from the parent’s equity. SFAS No. 160 is effective for fiscal years and interim periods within those fiscal
years beginning on or after December 15, 2008. We will adopt the provision of SFAS No. 160 on January 1, 2009
and have not yet determined the impact on our consolidated financial statements.

In December 2007, the FASB ratified the consensus reached on EITF 07-1, “Accounting for Collaborative

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

FORWARD-LOOKING INFORMATION

The Private Securities Litigation Reform Act of 1995 provides safe harbor provisions for forward-looking
information. Forward-looking information is based on projections and estimates, not historical information. Some
statements in this Form 10-K are forward-looking and use words like “may,” “may not,” “believes,” “do not
believe,” “expects,” “do not expect,” “anticipates,” “do not anticipate,” and other expressions. We may also provide
oral or written forward-looking information in other materials we release to the public. Forward-looking
information involves risk and uncertainties and reflects our best judgment based on current information. Our results
of operations can be affected by inaccurate assumptions we make or by known or unknown risks and uncertainties.
In addition, other factors may affect the accuracy of our forward-looking information. As a result, no forward-
looking information can be guaranteed. Actual events and the results of operations may vary materially.

2007 ANNUAL REPORT HALLI BURTON

We do not assume any responsibility to publicly update any of our forward-looking statements regardless
of whether factors change as a result of new information, future events, or for any other reason. You should review
any additional disclosures we make in our press releases and Forms 10-K, 10-Q, and 8-K filed with or furnished to
the SEC. We also suggest that you listen to our quarterly earnings release conference calls with financial analysts.
While it is not possible to identify all factors, we continue to face many risks and uncertainties that could

cause actual results to differ from our forward-looking statements and potentially materially and adversely affect our
financial condition and results of operations.

RISK FACTORS

Foreign Corrupt Practices Act Investigations

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

TSKJ is a private limited liability company registered in Madeira, Portugal whose members are Technip

SA of France, Snamprogetti Netherlands B.V. (a subsidiary of Saipem SpA of Italy), JGC Corporation of Japan, and
Kellogg Brown & Root LLC (a subsidiary of KBR), each of which had an approximate 25% interest in the venture.
TSKJ and other similarly owned entities entered into various contracts to build and expand the liquefied natural gas
project for Nigeria LNG Limited, which is owned by the Nigerian National Petroleum Corporation, Shell Gas B.V.,
Cleag Limited (an affiliate of Total), and Agip International B.V. (an affiliate of ENI SpA of Italy).

The SEC and the DOJ have been reviewing these matters in light of the requirements of the FCPA. In

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

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

HALLIBURTON 2007 A NNUAL REPORT

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

TSKJ suspended the receipt of services from and payments to Tri-Star Investments and the Japanese

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

As a result of these investigations, information has been uncovered suggesting that, commencing at least 10

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

In June 2004, all relationships with Mr. Stanley and another consultant and former employee of M.W.

Kellogg Limited were terminated. The terminations occurred because of Code of Business Conduct violations that
allegedly involved the receipt of improper personal benefits from Mr. Tesler in connection with TSKJ’s construction
of the Bonny Island project.

In 2006 and 2007, KBR suspended the services of other agents in and outside of Nigeria, including one

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

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

2007 ANNUAL REPORT HALLI BURTON

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

These investigations could also result in third-party claims against us, which may include claims for

special, indirect, derivative or consequential damages, damage to our business or reputation, loss of, or adverse
effect on, cash flow, assets, goodwill, results of operations, business prospects, profits or business value or claims by
directors, officers, employees, affiliates, advisors, attorneys, agents, debt holders, or other interest holders or
constituents of us or our current or former subsidiaries. In addition, we could incur costs and expenses for any
monitor required by or agreed to with a governmental authority to review our continued compliance with FCPA law.
As of December 31, 2007, we are unable to estimate an amount of probable loss or a range of possible loss
related to these matters as it relates to Halliburton directly. However, we provided indemnification in favor of KBR
under the master separation agreement for certain contingent liabilities, including Halliburton’s indemnification of
KBR and any of its greater than 50%-owned subsidiaries as of November 20, 2006, the date of the master separation
agreement, for fines or other monetary penalties or direct monetary damages, including disgorgement, as a result of
a claim made or assessed by a governmental authority in the United States, the United Kingdom, France, Nigeria,
Switzerland, and/or Algeria, or a settlement thereof, related to alleged or actual violations occurring prior to
November 20, 2006 of the FCPA or particular, analogous applicable foreign statutes, laws, rules, and regulations in
connection with investigations pending as of that date, including with respect to the construction and subsequent
expansion by TSKJ of a natural gas liquefaction complex and related facilities at Bonny Island in Rivers State,
Nigeria. We recorded the estimated fair market value of this indemnity regarding FCPA matters described above
upon our separation from KBR. See Note 2 to our consolidated financial statements for additional information.

Our indemnification obligation to KBR does not include losses resulting from third-party claims against

KBR, including claims for special, indirect, derivative or consequential damages, nor does our indemnification
apply to damage to KBR’s business or reputation, loss of, or adverse effect on, cash flow, assets, goodwill, results of
operations, business prospects, profits or business value or claims by directors, officers, employees, affiliates,
advisors, attorneys, agents, debt holders, or other interest holders or constituents of KBR or KBR’s current or former
subsidiaries.

In consideration of our agreement to indemnify KBR for the liabilities referred to above, KBR has agreed

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

HALLIBURTON 2007 A NNUAL REPORT

Barracuda-Caratinga Arbitration

We also provided indemnification in favor of KBR under the master separation agreement for all out-of-

pocket cash costs and expenses (except for legal fees and other expenses of the arbitration so long as KBR controls
and directs it), or cash settlements or cash arbitration awards in lieu thereof, KBR may incur after November 20,
2006 as a result of the replacement of certain subsea flowline bolts installed in connection with the Barracuda-
Caratinga project. Under the master separation agreement, KBR currently controls the defense, counterclaim, and
settlement of the subsea flowline bolts matter. As a condition of our indemnity, for any settlement to be binding
upon us, KBR must secure our prior written consent to such settlement’s terms. We have the right to terminate the
indemnity in the event KBR enters into any settlement without our prior written consent. See Note 2 to our
consolidated financial statements for additional information regarding the KBR indemnification.

At Petrobras’ direction, KBR replaced certain bolts located on the subsea flowlines that failed through mid-

November 2005, and KBR has informed us that additional bolts have failed thereafter, which were replaced by
Petrobras. These failed bolts were identified by Petrobras when it conducted inspections of the bolts. A key issue in
the arbitration is which party is responsible for the designation of the material to be used for the bolts. We
understand that KBR believes that an instruction to use the particular bolts was issued by Petrobras, and as such,
KBR believes the cost resulting from any replacement is not KBR’s responsibility. We understand Petrobras
disagrees. We understand KBR believes several possible solutions may exist, including replacement of the bolts.
Estimates indicate that costs of these various solutions range up to $140 million. In March 2006, Petrobras
commenced arbitration against KBR claiming $220 million plus interest for the cost of monitoring and replacing the
defective bolts and all related costs and expenses of the arbitration, including the cost of attorneys’ fees. We
understand KBR is vigorously defending and pursuing recovery of the costs incurred to date through the arbitration
process and to that end has submitted a counterclaim in the arbitration seeking the recovery of $22 million. The
arbitration panel has set an evidentiary hearing in April 2008.

Impairment of Oil and Gas Properties

At December 31, 2007, we had interests in oil and gas properties totaling $110 million, net of accumulated
depletion, which we account for under the successful efforts method. The majority of this amount is related to one
property in Bangladesh in which we have a 25% non-operating interest. These oil and gas properties are assessed
for impairment whenever changes in facts and circumstances indicate that the properties’ carrying amounts may not
be recoverable. The expected future cash flows used for impairment reviews and related fair-value calculations are
based on judgmental assessments of future production volumes, prices, and costs, considering all available
information at the date of review.

In December 2007, we learned that the drilling program in which we were engaged on one of two prospects

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

A downward trend in estimates of production volumes or prices or an upward trend in costs could result in
an impairment of our oil and gas properties, which in turn could have a material and adverse effect on our results of
operations.

Geopolitical and International Environment

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

Our operations in countries other than the United States accounted for approximately 56% of our
consolidated revenue during 2007 and 55% of our consolidated revenue during 2006. Operations in countries other
than the United States are subject to various risks unique to each country. With respect to any particular country,
these risks may include:

2007 ANNUAL REPORT HALLI BURTON

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expropriation and nationalization of our assets in that country;
political and economic instability;
civil unrest, acts of terrorism, force majeure, war, or other armed conflict;
natural disasters, including those related to earthquakes and flooding;
inflation;
currency fluctuations, devaluations, and conversion restrictions;
confiscatory taxation or other adverse tax policies;
governmental activities that limit or disrupt markets, restrict payments, or limit the movement of
funds;
governmental activities that may result in the deprivation of contract rights; and
governmental activities that may result in the inability to obtain or retain licenses required for
operation.

Due to the unsettled political conditions in many oil-producing countries, our revenue and profits are
subject to the adverse consequences of war, the effects of terrorism, civil unrest, strikes, currency controls, and
governmental actions. Countries where we operate that have significant political risk include: Algeria, Indonesia,
Nigeria, Russia, Venezuela, and Yemen. In addition, military action or continued unrest in the Middle East could
impact the supply and pricing for oil and gas, disrupt our operations in the region and elsewhere, and increase our
costs for security worldwide.

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

Our facilities and our employees are under threat of attack in some countries where we operate. In

addition, the risks related to loss of life of our personnel and our subcontractors in these areas continue.

We are also subject to the risks that our employees, joint venture partners, and agents outside of the United

States may fail to comply with applicable laws.

Military action, other armed conflicts, or terrorist attacks
Military action in Iraq, military tension involving North Korea and Iran, as well as the terrorist attacks of

September 11, 2001 and subsequent terrorist attacks, threats of attacks, and unrest, have caused instability or
uncertainty in the world’s financial and commercial markets and have significantly increased political and economic
instability in some of the geographic areas in which we operate. Acts of terrorism and threats of armed conflicts in
or around various areas in which we operate, such as the Middle East, Nigeria, and Indonesia, could limit or disrupt
markets and our operations, including disruptions resulting from the evacuation of personnel, cancellation of
contracts, or the loss of personnel or assets.

