Annual Report — Form 10-K Filing Table of Contents
Document/ExhibitDescriptionPagesSize 1: 10-K December 31, 2007 Form 10-K Final HTML 1.91M
2: EX-10.35 Resignation, General Release & Settlement HTML 67K
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3: EX-10.36 Employment Agreement - Brown HTML 54K
4: EX-10.37 Employment Agreement - King HTML 56K
5: EX-12 Statement of Computation of Ratio of Earnings to HTML 43K
Fixed Charges
6: EX-21 Subsidiaries of the Registrant HTML 16K
7: EX-23.1 Consent of Kpmg LLP HTML 11K
8: EX-24.2 POA for Kathleen M. Bader HTML 10K
9: EX-31.1 302 Cert. for Dave Lesar HTML 13K
10: EX-31.2 302 Cert. for Mark McCollum HTML 13K
11: EX-32.1 906 Cert. for Dave Lesar HTML 9K
12: EX-32.2 906 Cert. for Mark McCollum HTML 9K
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.
Market
for Registrant’s Common Equity, Related Stockholder
Matters,
and Issuer Purchases of Equity
Securities
10
Item
6.
Selected
Financial Data
11
Item
7.
Management’s
Discussion and Analysis of Financial Condition and
Results of
Operation
11
Item
7(a).
Quantitative
and Qualitative Disclosures About Market Risk
11
Item
8.
Financial
Statements and Supplementary Data
12
Item
9.
Changes
in and Disagreements with Accountants on Accounting and
Financial
Disclosure
12
Item
9(a).
Controls
and Procedures
12
Item
9(b).
Other
Information
12
MD&A AND FINANCIAL
STATEMENTS
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
13
Management’s
Report on Internal Control Over Financial Reporting
45
Reports
of Independent Registered Public Accounting Firm
46
Consolidated
Statements of Operations
48
Consolidated
Balance Sheets
49
Consolidated
Statements of Shareholders’ Equity
50
Consolidated
Statements of Cash Flows
51
Notes
to Consolidated Financial Statements
52
Selected
Financial Data (Unaudited)
86
Quarterly
Data and Market Price Information (Unaudited)
87
PART
III
Item
10.
Directors,
Executive Officers, and Corporate Governance
88
Item
11.
Executive
Compensation
88
Item
12(a).
Security
Ownership of Certain Beneficial Owners
88
Item
12(b).
Security
Ownership of Management
88
Item
12(c).
Changes
in Control
88
Item
12(d).
Securities
Authorized for Issuance Under Equity Compensation Plans
88
Item
13.
Certain
Relationships and Related Transactions, and Director
Independence
88
Item
14.
Principal
Accounting Fees and Services
89
PART
IV
Item
15.
Exhibits
and Financial Statement Schedules
90
SIGNATURES
99
(i)
PART
I
Item
1. Business.
General
description of business
Halliburton
Company’s predecessor was established in 1919 and incorporated under the laws of
the State of Delaware in 1924. Halliburton Company provides a variety
of services and products to customers in the energy industry.
In
November 2006, KBR, Inc. (KBR), which at the time was our wholly owned
subsidiary, completed an initial public offering (IPO), in which it sold
approximately 32 million shares of KBR common stock at $17.00 per
share. Proceeds from the IPO were approximately $508 million, net of
underwriting discounts and commissions and offering expenses. On
April 5, 2007, we completed the separation of KBR from us by exchanging the
135.6 million shares of KBR common stock owned by us on that date for 85.3
million shares of our common stock. In the second quarter of 2007, we
recorded a gain on the disposition of KBR of approximately $933 million, net of
tax and the estimated fair value of the indemnities and guarantees provided to
KBR, which is included in income from discontinued operations in the
consolidated statements of operations.
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.
1
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:
2
-
create
a balanced portfolio of products and services supported by global
infrastructure and anchored by technology innovation with a
well-integrated digital strategy to further differentiate our
company;
-
reach
a distinguished level of operational excellence that reduces costs and
creates real value from everything we
do;
-
preserve
a dynamic workforce by being a preferred employer to attract, develop, and
retain the best global talent; and
-
uphold
the ethical and business standards of the company and maintain the highest
standards of health, safety, and environmental
performance.
Markets
and competition
We are
one of the world’s largest diversified energy services companies. Our
services and products are sold in highly competitive markets throughout the
world. Competitive factors impacting sales of our services and
products include:
-
price;
-
service
delivery (including the ability to deliver services and products on an “as
needed, where needed” basis);
-
health,
safety, and environmental standards and
practices;
-
service
quality;
-
global
talent retention;
-
knowledge
of the reservoir;
-
product
quality;
-
warranty;
and
-
technical
proficiency.
We
conduct business worldwide in approximately 70 countries. In 2007,
based on the location of services provided and products sold, 44% of our
consolidated revenue was from the United States. In 2006, 45% of our
consolidated revenue was from the United States. In 2005, 43% of our
consolidated revenue was from the United States. No other country
accounted for more than 10% of our consolidated revenue during these
periods. See Note 4 to the consolidated financial statements for
additional financial information about geographic operations in the last three
years. Because the markets for our services and products are vast and
cross numerous geographic lines, a meaningful estimate of the total number of
competitors cannot be made. The industries we serve are highly
competitive, and we have many substantial competitors. Largely all of
our services and products are marketed through our servicing and sales
organizations.
Operations
in some countries may be adversely affected by unsettled political conditions,
acts of terrorism, civil unrest, expropriation or other governmental actions,
exchange control problems, and highly inflationary currencies. We
believe the geographic diversification of our business activities reduces the
risk that loss of operations in any one country would be material to the conduct
of our operations taken as a whole.
Information
regarding our exposure to foreign currency fluctuations, risk concentration, and
financial instruments used to minimize risk is included in Management’s
Discussion and Analysis of Financial Condition and Results of Operations –
Financial Instrument Market Risk and in Note 14 to the consolidated financial
statements.
Customers
Our
revenue from continuing operations during the past three years was derived from
the sale of services and products to the energy industry. No customer
represented more than 10% of consolidated revenue in any period
presented.
Raw
materials
Raw
materials essential to our business are normally readily
available. Current market conditions have triggered constraints in
the supply of certain raw materials, such as sand, cement, and specialty
metals. Given high activity levels, particularly in the United
States, we are seeking ways to ensure the availability of resources, as well as
manage the rising costs of raw materials. Our procurement department
is using our size and buying power through several programs designed to ensure
that we have access to key materials at competitive prices.
3
Research
and development costs
We
maintain an active research and development program. The program
improves existing products and processes, develops new products and processes,
and improves engineering standards and practices that serve the changing needs
of our customers. Our expenditures for research and development
activities were $301 million in 2007, $254 million in 2006, and $218 million in
2005, of which over 97% was company-sponsored in each year.
Patents
We own a
large number of patents and have pending a substantial number of patent
applications covering various products and processes. We are also
licensed to utilize patents owned by others. We do not consider any
particular patent to be material to our business operations.
Seasonality
On an
overall basis, our operations are not generally affected by
seasonality. Weather and natural phenomena can temporarily affect the
performance of our services, but the widespread geographical locations of our
operations serve to mitigate those effects. Examples of how weather
can impact our business include:
-
the
severity and duration of the winter in North America can have a
significant impact on gas storage levels and drilling activity for natural
gas;
-
the
timing and duration of the spring thaw in Canada directly affects activity
levels due to road restrictions;
-
typhoons
and hurricanes can disrupt coastal and offshore operations;
and
-
severe
weather during the winter months normally results in reduced activity
levels in the North Sea and Russia.
In
addition, due to higher spending near the end of the year by customers for
software and completion tools and services, Landmark and completion tools
results of operations are generally stronger in the fourth quarter of the year
than at the beginning of the year.
Employees
At
December 31, 2007, we employed approximately 51,000 people worldwide compared to
approximately 45,000 at December 31, 2006. At December 31, 2007,
approximately 12% of our employees were subject to collective bargaining
agreements. Based upon the geographic diversification of these
employees, we believe any risk of loss from employee strikes or other collective
actions would not be material to the conduct of our operations taken as a
whole.
Environmental
regulation
We are
subject to numerous environmental, legal, and regulatory requirements related to
our operations worldwide. In the United States, these laws and
regulations include, among others:
-
the
Comprehensive Environmental Response, Compensation and Liability
Act;
-
the
Resource Conservation and Recovery
Act;
-
the
Clean Air Act;
-
the
Federal Water Pollution Control Act;
and
-
the
Toxic Substances Control Act.
In
addition to the federal laws and regulations, states and other countries where
we do business may have numerous environmental, legal, and regulatory
requirements by which we must abide. We evaluate and address the
environmental impact of our operations by assessing and remediating contaminated
properties in order to avoid future liabilities and comply with environmental,
legal, and regulatory requirements. On occasion, we are involved in
specific environmental litigation and claims, including the remediation of
properties we own or have operated, as well as efforts to meet or correct
compliance-related matters. Our Health, Safety and Environment group
has several programs in place to maintain environmental leadership and to
prevent the occurrence of environmental contamination.
We do not
expect costs related to these remediation requirements to have a material
adverse effect on our consolidated financial position or our results of
operations.
4
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
5
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.
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
7
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
8
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,
There are
no family relationships between the executive officers of the registrant or
between any director and any executive officer of the
registrant.
9
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 February18, 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.
10
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 December31, 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.
11
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
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.
12
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;
13
-
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.
14
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 July15, 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.
15
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.
16
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
17
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.
18
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;
19
-
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.
20
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
21
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.
22
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.
23
(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.
24
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
25
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.
26
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.
27
NONOPERATING
ITEMS
Interest expense decreased
$31 million in 2006 compared to 2005, primarily due to the redemption in April
2005 of $500 million of our floating rate senior notes, the repayment in October
2005 of $300 million of our floating rate senior notes, and the repayment in
August 2006 of $275 million of our medium-term notes.
Interest income increased $75
million in 2006 compared to 2005 due to higher cash investment
balances.
Other, net increased $15
million in 2006 compared to 2005. The 2005 year included costs
related to our accounts receivable securitization facility, which had no
outstanding amounts.
(Provision) benefit for income taxes
from continuing operations in 2006 of $1 billion resulted in an effective
tax rate of 31%. The tax benefit for 2005 resulted from recording
favorable adjustments in 2005 totaling $805 million to our valuation allowance
against the deferred tax asset related to asbestos and silica
liabilities. Our strong 2005 earnings, coupled with an upward
revision in our estimate of future domestic taxable income in 2006, drove these
adjustments.
Income from discontinued operations,
net of income tax provision in 2006 and 2005 primarily consisted of our
results of KBR.
CRITICAL
ACCOUNTING ESTIMATES
The
preparation of financial statements requires the use of judgments and
estimates. Our critical accounting policies are described below to
provide a better understanding of how we develop our assumptions and judgments
about future events and related estimations and how they can impact our
financial statements. A critical accounting estimate is one that
requires our most difficult, subjective, or complex estimates and assessments
and is fundamental to our results of operations. We identified our
most critical accounting policies and estimates to be:
-
forecasting
our effective tax rate, including our future ability to utilize foreign
tax credits and the realizability of deferred tax assets, and providing
for uncertain tax positions;
-
percentage-of-completion
accounting for long-term, construction-type
contracts;
-
legal
and investigation matters;
-
valuations
of indemnities;
-
pensions;
and
-
allowance
for bad debts.
We base
our estimates on historical experience and on various other assumptions we
believe to be reasonable according to the current facts and circumstances, the
results of which form the basis for making judgments about the carrying values
of assets and liabilities that are not readily apparent from other
sources. We believe the following are the critical accounting
policies used in the preparation of our consolidated financial statements, as
well as the significant estimates and judgments affecting the application of
these policies. This discussion and analysis should be read in
conjunction with our consolidated financial statements and related notes
included in this report.
We have
discussed the development and selection of these critical accounting policies
and estimates with the Audit Committee of our Board of Directors, and the Audit
Committee has reviewed the disclosure presented below.
Income
tax accounting
We
account for income taxes in accordance with Statement of Financial Accounting
Standards No. 109 (SFAS No. 109), “Accounting for Income Taxes,” which requires
recognition of the amount of taxes payable or refundable for the current year
and an asset and liability approach in recognizing the amount of deferred tax
liabilities and assets for the future tax consequences of events that have been
recognized in our financial statements or tax returns. We apply the
following basic principles in accounting for our income taxes:
-
a
current tax liability or asset is recognized for the estimated taxes
payable or refundable on tax returns for the current
year;
-
a
deferred tax liability or asset is recognized for the estimated future tax
effects attributable to temporary differences and
carryforwards;
28
-
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.
29
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 December31, 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.
30
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.
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 $31 million adjustment to 2007
total operating costs and expenses.
OFF
BALANCE SHEET ARRANGEMENTS
At
December 31, 2007, we had no material off balance sheet arrangements, except for
operating leases. For information on our contractual obligations
related to operating leases, see “Management’s Discussion and Analysis of
Financial Condition and Results of Operations – Liquidity and Capital Resources
– Future uses of cash.”
FINANCIAL
INSTRUMENT MARKET RISK
We are
exposed to financial instrument market risk from changes in foreign currency
exchange rates, interest rates, and, to a limited extent, commodity
prices. From time to time, we may selectively manage these exposures
through the use of derivative instruments to mitigate our market risk from these
exposures. The objective of our risk management program is to protect
our cash flows related to sales or purchases of goods or services from market
fluctuations in currency rates. We do not use derivative instruments
for trading purposes. Our use of derivative instruments includes the
following types of market risk:
-
volatility
of the currency rates;
-
time
horizon of the derivative
instruments;
32
-
market
cycles; and
-
the
type of derivative instruments
used.
We do not
consider any of these risk management activities to be material. See
Note 1 to the consolidated financial statements for additional information on
our accounting policies on derivative instruments. See Note 14 to the
consolidated financial statements for additional disclosures related to
financial instruments.
Interest
rate risk
We have
exposure to interest rate risk from our long-term debt.
The
following table represents principal amounts of our long-term debt at December31, 2007 and related weighted average interest rates on the repaid amounts by
year of maturity for our long-term debt.
Millions
of dollars
2008
2009
2010
2011
2012
Thereafter
Total
Fixed-rate
debt:
Repayment amount
($US)
$
150
$
3
$
753
$
3
$
4
$
1,856
$
2,769
Weighted
average
interest rate
on
repaid amount
5.6
%
5.6
%
5.5
%
5.5
%
5.5
%
4.7
%
5.0
%
Variable-rate
debt:
Repayment amount
($US)
$
9
$
9
$
3
$
–
$
–
$
–
$
21
Weighted
average
interest rate
on
repaid amount
8.5
%
8.5
%
8.5
%
–
–
–
8.5
%
The fair
market value of long-term debt was $4.1 billion as of December 31,2007. The excess of the fair value of long-term debt over the
carrying amount of long-term debt is primarily due to the impact of the
increased value of our common stock on our 3.125% convertible senior
notes.
ENVIRONMENTAL
MATTERS
We are
subject to numerous environmental, legal, and regulatory requirements related to
our operations worldwide. In the United States, these laws and
regulations include, among others:
-
the
Comprehensive Environmental Response, Compensation, and Liability
Act;
-
the
Resource Conservation and Recovery
Act;
-
the
Clean Air Act;
-
the
Federal Water Pollution Control Act;
and
-
the
Toxic Substances Control Act.
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.
