ed10k2007_final.htm
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
(Mark
One)
[X] Annual
Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
For
the fiscal year ended December 31, 2007
OR
[ ] Transition
Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
For the
transition period from ______ to ______
Commission
File Number 001-03492
HALLIBURTON
COMPANY
(Exact
name of registrant as specified in its charter)
Delaware
|
75-2677995
|
(State
or other jurisdiction of
|
(I.R.S.
Employer
|
incorporation
or organization)
|
Identification
No.)
|
5
Houston Center
|
1401
McKinney, Suite 2400
|
Houston,
Texas 77010
|
(Address
of principal executive offices)
|
Telephone
Number – Area code (713) 759-2600
|
|
|
Securities
registered pursuant to Section 12(b) of the Act:
|
|
|
|
Name of each Exchange
on
|
Title of each
class
|
which
registered
|
Common
Stock par value $2.50 per share
|
New
York Stock Exchange
|
|
|
Securities
registered pursuant to Section 12(g) of the
Act: None
|
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.
Yes X No
______
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.
Yes _____ No X
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.
Yes X No
______
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
Large
accelerated
filer [X]
|
Accelerated
filer [ ]
|
Non-accelerated
filer
[ ]
|
Smaller
reporting
company [ ]
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes
No X
The
aggregate market value of Common Stock held by nonaffiliates on June 29, 2007,
determined using the per share closing price on the New York Stock Exchange
Composite tape of $34.50 on that date was approximately
$30,691,000,000.
As of
February 14, 2008, there were 880,157,300 shares of Halliburton Company Common
Stock, $2.50 par value per share, outstanding.
Portions
of the Halliburton Company Proxy Statement for our 2008 Annual Meeting of
Stockholders (File No. 001-03492) are incorporated by reference into Part III of
this report.
HALLIBURTON
COMPANY
Index
to Form 10-K
For
the Year Ended December 31, 2007
PART
I
|
|
PAGE
|
Item
1.
|
Business
|
1
|
Item
1(a).
|
Risk
Factors
|
5
|
Item
1(b).
|
Unresolved
Staff Comments
|
5
|
Item
2.
|
Properties
|
5
|
Item
3.
|
Legal
Proceedings
|
6
|
Item
4.
|
Submission
of Matters to a Vote of Security Holders
|
6
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EXECUTIVE OFFICERS OF
THE REGISTRANT
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7
|
PART
II
|
|
|
Item
5.
|
Market
for Registrant’s Common Equity, Related Stockholder
Matters,
|
|
|
and Issuer Purchases of Equity
Securities
|
10
|
Item
6.
|
Selected
Financial Data
|
11
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and
|
|
|
Results of
Operation
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11
|
Item
7(a).
|
Quantitative
and Qualitative Disclosures About Market Risk
|
11
|
Item
8.
|
Financial
Statements and Supplementary Data
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12
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Item
9.
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Changes
in and Disagreements with Accountants on Accounting and
|
|
|
Financial
Disclosure
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12
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Item
9(a).
|
Controls
and Procedures
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12
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Item
9(b).
|
Other
Information
|
12
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MD&A AND FINANCIAL
STATEMENTS
|
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
|
13
|
Management’s
Report on Internal Control Over Financial Reporting
|
45
|
Reports
of Independent Registered Public Accounting Firm
|
46
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Consolidated
Statements of Operations
|
48
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Consolidated
Balance Sheets
|
49
|
Consolidated
Statements of Shareholders’ Equity
|
50
|
Consolidated
Statements of Cash Flows
|
51
|
Notes
to Consolidated Financial Statements
|
52
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Selected
Financial Data (Unaudited)
|
86
|
Quarterly
Data and Market Price Information (Unaudited)
|
87
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PART
III
|
|
|
Item
10.
|
Directors,
Executive Officers, and Corporate Governance
|
88
|
Item
11.
|
Executive
Compensation
|
88
|
Item
12(a).
|
Security
Ownership of Certain Beneficial Owners
|
88
|
Item
12(b).
|
Security
Ownership of Management
|
88
|
Item
12(c).
|
Changes
in Control
|
88
|
Item
12(d).
|
Securities
Authorized for Issuance Under Equity Compensation Plans
|
88
|
Item
13.
|
Certain
Relationships and Related Transactions, and Director
|
|
|
Independence
|
88
|
Item
14.
|
Principal
Accounting Fees and Services
|
89
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PART
IV
|
|
|
Item
15.
|
Exhibits
and Financial Statement Schedules
|
90
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SIGNATURES
|
99
|
(i)
PART
I
Item
1. Business.
General
description of business
Halliburton
Company’s predecessor was established in 1919 and incorporated under the laws of
the State of Delaware in 1924. Halliburton Company provides a variety
of services and products to customers in the energy industry.
In
November 2006, KBR, Inc. (KBR), which at the time was our wholly owned
subsidiary, completed an initial public offering (IPO), in which it sold
approximately 32 million shares of KBR common stock at $17.00 per
share. Proceeds from the IPO were approximately $508 million, net of
underwriting discounts and commissions and offering expenses. On
April 5, 2007, we completed the separation of KBR from us by exchanging the
135.6 million shares of KBR common stock owned by us on that date for 85.3
million shares of our common stock. In the second quarter of 2007, we
recorded a gain on the disposition of KBR of approximately $933 million, net of
tax and the estimated fair value of the indemnities and guarantees provided to
KBR, which is included in income from discontinued operations in the
consolidated statements of operations.
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. The two KBR segments have been reclassified as
discontinued operations.
See Note
4 to the consolidated financial statements for financial information about our
business segments.
Description
of services and products
We offer
a broad suite of services and products to customers through our two business
segments for the exploration, development, and production of oil and
gas. We serve major, national, and independent oil and gas companies
throughout the world. The following summarizes our services and
products for each business segment.
Completion
and Production
Our
Completion and Production segment delivers cementing, stimulation, intervention,
and completion services. This segment consists of production
enhancement services, completion tools and services, and cementing
services.
Production
enhancement services include stimulation services, pipeline process services,
sand control services, and well intervention services. Stimulation
services optimize oil and gas reservoir production through a variety of pressure
pumping services, nitrogen services, and chemical processes, commonly known as
hydraulic fracturing and acidizing. Pipeline process services include
pipeline and facility testing, commissioning, and cleaning via pressure pumping,
chemical systems, specialty equipment, and nitrogen, which are provided to the
midstream and downstream sectors of the energy business. Sand control
services include fluid and chemical systems and pumping services for the
prevention of formation sand production. Well intervention services
enable live well intervention and continuous pipe deployment capabilities
through the use of hydraulic workover systems and coiled tubing tools and
services.
Completion
tools and services include subsurface safety valves and flow control equipment,
surface safety systems, packers and specialty completion equipment, intelligent
completion systems, expandable liner hanger systems, sand control systems, well
servicing tools, and reservoir performance services. Reservoir
performance services include testing tools, real-time reservoir analysis, and
data acquisition services. Additionally, completion tools and
services include WellDynamics, an intelligent well completions joint venture,
which we consolidate for accounting purposes.
Cementing
services involve bonding the well and well casing while isolating fluid zones
and maximizing wellbore stability. Our cementing service line also
provides casing equipment.
Drilling
and Evaluation
Our
Drilling and Evaluation segment provides field and reservoir modeling, drilling,
evaluation, and precise well-bore placement solutions that enable customers to
model, measure, and optimize their well construction activities. This
segment consists of Baroid Fluid Services, Sperry Drilling Services, Security
DBS Drill Bits, wireline and perforating services, Landmark, and project
management.
Baroid
Fluid Services provides drilling fluid systems, performance additives,
completion fluids, solids control, specialized testing equipment, and waste
management services for oil and gas drilling, completion, and workover
operations.
Sperry
Drilling Services provides drilling systems and services. These
services include directional and horizontal drilling,
measurement-while-drilling, logging-while-drilling, surface data logging,
multilateral systems, underbalanced applications, and rig site information
systems. Our drilling systems offer directional control while
providing important measurements about the characteristics of the drill string
and geological formations while drilling directional wells. Real-time
operating capabilities enable the monitoring of well progress and aid
decision-making processes.
Security
DBS Drill Bits provides roller cone rock bits, fixed cutter bits, hole
enlargement and related downhole tools and services used in drilling oil and gas
wells. In addition, coring equipment and services are provided to
acquire cores of the formation drilled for evaluation.
Wireline
and perforating services include open-hole wireline services that provide
information on formation evaluation, including resistivity, porosity, and
density, rock mechanics, and fluid sampling. Also offered are
cased-hole and slickline services, which provide cement bond evaluation,
reservoir monitoring, pipe evaluation, pipe recovery, mechanical services, well
intervention, and perforating. Perforating services include
tubing-conveyed perforating services and products.
Landmark
is a supplier of integrated exploration, drilling, and production software
information systems, as well as consulting and data management services for the
upstream oil and gas industry.
The
Drilling and Evaluation segment also provides oilfield project management and
integrated solutions to independent, integrated, and national oil
companies. These offerings make use of all of our oilfield services,
products, technologies, and project management capabilities to assist our
customers in optimizing the value of their oil and gas assets.
Acquisitions
and dispositions
In July
2007, we acquired the entire share capital of PSL Energy Services Limited
(PSLES), an eastern hemisphere provider of process, pipeline, and well
intervention services. PSLES has operational bases in the United
Kingdom, Norway, the Middle East, Azerbaijan, Algeria, and Asia
Pacific. We paid approximately $330 million for PSLES, consisting of
$326 million in cash and $4 million in debt assumed, subject to adjustment for
working capital purposes. As of December 31, 2007, we had recorded
goodwill of $163 million and intangible assets of $54 million on a preliminary
basis until our analysis of the fair value of assets acquired and liabilities
assumed is complete. Beginning in August 2007, PSLES’s results of
operations are included in our Completion and Production segment.
As a part
of our sale of Dresser Equipment Group in 2001, we retained a small equity
interest in Dresser Inc.’s Class A common stock. Dresser Inc. was
later reorganized as Dresser, Ltd., and we exchanged our shares for shares of
Dresser, Ltd. In May 2007, we sold our remaining interest in Dresser,
Ltd. We received $70 million in cash from the sale and recorded a $49
million gain. This investment was reflected in “Other assets” on our
consolidated balance sheet at December 31, 2006.
In
January 2007, we acquired all intellectual property, current assets, and
existing business associated with Calgary-based Ultraline Services Corporation
(Ultraline), a division of Savanna Energy Services Corp. Ultraline is
a provider of wireline services in Canada. We paid approximately $178
million for Ultraline and recorded goodwill of $124 million and intangible
assets of $41 million. Beginning in February 2007, Ultraline’s
results of operations are included in our Drilling and Evaluation
segment.
In
January 2005, we completed the sale of our 50% interest in Subsea 7, Inc. to our
joint venture partner, Siem Offshore (formerly DSND Subsea ASA), for
approximately $200 million in cash. As a result of the transaction,
we recorded a gain of approximately $110 million during the first quarter of
2005. We accounted for our 50% ownership of Subsea 7, Inc. using the
equity method in our Completion and Production segment.
Business
strategy
Our
business strategy is to secure a distinct and sustainable competitive position
as a pure-play oilfield service company by delivering products and services to
our customers that maximize their production and recovery and realize proven
reserves from difficult environments. Our objectives are
to:
|
-
|
create
a balanced portfolio of products and services supported by global
infrastructure and anchored by technology innovation with a
well-integrated digital strategy to further differentiate our
company;
|
|
-
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reach
a distinguished level of operational excellence that reduces costs and
creates real value from everything we
do;
|
|
-
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preserve
a dynamic workforce by being a preferred employer to attract, develop, and
retain the best global talent; and
|
|
-
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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:
|
-
|
service
delivery (including the ability to deliver services and products on an “as
needed, where needed” basis);
|
|
-
|
health,
safety, and environmental standards and
practices;
|
|
-
|
global
talent retention;
|
|
-
|
knowledge
of the reservoir;
|
We
conduct business worldwide in approximately 70 countries. In 2007,
based on the location of services provided and products sold, 44% of our
consolidated revenue was from the United States. In 2006, 45% of our
consolidated revenue was from the United States. In 2005, 43% of our
consolidated revenue was from the United States. No other country
accounted for more than 10% of our consolidated revenue during these
periods. See Note 4 to the consolidated financial statements for
additional financial information about geographic operations in the last three
years. Because the markets for our services and products are vast and
cross numerous geographic lines, a meaningful estimate of the total number of
competitors cannot be made. The industries we serve are highly
competitive, and we have many substantial competitors. Largely all of
our services and products are marketed through our servicing and sales
organizations.
Operations
in some countries may be adversely affected by unsettled political conditions,
acts of terrorism, civil unrest, expropriation or other governmental actions,
exchange control problems, and highly inflationary currencies. We
believe the geographic diversification of our business activities reduces the
risk that loss of operations in any one country would be material to the conduct
of our operations taken as a whole.
Information
regarding our exposure to foreign currency fluctuations, risk concentration, and
financial instruments used to minimize risk is included in Management’s
Discussion and Analysis of Financial Condition and Results of Operations –
Financial Instrument Market Risk and in Note 14 to the consolidated financial
statements.
Customers
Our
revenue from continuing operations during the past three years was derived from
the sale of services and products to the energy industry. No customer
represented more than 10% of consolidated revenue in any period
presented.
Raw
materials
Raw
materials essential to our business are normally readily
available. Current market conditions have triggered constraints in
the supply of certain raw materials, such as sand, cement, and specialty
metals. Given high activity levels, particularly in the United
States, we are seeking ways to ensure the availability of resources, as well as
manage the rising costs of raw materials. Our procurement department
is using our size and buying power through several programs designed to ensure
that we have access to key materials at competitive prices.
Research
and development costs
We
maintain an active research and development program. The program
improves existing products and processes, develops new products and processes,
and improves engineering standards and practices that serve the changing needs
of our customers. Our expenditures for research and development
activities were $301 million in 2007, $254 million in 2006, and $218 million in
2005, of which over 97% was company-sponsored in each year.
Patents
We own a
large number of patents and have pending a substantial number of patent
applications covering various products and processes. We are also
licensed to utilize patents owned by others. We do not consider any
particular patent to be material to our business operations.
Seasonality
On an
overall basis, our operations are not generally affected by
seasonality. Weather and natural phenomena can temporarily affect the
performance of our services, but the widespread geographical locations of our
operations serve to mitigate those effects. Examples of how weather
can impact our business include:
|
-
|
the
severity and duration of the winter in North America can have a
significant impact on gas storage levels and drilling activity for natural
gas;
|
|
-
|
the
timing and duration of the spring thaw in Canada directly affects activity
levels due to road restrictions;
|
|
-
|
typhoons
and hurricanes can disrupt coastal and offshore operations;
and
|
|
-
|
severe
weather during the winter months normally results in reduced activity
levels in the North Sea and Russia.
|
In
addition, due to higher spending near the end of the year by customers for
software and completion tools and services, Landmark and completion tools
results of operations are generally stronger in the fourth quarter of the year
than at the beginning of the year.
Employees
At
December 31, 2007, we employed approximately 51,000 people worldwide compared to
approximately 45,000 at December 31, 2006. At December 31, 2007,
approximately 12% of our employees were subject to collective bargaining
agreements. Based upon the geographic diversification of these
employees, we believe any risk of loss from employee strikes or other collective
actions would not be material to the conduct of our operations taken as a
whole.
Environmental
regulation
We are
subject to numerous environmental, legal, and regulatory requirements related to
our operations worldwide. In the United States, these laws and
regulations include, among others:
|
-
|
the
Comprehensive Environmental Response, Compensation and Liability
Act;
|
|
-
|
the
Resource Conservation and Recovery
Act;
|
|
-
|
the
Federal Water Pollution Control Act;
and
|
|
-
|
the
Toxic Substances Control Act.
|
In
addition to the federal laws and regulations, states and other countries where
we do business may have numerous environmental, legal, and regulatory
requirements by which we must abide. We evaluate and address the
environmental impact of our operations by assessing and remediating contaminated
properties in order to avoid future liabilities and comply with environmental,
legal, and regulatory requirements. On occasion, we are involved in
specific environmental litigation and claims, including the remediation of
properties we own or have operated, as well as efforts to meet or correct
compliance-related matters. Our Health, Safety and Environment group
has several programs in place to maintain environmental leadership and to
prevent the occurrence of environmental contamination.
We do not
expect costs related to these remediation requirements to have a material
adverse effect on our consolidated financial position or our results of
operations.