Such events may cause further disruption to financial and commercial markets and may generate greater
political and economic instability in some of the geographic areas in which we operate. In addition, any possible
reprisals as a consequence of the war and ongoing military action in Iraq, such as acts of terrorism in the United
States or elsewhere, could materially and adversely affect us in ways we cannot predict at this time.

Income taxes
We have operations in approximately 70 countries other than the United States. Consequently, we are

subject to the jurisdiction of a significant number of taxing authorities. The income earned in these various
jurisdictions is taxed on differing bases, including net income actually earned, net income deemed earned, and
revenue-based tax withholding. The final determination of our tax liabilities involves the interpretation of local tax
laws, tax treaties, and related authorities in each jurisdiction, as well as the significant use of estimates and
assumptions regarding the scope of future operations and results achieved and the timing and nature of income
earned and expenditures incurred. Changes in the operating environment, including changes in or interpretation of
tax law and currency/repatriation controls, could impact the determination of our tax liabilities for a tax year.

HALLIBURTON 2007 A NNUAL REPORT

Foreign exchange and currency risks
A sizable portion of our consolidated revenue and consolidated operating expenses is in foreign currencies.

As a result, we are subject to significant risks, including:

foreign exchange risks resulting from changes in foreign exchange rates and the implementation of
exchange controls; and
limitations on our ability to reinvest earnings from operations in one country to fund the capital
needs of our operations in other countries.

We conduct business in countries, such as Venezuela, that have nontraded or “soft” currencies which,

because of their restricted or limited trading markets, may be more difficult to exchange for “hard” currency. We
may accumulate cash in soft currencies, and we may be limited in our ability to convert our profits into United
States dollars or to repatriate the profits from those countries.

We selectively use hedging transactions to limit our exposure to risks from doing business in foreign
currencies. For those currencies that are not readily convertible, our ability to hedge our exposure is limited because
financial hedge instruments for those currencies are nonexistent or limited. Our ability to hedge is also limited
because pricing of hedging instruments, where they exist, is often volatile and not necessarily efficient.

In addition, the value of the derivative instruments could be impacted by:

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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;

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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.

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2007 ANNUAL REPORT HALLI BURTON

Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile.

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

Capital spending
Our business is directly affected by changes in capital expenditures by our customers. Some of the changes

that may materially and adversely affect us include:

the consolidation of our customers, which could:

cause customers to reduce their capital spending, which would in turn reduce the demand
for our services and products; and
result in customer personnel changes, which in turn affect the timing of contract
negotiations;

adverse developments in the business and operations of our customers in the oil and gas industry,
including write-downs of reserves and reductions in capital spending for exploration,
development, and production; and
ability of our customers to timely pay the amounts due us.

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Customers
We depend on a limited number of significant customers. While none of these customers represented more
than 10% of consolidated revenue in any period presented, the loss of one or more significant customers could have
a material adverse effect on our business and our consolidated results of operations.

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.

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These transactions also involve risks, and we cannot ensure that:
any acquisitions would result in an increase in income;
any acquisitions would be successfully integrated into our operations and internal controls;
the due diligence prior to an acquisition would uncover situations that could result in legal
exposure or that we will appropriately quantify the exposure from known risks;
any disposition would not result in decreased earnings, revenue, or cash flow;
any dispositions, investments, acquisitions, or integrations would not divert management
resources; or
any dispositions, investments, acquisitions, or integrations would not have a material adverse
effect on our results of operations or financial condition.

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We conduct some operations through joint ventures, where control may be shared with unaffiliated third

parties. As with any joint venture arrangement, differences in views among the joint venture participants may result
in delayed decisions or in failures to agree on major issues. We also cannot control the actions of our joint venture
partners, including any nonperformance, default, or bankruptcy of our joint venture partners. These factors could
potentially materially and adversely affect the business and operations of the joint venture and, in turn, our business
and operations.

Environmental requirements
Our businesses are subject to a variety of environmental laws, rules, and regulations in the United States

and other countries, including those covering hazardous materials and requiring emission performance standards for
facilities. For example, our well service operations routinely involve the handling of significant amounts of waste
materials, some of which are classified as hazardous substances. We also store, transport, and use radioactive and
explosive materials in certain of our operations. Environmental requirements include, for example, those
concerning:

HALLIBURTON 2007 A NNUAL REPORT

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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:

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administrative, civil, and criminal penalties;
revocation of permits to conduct business; and
corrective action orders, including orders to investigate and/or clean up contamination.
Failure on our part to comply with applicable environmental requirements could have a material adverse

effect on our consolidated financial condition. We are also exposed to costs arising from environmental compliance,
including compliance with changes in or expansion of environmental requirements, which could have a material
adverse effect on our business, financial condition, operating results, or cash flows.

We are exposed to claims under environmental requirements and, from time to time, such claims have been
made against us. In the United States, environmental requirements and regulations typically impose strict liability.
Strict liability means that in some situations we could be exposed to liability for cleanup costs, natural resource
damages, and other damages as a result of our conduct that was lawful at the time it occurred or the conduct of prior
operators or other third parties. Liability for damages arising as a result of environmental laws could be substantial
and could have a material adverse effect on our consolidated results of operations.

We are periodically notified of potential liabilities at state and federal superfund sites. These potential

liabilities may arise from both historical Halliburton operations and the historical operations of companies that we
have acquired. Our exposure at these sites may be materially impacted by unforeseen adverse developments both in
the final remediation costs and with respect to the final allocation among the various parties involved at the sites.
For any particular federal or state superfund site, since our estimated liability is typically within a range and our
accrued liability may be the amount on the low end of that range, our actual liability could eventually be well in
excess of the amount accrued. The relevant regulatory agency may bring suit against us for amounts in excess of
what we have accrued and what we believe is our proportionate share of remediation costs at any superfund site.
We also could be subject to third-party claims, including punitive damages, with respect to environmental matters
for which we have been named as a potentially responsible party.

Changes in environmental requirements may negatively impact demand for our services. For example, oil

and natural gas exploration and production may decline as a result of environmental requirements (including land
use policies responsive to environmental concerns). A decline in exploration and production, in turn, could
materially and adversely affect us.

Law and regulatory requirements
In the countries in which we conduct business, we are subject to multiple and, at times, inconsistent

regulatory regimes, including those that govern our use of radioactive materials, explosives, and chemicals in the
course of our operations. Various national and international regulatory regimes govern the shipment of these items.
Many countries, but not all, impose special controls upon the export and import of radioactive materials, explosives,
and chemicals. Our ability to do business is subject to maintaining required licenses and complying with these
multiple regulatory requirements applicable to these special products. In addition, the various laws governing
import and export of both products and technology apply to a wide range of services and products we offer. In turn,
this can affect our employment practices of hiring people of different nationalities because these laws may prohibit
or limit access to some products or technology by employees of various nationalities. Changes in, compliance with,
or our failure to comply with these laws may negatively impact our ability to provide services in, make sales of
equipment to, and transfer personnel or equipment among some of the countries in which we operate and could have
a material adverse affect on the results of operations.

Raw materials
Raw materials essential to our business are normally readily available. Current market conditions have

triggered constraints in the supply chain of certain raw materials, such as sand, cement, and specialty metals. The
majority of our risk associated with the current supply chain constraints occurs in those situations where we have a
relationship with a single supplier for a particular resource.

2007 ANNUAL REPORT HALLI BURTON

Intellectual property rights
We rely on a variety of intellectual property rights that we use in our services and products. We may not be

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

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

Reliance on management
We depend greatly on the efforts of our executive officers and other key employees to manage our
operations. The loss or unavailability of any of our executive officers or other key employees could have a material
adverse effect on our business.
Technical personnel
Many of the services that we provide and the products that we sell are complex and highly engineered and

often must perform or be performed in harsh conditions. We believe that our success depends upon our ability to
employ and retain technical personnel with the ability to design, utilize, and enhance these services and products. In
addition, our ability to expand our operations depends in part on our ability to increase our skilled labor force. The
demand for skilled workers is high, and the supply is limited. A significant increase in the wages paid by competing
employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or
both. If either of these events were to occur, our cost structure could increase, our margins could decrease, and our
growth potential could be impaired.

Weather
Our business could be materially and adversely affected by severe weather, particularly in the Gulf of

Mexico where we have operations. Repercussions of severe weather conditions may include:

evacuation of personnel and curtailment of services;

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inability to deliver materials to jobsites in accordance with contract schedules; and
loss of productivity.

Because demand for natural gas in the United States drives a significant amount of our business, warmer than
normal winters in the United States are detrimental to the demand for our services to gas producers.

HALLIBURTON 2007 A NNUAL REPORT

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Halliburton Company is responsible for establishing and maintaining adequate internal

control over financial reporting as defined in the Securities Exchange Act Rule 13a-15(f).

Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore,

even those systems determined to be effective can provide only reasonable assurance with respect to financial
statement preparation and presentation. Further, because of changes in conditions, the effectiveness of internal
control over financial reporting may vary over time.

Under the supervision and with the participation of our management, including our chief executive officer

and chief financial officer, we conducted an evaluation to assess the effectiveness of our internal control over
financial reporting as of December 31, 2007 based upon criteria set forth in the Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our
assessment, we believe that, as of December 31, 2007, our internal control over financial reporting is effective.

HALLIBURTON COMPANY

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

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

2007 ANNUAL REPORT HALLI BURTON

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders
Halliburton Company:

We have audited the accompanying consolidated balance sheets of Halliburton Company and subsidiaries as of
December 31, 2007 and 2006, and the related consolidated statements of operations, shareholders’ equity, and cash
flows for each of the years in the three-year period ended December 31, 2007. These consolidated financial
statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on
these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
financial position of Halliburton Company and subsidiaries as of December 31, 2007 and 2006, and the results of
their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, in
conformity with U.S. generally accepted accounting principles.

As discussed in Notes 11, 12 and 15, respectively, to the consolidated financial statements, the Company changed its
methods of accounting for uncertainty in income taxes as of January 1, 2007, its method of accounting for stock-
based compensation plans as of January 1, 2006, and its method of accounting for defined benefit and other
postretirement plans as of December 31, 2006, respectively.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), Halliburton Company’s internal control over financial reporting as of December 31, 2007, based on criteria
established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), and our report dated February 20, 2008 expressed an unqualified opinion on the
effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP
Houston, Texas
February 20, 2008

HALLIBURTON 2007 A NNUAL REPORT

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders
Halliburton Company:

We have audited Halliburton Company’s internal control over financial reporting as of December 31, 2007, based
on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). Halliburton Company's management is responsible for
maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in the accompanying Management’s Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial
reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether effective internal control over financial reporting was maintained in all material respects. Our audit
included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk. Our audit also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company's internal control over financial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.