33
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 December15, 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 December15, 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.
34
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 January1, 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.
35
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.
36
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.
37
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.
38
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:
39
-
expropriation
and nationalization of our assets in that
country;
-
political
and economic instability;
-
civil
unrest, acts of terrorism, force majeure, war, or other armed
conflict;
-
natural
disasters, including those related to earthquakes and
flooding;
-
inflation;
-
currency
fluctuations, devaluations, and conversion
restrictions;
-
confiscatory
taxation or other adverse tax
policies;
-
governmental
activities that limit or disrupt markets, restrict payments, or limit the
movement of funds;
-
governmental
activities that may result in the deprivation of contract rights;
and
-
governmental
activities that may result in the inability to obtain or retain licenses
required for operation.
Due to
the unsettled political conditions in many oil-producing countries, our revenue
and profits are subject to the adverse consequences of war, the effects of
terrorism, civil unrest, strikes, currency controls, and governmental
actions. Countries where we operate that have significant political
risk include: Algeria, Indonesia, Nigeria, Russia, Venezuela, and
Yemen. In addition, military action or continued unrest in the Middle
East could impact the supply and pricing for oil and gas, disrupt our operations
in the region and elsewhere, and increase our costs for security
worldwide.
In
addition, investigations by governmental authorities (see “Foreign Corrupt
Practices Act investigations” above), as well as legal, social, economic, and
political issues in Nigeria, could materially and adversely affect our Nigerian
business and operations.
Our
facilities and our employees are under threat of attack in some countries where
we operate. In addition, the risks related to loss of life of our
personnel and our subcontractors in these areas continue.
We are
also subject to the risks that our employees, joint venture partners, and agents
outside of the United States may fail to comply with applicable
laws.
Military
action, other armed conflicts, or terrorist attacks
Military
action in Iraq, military tension involving North Korea and Iran, as well as the
terrorist attacks of September 11, 2001 and subsequent terrorist attacks,
threats of attacks, and unrest, have caused instability or uncertainty in the
world’s financial and commercial markets and have significantly increased
political and economic instability in some of the geographic areas in which we
operate. Acts of terrorism and threats of armed conflicts in or
around various areas in which we operate, such as the Middle East, Nigeria, and
Indonesia, could limit or disrupt markets and our operations, including
disruptions resulting from the evacuation of personnel, cancellation of
contracts, or the loss of personnel or assets.
Such
events may cause further disruption to financial and commercial markets and may
generate greater political and economic instability in some of the geographic
areas in which we operate. In addition, any possible reprisals as a
consequence of the war and ongoing military action in Iraq, such as acts of
terrorism in the United States or elsewhere, could materially and adversely
affect us in ways we cannot predict at this time.
Income
taxes
We have
operations in approximately 70 countries other than the United
States. Consequently, we are subject to the jurisdiction of a
significant number of taxing authorities. The income earned in these
various jurisdictions is taxed on differing bases, including net income actually
earned, net income deemed earned, and revenue-based tax
withholding. The final determination of our tax liabilities involves
the interpretation of local tax laws, tax treaties, and related authorities in
each jurisdiction, as well as the significant use of estimates and assumptions
regarding the scope of future operations and results achieved and the timing and
nature of income earned and expenditures incurred. Changes in the
operating environment, including changes in or interpretation of tax law and
currency/repatriation controls, could impact the determination of our tax
liabilities for a tax year.
40
Foreign
exchange and currency risks
A sizable
portion of our consolidated revenue and consolidated operating expenses is in
foreign currencies. As a result, we are subject to significant risks,
including:
-
foreign
exchange risks resulting from changes in foreign exchange rates and the
implementation of exchange controls;
and
-
limitations
on our ability to reinvest earnings from operations in one country to fund
the capital needs of our operations in other
countries.
We
conduct business in countries, such as Venezuela, that have nontraded or “soft”
currencies which, because of their restricted or limited trading markets, may be
more difficult to exchange for “hard” currency. We may accumulate
cash in soft currencies, and we may be limited in our ability to convert our
profits into United States dollars or to repatriate the profits from those
countries.
We
selectively use hedging transactions to limit our exposure to risks from doing
business in foreign currencies. For those currencies that are not
readily convertible, our ability to hedge our exposure is limited because
financial hedge instruments for those currencies are nonexistent or
limited. Our ability to hedge is also limited because pricing of
hedging instruments, where they exist, is often volatile and not necessarily
efficient.
In
addition, the value of the derivative instruments could be impacted
by:
-
adverse
movements in foreign exchange
rates;
-
interest
rates;
-
commodity
prices; or
-
the
value and time period of the derivative being different than the exposures
or cash flows being hedged.
Customers
and Business
Exploration
and production activity
Demand
for our services and products depends on oil and natural gas industry activity
and expenditure levels that are directly affected by trends in oil and natural
gas prices.
Demand
for our services and products is particularly sensitive to the level of
exploration, development, and production activity of, and the corresponding
capital spending by, oil and natural gas companies, including national oil
companies. Prices for oil and natural gas are subject to large
fluctuations in response to relatively minor changes in the supply of and demand
for oil and natural gas, market uncertainty, and a variety of other factors that
are beyond our control. Any prolonged reduction in oil and natural
gas prices will depress the immediate levels of exploration, development, and
production activity, often reflected as changes in rig
counts. Perceptions of longer-term lower oil and natural gas prices
by oil and gas companies or longer-term higher material and contractor prices
impacting facility costs can similarly reduce or defer major expenditures given
the long-term nature of many large-scale development projects. Lower
levels of activity result in a corresponding decline in the demand for our oil
and natural gas well services and products, which could have a material adverse
effect on our revenue and profitability. Factors affecting the prices
of oil and natural gas include:
-
governmental
regulations, including the policies of governments regarding the
exploration for and production and development of their oil and natural
gas reserves;
-
global
weather conditions and natural
disasters;
-
worldwide
political, military, and economic
conditions;
-
the
level of oil production by non-OPEC countries and the available excess
production capacity within OPEC;
-
economic
growth in China and India;
-
oil
refining capacity and shifts in end-customer preferences toward fuel
efficiency and the use of natural
gas;
-
the
cost of producing and delivering oil and
gas;
-
potential
acceleration of development of alternative fuels;
and
-
the
level of demand for oil and natural gas, especially demand for natural gas
in the United States.
41
Historically,
the markets for oil and gas have been volatile and are likely to continue to be
volatile. Spending on exploration and production activities by large
oil and gas companies have a significant impact on the activity levels of our
businesses. In the current environment where oil and gas demand
exceeds supply, the ability to rebalance supply with demand may be constrained
by the global availability of rigs. Full utilization of rigs could
lead to limited growth in revenue. In addition, the extent of the
growth in oilfield services may be limited by the availability of equipment and
manpower.
Capital
spending
Our
business is directly affected by changes in capital expenditures by our
customers. Some of the changes that may materially and adversely
affect us include:
-
the
consolidation of our customers, which
could:
-
cause
customers to reduce their capital spending, which would in turn reduce the
demand for our services and products;
and
-
result
in customer personnel changes, which in turn affect the timing of contract
negotiations;
-
adverse
developments in the business and operations of our customers in the oil
and gas industry, including write-downs of reserves and reductions in
capital spending for exploration, development, and production;
and
-
ability
of our customers to timely pay the amounts due
us.
Customers
We depend
on a limited number of significant customers. While none of these
customers represented more than 10% of consolidated revenue in any period
presented, the loss of one or more significant customers could have a material
adverse effect on our business and our consolidated results of
operations.
Acquisitions,
dispositions, investments, and joint ventures
We
continually seek opportunities to maximize efficiency and value through various
transactions, including purchases or sales of assets, businesses, investments,
or joint ventures. These transactions are intended to result in the
realization of savings, the creation of efficiencies, the generation of cash or
income, or the reduction of risk. Acquisition transactions may be
financed by additional borrowings or by the issuance of our common
stock. These transactions may also affect our consolidated results of
operations.
These
transactions also involve risks, and we cannot ensure that:
-
any
acquisitions would result in an increase in
income;
-
any
acquisitions would be successfully integrated into our operations and
internal controls;
-
the
due diligence prior to an acquisition would uncover situations that could
result in legal exposure or that we will appropriately quantify the
exposure from known risks;
-
any
disposition would not result in decreased earnings, revenue, or cash
flow;
-
any
dispositions, investments, acquisitions, or integrations would not divert
management resources; or
-
any
dispositions, investments, acquisitions, or integrations would not have a
material adverse effect on our results of operations or financial
condition.
We
conduct some operations through joint ventures, where control may be shared with
unaffiliated third parties. As with any joint venture arrangement,
differences in views among the joint venture participants may result in delayed
decisions or in failures to agree on major issues. We also cannot
control the actions of our joint venture partners, including any nonperformance,
default, or bankruptcy of our joint venture partners. These factors
could potentially materially and adversely affect the business and operations of
the joint venture and, in turn, our business and operations.
Environmental
requirements
Our
businesses are subject to a variety of environmental laws, rules, and
regulations in the United States and other countries, including those covering
hazardous materials and requiring emission performance standards for
facilities. For example, our well service operations routinely
involve the handling of significant amounts of waste materials, some of which
are classified as hazardous substances. We also store, transport, and
use radioactive and explosive materials in certain of our
operations. Environmental requirements include, for example, those
concerning:
42
-
the
containment and disposal of hazardous substances, oilfield waste, and
other waste materials;
-
the
importation and use of radioactive
materials;
-
the
use of underground storage tanks;
and
-
the
use of underground injection wells.
Environmental
and other similar requirements generally are becoming increasingly
strict. Sanctions for failure to comply with these requirements, many
of which may be applied retroactively, may include:
-
administrative,
civil, and criminal penalties;
-
revocation
of permits to conduct business; and
-
corrective
action orders, including orders to investigate and/or clean up
contamination.
Failure
on our part to comply with applicable environmental requirements could have a
material adverse effect on our consolidated financial condition. We
are also exposed to costs arising from environmental compliance, including
compliance with changes in or expansion of environmental requirements, which
could have a material adverse effect on our business, financial condition,
operating results, or cash flows.
We are
exposed to claims under environmental requirements and, from time to time, such
claims have been made against us. In the United States, environmental
requirements and regulations typically impose strict
liability. Strict liability means that in some situations we could be
exposed to liability for cleanup costs, natural resource damages, and other
damages as a result of our conduct that was lawful at the time it occurred or
the conduct of prior operators or other third parties. Liability for
damages arising as a result of environmental laws could be substantial and could
have a material adverse effect on our consolidated results of
operations.
We are
periodically notified of potential liabilities at state and federal superfund
sites. These potential liabilities may arise from both historical
Halliburton operations and the historical operations of companies that we have
acquired. Our exposure at these sites may be materially impacted by
unforeseen adverse developments both in the final remediation costs and with
respect to the final allocation among the various parties involved at the
sites. For any particular federal or state superfund site, since our
estimated liability is typically within a range and our accrued liability may be
the amount on the low end of that range, our actual liability could eventually
be well in excess of the amount accrued. The relevant regulatory
agency may bring suit against us for amounts in excess of what we have accrued
and what we believe is our proportionate share of remediation costs at any
superfund site. We also could be subject to third-party claims,
including punitive damages, with respect to environmental matters for which we
have been named as a potentially responsible party.
Changes
in environmental requirements may negatively impact demand for our
services. For example, oil and natural gas exploration and production
may decline as a result of environmental requirements (including land use
policies responsive to environmental concerns). A decline in
exploration and production, in turn, could materially and adversely affect
us.
Law
and regulatory requirements
In the
countries in which we conduct business, we are subject to multiple and, at
times, inconsistent regulatory regimes, including those that govern our use of
radioactive materials, explosives, and chemicals in the course of our
operations. Various national and international regulatory regimes
govern the shipment of these items. Many countries, but not all,
impose special controls upon the export and import of radioactive materials,
explosives, and chemicals. Our ability to do business is subject to
maintaining required licenses and complying with these multiple regulatory
requirements applicable to these special products. In addition, the
various laws governing import and export of both products and technology apply
to a wide range of services and products we offer. In turn, this can
affect our employment practices of hiring people of different nationalities
because these laws may prohibit or limit access to some products or technology
by employees of various nationalities. Changes in, compliance with,
or our failure to comply with these laws may negatively impact our ability to
provide services in, make sales of equipment to, and transfer personnel or
equipment among some of the countries in which we operate and could have a
material adverse affect on the results of operations.
Raw
materials
Raw
materials essential to our business are normally readily
available. Current market conditions have triggered constraints in
the supply chain of certain raw materials, such as sand, cement, and specialty
metals. The majority of our risk associated with the current supply
chain constraints occurs in those situations where we have a relationship with a
single supplier for a particular resource.
43
Intellectual
property rights
We rely
on a variety of intellectual property rights that we use in our services and
products. We may not be able to successfully preserve these
intellectual property rights in the future, and these rights could be
invalidated, circumvented, or challenged. In addition, the laws of
some foreign countries in which our services and products may be sold do not
protect intellectual property rights to the same extent as the laws of the
United States. Our failure to protect our proprietary information and
any successful intellectual property challenges or infringement proceedings
against us could materially and adversely affect our competitive
position.
Technology
The
market for our services and products is characterized by continual technological
developments to provide better and more reliable performance and
services. If we are not able to design, develop, and produce
commercially competitive products and to implement commercially competitive
services in a timely manner in response to changes in technology, our business
and revenue could be materially and adversely affected, and the value of our
intellectual property may be reduced. Likewise, if our proprietary
technologies, equipment and facilities, or work processes become obsolete, we
may no longer be competitive, and our business and revenue could be materially
and adversely affected.
Reliance
on management
We depend
greatly on the efforts of our executive officers and other key employees to
manage our operations. The loss or unavailability of any of our
executive officers or other key employees could have a material adverse effect
on our business.
Technical
personnel
Many of
the services that we provide and the products that we sell are complex and
highly engineered and often must perform or be performed in harsh
conditions. We believe that our success depends upon our ability to
employ and retain technical personnel with the ability to design, utilize, and
enhance these services and products. In addition, our ability to
expand our operations depends in part on our ability to increase our skilled
labor force. The demand for skilled workers is high, and the supply
is limited. A significant increase in the wages paid by competing
employers could result in a reduction of our skilled labor force, increases in
the wage rates that we must pay, or both. If either of these events
were to occur, our cost structure could increase, our margins could decrease,
and our growth potential could be impaired.
Weather
Our
business could be materially and adversely affected by severe weather,
particularly in the Gulf of Mexico where we have
operations. Repercussions of severe weather conditions may
include:
-
evacuation
of personnel and curtailment of
services;
-
weather-related
damage to offshore drilling rigs resulting in suspension of
operations;
-
weather-related
damage to our facilities and project work
sites;
-
inability
to deliver materials to jobsites in accordance with contract schedules;
and
-
loss
of productivity.
Because
demand for natural gas in the United States drives a significant amount of our
business, warmer than normal winters in the United States are detrimental to the
demand for our services to gas producers.
44
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
45
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.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board
of Directors and Shareholders
Halliburton
Company:
We have
audited Halliburton Company’s internal control over financial reporting as of
December 31, 2007, based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Halliburton
Company's management is responsible for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in the accompanying Management’s
Report on Internal Control Over Financial Reporting. Our responsibility is
to express an opinion on the Company’s internal control over financial reporting
based on our audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our
audit also included performing such other procedures as we considered necessary
in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A
company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal
control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of the assets of the company;
(2) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial
statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
In our
opinion, Halliburton Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2007, based on
criteria established in Internal Control - Integrated
Framework issued by COSO.