Web
site access
Our
annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on
Form 8-K, and amendments to those reports filed or furnished pursuant to Section
13(a) or 15(d) of the Exchange Act of 1934 are made available free of charge on
our internet web site at www.halliburton.com
as soon as reasonably practicable after we have electronically filed the
material with, or furnished it to, the Securities and Exchange Commission
(SEC). The public may read and copy any materials we have filed with
the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580,
Washington, DC 20549. Information on the operation of the Public
Reference Room may be obtained by calling the SEC at
1-800-SEC-0330. The SEC maintains an internet site that contains our
reports, proxy and information statements, and our other SEC
filings. The address of that site is www.sec.gov. We
have posted on our web site our Code of Business Conduct, which applies to all
of our employees and Directors and serves as a code of ethics for our principal
executive officer, principal financial officer, principal accounting officer,
and other persons performing similar functions. Any amendments to our
Code of Business Conduct or any waivers from provisions of our Code of Business
Conduct granted to the specified officers above are disclosed on our web site
within four business days after the date of any amendment or waiver pertaining
to these officers. There have been no waivers from provisions of our
Code of Business Conduct during 2007, 2006, or 2005.
Item
1(a). Risk Factors.
Information
related to risk factors is described in “Management’s Discussion and Analysis of
Financial Condition and Results of Operations” under “Forward-Looking
Information and Risk Factors.”
Item
1(b). Unresolved Staff Comments.
None.
Item
2. Properties.
We own or
lease numerous properties in domestic and foreign locations. The
following locations represent our major facilities and corporate
offices.
Location
|
Owned/Leased
|
Description
|
Operations:
|
|
|
Completion and Production
segment:
|
|
|
Carrollton,
Texas
|
Owned
|
Manufacturing
facility
|
Johor,
Malaysia
|
Leased
|
Manufacturing
facility
|
Monterrey,
Mexico
|
Leased
|
Manufacturing
facility
|
Sao Jose dos Campos,
Brazil
|
Leased
|
Manufacturing
facility
|
|
|
|
Drilling and
Evaluation segment:
|
|
|
Alvarado,
Texas
|
Owned/Leased
|
Manufacturing
facility
|
Singapore
|
Leased
|
Manufacturing
facility
|
The Woodlands,
Texas
|
Leased
|
Manufacturing
facility
|
|
|
|
Shared
facilities:
|
|
|
Duncan,
Oklahoma
|
Owned
|
Manufacturing,
technology, and camp facilities
|
Houston, Texas
|
Owned
|
Manufacturing
and campus facilities
|
Houston, Texas
|
Owned/Leased
|
Campus
facility
|
Houston, Texas
|
Leased
|
Campus
facility
|
Pune, India
|
Leased
|
Technology
facility
|
|
|
|
Corporate:
|
|
|
Houston, Texas
|
Leased
|
Corporate
executive offices
|
Dubai, United Arab
Emirates
|
Leased
|
Corporate
executive offices
|
All of
our owned properties are unencumbered.
In
addition, we have 133 international and 97 United States field camps from which
we deliver our services and products. We also have numerous small
facilities that include sales offices, project offices, and bulk storage
facilities throughout the world.
We
believe all properties that we currently occupy are suitable for their intended
use.
Item
3. Legal Proceedings.
Information
related to various commitments and contingencies is described in “Management’s
Discussion and Analysis of Financial Condition and Results of Operations” in
“Forward-Looking Information and Risk Factors” and in Note 10 to the
consolidated financial statements.
Item
4. Submission of Matters to a Vote of Security Holders.
There
were no matters submitted to a vote of security holders during the fourth
quarter of 2007.
Executive
Officers of the Registrant
The
following table indicates the names and ages of the executive officers of
Halliburton Company as of February 15, 2008, including all offices and positions
held by each in the past five years:
Name and
Age
|
Offices Held and Term
of Office
|
Evelyn M. Angelle
|
Vice
President, Corporate Controller, and Principal Accounting Officer
of
|
(Age 40)
|
Halliburton Company, since
January 2008
|
|
Vice
President, Operations Finance of Halliburton Company,
|
|
December 2007 to January
2008
|
|
Vice
President, Investor Relations of Halliburton Company,
|
|
April 2005 to November
2007
|
|
Assistant
Controller of Halliburton Company, April 2003 to March
2005
|
|
Senior
Manager of Ernst & Young, April 1996 to March 2003
|
|
|
Peter C. Bernard
|
Senior
Vice President, Business Development and Marketing of
|
(Age 46)
|
Halliburton Company, since June
2006
|
|
Senior
Vice President, Digital and Consulting Solutions of
Halliburton
|
|
Company, December 2004 to May
2006
|
|
President
of Landmark Graphics Corporation, May 2004 to December
2004
|
|
Vice
President, Marketing and Managed Accounts of Landmark
Graphics
|
|
Corporation, May 2003 to May
2004
|
|
Vice
President, Strategic Account Business Development, January
2002
|
|
to May 2003
|
|
|
James S. Brown
|
President,
Western Hemisphere of Halliburton Company, since January
2008
|
(Age 53)
|
Senior
Vice President, Western Hemisphere of Halliburton
Company,
|
|
June 2006 to December
2007
|
|
Senior
Vice President, United States Region of Halliburton
Company,
|
|
December 2003 to June
2006
|
|
Vice
President, Western Area of Halliburton Company, November
2003
|
|
to December
2003
|
|
Vice
President, Business Development of Halliburton Company, October
2001
|
|
to October
2003
|
|
|
* Albert
O. Cornelison, Jr.
|
Executive
Vice President and General Counsel of Halliburton
Company,
|
(Age 58)
|
since December
2002
|
|
Director
of KBR, Inc., June 2006 to April 2007
|
|
|
C. Christopher
Gaut
|
President,
Drilling and Evaluation Division of Halliburton
Company,
|
(Age 51)
|
since January
2008
|
|
Director
of KBR, Inc., March 2006 to April 2007
|
|
Executive
Vice President and Chief Financial Officer of Halliburton
Company,
|
|
March 2003 to December
2007
|
|
Senior
Vice President, Chief Financial Officer, and Member – Office of
the
|
|
President and Chief Operating
Officer of ENSCO International, Inc.,
|
|
January 2002 to February
2003
|
Name and
Age
|
Offices Held and Term
of Office
|
David S. King
|
President,
Completion and Production Division of Halliburton
Company,
|
(Age 51)
|
since January
2008
|
|
Senior
Vice President, Completion and Production Division of
Halliburton
|
|
Company, July 2007 to December
2007
|
|
Senior
Vice President, Production Optimization of Halliburton
Company,
|
|
January 2007 to July
2007
|
|
Senior
Vice President, Eastern Hemisphere of Halliburton Energy
Services
|
|
Group, July 2006 to December
2006
|
|
Senior
Vice President, Global Operations of Halliburton Energy Services
Group,
|
|
July 2004 to July
2006
|
|
Vice
President, Production Optimization of Halliburton Energy Services
Group,
|
|
May 2003 to July
2004
|
|
Vice
President, Production Enhancement of Halliburton Energy Services
Group,
|
|
January 2000 to May
2003
|
|
|
* David
J. Lesar
|
Chairman
of the Board, President, and Chief Executive Officer of
Halliburton
|
(Age 54)
|
Company, since August
2000
|
|
|
Ahmed H. M.
Lotfy
|
President,
Eastern Hemisphere of Halliburton Company, since January
2008
|
(Age 53)
|
Senior
Vice President, Eastern Hemisphere of Halliburton
Company,
|
|
January 2007 to December
2007
|
|
Vice
President, Africa Region of Halliburton Company, January 2005
to
|
|
December
2006
|
|
Vice
President, North Africa Region of Halliburton Company,
|
|
June 2002 to December
2004
|
|
|
* Mark
A. McCollum
|
Executive
Vice President and Chief Financial Officer of Halliburton
Company,
|
(Age 48)
|
since January
2008
|
|
Director
of KBR, Inc., June 2006 to April 2007
|
|
Senior
Vice President and Chief Accounting Officer of Halliburton
Company,
|
|
August 2003 to December
2007
|
|
Senior
Vice President and Chief Financial Officer of Tenneco Automotive,
Inc.,
|
|
November 1999 to August
2003
|
|
|
Craig W. Nunez
|
Senior
Vice President and Treasurer of Halliburton Company,
|
(Age 46)
|
since January
2007
|
|
Vice
President and Treasurer of Halliburton Company, February
2006
|
|
to January
2007
|
|
Treasurer
of Colonial Pipeline Company, November 1999 to January
2006
|
Name and
Age
|
Offices Held and Term
of Office
|
* Lawrence
J. Pope
|
Executive
Vice President of Administration and Chief Human Resources
Officer
|
(Age 39)
|
of Halliburton Company, since
January 2008
|
|
Vice
President, Human Resources and Administration of Halliburton
Company,
|
|
January 2006 to December
2007
|
|
Senior
Vice President, Administration of Kellogg Brown & Root,
Inc.,
|
|
August 2004 to January
2006
|
|
Director,
Finance and Administration for Drilling and Formation
Evaluation
|
|
Division of Halliburton Energy
Services Group, July 2003 to August 2004
|
|
Division
Vice President, Human Resources for Halliburton Energy Services
Group,
|
|
May 2001 to July
2003
|
|
|
* Timothy
J. Probert
|
Executive
Vice President, Strategy and Corporate Development of
Halliburton
|
(Age 56)
|
Company, since January
2008
|
|
Senior
Vice President, Drilling and Evaluation of Halliburton
Company,
|
|
July 2007 to December
2007
|
|
Senior
Vice President, Drilling Evaluation and Digital Solutions of
Halliburton
|
|
Company, May 2006 to July
2007
|
|
Vice
President, Drilling and Formation Evaluation of Halliburton
Company,
|
|
January 2003 to May
2006
|
* Members
of the Policy Committee of the registrant.
There are
no family relationships between the executive officers of the registrant or
between any director and any executive officer of the
registrant.
PART
II
Item
5. Market for Registrant’s Common Equity, Related Stockholder
Matters, and Issuer Purchases of Equity Securities.
Halliburton
Company’s common stock is traded on the New York Stock
Exchange. Information related to the high and low market prices of
common stock and quarterly dividend payments is included under the caption
“Quarterly Data and Market Price Information” on page 87 of this annual
report. Cash dividends on common stock in the amount of $0.09 per
share were paid in June, September, and December of 2007 and $0.075 per share
were paid in March of 2007 and March, June, September, and December of
2006. Our Board of Directors intends to consider the payment of
quarterly dividends on the outstanding shares of our common stock in the
future. The declaration and payment of future dividends, however,
will be at the discretion of the Board of Directors and will depend upon, among
other things, future earnings, general financial condition and liquidity,
success in business activities, capital requirements, and general business
conditions.
The
following graph and table compare total shareholder return on our common stock
for the five-year period ending December 31, 2007, with the Standard &
Poor’s 500 Stock Index and the Standard & Poor’s Energy Composite Index over
the same period. This comparison assumes the investment of $100 on
December 31, 2002, and the reinvestment of all dividends. The
shareholder return set forth is not necessarily indicative of future
performance.
|
|
December
31
|
|
|
|
2002
|
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
Halliburton
|
|
$ |
100.00 |
|
|
$ |
142.06 |
|
|
$ |
217.75 |
|
|
$ |
347.23 |
|
|
$ |
351.09 |
|
|
$ |
432.98 |
|
Standard
& Poor’s 500 Stock Index
|
|
|
100.00 |
|
|
|
128.68 |
|
|
|
142.69 |
|
|
|
149.70 |
|
|
|
173.34 |
|
|
|
182.86 |
|
Standard
& Poor’s Energy Composite Index
|
|
|
100.00 |
|
|
|
125.63 |
|
|
|
165.25 |
|
|
|
217.08 |
|
|
|
269.64 |
|
|
|
362.40 |
|
At February
18, 2008, there were 19,110 shareholders of record. In calculating
the number of shareholders, we consider clearing agencies and security position
listings as one shareholder for each agency or
listing.
Following
is a summary of repurchases of our common stock during the three-month period
ended December 31, 2007.
|
|
|
|
|
|
|
|
Total
Number of
|
|
|
|
|
|
|
|
|
|
Shares
Purchased
|
|
|
|
Total
Number of |
|
|
|
|
|
as Part of
|
|
|
|
Shares
|
|
|
Average
Price
|
|
|
Publicly
Announced
|
|
Period
|
|
Purchased (a)
|
|
|
Paid
per Share
|
|
|
Plans
or Programs (b)
|
|
October
1-31
|
|
|
36,632 |
|
|
$ |
38.99 |
|
|
|
– |
|
November
1-30
|
|
|
1,270,142 |
|
|
$ |
36.16 |
|
|
|
1,261,022 |
|
December
1-31
|
|
|
640,977 |
|
|
$ |
36.58 |
|
|
|
590,253 |
|
Total
|
|
|
1,947,751 |
|
|
$ |
36.35 |
|
|
|
1,851,275 |
|
|
(a)
|
Of
the 1,947,751 shares purchased during the three-month period ended
December 31, 2007, 96,476 shares were acquired from employees in
connection with the settlement of income tax and related benefit
withholding obligations arising from vesting in restricted stock
grants. These shares were not part of a publicly announced
program to purchase common shares.
|
|
(b)
|
In
July 2007, our Board of Directors approved an additional increase to our
existing common share repurchase program of up to $2.0 billion, bringing
the entire authorization to $5.0 billion. This additional
authorization may be used for open market share purchases or to settle the
conversion premium on our 3.125% convertible senior notes, should they be
redeemed. From the inception of this program through December
31, 2007, we have repurchased approximately 79 million shares of our
common stock for approximately $2.7 billion at an average price per share
of $33.91. These numbers include the repurchases of
approximately 39 million shares of our common stock for approximately $1.4
billion at an average price per share of $34.93 during 2007. As
of December 31, 2007, $2.3 billion remained available under our share
repurchase authorization.
|
Item
6. Selected Financial Data.
Information
related to selected financial data is included on page 86 of this annual
report.
Item
7. Management’s Discussion and Analysis of Financial Condition and
Results of Operation.
Information
related to Management’s Discussion and Analysis of Financial Condition and
Results of Operations is included on pages 13 through 44 of this
annual report.
Item
7(a). Quantitative and Qualitative Disclosures About Market
Risk.
Information
related to market risk is included in Management’s Discussion and Analysis of
Financial Condition and Results of Operations under the caption “Financial
Instrument Market Risk” on page 32 of this annual report.
Item
8. Financial Statements and Supplementary Data.
|
Page No.
|
Management’s
Report on Internal Control Over Financial Reporting
|
45
|
Reports
of Independent Registered Public Accounting Firm
|
46
|
Consolidated
Statements of Operations for the years ended December 31, 2007, 2006, and
2005
|
48
|
Consolidated
Balance Sheets at December 31, 2007 and 2006
|
49
|
Consolidated
Statements of Shareholders’ Equity for the years ended
|
|
December 31, 2007, 2006, and
2005
|
50
|
Consolidated
Statements of Cash Flows for the years ended December 31, 2007, 2006, and
2005
|
51
|
Notes
to Consolidated Financial Statements
|
52
|
Selected
Financial Data (Unaudited)
|
86
|
Quarterly
Data and Market Price Information (Unaudited)
|
87
|
The
related financial statement schedules are included under Part IV, Item 15 of
this annual report.
Item
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
Item
9(a). Controls and Procedures.
In
accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we
carried out an evaluation, under the supervision and with the participation of
management, including our Chief Executive Officer and Chief Financial Officer,
of the effectiveness of our disclosure controls and procedures as of the end of
the period covered by this report. Based on that evaluation, our
Chief Executive Officer and Chief Financial Officer concluded that our
disclosure controls and procedures were effective as of December 31, 2007 to
provide reasonable assurance that information required to be disclosed in our
reports filed or submitted under the Exchange Act is recorded, processed,
summarized, and reported within the time periods specified in the Securities and
Exchange Commission’s rules and forms. Our disclosure controls and
procedures include controls and procedures designed to ensure that information
required to be disclosed in reports filed or submitted under the Exchange Act is
accumulated and communicated to our management, including our Chief Executive
Officer and Chief Financial Officer, as appropriate, to allow timely decisions
regarding required disclosure.
There has
been no change in our internal control over financial reporting that occurred
during the three months ended December 31, 2007 that has materially affected, or
is reasonably likely to materially affect, our internal control over financial
reporting.
