Annual Report — Form 10-K Filing Table of Contents
Document/ExhibitDescriptionPagesSize 1: 10-K 12-31-2008 Form 10-K HTML 1.88M
2: EX-10.34 Angelle Executive Agreement HTML 77K
3: EX-10.35 Lotfy Executive Agreement HTML 77K
4: EX-10.36 Probert Executive Agreement HTML 77K
5: EX-10.37 Nunez Executive Agreement HTML 78K
6: EX-10.38 King Executive Agreement HTML 83K
7: EX-10.39 Brown Amendment to Executive Employment Agreement HTML 18K
8: EX-10.40 Cornelison Amendment to Executive Employment HTML 19K
Agreement
9: EX-10.41 Gaut Amendment Ot Executive Employment Agreement HTML 19K
10: EX-10.42 King Amendment to Executive Employment Agreement HTML 19K
11: EX-10.43 McCollum Amendment to Executive Employment HTML 19K
Agreement
12: EX-12.1 Ratio of Efc-2008 HTML 48K
13: EX-21.1 Subsidiaries HTML 17K
14: EX-23.1 Consent HTML 12K
15: EX-24.2 Hackett Power of Attorney HTML 10K
16: EX-31.1 Lesar 302 Certification HTML 15K
17: EX-31.2 McCollum 302 Certification HTML 15K
18: EX-32.1 Lesar 906 Certification HTML 11K
19: EX-32.2 McCollum 906 Certification HTML 11K
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 (§229.405 of this chapter) is not contained herein, and will not
be contained, to the best of registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. [ ]
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, 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.:
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 30, 2008,
determined using the per share closing price on the New York Stock Exchange
Composite tape of $53.07 on that date was approximately
$46,371,000,000.
As of
February 13, 2009, there were 897,174,201 shares of Halliburton Company Common
Stock, $2.50 par value per share, outstanding.
Portions
of the Halliburton Company Proxy Statement for our 2009 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
Operations
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
52
Reports
of Independent Registered Public Accounting Firm
53
Consolidated
Statements of Operations
55
Consolidated
Balance Sheets
56
Consolidated
Statements of Shareholders’ Equity
57
Consolidated
Statements of Cash Flows
58
Notes
to Consolidated Financial Statements
59
Selected
Financial Data (Unaudited)
93
Quarterly
Data and Market Price Information (Unaudited)
94
PART III
Item
10.
Directors,
Executive Officers, and Corporate Governance
95
Item
11.
Executive
Compensation
95
Item
12(a).
Security
Ownership of Certain Beneficial Owners
95
Item
12(b).
Security
Ownership of Management
95
Item
12(c).
Changes
in Control
96
Item
12(d).
Securities
Authorized for Issuance Under Equity Compensation Plans
96
Item
13.
Certain
Relationships and Related Transactions, and Director
Independence
96
Item
14.
Principal
Accounting Fees and Services
96
PART IV
Item
15.
Exhibits
and Financial Statement Schedules
97
SIGNATURES
107
(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. We
operate under two divisions, which form the basis for the two operating segments
we report: the Completion and Production segment and the Drilling and
Evaluation segment. See Note 4 to the consolidated financial
statements for financial information about our business segments.
In
November 2006, KBR, Inc. (KBR) which at the time was our wholly-owned
subsidiary, completed an initial public offering. During the second
quarter of 2007, we completed the separation of KBR from us and 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 for prior years. See Note 2 to the consolidated
financial statements for further information relating to the specific
indemnities and guarantees provided to KBR upon separation. During
2008, we recorded $420 million, net of tax, as a loss from discontinued
operations to reflect the resolution of the Department of Justice (DOJ) and
Securities and Exchange Commission (SEC) investigations related to the Foreign
Corrupt Practices Act (FCPA) and our most recent assumptions regarding the value
of other indemnities and guarantees provided to KBR. See Note 10 to
the consolidated financial statements for further information related to the
FCPA investigations.
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.
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.
1
Drilling
and Evaluation
Our
Drilling and Evaluation segment provides field and reservoir modeling, drilling,
evaluation, and well construction solutions that enable customers to model,
measure, and optimize their well placement, stability, and reservoir evaluation
activities. This segment consists of fluid services, drilling
services, drill bits, wireline and perforating services, software and asset
solutions, and project management services.
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.
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 for precise wellbore placement while
providing important measurements about the characteristics of the drill string
and geological formations while drilling wells. Real-time operating
capabilities enable the monitoring of well progress and aid decision-making
processes.
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, 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,
perforating, and borehole seismic services. Perforating services
include tubing-conveyed perforating services and products. Borehole
seismic services include fracture analysis and mapping.
Software
and asset solutions 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
2008, we acquired the remaining 49% equity interest in WellDynamics from Shell
Technology Ventures Fund 1 B.V. (STV Fund), resulting in our 100% ownership of
WellDynamics. WellDynamics is a provider of intelligent well completion
technology and its results of operations are included in our Completion and
Production segment.
In July
2007, we acquired the entire share capital of PSL Energy Services Limited
(PSLES), a leading 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 $335 million for PSLES, consisting of $331 million
in cash and $4 million in debt assumed. We have recorded goodwill of
$158 million and intangible assets of $61 million associated with the
acquisition. Beginning in August 2007, PSLES’s results of operations
are included in our Completion and Production segment.
2
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.
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.
Business
strategy
Our
business strategy is to secure a distinct and sustainable competitive position
as a pure-play oilfield service company by delivering products and services to
our customers that maximize their production and recovery and realize proven
reserves from difficult environments. Our objectives are
to:
-
create
a balanced portfolio of products and services supported by global
infrastructure and anchored by technology innovation with a
well-integrated digital strategy to further differentiate our
company;
-
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. The
business operations of our divisions are organized around four primary
geographic regions: North America, Latin America, Europe/Africa/CIS, and Middle
East/Asia. In 2008, based on the location of services provided and
products sold, 43% of our consolidated revenue was from the United
States. In 2007 and 2006, 44% and 45% 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 “Management’s
Discussion and Analysis of Financial Condition and Results of Operations –
Business Environment and Results of Operations” and 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.
3
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. Market conditions can trigger constraints in the supply of
certain raw materials, such as sand, cement, and specialty metals. We
are always seeking ways to ensure the availability of resources, as well as
manage costs of raw materials. Our procurement department is using
our size and buying power through several programs designed to ensure that we
have access to key materials at competitive prices.