In our opinion, Halliburton Company maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by
COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), the consolidated balance sheets of Halliburton Company as of December 31, 2007 and 2006, and the related
consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year
period ended December 31, 2007, and our report dated February 20, 2008 expressed an unqualified opinion on those
consolidated financial statements.

/s/ KPMG LLP
Houston, Texas
February 20, 2008

2007 ANNUAL REPORT HALLI BURTON

HALLIBURTON COMPANY
Consolidated Statements of Operations

Millions of dollars and shares except per share data
Revenue:
Services
Product sales
Total revenue
Operating costs and expenses:
Cost of services
Cost of sales
General and administrative
Gain on sale of business assets, net
Total operating costs and expenses
Operating income
Interest expense
Interest income
Other, net
Income from continuing operations before income

taxes and minority interest
(Provision) benefit for income taxes
Minority interest in net income of subsidiaries
Income from continuing operations
Income from discontinued operations, net of income

tax provision of $15, $183, and $205

Net income

Basic income per share:
Income from continuing operations
Income from discontinued operations, net
Net income per share

Diluted income per share:
Income from continuing operations
Income from discontinued operations, net
Net income per share

Year Ended December 31
2006

2007

2005

$ 11,256
4,008
15,264

$ 9,643
3,312
12,955

$ 7,513
2,587
10,100

8,167
3,358
293
(52)
11,766
3,498
(154)
124
(8)

3,460
(907)
(29)
2,524

6,751
2,675
342
(58)
9,710
3,245
(165)
129
(10)

3,199
(1,003)
(19)
2,177

5,614
2,129
294
(101)
7,936
2,164
(196)
54
(25)

1,997
125
(15)
2,107

975
3,499

171
$ 2,348

251
$ 2,358

$ 2.76
1.07
$ 3.83

$ 2.15
0.16
$ 2.31

$ 2.09
0.25
$ 2.34

$ 2.66
1.02
$ 3.68

$ 2.07
0.16
$ 2.23

$ 2.03
0.24
$ 2.27

Basic weighted average common shares outstanding
Diluted weighted average common shares outstanding

913
950

1,014
1,054

1,010
1,038

See notes to consolidated financial statements.

HALLIBURTON 2007 A NNUAL REPORT

Liabilities and Shareholders’ Equity

$ 13,135

$ 16,860

HALLIBURTON COMPANY
Consolidated Balance Sheets

Millions of dollars and shares except per share data

Assets

Current assets:

Cash and equivalents

Receivables (less allowance for bad debts of $49 and $40)

Inventories

Investments in marketable securities

Current deferred income taxes

Current assets of discontinued operations

Other current assets

Total current assets

Property, plant, and equipment, net of accumulated depreciation of $4,126 and $3,793

Goodwill

Noncurrent deferred income taxes

Noncurrent assets of discontinued operations

Other assets

Total assets

Current liabilities:

Accounts payable

Accrued employee compensation and benefits

Income tax payable

Deferred revenue

Current maturities of long-term debt

Current liabilities of discontinued operations

Other current liabilities

Total current liabilities

Long-term debt

Employee compensation and benefits

Noncurrent liabilities of discontinued operations

Other liabilities

Total liabilities

Minority interest in consolidated subsidiaries

Shareholders’ equity:

Common shares, par value $2.50 per share – authorized 2,000 shares, issued 1,063

and 1,060 shares

Paid-in capital in excess of par value

Accumulated other comprehensive loss

Retained earnings

Less 183 and 62 shares of treasury stock, at cost

Total shareholders’ equity

Total liabilities and shareholders’ equity

See notes to consolidated financial statements.

December 31

2007

2006

1,847

$ 2,918

3,093

1,459

388

376
(cid:2)

410

7,573

3,630

790

348
(cid:2)

794

2,629

1,235

205

3,898

285

11,190

2,557

486

448

1,497

682

768

575

209

159
(cid:2)

491

2,411

2,627

403
(cid:2)

734

6,175

2,657

1,741

(104)

8,202

12,496

5,630

6,866

655

496

146

171

2,831

409

4,734

2,783

474

981

443

9,415

2,650

1,689

(437)

5,051

8,953

1,577

7,376

$ 13,135

$ 16,860

2007 ANNUAL REPORT HALLI BURTON

HALLIBURTON COMPANY
Consolidated Statements of Shareholders’ Equity

Millions of dollars and shares
Balance at January 1
Dividends and other transactions with shareholders
Sale of stock by a subsidiary
Adoption of Statement of Financial Accounting

Standards No. 158

Adoption of Financial Accounting Standards Board

Interpretation No. 48

Shares exchanged in KBR, Inc. exchange offer
Other

Comprehensive income:
Net income
Net cumulative translation adjustments
Defined benefit and other postretirement plans adjustments
Net unrealized gains (losses) on investments

and derivatives
Total comprehensive income

2007
$ 7,376
(1,499)

–

(30)
(2,809)
(4)

3,499
(23)
355

1
3,832

2006
$ 6,372
(1,324)
117

2005
$ 3,932
202
–

(218)

–

–
34

–

2,348
34
2

11
2,395

2,358
(41)
(54)

(25)
2,238

Balance at December 31

$ 6,866

$ 7,376

$ 6,372

See notes to consolidated financial statements.

HALLIBURTON 2007 A NNUAL REPORT

HALLIBURTON COMPANY
Consolidated Statements of Cash Flows

Millions of dollars
Cash flows from operating activities:
Net income
Adjustments to reconcile net income to net cash from operations:
Income from discontinued operations
Depreciation, depletion, and amortization
Provision (benefit) for deferred income taxes
Gain on sale of business assets
Asbestos and silica liability payment related to Chapter 11 filing
Collection of asbestos- and silica-related insurance receivables
Other changes:
Receivables
Accounts receivable facilities transactions
Inventories
Accounts payable
Contributions to pension plans
Other
Cash flows from discontinued operations
Total cash flows from operating activities
Cash flows from investing activities:
Sales of property, plant, and equipment
Dispositions of business assets, net of cash disposed
Investments – restricted cash
Sales (purchases) of short-term investments in marketable securities, net
Acquisitions of business assets, net of cash acquired
Disposal of KBR, Inc. cash upon separation
Capital expenditures
Other investing activities
Cash flows from discontinued operations
Total cash flows from investing activities
Cash flows from financing activities:
Proceeds from exercises of stock options
Tax benefit from exercise of options and restricted stock
Borrowings (repayments) of short-term debt, net
Proceeds from long-term debt, net of offering costs
Payments on long-term debt
Payments of dividends to shareholders
Payments to reacquire common stock
Other financing activities
Cash flows from discontinued operations
Total cash flows from financing activities
Effect of exchange rate changes on cash, including $0, $50, and $(3) related to

discontinued operations

Increase (decrease) in cash and equivalents
Cash and equivalents at beginning of year, including $1,461, $390, and $188

related to discontinued operations

Cash and equivalents at end of year, including $0, $1,461, and $390 related

to discontinued operations

Supplemental disclosure of cash flow information:
Cash payments during the year for:
Interest from continuing operations
Income taxes from continuing operations

See notes to consolidated financial statements.

Year Ended December 31
2006

2007

2005

3,499

$ 2,348

$ 2,358

(975)
583
(111)
(52)
–
29

(355)
–
(218)
77
(41)
259
31
2,726

203
70
56
(332)
(563)
(1,461)
(1,583)
(38)
(13)
(3,661)

110
29
9
–
(7)
(314)
(1,374)
(5)
(18)
(1,570)

(27)
(2,532)

4,379

(171)
480
658
(66)
–
167

(494)
–
(309)
96
(75)
712
311
3,657

152
98
–
(20)
(27)
–
(834)
(20)
225
(426)

159
53
(13)
–
(324)
(306)
(1,339)
5
485
(1,280)

37
1,988

2,391

(251)
448
(243)
(102)
(2,345)
1,032

(314)
(256)
(151)
102
(39)
252
210
701

106
212
1
891
(108)
–
(575)
(36)
19
510

342
–
8
23
(802)
(254)
(12)
(1)
(24)
(720)

(17)
474

1,917

1,847

$ 4,379

$ 2,391

$
$

144
941

$
$

164
289

$
$

193
203

2007 ANNUAL REPORT HALLI BURTON

HALLIBURTON COMPANY
Notes to Consolidated Financial Statements

Note 1. Description of Company and Significant Accounting Policies

Description of Company
Halliburton Company’s predecessor was established in 1919 and incorporated under the laws of the State of

Delaware in 1924. We are one of the world’s largest oilfield services companies. Our two business segments are
the Completion and Production segment and the Drilling and Evaluation segment. We provide a comprehensive
range of services and products for the exploration, development, and production of oil and gas around the world.

Use of estimates
Our financial statements are prepared in conformity with accounting principles generally accepted in the

United States, requiring us to make estimates and assumptions that affect:

the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements; and
the reported amounts of revenue and expenses during the reporting period.

Ultimate results could differ from those estimates.

Basis of presentation
The consolidated financial statements include the accounts of our company and all of our subsidiaries that

we control or variable interest entities for which we have determined that we are the primary beneficiary. All
material intercompany accounts and transactions are eliminated. Investments in companies in which we have
significant influence are accounted for using the equity method. If we do not have significant influence, we use the
cost method.

As the result of realigning our products and services during the third quarter of 2007, we are now reporting

two business segments. See Note 4 for further information. Additionally, KBR, Inc. (KBR), formerly a wholly
owned subsidiary, is reclassified as discontinued operations in the consolidated financial statements. See Note 2 for
additional information. All prior periods presented reflect these changes.

Certain other prior year amounts have been reclassified to conform to the current year presentation.
Revenue recognition
Overall. Our services and products are generally sold based upon purchase orders or contracts with our

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

Software sales. Sales of perpetual software licenses, net of any deferred maintenance and support fees, are

recognized as revenue upon shipment. Sales of time-based licenses are recognized as revenue over the license
period. Maintenance and support fees are recognized as revenue ratably over the contract period, usually a one-year
duration.