See
page 45 for Management’s Report on Internal Control Over Financial
Reporting and page 47 for Report of Independent Registered Public
Accounting Firm on its assessment of our internal control over financial
reporting.
Item
9(b). Other Information.
None.
HALLIBURTON
COMPANY
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
EXECUTIVE
OVERVIEW
During
2007, our continuing operations produced revenue of $15.3 billion and operating
income of $3.5 billion, reflecting an operating margin of
23%. Revenue increased $2.3 billion or 18% over 2006, while operating
income improved $253 million or 8% over 2006. Internationally, our
operations experienced 21% revenue growth and 18% operating income growth in
2007 compared to 2006. Consistent with our initiative to grow our
eastern hemisphere operations, revenue from the eastern hemisphere increased 27%
to $6.3 billion in 2007 compared to 2006, comprising nearly 90% of the revenue
growth derived internationally. Moreover, eastern hemisphere
quarterly operating margins consistently remained above 20%.
Business
outlook
The
outlook for our business remains generally favorable. Despite
challenging market conditions in North America, the region realized strong
revenue growth in 2007 compared to 2006. However, downward pressure
on pricing in the latter half of 2007, particularly in our United States well
stimulation land operations, negatively impacted our operating
results. Based on price levels that were negotiated on contracts that
renewed in the fourth quarter of 2007, we anticipate an average price decline
for our United States land stimulation work in the mid- to upper-single digits
in the first quarter of 2008 relative to the fourth quarter of
2007. We believe pricing pressure may be partially mitigated by
higher levels of asset utilization for our fracturing equipment and our
horizontal drilling technologies, as we continue to see increasing demand from
our customers due to trends toward production from unconventional reservoirs
that were previously not economical. We believe that these factors
may contribute to volume increases in the technologically driven segments of the
energy services business, even if rig counts remain relatively
flat. Also, we believe our ability to offer multiple product lines to
our customers helps mitigate the impact of pricing pressures in our well
stimulation operations. We have seen North America pricing declines
in other product lines as well, including cementing, fluid services, and
wireline and perforating, but they continue to be at lower levels than what we
have seen in our well stimulation business. While we anticipate
improved activity levels in our United States land operations, we do think there
is downside risk to our operating margins if pricing continues to erode or if
natural gas prices decline significantly. In Canada, while we
experienced a moderate seasonal recovery in the second half of 2007, our
full-year revenue compared to 2006 declined 22% on a 27% decrease in average
Canada rig count for the year. Looking ahead, we are not planning on
a significant recovery in Canada in 2008. Where appropriate, we
reduced personnel and moved equipment to higher utilization areas.
Outside
of North America, our outlook remains positive. Worldwide demand for
hydrocarbons continues to grow, and the reservoirs are becoming more
complex. The trend toward exploration and exploitation of more
complex reservoirs bodes well for the mix of our product line offerings and
degree of service intensity on a per rig basis. Therefore, we have
been investing and will continue to invest in infrastructure, capital, and
technology predominantly in the eastern hemisphere, consistent with our
initiative to grow our operations in that part of the world.
In 2008,
we will focus on:
|
-
|
maintaining
optimal utilization of our equipment and
resources;
|
|
-
|
managing
pricing, particularly in our North America
operations;
|
|
-
|
hiring
and training additional personnel to meet the increased demand for our
services;
|
|
-
|
continuing
the globalization of our manufacturing and supply chain
processes;
|
|
-
|
balancing
our United States operations by capitalizing on the trend toward
horizontal drilling;
|
|
-
|
leveraging
our technologies to provide our customers with the ability to more
efficiently drill and complete their wells and to increase their
productivity. To that end, we
opened one international research and development center with global
technology and training missions in 2007 and expect to open the second in
2008;
|
|
-
|
maximizing
our position to win meaningful international tenders, especially in
deepwater fields, complex reservoirs, and high-pressure/high-temperature
environments;
|
|
-
|
cultivating
our relationships with national oil
companies;
|
|
-
|
pursuing
strategic acquisitions in line with our core products and services to
expand our portfolio in key geographic areas;
and
|
|
-
|
directing
our capital spending primarily toward eastern hemisphere operations for
service equipment additions and infrastructure. Capital
spending for 2008 is expected to be approximately $1.7 billion to $1.8
billion.
|
Our
operating performance is described in more detail in “Business Environment and
Results of Operations.”
Separation
of KBR, Inc.
In
November 2006, KBR, Inc. (KBR), which at the time was our wholly owned
subsidiary, completed an initial public offering (IPO), in which it sold
approximately 32 million shares of KBR common stock. On April 5,
2007, we completed the separation of KBR from us by exchanging the 135.6 million
shares of KBR common stock owned by us on that date for 85.3 million shares of
our common stock. Consequently, KBR operations have been reclassified
as discontinued operations in the consolidated financial statements for all
periods presented. See Note 2 to our consolidated financial
statements for further information.
Foreign
Corrupt Practices Act investigations
The
Securities and Exchange Commission (SEC) is conducting a formal investigation
into whether improper payments were made to government officials in
Nigeria. The Department of Justice (DOJ) is also conducting a related
criminal investigation. See Note 10 to our consolidated financial
statements for further information.
Other
corporate matters
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.
Significant
uses of cash
Capital
expenditures were $1.6 billion in 2007, with increased focus toward building
infrastructure and adding service equipment in support of our expanding
operations in the eastern hemisphere. Capital expenditures were
predominantly made in the drilling services, production enhancement, wireline,
and cementing product service lines.
During
2007, we repurchased approximately 39 million shares of our common stock under
our share repurchase program at a cost of approximately $1.4 billion at an
average price per share of $34.93.
During
2007, we invested in approximately $332 million of marketable securities,
consisting of auction-rate securities, variable-rate demand notes, and municipal
bonds.
We paid
$314 million in dividends to our shareholders in 2007. In May 2007,
the Board of Directors authorized a dividend increase of $0.015 per common
share, bringing quarterly dividends to $0.09 per common share for the remainder
of 2007.
In the
third quarter of 2007, we purchased the entire share capital of PSL Energy
Services Limited (PSLES), an eastern hemisphere provider of process, pipeline,
and well intervention services, for $326 million in cash and $4 million in debt
assumed upon acquisition.
In
January 2007, we acquired all of the intellectual property, current assets, and
existing wireline services business associated with Ultraline Services
Corporation, a division of Savanna Energy Services Corp., for approximately $178
million.
Future uses of
cash. In July 2007, our Board of Directors approved an
increase to our existing common share repurchase program of up to an additional
$2.0 billion, bringing the entire authorization to $5.0 billion. This
additional authorization may be used for open market share purchases or to
settle the conversion premium over the face amount of our 3.125% convertible
senior notes, should they be redeemed. As of December 31, 2007, $2.3
billion remained available under our share repurchase
authorization.
Capital
spending for 2008 is expected to be approximately $1.7 billion to $1.8
billion. The capital expenditures forecast for 2008 is primarily
directed toward our drilling services, wireline and perforating, production
enhancement, and cementing operations. We will continue to explore
opportunities for acquisitions that will enhance or augment our current
portfolio of products and services, including those with unique technologies or
distribution networks in areas where we do not already have large
operations. Further, as market conditions change, we will continue to
evaluate the allocation of our cash between acquisitions and stock buybacks in
order to provide good return for our shareholders.
Our
3.125% convertible senior notes become redeemable at our option on or after July
15, 2008. If we choose to redeem the notes prior to their maturity or
if the holders choose to convert the notes, we must settle the principal amount
of the notes, which totaled $1.2 billion at December 31, 2007, in
cash. We have the option to settle any amounts due in excess of the
principal, which also totaled approximately $1.2 billion at December 31, 2007,
by delivering shares of our common stock, cash, or a combination of common stock
and cash.
Subject
to Board of Director approval, we expect to pay dividends of approximately $80
million per quarter in 2008.
The
following table summarizes our significant contractual obligations and other
long-term liabilities as of December 31, 2007:
|
|
Payments
Due
|
|
|
|
|
|
|
|
Millions
of dollars
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Thereafter
|
|
|
Total
|
|
Long-term
debt
|
|
$ |
159 |
|
|
$ |
12 |
|
|
$ |
755 |
|
|
$ |
3 |
|
|
$ |
3 |
|
|
$ |
1,854 |
|
|
$ |
2,786 |
|
Interest
on debt (a)
|
|
|
138 |
|
|
|
129 |
|
|
|
129 |
|
|
|
87 |
|
|
|
87 |
|
|
|
2,582 |
|
|
|
3,152 |
|
Operating
leases
|
|
|
180 |
|
|
|
131 |
|
|
|
104 |
|
|
|
74 |
|
|
|
40 |
|
|
|
172 |
|
|
|
701 |
|
Purchase
obligations
|
|
|
1,292 |
|
|
|
125 |
|
|
|
39 |
|
|
|
11 |
|
|
|
1 |
|
|
|
8 |
|
|
|
1,476 |
|
Pension
funding obligations
|
|
|
30 |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
30 |
|
Total
|
|
$ |
1,799 |
|
|
$ |
397 |
|
|
$ |
1,027 |
|
|
$ |
175 |
|
|
$ |
131 |
|
|
$ |
4,616 |
|
|
$ |
8,145 |
|
|
(a)
|
Interest
on debt includes 89 years of interest on $300 million of debentures at
7.6% interest that become due in
2096.
|
With the
adoption of Financial Accounting Standards Board (FASB) Interpretation No. 48
(FIN 48), we had $425 million of gross unrecognized tax benefits at December 31,
2007, of which we estimate $189 million may require a cash
payment. We estimate that $102 million may be settled within the next
12 months, although the amounts are not agreed with tax
authorities. We are not able to reasonably estimate in which future
periods the remaining amounts will ultimately be settled and paid.
Other
factors affecting liquidity
Letters of
credit. In the normal course of business, we have agreements
with banks under which approximately $2.2 billion of letters of credit, surety
bonds, or bank guarantees were outstanding as of December 31, 2007, including
$1.1 billion that relate to KBR. These KBR letters of credit, surety
bonds, or bank guarantees are being guaranteed by us in favor of KBR’s customers
and lenders. KBR has agreed to compensate us for these guarantees and
indemnify us if we are required to perform under any of these
guarantees. Some of the outstanding letters of credit have triggering
events that would entitle a bank to require cash collateralization.
Credit
ratings. The credit ratings for our long-term debt are A2 with
Moody’s Investors Service and A with Standard & Poor’s. Our
Moody’s Investors Service rating became effective May 1, 2007, and was an upward
revision from our previous Moody’s Investors Service rating of Baa1, which had
been in effect since December 2005. Our Standard & Poor’s rating
became effective August 20, 2007, and was an upward revision from our previous
Standard & Poor’s rating of BBB+, which had been in effect since May
2006. The credit ratings on our short-term debt are P1 with Moody’s
Investors Service and A1 with Standard & Poor’s.
BUSINESS
ENVIRONMENT AND RESULTS OF OPERATIONS
We
operate in approximately 70 countries throughout the world to provide a
comprehensive range of discrete and integrated services and products to the
energy industry. The majority of our consolidated revenue is derived
from the sale of services and products to major, national, and independent oil
and gas companies worldwide. We serve the upstream oil and gas
industry throughout the lifecycle of the reservoir: from locating
hydrocarbons and managing geological data, to drilling and formation evaluation,
well construction and completion, and optimizing production through the life of
the field. Our two business segments are the Completion and
Production segment and the Drilling and Evaluation segment. The two
KBR segments have been reclassified as discontinued operations as a result of
the separation of KBR.
The
industries we serve are highly competitive with many substantial competitors in
each segment. In 2007, based upon the location of the services
provided and products sold, 44% of our consolidated revenue was from the United
States. In 2006, 45% of our consolidated revenue was from the United
States. In 2005, 43% of our consolidated revenue was from the United
States. No other country accounted for more than 10% of our revenue
during these periods.
Operations
in some countries may be adversely affected by unsettled political conditions,
acts of terrorism, civil unrest, force majeure, war or other armed conflict,
expropriation or other governmental actions, inflation, exchange control
problems, and highly inflationary currencies. We believe the
geographic diversification of our business activities reduces the risk that loss
of operations in any one country would be material to our consolidated results
of operations.
Activity
levels within our business segments are significantly impacted by spending on
upstream exploration, development, and production programs by major, national,
and independent oil and gas companies. Also impacting our activity is
the status of the global economy, which impacts oil and gas
consumption.
Some of
the more significant barometers of current and future spending levels of oil and
gas companies are oil and gas prices, the world economy, and global stability,
which together drive worldwide drilling activity. Our financial
performance is significantly affected by oil and gas prices and worldwide rig
activity, which are summarized in the following tables.
This
table shows the average oil and gas prices for West Texas Intermediate (WTI) and
United Kingdom Brent crude oil, and Henry Hub natural gas:
Average Oil Prices
(dollars per barrel)
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
West
Texas Intermediate
|
|
$ |
71.91 |
|
|
$ |
66.17 |
|
|
$ |
56.30 |
|
United
Kingdom Brent
|
|
$ |
72.21 |
|
|
$ |
65.35 |
|
|
$ |
54.45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average United States Gas
Prices (dollars per million British
|
|
|
|
|
|
|
|
|
|
|
|
|
thermal units, or
mmBtu)
|
|
|
|
|
|
|
|
|
|
|
|
|
Henry
Hub
|
|
$ |
6.97 |
|
|
$ |
6.81 |
|
|
$ |
8.79 |
|
The
yearly average rig counts based on the Baker Hughes Incorporated rig count
information were as follows:
Land
vs. Offshore
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
United
States:
|
|
|
|
|
|
|
|
|
|
Land
|
|
|
1,694 |
|
|
|
1,558 |
|
|
|
1,287 |
|
Offshore
|
|
|
73 |
|
|
|
90 |
|
|
|
93 |
|
Total
|
|
|
1,767 |
|
|
|
1,648 |
|
|
|
1,380 |
|
Canada:
|
|
|
|
|
|
|
|
|
|
|
|
|
Land
|
|
|
341 |
|
|
|
467 |
|
|
|
454 |
|
Offshore
|
|
|
3 |
|
|
|
3 |
|
|
|
4 |
|
Total
|
|
|
344 |
|
|
|
470 |
|
|
|
458 |
|
International
(excluding Canada):
|
|
|
|
|
|
|
|
|
|
|
|
|
Land
|
|
|
719 |
|
|
|
656 |
|
|
|
593 |
|
Offshore
|
|
|
287 |
|
|
|
269 |
|
|
|
258 |
|
Total
|
|
|
1,006 |
|
|
|
925 |
|
|
|
851 |
|
Worldwide
total
|
|
|
3,117 |
|
|
|
3,043 |
|
|
|
2,689 |
|
Land
total
|
|
|
2,754 |
|
|
|
2,681 |
|
|
|
2,334 |
|
Offshore
total
|
|
|
363 |
|
|
|
362 |
|
|
|
355 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
vs. Gas
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
United
States:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
297 |
|
|
|
273 |
|
|
|
194 |
|
Gas
|
|
|
1,470 |
|
|
|
1,375 |
|
|
|
1,186 |
|
Total
|
|
|
1,767 |
|
|
|
1,648 |
|
|
|
1,380 |
|
Canada:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
128 |
|
|
|
110 |
|
|
|
100 |
|
Gas
|
|
|
216 |
|
|
|
360 |
|
|
|
358 |
|
Total
|
|
|
344 |
|
|
|
470 |
|
|
|
458 |
|
International
(excluding Canada):
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
784 |
|
|
|
709 |
|
|
|
651 |
|
Gas
|
|
|
222 |
|
|
|
216 |
|
|
|
200 |
|
Total
|
|
|
1,006 |
|
|
|
925 |
|
|
|
851 |
|
Worldwide
total
|
|
|
3,117 |
|
|
|
3,043 |
|
|
|
2,689 |
|
Oil
total
|
|
|
1,209 |
|
|
|
1,092 |
|
|
|
945 |
|
Gas
total
|
|
|
1,908 |
|
|
|
1,951 |
|
|
|
1,744 |
|
Our
customers’ cash flows, in many instances, depend upon the revenue they generate
from the sale of oil and gas. Higher oil and gas prices usually
translate into higher exploration and production budgets. Higher
prices also improve the economic attractiveness of unconventional
reservoirs. This promotes additional investment by our
customers. The opposite is true for lower oil and gas
prices.