Research
and development costs
We
maintain an active research and development program. The program
improves existing products and processes, develops new products and processes,
and improves engineering standards and practices that serve the changing needs
of our customers. Our expenditures for research and development
activities were $326 million in 2008, $301 million in 2007, and $254 million in
2006, of which over 96% 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, software and asset solutions and
completion tools results of operations are generally stronger in the fourth
quarter of the year than at the beginning of the year.
4
Employees
At
December 31, 2008, we employed approximately 57,000 people worldwide compared to
approximately 51,000 at December 31, 2007. At December 31, 2008,
approximately 14% 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.
Working
capital
We fund
our business operations through a combination of available cash and equivalents,
short-term investments, and cash flow generated from operations. In
addition, our revolving credit facilities are available for additional working
capital needs.
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 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 for the years presented, 2008, 2007, or
2006. The CEO and CFO certifications required by Section 302 of the
Sarbanes-Oxley Act of 2002 have been filed as exhibits to our Form 10-K. We have
also submitted the Annual CEO Certification to the New York Stock
Exchange.
5
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— 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:
Johor,
Malaysia
Leased
Manufacturing
facility
Monterrey,
Mexico
Leased
Manufacturing
facility
Sao Jose dos Campos,
Brazil
Leased
Manufacturing
facility
Stavanger,
Norway
Leased
Research
and development laboratory
Drilling and Evaluation
segment:
Alvarado,
Texas
Owned/Leased
Manufacturing
facility
Houston, Texas
Owned
Manufacturing,
technology, and campus facilities
Singapore
Leased
Manufacturing
and technology facility
The Woodlands,
Texas
Leased
Manufacturing
facility
Shared
facilities:
Carrollton,
Texas
Owned
Manufacturing
facility
Duncan,
Oklahoma
Owned
Manufacturing,
technology, and campus facilities
Houston, Texas
Owned
Campus
facility
Houston, Texas
Leased
Campus
facility
Pune, India
Leased
Technology
facility
Corporate:
Houston, Texas
Leased
Corporate
executive offices
Dubai, United Arab
Emirates
Leased
Corporate
executive offices
All of
our owned properties are unencumbered.
In
addition, we have 133 international and 103 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—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 2008.
The
following table indicates the names and ages of the executive officers of
Halliburton Company as of February 13, 2009, 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 41)
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
James S. Brown
President,
Western Hemisphere of Halliburton Company, since January
2008
(Age 54)
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
* Albert
O. Cornelison, Jr.
Executive
Vice President and General Counsel of Halliburton
Company,
(Age 59)
since December
2002
Director
of KBR, Inc., June 2006 to April 2007
C. Christopher
Gaut
President,
Drilling and Evaluation Division of Halliburton
Company,
(Age 52)
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
7
Name and Age
Offices Held and Term of
Office
David S. King
President,
Completion and Production Division of Halliburton
Company,
(Age 52)
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
* David
J. Lesar
Chairman
of the Board, President, and Chief Executive Officer of
Halliburton
(Age 55)
Company, since August
2000
Ahmed H. M.
Lotfy
President,
Eastern Hemisphere of Halliburton Company, since January
2008
(Age 54)
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 49)
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
Craig W. Nunez
Senior
Vice President and Treasurer of Halliburton Company,
(Age 47)
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 40)
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
* Timothy
J. Probert
Executive
Vice President, Strategy and Corporate Development of
Halliburton
(Age 57)
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 94 of this annual
report. Cash dividends on common stock in the amount of $0.09 per
share were paid in March, June, September, and December of 2008 and June,
September, and December of 2007. Cash dividends on common stock in
the amount of $0.075 per share were paid in March of 2007. 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 ended December 31, 2008, 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, 2003, and the reinvestment of all dividends. The
shareholder return set forth is not necessarily indicative of future
performance.
December
31
2003
2004
2005
2006
2007
2008
Halliburton
$
100.00
$
153.28
$
244.43
$
247.14
$
304.79
$
147.95
Standard
& Poor’s 500 Stock Index
100.00
110.88
116.33
134.70
142.10
89.53
Standard
& Poor’s Energy Composite Index
100.00
131.54
172.80
214.63
288.47
187.88
At
February 13, 2009, there were 18,585 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, 2008.
Total Number of
Shares
Purchased as Part
of
Total Number of
Shares
Average Price Paid
per
Publicly
Announced
Period
Purchased
(a)
Share
Plans or
Programs
October
1-31
36,642
$
26.20
–
November
1-30
12,264
$
18.46
–
December
1-31
66,986
$
15.32
–
Total
115,892
$
19.09
–
(a)
All
of the 115,892 shares purchased during the three-month period ended
December 31, 2008 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.
Item
6. Selected Financial Data.
Information
related to selected financial data is included on page 93 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 51 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 37 of this annual report.
11
Item
8. Financial Statements and Supplementary Data.
Page No.
Management’s
Report on Internal Control Over Financial Reporting
52
Reports
of Independent Registered Public Accounting Firm
Quarterly
Data and Market Price Information (Unaudited)
94
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, 2008 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, 2008 that has materially affected, or
is reasonably likely to materially affect, our internal control over financial
reporting.
See
page 52 for Management’s Report on Internal Control Over Financial
Reporting and page 54 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
Organization
We are a
leading provider of products and services to the energy industry. 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. Activity
levels within our operations are significantly impacted by spending on upstream
exploration, development, and production programs by major, national, and
independent oil and natural gas companies. We report our results
under two segments, Completion and Production and Drilling and
Evaluation:
-
our
Completion and Production segment delivers cementing, stimulation,
intervention, and completion services. The segment consists of
production enhancement services, completion tools and services, and
cementing services; and
-
our
Drilling and Evaluation segment provides field and reservoir modeling,
drilling, evaluation, and precise wellbore placement solutions that enable
customers to model, measure, and optimize their well construction
activities. The segment consists of fluid services, drilling
services, drill bits, wireline and perforating services, software and
asset solutions, and project management
services.
The
business operations of our segments are organized around four primary geographic
regions: North America, Latin America, Europe/Africa/CIS, and Middle
East/Asia. We have significant manufacturing operations in various
locations, including, but not limited to, the United States, Canada, the United
Kingdom, Continental Europe, Malaysia, Mexico, Brazil, and
Singapore. With approximately 57,000 employees, we operate in
approximately 70 countries around the world, and our corporate headquarters are
in Houston, Texas and Dubai, United Arab Emirates.