We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets of Halliburton
Company as of December 31, 2007 and 2006, and the related consolidated
statements of operations, stockholders’ equity, and cash flows for each of the
years in the three-year period ended December 31, 2007, and our report dated
February 20, 2008 expressed an
unqualified opinion on those consolidated financial statements.
Common
shares, par value $2.50 per share – authorized 2,000 shares, issued
1,063
and 1,060
shares
2,657
2,650
Paid-in
capital in excess of par value
1,741
1,689
Accumulated
other comprehensive loss
(104
)
(437
)
Retained
earnings
8,202
5,051
12,496
8,953
Less
183 and 62 shares of treasury stock, at cost
5,630
1,577
Total
shareholders’ equity
6,866
7,376
Total
liabilities and shareholders’ equity
$
13,135
$
16,860
See notes to consolidated financial
statements.
49
HALLIBURTON
COMPANY
Consolidated
Statements of Shareholders’ Equity
Millions
of dollars and shares
2007
2006
2005
Balance
at January 1
$
7,376
$
6,372
$
3,932
Dividends
and other transactions with shareholders
(1,499
)
(1,324
)
202
Sale
of stock by a subsidiary
–
117
–
Adoption
of Statement of Financial Accounting
Standards No.
158
–
(218
)
–
Adoption
of Financial Accounting Standards Board
Interpretation No.
48
(30
)
–
–
Shares
exchanged in KBR, Inc. exchange offer
(2,809
)
–
–
Other
(4
)
34
–
Comprehensive
income:
Net income
3,499
2,348
2,358
Net cumulative translation
adjustments
(23
)
34
(41
)
Defined benefit and other
postretirement plans adjustments
355
2
(54
)
Net unrealized gains (losses)
on investments
and derivatives
1
11
(25
)
Total
comprehensive income
3,832
2,395
2,238
Balance
at December 31
$
6,866
$
7,376
$
6,372
See notes to consolidated financial
statements.
50
HALLIBURTON
COMPANY
Consolidated
Statements of Cash Flows
Year
Ended December 31
Millions
of dollars
2007
2006
2005
Cash
flows from operating activities:
Net
income
$
3,499
$
2,348
$
2,358
Adjustments
to reconcile net income to net cash from operations:
Income
from discontinued operations
(975
)
(171
)
(251
)
Depreciation,
depletion, and amortization
583
480
448
Provision
(benefit) for deferred income taxes
(111
)
658
(243
)
Gain
on sale of business assets
(52
)
(66
)
(102
)
Asbestos
and silica liability payment related to Chapter 11 filing
–
–
(2,345
)
Collection
of asbestos- and silica-related insurance receivables
29
167
1,032
Other
changes:
Receivables
(355
)
(494
)
(314
)
Accounts
receivable facilities transactions
–
–
(256
)
Inventories
(218
)
(309
)
(151
)
Accounts
payable
77
96
102
Contributions
to pension plans
(41
)
(75
)
(39
)
Other
259
712
252
Cash
flows from discontinued operations
31
311
210
Total
cash flows from operating activities
2,726
3,657
701
Cash
flows from investing activities:
Sales
of property, plant, and equipment
203
152
106
Dispositions
of business assets, net of cash disposed
70
98
212
Investments
– restricted cash
56
–
1
Sales
(purchases) of short-term investments in marketable securities,
net
(332
)
(20
)
891
Acquisitions
of business assets, net of cash acquired
(563
)
(27
)
(108
)
Disposal
of KBR, Inc. cash upon separation
(1,461
)
–
–
Capital
expenditures
(1,583
)
(834
)
(575
)
Other
investing activities
(38
)
(20
)
(36
)
Cash
flows from discontinued operations
(13
)
225
19
Total
cash flows from investing activities
(3,661
)
(426
)
510
Cash
flows from financing activities:
Proceeds
from exercises of stock options
110
159
342
Tax
benefit from exercise of options and restricted stock
29
53
–
Borrowings
(repayments) of short-term debt, net
9
(13
)
8
Proceeds
from long-term debt, net of offering costs
–
–
23
Payments
on long-term debt
(7
)
(324
)
(802
)
Payments
of dividends to shareholders
(314
)
(306
)
(254
)
Payments
to reacquire common stock
(1,374
)
(1,339
)
(12
)
Other
financing activities
(5
)
5
(1
)
Cash
flows from discontinued operations
(18
)
485
(24
)
Total
cash flows from financing activities
(1,570
)
(1,280
)
(720
)
Effect
of exchange rate changes on cash, including $0, $50, and $(3) related
to
discontinued
operations
(27
)
37
(17
)
Increase
(decrease) in cash and equivalents
(2,532
)
1,988
474
Cash
and equivalents at beginning of year, including $1,461, $390, and
$188
related to discontinued
operations
4,379
2,391
1,917
Cash
and equivalents at end of year, including $0, $1,461, and $390
related
to discontinued
operations
$
1,847
$
4,379
$
2,391
Supplemental
disclosure of cash flow information:
Cash
payments during the year for:
Interest
from continuing operations
$
144
$
164
$
193
Income
taxes from continuing operations
$
941
$
289
$
203
See notes
to consolidated financial statements.
51
HALLIBURTON
COMPANY
Notes
to Consolidated Financial Statements
Note
1. Description of Company and Significant Accounting
Policies
Description
of Company
Halliburton
Company’s predecessor was established in 1919 and incorporated under the laws of
the State of Delaware in 1924. We are one of the world’s largest
oilfield services companies. Our two business segments are the
Completion and Production segment and the Drilling and Evaluation
segment. We provide a comprehensive range of services and products
for the exploration, development, and production of oil and gas around the
world.
Use
of estimates
Our
financial statements are prepared in conformity with accounting principles
generally accepted in the United States, requiring us to make estimates and
assumptions that affect:
-
the
reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the financial statements;
and
-
the
reported amounts of revenue and expenses during the reporting
period.
Ultimate
results could differ from those estimates.
Basis
of presentation
The
consolidated financial statements include the accounts of our company and all of
our subsidiaries that we control or variable interest entities for which we have
determined that we are the primary beneficiary. All material
intercompany accounts and transactions are eliminated. Investments in
companies in which we have significant influence are accounted for using the
equity method. If we do not have significant influence, we use the
cost method.
As the
result of realigning our products and services during the third quarter of 2007,
we are now reporting two business segments. See Note 4 for further
information. Additionally, KBR, Inc. (KBR), formerly a wholly owned
subsidiary, is reclassified as discontinued operations in the consolidated
financial statements. See Note 2 for additional
information. All prior periods presented reflect these
changes.
Certain
other prior year amounts have been reclassified to conform to the current year
presentation.
Revenue
recognition
Overall. Our
services and products are generally sold based upon purchase orders or contracts
with our customers that do not include right of return provisions or other
significant post-delivery obligations. Our products are produced in a
standard manufacturing operation, even if produced to our customer’s
specifications. We recognize revenue from product sales when title
passes to the customer, the customer assumes risks and rewards of ownership, and
collectibility is reasonably assured. Service revenue, including
training and consulting services, is recognized when the services are rendered
and collectibility is reasonably assured. Rates for services are
typically priced on a per day, per meter, per man-hour, or similar
basis.
Software
sales. Sales of perpetual software licenses, net of any
deferred maintenance and support fees, are recognized as revenue upon
shipment. Sales of time-based licenses are recognized as revenue over
the license period. Maintenance and support fees are recognized as
revenue ratably over the contract period, usually a one-year
duration.
Percentage of
completion. Revenue from long-term contracts to provide well
construction and completion services is reported on the percentage-of-completion
method of accounting. Progress is generally based upon physical
progress related to contractually defined units of work. Physical
percent complete is determined as a combination of input and output measures as
deemed appropriate by the circumstances. All known or anticipated
losses on contracts are provided for when they become evident. Cost
adjustments that are in the process of being negotiated with customers for extra
work or changes in the scope of work are included in revenue when collection is
deemed probable.
Sale
of stock by a subsidiary
When, as
part of a broader corporate reorganization, a subsidiary or affiliate sells
unissued shares in a public offering, we treat the transaction as a capital
transaction. Therefore, the increase or decrease in the carrying
amount of our subsidiary’s stock is not reflected as a gain or loss on our
consolidated statements of operations, but as an increase or decrease to
“Paid-in capital in excess of par value.”
52
Research
and development
Research
and development expenses are charged to income as incurred. Research
and development expenses were $301 million in 2007, $254 million in 2006, and
$218 million in 2005, of which over 97% was company-sponsored in each
year.
Software
development costs
Costs of
developing software for sale are charged to expense as research and development
when incurred until technological feasibility has been established for the
product. Once technological feasibility is established, software
development costs are capitalized until the software is ready for general
release to customers. We capitalized costs related to software
developed for resale of $23 million in 2007 and $21 million in both 2006 and
2005. Amortization expense of software development costs was $17
million for 2007, $21 million for 2006, and $22 million for
2005. Once the software is ready for release, amortization of
software development costs begins. Capitalized software development
costs are amortized over periods not exceeding five years.
Cash
equivalents
We
consider all highly liquid investments with an original maturity of three months
or less to be cash equivalents, except for cash equivalents of KBR, which are
reflected as current assets of discontinued operations at December 31,2006.
Inventories
Inventories
are stated at the lower of cost or market. Cost represents invoice or
production cost for new items and original cost less allowance for condition for
used material returned to stock. Production cost includes material,
labor, and manufacturing overhead. Some domestic manufacturing and
field service finished products and parts inventories for drill bits, completion
products, and bulk materials are recorded using the last-in, first-out
method. The remaining inventory is recorded on the average cost
method.
Allowance
for bad debts
We
establish an allowance for bad debts through a review of several factors,
including historical collection experience, current aging status of the customer
accounts, and financial condition of our customers.
Property,
plant, and equipment
Other
than those assets that have been written down to their fair values due to
impairment, property, plant, and equipment are reported at cost less accumulated
depreciation, which is generally provided on the straight-line method over the
estimated useful lives of the assets. Accelerated depreciation
methods are also used for tax purposes, wherever permitted. Upon sale
or retirement of an asset, the related costs and accumulated depreciation are
removed from the accounts and any gain or loss is recognized. Planned
major maintenance costs are generally expensed as incurred.
Goodwill
The
reported amounts of goodwill for each reporting unit are reviewed for impairment
on an annual basis and more frequently when negative conditions such as
significant current or projected operating losses exist. The annual
impairment test for goodwill is a two-step process and involves comparing the
estimated fair value of each reporting unit to the reporting unit’s carrying
value, including goodwill. If the fair value of a reporting unit
exceeds its carrying amount, goodwill of the reporting unit is not considered
impaired, and the second step of the impairment test is
unnecessary. If the carrying amount of a reporting unit exceeds its
fair value, the second step of the goodwill impairment test would be performed
to measure the amount of impairment loss to be recorded, if any. Our
annual impairment tests resulted in no goodwill impairment in 2007, 2006, or
2005.
Evaluating
impairment of long-lived assets
When
events or changes in circumstances indicate that long-lived assets other than
goodwill may be impaired, an evaluation is performed. For an asset
classified as held for use, the estimated future undiscounted cash flows
associated with the asset are compared to the asset’s carrying amount to
determine if a write-down to fair value is required. When an asset is
classified as held for sale, the asset’s book value is evaluated and adjusted to
the lower of its carrying amount or fair value less cost to sell. In
addition, depreciation and amortization is ceased while it is classified as held
for sale.
53
Income
taxes
We
recognize the amount of taxes payable or refundable for the year. In
addition, deferred tax assets and liabilities are recognized for the expected
future tax consequences of events that have been recognized in the financial
statements or tax returns. A valuation allowance is provided for
deferred tax assets if it is more likely than not that these items will not be
realized.
In
assessing the realizability of deferred tax assets, management considers whether
it is more likely than not that some portion or all of the deferred tax assets
will not be realized. The ultimate realization of deferred tax assets
is dependent upon the generation of future taxable income during the periods in
which those temporary differences become deductible. Management
considers the scheduled reversal of deferred tax liabilities, projected future
taxable income, and tax planning strategies in making this
assessment. Based upon the level of historical taxable income and
projections for future taxable income over the periods in which the deferred tax
assets are deductible, management believes it is more likely than not that we
will realize the benefits of these deductible differences, net of the existing
valuation allowances.
We
recognize interest and penalties related to unrecognized tax benefits within the
provision for income taxes on continuing operations in our consolidated
statements of operations.
We
generally do not provide income taxes on the undistributed earnings of
non-United States subsidiaries because such earnings are intended to be
reinvested indefinitely to finance foreign activities. These
additional foreign earnings could be subject to additional tax if remitted, or
deemed remitted, as a dividend; however, it is not practicable to estimate the
additional amount, if any, of taxes payable. Taxes are provided as
necessary with respect to earnings that are not permanently
reinvested.
Derivative
instruments
At times,
we enter into derivative financial transactions to hedge existing or projected
exposures to changing foreign currency exchange rates, interest rates, and
commodity prices. We do not enter into derivative transactions for
speculative or trading purposes. We recognize all derivatives on the
balance sheet at fair value. Derivatives are adjusted to fair value
and reflected through the results of operations. Gains or losses on
foreign currency derivatives are included in other, net; gains or losses on
interest rate derivatives are included in interest expense; and gains or losses
on commodity derivatives are included in operating income. Our
derivatives are not designated as hedges for accounting purposes.
Foreign
currency translation
Foreign
entities whose functional currency is the United States dollar translate
monetary assets and liabilities at year-end exchange rates, and nonmonetary
items are translated at historical rates. Income and expense accounts
are translated at the average rates in effect during the year, except for
depreciation, cost of product sales and revenue, and expenses associated with
nonmonetary balance sheet accounts, which are translated at historical
rates. Gains or losses from changes in exchange rates are recognized
in consolidated income in the year of occurrence. Foreign entities
whose functional currency is not the United States dollar translate net assets
at year-end rates and income and expense accounts at average exchange
rates. Adjustments resulting from these translations are reflected in
the consolidated statements of shareholders’ equity as cumulative translation
adjustments.
54
Stock-based
compensation
Effective
January 1, 2006, we adopted the fair value recognition provisions of Financial
Accounting Standards Board (FASB) Statement of Financial Accounting Standards
No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123(R)), using the
modified prospective application. Accordingly, we are recognizing
compensation expense for all newly granted awards and awards modified,
repurchased, or cancelled after January 1, 2006. Compensation cost
for the unvested portion of awards that were outstanding as of January 1, 2006
is being recognized ratably over the remaining vesting period based on the fair
value at date of grant. Also, beginning with the January 1, 2006
purchase period, compensation expense for our 2002 Employee Stock Purchase Plan
(ESPP) is being recognized. The cumulative effect of this change in
accounting principle related to stock-based awards was
immaterial. Prior to January 1, 2006, we accounted for these plans
under the recognition and measurement provisions of Accounting Principles Board
(APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related
interpretations. Under APB No. 25, no compensation expense was
recognized for stock options or the ESPP. Compensation expense was
recognized for restricted stock awards. As a result of adopting SFAS
No. 123(R), the incremental pretax expense related to employee stock option
awards and our ESPP totaled approximately $33 million in 2006 or $0.02 per
diluted share after tax on continuing operations. The incremental
impact to net income related to employee stock option awards and our ESPP in
2006 totaled approximately $26 million.