After
declining from record highs during the third and fourth quarters of 2006, WTI
oil spot prices averaged $72.00 per barrel in 2007 and are expected to average
$87.00 per barrel in 2008 according to the Energy Information Administration
(EIA). Between mid-December 2006 and mid-January 2007, the WTI crude
oil price fell about $12 per barrel to a low of $50.51 per barrel, as warm
weather reduced demand for heating fuels throughout most of the United
States. However, the WTI price recovered to over $66 per barrel by
the end of March 2007, as the weather turned colder than normal and geopolitical
tensions intensified. Crude oil prices continued to rise to record
levels over the $99 per barrel mark throughout 2007 due to a tight world oil
supply and demand balance, ending the year at approximately $96 per
barrel. We expect that oil prices will remain at levels sufficient to
sustain, and likely grow, our customers’ current levels of spending due to a
combination of the following factors:
|
-
|
continued
growth in worldwide petroleum demand, despite high oil
prices;
|
|
-
|
projected
production growth in non-Organization of Petroleum Exporting Countries
(non-OPEC) supplies is not expected to accommodate world wide demand
growth;
|
|
-
|
OPEC’s
commitment to control production;
|
|
-
|
modest
increases in OPEC’s current and forecasted production capacity;
and
|
|
-
|
geopolitical
tensions in major oil-exporting
nations.
|
According
to the International Energy Agency’s (IEA) January 2008 “Oil Market Report,” the
outlook for world oil demand remains strong, with China, the Middle East, and
Europe accounting for approximately 52% of the expected demand growth in
2008. Excess oil production capacity is expected to remain
constrained and that, along with increased demand, is expected to keep supplies
tight. Thus, any unexpected supply disruption or change in demand
could lead to fluctuating prices. The IEA forecasts world petroleum
demand growth in 2008 to increase 2% over 2007.
North America
operations. Volatility in natural gas prices has the potential
to impact our customers' drilling and production activities, particularly in
North America. In the first quarter of 2007, we experienced lower
than anticipated customer activity in North America, particularly the pressure
pumping market in Canada and the United States Rockies. Some of this
activity decline was attributable to poor weather, including an early spring
break-up season in Canada and severe weather early in 2007 in the United States
Rockies and mid-continent regions. In addition, the unusually warm
start to the United States 2006/2007 winter caused concern about natural gas
storage levels, which negatively impacted the price of natural
gas. This uncertainty made many of our customers more cautious about
their drilling and production plans in the early part of 2007. The
second half of 2007 was characterized by increased activity for our United
States customers and recovery in the Gulf of Mexico after the hurricane
season. Despite recovery from a traditionally slow second quarter
spring break-up season, Canada experienced a significant decline in activity as
compared to 2006. Beginning in late 2006, we began moving equipment
and personnel from Canada to the United States and Latin America to address the
anticipated slowdown. In January 2008, the EIA stated that the Henry
Hub spot price averaged $7.17 per thousand cubic feet (mcf) in 2007 and was
projected to average $7.78 per mcf in 2008.
It is
common practice in the United States oilfield services industry to sell services
and products based on a price book and then apply discounts to the price book
based upon a variety of factors. The discounts applied typically
increase to partially offset price book increases. We experienced
increased pricing pressure from our customers in the North American market in
2007, particularly in Canada and in our United States well stimulation
operations. In the fourth quarter of 2007, we saw price declines for
our fracturing services in the United States in the low- to mid-single
digits. While we anticipate improved activity levels in our United
States land operations, we do think there is downside risk to our operating
margins if pricing continues to erode or if natural gas prices decline
significantly.
Focus on international
growth. Consistent with our strategy to grow our international
operations, we expect to continue to invest capital and increase manufacturing
capacity to bring new tools online to serve the high demand for our
services. Following is a brief discussion of some of our recent
initiatives:
|
-
|
we
opened a corporate office in Dubai, United Arab Emirates, allowing us to
focus more attention on customer relationships in that part of the world,
particularly with national oil
companies;
|
|
-
|
in
order to continue to supply our customers with leading-edge services and
products, we have increased our technology spending during 2007 as
compared to the prior year. Our plans are progressing for new
international research and development centers with global technology and
training missions. We opened one in Pune, India in the third
quarter of 2007, and we expect to open a second facility in Singapore in
2008;
|
|
-
|
we
are expanding our manufacturing capability and capacity to meet the
increasing demands for our services and products. In 2007, we
opened manufacturing plants in Mexico, Brazil, Malaysia, and
Singapore. Having manufacturing facilities closer to our
worksites allows us to more efficiently deploy equipment to our field
operations, as well as locally source employees and
materials;
|
|
-
|
as
our workforce becomes more global, the need for regional training centers
increases. To meet the increasing need for technical training,
we opened a new training center in Tyumen, Russia during the first quarter
of 2007. We have also recently expanded training centers in
Malaysia, Egypt, and Mexico; and
|
|
-
|
part
of our growth strategy includes acquisitions that will enhance or augment
our current portfolio of products and services, including those with
unique technologies or distribution networks in areas where we do not
already have large operations;
|
|
-
|
in
January 2007, we acquired Ultraline Services Company, a provider of
wireline services in Canada. Prior to this acquisition, we did
not have meaningful wireline and perforating operations in
Canada;
|
|
-
|
in
May 2007, we acquired the intellectual property, assets, and existing
business associated with Vector Magnetics LLC’s active ranging technology
for steam-assisted gravity drainage
applications;
|
|
-
|
in
July 2007, we acquired PSL Energy Services Limited, an eastern hemisphere
provider of process, pipeline, and well intervention
services. This acquisition increases our eastern hemisphere
production enhancement operations significantly, putting us in a strong
position in pipeline processing services both in the eastern hemisphere
and globally;
|
|
-
|
in
September 2007, we acquired the intellectual property and substantially
all of the assets and existing business of GeoSmith Consulting Group, LLC,
a developer of software components for 3-D interpretation and geometric
modeling applications; and
|
|
-
|
in
November 2007, we acquired the entire share capital of OOO Burservice, a
provider of directional drilling services in
Russia.
|
Contract
wins in 2007 are positioning us to grow our international operations over the
coming years. Examples include:
|
-
|
a
multiservice contract for work in the Tyumen region of
Russia. We will be providing drilling fluids, waste management,
cementing, drill bits, directional drilling, and logging-while-drilling
services;
|
|
-
|
a
contract to provide acidizing, acid fracturing, water control, and
nitrogen stimulation services for a customer in the Bay of Campeche,
Mexico;
|
|
-
|
a
contract to provide deepwater sand control completion technology in two
offshore fields of India;
|
|
-
|
a
contract to provide completion products and services to a group of energy
companies for operations throughout Malaysia for a term of five
years;
|
|
-
|
a
contract to provide exploration and development testing services in high
pressure, high temperature environments in
Brazil;
|
|
-
|
a
five-year contract for sand control completions for over 200 wells in
offshore China;
|
|
-
|
a
three-year contract to provide a full range of subsurface services,
including drilling and formation evaluation, slickline, fluids, cementing
services, and production enhancement in Papua New
Guinea;
|
|
-
|
a
contract to provide completion products and services in Indonesia;
and
|
|
-
|
a
contract to manage the drilling and completion of 58 land wells in the
southern region of Mexico.
|
RESULTS
OF OPERATIONS IN 2007 COMPARED TO 2006
REVENUE:
|
|
|
|
|
|
|
|
Percentage
|
|
Millions
of dollars
|
|
2007
|
|
|
2006
|
|
|
Increase
|
|
|
Change
|
|
Completion
and Production
|
|
$ |
8,386 |
|
|
$ |
7,221 |
|
|
$ |
1,165 |
|
|
|
16 |
% |
Drilling
and Evaluation
|
|
|
6,878 |
|
|
|
5,734 |
|
|
|
1,144 |
|
|
|
20 |
|
Total
revenue
|
|
$ |
15,264 |
|
|
$ |
12,955 |
|
|
$ |
2,309 |
|
|
|
18 |
% |
By
geographic region:
|
|
Completion
and Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
$ |
4,655 |
|
|
$ |
4,275 |
|
|
$ |
380 |
|
|
|
9 |
% |
Latin America
|
|
|
756 |
|
|
|
583 |
|
|
|
173 |
|
|
|
30 |
|
Europe/Africa/CIS
|
|
|
1,767 |
|
|
|
1,436 |
|
|
|
331 |
|
|
|
23 |
|
Middle
East/Asia
|
|
|
1,208 |
|
|
|
927 |
|
|
|
281 |
|
|
|
30 |
|
Total
|
|
|
8,386 |
|
|
|
7,221 |
|
|
|
1,165 |
|
|
|
16 |
|
Drilling
and Evaluation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
2,478 |
|
|
|
2,183 |
|
|
|
295 |
|
|
|
14 |
|
Latin America
|
|
|
1,042 |
|
|
|
931 |
|
|
|
111 |
|
|
|
12 |
|
Europe/Africa/CIS
|
|
|
1,933 |
|
|
|
1,424 |
|
|
|
509 |
|
|
|
36 |
|
Middle
East/Asia
|
|
|
1,425 |
|
|
|
1,196 |
|
|
|
229 |
|
|
|
19 |
|
Total
|
|
|
6,878 |
|
|
|
5,734 |
|
|
|
1,144 |
|
|
|
20 |
|
Total
revenue by region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
7,133 |
|
|
|
6,458 |
|
|
|
675 |
|
|
|
10 |
|
Latin America
|
|
|
1,798 |
|
|
|
1,514 |
|
|
|
284 |
|
|
|
19 |
|
Europe/Africa/CIS
|
|
|
3,700 |
|
|
|
2,860 |
|
|
|
840 |
|
|
|
29 |
|
Middle
East/Asia
|
|
|
2,633 |
|
|
|
2,123 |
|
|
|
510 |
|
|
|
24 |
|
OPERATING
INCOME (LOSS):
|
|
|
|
|
Increase
|
|
|
Percentage
|
|
Millions
of dollars
|
|
2007
|
|
|
2006
|
|
|
(Decrease)
|
|
|
Change
|
|
Completion
and Production
|
|
$ |
2,199 |
|
|
$ |
2,140 |
|
|
$ |
59 |
|
|
|
3 |
% |
Drilling
and Evaluation
|
|
|
1,485 |
|
|
|
1,328 |
|
|
|
157 |
|
|
|
12 |
|
Corporate
and other
|
|
|
(186 |
) |
|
|
(223 |
) |
|
|
37 |
|
|
|
17 |
|
Total
operating income
|
|
$ |
3,498 |
|
|
$ |
3,245 |
|
|
$ |
253 |
|
|
|
8 |
% |
By
geographic region:
|
|
Completion
and Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
$ |
1,404 |
|
|
$ |
1,476 |
|
|
$ |
(72 |
) |
|
|
(5 |
)% |
Latin America
|
|
|
170 |
|
|
|
130 |
|
|
|
40 |
|
|
|
31 |
|
Europe/Africa/CIS
|
|
|
330 |
|
|
|
324 |
|
|
|
6 |
|
|
|
2 |
|
Middle
East/Asia
|
|
|
295 |
|
|
|
210 |
|
|
|
85 |
|
|
|
40 |
|
Total
|
|
|
2,199 |
|
|
|
2,140 |
|
|
|
59 |
|
|
|
3 |
|
Drilling
and Evaluation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
552 |
|
|
|
595 |
|
|
|
(43 |
) |
|
|
(7 |
) |
Latin America
|
|
|
179 |
|
|
|
170 |
|
|
|
9 |
|
|
|
5 |
|
Europe/Africa/CIS
|
|
|
414 |
|
|
|
263 |
|
|
|
151 |
|
|
|
57 |
|
Middle
East/Asia
|
|
|
340 |
|
|
|
300 |
|
|
|
40 |
|
|
|
13 |
|
Total
|
|
|
1,485 |
|
|
|
1,328 |
|
|
|
157 |
|
|
|
12 |
|
Total
operating income by region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(excluding Corporate and
other):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
1,956 |
|
|
|
2,071 |
|
|
|
(115 |
) |
|
|
(6 |
) |
Latin America
|
|
|
349 |
|
|
|
300 |
|
|
|
49 |
|
|
|
16 |
|
Europe/Africa/CIS
|
|
|
744 |
|
|
|
587 |
|
|
|
157 |
|
|
|
27 |
|
Middle
East/Asia
|
|
|
635 |
|
|
|
510 |
|
|
|
125 |
|
|
|
25 |
|
|
Note
1
|
–
|
All
periods presented reflect the new segment structure and the
reclassification of certain amounts between the segments/regions and
“Corporate and other.”
|
The
increase in consolidated revenue in 2007 compared to 2006 spanned all four
regions in both segments and was attributable to higher worldwide activity,
particularly in Europe, Africa, and the United States. Revenue
derived from the eastern hemisphere contributed 58% to the total revenue
increase. International revenue was 56% of consolidated revenue in
2007 and 55% of consolidated revenue in 2006.
The
increase in consolidated operating income was primarily derived from the eastern
hemisphere, which increased 26% compared to 2006. Operating income
for 2007 was positively impacted by a $49 million gain recorded on the sale of
our remaining interest in Dresser, Ltd. and negatively impacted by $34 million
in charges related to the impairment of an oil and gas property and $32 million
in charges for environmental reserves. Operating income for 2006
included a $48 million gain on the sale of lift boats in west Africa and the
North Sea and $47 million of insurance proceeds for business interruptions
resulting from the 2005 Gulf of Mexico hurricanes.
Following
is a discussion of our results of operations by reportable
segment.
Completion and Production
increase in revenue compared to 2006 was derived from all
regions. Europe/Africa/CIS revenue grew 23% on increased activity
from production enhancement services in Europe and Africa. The region
also benefited from increased activity in our intelligent well completions joint
venture and increased testing activity and completion product sales in Africa
and improved cementing services pricing in the North Sea and
Russia. Middle East/Asia revenue grew 30% from increased completion
product sales in Asia, improved completion tools sales in the Middle East, and
new cementing services contracts in the Middle East. North America
revenue improved 9% largely driven by increased production enhancement services
and cementing services activity in the United States. The North
America revenue increase was partially offset by lower pricing, particularly in
fracturing, and decreased production enhancement services activity in
Canada. Latin America revenue increased 30% largely driven by
cementing services revenue increasing on new contracts and improved pricing,
increased stimulation activity in Mexico, and increased testing activity in
Brazil. International revenue was 47% of total segment revenue in
2007 compared to 45% in 2006.
The
Completion and Production segment operating income improvement spanned all
regions except North America. Europe/Africa/CIS operating income grew
2% from increased activity and improved pricing for cementing services in the
North Sea. Europe/Africa/CIS segment operating income in 2006
included a $48 million gain on the sale of lift boats in west Africa and the
North Sea. Middle East/Asia operating income grew 40% from improved
completion product deliveries in Asia and the Middle East and additional
cementing service projects in the Middle East. North America
operating income decreased 5% largely because the segment received hurricane
insurance proceeds of $21 million in 2006 and due to a decline in production
enhancement services pricing. Latin America operating income
increased 31% due to new technology and improved pricing for cementing
services.
Drilling and Evaluation
revenue increase in 2007 compared to 2006 was derived from all four
regions. Europe/Africa/CIS revenue improved 36% from increased
drilling services activity throughout the region, new fluid services contracts
in the North Sea, and increased wireline and perforating services in
Africa. Middle East/Asia revenue increased 19% from additional
drilling service contract awards and activity in the region, new wireline and
perforating services contracts in Asia, and increased fluid sales in the Middle
East. North America revenue grew 14% from improvements in all product
service lines, particularly wireline and perforating services and drilling
services. The United States benefited from increased land rig
activity, particularly for horizontally and directionally drilled
wells. Latin America revenue improved 12% primarily on increased
activity in drilling services, fluid services, and wireline and perforating
services. International revenue was 68% of total segment revenue in
2007 compared to 67% in 2006.
Drilling
and Evaluation operating income increase compared to 2006 was led by the eastern
hemisphere. Europe/Africa/CIS Drilling and Evaluation operating
income grew 57% from increased drilling services activity in Europe and
Africa. Africa also benefited from improved fluid service product mix
and new wireline and perforating projects. Middle East/Asia operating
income grew 13% from additional drilling service and wireline and perforating
activity in the Middle East and Asia. Included in the region in 2007
was a $34 million charge related to the impairment of an oil and gas property in
Bangladesh. Latin America operating income increased 5% from
increased wireline and perforating activity. Partially offsetting the
improvement was decreased fluid service activity. North America
operating income fell 7% largely because the segment received hurricane
insurance proceeds of $26 million in 2006 and recorded a $24 million
environmental exposure charge in the third quarter of 2007.