Financial
results
During
2008, we produced revenue of $18.3 billion and operating income of $4.0 billion,
reflecting an operating margin of 22%. Revenue increased $3.0 billion or
20% over 2007, while operating income improved $512 million or 15% over
2007. Consistent with our initiative to grow our non-North America
operations, we experienced 22% revenue growth and 26% operating income growth
outside of North America in 2008 compared to 2007. Revenue from our Latin
America region increased 35% to $2.4 billion, and operating income increased 49%
to $521 million in 2008 compared to 2007. Our Middle East/Asia region also
returned revenue and operating income growth in excess of 20% in 2008 compared
to 2007.
Business
outlook
We
continue to believe in the strength of the long-term fundamentals of our
business. However, due to the financial crisis that developed in
mid-2008, the ensuing negative impact on credit availability, and the current
excess supply of oil and natural gas, the near- and mid-term outlook for our
business and the industry remains uncertain. Forecasting the depth
and length of the current recession and its impact on the declining demand for
energy is challenging due to the many factors involved.
13
Although
prices and margins had started to stabilize in North America during the first
nine months of 2008, a significant reduction in activity beginning in December
of 2008 and a corresponding drop in the United States rig count from the end of
the third quarter of 2008 have reversed this trend. Pricing declines
are now occurring due to excess equipment and customer requests for discounts on
existing work. In 2009, rig counts have continued to fall and as of
February 13, 2009 are approximately 34% below 2008 highs. Capital
expenditure adjustments from our customers remain fluid as they adjust their
spending in response to a continued drop in commodity price fundamentals and
lack of readily available credit. As a result, we are seeing activity
declines intensify and expect activity declines for North America land to
accelerate in the first quarter of 2009. We also anticipate severe
margin contraction to occur worldwide throughout 2009. Outside of North
America, declining oil prices have caused our customers to defer many of their
new projects. Operators have announced a decline in spending in 2009,
and we anticipate severe margin contraction throughout 2009. Several
areas have been affected by capital access issues that have constrained the
ability of some of our independent, upstream customers to fund their
programs. Our larger customers are deferring several platform-based
projects until they see commodity price stabilization.
In 2009,
we will focus on:
-
minimizing
discretionary spending;
-
lowering
our costs from vendors;
-
reducing
headcount in locations experiencing significant activity
declines;
-
focusing
on working capital management and managing our balance sheet to maximize
our financial flexibility;
- continuing
the globalization of our manufacturing and supply chain processes;
-
leveraging
our technologies to provide our customers with the ability to more
efficiently drill and complete their wells. To that end, we
opened one international research and development center with global
technology and training missions in 2007 and two in
2008;
-
continuing
to deploy our packaged services strategy that creates an efficiency model
for our customers in the development of their
assets;
-
expanding
our business with national oil companies, including preparing for a shift
to increased use of our integrated project management
services;
-
continuing
to pursue strategic acquisitions that enhance our technological position
and our product and service portfolio in key areas, such as the following
acquisitions in 2008:
-
in
October 2008, we acquired the assets of Pinnacle Technologies, Inc.
(Pinnacle), including the Pinnacle brand from CARBO Ceramics
Inc. Pinnacle is a provider of microseismic fracture mapping
services and tiltmeter mapping
services;
-
in
July 2008, we acquired the remaining 49% equity interest in WellDynamics
B.V. (WellDynamics) from Shell Technology Ventures Fund 1 B.V. (STV
Fund). We now own 100% of WellDynamics, a provider of
intelligent well completion
technology;
-
in
June 2008, we acquired all the intellectual property and assets of Protech
Centerform, a provider of casing centralization services;
and
-
in
May 2008, we acquired all intellectual property, assets, and existing
business of Knowledge Systems Inc. (KSI), a leading provider of
combined geopressure and geomechanical analysis software and
services.
Our
operating performance is described in more detail in “Business Environment and
Results of Operations.”
14
Financial
markets, liquidity, and capital resources
In the
latter half of 2008 and so far in 2009, the equity, credit, and commodity
markets have seen unprecedented volatility. While this has created
certain additional risks for our business, we believe we have invested our cash
balances conservatively, reduced our leverage, and secured sufficient short-term
credit capacity to help mitigate any near-term, negative impact on our
operations. During the third quarter of 2008, we issued an aggregate
amount of $1.2 billion in senior notes and settled the principal and conversion
premium on our 3.125% convertible senior notes. For additional
information, see “Liquidity and Capital Resources”, “Risk Factors”, Note 9 to
our consolidated financial statements, and “Business Environment and Results of
Operations.”
Resolution of the DOJ and SEC FCPA
investigations has resulted in additional charges in 2008 to discontinued
operations. See Note
10 to our consolidated financial statements and “Risk Factors” for further
information.
15
LIQUIDITY
AND CAPITAL RESOURCES
We ended
2008 with cash and equivalents of $1.1 billion compared to $1.8 billion at
December 31, 2007.
Significant
sources of cash
Cash
flows from operating activities contributed $2.7 billion to cash in
2008. Growth in revenue and operating income was attributable to
higher customer demand and increased service intensity due to a trend toward
exploration and exploitation of more complex reservoirs.
In
September 2008, we issued senior notes due 2038 totaling $800 million and senior
notes due 2018 totaling $400 million, which were used to pay the principal
amount of our 3.125% convertible senior notes.
Early in
2008, we sold approximately $388 million of marketable securities, consisting of
auction-rate securities and variable-rate demand notes.
Further available sources of cash.
We have an unsecured $1.2 billion five-year revolving credit facility
expiring in 2012 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, 2008.
In
October of 2008, we entered into an additional unsecured, six-month revolving
credit facility, with current commitments of $400 million, in order to give us
additional liquidity and for other general corporate purposes. There
were no cash drawings under the facility as of December 31, 2008.
Significant
uses of cash
Our
3.125% convertible senior notes due July 2023 became redeemable at our option on
July 15, 2008. On July 30, 2008, we gave notice of redemption on the
convertible notes. In lieu of redemption, the holders of the convertible
notes could convert each $1,000 principal amount of convertible notes into
53.4069 shares of our common stock. Substantially all of the holders
timely elected to convert during the third quarter of 2008. Upon
conversion, we settled the principal amount of our convertible notes in cash and
the premium on our notes with a combination of $693 million in cash and
approximately $840 million, or 20 million shares, of our treasury
stock.