Total
stock-based compensation expense for continuing operations, net of related tax
effects, was $62 million in 2007 and $49 million in 2006. Total
income tax benefit recognized in continuing operations for stock-based
compensation arrangements was $35 million in 2007, $27 million in 2006, and $13
million in 2005. Total incremental compensation cost resulting from
modifications of previously granted stock-based awards was $18 million in 2007,
$10 million in 2006, and $12 million in 2005. These modifications
allowed certain employees to retain their awards after leaving the
company.
The
following table summarizes the pro forma effect on net income and income per
share for 2005 as if we had applied the fair value recognition provisions of
SFAS No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee
compensation.
discontinued operations, net of
related tax effects
8
Less:
Stock-based compensation
expense for continuing
operations determined under
fair-value-based
method for all awards, net of
related tax effects
(46
)
Stock-based compensation
expense for discontinued
operations determined under
fair-value-based
method for all awards, net of
related tax effects
(15
)
Net
income, pro forma
$
2,328
Basic
income per share:
Continuing
operations
As reported
$
2.09
Pro forma
$
2.07
Discontinued
operations
As reported
$
0.25
Pro forma
$
0.24
Diluted
income per share:
Continuing
operations
As reported
$
2.03
Pro forma
$
2.01
Discontinued
operations
As reported
$
0.24
Pro forma
$
0.24
The fair
value of options at the date of grant was estimated using the Black-Scholes
option pricing model. The expected volatility of options granted in
2007 and 2006 was a blended rate based upon implied volatility calculated on
actively traded options on our common stock and upon the historical volatility
of our common stock. The expected volatility of options granted in
2005 was based upon the historical volatility of our common
stock. The expected term of options granted in 2007, 2006, and 2005
was based upon historical observation of actual time elapsed between date of
grant and exercise of options for all employees. The assumptions and
resulting fair values of options granted were as follows:
Year
Ended December 31
2007
2006
2005
Expected
term (in years)
5.14
5.24
5.00
Expected
volatility
35.70
%
42.20
%
51.06 – 52.79
%
Expected
dividend yield
0.89 – 1.14
%
0.76 – 1.06
%
0.73 – 1.16
%
Risk-free
interest rate
3.37 – 5.00
%
4.30 – 5.03
%
3.77 – 4.33
%
Weighted
average grant-date fair value per share
$
11.35
$
14.20
$
11.42
56
The fair
value of ESPP shares was estimated using the Black-Scholes option pricing
model. The expected volatility was a one-year historical volatility
of our common stock. The assumptions and resulting fair values were
as follows:
Offering
period July 1 through December 31
2007
2006
2005
Expected
term (in years)
0.5
0.5
0.5
Expected
volatility
29.49
%
37.77
%
30.46
%
Expected
dividend yield
1.03
%
0.80
%
0.73
%
Risk-free
interest rate
4.98
%
5.29
%
3.89
%
Weighted
average grant-date fair value per share
$
7.97
$
9.32
$
5.50
Offering
period January 1 through June 30
2007
2006
2005
Expected
term (in years)
0.5
0.5
0.5
Expected
volatility
34.91
%
35.65
%
26.93
%
Expected
dividend yield
1.00
%
0.75
%
1.16
%
Risk-free
interest rate
5.09
%
4.38
%
3.15
%
Weighted
average grant-date fair value per share
$
7.20
$
7.91
$
4.15
See Note
12 for further detail on stock incentive plans.
Note
2. KBR Separation
In
November 2006, KBR completed an initial public offering (IPO), in which it sold
approximately 32 million shares of KBR common stock at $17.00 per
share. Proceeds from the IPO were approximately $508 million, net of
underwriting discounts and commissions and offering expenses. The
increase in the carrying amount of our investment in KBR, resulting from the
IPO, was recorded in “Paid-in capital in excess of par value” on our
consolidated balance sheet at December 31, 2006. On April 5, 2007, we
completed the separation of KBR from us by exchanging the 135.6 million shares
of KBR common stock owned by us on that date for 85.3 million shares of our
common stock. In the second quarter of 2007, we recorded a gain on
the disposition of KBR of approximately $933 million, net of tax and the
estimated fair value of the indemnities and guarantees provided to KBR as
described below, which is included in income from discontinued operations on the
consolidated statement of operations.
The
following table presents the financial results of KBR, which are reflected as
discontinued operations in our consolidated statements of
operations. For accounting purposes, we ceased including KBR’s
operations in our results effective March 31, 2007.
We
entered into various agreements relating to the separation of KBR, including,
among others, a master separation agreement, a registration rights agreement, a
tax sharing agreement, transition services agreements, and an employee matters
agreement. The master separation agreement provides for, among other
things, KBR’s responsibility for liabilities related to its business and
Halliburton’s responsibility for liabilities unrelated to KBR’s
business. Halliburton provides indemnification in favor of KBR under
the master separation agreement for certain contingent liabilities, including
Halliburton’s indemnification of KBR and any of its greater than 50%-owned
subsidiaries as of November 20, 2006, the date of the master separation
agreement, for:
57
-
fines
or other monetary penalties or direct monetary damages, including
disgorgement, as a result of a claim made or assessed by a governmental
authority in the United States, the United Kingdom, France, Nigeria,
Switzerland, and/or Algeria, or a settlement thereof, related to alleged
or actual violations occurring prior to November 20, 2006 of the United
States Foreign Corrupt Practices Act (FCPA) or particular, analogous
applicable foreign statutes, laws, rules, and regulations in connection
with investigations pending as of that date, including with respect to the
construction and subsequent expansion by TSKJ of a natural gas
liquefaction complex and related facilities at Bonny Island in Rivers
State, Nigeria; and
-
all
out-of-pocket cash costs and expenses, or cash settlements or cash
arbitration awards in lieu thereof, KBR may incur after the effective date
of the master separation agreement as a result of the replacement of the
subsea flowline bolts installed in connection with the Barracuda-Caratinga
project. See Note 10 for further discussion of these
matters.
As a
result of these agreements, we recorded $190 million, as a reduction of the gain
on the disposition of KBR, to reflect the estimated fair value of the above
indemnities and guarantees, net of the associated estimated future tax
benefit. The estimated fair value of these indemnities and guarantees
is primarily included in “Other liabilities” on the consolidated balance sheet
at December 31, 2007.
Additionally,
Halliburton provides indemnities, performance guarantees, surety bond
guarantees, and letter of credit guarantees that are currently in place in favor
of KBR’s customers or lenders under project contract, credit agreements, letters
of credit, and other KBR credit instruments. These indemnities and
guarantees will continue until they expire at the earlier of: (1) the
termination of the underlying project contract or KBR obligations thereunder;
(2) the expiration of the relevant credit support instrument in accordance with
its terms or release of such instrument by the customer; or (3) the expiration
of the credit agreements. Further, KBR and we have agreed that, until
December 31, 2009, we will issue additional guarantees, indemnification, and
reimbursement commitments for KBR’s benefit in connection with: (a) letters of
credit necessary to comply with KBR’s Egypt Basic Industries Corporation ammonia
plant contract, KBR’s Allenby & Connaught project, and all other KBR project
contracts that were in place as of December 15, 2005; (b) surety bonds issued to
support new task orders pursuant to the Allenby & Connaught project, two job
order contracts for KBR’s Government and Infrastructure segment, and all other
KBR project contracts that were in place as of December 15, 2005; and (c)
performance guarantees in support of these contracts. KBR is
compensating Halliburton for these guarantees. Halliburton has also
provided a limited indemnity, with respect to FCPA governmental and third-party
claims, to the lender parties under KBR’s revolving credit agreement expiring in
December 2010. KBR has agreed to indemnify Halliburton, other than
for the FCPA and Barracuda-Caratinga bolts matter, if Halliburton is required to
perform under any of the indemnities or guarantees related to KBR’s revolving
credit agreement, letters of credit, surety bonds, or performance guarantees
described above.
The tax
sharing agreement provides for allocations of United States and certain other
jurisdiction tax liabilities between us and KBR. Under the transition
services agreements, we continue to provide various interim corporate support
services to KBR, and KBR continues to provide various interim corporate support
services to us. The fees are determined on a basis generally intended
to approximate the fully allocated direct and indirect costs of providing the
services, without any profit. Under an employee matters agreement,
Halliburton and KBR have allocated liabilities and responsibilities related to
current and former employees and their participation in certain benefit
plans. Among other items, the employee matters agreement provided for
the conversion, which occurred upon completion of the separation of KBR, of
stock options and restricted stock awards (with restrictions that had not yet
lapsed as of the final separation date) granted to KBR employees under our 1993
Stock and Incentive Plan (1993 Plan) to options and restricted stock awards
covering KBR common stock. As of April 5, 2007, these awards
consisted of 1.2 million options with a weighted average exercise price per
share of $15.01 and approximately 600,000 restricted shares with a weighted
average grant-date fair value per share of $17.95 under our 1993
Plan.
58
Note
3. Acquisitions and Dispositions
PSL
Energy Services Limited
In July
2007, we acquired the entire share capital of PSL Energy Services Limited
(PSLES), an eastern 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.
Dresser,
Ltd. interest
As a part
of our sale of Dresser Equipment Group in 2001, we retained a small equity
interest in Dresser Inc.’s Class A common stock. Dresser Inc. was
later reorganized as Dresser, Ltd., and we exchanged our shares for shares of
Dresser, Ltd. In May 2007, we sold our remaining interest in Dresser,
Ltd. We received $70 million in cash from the sale and recorded a $49
million gain. This investment was reflected in “Other assets” on our
consolidated balance sheet at December 31, 2006.
Ultraline
Services Corporation
In
January 2007, we acquired all intellectual property, current assets, and
existing business associated with Calgary-based Ultraline Services Corporation
(Ultraline), a division of Savanna Energy Services Corp. Ultraline is
a provider of wireline services in Canada. We paid approximately $178
million for Ultraline and recorded goodwill of $124 million and intangible
assets of $41 million. Beginning in February 2007, Ultraline’s
results of operations are included in our Drilling and Evaluation
segment.
Subsea
7, Inc.
In
January 2005, we completed the sale of our 50% interest in Subsea 7, Inc. to our
joint venture partner, 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.
Note
4. Business Segment Information
Subsequent
to the KBR separation, in the third quarter of 2007, we realigned our products
and services to improve operational and cost management efficiencies, better
serve our customers, and become better aligned with the process of exploring for
and producing from oil and natural gas wells. We now operate under
two divisions, which form the basis for the two operating segments we now
report: the Completion and Production segment and the Drilling and
Evaluation segment. All periods presented reflect reclassifications
related to the change in operating segments and the reclassification of certain
amounts between the operating segments and “Corporate and other.” The
two KBR segments have been reclassified as discontinued operations as a result
of the separation of KBR from us.
Following
is a discussion of our operating segments.
Completion and Production
delivers cementing, stimulation, intervention, and completion
services. This segment consists of production enhancement services,
completion tools and services, and cementing services.
Production
enhancement services include stimulation services, pipeline process services,
sand control 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.
59
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
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.
Corporate and other includes
expenses related to support functions and corporate executives. Also
included are certain gains and losses that are not attributable to a particular
business segment. “Corporate and other” represents assets not
included in a business segment and is primarily composed of cash and
equivalents, deferred tax assets, and marketable securities.
Intersegment
revenue and revenue between geographic areas are immaterial. Our
equity in earnings and losses of unconsolidated affiliates that are accounted
for on the equity method is included in revenue and operating income of the
applicable segment.
60
The
following tables present information on our business segments.
Operations
by business segment
Year
Ended December 31
Millions
of dollars
2007
2006
2005
Revenue:
Completion
and Production
$
8,386
$
7,221
$
5,495
Drilling
and Evaluation
6,878
5,734
4,605
Total
$
15,264
$
12,955
$
10,100
Operating
income (loss):
Completion
and Production
$
2,199
$
2,140
$
1,524
Drilling
and Evaluation
1,485
1,328
840
Corporate
and other
(186
)
(223
)
(200
)
Total
$
3,498
$
3,245
$
2,164
Capital
expenditures:
Completion
and Production
$
791
$
441
$
309
Drilling
and Evaluation
759
390
266
Corporate
and other
33
3
–
Total
$
1,583
$
834
$
575
Depreciation,
depletion, and amortization:
Completion
and Production
$
288
$
239
$
217
Drilling
and Evaluation
295
241
231
Total
$
583
$
480
$
448
December
31
Millions
of dollars
2007
2006
Total
assets:
Completion
and Production
$
4,842
$
3,636
Drilling
and Evaluation
4,606
3,566
Shared
assets
672
1,216
Corporate
and other
3,015
3,047
Discontinued
operations
–
5,395
Total
$
13,135
$
16,860
Not all
assets are associated with specific segments. Those assets specific
to segments include receivables, inventories, certain identified property,
plant, and equipment (including field service equipment), equity in and advances
to related companies, and goodwill. The remaining assets, such as
cash, are considered to be shared among the segments.
Revenue
by country is determined based on the location of services provided and products
sold.
Operations
by geographic area
Year
Ended December 31
Millions
of dollars
2007
2006
2005
Revenue:
United
States
$
6,673
$
5,869
$
4,317
Other
countries
8,591
7,086
5,783
Total
$
15,264
$
12,955
$
10,100
61
December
31
Millions
of dollars
2007
2006
Long-lived
assets:
United
States
$
2,733
$
2,045
Other
countries
2,263
1,413
Total
$
4,996
$
3,458
Note
5. Receivables
Our trade
receivables are generally not collateralized. At December 31, 2007,
35% of our gross trade receivables were from customers in the United
States. As of December 31, 2006, 39% of our gross trade receivables
were from customers in the United States. No other country accounted
for more than 10% of our gross trade receivables at these dates.
Note
6. Inventories
Inventories
are stated at the lower of cost or market. In the United States we
manufacture certain finished products and parts inventories for drill bits,
completion products, bulk materials, and other tools that are recorded using the
last-in, first-out method, which totaled $71 million at December 31, 2007 and
$58 million at December 31, 2006. If the average cost method had been
used, total inventories would have been $25 million higher than reported at
December 31, 2007 and $20 million higher than reported at December 31,2006. The cost of the remaining inventory was recorded on the average
cost method. Inventories consisted of the following:
December
31
Millions
of dollars
2007
2006
Finished
products and parts
$
1,042
$
883
Raw
materials and supplies
325
256
Work
in process
92
96
Total
$
1,459
$
1,235
Finished
products and parts are reported net of obsolescence reserves of $65 million at
December 31, 2007 and $63 million at December 31, 2006.
Note
7. Investments
Investments
in marketable securities
At
December 31, 2007, we had $388 million invested in marketable securities,
consisting of auction-rate securities and variable-rate demand notes which were
classified as available-for-sale and recorded at fair value. In
January 2008, we sold the entire balance of marketable securities at face
value. At December 31, 2006, our investments in marketable securities
were $20 million.
Restricted
cash
At
December 31, 2007, we had restricted cash of $52 million, which primarily
consisted of collateral for potential future insurance claim reimbursements,
included in “Other assets.” At December 31, 2006, we had restricted
cash of $108 million in “Other assets,” which primarily consisted of similar
items. The $56 million decrease in restricted cash primarily reflects
the release, due to the separation of KBR, of collateral related to potential
insurance claim reimbursements.