Corporate and other expenses
were $186 million in 2007 compared to $223 million in 2006. 2007
included a $49 million gain recorded on the sale of our remaining interest in
Dresser, Ltd. and a $12 million charge for executive separation
costs.
NONOPERATING
ITEMS
Interest expense decreased
$11 million in 2007 compared to 2006, primarily due to the repayment in August
2006 of $275 million of our medium-term notes.
Interest income decreased $5
million in 2007 compared to 2006 due to lower average cash
balances.
(Provision) benefit for income taxes
from continuing operations in 2007 of $907 million resulted in an
effective tax rate of 26% compared to an effective tax rate of 31% in
2006. The provision for income taxes in 2007 included a $205 million
favorable income tax impact from the ability to recognize foreign tax credits
previously thought not to be fully utilizable.
Income from discontinued operations,
net of income tax provision in 2007 primarily consisted of an approximate
$933 million net gain recorded on the disposition of KBR.
RESULTS
OF OPERATIONS IN 2006 COMPARED TO 2005
REVENUE:
|
|
|
|
|
|
|
|
Percentage
|
|
Millions
of dollars
|
|
2006
|
|
|
2005
|
|
|
Increase
|
|
|
Change
|
|
Completion
and Production
|
|
$ |
7,221 |
|
|
$ |
5,495 |
|
|
$ |
1,726 |
|
|
|
31 |
% |
Drilling
and Evaluation
|
|
|
5,734 |
|
|
|
4,605 |
|
|
|
1,129 |
|
|
|
25 |
|
Total
revenue
|
|
$ |
12,955 |
|
|
$ |
10,100 |
|
|
$ |
2,855 |
|
|
|
28 |
% |
By
geographic region:
|
|
Completion
and Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
$ |
4,275 |
|
|
$ |
3,118 |
|
|
$ |
1,157 |
|
|
|
37 |
% |
Latin America
|
|
|
583 |
|
|
|
542 |
|
|
|
41 |
|
|
|
8 |
|
Europe/Africa/CIS
|
|
|
1,436 |
|
|
|
1,123 |
|
|
|
313 |
|
|
|
28 |
|
Middle
East/Asia
|
|
|
927 |
|
|
|
712 |
|
|
|
215 |
|
|
|
30 |
|
Total
|
|
|
7,221 |
|
|
|
5,495 |
|
|
|
1,726 |
|
|
|
31 |
|
Drilling
and Evaluation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
2,183 |
|
|
|
1,701 |
|
|
|
482 |
|
|
|
28 |
|
Latin America
|
|
|
931 |
|
|
|
802 |
|
|
|
129 |
|
|
|
16 |
|
Europe/Africa/CIS
|
|
|
1,424 |
|
|
|
1,151 |
|
|
|
273 |
|
|
|
24 |
|
Middle
East/Asia
|
|
|
1,196 |
|
|
|
951 |
|
|
|
245 |
|
|
|
26 |
|
Total
|
|
|
5,734 |
|
|
|
4,605 |
|
|
|
1,129 |
|
|
|
25 |
|
Total
revenue by region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
6,458 |
|
|
|
4,819 |
|
|
|
1,639 |
|
|
|
34 |
|
Latin America
|
|
|
1,514 |
|
|
|
1,344 |
|
|
|
170 |
|
|
|
13 |
|
Europe/Africa/CIS
|
|
|
2,860 |
|
|
|
2,274 |
|
|
|
586 |
|
|
|
26 |
|
Middle
East/Asia
|
|
|
2,123 |
|
|
|
1,663 |
|
|
|
460 |
|
|
|
28 |
|
OPERATING
INCOME (LOSS):
|
|
|
|
|
Increase
|
|
|
Percentage
|
|
Millions
of dollars
|
|
2006
|
|
|
2005
|
|
|
(Decrease)
|
|
|
Change
|
|
Completion
and Production
|
|
$ |
2,140 |
|
|
$ |
1,524 |
|
|
$ |
616 |
|
|
|
40 |
% |
Drilling
and Evaluation
|
|
|
1,328 |
|
|
|
840 |
|
|
|
488 |
|
|
|
58 |
|
Corporate
and other
|
|
|
(223 |
) |
|
|
(200 |
) |
|
|
(23 |
) |
|
|
(12 |
) |
Total
operating income
|
|
$ |
3,245 |
|
|
$ |
2,164 |
|
|
$ |
1,081 |
|
|
|
50 |
% |
By
geographic region:
|
|
Completion
and Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
$ |
1,476 |
|
|
$ |
1,046 |
|
|
$ |
430 |
|
|
|
41 |
% |
Latin America
|
|
|
130 |
|
|
|
126 |
|
|
|
4 |
|
|
|
3 |
|
Europe/Africa/CIS
|
|
|
324 |
|
|
|
203 |
|
|
|
121 |
|
|
|
60 |
|
Middle
East/Asia
|
|
|
210 |
|
|
|
149 |
|
|
|
61 |
|
|
|
41 |
|
Total
|
|
|
2,140 |
|
|
|
1,524 |
|
|
|
616 |
|
|
|
40 |
|
Drilling
and Evaluation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
595 |
|
|
|
365 |
|
|
|
230 |
|
|
|
63 |
|
Latin America
|
|
|
170 |
|
|
|
77 |
|
|
|
93 |
|
|
|
121 |
|
Europe/Africa/CIS
|
|
|
263 |
|
|
|
207 |
|
|
|
56 |
|
|
|
27 |
|
Middle
East/Asia
|
|
|
300 |
|
|
|
191 |
|
|
|
109 |
|
|
|
57 |
|
Total
|
|
|
1,328 |
|
|
|
840 |
|
|
|
488 |
|
|
|
58 |
|
Total
operating income by region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(excluding Corporate and
other):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
2,071 |
|
|
|
1,411 |
|
|
|
660 |
|
|
|
47 |
|
Latin America
|
|
|
300 |
|
|
|
203 |
|
|
|
97 |
|
|
|
48 |
|
Europe/Africa/CIS
|
|
|
587 |
|
|
|
410 |
|
|
|
177 |
|
|
|
43 |
|
Middle
East/Asia
|
|
|
510 |
|
|
|
340 |
|
|
|
170 |
|
|
|
50 |
|
|
Note
1
|
–
|
All
periods presented reflect the new segment structure and the
reclassification of certain amounts between the segments/regions and
“Corporate and other.”
|
The
increase in consolidated revenue in 2006 compared to 2005 predominantly resulted
from increased activity, higher utilization of our equipment, and increased
pricing due to higher exploration and production spending by our
customers. Revenue in 2005 was impacted by an estimated $80 million
in lost revenue due to Gulf of Mexico hurricanes. International
revenue was 55% of consolidated revenue in 2006 and 57% of consolidated revenue
in 2005.
The
increase in consolidated operating income was primarily due to improved demand
due to increased rig activity and improved pricing and asset
utilization. Operating income for 2006 included a $48 million gain on
the sale of lift boats in west Africa and the North Sea and $47 million of
insurance proceeds for business interruptions resulting from the 2005 Gulf of
Mexico hurricanes. Operating income in 2005 was adversely impacted by
an estimated $45 million due to Gulf of Mexico hurricanes.
Following
is a discussion of our results of operations by reportable
segment.
Completion and Production
increase in revenue compared to 2005 was derived from all
regions. Europe/Africa/CIS revenue grew 28% from increased activity
from production enhancement services. Completion tools sales
benefited from the addition of Easywell to the completion tool portfolio in
Europe and cementing services improved due to increased activity in Russia, the
North Sea, and Nigeria and improved pricing and sales in
Angola. Middle East/Asia revenue grew 30% from the addition of
Easywell to the completion tool portfolio in Asia, increased WellDynamics
activity in Asia, a new contract in Oman for production enhancement services,
and new contract start-ups and product sales of cementing services in
Asia. North America revenue improved 37% largely driven by United
States onshore operations due to strong demand for stimulation services, coupled
with improved equipment utilization and pricing. Production
enhancement services North America revenue also grew due to improved pricing and
improved equipment utilization in Canada. Latin America revenue
increased 8%. International revenue was 45% of total segment revenue
in 2006 compared to 48% in 2005.
The
Completion and Production segment operating income improvement spanned all
regions. Europe/Africa/CIS operating income improved
60%. The 2006 Europe/Africa/CIS segment operating income was
positively impacted by a $48 million gain on the sale of lift boats in west
Africa and the North Sea. Cementing services results were also
favorable as a result of new contracts and increased activity in
Europe. Operating income in 2005 included a $17 million favorable
insurance settlement related to a pipe fabrication and laying project in the
North Sea. Middle East/Asia operating income grew 41% primarily from
improved production enhancement services product mix and increased completion
tools sales in Asia, which were partially offset by decreased WellDynamics
activity. North America operating income increased 41% largely due to
an improved production enhancement services product mix and increased cementing
services activity in the United States. The segment received
hurricane insurance proceeds of $21 million in 2006 and was negatively impacted
by an estimated $24 million in 2005 by hurricanes in the Gulf of
Mexico. The 2005 segment operating income included a $110 million
gain on the sale in 2005 of our equity interest in the Subsea 7, Inc. joint
venture. Latin America operating income increased 3% due primarily to
increased sand control tools activity in Brazil.
Drilling and Evaluation
revenue increase in 2006 compared to 2005 was derived from all four regions in
all product service lines. Europe/Africa/CIS revenue improved 24%
from new drilling service contracts in Europe. The fluid services
revenue comparison was also favorable, primarily due to increased activity in
the region. Middle East/Asia revenue grew 26% from new drilling
services contracts in Asia and increased drill bits activity in the
region. The region also benefited from increased cased hole activity
in Asia and new wireline and perforating contracts. Lower sales of
logging equipment and the expiration of a fluid services contract in Asia
partially offset the Middle East/Asia revenue improvement. North
America revenue grew 28% from improved pricing and increased activity in fluid
services, wireline and perforating services, and drilling services and increased
sales of fixed cutter bits. Latin America revenue grew 16% with
increased fluid services operations, improved wireline and perforating pricing,
and increased Landmark consulting services and software sales. The
completion of two fixed-price integrated solutions projects in southern Mexico
partially offset the Latin America revenue improvement. International
revenue was 67% of total segment revenue in 2006 compared to 68% in
2005.
Drilling
and Evaluation operating income increase compared to 2005 spanned all geographic
regions, with the United States as the predominant contributor due to improved
pricing and increased rig activity. Europe/Africa/CIS operating
income grew 27% from new drilling service contracts in Europe and stronger
software and service sales for Landmark in Europe. Middle East/Asia
operating income grew 57% from higher wireline and perforating services activity
in the region, new drilling services contracts in Asia, and increased fluid
services activity in Asia. Latin America operating income more than
doubled. Wireline and perforating results contributed to the Latin
America increase due to improved product mix. Included in Latin
America 2005 results was $23 million in losses on two fixed-priced integrated
solutions projects. The segment received hurricane insurance proceeds
of $26 million in 2006. Operating income in 2005 included a $24
million gain related to a patent infringement case settlement, while hurricanes
in the Gulf of Mexico negatively impacted segment operating income by an
estimated $21 million.
Corporate and other expenses
were $223 million in 2006 compared to $200 million in 2005. The
increase was primarily due to increased legal costs and costs incurred for the
separation of KBR from Halliburton. The 2006 segment results included
a gain of $10 million from the sale of an investment accounted for under the
cost method.
NONOPERATING
ITEMS
Interest expense decreased
$31 million in 2006 compared to 2005, primarily due to the redemption in April
2005 of $500 million of our floating rate senior notes, the repayment in October
2005 of $300 million of our floating rate senior notes, and the repayment in
August 2006 of $275 million of our medium-term notes.
Interest income increased $75
million in 2006 compared to 2005 due to higher cash investment
balances.
Other, net increased $15
million in 2006 compared to 2005. The 2005 year included costs
related to our accounts receivable securitization facility, which had no
outstanding amounts.
(Provision) benefit for income taxes
from continuing operations in 2006 of $1 billion resulted in an effective
tax rate of 31%. The tax benefit for 2005 resulted from recording
favorable adjustments in 2005 totaling $805 million to our valuation allowance
against the deferred tax asset related to asbestos and silica
liabilities. Our strong 2005 earnings, coupled with an upward
revision in our estimate of future domestic taxable income in 2006, drove these
adjustments.
Income from discontinued operations,
net of income tax provision in 2006 and 2005 primarily consisted of our
results of KBR.
CRITICAL
ACCOUNTING ESTIMATES
The
preparation of financial statements requires the use of judgments and
estimates. Our critical accounting policies are described below to
provide a better understanding of how we develop our assumptions and judgments
about future events and related estimations and how they can impact our
financial statements. A critical accounting estimate is one that
requires our most difficult, subjective, or complex estimates and assessments
and is fundamental to our results of operations. We identified our
most critical accounting policies and estimates to be:
|
-
|
forecasting
our effective tax rate, including our future ability to utilize foreign
tax credits and the realizability of deferred tax assets, and providing
for uncertain tax positions;
|
|
-
|
percentage-of-completion
accounting for long-term, construction-type
contracts;
|
|
-
|
legal
and investigation matters;
|
|
-
|
valuations
of indemnities;
|
|
-
|
allowance
for bad debts.
|
We base
our estimates on historical experience and on various other assumptions we
believe to be reasonable according to the current facts and circumstances, the
results of which form the basis for making judgments about the carrying values
of assets and liabilities that are not readily apparent from other
sources. We believe the following are the critical accounting
policies used in the preparation of our consolidated financial statements, as
well as the significant estimates and judgments affecting the application of
these policies. This discussion and analysis should be read in
conjunction with our consolidated financial statements and related notes
included in this report.
We have
discussed the development and selection of these critical accounting policies
and estimates with the Audit Committee of our Board of Directors, and the Audit
Committee has reviewed the disclosure presented below.
Income
tax accounting
We
account for income taxes in accordance with Statement of Financial Accounting
Standards No. 109 (SFAS No. 109), “Accounting for Income Taxes,” which requires
recognition of the amount of taxes payable or refundable for the current year
and an asset and liability approach in recognizing the amount of deferred tax
liabilities and assets for the future tax consequences of events that have been
recognized in our financial statements or tax returns. We apply the
following basic principles in accounting for our income taxes:
|
-
|
a
current tax liability or asset is recognized for the estimated taxes
payable or refundable on tax returns for the current
year;
|
|
-
|
a
deferred tax liability or asset is recognized for the estimated future tax
effects attributable to temporary differences and
carryforwards;
|
|
-
|
the
measurement of current and deferred tax liabilities and assets is based on
provisions of the enacted tax law, and the effects of potential future
changes in tax laws or rates are not considered;
and
|
|
-
|
the
value of deferred tax assets is reduced, if necessary, by the amount of
any tax benefits that, based on available evidence, are not expected to be
realized.
|
We
determine deferred taxes separately for each tax-paying component (an entity or
a group of entities that is consolidated for tax purposes) in each tax
jurisdiction. That determination includes the following
procedures:
|
-
|
identifying
the types and amounts of existing temporary
differences;
|
|
-
|
measuring
the total deferred tax liability for taxable temporary differences using
the applicable tax rate;
|
|
-
|
measuring
the total deferred tax asset for deductible temporary differences and
operating loss carryforwards using the applicable tax
rate;
|
|
-
|
measuring
the deferred tax assets for each type of tax credit carryforward;
and
|
|
-
|
reducing
the deferred tax assets by a valuation allowance if, based on available
evidence, it is more likely than not that some portion or all of the
deferred tax assets will not be
realized.
|
Our
methodology for recording income taxes requires a significant amount of judgment
in the use of assumptions and estimates. Additionally, we use
forecasts of certain tax elements, such as taxable income and foreign tax credit
utilization, as well as evaluate the feasibility of implementing tax planning
strategies. Given the inherent uncertainty involved with the use of
such variables, there can be significant variation between anticipated and
actual results. Unforeseen events may significantly impact these
variables, and changes to these variables could have a material impact on our
income tax accounts related to both continuing and discontinued
operations.