Capital
expenditures were $1.8 billion in 2008, with increased focus toward building
infrastructure and adding service equipment in support of our expanding
operations outside of North America. Capital expenditures were
predominantly made in the drilling services, production enhancement, cementing,
and wireline and perforating product service lines.
During
2008, we repurchased approximately 13 million shares of our common stock under
our share repurchase program at a cost of approximately $481 million at an
average price of $36.61 per share.
We paid
$319 million in dividends to our shareholders in 2008.
We repaid
$150 million of medium term notes, which matured in December 2008.
Future uses of
cash. We have approximately $1.8 billion remaining available
under our share repurchase authorization, which may be used for open market
share purchases.
In 2009,
we believe we will maintain our capital expenditures up to 2008 levels but
will monitor our customers' activity and make reductions as
necessary. The capital expenditures plan for 2009 is primarily
directed toward our production enhancement, drilling services, wireline and
perforating, and cementing product service lines and toward retiring old
equipment to replace it with new equipment to improve our fleet
reliability. We are currently exploring 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.
As a
result of the resolution of the DOJ and SEC FCPA investigations, we will pay a
total of $559 million over the next two years under the settlements and
indemnities provided to KBR upon separation. See Notes 2 and 10 to
our consolidated financial statements for more information.
Subject
to Board of Directors approval, we expect to pay dividends of approximately $80
million per quarter in 2009.
16
The
following table summarizes our significant contractual obligations and other
long-term liabilities as of December 31, 2008:
Payments
Due
Millions
of dollars
2009
2010
2011
2012
2013
Thereafter
Total
Long-term
debt
$
26
$
749
$
–
$
–
$
–
$
1,837
$
2,612
Interest
on debt (a)
168
168
127
127
126
3,578
4,294
Operating
leases
183
161
130
84
66
175
799
Purchase
obligations
1,501
65
32
16
5
8
1,627
Pension
funding obligations (b)
48
–
–
–
–
–
48
DOJ
and SEC settlement and indemnity
373
186
–
–
–
–
559
Other
long-term liabilities
9
9
9
9
9
–
45
Total
$
2,308
$
1,338
$
298
$
236
$
206
$
5,598
$
9,984
(a)
Interest
on debt includes 88 years of interest on $300 million of debentures at
7.6% interest that become due in
2096.
(b)
Amount
based on assumptions that are subject to change. Also, we may
choose to make additional discretionary contributions. We are
currently not able to reasonably estimate our contributions for years
after 2009. See Note 15 to the consolidated financial
statements for further information regarding pension
contributions.
We had
$343 million of gross unrecognized tax benefits at December 31, 2008, of which
we estimate $79 million may require a cash payment. We estimate that
$38 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, 2008, including
approximately $828 million 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.
Financial position in current
market. In recent years, we have reduced our leverage and
improved our liquidity by focusing on debt reduction and improvement to our
credit profile. Our debt maturities extend over a long period of
time. We have no financial covenants or material adverse change
provisions in our bank agreements, and we are working to continue to improve our
short-term credit capacity. We currently have a total of $1.6 billion
of committed bank credit under revolving credit facilities to support our
operations and any commercial paper we may issue in the
future. Currently, there are no borrowings under these revolving
credit facilities.
In
addition, we manage our cash investments by investing principally in United
States Treasury securities and repurchase agreements collateralized by United
States Treasury securities.
Credit
ratings. Credit ratings for our long-term debt remain A2 with
Moody’s Investors Service and A with Standard & Poor’s. The
credit ratings on our short-term debt remain P-1 with Moody’s Investors Service
and A-1 with Standard & Poor’s.
Customer receivables.
In most cases, we bill our customers for our services in arrears and are,
therefore, subject to our customers delaying or failing to pay our
invoices. In weak economic environments, we may experience increased
delays and failures due to, among other reasons, a reduction in our customer’s
cash flow from operations and their access to the credit markets. If our
customers delay in paying or fail to pay us a significant amount of our
outstanding receivables, it could have a material adverse effect on our
liquidity, consolidated results of operations, and consolidated financial
condition.
17
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 natural
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 throughout the life
of the field. Our two business segments are the Completion and
Production segment and the Drilling and Evaluation segment. The
industries we serve are highly competitive with many substantial competitors in
each segment. In 2008, based upon the location of the services
provided and products sold, 43% of our consolidated revenue was from the United
States. In 2007 and 2006, 44% and 45% 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, economic recessions, 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 natural gas
consumption. See “Risk Factors—Worldwide recession and effect on
exploration and production activity” for further information related to the
effect of the current recession.
Some of
the more significant barometers of current and future spending levels of oil and
gas companies are oil and natural gas prices, the world economy, and global
stability, which together drive worldwide drilling activity. Our
financial performance is significantly affected by oil and natural gas prices
and worldwide rig activity, which are summarized in the following
tables.
This
table shows the historical average prices for West Texas Intermediate (WTI) and
United Kingdom Brent crude oil and Henry Hub natural gas:
Average Oil Prices
(dollars per barrel)
2008
2007
2006
West
Texas Intermediate
$
99.37
$
71.91
$
66.17
United
Kingdom Brent
$
96.86
$
72.21
$
65.35
Average United States Gas
Prices (dollars per million British
thermal units, or
mmBtu)
Henry
Hub
$
8.79
$
6.97
$
6.81
18
The
historical yearly average rig counts based on the Baker Hughes Incorporated rig
count information were as follows:
Land
vs. Offshore
2008
2007
2006
United
States:
Land
1,812
1,694
1,558
Offshore (incl. Gulf of
Mexico)
128
144
176
Total
1,940
1,838
1,734
Canada:
Land
378
341
467
Offshore
1
3
3
Total
379
344
470
International
(excluding Canada):
Land
784
719
656
Offshore
295
287
269
Total
1,079
1,006
925
Worldwide
total
3,398
3,188
3,129
Land
total
2,974
2,754
2,681
Offshore
total
424
434
448
Oil
vs. Natural Gas
2008
2007
2006
United
States (incl. Gulf of Mexico):
Oil
381
300
278
Natural Gas
1,559
1,538
1,456
Total
1,940
1,838
1,734
Canada:
Oil
160
128
110
Natural Gas
219
216
360
Total
379
344
470
International
(excluding Canada):
Oil
825
784
709
Natural Gas
254
222
216
Total
1,079
1,006
925
Worldwide
total
3,398
3,188
3,129
Oil
total
1,366
1,212
1,097
Natural
Gas total
2,032
1,976
2,032
Our
customers’ cash flows, in most instances, depend upon the revenue they generate
from the sale of oil and natural gas. Lower oil and natural gas
prices usually translate into lower exploration and production
budgets. The opposite is true for higher oil and natural gas
prices.