62
Note
8. Property, Plant, and Equipment
Property,
plant, and equipment were composed of the following:
December
31
Millions
of dollars
2007
2006
Land
$
46
$
37
Buildings
and property improvements
869
782
Machinery,
equipment, and other
6,841
5,531
Total
7,756
6,350
Less
accumulated depreciation
4,126
3,793
Net
property, plant, and equipment
$
3,630
$
2,557
The
percentages of total buildings and property improvements and total machinery,
equipment, and other, excluding oil and gas investments, are depreciated over
the following useful lives:
Buildings
and Property
Improvements
2007
2006
1 – 10 years
17
%
18
%
11
– 20 years
50
%
49
%
21
– 30 years
13
%
14
%
31
– 40 years
20
%
19
%
Machinery,
Equipment,
and
Other
2007
2006
1 –
5 years
22
%
26
%
6 –
10 years
72
%
68
%
11 –
20 years
6
%
6
%
Note
9. Debt
Short-term
notes payable consist primarily of overdraft and other facilities with varying
rates of interest. Long-term debt consisted of the
following:
December
31
Millions
of dollars
2007
2006
3.125%
convertible senior notes due July 2023
$
1,200
$
1,200
5.5%
senior notes due October 2010
749
749
7.6%
debentures due August 2096
294
294
8.75%
debentures due February 2021
185
185
Medium-term
notes due 2008 through 2027
299
299
Other
59
82
Total
long-term debt
2,786
2,809
Less
current portion
159
26
Noncurrent
portion of long-term debt
$
2,627
$
2,783
Convertible
notes
In June
2003, we issued $1.2 billion of 3.125% convertible senior notes due July 15,2023, with interest payable semiannually. The notes are our senior
unsecured obligations ranking equally with all of our existing and future senior
unsecured indebtedness.
63
The notes
are convertible under any of the following circumstances:
-
during
any calendar quarter if the last reported sale price of our common stock
for at least 20 trading days during the period of 30 consecutive trading
days ending on the last trading day of the previous quarter is greater
than or equal to 120% of the conversion price per share of our common
stock on such last trading day;
-
if
the notes have been called for
redemption;
-
upon
the occurrence of specified corporate transactions that are described in
the indenture governing the notes;
or
-
during
any period in which the credit ratings assigned to the notes by both
Moody’s Investors Service and Standard & Poor’s are lower than Ba1 and
BB+, respectively, or the notes are no longer rated by at least one of
these rating services or their
successors.
The
conversion price is $18.825 per share and is subject to adjustment upon the
occurrence of stock dividends in common stock, the issuance of rights or
warrants, stock splits and combinations, the distribution of indebtedness,
securities, or assets, or excess cash distributions. The stock
conversion rate for the notes changed as a result of our July 2006 stock split
and periodic increases to our quarterly dividend. The maximum stock
conversion rate is 87.6424 shares of common stock per $1,000 principal amount of
notes. As of December 31, 2007, the stock conversion rate was 53.3383
shares of common stock per $1,000 principal amount of notes.
Subsequent
to issuing the notes, we agreed upon conversion to settle the principal amount
of the notes in cash. For any amounts in excess of the aggregate
principal amount we have the right to deliver shares of our common stock, cash,
or a combination of cash and common stock. See Note 13 for discussion
of the impact on diluted earnings per share.
The notes
are redeemable for cash at our option on or after July 15,2008. Holders may require us to repurchase the notes for cash on July
15 of 2008, 2013, or 2018 or, prior to July 15, 2008, in the event of a
fundamental change as defined in the underlying indenture.
Other
senior debt
We have
issued various senior notes, medium-term notes, and debentures, all of which
rank equally with our existing and future senior unsecured
indebtedness. Our senior notes with an aggregate principal amount of
$750 million will mature in October 2010 and bear interest at a rate equal to
5.5%, payable semiannually. They are redeemable by us, in whole or in
part, at any time, subject to a redemption price equal to the greater of 100% of
the principal amount of the notes or the sum of the present values of the
remaining scheduled payments of principal and interest due on the notes
discounted to the redemption date at the treasury rate plus 25 basis
points. The senior notes were initially offered on a discounted basis
at 99.679% of their face value. The discount is being amortized to
interest expense over the life of the notes.
We have
outstanding notes under our medium-term note program, including $150 million
that will mature in December 2008 and bear interest at a rate equal to 5.63%,
payable semiannually. They are redeemable by us, in whole or in part,
at any time, subject to a redemption price equal to the greater of 100% of the
principal amount of the notes or the sum of the present values of the remaining
scheduled payments of principal and interest due on the notes discounted to the
redemption date at the treasury rate plus 15 basis points. In
addition, we have notes issued under the medium-term note program with a
principal amount of $45 million that mature in May 2017 and notes with a
principal amount of $104 million that mature in February 2027, which bear
interest rates equal to 7.53% and 6.75%, respectively, payable
semiannually. The 7.53% and 6.75% notes may not be redeemed prior to
maturity. The medium-term notes do not have sinking fund
requirements.
We have
outstanding debentures with an aggregate principal amount of $185 million that
will mature in February 2021 and bear interest at a rate equal to 8.75%, payable
semiannually. In addition, we have outstanding debentures with an
aggregate principal amount of $294 million that will mature in August 2096 and
bear interest at a rate equal to 7.6%, payable semiannually. The
debentures may not be redeemed prior to maturity and do not have sinking fund
requirements.
64
Revolving
credit facilities
On July9, 2007, we entered into a new unsecured $1.2 billion five-year revolving credit
facility that replaced our then existing unsecured $1.2 billion five-year
revolving credit facility with generally similar terms and conditions except
that the new facility does not contain any financial covenants. The
purpose of the facility is to provide commercial paper support, general working
capital, and credit for other corporate purposes. There were no cash
drawings under the revolving credit facility as of December 31,2007.
Maturities
Our debt
matures as follows: $159 million in 2008; $12 million in 2009; $755
million in 2010; $3 million in 2011; $3 million in 2012; and $1.9 billion
thereafter.
Note
10. Commitments and Contingencies
Foreign
Corrupt Practices Act investigations
The
Securities and Exchange Commission (SEC) is conducting a formal investigation
into whether improper payments were made to government officials in Nigeria
through the use of agents or subcontractors in connection with the construction
and subsequent expansion by TSKJ of a multibillion dollar natural gas
liquefaction complex and related facilities at Bonny Island in Rivers State,
Nigeria. The Department of Justice (DOJ) is also conducting a related
criminal investigation. The SEC has also issued subpoenas seeking
information, which we and KBR are furnishing, regarding current and former
agents used in connection with multiple projects, including current and prior
projects, over the past 20 years located both in and outside of Nigeria in which
the Halliburton energy services business, KBR or affiliates, subsidiaries or
joint ventures of Halliburton or KBR, are or were participants. In
September 2006 and October 2007, the SEC and the DOJ, respectively, each
requested that we enter into an agreement to extend the statute of limitations
with respect to its investigation. We anticipate that we will enter
into appropriate tolling agreements with the SEC and the DOJ.
TSKJ is a
private limited liability company registered in Madeira, Portugal whose members
are Technip 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.
65
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.
66
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 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.
67
Barracuda-Caratinga
arbitration
We also
provided indemnification in favor of KBR under the master separation agreement
for all out-of-pocket cash costs and expenses (except for legal fees and other
expenses of the arbitration so long as KBR controls and directs it), or cash
settlements or cash arbitration awards in lieu thereof, KBR may incur after
November 20, 2006 as a result of the replacement of certain subsea flowline
bolts installed in connection with the Barracuda-Caratinga
project. Under the master separation agreement, KBR currently
controls the defense, counterclaim, and settlement of the subsea flowline bolts
matter. As a condition of our indemnity, for any settlement to be
binding upon us, KBR must secure our prior written consent to such settlement’s
terms. We have the right to terminate the indemnity in the event KBR
enters into any settlement without our prior written consent. See
Note 2 for additional information regarding the KBR
indemnification.
At
Petrobras’ direction, KBR replaced certain bolts located on the subsea flowlines
that failed through mid-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.
Securities
and related litigation
In June
2002, a class action lawsuit was filed against us in federal court alleging
violations of the federal securities laws after the SEC initiated an
investigation in connection with our change in accounting for revenue on
long-term construction projects and related disclosures. In the weeks
that followed, approximately twenty similar class actions were filed against
us. Several of those lawsuits also named as defendants several of our
present or former officers and directors. The class action cases were
later consolidated, and the amended consolidated class action complaint, styled
Richard Moore, et al. v.
Halliburton Company, et al., was filed and served upon us in April
2003. As a result of a substitution of lead plaintiffs, the case is
now styled Archdiocese of
Milwaukee Supporting Fund (“AMSF”) v. Halliburton Company, et
al. We settled with the SEC in the second quarter of
2004.
In early
May 2003, we entered into a written memorandum of understanding setting forth
the terms upon which the Moore class action would be
settled. In June 2003, the lead plaintiffs filed a motion for leave
to file a second amended consolidated complaint, which was granted by the
court. In addition to restating the original accounting and
disclosure claims, the second amended consolidated complaint included claims
arising out of the 1998 acquisition of Dresser Industries, Inc. by Halliburton,
including that we failed to timely disclose the resulting asbestos liability
exposure (the “Dresser claims”). The memorandum of understanding
contemplated settlement of the Dresser claims as well as the original
claims.
In June
2004, the court entered an order preliminarily approving the
settlement. Following the transfer of the case to another district
judge, the court held that evidence of the settlement’s fairness was inadequate,
denied the motion for final approval of the settlement, and ordered the parties
to mediate. The mediation was unsuccessful.
68
In April
2005, the court appointed new co-lead counsel and named AMSF the new lead
plaintiff, directing that it file a third consolidated amended complaint and
that we file our motion to dismiss. The court held oral arguments on
that motion in August 2005, at which time the court took the motion under
advisement. In March 2006, the court entered an order in which it
granted the motion to dismiss with respect to claims arising prior to June 1999
and granted the motion with respect to certain other claims while permitting
AMSF to re-plead some of those claims to correct deficiencies in its earlier
complaint. In April 2006, AMSF filed its fourth amended consolidated
complaint. We filed a motion to dismiss those portions of the
complaint that had been re-pled. A hearing was held on that motion in
July 2006, and in March 2007 the court ordered dismissal of the claims against
all individual defendants other than our CEO. The court ordered that
the case proceed against our CEO and Halliburton. In response to a
motion by the lead plaintiff, on February 26, 2007, the court ordered the
removal and replacement of their co-lead counsel. In June 2007, upon
becoming aware of a United States Supreme Court opinion issued in that month,
the court allowed further briefing on the motion to dismiss filed on behalf of
our CEO. That briefing is complete, but the court has not yet
ruled. In September 2007, AMSF filed a motion for class
certification, and our response was filed in November 2007. The case
is set for trial in July 2009.
As of
December 31, 2007, we had not accrued any amounts related to this matter because
we do not believe that a loss is probable. Further, an estimate of
possible loss or range of loss related to this matter cannot be
made.
Asbestos
insurance settlements
At
December 31, 2004, we resolved all open and future asbestos- and silica-related
claims in the prepackaged Chapter 11 proceedings of DII Industries LLC, Kellogg
Brown & Root LLC, and our other affected subsidiaries that had previously
been named as defendants in a large number of asbestos- and silica-related
lawsuits. During 2004, we settled insurance disputes with
substantially all the insurance companies for asbestos- and silica-related
claims and all other claims under the applicable insurance policies and
terminated all the applicable insurance policies.
Under the
insurance settlements entered into as part of the resolution of our Chapter 11
proceedings, we have agreed to indemnify our insurers under certain historic
general liability insurance policies in certain situations. We have
concluded that the likelihood of any claims triggering the indemnity obligations
is remote, and we believe any potential liability for these indemnifications
will be immaterial. Further, an estimate of possible loss or range of
loss related to this matter cannot be made. At December 31, 2007, we
had not recorded any liability associated with these
indemnifications.
M-I,
LLC antitrust litigation
On
February 16, 2007, we were informed that M-I, LLC, a competitor of ours in the
drilling fluids market, had sued us for allegedly attempting to monopolize the
market for invert emulsion drilling fluids used in deep water and/or in cold
water temperatures. The claims M-I, LLC asserted are based upon its
allegation that the patent issued for our Accolade® drilling fluid was invalid
as a result of its allegedly having been procured by fraud on the United States
Patent and Trademark Office and that our subsequent prosecution of an
infringement action against M-I, LLC amounted to predatory conduct in violation
of Section 2 of the Sherman Antitrust Act. In October 2006, a federal
court dismissed our infringement action based upon its holding that the claims
in our patent were indefinite and the patent was, therefore,
invalid. That judgment was affirmed by the appellate court in January
2008. M-I, LLC also alleges that we falsely advertised our Accolade®
drilling fluid in violation of the Lanham Act and California law and that our
earlier infringement action amounted to malicious prosecution in violation of
Texas state law. M-I, LLC seeks compensatory damages, which it claims
should be trebled, as well as punitive damages and injunctive
relief. We believe that M-I, LLC’s claims are without merit and
intend to aggressively defend them. The case is set for trial in
September 2008.
As of
December 31, 2007, we had not accrued any amounts in connection with this matter
because we do not believe that a loss is probable. Further, an
estimate of possible loss or range of loss related to this matter cannot be
made.
69
Dirt,
Inc. litigation
In April
2005, Dirt, Inc. brought suit in Alabama against Bredero-Shaw (a joint venture
in which we formerly held a 50% interest that we sold to the other party in the
venture, ShawCor Ltd., in 2002), Halliburton Energy Services, Inc., and ShawCor
Ltd., claiming that Bredero-Shaw disposed of hazardous waste in a construction
materials landfill owned and operated by Dirt, Inc. Bredero-Shaw has
offered to take responsibility for cleanup of the site. The plaintiff
did not accept that offer, and the method and cost of such cleanup are disputed,
with expert opinions ranging from $6 million to $144 million. On
November 1, 2007, the trial court in the above-referenced matter entered a
judgment in the total amount of $108 million, of which Halliburton Energy
Services, Inc. could be responsible for as much as 50%. We are
pursuing an appeal and believe that it is probable that the Alabama Supreme
Court will reverse the trial court’s judgment because, among other
things:
-
the
trial court misapplied the law on the measure of
damages;
-
Halliburton
Energy Services, Inc., as a shareholder, should not have liability for
actions of the venture; and
-
the
statute of limitations had run on an issue submitted to the
jury.
We have
accrued an amount less than $10 million, which represents our 50% portion of
what we believe it will cost to remediate the site.
Environmental
We are
subject to numerous environmental, legal, and regulatory requirements related to
our operations worldwide. In the United States, these laws and
regulations include, among others:
-
the
Comprehensive Environmental Response, Compensation, and Liability
Act;
-
the
Resource Conservation and Recovery
Act;
-
the
Clean Air Act;
-
the
Federal Water Pollution Control Act;
and
-
the
Toxic Substances Control Act.
In
addition to the federal laws and regulations, states and other countries where
we do business often have numerous environmental, legal, and regulatory
requirements by which we must abide. We evaluate and address the
environmental impact of our operations by assessing and remediating contaminated
properties in order to avoid future liabilities and comply with environmental,
legal, and regulatory requirements. On occasion, we are involved in
specific environmental litigation and claims, including the remediation of
properties we own or have operated, as well as efforts to meet or correct
compliance-related matters. Our Health, Safety and Environment group
has several programs in place to maintain environmental leadership and to
prevent the occurrence of environmental contamination.