We have
operations in approximately 70 countries other than the United
States. Consequently, we are subject to the jurisdiction of a
significant number of taxing authorities. The income earned in these
various jurisdictions is taxed on differing bases, including income actually
earned, income deemed earned, and revenue-based tax withholding. The
final determination of our tax liabilities involves the interpretation of local
tax laws, tax treaties, and related authorities in each
jurisdiction. Changes in the operating environment, including changes
in tax law and currency/repatriation controls, could impact the determination of
our tax liabilities for a tax year.
Tax
filings of our subsidiaries, unconsolidated affiliates, and related entities are
routinely examined in the normal course of business by tax
authorities. These examinations may result in assessments of
additional taxes, which we work to resolve with the tax authorities and through
the judicial process. Predicting the outcome of disputed assessments
involves some uncertainty. Factors such as the availability of
settlement procedures, willingness of tax authorities to negotiate, and the
operation and impartiality of judicial systems vary across the different tax
jurisdictions and may significantly influence the ultimate
outcome. We review the facts for each assessment, and then utilize
assumptions and estimates to determine the most likely outcome and provide
taxes, interest, and penalties as needed based on this outcome. We
provide for uncertain tax positions pursuant to FIN 48, “Accounting for
Uncertainty in Income Taxes, an interpretation of FASB Statement No.
109.” FIN 48, as amended May 2007 by FASB Staff Position FIN 48-1,
“Definition of ‘Settlement’ in FASB Interpretation No. 48,” prescribes a minimum
recognition threshold and measurement methodology that a tax position taken or
expected to be taken in a tax return is required to meet before being recognized
in the financial statements. It also provides guidance for
derecognition classification, interest and penalties, accounting in interim
periods, disclosure, and transition.
We had
recorded a valuation allowance based on the anticipated inability to utilize
future foreign tax credits in the United States as of the end of
2006. This valuation allowance is reassessed quarterly based on a
number of estimates, including future creditable foreign taxes and future
taxable income. Factors such as actual operating results, material
acquisitions or dispositions, and changes to our operating environment could
alter the estimates, which could have a material impact on the valuation
allowance. Given that we fully utilized the United States net
operating loss and began utilizing foreign tax credits in the United States in
2006, the valuation allowance balance has been reduced to zero as of the end of
2007. In addition, the provision for income taxes in 2007 included a
favorable income tax adjustment from the ability to recognize foreign tax
credits previously generated in 2005 and 2006 thought not to be fully
utilizable. We now believe we can utilize these credits currently
because we have generated additional taxable income and expect to continue to
generate a higher level of taxable income largely from the growth of our
international operations.
Percentage
of completion
Revenue
from long-term contracts to provide well construction and completion services is
reported on the percentage-of-completion method of accounting. This
method of accounting requires us to calculate job profit to be recognized in
each reporting period for each job based upon our projections of future
outcomes, which include:
|
-
|
estimates
of the total cost to complete the
project;
|
|
-
|
estimates
of project schedule and completion
date;
|
|
-
|
estimates
of the extent of progress toward completion;
and
|
|
-
|
amounts
of any probable unapproved claims and change orders included in
revenue.
|
Progress
is generally based upon physical progress related to contractually defined units
of work. At the outset of each contract, we prepare a detailed
analysis of our estimated cost to complete the project. Risks related
to service delivery, usage, productivity, and other factors are considered in
the estimation process. Our project personnel periodically evaluate
the estimated costs, claims, change orders, and percentage of completion at the
project level. The recording of profits and losses on long-term
contracts requires an estimate of the total profit or loss over the life of each
contract. This estimate requires consideration of total contract
value, change orders, and claims, less costs incurred and estimated costs to
complete. Anticipated losses on contracts are recorded in full in the
period in which they become evident. Profits are recorded based upon
the total estimated contract profit times the current percentage complete for
the contract.
When
calculating the amount of total profit or loss on a long-term contract, we
include unapproved claims as revenue when the collection is deemed probable
based upon the four criteria for recognizing unapproved claims under the
American Institute of Certified Public Accountants Statement of Position 81-1,
“Accounting for Performance of Construction-Type and Certain Production-Type
Contracts.” Including probable unapproved claims in this calculation
increases the operating income (or reduces the operating loss) that would
otherwise be recorded without consideration of the probable unapproved
claims. Probable unapproved claims are recorded to the extent of
costs incurred and include no profit element. In all cases, the
probable unapproved claims included in determining contract profit or loss are
less than the actual claim that will be or has been presented to the
customer.
At least
quarterly, significant projects are reviewed in detail by senior
management. There are many factors that impact future costs,
including but not limited to weather, inflation, labor and community
disruptions, timely availability of materials, productivity, and other factors
as outlined in our “Risk Factors.” These factors can affect the
accuracy of our estimates and materially impact our future reported
earnings.
Legal
and investigation matters
As
discussed in Note 10 of our consolidated financial statements, as of December
31, 2007, we have accrued an estimate of the probable and estimable costs for
the resolution of some of these legal and investigation matters. For
other matters for which the liability is not probable and reasonably estimable,
we have not accrued any amounts. Attorneys in our legal department
monitor and manage all claims filed against us and review all pending
investigations. Generally, the estimate of probable costs related to
these matters is developed in consultation with internal and outside legal
counsel representing us. Our estimates are based upon an analysis of
potential results, assuming a combination of litigation and settlement
strategies. The precision of these estimates is impacted by the
amount of due diligence we have been able to perform. We attempt to
resolve these matters through settlements, mediation, and arbitration
proceedings when possible. If the actual settlement costs, final
judgments, or fines, after appeals, differ from our estimates, our future
financial results may be adversely affected. We have in the past
recorded significant adjustments to our initial estimates of these types of
contingencies.
Indemnity
valuations
We
provided indemnification in favor of KBR for certain contingent liabilities
related to Foreign Corrupt Practices Act (FCPA) investigations and the
Barracuda-Caratinga bolts matter. See Note 2 to the consolidated
financial statements for further information. FASB Interpretation No.
45 (FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others – An Interpretation of
FASB Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No.
34,” requires recognition of third-party indemnities at their
inception. Therefore, in accordance with FIN 45, we recorded our estimate of
the fair market value of these indemnities as of the date of KBR’s
separation. The amounts recorded for the FCPA and Barracuda-Caratinga
indemnities were based upon analyses conducted by a third-party valuation
expert. The valuation models employed a probability-weighted cost
analysis, with certain assumptions based upon the accumulation of data and
knowledge of the relevant issues. Periodically, a determination will
be made as to whether any material changes in facts or circumstances have
occurred that would impact assumptions used in the third-party
valuation.
Pensions
Our
pension benefit obligations and expenses are calculated using actuarial models
and methods, in accordance with SFAS No. 158, “Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans, an
amendment of FASB Statements No. 87, 88, 106 and 132(R).” Two of the
more critical assumptions and estimates used in the actuarial calculations are
the discount rate for determining the current value of plan benefits and the
expected rate of return on plan assets. Other critical assumptions
and estimates used in determining benefit obligations and plan expenses,
including demographic factors such as retirement age, mortality, and turnover,
are also evaluated periodically and updated accordingly to reflect our actual
experience.
Discount
rates are determined annually and are based on the prevailing market rate of a
portfolio of high-quality debt instruments with maturities matching the expected
timing of the payment of the benefit obligations. Expected long-term
rates of return on plan assets are determined annually and are based on an
evaluation of our plan assets, historical trends, and experience, taking into
account current and expected market conditions. Plan assets are
comprised primarily of equity and debt securities. As we have both
domestic and international plans, these assumptions differ based on varying
factors specific to each particular country or economic
environment.
The
discount rate utilized in 2007 to determine the projected benefit obligation at
the measurement date for our United States non-terminating pension plans ranged
from 6.03% to 6.19%, an increase from the 5.75% discount rate that was utilized
in 2006. The discount rate utilized to determine the projected
benefit obligation at the measurement date for our United Kingdom pension plan,
which constitutes 76% of our international plans and 67% of all plans, increased
from 5.0% at September 30, 2006 to 5.7% at September 30, 2007. The
following table illustrates the sensitivity to changes in certain assumptions,
holding all other assumptions constant, for the United Kingdom pension
plan.
|
|
Effect
on
|
|
|
|
|
|
|
Pension
Benefit
|
|
|
|
Pension
Expense
|
|
|
Obligation
|
|
Millions
of dollars
|
|
in
2007
|
|
|
at
December 31, 2007
|
|
25-basis-point
decrease in discount rate
|
|
$ |
3 |
|
|
$ |
40 |
|
25-basis-point
increase in discount rate
|
|
$ |
(3 |
) |
|
$ |
(38 |
) |
Our
defined benefit plans reduced pretax earnings by $48 million in 2007, $45
million in 2006, and $37 million in 2005. Included in the amounts
were earnings from our expected pension returns of $47 million in 2007, $37
million in 2006, and $35 million in 2005. Unrecognized actuarial
gains and losses were being recognized over a period of one to 24 years, which
represented the expected remaining service life of the employee
group. Our unrecognized actuarial gains and losses arose from several
factors, including experience and assumptions changes in the obligations and the
difference between expected returns and actual returns on plan
assets. Actual returns were $68 million in 2007, $65 million in 2006,
and $83 million in 2005. The difference between actual and expected
returns is deferred and recorded net of tax in other comprehensive income as
actuarial gain or loss and is recognized as future pension
expense. Our net actuarial loss, net of tax, at December 31, 2007 was
$46 million. On a pretax basis, $3 million of our net actuarial loss
at December 31, 2007 will be recognized as a component of our expected 2008
pension expense. During 2007, we made contributions to fund our
defined benefit plans of $41 million, which included $16 million contributed to
our United Kingdom plan. We expect to make additional contributions
in 2008 of approximately $30 million.
The
actuarial assumptions used in determining our pension benefits may differ
materially from actual results due to changing market and economic conditions,
higher or lower withdrawal rates, and longer or shorter life spans of
participants. While we believe that the assumptions used are
appropriate, differences in actual experience or changes in assumptions may
materially affect our financial position or results of operations.
Allowance
for bad debts
We
evaluate our accounts receivable through a continuous process of assessing our
portfolio on an individual customer and overall basis. This process
consists of a thorough review of historical collection experience, current aging
status of the customer accounts, financial condition of our customers, and
whether the receivables involve retentions. We also consider the
economic environment of our customers, both from a marketplace and geographic
perspective, in evaluating the need for an allowance. Based on our
review of these factors, we establish or adjust allowances for specific
customers and the accounts receivable portfolio as a whole. This
process involves a high degree of judgment and estimation, and frequently
involves significant dollar amounts. Accordingly, our results of
operations can be affected by adjustments to the allowance due to actual
write-offs that differ from estimated amounts. Our estimates of
allowances for bad debts have historically been accurate. Over the
last five years, our estimates of allowances for bad debts, as a percentage of
notes and accounts receivable before the allowance, have ranged from 1.5% to
7.3%. At December 31, 2007, allowance for bad debts totaled $49
million or 1.6% of notes and accounts receivable before the allowance, and at
December 31, 2006, allowance for bad debts totaled $40 million or 1.5% of notes
and accounts receivable before the allowance. A 1% change in our
estimate of the collectibility of our notes and accounts receivable balance as
of December 31, 2007 would have resulted in a $31 million adjustment to 2007
total operating costs and expenses.
OFF
BALANCE SHEET ARRANGEMENTS
At
December 31, 2007, we had no material off balance sheet arrangements, except for
operating leases. For information on our contractual obligations
related to operating leases, see “Management’s Discussion and Analysis of
Financial Condition and Results of Operations – Liquidity and Capital Resources
– Future uses of cash.”
FINANCIAL
INSTRUMENT MARKET RISK
We are
exposed to financial instrument market risk from changes in foreign currency
exchange rates, interest rates, and, to a limited extent, commodity
prices. From time to time, we may selectively manage these exposures
through the use of derivative instruments to mitigate our market risk from these
exposures. The objective of our risk management program is to protect
our cash flows related to sales or purchases of goods or services from market
fluctuations in currency rates. We do not use derivative instruments
for trading purposes. Our use of derivative instruments includes the
following types of market risk:
|
-
|
volatility
of the currency rates;
|
|
-
|
time
horizon of the derivative
instruments;
|
|
-
|
the
type of derivative instruments
used.
|
We do not
consider any of these risk management activities to be material. See
Note 1 to the consolidated financial statements for additional information on
our accounting policies on derivative instruments. See Note 14 to the
consolidated financial statements for additional disclosures related to
financial instruments.
Interest
rate risk
We have
exposure to interest rate risk from our long-term debt.
The
following table represents principal amounts of our long-term debt at December
31, 2007 and related weighted average interest rates on the repaid amounts by
year of maturity for our long-term debt.
Millions
of dollars
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Thereafter
|
|
|
Total
|
|
Fixed-rate
debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Repayment amount
($US)
|
|
$ |
150 |
|
|
$ |
3 |
|
|
$ |
753 |
|
|
$ |
3 |
|
|
$ |
4 |
|
|
$ |
1,856 |
|
|
$ |
2,769 |
|
Weighted
average
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
interest rate
on
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
repaid amount
|
|
|
5.6 |
% |
|
|
5.6 |
% |
|
|
5.5 |
% |
|
|
5.5 |
% |
|
|
5.5 |
% |
|
|
4.7 |
% |
|
|
5.0 |
% |
Variable-rate
debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Repayment amount
($US)
|
|
$ |
9 |
|
|
$ |
9 |
|
|
$ |
3 |
|
|
$ |
– |
|
|
$ |
– |
|
|
$ |
– |
|
|
$ |
21 |
|
Weighted
average
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
interest rate
on
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
repaid amount
|
|
|
8.5 |
% |
|
|
8.5 |
% |
|
|
8.5 |
% |
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
8.5 |
% |
The fair
market value of long-term debt was $4.1 billion as of December 31,
2007. The excess of the fair value of long-term debt over the
carrying amount of long-term debt is primarily due to the impact of the
increased value of our common stock on our 3.125% convertible senior
notes.
ENVIRONMENTAL
MATTERS
We are
subject to numerous environmental, legal, and regulatory requirements related to
our operations worldwide. In the United States, these laws and
regulations include, among others:
|
-
|
the
Comprehensive Environmental Response, Compensation, and Liability
Act;
|
|
-
|
the
Resource Conservation and Recovery
Act;
|
|
-
|
the
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. Our accrued liabilities for environmental matters were
$72 million as of December 31, 2007 and $39 million as of December 31,
2006. Our total liability related to environmental matters covers
numerous properties, including the property in regard to which Dirt, Inc. has
brought suit against Bredero-Shaw (a joint venture in which we formerly held a
50% interest that we sold to the other party in the venture, ShawCor Ltd., in
2002), Halliburton Energy Services, Inc., and ShawCor Ltd. See Note
10 to our consolidated financial statements for further information regarding
this matter.
We have
subsidiaries that have been named as potentially responsible parties along with
other third parties for 9 federal and state superfund sites for which we have
established a liability. As of December 31, 2007, those 9 sites
accounted for approximately $10 million of our total $72 million
liability. For any particular federal or state superfund site, since
our estimated liability is typically within a range and our accrued liability
may be the amount on the low end of that range, our actual liability could
eventually be well in excess of the amount accrued. Despite attempts
to resolve these superfund matters, the relevant regulatory agency may at any
time bring suit against us for amounts in excess of the amount
accrued. With respect to some superfund sites, we have been named a
potentially responsible party by a regulatory agency; however, in each of those
cases, we do not believe we have any material liability. We also
could be subject to third-party claims with respect to environmental matters for
which we have been named as a potentially responsible party.
NEW
ACCOUNTING PRONOUNCEMENTS
Effective
January 1, 2007, we adopted FASB Interpretation No. 48 (FIN 48), “Accounting for
Uncertainty in Income Taxes, an interpretation of FASB Statement No.
109.” FIN 48, as amended May 2007 by FASB Staff Position FIN 48-1,
“Definition of ‘settlement’ in FASB Interpretation No. 48,” prescribes a minimum
recognition threshold and measurement methodology that a tax position taken or
expected to be taken in a tax return is required to meet before being recognized
in the financial statements. It also provides guidance for
derecognition, classification, interest and penalties, accounting in interim
periods, disclosure, and transition.
As a
result of the adoption of FIN 48, we recognized a decrease of $4 million in
other liabilities to account for a decrease in unrecognized tax benefits and an
increase of $34 million for accrued interest and penalties, which were accounted
for as a net reduction of $30 million to the January 1, 2007 balance of retained
earnings. Of the $30 million reduction to retained earnings, $10
million was attributable to KBR, which is now reported as discontinued
operations in the consolidated financial statements. See Note 11 to
our consolidated financial statements for further information.