19
WTI oil
spot prices have fallen from a high of $145 per barrel in July to an average of
$41 per barrel in the month of December, according to the Energy Information
Administration (EIA). As of February 10, 2009, the WTI oil spot price was $37.54
per barrel. According to the International Energy Agency’s (IEA)
February 2009 “Oil Market Report,” the outlook for world petroleum demand is
expected to contract for the first time since the 1980s, with the decrease in
demand of North America and the Pacific only partially offset by the increase in
demand in Asia, the Middle East, and Latin America. The IEA forecasts
world petroleum demand in 2009 to decrease approximately 1% over 2008, but there
are other forecasts that indicate that demand contraction could be more
severe. Despite the decline in oil and gas prices and reduction in
our customers’ capital spending, we believe that, over the long-term, any major
macroeconomic disruptions may ultimately correct themselves as the underlying
trends of smaller and more complex reservoirs, high depletion rates, and the
need for continual reserve replacement should drive the long-term need for our
services.
North America
operations. Volatility in natural gas prices can impact our
customers' drilling and production activities, particularly in North
America. As we enter 2009, capital expenditure adjustments from our
customers remain fluid as they adjust their spending in response to a continued
drop in commodity price fundamentals and lack of readily available
credit. In 2009, rig counts have fallen sharply and as of February13, 2009 are approximately 34% below 2008 highs. Our customers’
capital expenditure cuts have intensified especially related to conventional and
shallower drilling activity.
As noted
in the table above, the Henry Hub spot price averaged $8.79 per mmBtu in
2008. However, as of February 11, 2009, the Henry Hub spot price had
fallen to $4.68 per mmBtu. We began to see signs of pricing weakness
in our services beginning in December of 2008 due to excess equipment and
customer requests for discounts on existing work. We expect activity
declines in United States land to accelerate in the first quarter of
2009. In addition, due to these volume declines and pricing
adjustments, we expect severe margin contraction to occur worldwide starting in
the first quarter of 2009.
Focus on international
operations. Consistent with our long-term strategy to grow our
operations outside of North America, we expect to continue to invest capital and
increase manufacturing capacity to bring new tools online to serve the need for
our services. However, operators have announced a decline in spending
in 2009, and we expect to see contraction of our business, at least in the near
term. Declining oil prices have caused customers to defer several of
their new and platform-based projects and slowdown their existing
projects. Several areas have also been affected by capital access
issues that have constrained the ability of some of our independent, upstream
customers to fund their programs. We continue to believe in the
long-term prospects of the international market and will align our business
accordingly.
20
As our
customers award work in this environment of declining commodity prices, pricing
competition in the international arena has intensified. Following is
a brief discussion of some of our recent and current initiatives:
-
minimizing
discretionary spending;
-
lowering
our costs from vendors;
-
reducing
headcount in locations experiencing significant activity
declines;
-
focusing
on working capital management and managing our balance sheet to maximize
our financial flexibility;
-
making
our research and development efforts more geographically diverse in order
to continue to supply our customers with leading-edge services and
products and to provide our customers with the ability to more efficiently
drill and complete their wells. To that end, we opened a
technology center in India in 2007 and in Singapore in the first quarter
of 2008 and a research and development laboratory in Norway in the third
quarter of 2008;
-
continuing
to deploy our packaged services strategy that creates an efficiency model
for our customers in the development of their
assets;
-
continuing
the globalization of our manufacturing and supply chain
processes. In 2007 and 2008, we opened four new regional
manufacturing facilities in Asia and Latin America. These new
centers will enable us to be more responsive to our international
customers while building regional supply networks that support local
economies;
-
as
our workforce becomes more global, the need for regional training centers
increases. As a result, we have expanded our number of regional
training centers to meet this need. We now have 12 training
centers worldwide that integrate new workers and advance the technical
skills of our workforce;
-
expanding
our business with national oil companies, including preparing for a shift
to increased use of our integrated project management services;
and
-
continuing
to pursue strategic acquisitions that enhance our technological position
and our product and service portfolio in key areas, such as the following
acquisitions in 2008:
-
in
October 2008, we acquired the assets of Pinnacle, including the Pinnacle
brand from CARBO Ceramics Inc. Pinnacle is a leading provider
of microseismic fracture mapping services and tiltmeter mapping
services;
-
in
July 2008, we acquired the remaining 49% equity interest of WellDynamics
from STV Fund. We now own 100% of WellDynamics, a provider of
intelligent well completion
technology;
-
in
June 2008, we acquired all the intellectual property and assets of Protech
Centerform in Houston, Ravenna, Italy, and Aberdeen,
Scotland. Protech Centerform is a provider of casing
centralization service;
-
in
May 2008, we acquired all intellectual property, assets, and existing
business of KSI, a leading provider of combined geopressure and
geomechanical analysis software and
services;
21
Contract wins positioning us to
grow our international operations over the long term include:
-
a
contract to manage the drilling and completion of 58 onshore wells in the
southern region of Mexico;
-
a
contract to perform workover and sidetrack services in the United
Kingdom;
-
a
contract to provide completion equipment and services, tubing conveyed
perforating services and SmartWell® completion technology for numerous oil
and natural gas fields on the Norwegian continental shelf. The
contract also allows for the provision of other products and
services;
-
a
three-year contract to provide directional drilling,
logging-while-drilling, cementing, wireline and perforating, coiled
tubing, and stimulation services in support of the offshore portion of the
Manifa mega-project in Saudi
Arabia;
-
a
three-year contract to provide a range of completion equipment for onshore
oil and gas wells in Abu Dhabi; and
-
a
three-year contract to provide special cased-hole services in support of
our work in Indonesia’s Mahakam
Delta.