Percentage of completion. Revenue from long-term contracts to provide well construction and completion

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

Sale of stock by a subsidiary
When, as part of a broader corporate reorganization, a subsidiary or affiliate sells unissued shares in a

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

HALLIBURTON 2007 A NNUAL REPORT

Research and development
Research and development expenses are charged to income as incurred. Research and development
expenses were $301 million in 2007, $254 million in 2006, and $218 million in 2005, of which over 97% was
company-sponsored in each year.

Software development costs
Costs of developing software for sale are charged to expense as research and development when incurred

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

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

equivalents, except for cash equivalents of KBR, which are reflected as current assets of discontinued operations at
December 31, 2006.
Inventories
Inventories are stated at the lower of cost or market. Cost represents invoice or production cost for new
items and original cost less allowance for condition for used material returned to stock. Production cost includes
material, labor, and manufacturing overhead. Some domestic manufacturing and field service finished products and
parts inventories for drill bits, completion products, and bulk materials are recorded using the last-in, first-out
method. The remaining inventory is recorded on the average cost method.

Allowance for bad debts
We establish an allowance for bad debts through a review of several factors, including historical collection

experience, current aging status of the customer accounts, and financial condition of our customers.

Property, plant, and equipment
Other than those assets that have been written down to their fair values due to impairment, property, plant,

and equipment are reported at cost less accumulated depreciation, which is generally provided on the straight-line
method over the estimated useful lives of the assets. Accelerated depreciation methods are also used for tax
purposes, wherever permitted. Upon sale or retirement of an asset, the related costs and accumulated depreciation
are removed from the accounts and any gain or loss is recognized. Planned major maintenance costs are generally
expensed as incurred.

Goodwill
The reported amounts of goodwill for each reporting unit are reviewed for impairment on an annual basis
and more frequently when negative conditions such as significant current or projected operating losses exist. The
annual impairment test for goodwill is a two-step process and involves comparing the estimated fair value of each
reporting unit to the reporting unit’s carrying value, including goodwill. If the fair value of a reporting unit exceeds
its carrying amount, goodwill of the reporting unit is not considered impaired, and the second step of the impairment
test is unnecessary. If the carrying amount of a reporting unit exceeds its fair value, the second step of the goodwill
impairment test would be performed to measure the amount of impairment loss to be recorded, if any. Our annual
impairment tests resulted in no goodwill impairment in 2007, 2006, or 2005.

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

2007 ANNUAL REPORT HALLI BURTON

Income taxes
We recognize the amount of taxes payable or refundable for the year. In addition, deferred tax assets and

liabilities are recognized for the expected future tax consequences of events that have been recognized in the
financial statements or tax returns. A valuation allowance is provided for deferred tax assets if it is more likely than
not that these items will not be realized.

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

We recognize interest and penalties related to unrecognized tax benefits within the provision for income

taxes on continuing operations in our consolidated statements of operations.

We generally do not provide income taxes on the undistributed earnings of non-United States subsidiaries

because such earnings are intended to be reinvested indefinitely to finance foreign activities. These additional
foreign earnings could be subject to additional tax if remitted, or deemed remitted, as a dividend; however, it is not
practicable to estimate the additional amount, if any, of taxes payable. Taxes are provided as necessary with respect
to earnings that are not permanently reinvested.

Derivative instruments
At times, we enter into derivative financial transactions to hedge existing or projected exposures to

changing foreign currency exchange rates, interest rates, and commodity prices. We do not enter into derivative
transactions for speculative or trading purposes. We recognize all derivatives on the balance sheet at fair value.
Derivatives are adjusted to fair value and reflected through the results of operations. Gains or losses on foreign
currency derivatives are included in other, net; gains or losses on interest rate derivatives are included in interest
expense; and gains or losses on commodity derivatives are included in operating income. Our derivatives are not
designated as hedges for accounting purposes.
Foreign currency translation
Foreign entities whose functional currency is the United States dollar translate monetary assets and
liabilities at year-end exchange rates, and nonmonetary items are translated at historical rates. Income and expense
accounts are translated at the average rates in effect during the year, except for depreciation, cost of product sales
and revenue, and expenses associated with nonmonetary balance sheet accounts, which are translated at historical
rates. Gains or losses from changes in exchange rates are recognized in consolidated income in the year of
occurrence. Foreign entities whose functional currency is not the United States dollar translate net assets at year-end
rates and income and expense accounts at average exchange rates. Adjustments resulting from these translations are
reflected in the consolidated statements of shareholders’ equity as cumulative translation adjustments.

HALLIBURTON 2007 A NNUAL REPORT

Stock-based compensation
Effective January 1, 2006, we adopted the fair value recognition provisions of Financial Accounting
Standards Board (FASB) Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based
Payment” (SFAS No. 123(R)), using the modified prospective application. Accordingly, we are recognizing
compensation expense for all newly granted awards and awards modified, repurchased, or cancelled after January 1,
2006. Compensation cost for the unvested portion of awards that were outstanding as of January 1, 2006 is being
recognized ratably over the remaining vesting period based on the fair value at date of grant. Also, beginning with
the January 1, 2006 purchase period, compensation expense for our 2002 Employee Stock Purchase Plan (ESPP) is
being recognized. The cumulative effect of this change in accounting principle related to stock-based awards was
immaterial. Prior to January 1, 2006, we accounted for these plans under the recognition and measurement
provisions of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,”
and related interpretations. Under APB No. 25, no compensation expense was recognized for stock options or the
ESPP. Compensation expense was recognized for restricted stock awards. As a result of adopting SFAS No.
123(R), the incremental pretax expense related to employee stock option awards and our ESPP totaled
approximately $33 million in 2006 or $0.02 per diluted share after tax on continuing operations. The incremental
impact to net income related to employee stock option awards and our ESPP in 2006 totaled approximately $26
million.

Total stock-based compensation expense for continuing operations, net of related tax effects, was $62

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

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

2007 ANNUAL REPORT HALLI BURTON

Millions of dollars except per share data
Net income, as reported
Add:
Stock-based compensation expense included in

continuing operations, net of related tax effects

Stock-based compensation expense included in

discontinued operations, net of related tax effects

Less:
Stock-based compensation expense for continuing
operations determined under fair-value-based
method for all awards, net of related tax effects
Stock-based compensation expense for discontinued
operations determined under fair-value-based
method for all awards, net of related tax effects

Net income, pro forma

Basic income per share:
Continuing operations

As reported
Pro forma

Discontinued operations

As reported
Pro forma

Diluted income per share:
Continuing operations

As reported
Pro forma

Discontinued operations

As reported
Pro forma

Year ended
December 31, 2005
$ 2,358

(46)

(15)
$ 2,328

$
$

2.09
2.07

0.25
0.24

2.03
2.01

0.24
0.24

The fair value of options at the date of grant was estimated using the Black-Scholes option pricing model.

The expected volatility of options granted in 2007 and 2006 was a blended rate based upon implied volatility
calculated on actively traded options on our common stock and upon the historical volatility of our common stock.
The expected volatility of options granted in 2005 was based upon the historical volatility of our common stock.
The expected term of options granted in 2007, 2006, and 2005 was based upon historical observation of actual time
elapsed between date of grant and exercise of options for all employees. The assumptions and resulting fair values
of options granted were as follows:

2007
5.14
35.70%
0.89 – 1.14%
3.37 – 5.00%

Year Ended December 31
2006
5.24
42.20%
0.76 – 1.06%
4.30 – 5.03 %

2005
5.00
51.06 – 52.79%
0.73 – 1.16%
3.77 – 4.33%

$ 11.35

$ 14.20

$ 11.42

Expected term (in years)
Expected volatility
Expected dividend yield
Risk-free interest rate
Weighted average grant-date fair value per share

HALLIBURTON 2007 A NNUAL REPORT

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:

Expected term (in years)
Expected volatility
Expected dividend yield
Risk-free interest rate
Weighted average grant-date fair value per share

See Note 12 for further detail on stock incentive plans.

Note 2. KBR Separation

Offering period July 1 through December 31
2005
2006
2007
0.5
0.5
0.5
30.46%
37.77%
29.49%
0.73%
0.80%
1.03%
3.89%
5.29%
4.98%
5.50
9.32
7.97

Offering period January 1 through June 30
2006
0.5
35.65%
0.75%
4.38%
7.91

2007
0.5
34.91%
1.00%
5.09%
7.20

2005
0.5
26.93%
1.16%
3.15%
4.15

In November 2006, KBR completed an initial public offering (IPO), in which it sold approximately 32

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

The following table presents the financial results of KBR, which are reflected as discontinued operations in

our consolidated statements of operations. For accounting purposes, we ceased including KBR’s operations in our
results effective March 31, 2007.

Millions of dollars
Revenue
Operating income
Net income
(a)

2007
$ 2,250
62
$
23 (a)
$

Year Ended December 31
2006
$ 9,621
239
$
180
$

$ 10,141
453
$
250
$
Net income for 2007 represents our 81% share of KBR’s results from January 1, 2007 through
March 31, 2007.

2005

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

2007 ANNUAL REPORT HALLI BURTON

fines or other monetary penalties or direct monetary damages, including disgorgement, as a result
of a claim made or assessed by a governmental authority in the United States, the United
Kingdom, France, Nigeria, Switzerland, and/or Algeria, or a settlement thereof, related to alleged
or actual violations occurring prior to November 20, 2006 of the United States Foreign Corrupt
Practices Act (FCPA) or particular, analogous applicable foreign statutes, laws, rules, and
regulations in connection with investigations pending as of that date, including with respect to the
construction and subsequent expansion by TSKJ of a natural gas liquefaction complex and related
facilities at Bonny Island in Rivers State, Nigeria; and
all out-of-pocket cash costs and expenses, or cash settlements or cash arbitration awards in lieu
thereof, KBR may incur after the effective date of the master separation agreement as a result of
the replacement of the subsea flowline bolts installed in connection with the Barracuda-Caratinga
project. See Note 10 for further discussion of these matters.

As a result of these agreements, we recorded $190 million, as a reduction of the gain on the disposition of

KBR, to reflect the estimated fair value of the above indemnities and guarantees, net of the associated estimated
future tax benefit. The estimated fair value of these indemnities and guarantees is primarily included in “Other
liabilities” on the consolidated balance sheet at December 31, 2007.