In
September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined
Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements
No. 87, 88, 106, and 132(R).” SFAS No. 158 requires an employer
to:
|
-
|
recognize
on its balance sheet the funded status (measured as the difference between
the fair value of plan assets and the benefit obligation) of pension and
other postretirement benefit plans;
|
|
-
|
recognize,
through comprehensive income, certain changes in the funded status of a
defined benefit and postretirement plan in the year in which the changes
occur;
|
|
-
|
measure
plan assets and benefit obligations as of the end of the employer’s fiscal
year; and
|
|
-
|
disclose
additional information.
|
The
requirements to recognize the funded status of a benefit plan and the additional
disclosure requirements were effective for fiscal years ending after December
15, 2006. Accordingly, we adopted SFAS No. 158 for our fiscal year
ending December 31, 2006. See Note 15 to our consolidated financial
statements for further information.
The
requirement to measure plan assets and benefit obligations as of the date of the
employer’s fiscal year-end is effective for fiscal years ending after December
15, 2008. We did not elect early adoption of these additional SFAS
No. 158 requirements and will adopt these requirements for our fiscal year
ending December 31, 2008.
In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which
is intended to increase consistency and comparability in fair value measurements
by defining fair value, establishing a framework for measuring fair value, and
expanding disclosures about fair value measurements. SFAS No. 157
applies to other accounting pronouncements that require or permit fair value
measurements and is effective for financial statements issued for fiscal years
beginning after November 15, 2007 and interim periods within those fiscal
years. In November 2007, the FASB deferred for one year the
application of the fair value measurement requirements to nonfinancial assets
and liabilities that are not required or permitted to be measured at fair value
on a recurring basis. On January 1, 2008, we adopted without material
impact on our consolidated financial statements the provisions of SFAS No. 157
related to financial assets and liabilities and to nonfinancial assets and
liabilities measured at fair value on a recurring basis. Beginning
January 1, 2009, we will adopt the provisions for nonfinancial assets and
liabilities that are not required or permitted to be measured at fair value on a
recurring basis, which we do not expect to have a material impact on our
consolidated financial statements.
In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities – Including an amendment of FASB
Statement No. 115.” SFAS No. 159 permits entities to measure eligible
assets and liabilities at fair value. Unrealized gains and losses on
items for which the fair value option has been elected are reported in
earnings. SFAS No. 159 is effective for fiscal years beginning after
November 15, 2007. We adopted SFAS No. 159 on January 1, 2008 and did
not elect to apply the fair value method to any eligible assets or liabilities
at that time.
In
December 2007, the FASB issued Statement No. 141(Revised 2007), “Business
Combinations” (SFAS No. 141(R)). SFAS No. 141(R) requires an
acquiring entity to recognize all the assets acquired and liabilities assumed in
a transaction at the acquisition-date fair value with limited
exceptions. SFAS No. 141(R) also changes the accounting treatment for
certain specific items. SFAS No. 141(R) applies prospectively to
business combinations for which the acquisition date is on or after the first
annual reporting period beginning on or after December 15, 2008. We
will adopt the provisions of SFAS No. 141(R) for business combinations on or
after January 1, 2009.
In
December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements – An Amendment of ARB No. 51.” SFAS
No. 160 establishes new accounting and reporting standards for the
noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. This statement requires the recognition of a
noncontrolling interest (minority interest) as equity in the consolidated
financial statements and separate from the parent’s equity. SFAS No.
160 is effective for fiscal years and interim periods within those fiscal years
beginning on or after December 15, 2008. We will adopt the provision
of SFAS No. 160 on January 1, 2009 and have not yet determined the impact on our
consolidated financial statements.
In
December 2007, the FASB ratified the consensus reached on EITF 07-1, “Accounting
for Collaborative Arrangements Related to the Development and Commercialization
of Intellectual Property.” EITF 07-1 defines collaborative
arrangements and establishes reporting requirements for transactions between
participants in a collaborative arrangement and between participants in the
arrangement and third parties. EITF 07-1 is effective for financial
statements issued for fiscal years beginning after December 15, 2008 and interim
periods within those fiscal years. We will adopt EITF 07-1 on January
1, 2009, which we do not expect to have a material impact on our consolidated
financial statements.
FORWARD-LOOKING
INFORMATION
The
Private Securities Litigation Reform Act of 1995 provides safe harbor provisions
for forward-looking information. Forward-looking information is based
on projections and estimates, not historical information. Some
statements in this Form 10-K are forward-looking and use words like “may,” “may
not,” “believes,” “do not believe,” “expects,” “do not expect,” “anticipates,”
“do not anticipate,” and other expressions. We may also provide oral
or written forward-looking information in other materials we release to the
public. Forward-looking information involves risk and uncertainties
and reflects our best judgment based on current information. Our
results of operations can be affected by inaccurate assumptions we make or by
known or unknown risks and uncertainties. In addition, other factors
may affect the accuracy of our forward-looking information. As a
result, no forward-looking information can be guaranteed. Actual
events and the results of operations may vary materially.
We do not
assume any responsibility to publicly update any of our forward-looking
statements regardless of whether factors change as a result of new information,
future events, or for any other reason. You should review any
additional disclosures we make in our press releases and Forms 10-K, 10-Q, and
8-K filed with or furnished to the SEC. We also suggest that you
listen to our quarterly earnings release conference calls with financial
analysts.
While it
is not possible to identify all factors, we continue to face many risks and
uncertainties that could cause actual results to differ from our forward-looking
statements and potentially materially and adversely affect our financial
condition and results of operations.
RISK
FACTORS
Foreign
Corrupt Practices Act Investigations
The SEC
is conducting a formal investigation into whether improper payments were made to
government officials in Nigeria through the use of agents or subcontractors in
connection with the construction and subsequent expansion by TSKJ of a
multibillion dollar natural gas liquefaction complex and related facilities at
Bonny Island in Rivers State, Nigeria. The Department of Justice
(DOJ) is also conducting a related criminal investigation. The SEC
has also issued subpoenas seeking information, which we and KBR are furnishing,
regarding current and former agents used in connection with multiple projects,
including current and prior projects, over the past 20 years located both in and
outside of Nigeria in which the Halliburton energy services business, KBR or
affiliates, subsidiaries or joint ventures of Halliburton or KBR, are or were
participants. In September 2006 and October 2007, the SEC and the
DOJ, respectively, each requested that we enter into an agreement to extend the
statute of limitations with respect to its investigation. We
anticipate that we will enter into appropriate tolling agreements with the SEC
and the DOJ.
TSKJ is a
private limited liability company registered in Madeira, Portugal whose members
are Technip SA of France, Snamprogetti Netherlands B.V. (a subsidiary of Saipem
SpA of Italy), JGC Corporation of Japan, and Kellogg Brown & Root LLC (a
subsidiary of KBR), each of which had an approximate 25% interest in the
venture. TSKJ and other similarly owned entities entered into various
contracts to build and expand the liquefied natural gas project for Nigeria LNG
Limited, which is owned by the Nigerian National Petroleum Corporation, Shell
Gas B.V., Cleag Limited (an affiliate of Total), and Agip International B.V. (an
affiliate of ENI SpA of Italy).
The SEC
and the DOJ have been reviewing these matters in light of the requirements of
the FCPA. In addition to performing our own investigation, we have
been cooperating with the SEC and the DOJ investigations and with other
investigations in France, Nigeria, and Switzerland regarding the Bonny Island
project. The government of Nigeria gave notice in 2004 to the French
magistrate of a civil claim as an injured party in the French
investigation. We also believe that the Serious Fraud Office in the
United Kingdom is conducting an investigation relating to the Bonny Island
project. Our Board of Directors has appointed a committee of
independent directors to oversee and direct the FCPA
investigations.
The
matters under investigation relating to the Bonny Island project cover an
extended period of time (in some cases significantly before our 1998 acquisition
of Dresser Industries and continuing through the current time
period). We have produced documents to the SEC and the DOJ from the
files of numerous officers and employees of Halliburton and KBR, including
current and former executives of Halliburton and KBR, both voluntarily and
pursuant to company subpoenas from the SEC and a grand jury, and we are making
our employees and we understand KBR is making its employees available to the SEC
and the DOJ for interviews. In addition, the SEC has issued a
subpoena to A. Jack Stanley, who formerly served as a consultant and chairman of
Kellogg Brown & Root LLC, and to others, including certain of our and KBR’s
current or former executive officers or employees, and at least one
subcontractor of KBR. We further understand that the DOJ has issued
subpoenas for the purpose of obtaining information abroad, and we understand
that other partners in TSKJ have provided information to the DOJ and the SEC
with respect to the investigations, either voluntarily or under
subpoenas.
The SEC
and DOJ investigations include an examination of whether TSKJ’s engagements of
Tri-Star Investments as an agent and a Japanese trading company as a
subcontractor to provide services to TSKJ were utilized to make improper
payments to Nigerian government officials. In connection with the
Bonny Island project, TSKJ entered into a series of agency agreements, including
with Tri-Star Investments, of which Jeffrey Tesler is a principal, commencing in
1995 and a series of subcontracts with a Japanese trading company commencing in
1996. We understand that a French magistrate has officially placed
Mr. Tesler under investigation for corruption of a foreign public
official. In Nigeria, a legislative committee of the National
Assembly and the Economic and Financial Crimes Commission, which is organized as
part of the executive branch of the government, are also investigating these
matters. Our representatives have met with the French magistrate and
Nigerian officials. In October 2004, representatives of TSKJ
voluntarily testified before the Nigerian legislative committee.
TSKJ
suspended the receipt of services from and payments to Tri-Star Investments and
the Japanese trading company and has considered instituting legal proceedings to
declare all agency agreements with Tri-Star Investments terminated and to
recover all amounts previously paid under those agreements. In
February 2005, TSKJ notified the Attorney General of Nigeria that TSKJ would not
oppose the Attorney General’s efforts to have sums of money held on deposit in
accounts of Tri-Star Investments in banks in Switzerland transferred to Nigeria
and to have the legal ownership of such sums determined in the Nigerian
courts.
As a
result of these investigations, information has been uncovered suggesting that,
commencing at least 10 years ago, members of TSKJ planned payments to Nigerian
officials. We have reason to believe that, based on the ongoing
investigations, payments may have been made by agents of TSKJ to Nigerian
officials. In addition, information uncovered in the summer of 2006
suggests that, prior to 1998, plans may have been made by employees of The M.W.
Kellogg Company (a predecessor of a KBR subsidiary) to make payments to
government officials in connection with the pursuit of a number of other
projects in countries outside of Nigeria. We are reviewing a number
of more recently discovered documents related to KBR’s activities in countries
outside of Nigeria with respect to agents for projects after
1998. Certain activities discussed in this paragraph involve current
or former employees or persons who were or are consultants to KBR, and our
investigation is continuing.
In June
2004, all relationships with Mr. Stanley and another consultant and former
employee of M.W. Kellogg Limited were terminated. The terminations
occurred because of Code of Business Conduct violations that allegedly involved
the receipt of improper personal benefits from Mr. Tesler in connection with
TSKJ’s construction of the Bonny Island project.
In 2006
and 2007, KBR suspended the services of other agents in and outside of Nigeria,
including one agent who, until such suspension, had worked for KBR outside of
Nigeria on several current projects and on numerous older projects going back to
the early 1980s. Such suspensions have occurred when possible
improper conduct has been discovered or alleged or when Halliburton and KBR have
been unable to confirm the agent’s compliance with applicable law and the Code
of Business Conduct.
The SEC
and DOJ are also investigating and have issued subpoenas concerning TSKJ's use
of an immigration services provider, apparently managed by a Nigerian
immigration official, to which approximately $1.8 million in payments in excess
of costs of visas were allegedly made between approximately 1997 and the
termination of the provider in December 2004. We understand that TSKJ
terminated the immigration services provider after a KBR employee discovered the
issue. We reported this matter to the United States government in
2007. The SEC has issued a subpoena requesting documents among other
things concerning any payment of anything of value to Nigerian government
officials. In response to such subpoena, we have produced and
continue to produce additional documents regarding KBR and Halliburton’s energy
services business use of immigration and customs service providers, which may
result in further inquiries. Furthermore, as a result of these
matters, we have expanded our own investigation to consider any matters raised
by energy services activities in Nigeria.
If
violations of the FCPA were found, a person or entity found in violation could
be subject to fines, civil penalties of up to $500,000 per violation, equitable
remedies, including disgorgement (if applicable) generally of profits, including
prejudgment interest on such profits, causally connected to the violation, and
injunctive relief. Criminal penalties could range up to the greater
of $2 million per violation or twice the gross pecuniary gain or loss from the
violation, which could be substantially greater than $2 million per
violation. It is possible that both the SEC and the DOJ could assert
that there have been multiple violations, which could lead to multiple
fines. The amount of any fines or monetary penalties that could be
assessed would depend on, among other factors, the findings regarding the
amount, timing, nature, and scope of any improper payments, whether any such
payments were authorized by or made with knowledge of us, KBR or our or KBR’s
affiliates, the amount of gross pecuniary gain or loss involved, and the level
of cooperation provided the government authorities during the
investigations. The government has expressed concern regarding the
level of our cooperation. Agreed dispositions of these types of
violations also frequently result in an acknowledgement of wrongdoing by the
entity and the appointment of a monitor on terms negotiated with the SEC and the
DOJ to review and monitor current and future business practices, including the
retention of agents, with the goal of assuring compliance with the
FCPA.
These
investigations could also result in third-party claims against us, which may
include claims for special, indirect, derivative or consequential damages,
damage to our business or reputation, loss of, or adverse effect on, cash flow,
assets, goodwill, results of operations, business prospects, profits or business
value or claims by directors, officers, employees, affiliates, advisors,
attorneys, agents, debt holders, or other interest holders or constituents of us
or our current or former subsidiaries. In addition, we could incur
costs and expenses for any monitor required by or agreed to with a governmental
authority to review our continued compliance with FCPA law.
As of
December 31, 2007, we are unable to estimate an amount of probable loss or a
range of possible loss related to these matters as it relates to Halliburton
directly. However, we provided indemnification in favor of KBR under
the master separation agreement for certain contingent liabilities, including
Halliburton’s indemnification of KBR and any of its greater than 50%-owned
subsidiaries as of November 20, 2006, the date of the master separation
agreement, for fines or other monetary penalties or direct monetary damages,
including disgorgement, as a result of a claim made or assessed by a
governmental authority in the United States, the United Kingdom, France,
Nigeria, Switzerland, and/or Algeria, or a settlement thereof, related to
alleged or actual violations occurring prior to November 20, 2006 of the FCPA or
particular, analogous applicable foreign statutes, laws, rules, and regulations
in connection with investigations pending as of that date, including with
respect to the construction and subsequent expansion by TSKJ of a natural gas
liquefaction complex and related facilities at Bonny Island in Rivers State,
Nigeria. We recorded the estimated fair market value of this
indemnity regarding FCPA matters described above upon our separation from
KBR. See Note 2 to our consolidated financial statements for
additional information.
Our
indemnification obligation to KBR does not include losses resulting from
third-party claims against KBR, including claims for special, indirect,
derivative or consequential damages, nor does our indemnification apply to
damage to KBR’s business or reputation, loss of, or adverse effect on, cash
flow, assets, goodwill, results of operations, business prospects, profits or
business value or claims by directors, officers, employees, affiliates,
advisors, attorneys, agents, debt holders, or other interest holders or
constituents of KBR or KBR’s current or former subsidiaries.
In
consideration of our agreement to indemnify KBR for the liabilities referred to
above, KBR has agreed that we will at all times, in our sole discretion, have
and maintain control over the investigation, defense and/or settlement of these
FCPA matters until such time, if any, that KBR exercises its right to assume
control of the investigation, defense and/or settlement of the FCPA matters as
it relates to KBR. KBR has also agreed, at our expense, to assist
with Halliburton’s full cooperation with any governmental authority in our
investigation of these FCPA matters and our investigation, defense and/or
settlement of any claim made by a governmental authority or court relating to
these FCPA matters, in each case even if KBR assumes control of these FCPA
matters as it relates to KBR. If KBR takes control over the
investigation, defense, and/or settlement of FCPA matters, refuses a settlement
of FCPA matters negotiated by us, enters into a settlement of FCPA matters
without our consent, or materially breaches its obligation to cooperate with
respect to our investigation, defense, and/or settlement of FCPA matters, we may
terminate the indemnity.