22
RESULTS
OF OPERATIONS IN 2008 COMPARED TO 2007
REVENUE:
Percentage
Millions
of dollars
2008
2007
Increase
Change
Completion
and Production
$
9,935
$
8,386
$
1,549
18
%
Drilling
and Evaluation
8,344
6,878
1,466
21
Total
revenue
$
18,279
$
15,264
$
3,015
20
%
By
geographic region:
Completion
and Production:
North America
$
5,348
$
4,655
$
693
15
%
Latin America
1,084
756
328
43
Europe/Africa/CIS
2,065
1,767
298
17
Middle
East/Asia
1,438
1,208
230
19
Total
9,935
8,386
1,549
18
Drilling
and Evaluation:
North America
2,992
2,478
514
21
Latin America
1,341
1,042
299
29
Europe/Africa/CIS
2,281
1,933
348
18
Middle
East/Asia
1,730
1,425
305
21
Total
8,344
6,878
1,466
21
Total
revenue by region:
North America
8,340
7,133
1,207
17
Latin America
2,425
1,798
627
35
Europe/Africa/CIS
4,346
3,700
646
17
Middle
East/Asia
3,168
2,633
535
20
23
OPERATING
INCOME:
Increase
Percentage
Millions
of dollars
2008
2007
(Decrease)
Change
Completion
and Production
$
2,409
$
2,199
$
210
10
%
Drilling
and Evaluation
1,865
1,485
380
26
Corporate
and other
(264
)
(186
)
(78
)
(42
)
Total
operating income
$
4,010
$
3,498
$
512
15
%
By
geographic region:
Completion
and Production:
North America
$
1,404
$
1,404
$
—
—
%
Latin America
260
170
90
53
Europe/Africa/CIS
409
330
79
24
Middle
East/Asia
336
295
41
14
Total
2,409
2,199
210
10
Drilling
and Evaluation:
North America
701
552
149
27
Latin America
261
179
82
46
Europe/Africa/CIS
448
414
34
8
Middle
East/Asia
455
340
115
34
Total
1,865
1,485
380
26
Total
operating income by region
(excluding Corporate and
other):
North America
2,105
1,956
149
8
Latin America
521
349
172
49
Europe/Africa/CIS
857
744
113
15
Middle
East/Asia
791
635
156
25
The
increase in consolidated revenue in 2008 compared to 2007 spanned all four
regions and was attributable to higher worldwide activity, particularly in North
America, Asia, and Latin America. Approximately $74 million in
revenue was lost during 2008 due to Gulf of Mexico
hurricanes. International revenue was 57% of consolidated revenue in
2008 and 56% of consolidated revenue in 2007.
The
increase in consolidated operating income in 2008 compared to 2007 was primarily
due to a 49% increase in Latin America and a 25% increase in Middle East/Asia
resulting from increased customer activity, new contracts, and improved
pricing. Operating income in 2008 was positively impacted by a $35
million gain on the sale of a joint venture interest in the United States, a
combined $25 million gain related to the sale of two investments in the United
States, and a net $5 million gain on the settlement of two patent
disputes. Operating income in 2008 was adversely impacted by $52
million due to Gulf of Mexico hurricanes, a $23 million impairment charge
related to an oil and gas property in Bangladesh, and a $22 million
acquisition-related charge for WellDynamics related to employee incentive
compensation awards. Operating income in 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 in Bangladesh and $32 million in charges for
environmental reserves.
24
Following
is a discussion of our results of operations by reportable
segments.
Completion and Production
increase in revenue compared to 2007 was derived from all
regions. Europe/Africa/CIS revenue grew 17% primarily from increased
production enhancement services activity, largely related to the acquisition of
PSL Energy Services Limited. Additionally, completion tools revenue
benefited from increased sales and service in Africa. Middle
East/Asia revenue grew 19% from increased completion tools sales and deliveries
and new contracts for production enhancement services in the
region. Increased demand for cementing products and services in the
Middle East and Australia also contributed to the increase. North
America revenue grew 15% from improved demand for production enhancement
services and cementing products and services largely driven by increased
capacity and rig count in the United States. Partially offsetting the
improvement in the United States was $34 million in lost revenue due to Gulf of
Mexico hurricanes. Latin America revenue grew 43% as a result of
higher activity for all product service lines, particularly in Mexico and
Brazil. Higher demand for production enhancement services, new
cementing contracts with more favorable pricing, and improved completion tools
sales were large contributors to the increase in
revenue. International revenue was 49% of total segment revenue in
2008 and 47% in 2007.
The
increase in segment operating income in 2008 compared to 2007 spanned all
regions except North America. Europe/Africa/CIS operating income
increased 24% from increased completion tools sales and services in Africa and
higher production enhancement activity in Europe. Middle East/Asia
operating income increased 14% primarily due to increased sales and service
revenue from completion tools and increased production enhancement activity in
the region. North America operating income was flat primarily due to
a $25 million negative impact from Gulf of Mexico hurricanes and pricing
declines and cost increases in the United States for production enhancement,
offset by improved completion tools sales and services and a $35 million gain on
the sale of a joint venture interest in the United States. Latin
America operating income increased 53% with improved cementing and production
enhancement performance primarily in Mexico and Brazil.
Drilling and Evaluation
revenue increase compared to 2007 was derived from all
regions. Europe/Africa/CIS revenue grew 18% from increased drilling
services activity and higher customer demand for fluid and wireline and
perforating services throughout the region. Middle East/Asia revenue
grew 21% primarily due to increased fluid services activity throughout the
region and higher customer demand for drilling services in
Asia. North America revenue grew 21% from higher activity across all
product service lines in the United States primarily due to increased land rig
count and higher demand for new technology. The region also benefited
from higher activity for fluid services in Canada. Partially
offsetting the improvement in the United States was $40 million in lost revenue
due to Gulf of Mexico hurricanes. Latin America revenue grew 29% as a
result of increased customer demand for drilling services, increased activity
and new contracts for wireline and perforating services, and increased project
management services. International revenue was 68% of total segment
revenue in both 2008 and 2007.