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

The tax sharing agreement provides for allocations of United States and certain other jurisdiction tax

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

HALLIBURTON 2007 A NNUAL REPORT

Note 3. Acquisitions and Dispositions
PSL Energy Services Limited
In July 2007, we acquired the entire share capital of PSL Energy Services Limited (PSLES), an eastern

Dresser, Ltd. interest
As a part of our sale of Dresser Equipment Group in 2001, we retained a small equity interest in Dresser

Inc.’s Class A common stock. Dresser Inc. was later reorganized as Dresser, Ltd., and we exchanged our shares for
shares of Dresser, Ltd. In May 2007, we sold our remaining interest in Dresser, Ltd. We received $70 million in
cash from the sale and recorded a $49 million gain. This investment was reflected in “Other assets” on our
consolidated balance sheet at December 31, 2006.
Ultraline Services Corporation
In January 2007, we acquired all intellectual property, current assets, and existing business associated with
Calgary-based Ultraline Services Corporation (Ultraline), a division of Savanna Energy Services Corp. Ultraline is
a provider of wireline services in Canada. We paid approximately $178 million for Ultraline and recorded goodwill
of $124 million and intangible assets of $41 million. Beginning in February 2007, Ultraline’s results of operations
are included in our Drilling and Evaluation segment.

Subsea 7, Inc.
In January 2005, we completed the sale of our 50% interest in Subsea 7, Inc. to our joint venture partner,

Note 4. Business Segment Information

Subsequent to the KBR separation, in the third quarter of 2007, we realigned our products and services to
improve operational and cost management efficiencies, better serve our customers, and become better aligned with
the process of exploring for and producing from oil and natural gas wells. We now operate under two divisions,
which form the basis for the two operating segments we now report: the Completion and Production segment and
the Drilling and Evaluation segment. All periods presented reflect reclassifications related to the change in
operating segments and the reclassification of certain amounts between the operating segments and “Corporate and
other.” The two KBR segments have been reclassified as discontinued operations as a result of the separation of
KBR from us.

Following is a discussion of our operating segments.
Completion and Production delivers cementing, stimulation, intervention, and completion services. This

segment consists of production enhancement services, completion tools and services, and cementing services.
Production enhancement services include stimulation services, pipeline process services, sand control

2007 ANNUAL REPORT HALLI BURTON

Completion tools and services include subsurface safety valves and flow control equipment, surface safety

Cementing services involve bonding the well and well casing while isolating fluid zones and maximizing

wellbore stability. Our cementing service line also provides casing equipment.

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

Sperry Drilling Services provides drilling systems and services. These services include directional and

Landmark is a supplier of integrated exploration, drilling, and production software information systems, as

well as consulting and data management services for the upstream oil and gas industry.

The Drilling and Evaluation segment also provides oilfield project management and integrated solutions to

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

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

losses of unconsolidated affiliates that are accounted for on the equity method is included in revenue and operating
income of the applicable segment.

HALLIBURTON 2007 A NNUAL REPORT

The following tables present information on our business segments.

Operations by business segment

Millions of dollars
Revenue:
Completion and Production
Drilling and Evaluation
Total
Operating income (loss):
Completion and Production
Drilling and Evaluation
Corporate and other
Total
Capital expenditures:
Completion and Production
Drilling and Evaluation
Corporate and other
Total
Depreciation, depletion, and amortization:
Completion and Production
Drilling and Evaluation
Total

Millions of dollars
Total assets:
Completion and Production
Drilling and Evaluation
Shared assets
Corporate and other
Discontinued operations
Total

Year Ended December 31
2006

2005

2007

$ 8,386
6,878
$ 15,264

$ 7,221
5,734
$ 12,955

$ 5,495
4,605
$ 10,100

$ 2,199
1,485
(186)
$ 3,498

$ 2,140
1,328
(223)
$ 3,245

$ 1,524
840
(200)
$ 2,164

791
759
33
$ 1,583

288
295
583

441
390
3
834

239
241
480

309
266
–
575

217
231
448

December 31

2007

2006

$ 4,842
4,606
672
3,015
–
$ 13,135

3,636
3,566
1,216
3,047
5,395
$ 16,860

Not all assets are associated with specific segments. Those assets specific to segments include receivables,

inventories, certain identified property, plant, and equipment (including field service equipment), equity in and
advances to related companies, and goodwill. The remaining assets, such as cash, are considered to be shared
among the segments.

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

Operations by geographic area

Millions of dollars
Revenue:
United States
Other countries
Total

Year Ended December 31
2006

2005

2007

$ 6,673
8,591
$ 15,264

$ 5,869
7,086
$ 12,955

$ 4,317
5,783
$ 10,100

2007 ANNUAL REPORT HALLI BURTON

Millions of dollars
Long-lived assets:
United States
Other countries
Total

December 31

2007

2006

$ 2,733
2,263
$ 4,996

$ 2,045
1,413
$ 3,458

Note 5. Receivables

Our trade receivables are generally not collateralized. At December 31, 2007, 35% of our gross trade

receivables were from customers in the United States. As of December 31, 2006, 39% of our gross trade receivables
were from customers in the United States. No other country accounted for more than 10% of our gross trade
receivables at these dates.

Note 6. Inventories

Inventories are stated at the lower of cost or market. In the United States we manufacture certain finished

products and parts inventories for drill bits, completion products, bulk materials, and other tools that are recorded
using the last-in, first-out method, which totaled $71 million at December 31, 2007 and $58 million at December 31,
2006. If the average cost method had been used, total inventories would have been $25 million higher than reported
at December 31, 2007 and $20 million higher than reported at December 31, 2006. The cost of the remaining
inventory was recorded on the average cost method. Inventories consisted of the following:

December 31

Millions of dollars
Finished products and parts
Raw materials and supplies
Work in process
Total

2007
$ 1,042
325
92
$ 1,459

2006

883
256
96
$ 1,235

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

and $63 million at December 31, 2006.

Note 7. Investments

Investments in marketable securities
At December 31, 2007, we had $388 million invested in marketable securities, consisting of auction-rate
securities and variable-rate demand notes which were classified as available-for-sale and recorded at fair value. In
January 2008, we sold the entire balance of marketable securities at face value. At December 31, 2006, our
investments in marketable securities were $20 million.

Restricted cash
At December 31, 2007, we had restricted cash of $52 million, which primarily consisted of collateral for

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

HALLIBURTON 2007 A NNUAL REPORT

Note 8. Property, Plant, and Equipment

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

December 31

Millions of dollars
Land
Buildings and property improvements
Machinery, equipment, and other
Total
Less accumulated depreciation
Net property, plant, and equipment

2007

46
869
6,841
7,756
4,126
$ 3,630

2006
37
782
5,531
6,350
3,793
$ 2,557

The percentages of total buildings and property improvements and total machinery, equipment, and other,

excluding oil and gas investments, are depreciated over the following useful lives:

Buildings and Property
Improvements
2007
17%
50%
13%
20%

2006
18%
49%
14%
19%

Machinery, Equipment,
and Other

2007
22%
72%
6%

2006
26%
68%
6%

1 – 10 years
11 – 20 years
21 – 30 years
31 – 40 years

1 – 5 years
6 – 10 years
11 – 20 years

Note 9. Debt

Short-term notes payable consist primarily of overdraft and other facilities with varying rates of interest.

Long-term debt consisted of the following:

Millions of dollars
3.125% convertible senior notes due July 2023
5.5% senior notes due October 2010
7.6% debentures due August 2096
8.75% debentures due February 2021
Medium-term notes due 2008 through 2027
Other
Total long-term debt
Less current portion
Noncurrent portion of long-term debt

December 31

2007
$ 1,200
749
294
185
299
59
2,786
159
$ 2,627

2006
$ 1,200
749
294
185
299
82
2,809
26
$ 2,783

Convertible notes
In June 2003, we issued $1.2 billion of 3.125% convertible senior notes due July 15, 2023, with interest

payable semiannually. The notes are our senior unsecured obligations ranking equally with all of our existing and
future senior unsecured indebtedness.

2007 ANNUAL REPORT HALLI BURTON

The notes are convertible under any of the following circumstances:

-
-

during any calendar quarter if the last reported sale price of our common stock for at least 20
trading days during the period of 30 consecutive trading days ending on the last trading day of the
previous quarter is greater than or equal to 120% of the conversion price per share of our common
stock on such last trading day;
if the notes have been called for redemption;
upon the occurrence of specified corporate transactions that are described in the indenture
governing the notes; or
during any period in which the credit ratings assigned to the notes by both Moody’s Investors
Service and Standard & Poor’s are lower than Ba1 and BB+, respectively, or the notes are no
longer rated by at least one of these rating services or their successors.

The conversion price is $18.825 per share and is subject to adjustment upon the occurrence of stock

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

Subsequent to issuing the notes, we agreed upon conversion to settle the principal amount of the notes in

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

The notes are redeemable for cash at our option on or after July 15, 2008. Holders may require us to

repurchase the notes for cash on July 15 of 2008, 2013, or 2018 or, prior to July 15, 2008, in the event of a
fundamental change as defined in the underlying indenture.

Other senior debt
We have issued various senior notes, medium-term notes, and debentures, all of which rank equally with

our existing and future senior unsecured indebtedness. Our senior notes with an aggregate principal amount of $750
million will mature in October 2010 and bear interest at a rate equal to 5.5%, payable semiannually. They are
redeemable by us, in whole or in part, at any time, subject to a redemption price equal to the greater of 100% of the
principal amount of the notes or the sum of the present values of the remaining scheduled payments of principal and
interest due on the notes discounted to the redemption date at the treasury rate plus 25 basis points. The senior notes
were initially offered on a discounted basis at 99.679% of their face value. The discount is being amortized to
interest expense over the life of the notes.

We have outstanding notes under our medium-term note program, including $150 million that will mature
in December 2008 and bear interest at a rate equal to 5.63%, payable semiannually. They are redeemable by us, in
whole or in part, at any time, subject to a redemption price equal to the greater of 100% of the principal amount of
the notes or the sum of the present values of the remaining scheduled payments of principal and interest due on the
notes discounted to the redemption date at the treasury rate plus 15 basis points. In addition, we have notes issued
under the medium-term note program with a principal amount of $45 million that mature in May 2017 and notes
with a principal amount of $104 million that mature in February 2027, which bear interest rates equal to 7.53% and
6.75%, respectively, payable semiannually. The 7.53% and 6.75% notes may not be redeemed prior to maturity.
The medium-term notes do not have sinking fund requirements.