Barracuda-Caratinga
Arbitration
We also
provided indemnification in favor of KBR under the master separation agreement
for all out-of-pocket cash costs and expenses (except for legal fees and other
expenses of the arbitration so long as KBR controls and directs it), or cash
settlements or cash arbitration awards in lieu thereof, KBR may incur after
November 20, 2006 as a result of the replacement of certain subsea flowline
bolts installed in connection with the Barracuda-Caratinga
project. Under the master separation agreement, KBR currently
controls the defense, counterclaim, and settlement of the subsea flowline bolts
matter. As a condition of our indemnity, for any settlement to be
binding upon us, KBR must secure our prior written consent to such settlement’s
terms. We have the right to terminate the indemnity in the event KBR
enters into any settlement without our prior written consent. See
Note 2 to our consolidated financial statements for additional information
regarding the KBR indemnification.
At
Petrobras’ direction, KBR replaced certain bolts located on the subsea flowlines
that failed through mid-November 2005, and KBR has informed us that additional
bolts have failed thereafter, which were replaced by Petrobras. These
failed bolts were identified by Petrobras when it conducted inspections of the
bolts. A key issue in the arbitration is which party is responsible
for the designation of the material to be used for the bolts. We
understand that KBR believes that an instruction to use the particular bolts was
issued by Petrobras, and as such, KBR believes the cost resulting from any
replacement is not KBR’s responsibility. We understand Petrobras
disagrees. We understand KBR believes several possible solutions may
exist, including replacement of the bolts. Estimates indicate that
costs of these various solutions range up to $140 million. In March
2006, Petrobras commenced arbitration against KBR claiming $220 million plus
interest for the cost of monitoring and replacing the defective bolts and all
related costs and expenses of the arbitration, including the cost of attorneys’
fees. We understand KBR is vigorously defending and pursuing recovery
of the costs incurred to date through the arbitration process and to that end
has submitted a counterclaim in the arbitration seeking the recovery of $22
million. The arbitration panel has set an evidentiary hearing in
April 2008.
Impairment
of Oil and Gas Properties
At
December 31, 2007, we had interests in oil and gas properties totaling $110
million, net of accumulated depletion, which we account for under the successful
efforts method. The majority of this amount is related to one
property in Bangladesh in which we have a 25% non-operating
interest. These oil and gas properties are assessed for impairment
whenever changes in facts and circumstances indicate that the properties’
carrying amounts may not be recoverable. The expected future cash
flows used for impairment reviews and related fair-value calculations are based
on judgmental assessments of future production volumes, prices, and costs,
considering all available information at the date of review.
In
December 2007, we learned that the drilling program in which we were engaged on
one of two prospects in Bangladesh was unsuccessful. Consequently, we
recorded a $34 million charge for the write-off of our drilling costs and
impairment of the leasehold carrying value. This charge is included
in our results of operations for 2007. We expect to know the results
of the drilling activity on the second prospect by the end of the first quarter
of 2008. Depending on the results, we could incur additional
charges.
A
downward trend in estimates of production volumes or prices or an upward trend
in costs could result in an impairment of our oil and gas properties, which in
turn could have a material and adverse effect on our results of
operations.
Geopolitical
and International Environment
International
and political events
A
significant portion of our revenue is derived from our non-United States
operations, which exposes us to risks inherent in doing business in each of the
countries in which we transact business. The occurrence of any of the
risks described below could have a material adverse effect on our consolidated
results of operations and consolidated financial condition.
Our
operations in countries other than the United States accounted for approximately
56% of our consolidated revenue during 2007 and 55% of our consolidated revenue
during 2006. Operations in countries other than the United States are
subject to various risks unique to each country. With respect to any
particular country, these risks may include:
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expropriation
and nationalization of our assets in that
country;
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political
and economic instability;
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civil
unrest, acts of terrorism, force majeure, war, or other armed
conflict;
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natural
disasters, including those related to earthquakes and
flooding;
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currency
fluctuations, devaluations, and conversion
restrictions;
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confiscatory
taxation or other adverse tax
policies;
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governmental
activities that limit or disrupt markets, restrict payments, or limit the
movement of funds;
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governmental
activities that may result in the deprivation of contract rights;
and
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governmental
activities that may result in the inability to obtain or retain licenses
required for operation.
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Due to
the unsettled political conditions in many oil-producing countries, our revenue
and profits are subject to the adverse consequences of war, the effects of
terrorism, civil unrest, strikes, currency controls, and governmental
actions. Countries where we operate that have significant political
risk include: Algeria, Indonesia, Nigeria, Russia, Venezuela, and
Yemen. In addition, military action or continued unrest in the Middle
East could impact the supply and pricing for oil and gas, disrupt our operations
in the region and elsewhere, and increase our costs for security
worldwide.
In
addition, investigations by governmental authorities (see “Foreign Corrupt
Practices Act investigations” above), as well as legal, social, economic, and
political issues in Nigeria, could materially and adversely affect our Nigerian
business and operations.
Our
facilities and our employees are under threat of attack in some countries where
we operate. In addition, the risks related to loss of life of our
personnel and our subcontractors in these areas continue.
We are
also subject to the risks that our employees, joint venture partners, and agents
outside of the United States may fail to comply with applicable
laws.
Military
action, other armed conflicts, or terrorist attacks
Military
action in Iraq, military tension involving North Korea and Iran, as well as the
terrorist attacks of September 11, 2001 and subsequent terrorist attacks,
threats of attacks, and unrest, have caused instability or uncertainty in the
world’s financial and commercial markets and have significantly increased
political and economic instability in some of the geographic areas in which we
operate. Acts of terrorism and threats of armed conflicts in or
around various areas in which we operate, such as the Middle East, Nigeria, and
Indonesia, could limit or disrupt markets and our operations, including
disruptions resulting from the evacuation of personnel, cancellation of
contracts, or the loss of personnel or assets.
Such
events may cause further disruption to financial and commercial markets and may
generate greater political and economic instability in some of the geographic
areas in which we operate. In addition, any possible reprisals as a
consequence of the war and ongoing military action in Iraq, such as acts of
terrorism in the United States or elsewhere, could materially and adversely
affect us in ways we cannot predict at this time.
Income
taxes
We have
operations in approximately 70 countries other than the United
States. Consequently, we are subject to the jurisdiction of a
significant number of taxing authorities. The income earned in these
various jurisdictions is taxed on differing bases, including net income actually
earned, net income deemed earned, and revenue-based tax
withholding. The final determination of our tax liabilities involves
the interpretation of local tax laws, tax treaties, and related authorities in
each jurisdiction, as well as the significant use of estimates and assumptions
regarding the scope of future operations and results achieved and the timing and
nature of income earned and expenditures incurred. Changes in the
operating environment, including changes in or interpretation of tax law and
currency/repatriation controls, could impact the determination of our tax
liabilities for a tax year.
Foreign
exchange and currency risks
A sizable
portion of our consolidated revenue and consolidated operating expenses is in
foreign currencies. As a result, we are subject to significant risks,
including:
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foreign
exchange risks resulting from changes in foreign exchange rates and the
implementation of exchange controls;
and
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limitations
on our ability to reinvest earnings from operations in one country to fund
the capital needs of our operations in other
countries.
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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;
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the
value and time period of the derivative being different than the exposures
or cash flows being hedged.
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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:
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governmental
regulations, including the policies of governments regarding the
exploration for and production and development of their oil and natural
gas reserves;
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global
weather conditions and natural
disasters;
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worldwide
political, military, and economic
conditions;
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the
level of oil production by non-OPEC countries and the available excess
production capacity within OPEC;
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economic
growth in China and India;
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oil
refining capacity and shifts in end-customer preferences toward fuel
efficiency and the use of natural
gas;
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the
cost of producing and delivering oil and
gas;
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potential
acceleration of development of alternative fuels;
and
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the
level of demand for oil and natural gas, especially demand for natural gas
in the United States.
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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:
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the
consolidation of our customers, which
could:
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cause
customers to reduce their capital spending, which would in turn reduce the
demand for our services and products;
and
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result
in customer personnel changes, which in turn affect the timing of contract
negotiations;
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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
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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.
These
transactions also involve risks, and we cannot ensure that:
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any
acquisitions would result in an increase in
income;
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any
acquisitions would be successfully integrated into our operations and
internal controls;
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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;
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any
disposition would not result in decreased earnings, revenue, or cash
flow;
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any
dispositions, investments, acquisitions, or integrations would not divert
management resources; or
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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:
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the
containment and disposal of hazardous substances, oilfield waste, and
other waste materials;
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the
importation and use of radioactive
materials;
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the
use of underground storage tanks;
and
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the
use of underground injection wells.
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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;
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revocation
of permits to conduct business; and
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corrective
action orders, including orders to investigate and/or clean up
contamination.
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Failure
on our part to comply with applicable environmental requirements could have a
material adverse effect on our consolidated financial condition. We
are also exposed to costs arising from environmental compliance, including
compliance with changes in or expansion of environmental requirements, which
could have a material adverse effect on our business, financial condition,
operating results, or cash flows.
We are
exposed to claims under environmental requirements and, from time to time, such
claims have been made against us. In the United States, environmental
requirements and regulations typically impose strict
liability. Strict liability means that in some situations we could be
exposed to liability for cleanup costs, natural resource damages, and other
damages as a result of our conduct that was lawful at the time it occurred or
the conduct of prior operators or other third parties. Liability for
damages arising as a result of environmental laws could be substantial and could
have a material adverse effect on our consolidated results of
operations.
We are
periodically notified of potential liabilities at state and federal superfund
sites. These potential liabilities may arise from both historical
Halliburton operations and the historical operations of companies that we have
acquired. Our exposure at these sites may be materially impacted by
unforeseen adverse developments both in the final remediation costs and with
respect to the final allocation among the various parties involved at the
sites. For any particular federal or state superfund site, since our
estimated liability is typically within a range and our accrued liability may be
the amount on the low end of that range, our actual liability could eventually
be well in excess of the amount accrued. The relevant regulatory
agency may bring suit against us for amounts in excess of what we have accrued
and what we believe is our proportionate share of remediation costs at any
superfund site. We also could be subject to third-party claims,
including punitive damages, with respect to environmental matters for which we
have been named as a potentially responsible party.
Changes
in environmental requirements may negatively impact demand for our
services. For example, oil and natural gas exploration and production
may decline as a result of environmental requirements (including land use
policies responsive to environmental concerns). A decline in
exploration and production, in turn, could materially and adversely affect
us.
Law
and regulatory requirements
In the
countries in which we conduct business, we are subject to multiple and, at
times, inconsistent regulatory regimes, including those that govern our use of
radioactive materials, explosives, and chemicals in the course of our
operations. Various national and international regulatory regimes
govern the shipment of these items. Many countries, but not all,
impose special controls upon the export and import of radioactive materials,
explosives, and chemicals. Our ability to do business is subject to
maintaining required licenses and complying with these multiple regulatory
requirements applicable to these special products. In addition, the
various laws governing import and export of both products and technology apply
to a wide range of services and products we offer. In turn, this can
affect our employment practices of hiring people of different nationalities
because these laws may prohibit or limit access to some products or technology
by employees of various nationalities. Changes in, compliance with,
or our failure to comply with these laws may negatively impact our ability to
provide services in, make sales of equipment to, and transfer personnel or
equipment among some of the countries in which we operate and could have a
material adverse affect on the results of operations.
Raw
materials
Raw
materials essential to our business are normally readily
available. Current market conditions have triggered constraints in
the supply chain of certain raw materials, such as sand, cement, and specialty
metals. The majority of our risk associated with the current supply
chain constraints occurs in those situations where we have a relationship with a
single supplier for a particular resource.
Intellectual
property rights
We rely
on a variety of intellectual property rights that we use in our services and
products. We may not be able to successfully preserve these
intellectual property rights in the future, and these rights could be
invalidated, circumvented, or challenged. In addition, the laws of
some foreign countries in which our services and products may be sold do not
protect intellectual property rights to the same extent as the laws of the
United States. Our failure to protect our proprietary information and
any successful intellectual property challenges or infringement proceedings
against us could materially and adversely affect our competitive
position.
Technology
The
market for our services and products is characterized by continual technological
developments to provide better and more reliable performance and
services. If we are not able to design, develop, and produce
commercially competitive products and to implement commercially competitive
services in a timely manner in response to changes in technology, our business
and revenue could be materially and adversely affected, and the value of our
intellectual property may be reduced. Likewise, if our proprietary
technologies, equipment and facilities, or work processes become obsolete, we
may no longer be competitive, and our business and revenue could be materially
and adversely affected.
Reliance
on management
We depend
greatly on the efforts of our executive officers and other key employees to
manage our operations. The loss or unavailability of any of our
executive officers or other key employees could have a material adverse effect
on our business.
Technical
personnel
Many of
the services that we provide and the products that we sell are complex and
highly engineered and often must perform or be performed in harsh
conditions. We believe that our success depends upon our ability to
employ and retain technical personnel with the ability to design, utilize, and
enhance these services and products. In addition, our ability to
expand our operations depends in part on our ability to increase our skilled
labor force. The demand for skilled workers is high, and the supply
is limited. A significant increase in the wages paid by competing
employers could result in a reduction of our skilled labor force, increases in
the wage rates that we must pay, or both. If either of these events
were to occur, our cost structure could increase, our margins could decrease,
and our growth potential could be impaired.
Weather
Our
business could be materially and adversely affected by severe weather,
particularly in the Gulf of Mexico where we have
operations. Repercussions of severe weather conditions may
include:
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evacuation
of personnel and curtailment of
services;
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weather-related
damage to offshore drilling rigs resulting in suspension of
operations;
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weather-related
damage to our facilities and project work
sites;
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inability
to deliver materials to jobsites in accordance with contract schedules;
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Because
demand for natural gas in the United States drives a significant amount of our
business, warmer than normal winters in the United States are detrimental to the
demand for our services to gas producers.
MANAGEMENT’S
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The
management of Halliburton Company is responsible for establishing and
maintaining adequate internal control over financial reporting as defined in the
Securities Exchange Act Rule 13a-15(f).
Internal
control over financial reporting, no matter how well designed, has inherent
limitations. Therefore, even those systems determined to be effective
can provide only reasonable assurance with respect to financial statement
preparation and presentation. Further, because of changes in
conditions, the effectiveness of internal control over financial reporting may
vary over time.
Under the
supervision and with the participation of our management, including our chief
executive officer and chief financial officer, we conducted an evaluation to
assess the effectiveness of our internal control over financial reporting as of
December 31, 2007 based upon criteria set forth in the Internal Control -
Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on our assessment, we believe that, as of
December 31, 2007, our internal control over financial reporting is
effective.
HALLIBURTON
COMPANY
by
/s/ David J.
Lesar
|
/s/ Mark A.
McCollum
|
David
J. Lesar
|
Mark
A. McCollum
|
Chairman
of the Board,
|
Executive
Vice President and
|
President,
and Chief Executive Officer
|
Chief
Financial Officer
|
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board
of Directors and Shareholders
Halliburton
Company:
We have
audited the accompanying consolidated balance sheets of Halliburton Company and
subsidiaries as of December 31, 2007 and 2006, and the related consolidated
statements of operations, shareholders’ equity, and cash flows for each of the
years in the three-year period ended December 31, 2007. These consolidated
financial statements are the responsibility of the Company’s management.
Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing
the accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of Halliburton Company and
subsidiaries as of December 31, 2007 and 2006, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2007, in conformity with U.S. generally accepted accounting
principles.
As
discussed in Notes 11, 12 and 15, respectively, to the consolidated financial
statements, the Company changed its methods of accounting for uncertainty
in income taxes as of January 1, 2007, its method of accounting for stock-based
compensation plans as of January 1, 2006, and its method of accounting for
defined benefit and other postretirement plans as of December 31, 2006,
respectively.
We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), Halliburton Company’s internal control over
financial reporting as of December 31, 2007, based on criteria established in
Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), and our report dated February 20, 2008 expressed an
unqualified opinion on the effectiveness of the Company’s internal control over
financial reporting.
/s/ KPMG
LLP
Houston,
Texas
February
20, 2008
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board
of Directors and Shareholders
Halliburton
Company:
We have
audited Halliburton Company’s internal control over financial reporting as of
December 31, 2007, based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Halliburton
Company's management is responsible for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in the accompanying Management’s
Report on Internal Control Over Financial Reporting. Our responsibility is
to express an opinion on the Company’s internal control over financial reporting
based on our audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our
audit also