We do not
expect costs related to these remediation requirements to have a material
adverse effect on our consolidated financial position or our results of
operations. Our accrued liabilities for environmental matters were
$72 million as of December 31, 2007 and $39 million as of December 31,2006. Our total liability related to environmental matters covers
numerous properties, including the property in regard to which Dirt, Inc. has
brought suit against Bredero-Shaw (a joint venture in which we formerly held a
50% interest that we sold to the other party in the venture, ShawCor Ltd., in
2002), Halliburton Energy Services, Inc., and ShawCor Ltd. See “Dirt,
Inc. litigation” in this note for further information regarding this
matter.
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.
70
Letters
of credit
In the
normal course of business, we have agreements with banks under which
approximately $2.2 billion of letters of credit, surety bonds, or bank
guarantees were outstanding as of December 31, 2007, including $1.1 billion that
relate to KBR. These KBR letters of credit, surety bonds, or bank
guarantees are being guaranteed by us in favor of KBR’s customers and
lenders. KBR has agreed to compensate us for these guarantees and
indemnify us if we are required to perform under any of these
guarantees. Some of the outstanding letters of credit have triggering
events that would entitle a bank to require cash collateralization.
Leases
We are
obligated under operating leases, principally for the use of land, offices,
equipment, manufacturing and field facilities, and warehouses. Total
rentals, net of sublease rentals, were $487 million in 2007, $402 million in
2006, and $338 million in 2005.
Future
total rentals on noncancelable operating leases are as follows: $180
million in 2008; $131 million in 2009; $104 million in 2010; $74 million in
2011; $40 million in 2012; and $172 million thereafter.
Note
11. Income Taxes
The
components of the provision for income taxes on continuing operations
were:
Year
Ended December 31
Millions
of dollars
2007
2006
2005
Current
income taxes:
Federal
$
(560
)
$
(156
)
$
22
Foreign
(449
)
(122
)
(116
)
State
(38
)
(11
)
(1
)
Total
current
(1,047
)
(289
)
(95
)
Deferred
income taxes:
Federal
129
(600
)
291
Foreign
7
(95
)
(14
)
State
4
(19
)
(57
)
Total
deferred
140
(714
)
220
(Provision)
benefit for income taxes
$
(907
)
$
(1,003
)
$
125
The
United States and foreign components of income from continuing operations before
income taxes and minority interest were as follows:
Year
Ended December 31
Millions
of dollars
2007
2006
2005
United
States
$
2,219
$
2,280
$
1,399
Foreign
1,241
919
598
Total
$
3,460
$
3,199
$
1,997
71
Reconciliations
between the actual provision for income taxes on continuing operations and that
computed by applying the United States statutory rate to income from continuing
operations before income taxes and minority interest were as
follows:
Year
Ended December 31
2007
2006
2005
United
States statutory rate
35.0
%
35.0
%
35.0
%
Impact of foreign income taxed
at different rates
(2.3
)
(1.3
)
0.3
Other impact of foreign
operations
(3.9
)
3.1
(2.0
)
Valuation
allowance
(2.0
)
(3.3
)
(40.3
)
State income taxes, net of
federal income tax benefit
0.3
0.7
1.1
Adjustments of prior year
taxes
(0.3
)
(2.1
)
0.4
Other items,
net
(0.6
)
(0.7
)
(0.8
)
Total
effective tax rate on continuing operations
26.2
%
31.4
%
(6.3
)%
The major
component of the difference between the 2007 statutory rate compared to the
effective rate is the favorable impact of the ability to recognize United States
foreign tax credits of approximately $205 million. This amount
consists of approximately $68 million of a change in valuation allowance for
credits previously recognized and approximately $137 million reflected in other
impact of foreign operations for changes to United States tax filings to claim
foreign tax credits rather than deducting foreign taxes. We now
believe we can utilize these credits currently because we have generated
additional taxable income and expect to continue to generate a higher level of
taxable income largely from the growth of our international
operations. The major component of the difference between the 2005
statutory tax rate compared to the effective tax rate is the release of a
valuation allowance for future tax attributes related to United States net
operating losses established in prior years. The remaining valuation
allowance on future tax attributes related to United States net operating loss
was released in 2006. The primary components of our deferred tax
assets and liabilities and the related valuation allowances were as
follows:
72
December
31
Millions
of dollars
2007
2006
Gross
deferred tax assets:
Employee compensation and
benefits
$
262
$
289
Capitalized research
and experimentation
94
65
Accrued
liabilities
80
64
Foreign tax credit
carryforward
61
68
Inventory
63
62
Insurance
accruals
46
45
Software revenue
recognition
37
57
Net operating loss
carryforwards
24
29
Alternative minimum tax
credit carryforward
19
66
Other
176
90
Total
gross deferred tax assets
862
835
Gross
deferred tax liabilities:
Depreciation and
amortization
164
135
Joint ventures, partnerships,
and unconsolidated affiliates
34
2
Other
55
20
Total
gross deferred tax liabilities
253
157
Valuation
allowances:
Net operating loss
carryforwards
22
29
Foreign tax credit
carryforwards
–
68
Other
7
–
Total
valuation allowances
29
97
Net
deferred income tax asset
$
580
$
581
At
December 31, 2007, we had a total of $58 million of foreign net operating loss
carryforwards, of which $31 million will expire from 2008 through 2020 and $27
million will not expire due to indefinite expiration dates. At
December 31, 2007, we had $27 million of domestic net operating loss
carryforwards that will expire from 2021 through 2023 related to a consolidated
joint venture. During 2005, our existing deferred tax asset related
to asbestos and silica liabilities became a United States net operating loss due
to the tax deduction of the related costs in 2005. As a result, a
domestic net operating loss carryforward of $2.1 billion was created and was
fully utilized in 2006. At December 31, 2007, we had United States
foreign tax credit carryforwards of $61 million that are expected to expire in
2016. The federal alternative minimum tax credit carryforwards are
available to reduce future United States federal income taxes on an indefinite
basis.
We
established a valuation allowance on certain domestic and foreign operating loss
carryforwards on the basis that we believe these assets will not be utilized in
the statutory carryover period.
Effective
January 1, 2007, we adopted Financial Accounting Standards Board (FASB)
Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes, an
interpretation of FASB Statement No. 109.” FIN 48, as amended May
2007 by FASB Staff Position FIN 48-1, “Definition of ‘Settlement’ in FASB
Interpretation No. 48,” prescribes a minimum recognition threshold and
measurement methodology that a tax position taken or expected to be taken in a
tax return is required to meet before being recognized in the financial
statements. It also provides guidance for derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure, and transition.
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.
73
The
following presents a rollforward of our unrecognized tax benefits and associated
interest and penalties.
At
December 31, 2007, $99 million of tax benefits associated with United States
foreign tax credits was included in the balance of unrecognized tax benefits
that could be resolved within the next 12 months. A review of foreign
tax documentation is currently underway and will likely be significantly
progressed within the next 12 months. Also, as of December 31, 2007,
a significant portion of our non-United States unrecognized tax benefits, while
not individually significant, could be settled within the next 12
months. As of December 31, 2007, we estimated that $289 million of
the balance of unrecognized tax benefits, if resolved in our favor, would
positively impact the effective tax rate and, therefore, be recognized as
additional tax benefits in our statement of operations. We file
income tax returns in the United States federal jurisdiction and in various
states and foreign jurisdictions. In most cases, we are no longer
subject to United States federal, state, and local, or non-United States income
tax examination by tax authorities for years before 1998. Tax filings
of our subsidiaries, unconsolidated affiliates, and related entities are
routinely examined in the normal course of business by tax
authorities. Currently, our United States federal tax filings are
under review for tax years 2000 through 2005. An unrecognized tax
benefit of $6 million related to the 2000 through 2002 tax years could be
resolved within the next 12 months.
74
Note
12. Shareholders’ Equity and Stock Incentive Plans
The
following tables summarize our common stock and other shareholders’ equity
activity:
Defined
benefit and other postretirement liability adjustments
(45
)
(400
)
(184
)
Unrealized
gains (losses) on investments and derivatives
2
1
(10
)
Total
accumulated other comprehensive loss
$
(104
)
$
(437
)
$
(266
)
Shares
of common stock
December
31
Millions
of shares
2007
2006
2005
Issued
1,063
1,060
1,054
In
treasury
(183
)
(62
)
(26
)
Total
shares of common stock outstanding
880
998
1,028
76
In May
2006, the shareholders increased the number of authorized shares of common stock
to two billion. Also in May 2006, our Board of Directors finalized
the terms of a two-for-one common stock split, effected in the form of a stock
dividend. As a result, the split was effected in the form of a stock
dividend paid on July 14, 2006 to shareholders of record on June 23,2006. The effect on the balance sheet was to reduce “Paid-in capital
in excess of par value” by $1.3 billion and to increase “Common shares” by $1.3
billion. All prior period common stock and applicable share and per
share amounts were retroactively adjusted to reflect the split.
In
February 2006, our Board of Directors approved a share repurchase program up to
$1.0 billion, which replaced our previous share repurchase
program. In September 2006, our Board of Directors approved an
increase to our existing common share repurchase program of up to an additional
$2.0 billion. In July 2007, our Board of Directors approved an
additional increase to our existing common share repurchase program of up to
$2.0 billion, bringing the entire authorization to $5.0 billion. This
additional authorization may be used for open market share purchases or to
settle the conversion premium on our 3.125% convertible senior notes, should
they be redeemed. The stock repurchase program does not require a
specific number of shares to be purchased and the program may be effected
through solicited or unsolicited transactions in the market or in privately
negotiated transactions. The program may be terminated or suspended
at any time. From the inception of this program through December 31,2007, we have repurchased approximately 79 million shares of our common stock
for approximately $2.7 billion at an average price per share of
$33.91. These numbers include the repurchases of approximately 39
million shares of our common stock for approximately $1.4 billion at an average
price per share of $34.93 during 2007. As of December 31, 2007, $2.3
billion remained available under our share repurchase
authorization.
Preferred
Stock
Our
preferred stock consists of five million total authorized shares at December 31,2007, of which none were issued.
Stock
Incentive Plans
Our 1993
Stock and Incentive Plan, as amended (1993 Plan), provides for the grant of any
or all of the following types of stock-based awards:
-
stock
options, including incentive stock options and nonqualified stock
options;
-
restricted
stock awards;
-
restricted
stock unit awards;
-
stock
appreciation rights; and
-
stock
value equivalent awards.
There are
currently no stock appreciation rights or stock value equivalent awards
outstanding.
Under the
terms of the 1993 Plan, 98 million shares of common stock have been reserved for
issuance to employees and non-employee directors. The plan specifies
that no more than 32 million shares can be awarded as restricted
stock. At December 31, 2007, approximately 18 million shares were
available for future grants under the 1993 Plan, of which approximately 10
million shares remained available for restricted stock awards. The
stock to be offered pursuant to the grant of an award under the 1993 Plan may be
authorized but unissued common shares or treasury shares.
In
addition to the provisions of the 1993 Plan, we also have stock-based
compensation provisions under our Restricted Stock Plan for Non-Employee
Directors and our ESPP.
Each of
the active stock-based compensation arrangements is discussed
below.
Stock
options
All stock
options under the 1993 Plan are granted at the fair market value of our common
stock at the grant date. Employee stock options vest ratably over a
three- or four-year period and generally expire 10 years from the grant
date. Stock options granted to non-employee directors vest after six
months. Compensation expense for stock options is generally
recognized on a straight line basis over the entire vesting
period. No further stock option grants are being made under the stock
plans of acquired companies.
The
following table represents our stock options activity during 2007, and includes
exercised, forfeited, and expired shares from our acquired companies’ stock
plans.
The total
intrinsic value of options exercised was $68 million in 2007, $123 million in
2006, and $194 million in 2005. As of December 31, 2007, there was
$32 million of unrecognized compensation cost, net of estimated forfeitures,
related to nonvested stock options, which is expected to be recognized over a
weighted average period of approximately 1.7 years.
Cash
received from option exercises was $110 million during 2007, $159 million during
2006, and $342 million during 2005. The tax benefit realized from the
exercise of stock options was $22 million in 2007 and $42 million in
2006.
Restricted
stock
Restricted
shares issued under the 1993 Plan are restricted as to sale or
disposition. These restrictions lapse periodically over an extended
period of time not exceeding 10 years. Restrictions may also lapse
for early retirement and other conditions in accordance with our established
policies. Upon termination of employment, shares on which
restrictions have not lapsed must be returned to us, resulting in restricted
stock forfeitures. The fair market value of the stock on the date of
grant is amortized and charged to income on a straight-line basis over the
requisite service period for the entire award.
Our
Restricted Stock Plan for Non-Employee Directors (Directors Plan) allows for
each non-employee director to receive an annual award of 800 restricted shares
of common stock as a part of compensation. These awards have a
minimum restriction period of six months, and the restrictions lapse upon the
earlier of mandatory director retirement at age 72 or early retirement from the
Board after four years of service. The fair market value of the stock
on the date of grant is amortized over the lesser of the time from the grant
date to age 72 or the time from the grant date to completion of four years of
service on the Board. We reserved 200,000 shares of common stock for
issuance to non-employee directors, which may be authorized but unissued common
shares or treasury shares. At December 31, 2007, 115,200 shares had
been issued to non-employee directors under this plan. There were
8,800 shares, 8,000 shares, and 6,400 shares of restricted stock awarded under
the Directors Plan in 2007, 2006, and 2005. In addition, during 2007,
our non-employee directors were awarded 22,642 shares of restricted stock under
the 1993 Plan, which are included in the table below.
The
following table represents our 1993 Plan and Directors Plan restricted stock
awards and restricted stock units granted, vested, and forfeited during
2007.
The
weighted average grant-date fair value of shares granted during 2006 was $34.39
and during 2005 was $24.28. The total fair value of shares vested
during 2007 was $79 million, during 2006 was $64 million, and during 2005 was
$49 million. As of December 31, 2007, there was $153 million of
unrecognized compensation cost, net of estimated forfeitures, related to
nonvested restricted stock, which is expected to be recognized over a weighted
average period of 4.1 years.
2002
Employee Stock Purchase Plan
Under the
ESPP, eligible employees may have up to 10% of their earnings withheld, subject
to some limitations, to be used to purchase shares of our common
stock. Unless the Board of Directors shall determine otherwise, each
six-month offering period commences on January 1 and July 1 of each
year. The price at which common stock may be purchased under the ESPP
is equal to 85% of the lower of the fair market value of the common stock on the
commencement date or last trading day of each offering period. Under
this plan, 24 million shares of common stock have been reserved for
issuance. They may be authorized but unissued shares or treasury
shares. As of December 31, 2007, 13.3 million shares have been sold
through the ESPP.
Note
13. Income per Share
Basic
income per share is based on the weighted average number of common shares
outstanding during the period. Effective April 5, 2007, common shares
outstanding were reduced by the 85.3 million shares of our common stock that we
accepted in exchange for the shares of KBR common stock we
owned. Diluted income per share includes additional common shares
that would have been outstanding if potential common shares with a dilutive
effect had been issued. A reconciliation of the number of shares used
for the basic and diluted income per share calculation is as
follows:
Millions
of shares
2007
2006
2005
Basic
weighted average common shares outstanding
913
1,014
1,010
Dilutive
effect of:
Convertible senior notes
premium
29
29
16
Stock options
6
9
10
Restricted
stock
2
2
2
Diluted
weighted average common shares outstanding
950
1,054
1,038
In
December 2004, we entered into a supplemental indenture that requires us to
satisfy our conversion obligation for our convertible senior notes in cash,
rather than in common stock, for at least the aggregate principal amount of the
notes. This reduced the resulting potential earnings dilution to only
include the conversion premium, which is the difference between the conversion
price per share of common stock and the average share price. See the
table above for the dilutive effect for 2007, 2006, and 2005.