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

HALLIBURTON 2007 A NNUAL REPORT

Revolving credit facilities
On July 9, 2007, we entered into a new unsecured $1.2 billion five-year revolving credit facility that

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

Maturities
Our debt matures as follows: $159 million in 2008; $12 million in 2009; $755 million in 2010; $3 million

in 2011; $3 million in 2012; and $1.9 billion thereafter.

Note 10. Commitments and Contingencies

Foreign Corrupt Practices Act investigations
The Securities and Exchange Commission (SEC) is conducting a formal investigation into whether

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

TSKJ is a private limited liability company registered in Madeira, Portugal whose members are Technip

The SEC and the DOJ have been reviewing these matters in light of the requirements of the FCPA. In

2007 ANNUAL REPORT HALLI BURTON

TSKJ suspended the receipt of services from and payments to Tri-Star Investments and the Japanese

As a result of these investigations, information has been uncovered suggesting that, commencing at least 10

In June 2004, all relationships with Mr. Stanley and another consultant and former employee of M.W.

In 2006 and 2007, KBR suspended the services of other agents in and outside of Nigeria, including one

HALLIBURTON 2007 A NNUAL REPORT

These investigations could also result in third-party claims against us, which may include claims for

Our indemnification obligation to KBR does not include losses resulting from third-party claims against

In consideration of our agreement to indemnify KBR for the liabilities referred to above, KBR has agreed

2007 ANNUAL REPORT HALLI BURTON

Barracuda-Caratinga arbitration
We also provided indemnification in favor of KBR under the master separation agreement for all out-of-

pocket cash costs and expenses (except for legal fees and other expenses of the arbitration so long as KBR controls
and directs it), or cash settlements or cash arbitration awards in lieu thereof, KBR may incur after November 20,
2006 as a result of the replacement of certain subsea flowline bolts installed in connection with the Barracuda-
Caratinga project. Under the master separation agreement, KBR currently controls the defense, counterclaim, and
settlement of the subsea flowline bolts matter. As a condition of our indemnity, for any settlement to be binding
upon us, KBR must secure our prior written consent to such settlement’s terms. We have the right to terminate the
indemnity in the event KBR enters into any settlement without our prior written consent. See Note 2 for additional
information regarding the KBR indemnification.

At Petrobras’ direction, KBR replaced certain bolts located on the subsea flowlines that failed through mid-

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

In early May 2003, we entered into a written memorandum of understanding setting forth the terms upon

which the Moore class action would be settled. In June 2003, the lead plaintiffs filed a motion for leave to file a
second amended consolidated complaint, which was granted by the court. In addition to restating the original
accounting and disclosure claims, the second amended consolidated complaint included claims arising out of the
1998 acquisition of Dresser Industries, Inc. by Halliburton, including that we failed to timely disclose the resulting
asbestos liability exposure (the “Dresser claims”). The memorandum of understanding contemplated settlement of
the Dresser claims as well as the original claims.

In June 2004, the court entered an order preliminarily approving the settlement. Following the transfer of

the case to another district judge, the court held that evidence of the settlement’s fairness was inadequate, denied the
motion for final approval of the settlement, and ordered the parties to mediate. The mediation was unsuccessful.

HALLIBURTON 2007 A NNUAL REPORT

In April 2005, the court appointed new co-lead counsel and named AMSF the new lead plaintiff, directing

that it file a third consolidated amended complaint and that we file our motion to dismiss. The court held oral
arguments on that motion in August 2005, at which time the court took the motion under advisement. In March
2006, the court entered an order in which it granted the motion to dismiss with respect to claims arising prior to June
1999 and granted the motion with respect to certain other claims while permitting AMSF to re-plead some of those
claims to correct deficiencies in its earlier complaint. In April 2006, AMSF filed its fourth amended consolidated
complaint. We filed a motion to dismiss those portions of the complaint that had been re-pled. A hearing was held
on that motion in July 2006, and in March 2007 the court ordered dismissal of the claims against all individual
defendants other than our CEO. The court ordered that the case proceed against our CEO and Halliburton. In
response to a motion by the lead plaintiff, on February 26, 2007, the court ordered the removal and replacement of
their co-lead counsel. In June 2007, upon becoming aware of a United States Supreme Court opinion issued in that
month, the court allowed further briefing on the motion to dismiss filed on behalf of our CEO. That briefing is
complete, but the court has not yet ruled. In September 2007, AMSF filed a motion for class certification, and our
response was filed in November 2007. The case is set for trial in July 2009.

As of December 31, 2007, we had not accrued any amounts related to this matter because we do not believe

that a loss is probable. Further, an estimate of possible loss or range of loss related to this matter cannot be made.

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

Under the insurance settlements entered into as part of the resolution of our Chapter 11 proceedings, we

have agreed to indemnify our insurers under certain historic general liability insurance policies in certain situations.
We have concluded that the likelihood of any claims triggering the indemnity obligations is remote, and we believe
any potential liability for these indemnifications will be immaterial. Further, an estimate of possible loss or range of
loss related to this matter cannot be made. At December 31, 2007, we had not recorded any liability associated with
these indemnifications.

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

As of December 31, 2007, we had not accrued any amounts in connection with this matter because we do

not believe that a loss is probable. Further, an estimate of possible loss or range of loss related to this matter cannot
be made.

2007 ANNUAL REPORT HALLI BURTON

Dirt, Inc. litigation
In April 2005, Dirt, Inc. brought suit in Alabama against Bredero-Shaw (a joint venture in which we

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

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

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

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

We have accrued an amount less than $10 million, which represents our 50% portion of what we believe it

will cost to remediate the site.

Environmental
We are subject to numerous environmental, legal, and regulatory requirements related to our operations

worldwide. In the United States, these laws and regulations include, among others:

-
-
-
-
-

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

We do not expect costs related to these remediation requirements to have a material adverse effect on our
consolidated financial position or our results of operations. Our accrued liabilities for environmental matters were
$72 million as of December 31, 2007 and $39 million as of December 31, 2006. Our total liability related to
environmental matters covers numerous properties, including the property in regard to which Dirt, Inc. has brought
suit against Bredero-Shaw (a joint venture in which we formerly held a 50% interest that we sold to the other party
in the venture, ShawCor Ltd., in 2002), Halliburton Energy Services, Inc., and ShawCor Ltd. See “Dirt, Inc.
litigation” in this note for further information regarding this matter.

HALLIBURTON 2007 A NNUAL REPORT

Letters of credit
In the normal course of business, we have agreements with banks under which approximately $2.2 billion

of letters of credit, surety bonds, or bank guarantees were outstanding as of December 31, 2007, including $1.1
billion that relate to KBR. These KBR letters of credit, surety bonds, or bank guarantees are being guaranteed by us
in favor of KBR’s customers and lenders. KBR has agreed to compensate us for these guarantees and indemnify us
if we are required to perform under any of these guarantees. Some of the outstanding letters of credit have
triggering events that would entitle a bank to require cash collateralization.

Leases
We are obligated under operating leases, principally for the use of land, offices, equipment, manufacturing
and field facilities, and warehouses. Total rentals, net of sublease rentals, were $487 million in 2007, $402 million
in 2006, and $338 million in 2005.

Future total rentals on noncancelable operating leases are as follows: $180 million in 2008; $131 million in

2009; $104 million in 2010; $74 million in 2011; $40 million in 2012; and $172 million thereafter.

Note 11. Income Taxes

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

Millions of dollars
Current income taxes:
Federal
Foreign
State
Total current
Deferred income taxes:
Federal
Foreign
State
Total deferred
(Provision) benefit for income taxes

Year Ended December 31
2006

2005

2007

(560)
(449)
(38)
(1,047)

(156)
(122)
(11)
(289)

129
7
4
140
(907)

(600)
(95)
(19)
(714)
$ (1,003)

22
(116)
(1)
(95)

291
(14)
(57)
220
$ 125

The United States and foreign components of income from continuing operations before income taxes and

minority interest were as follows:

Millions of dollars
United States
Foreign
Total

Year Ended December 31
2006
$ 2,280
919
$ 3,199

2005
$ 1,399
598
$ 1,997

2007
$ 2,219
1,241
$ 3,460

2007 ANNUAL REPORT HALLI BURTON

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

United States statutory rate

Impact of foreign income taxed at different rates

Other impact of foreign operations
Valuation allowance

State income taxes, net of federal income tax benefit

Adjustments of prior year taxes
Other items, net
Total effective tax rate on continuing operations

Year Ended December 31
2006
35.0%
(1.3)
3.1
(3.3)
0.7
(2.1)
(0.7)
31.4%

2007
35.0%
(2.3)
(3.9)
(2.0)
0.3
(0.3)
(0.6)
26.2%

2005
35.0%
0.3
(2.0)
(40.3)
1.1
0.4
(0.8)
(6.3)%

The major component of the difference between the 2007 statutory rate compared to the effective rate is the

favorable impact of the ability to recognize United States foreign tax credits of approximately $205 million. This
amount consists of approximately $68 million of a change in valuation allowance for credits previously recognized
and approximately $137 million reflected in other impact of foreign operations for changes to United States tax
filings to claim foreign tax credits rather than deducting foreign taxes. We now believe we can utilize these credits
currently because we have generated additional taxable income and expect to continue to generate a higher level of
taxable income largely from the growth of our international operations. The major component of the difference
between the 2005 statutory tax rate compared to the effective tax rate is the release of a valuation allowance for
future tax attributes related to United States net operating losses established in prior years. The remaining valuation
allowance on future tax attributes related to United States net operating loss was released in 2006. The primary
components of our deferred tax assets and liabilities and the related valuation allowances were as follows:

HALLIBURTON 2007 A NNUAL REPORT

Millions of dollars
Gross deferred tax assets:

Employee compensation and benefits
Capitalized research and experimentation
Accrued liabilities
Foreign tax credit carryforward

Inventory
Insurance accruals

Software revenue recognition
Net operating loss carryforwards
Alternative minimum tax credit carryforward

Other

Total gross deferred tax assets
Gross deferred tax liabilities:

Depreciation and amortization
Joint ventures, partnerships, and unconsolidated affiliates
Other

Total gross deferred tax liabilities
Valuation allowances:

Net operating loss carryforwards
Foreign tax credit carryforwards
Other

Total valuation allowances
Net deferred income tax asset

December 31

2007

2006

$ 262
94
80
61
63
46
37
24
19
176
862

164
34
55
253

22
–
7
29
$ 580

289
65
64
68
62
45
57
29
66
90
835

135
2
20
157

29
68
–
97
581

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

We established a valuation allowance on certain domestic and foreign operating loss carryforwards on the

basis that we believe these assets will not be utilized in the statutory carryover period.