25
The
increase in segment operating income in 2008 compared to 2007 was derived from
all regions led by growth in North America, Latin America and
Asia. Europe/Africa/CIS operating income increased 8% benefiting from
higher customer demand for wireline and perforating services in
Africa. Higher demand for software sales and consulting services in
Europe also contributed to the increase. Middle East/Asia operating
income grew 34% primarily due to increased fluid services results in the Middle
East as well as higher demand for drilling services and improved wireline and
perforating services and software sales and consulting services in
Asia. Operating income was impacted by a $23 million impairment
charge related to an oil and gas property in Bangladesh. North
America operating income increased 27% primarily from increased activity in most
of the product service lines including higher demand for fluid services and
increased drilling activity. Negatively impacting the region was a
loss of $27 million due to Gulf of Mexico hurricanes. This region’s
results also reflect $25 million of gains related to the sale of two investments
in the United States. Latin America operating income increased 46%
primarily due to increased activity in drilling services and wireline and
perforating services and improvements in software sales and consulting
services.
Corporate and other expenses
were $264 million in 2008 compared to $186 million in 2007. 2008
included a $35 million gain in the fourth quarter and a $30 million charge in
the second quarter related to patent dispute settlements, a $22 million
acquisition-related charge for WellDynamics related to employee incentive
compensation awards, higher legal costs, and increased corporate development
costs. 2007 was impacted by a $49 million gain on the sale of our
remaining interest in Dresser, Ltd. and a $12 million charge for executive
separation costs.
NONOPERATING
ITEMS
Interest income decreased $85
million in 2008 compared to 2007 due to a decrease of cash and equivalents and
marketable securities balances and a general decline in market interest
rates.
Other, net in 2008 included the loss of
$693 million for the portion of the premium paid in cash on the settlement of
our convertible senior notes in the third quarter and a $31 million loss on
foreign exchange.
Provision for income taxes
from continuing operations of $1.2 billion in 2008 resulted in an effective tax
rate of 38% compared to an effective tax rate of 26% in 2007. The
increase in the effective tax rate from 2007 to 2008 is primarily related to the
non-tax deductibility of the $693 million loss on the portion of the premium on
our convertible debt that we settled in cash. The provision for
income taxes in 2007 included a $205 million favorable income tax impact from
the ability to recognize foreign tax credits previously estimated not to be
fully utilizable.
Minority interest in net income of
subsidiaries decreased $38 million compared to 2007, primarily related to
a change in effective ownership of a joint venture in 2008.
Income (loss) from discontinued
operations, net of income tax in 2008 included $420 million in charges
reflecting the resolution of the DOJ and SEC FCPA investigations and the impact
of our most recent assumptions regarding the resolution of the
Barracuda-Caratinga bolt arbitration matter under the indemnities and guarantees
provided to KBR upon separation. 2007 included a $933 million net
gain on the disposition of KBR, which included the estimated fair value of the
indemnities and guarantees provided to KBR and our 81% share of KBR’s $28
million in net income in the first quarter of 2007.
26
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
27
OPERATING
INCOME:
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
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 in Bangladesh
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.
28
Following
is a discussion of our results of operations by reportable segment.
Completion and Production
increase in revenue compared to 2006 was derived from all
regions. Europe/Africa/CIS revenue grew 23% on increased activity
from production enhancement services in Europe and Africa. The region
also benefited from increased activity in our intelligent well completions sales
and increased 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 production enhancement activity in Mexico, and
increased completion product sales and services 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.
29
NONOPERATING
ITEMS
Interest expense decreased
$11 million in 2007 compared to 2006, primarily due to the repayment in August
2006 of $275 million of our medium-term notes.
Interest income decreased $5
million in 2007 compared to 2006 due to lower average cash
balances.
Provision 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 estimated not to be fully utilizable.
Minority interest in net income of
subsidiaries increased $10 million compared to 2006, primarily related to
our joint venture in Saudi Arabia.
Income (loss) from discontinued
operations, net of income tax in 2007 included a $933 million net gain on
the disposition of KBR, which included the estimated fair value of the
indemnities and guarantees provided to KBR and our 81% share of KBR’s $28
million in net income in the first quarter of 2007.
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 estimates to be:
-
forecasting
our effective income 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;
-
valuations
of long-lived assets, including intangible
assets;
-
purchase
price allocation for acquired
businesses;
-
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.
30
Income
tax accounting
We
account for income taxes in accordance with Statement of Financial Accounting
Standards (SFAS) No. 109, “Accounting for Income Taxes,” which requires
recognition of the amount of taxes payable or refundable for the current year
and an asset and liability approach in recognizing the amount of deferred tax
liabilities and assets for the future tax consequences of events that have been
recognized in our financial statements or tax returns. We apply the
following basic principles in accounting for our income taxes:
-
a
current tax liability or asset is recognized for the estimated taxes
payable or refundable on tax returns for the current
year;
-
a
deferred tax liability or asset is recognized for the estimated future tax
effects attributable to temporary differences and
carryforwards;
-
the
measurement of current and deferred tax liabilities and assets is based on
provisions of the enacted tax law, and the effects of potential future
changes in tax laws or rates are not considered;
and
-
the
value of deferred tax assets is reduced, if necessary, by the amount of
any tax benefits that, based on available evidence, are not expected to be
realized.
We
determine deferred taxes separately for each tax-paying component (an entity or
a group of entities that is consolidated for tax purposes) in each tax
jurisdiction. That determination includes the following
procedures:
-
identifying
the types and amounts of existing temporary
differences;
-
measuring
the total deferred tax liability for taxable temporary differences using
the applicable tax rate;
-
measuring
the total deferred tax asset for deductible temporary differences and
operating loss carryforwards using the applicable tax
rate;
-
measuring
the deferred tax assets for each type of tax credit carryforward;
and
-
reducing
the deferred tax assets by a valuation allowance if, based on available
evidence, it is more likely than not that some portion or all of the
deferred tax assets will not be
realized.
Our
methodology for recording income taxes requires a significant amount of judgment
in the use of assumptions and estimates. Additionally, we use
forecasts of certain tax elements, such as taxable income and foreign tax credit
utilization, as well as evaluate the feasibility of implementing tax planning
strategies. Given the inherent uncertainty involved with the use of
such variables, there can be significant variation between anticipated and
actual results. Unforeseen events may significantly impact these
variables, and changes to these variables could have a material impact on our
income tax accounts related to both continuing and discontinued
operations.
We have
operations in approximately 70 countries other than the United
States. Consequently, we are subject to the jurisdiction of a
significant number of taxing authorities. The income earned in these
various jurisdictions is taxed on differing bases, including income actually
earned, income deemed earned, and revenue-based tax withholding. The
final determination of our income 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 income tax liabilities for a tax year.