Excluded
from the computation of diluted income per share were options to purchase three
million shares of common stock that were outstanding in 2007 and two million
shares of common stock that were outstanding in both 2006 and
2005. These options were outstanding during these years but were
excluded because the option exercise price was greater than the average market
price of the common shares.
78
Note
14. Financial Instruments and Risk Management
Foreign
exchange risk
Techniques
in managing foreign exchange risk include, but are not limited to, foreign
currency borrowing and investing and the use of currency derivative
instruments. We selectively manage significant exposures to potential
foreign exchange losses considering current market conditions, future operating
activities, and the associated cost in relation to the perceived risk of
loss. The purpose of our foreign currency risk management activities
is to protect us from the risk that the eventual dollar cash flows resulting
from the sale and purchase of services and products in foreign currencies will
be adversely affected by changes in exchange rates.
We manage
our currency exposure through the use of currency derivative instruments as it
relates to the major currencies, which are generally the currencies of the
countries in which we do the majority of our international
business. These instruments are not treated as hedges for accounting
purposes and generally have an expiration date of two years or
less. Forward exchange contracts, which are commitments to buy or
sell a specified amount of a foreign currency at a specified price and time, are
generally used to manage identifiable foreign currency
commitments. Forward exchange contracts and foreign exchange option
contracts, which convey the right, but not the obligation, to sell or buy a
specified amount of foreign currency at a specified price, are generally used to
manage exposures related to assets and liabilities denominated in a foreign
currency. None of the forward or option contracts are exchange
traded. While derivative instruments are subject to fluctuations in
value, the fluctuations are generally offset by the value of the underlying
exposures being managed. The use of some contracts may limit our
ability to benefit from favorable fluctuations in foreign exchange
rates.
Foreign
currency contracts are not utilized to manage exposures in some currencies due
primarily to the lack of available markets or cost considerations (non-traded
currencies). We attempt to manage our working capital position to
minimize foreign currency commitments in non-traded currencies and recognize
that pricing for the services and products offered in these countries should
cover the cost of exchange rate devaluations. We have historically
incurred transaction losses in non-traded currencies.
Notional amounts and fair market
values. The notional amounts of open forward contracts and
option contracts were $272 million at December 31, 2007 and $358 million at
December 31, 2006. The notional amounts of our foreign exchange
contracts do not generally represent amounts exchanged by the parties and, thus,
are not a measure of our exposure or of the cash requirements related to these
contracts. The amounts exchanged are calculated by reference to the
notional amounts and by other terms of the derivatives, such as exchange
rates. The estimated fair market value of our foreign exchange
contracts was not material at both December 31, 2007 and December 31,2006.
Credit
risk
Financial
instruments that potentially subject us to concentrations of credit risk are
primarily cash equivalents, investments, and trade receivables. It is
our practice to place our cash equivalents and investments in high quality
securities with various investment institutions. We derive the
majority of our revenue from sales and services to the energy
industry. Within the energy industry, trade receivables are generated
from a broad and diverse group of customers. There are concentrations
of receivables in the United States. We maintain an allowance for
losses based upon the expected collectibility of all trade accounts
receivable. In addition, see Note 5 for discussion of
receivables.
There are
no significant concentrations of credit risk with any individual counterparty
related to our derivative contracts. We select counterparties based
on their profitability, balance sheet, and a capacity for timely payment of
financial commitments, which is unlikely to be adversely affected by foreseeable
events.
Interest
rate risk
Our
material outstanding debt instruments have fixed interest rates. As
of December 31, 2007 and 2006, we held no material interest rate derivative
instruments.
79
Fair market value of financial
instruments. The estimated fair market value of long-term debt
was $4.1 billion at December 31, 2007 and $3.7 billion at December 31, 2006, as
compared to the carrying amount of $2.8 billion at both December 31, 2007 and
December 31, 2006. The fair market value of fixed-rate long-term debt
is based on quoted market prices for those or similar
instruments. The carrying amount of short-term financial instruments,
cash and equivalents, receivables, short-term notes payable, and accounts
payable, as reflected in the consolidated balance sheets, approximates fair
market value due to the short maturities of these instruments. The
currency derivative instruments are carried on the balance sheet at fair value
and are based upon third-party quotes.
Note
15. Retirement Plans
Our
company and subsidiaries have various plans that cover a significant number of
our employees. These plans include defined contribution plans,
defined benefit plans, and other postretirement plans:
-
our
defined contribution plans provide retirement benefits in return for
services rendered. These plans provide an individual account
for each participant and have terms that specify how contributions to the
participant’s account are to be determined rather than the amount of
pension benefits the participant is to receive. Contributions
to these plans are based on pretax income and/or discretionary amounts
determined on an annual basis. Our expense for the defined
contribution plans for continuing operations totaled $162 million in 2007,
$138 million in 2006, and $115 million in
2005;
-
our
defined benefit plans include both funded and unfunded pension plans,
which define an amount of pension benefit to be provided, usually as a
function of age, years of service, or compensation;
and
-
our
postretirement medical plans are offered to specific eligible
employees. These plans are contributory. For some
plans, our liability is limited to a fixed contribution amount for each
participant or dependent. The plan participants share the total
cost for all benefits provided above our fixed
contributions. Participants’ contributions are adjusted as
required to cover benefit payments. We have made no commitment
to adjust the amount of our contributions; therefore, for these plans the
computed accumulated postretirement benefit obligation amount is not
affected by the expected future health care cost inflation
rate.
In
September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined
Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements
No. 87, 88, 106, and 132(R).” SFAS No. 158 requires an employer
to:
-
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 December15, 2006. Accordingly, we adopted SFAS No. 158 for our fiscal year
ending December 31, 2006.
The
requirement to measure plan assets and benefit obligations as of the date of the
employer’s fiscal year-end is effective for fiscal years ending after December15, 2008. We did not elect early adoption of these additional SFAS
No. 158 requirements and will adopt these requirements for our fiscal year
ending December 31, 2008.
The
discontinued operations of KBR have been excluded from all of the following
tables and disclosures.
Benefit
obligation and plan assets
The
following tables present plan assets, expenses, and obligation for retirement
plans for continuing operations. We use a September 30 measurement
date for our international plans and an October 31 measurement date for our
domestic plans.
80
Pension
Benefits
Other
United
United
Postretirement
Benefit
obligation
States
Int’l
States
Int’l
Benefits
Millions
of dollars
2007
2006
2007
2006
Change
in benefit obligation
Benefit
obligation at beginning of period
$
127
$
814
$
127
$
680
$
155
$
158
Service
cost
–
26
–
23
1
1
Interest
cost
7
44
7
37
8
9
Plan
participants’ contributions
–
4
–
4
5
7
Plan
amendments
–
2
–
–
(4
)
–
Settlements/curtailments
–
(16
)
–
–
–
–
Currency
fluctuations
–
38
–
39
–
–
Actuarial
(gain) loss
(9
)
(22
)
–
47
(50
)
(6
)
Transfers
–
1
–
–
–
–
Benefits
paid
(15
)
(17
)
(7
)
(16
)
(11
)
(14
)
Benefit
obligation at end of period
$
110
$
874
$
127
$
814
$
104
$
155
Accumulated
benefit obligation at end of period
$
110
$
678
$
127
$
654
$
–
$
–
Pension
Benefits
Other
United
United
Postretirement
States
Int’l
States
Int’l
Benefits
Millions
of dollars
2007
2006
2007
2006
Change
in plan assets
Fair
value of plan assets at beginning of period
$
105
$
622
$
95
$
480
$
–
$
–
Actual
return on plan assets
15
53
13
52
–
–
Employer
contributions
2
39
4
71
7
7
Settlements
–
(9
)
–
–
–
–
Plan
participants’ contributions
–
4
–
4
4
7
Currency
fluctuations
–
32
–
31
–
–
Benefits
paid
(15
)
(17
)
(7
)
(16
)
(11
)
(14
)
Fair
value of plan assets at end of period
$
107
$
724
$
105
$
622
$
–
$
–
Funded
status
$
(3
)
$
(150
)
$
(22
)
$
(192
)
$
(104
)
$
(155
)
Employer
contribution
–
5
–
4
1
1
Net
amount recognized
$
(3
)
$
(145
)
$
(22
)
$
(188
)
$
(103
)
$
(154
)
81
Pension
Benefits
Other
United
United
Postretirement
States
Int’l
States
Int’l
Benefits
Millions
of dollars
2007
2006
2007
2006
Amounts
recognized on the
consolidated balance
sheet
Other
assets
$
2
$
9
$
–
$
2
$
–
$
–
Accrued
employee compensation
and benefits
(1
)
(11
)
–
(9
)
(10
)
(13
)
Employee
compensation and benefits
(4
)
(143
)
(22
)
(181
)
(93
)
(141
)
Pension
plans in which accumulated
benefit obligation exceeded
plan
assets at December
31
Projected
benefit obligation
$
20
$
104
$
127
$
110
$
–
$
–
Accumulated
benefit obligation
20
65
127
72
–
–
Fair
value of plan assets
15
7
105
15
–
–
Weighted-average
assumptions used
to determine benefit
obligations
at measurement
date
Discount
rate
4.61-6.19
%
2.50-8.75
%
5.75
%
2.25-8.75
%
5.77-5.81
%
5.5
%
Rate
of compensation increase
4.5
%
2.0-10.0
%
4.5
%
2.0-10.0
%
N/A
N/A
Asset
allocation at December 31
Asset
categoryTarget allocation 2008
Equity
securities 50%-70%
64
%
57
%
63
%
57
%
N/A
N/A
Debt
securities
30%-50%
35
%
32
%
36
%
35
%
N/A
N/A
Other 0%-5%
1
%
11
%
1
%
8
%
N/A
N/A
Total
100%
100
%
100
%
100
%
100
%
N/A
N/A
Assumed
health care cost trend rates at December 31
2007
2006
2005
Health
care cost trend rate assumed for next year
9.0
%
10.0
%
10.0
%
Rate
to which the cost trend rate is assumed to decline
(the ultimate trend
rate)
5.0
%
5.0
%
5.0
%
Year
that the rate reached the ultimate trend rate
2015
2011
2008
Assumed
long-term rates of return on plan assets, discount rates for estimating benefit
obligations, and rates of compensation increases vary for the different plans
according to the local economic conditions. The weighted average
assumptions for the Nigerian, Indian, and Indonesian plans are not included in
the above tables as the plans were immaterial. The discount rates
were determined based on the prevailing market rate of a portfolio of
high-quality debt instruments with maturities matching the expected timing of
the payment of the benefit obligations. For our United Kingdom
pension plan, which constitutes 76% of our international pension plans’
projected benefit obligation, the discount rate increased from 5.0% at September30, 2006 to 5.7% at September 30, 2007.
The
overall expected long-term rate of return on assets was determined based upon an
evaluation of our plan assets, historical trends, and experience, taking into
account current and expected market conditions.
Our
investment strategy varies by country depending on the circumstances of the
underlying plan. Typically, less mature plan benefit obligations are
funded by using more equity securities, as they are expected to achieve
long-term growth while exceeding inflation. More mature plan benefit
obligations are funded using more fixed income securities, as they are expected
to produce current income with limited volatility. Risk management
practices include the use of multiple asset classes and investment managers
within each.
82
Amounts
recognized in accumulated other comprehensive loss were as follows:
Pension
Benefits
Other
United
United
Postretirement
States
Int’l
States
Int’l
Benefits
Millions
of dollars
2007
2006
2007
2006
Net
actuarial (gain) loss
$
13
$
72
$
29
$
106
$
(39
)
$
(7
)
Prior
service cost (benefit)
–
2
–
2
(3
)
(1
)
Total
recognized in accumulated other
comprehensive
loss
$
13
$
74
$
29
$
108
$
(42
)
$
(8
)
Expected
cash flows
Contributions. Funding
requirements for each plan are determined based on the local laws of the country
where such plan resides. In certain countries the funding
requirements are mandatory, while in other countries they are
discretionary. We currently expect to contribute $29 million to our
international pension plans in 2008. For our domestic plans, we
expect our contributions to be no more than $1 million in 2008. We do
not have a required minimum contribution for our domestic plans; however, we may
make additional discretionary contributions, which will be determined after the
actuarial valuations are complete.
Benefit
payments. The following table presents the expected benefit
payments over the next 10 years.
Pension
Benefits
Other
Postretirement Benefits
United
Gross
Benefit
Gross
Medicare
Millions
of dollars
States
Int’l
Payments
Part
D Receipts
2008
$
11
$
22
$
10
$
1
2009
7
18
11
1
2010
7
20
11
1
2011
8
22
11
1
2012
8
25
12
1
Years
2013 – 2017
37
181
54
5
Net
periodic cost
Pension
Benefits
Other
United
United
United
Postretirement
States
Int’l
States
Int’l
States
Int’l
Benefits
Millions
of dollars
2007
2006
2005
2007
2006
2005
Components
of net
periodic benefit
cost
Service
cost
$
–
$
26
$
–
$
23
$
–
$
22
$
1
$
1
$
1
Interest
cost
7
45
7
37
7
34
8
9
10
Expected
return on plan assets
(7
)
(40
)
(7
)
(30
)
(7
)
(28
)
–
–
–
Amortization
of prior service
cost
–
–
–
–
–
–
–
–
(1
)
Settlements/curtailments
2
–
–
1
–
1
–
–
–
Recognized
actuarial loss
6
9
6
8
4
4
–
–
–
Net
periodic benefit cost
$
8
$
40
$
6
$
39
$
4
$
33
$
9
$
10
$
10
Weighted-average
assumptions used
to
determine net
periodic
benefit cost for
years
ended December
31
Discount
rate
5.75
%
2.25-8.75
%
5.75
%
2.25-8.0
%
5.75
%
2.5-8.0
%
5.5
%
5.75
%
5.75
%
Expected
return on plan assets
8.25
%
4.0-9.0
%
8.25
%
4.0-7.0
%
8.5
%
5.0-7.0
%
N/A
N/A
N/A
Rate
of compensation increase
4.5
%
2.0-10.0
%
4.5
%
2.0-5.0
%
4.5
%
2.0-5.0
%
N/A
N/A
N/A
83
Estimated
amounts that will be amortized from accumulated other comprehensive loss, net of
tax, into net periodic benefit cost in 2008 are as follows:
Pension
Benefits
Other
Postretirement
Millions
of dollars
United
States
International
Benefits
Actuarial
(gain) loss
$
2
$
4
$
(3
)
Prior
service (benefit) cost
–
–
–
Total
$
2
$
4
$
(3
)
The
majority of our postretirement benefit plans are not subjected to risk
associated with fluctuations in the medical trend rates because the company
subsidy is capped. However, for one plan in which the company subsidy
is not capped, the assumed health care cost trend rates could have an impact on
the amounts reported for the total of such health care plans. A
one-percentage-point change in assumed health care cost trend rates would have
the following effects:
One-Percentage-Point
Millions
of dollars
Increase
(Decrease)
Effect
on total of service and interest cost components
$
-
$
–
Effect
on the postretirement benefit obligation
$
4
$
(3
)
Note
16. Related Companies
We
conduct some of our operations through joint ventures that are in partnership,
corporate, and other business forms and are principally accounted for using the
equity method. Financial information pertaining to related companies
for our continuing operations is set out in the following
tables. This information includes the total related-company balances
and not our proportional interest in those balances.