Effective January 1, 2007, we adopted Financial Accounting Standards Board (FASB) Interpretation No.

48 (FIN 48), “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” FIN 48,
as amended May 2007 by FASB Staff Position FIN 48-1, “Definition of ‘Settlement’ in FASB Interpretation No.
48,” prescribes a minimum recognition threshold and measurement methodology that a tax position taken or
expected to be taken in a tax return is required to meet before being recognized in the financial statements. It also
provides guidance for derecognition, classification, interest and penalties, accounting in interim periods, disclosure,
and transition.

2007 ANNUAL REPORT HALLI BURTON

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

Millions of dollars
Balance at January 1, 2007
Change in prior year tax positions
Change in current year tax positions
Settlements with taxing authorities
Lapse of statute of limitations
Balance at December 31, 2007

Unrecognized
Tax Benefits
242
145
34
(30)
(3)
388

Interest
and Penalties
$

34
–
4
(1)
–
37

At December 31, 2007, $99 million of tax benefits associated with United States foreign tax credits was

included in the balance of unrecognized tax benefits that could be resolved within the next 12 months. A review of
foreign tax documentation is currently underway and will likely be significantly progressed within the next 12
months. Also, as of December 31, 2007, a significant portion of our non-United States unrecognized tax benefits,
while not individually significant, could be settled within the next 12 months. As of December 31, 2007, we
estimated that $289 million of the balance of unrecognized tax benefits, if resolved in our favor, would positively
impact the effective tax rate and, therefore, be recognized as additional tax benefits in our statement of operations.
We file income tax returns in the United States federal jurisdiction and in various states and foreign jurisdictions. In
most cases, we are no longer subject to United States federal, state, and local, or non-United States income tax
examination by tax authorities for years before 1998. Tax filings of our subsidiaries, unconsolidated affiliates, and
related entities are routinely examined in the normal course of business by tax authorities. Currently, our United
States federal tax filings are under review for tax years 2000 through 2005. An unrecognized tax benefit of $6
million related to the 2000 through 2002 tax years could be resolved within the next 12 months.

HALLIBURTON 2007 A NNUAL REPORT

Note 12. Shareholders’ Equity and Stock Incentive Plans

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

Treasury
Stock
$ (477)
–
115
(12)

Deferred
Compensation
$ (74)
–
(24)
–

Retained
Earnings
871
$
(254)
–
–

Accumulated
Other
Comprehensive
Income
$ (146)
–
–
–

–

(24)
–

–

(254)
–

2,358

–

–
–

–

(48)

(54)

(12)

–
–
$ (98)
–
–
–

–
2,358
$ 2,975
(306)
–
–

(13)
(120)
$ (266)
–
–
–

Millions of dollars
Balance at December 31, 2004
Cash dividends paid
Stock plans
Common shares purchased
Tax benefit from exercise of options
and restricted stock
Total dividends and other transactions
with shareholders
Asbestos trust shares
Comprehensive income (loss):
Net income
Other comprehensive income:
Cumulative translation

adjustment

Realization of translation losses
included in net income
Defined benefit and other
postretirement plans
adjustments, net of tax
benefit of $23

Net unrealized losses on

investments and derivatives,

net of tax benefit of $7

Realization of gains on

investments and derivatives,

net of tax provision of $8

Total comprehensive income
Balance at December 31, 2005
Cash dividends paid
Stock plans
Common shares purchased
Tax benefit from exercise of options
and restricted stock
Total dividends and other transactions
with shareholders
Sale of stock by a subsidiary
Reclassification of deferred
compensation
Adoption of SFAS No. 158, net of tax
benefit of $146
Other
Comprehensive income (loss):
Net income
Other comprehensive income:

Cumulative translation adjustment
Realization of translation gains
included in net income
Defined benefit and other
postretirement plans
adjustments, net of tax benefit
of $16

Net unrealized gains on

investments and derivatives, net

of tax benefit of $7
Realization of gains on

investments and derivatives,

net of tax provision of $0

Total comprehensive income
Balance at December 31, 2006

Paid-in
Capital in
Excess
of Par
Value

(869)
–
258
–

Asbestos
Trust
Shares
$ 2,335
–
–
–

–

333
2,037

–
(2,335)

Common
Shares
$ 2,292
–
44
–

–

44
298

–

–
–
$ 2,634
–
16
–

–
–
$ 1,501
–
116
–

–

16
–

–

–
–

–

169
117

(98)

–
–

–

–
–
$ 2,650

–
–
$ 1,689

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–

–

103
–

–

–
–
$ (374)
–
136
(1,339)

–

(1,203)
–

–

–
–

–

–
–
$ (1,577)

–

–
–

–

–
–
–

–

(306)
–

–

–
34

2,348

–

–
–

–

(218)
–

–

(14)

–
2,348
$ 5,051

(1)
47
$ (437)

2007 ANNUAL REPORT HALLI BURTON

Asbestos
Trust
Shares

Deferred
Compensation

Paid-in
Capital in
Excess
of Par
Value
$ 1,689
–
23
–

Common
Shares
$ 2,650
–
7
–

–

–
–
–

–

–
–

–
–
–

–
–

–

–
–
–

–

–
–

–
–
–

–
–

–

Millions of dollars
Balance at December 31, 2006
Cash dividends paid
Stock plans
Common shares purchased
Tax benefit from exercise of options
and restricted stock
Total dividends and other transactions
with shareholders
Shares exchanged in KBR, Inc.
exchange offer
Adoption of FIN 48
Other
Comprehensive income (loss):
Net income
Other comprehensive income:
Cumulative translation

adjustment

Realization of translation gains
included in net income
Defined benefit and other
postretirement plans
adjustments:
Prior service cost:

Plan amendment
Settlements/curtailments

Actuarial gain (loss):

Net gain
Amortization of net loss
Settlements/curtailments
Tax effect on defined benefit
and postretirement plans

KBR, Inc. separation
Defined benefit and other

postretirement plans, net

Net unrealized gains on
investments, net of tax

benefit of $0
Total comprehensive income
Balance at December 31, 2007

Treasury
Stock
$ (1,577)
–
130
(1,374)

–

(1,244)

(2,809)
–
–

–

–
–

–
–
–

–
–

–

–
–

–
–
–
–

–

–
–
–

–

–
–

–
–
–

–
–

–

–
–
–

Accumulated
Other
Comprehensive
Income
$ (437)
–
–
–

Retained
Earnings
$ 5,051
(314)
–
–

–

(314)

–
(30)
(4)

3,499

–

–
–

–
–
–

–
–

–

–
–
–

–

(24)

(2)
5

105
14
7

(45)
271

355

–
3,499
$ 8,202

1
333
$ (104)

–
–
–
–

–

–
–
–

–

–
–

–
–
–

–
–

–

–
–
–

–
–
$ 2,657

–
–
$ 1,741

$(5,630)

Accumulated other comprehensive loss
Millions of dollars
Cumulative translation adjustment
Defined benefit and other postretirement liability adjustments
Unrealized gains (losses) on investments and derivatives
Total accumulated other comprehensive loss

2007

(61)
(45)
2
(104)

Shares of common stock
Millions of shares
Issued
In treasury
Total shares of common stock outstanding

2007

1,063
(183)
880

December 31
2006

(38)
(400)
1
(437)

December 31
2006
1,060
(62)
998

2005

(72)
(184)
(10)
(266)

2005
1,054
(26)
1,028

HALLIBURTON 2007 A NNUAL REPORT

In May 2006, the shareholders increased the number of authorized shares of common stock to two billion.

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

In February 2006, our Board of Directors approved a share repurchase program up to $1.0 billion, which
replaced our previous share repurchase program. In September 2006, our Board of Directors approved an increase
to our existing common share repurchase program of up to an additional $2.0 billion. In July 2007, our Board of
Directors approved an additional increase to our existing common share repurchase program of up to $2.0 billion,
bringing the entire authorization to $5.0 billion. This additional authorization may be used for open market share
purchases or to settle the conversion premium on our 3.125% convertible senior notes, should they be redeemed.
The stock repurchase program does not require a specific number of shares to be purchased and the program may be
effected through solicited or unsolicited transactions in the market or in privately negotiated transactions. The
program may be terminated or suspended at any time. From the inception of this program through December 31,
2007, we have repurchased approximately 79 million shares of our common stock for approximately $2.7 billion at
an average price per share of $33.91. These numbers include the repurchases of approximately 39 million shares of
our common stock for approximately $1.4 billion at an average price per share of $34.93 during 2007. As of
December 31, 2007, $2.3 billion remained available under our share repurchase authorization.

Preferred Stock

Our preferred stock consists of five million total authorized shares at December 31, 2007, of which none

were issued.

Stock Incentive Plans

Our 1993 Stock and Incentive Plan, as amended (1993 Plan), provides for the grant of any or all of the

following types of stock-based awards:

-
-
-
-
-

stock options, including incentive stock options and nonqualified stock options;
restricted stock awards;
restricted stock unit awards;
stock appreciation rights; and
stock value equivalent awards.

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

Under the terms of the 1993 Plan, 98 million shares of common stock have been reserved for issuance to
employees and non-employee directors. The plan specifies that no more than 32 million shares can be awarded as
restricted stock. At December 31, 2007, approximately 18 million shares were available for future grants under the
1993 Plan, of which approximately 10 million shares remained available for restricted stock awards. The stock to be
offered pursuant to the grant of an award under the 1993 Plan may be authorized but unissued common shares or
treasury shares.

In addition to the provisions of the 1993 Plan, we also have stock-based compensation provisions under our

Restricted Stock Plan for Non-Employee Directors and our ESPP.