Combined
summarized financial information for all jointly owned operations that are
accounted for under the equity method was as follows:
Combined
operating results
Year
Ended December 31
Millions
of dollars
2007
2006
2005
Revenue
$
500
$
435
$
487
Operating
income
$
111
$
108
$
100
Net
income
$
100
$
122
$
89
Combined
financial position
December
31
Millions
of dollars
2007
2006
Current
assets
$
276
$
195
Noncurrent
assets
210
105
Total
$
486
$
300
Current
liabilities
$
116
$
73
Noncurrent
liabilities
62
31
Shareholders’
equity
308
196
Total
$
486
$
300
84
Note
17. New Accounting Standards
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 January1, 2009, which we do not expect to have a material impact on our consolidated
financial statements.
All
periods presented reflect the reclassification of KBR, Inc. to
discontinued operations in the first quarter of 2007 and the two-for-one
common stock split, effected in the form of a stock dividend, in July
2006.
86
HALLIBURTON
COMPANY
Quarterly
Data and Market Price Information (1)
(Unaudited)
Quarter
Millions
of dollars except per share data
First
Second
Third
Fourth
Year
2007
Revenue
$
3,422
$
3,735
$
3,928
$
4,179
$
15,264
Operating
income
788
893
910
907
3,498
Income
from continuing operations
529
595
726
674
2,524
Income
from discontinued operations
23
935
1
16
975
Net
income
552
1,530
727
690
3,499
Earnings
per share:
Basic income per
share:
Income from continuing
operations
0.53
0.66
0.83
0.77
2.76
Income from discontinued
operations
0.02
1.03
–
0.02
1.07
Net income
0.55
1.69
0.83
0.79
3.83
Diluted income per
share:
Income from continuing
operations
0.52
0.63
0.79
0.74
2.66
Income from discontinued
operations
0.02
0.99
–
0.01
1.02
Net income
0.54
1.62
0.79
0.75
3.68
Cash
dividends paid per share
0.075
0.09
0.09
0.09
0.345
Common
stock prices (2)
High
32.72
37.20
39.17
41.95
41.95
Low
27.65
30.99
30.81
34.42
27.65
2006
Revenue
$
2,938
$
3,116
$
3,392
$
3,509
$
12,955
Operating
income
692
760
870
923
3,245
Income
from continuing operations
449
498
603
627
2,177
Income
from discontinued operations
39
93
8
31
171
Net
income
488
591
611
658
2,348
Earnings
per share:
Basic income per
share:
Income from continuing
operations
0.44
0.49
0.60
0.63
2.15
Income from discontinued
operations
0.04
0.09
0.01
0.03
0.16
Net income
0.48
0.58
0.61
0.66
2.31
Diluted income per
share:
Income from continuing
operations
0.42
0.47
0.57
0.61
2.07
Income from discontinued
operations
0.04
0.08
0.01
0.03
0.16
Net income
0.46
0.55
0.58
0.64
2.23
Cash
dividends paid per share
0.075
0.075
0.075
0.075
0.30
Common
stock prices (2)
High
41.19
41.99
37.93
34.30
41.99
Low
31.35
33.92
27.35
26.33
26.33
(1)
All
periods presented reflect the reclassification of KBR, Inc. to
discontinued operations in the first quarter of 2007 and the two-for-one
common stock split, effected in the form of a stock dividend, in July
2006.
(2)
New
York Stock Exchange – composite transactions high and low intraday
price.
87
PART
III
Item
10. Directors, Executive Officers, and Corporate
Governance.
The
information required for the directors of the Registrant is incorporated by
reference to the Halliburton Company Proxy Statement for our 2008 Annual Meeting
of Stockholders (File No. 001-03492), under the caption “Election of
Directors.” The information required for the executive officers of
the Registrant is included under Part I on pages 7 through 9 of this
annual report. The information required for a delinquent form
required under Section 16(a) of the Securities Exchange Act of 1934 is
incorporated by reference to the Halliburton Company Proxy Statement for our
2008 Annual Meeting of Stockholders (File No. 001-03492), under the caption
“Section 16(a) Beneficial Ownership Reporting Compliance,” to the extent any
disclosure is required. The information for our code of ethics is
incorporated by reference to the Halliburton Company Proxy Statement for our
2008 Annual Meeting of Stockholders (File No. 001-03492), under the caption
“Corporate Governance.”
Audit
Committee financial experts
In the
business judgment of the Board of Directors, all five members of the Audit
Committee, Kathleen M. Bader, Alan M. Bennett, Robert L. Crandall, J. Landis
Martin, and Jay A. Precourt, are independent and have accounting or related
financial management experience required under the listing standards and have
been designated by the Board of Directors as “audit committee financial
experts.”
Item
11. Executive Compensation.
This
information is incorporated by reference to the Halliburton Company Proxy
Statement for our 2008 Annual Meeting of Stockholders (File No. 001-03492) under
the captions “Compensation Discussion and Analysis,”“Compensation Committee
Report,”“Summary Compensation Table,”“Grants of Plan-Based Awards in Fiscal
2007,”“Outstanding Equity Awards at Fiscal Year End 2007,”“2007 Option
Exercises and Stock Vested,”“2007 Nonqualified Deferred Compensation,”“Pension
Benefits Table,”“Employment Contracts and Change-in-Control Arrangements,”“Post-Termination Payments,”“Equity Compensation Plan Information,” and “2007
Director Compensation.”
Item
12(a). Security Ownership of Certain Beneficial Owners.
This
information is incorporated by reference to the Halliburton Company Proxy
Statement for our 2008 Annual Meeting of Stockholders (File No. 001-03492) under
the caption “Stock Ownership of Certain Beneficial Owners and
Management.”
This
information is incorporated by reference to the Halliburton Company Proxy
Statement for our 2008 Annual Meeting of Stockholders (File No. 001-03492) under
the caption “Stock Ownership of Certain Beneficial Owners and
Management.”
Item
12(d). Securities Authorized for Issuance Under Equity Compensation
Plans.
This
information is incorporated by reference to the Halliburton Company Proxy
Statement for our 2008 Annual Meeting of Stockholders (File No. 001-03492) under
the caption “Equity Compensation Plan Information.”
Item
13. Certain Relationships and Related Transactions, and Director
Independence.
This
information is incorporated by reference to the Halliburton Company Proxy
Statement for our 2008 Annual Meeting of Stockholders (File No. 001-03492) under
the caption “Certain Relationships and Related Transactions” to the extent any
disclosure is required.
88
Item
14. Principal Accounting Fees and Services.
This
information is incorporated by reference to the Halliburton Company Proxy
Statement for our 2008 Annual Meeting of Stockholders (File No. 001-03492) under
the caption “Fees Paid to KPMG LLP.”
89
PART
IV
Item
15. Exhibits and Financial Statement Schedules.
1.
Financial
Statements:
The
reports of the Independent Registered Public Accounting Firm and the
financial statements of the Company as required by Part II, Item 8, are
included on pages 46 and 47 and pages 48 through 85 of
this annual report. See index on page
(i).
2.
Financial
Statement Schedules:
Page
No.
Report
on supplemental schedule of KPMG LLP
97
Schedule
II – Valuation and qualifying accounts for the three
Note: All
schedules not filed with this report required by Regulation S-X have been
omitted as not applicable or not required, or the information required has been
included in the notes to financial statements.
Form
of debt security of 8.75% Debentures due February 12, 2021 (incorporated
by reference to Exhibit 4(a) to the Form 8-K of Halliburton Company, now
known as Halliburton Energy Services, Inc. (the Predecessor) dated as of
February 20, 1991, File No.
001-03492).
4.2
Senior
Indenture dated as of January 2, 1991 between the Predecessor and The Bank
of New York Trust Company, N.A. (as successor to Texas Commerce Bank
National Association), as Trustee (incorporated by reference to Exhibit
4(b) to the Predecessor’s Registration Statement on Form S-3 (Registration
No. 33-38394) originally filed with the Securities and Exchange Commission
on December 21, 1990), as supplemented and amended by the First
Supplemental Indenture dated as of December 12, 1996 among the
Predecessor, Halliburton and the Trustee (incorporated by reference to
Exhibit 4.1 of Halliburton’s Registration Statement on Form 8-B dated
December 12, 1996, File No.
001-03492).
4.3
Resolutions
of the Predecessor’s Board of Directors adopted at a meeting held on
February 11, 1991 and of the special pricing committee of the Board of
Directors of the Predecessor adopted at a meeting held on February 11,
1991 and the special pricing committee’s consent in lieu of meeting dated
February 12, 1991 (incorporated by reference to Exhibit 4(c) to the
Predecessor’s Form 8-K dated as of February 20, 1991, File No.
001-03492).
90
4.4
Second
Senior Indenture dated as of December 1, 1996 between the Predecessor and
The Bank of New York Trust Company, N.A. (as successor to Texas Commerce
Bank National Association), as Trustee, as supplemented and amended by the
First Supplemental Indenture dated as of December 5, 1996 between the
Predecessor and the Trustee and the Second Supplemental Indenture dated as
of December 12, 1996 among the Predecessor, Halliburton and the Trustee
(incorporated by reference to Exhibit 4.2 of Halliburton’s Registration
Statement on Form 8-B dated December 12, 1996, File No.
001-03492).
Form
of debt security of 6.75% Notes due February 1, 2027 (incorporated by
reference to Exhibit 4.1 to Halliburton’s Form 8-K dated as of February11, 1997, File No. 001-03492).
Copies
of instruments that define the rights of holders of miscellaneous
long-term notes of Halliburton and its subsidiaries, totaling $9 million
in the aggregate at December 31, 2007, have not been filed with the
Commission. Halliburton agrees to furnish copies of these
instruments upon request.
4.11
Form
of debt security of 7.53% Notes due May 12, 2017 (incorporated by
reference to Exhibit 4.4 to Halliburton’s Form 10-Q for the quarter ended
March 31, 1997, File No.
001-03492).
4.12
Form
of debt security of 5.63% Notes due December 1, 2008 (incorporated by
reference to Exhibit 4.1 to Halliburton’s Form 8-K dated as of November24, 1998, File No. 001-03492).
4.13
Form
of Indenture, between Dresser and The Bank of New York Trust Company, N.A.
(as successor to Texas Commerce Bank National Association), as Trustee,
for 7.60% Debentures due 2096 (incorporated by reference to Exhibit 4 to
the Registration Statement on Form S-3 filed by Dresser as amended,
Registration No. 333-01303), as supplemented and amended by Form of
Supplemental Indenture, between Dresser and The Bank of New York Trust
Company, N.A. (as successor to Texas Commerce Bank National Association),
Trustee, for 7.60% Debentures due 2096 (incorporated by reference to
Exhibit 4.1 to Dresser’s Form 8-K filed on August 9, 1996, File No.
1-4003).
Indenture
dated as of June 30, 2003 between Halliburton and The Bank of New York
Trust Company, N.A. (as successor to JPMorgan Chase Bank), as Trustee
(incorporated by reference to Exhibit 4.1 to Halliburton’s Form 10-Q for
the quarter ended June 30, 2003, File No.
001-03492).
4.17
Form
of note of 3.125% Convertible Senior Notes due July 15, 2023 (included as
Exhibit A to Exhibit 4.16 above).
4.18
First
Supplemental Indenture dated as of December 17, 2004 between Halliburton
and The Bank of New York Trust Company, N.A. (as successor to JPMorgan
Chase Bank), as Trustee, to Indenture dated as of June 30, 2003, between
Halliburton and The Bank of New York Trust Company, N.A. (as successor to
JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.1
to Halliburton’s Form 8-K filed on December 21, 2004, File No.
001-03492).
Halliburton
Company Career Executive Incentive Stock Plan as amended November 15, 1990
(incorporated by reference to Exhibit 10(a) to the Predecessor’s Form 10-K
for the year ended December 31, 1992, File No.
001-03492).
Halliburton
Company Restricted Stock Plan for Non-Employee Directors (incorporated by
reference to Appendix B of the Predecessor’s proxy statement dated March23, 1993, File No. 001-03492).
Amendment
No. 1 to the Supplemental Executive Retirement Plan of Dresser Industries,
Inc. (incorporated by reference to Exhibit 10.1 to Dresser’s Form 10-Q for
the quarter ended April 30, 1998, File No.
1-4003).
Amendments
No. 1 and 2 to Dresser Industries, Inc. 1992 Stock Compensation Plan
(incorporated by reference to Exhibit A to Dresser’s Proxy Statement dated
February 6, 1995, File No. 1-4003).
10.11
Amendment
No. 3 to the Dresser Industries, Inc. 1992 Stock Compensation Plan
(incorporated by reference to Exhibit 10.25 to Dresser’s Form 10-K for the
year ended October 31, 1997, File No.
1-4003).
Five
Year Revolving Credit Agreement among Halliburton, as Borrower, the Banks
party thereto, and Citicorp North America, Inc., as Administrative Agent
(incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed
July 13, 2007, File No. 001-03492).
Power
of attorney for Kathleen M. Bader signed in February
2008.
*
31.1
Certification
of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
*
31.2
Certification
of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
**
32.1
Certification
of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
**
32.2
Certification
of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
*
Filed
with this Form 10-K.
**
Furnished
with this Form 10-K.
96
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM
ON
SUPPLEMENTAL SCHEDULE
The Board
of Directors and Shareholders
Halliburton
Company:
Under
date of February 20, 2008, we reported on the consolidated balance sheets of
Halliburton Company and subsidiaries as of December 31, 2007 and 2006, and the
related consolidated statements of operations, shareholders’ equity, and cash
flows for each of the years in the three-year period ended December 31, 2007,
which are included in the Company’s Annual Report on Form 10-K. In
connection with our audits of the aforementioned consolidated financial
statements, we also audited the related consolidated financial statement
schedule (Schedule II) in the Company’s Annual Report on Form 10-K. The
financial statement schedule is the responsibility of the Company’s
management. Our responsibility is to express an opinion on this
financial statement schedule based on our audits.
In our
opinion, the financial statement schedule, when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly, in
all material respects, the information set forth therein.
Our
report on the financial statements referred to above, refers to a change in the
methods of accounting for uncertainty in income taxes as of January 1, 2007,
accounting for stock-based compensation plans as of January 1, 2006, and
accounting for defined benefit and other postretirement plans as of December 31,2006.
(a) Amount represents
releases of excess reserves.
(b) Includes the write-off
of allowance for doubtful accounts related to asbestos
receivables.
98
SIGNATURES
As
required by Section 13 or 15(d) of the Securities Exchange Act of 1934, the
registrant has authorized this report to be signed on its behalf by the
undersigned authorized individuals on this 22nd day of February,
2008.
HALLIBURTON
COMPANY
By
/s/
David J. Lesar
David
J. Lesar
Chairman
of the Board,
President,
and Chief Executive Officer
As
required by the Securities Exchange Act of 1934, this report has been signed
below by the following persons in the capacities indicated on this 22nd day of
February, 2008.