Each of the active stock-based compensation arrangements is discussed below.
Stock options
All stock options under the 1993 Plan are granted at the fair market value of our common stock at the grant

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

The following table represents our stock options activity during 2007, and includes exercised, forfeited, and

expired shares from our acquired companies’ stock plans.

2007 ANNUAL REPORT HALLI BURTON

Stock Options
Outstanding at January 1, 2007

Granted
Exercised
Forfeited/expired
Converted to KBR, Inc. stock

options

Outstanding at December 31, 2007

Weighted
Average
Exercise
Price
per Share
$ 18.55
32.13
17.30
25.37

Number
of Shares
(in millions)
17.6
1.9
(3.6)
(0.4)

(1.2)
14.3

15.01
$ 20.81

Exercisable at December 31, 2007

10.5

$ 16.94

Weighted
Average
Remaining
Contractual
Term (years)

Aggregate
Intrinsic
Value
(in millions)

5.72

4.64

$ 244

$ 219

The total intrinsic value of options exercised was $68 million in 2007, $123 million in 2006, and $194

million in 2005. As of December 31, 2007, there was $32 million of unrecognized compensation cost, net of
estimated forfeitures, related to nonvested stock options, which is expected to be recognized over a weighted
average period of approximately 1.7 years.

Cash received from option exercises was $110 million during 2007, $159 million during 2006, and $342
million during 2005. The tax benefit realized from the exercise of stock options was $22 million in 2007 and $42
million in 2006.

Restricted stock
Restricted shares issued under the 1993 Plan are restricted as to sale or disposition. These restrictions lapse

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

Our Restricted Stock Plan for Non-Employee Directors (Directors Plan) allows for each non-employee
director to receive an annual award of 800 restricted shares of common stock as a part of compensation. These
awards have a minimum restriction period of six months, and the restrictions lapse upon the earlier of mandatory
director retirement at age 72 or early retirement from the Board after four years of service. The fair market value of
the stock on the date of grant is amortized over the lesser of the time from the grant date to age 72 or the time from
the grant date to completion of four years of service on the Board. We reserved 200,000 shares of common stock for
issuance to non-employee directors, which may be authorized but unissued common shares or treasury shares. At
December 31, 2007, 115,200 shares had been issued to non-employee directors under this plan. There were 8,800
shares, 8,000 shares, and 6,400 shares of restricted stock awarded under the Directors Plan in 2007, 2006, and 2005.
In addition, during 2007, our non-employee directors were awarded 22,642 shares of restricted stock under the 1993
Plan, which are included in the table below.

The following table represents our 1993 Plan and Directors Plan restricted stock awards and restricted stock

units granted, vested, and forfeited during 2007.

HALLIBURTON 2007 A NNUAL REPORT

Restricted Stock
Nonvested shares at January 1, 2007

Granted
Vested
Forfeited
Converted to KBR, Inc. restricted stock

Nonvested shares at December 31, 2007

Number of Shares
(in millions)
7.9
2.8
(2.3)
(0.5)
(0.6)
7.3

Weighted Average
Grant-Date Fair
Value per Share
$ 22.50
32.24
21.16
21.93
17.95
$ 27.16

The weighted average grant-date fair value of shares granted during 2006 was $34.39 and during 2005 was
$24.28. The total fair value of shares vested during 2007 was $79 million, during 2006 was $64 million, and during
2005 was $49 million. As of December 31, 2007, there was $153 million of unrecognized compensation cost, net of
estimated forfeitures, related to nonvested restricted stock, which is expected to be recognized over a weighted
average period of 4.1 years.

2002 Employee Stock Purchase Plan
Under the ESPP, eligible employees may have up to 10% of their earnings withheld, subject to some
limitations, to be used to purchase shares of our common stock. Unless the Board of Directors shall determine
otherwise, each six-month offering period commences on January 1 and July 1 of each year. The price at which
common stock may be purchased under the ESPP is equal to 85% of the lower of the fair market value of the
common stock on the commencement date or last trading day of each offering period. Under this plan, 24 million
shares of common stock have been reserved for issuance. They may be authorized but unissued shares or treasury
shares. As of December 31, 2007, 13.3 million shares have been sold through the ESPP.

Note 13. Income per Share

Basic income per share is based on the weighted average number of common shares outstanding during the

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

Millions of shares
Basic weighted average common shares outstanding
Dilutive effect of:

Convertible senior notes premium
Stock options
Restricted stock

Diluted weighted average common shares outstanding

2007
913

2006
1,014

2005
1,010

29
6
2
950

29
9
2
1,054

16
10
2
1,038

In December 2004, we entered into a supplemental indenture that requires us to satisfy our conversion

obligation for our convertible senior notes in cash, rather than in common stock, for at least the aggregate principal
amount of the notes. This reduced the resulting potential earnings dilution to only include the conversion premium,
which is the difference between the conversion price per share of common stock and the average share price. See
the table above for the dilutive effect for 2007, 2006, and 2005.

Excluded from the computation of diluted income per share were options to purchase three million shares
of common stock that were outstanding in 2007 and two million shares of common stock that were outstanding in
both 2006 and 2005. These options were outstanding during these years but were excluded because the option
exercise price was greater than the average market price of the common shares.

2007 ANNUAL REPORT HALLI BURTON

Note 14. Financial Instruments and Risk Management

Foreign exchange risk
Techniques in managing foreign exchange risk include, but are not limited to, foreign currency borrowing

and investing and the use of currency derivative instruments. We selectively manage significant exposures to
potential foreign exchange losses considering current market conditions, future operating activities, and the
associated cost in relation to the perceived risk of loss. The purpose of our foreign currency risk management
activities is to protect us from the risk that the eventual dollar cash flows resulting from the sale and purchase of
services and products in foreign currencies will be adversely affected by changes in exchange rates.

We manage our currency exposure through the use of currency derivative instruments as it relates to the

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

Foreign currency contracts are not utilized to manage exposures in some currencies due primarily to the

lack of available markets or cost considerations (non-traded currencies). We attempt to manage our working capital
position to minimize foreign currency commitments in non-traded currencies and recognize that pricing for the
services and products offered in these countries should cover the cost of exchange rate devaluations. We have
historically incurred transaction losses in non-traded currencies.

Notional amounts and fair market values. The notional amounts of open forward contracts and option

contracts were $272 million at December 31, 2007 and $358 million at December 31, 2006. The notional amounts
of our foreign exchange contracts do not generally represent amounts exchanged by the parties and, thus, are not a
measure of our exposure or of the cash requirements related to these contracts. The amounts exchanged are
calculated by reference to the notional amounts and by other terms of the derivatives, such as exchange rates. The
estimated fair market value of our foreign exchange contracts was not material at both December 31, 2007 and
December 31, 2006.
Credit risk
Financial instruments that potentially subject us to concentrations of credit risk are primarily cash
equivalents, investments, and trade receivables. It is our practice to place our cash equivalents and investments in
high quality securities with various investment institutions. We derive the majority of our revenue from sales and
services to the energy industry. Within the energy industry, trade receivables are generated from a broad and
diverse group of customers. There are concentrations of receivables in the United States. We maintain an
allowance for losses based upon the expected collectibility of all trade accounts receivable. In addition, see Note 5
for discussion of receivables.

There are no significant concentrations of credit risk with any individual counterparty related to our

derivative contracts. We select counterparties based on their profitability, balance sheet, and a capacity for timely
payment of financial commitments, which is unlikely to be adversely affected by foreseeable events.

Interest rate risk
Our material outstanding debt instruments have fixed interest rates. As of December 31, 2007 and 2006,

we held no material interest rate derivative instruments.

HALLIBURTON 2007 A NNUAL REPORT

Fair market value of financial instruments. The estimated fair market value of long-term debt was $4.1
billion at December 31, 2007 and $3.7 billion at December 31, 2006, as compared to the carrying amount of $2.8
billion at both December 31, 2007 and December 31, 2006. The fair market value of fixed-rate long-term debt is
based on quoted market prices for those or similar instruments. The carrying amount of short-term financial
instruments, cash and equivalents, receivables, short-term notes payable, and accounts payable, as reflected in the
consolidated balance sheets, approximates fair market value due to the short maturities of these instruments. The
currency derivative instruments are carried on the balance sheet at fair value and are based upon third-party quotes.

Note 15. Retirement Plans

Our company and subsidiaries have various plans that cover a significant number of our employees. These

plans include defined contribution plans, defined benefit plans, and other postretirement plans:

our defined contribution plans provide retirement benefits in return for services rendered. These
plans provide an individual account for each participant and have terms that specify how
contributions to the participant’s account are to be determined rather than the amount of pension
benefits the participant is to receive. Contributions to these plans are based on pretax income
and/or discretionary amounts determined on an annual basis. Our expense for the defined
contribution plans for continuing operations totaled $162 million in 2007, $138 million in 2006,
and $115 million in 2005;
our defined benefit plans include both funded and unfunded pension plans, which define an
amount of pension benefit to be provided, usually as a function of age, years of service, or
compensation; and
our postretirement medical plans are offered to specific eligible employees. These plans are
contributory. For some plans, our liability is limited to a fixed contribution amount for each
participant or dependent. The plan participants share the total cost for all benefits provided above
our fixed contributions. Participants’ contributions are adjusted as required to cover benefit
payments. We have made no commitment to adjust the amount of our contributions; therefore, for
these plans the computed accumulated postretirement benefit obligation amount is not affected by
the expected future health care cost inflation rate.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension

and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).” SFAS No. 158
requires an employer to:

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

disclose additional information.

The requirements to recognize the funded status of a benefit plan and the additional disclosure requirements

were effective for fiscal years ending after December 15, 2006. Accordingly, we adopted SFAS No. 158 for our
fiscal year ending December 31, 2006.

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

The discontinued operations of KBR have been excluded from all of the following tables and disclosures.
Benefit obligation and plan assets
The following tables present plan assets, expenses, and obligation for retirement plans for continuing

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

2007 ANNUAL REPORT HALLI BURTON

Benefit obligation
Millions of dollars

Change in benefit obligation
Benefit obligation at beginning of period
Service cost
Interest cost
Plan participants’ contributions
Plan amendments
Settlements/curtailments
Currency fluctuations
Actuarial (gain) loss
Transfers
Benefits paid

Benefit obligation at end of period

Accumulated benefit obligation at end of period

United
States

Pension Benefits
United
States

Int’l