31
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 FASB Interpretation No. (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 (FSP) 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 income taxes and future
taxable income. Factors such as actual operating results, material
acquisitions or dispositions, and changes to our operating environment could
alter the estimates, which could have a material impact on the valuation
allowance. Given that we fully utilized the United States net
operating loss and began utilizing foreign tax credits in the United States in
2006, the valuation allowance balance has been reduced to zero as of the end of
2007. In addition, the provision for income taxes in 2007 included a
favorable income tax adjustment from the ability to recognize foreign tax
credits previously generated in 2005 and 2006 thought not to be fully
utilizable. We now believe we can utilize these credits currently,
because we have generated additional taxable income and expect to continue to
generate a higher level of taxable income largely from the growth of our
international operations.
Percentage
of completion
Revenue
from certain long-term integrated, project management 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.
32
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. Currently, long-term contracts accounted for under the
percentage-of-completion method of accounting do not comprise a significant
portion of our business. However, in the future, we expect our
business with national or state-owned oil companies to grow relative to our
other business, with these types of contracts likely comprising a more
significant portion of our business. See Note 1 to the consolidated
financial statements for further information.
Legal
and investigation matters
As
discussed in Note 10 of our consolidated financial statements, as of December31, 2008, we have accrued an estimate of the probable and estimable costs for
the resolution of some of these legal and investigation matters. For
other matters for which the liability is not probable and reasonably estimable,
we have not accrued any amounts. Attorneys in our legal department
monitor and manage all claims filed against us and review all pending
investigations. Generally, the estimate of probable costs related to
these matters is developed in consultation with internal and outside legal
counsel representing us. Our estimates are based upon an analysis of
potential results, assuming a combination of litigation and settlement
strategies. The precision of these estimates is impacted by the
amount of due diligence we have been able to perform. We attempt to
resolve these matters through settlements, mediation, and arbitration
proceedings when possible. If the actual settlement costs, final
judgments, or fines, after appeals, differ from our estimates, our future
financial results may be adversely affected. We have in the past
recorded significant adjustments to our initial estimates of these types of
contingencies.
Indemnity
valuations
We
provided indemnification in favor of KBR for certain contingent liabilities
related to FCPA investigations and the Barracuda-Caratinga bolts
matter. See Note 10 to the consolidated financial statements for
further information. 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 initial 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. FSP FIN
45-2, “Whether FASB Interpretation No. 45, ‘Guarantor’s Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others’,
Provides Support for Subsequently Accounting for a Guarantor’s Liability
at Fair Value,” states that the subsequent measurement of FIN 45 liabilities
should not necessarily be based on fair value. The FSP references
SFAS No. 5, “Accounting for Contingencies” for subsequent adjustments related to
contingent liabilities. As such, subsequent adjustments to the
indemnities provided to KBR upon separation, including the
indemnity relating to the FCPA investigations, have been recorded when the
loss is both probable and estimable under SFAS No. 5.
33
Value
of long-lived assets, including intangible assets
We carry
a variety of long-lived assets on our balance sheet including property, plant
and equipment, intangible assets, and goodwill. We conduct impairment
tests on long-lived assets whenever events or changes in circumstances indicate
that the carrying value may not be recoverable and intangible assets quarterly
in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of
Long-Lived Assets.” Impairment is the condition that exists when the
carrying amount of a long-lived asset exceeds its fair value, and any impairment
charge that we record reduces our earnings. We review the carrying
value of these assets based upon estimated future cash flows while taking into
consideration assumptions and estimates including the future use of the asset,
remaining useful life of the asset, and service potential of the
asset.
Goodwill
is the excess of the cost of an acquired entity over the net of the amounts
assigned to assets acquired and liabilities assumed. We test goodwill
for impairment annually, during the third quarter, or if an event occurs or
circumstances change that would more likely than not reduce the fair value of a
reporting unit below its carrying amount in accordance with SFAS No. 142,
“Goodwill and Other Intangible Assets.” For purposes of performing
the goodwill impairment test our reporting units are the same as our reportable
segments, the Completion and Production division and the Drilling and Evaluation
division. The impairment test consists of a two-step
process. The first step compares the fair value of a reporting unit
with its carrying amount, including goodwill, and utilizes a future cash flow
analysis based on the estimates and assumptions of our forecasted long-term
growth model. If the fair value of a reporting unit exceeds its
carrying amount, goodwill of the reporting unit is considered not
impaired. If the carrying amount of a reporting unit exceeds its fair
value, we perform the second step of the goodwill impairment test to measure the
amount of the impairment loss, if any. The second step of the
goodwill impairment test compares the implied fair value of the reporting unit’s
goodwill with the carrying amount of that goodwill. The implied fair
value of goodwill is determined in the same manner as the amount of goodwill
recognized in a business combination. In other words, the estimated
fair value of the reporting unit is allocated to all of the assets and
liabilities of that unit (including any unrecognized intangible assets) as if
the reporting unit had been acquired in a business combination and the fair
value of the reporting unit was the purchase price paid. If the
carrying amount of the reporting unit’s goodwill exceeds the implied fair value
of that goodwill, an impairment loss is recognized in an amount equal to that
excess. Any impairment charge that we record reduces our
earnings. The fair value of each of our reporting units exceeded its
carrying amount by a significant margin for 2008, 2007, and 2006. See
Note 1 to the consolidated financial statements for accounting policies related
to long-lived assets and intangible assets.
Acquisitions-purchase
price allocation
We
allocate the purchase price of an acquired business to its identifiable assets
and liabilities based on estimated fair values. The excess of the
purchase price over the amount allocated to the assets and liabilities, if any,
is recorded as goodwill. We use all available information to estimate
fair values including quoted market prices, the carrying value of acquired
assets, and widely accepted valuation techniques such as discounted cash
flows. We engage third-party appraisal firms to assist in fair value
determination of inventory, identifiable intangible assets, and any other
significant assets or liabilities when appropriate. We adjust the
preliminary purchase price allocation, as necessary, as we obtain more
information regarding asset valuations and liabilities assumed until the
expiration of the measurement period. The judgments made in determining the
estimated fair value assigned to each class of assets acquired and liabilities
assumed, as well as asset lives, can materially impact our results of
operations. See Note 3 to the consolidated financial statements for
further information regarding acquisitions.
34
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 benefit obligations
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. Considering the
recent financial markets downturn, we elected to modify our methodology for
selecting discount rates at December 31, 2008 for our United States pension and
postretirement plans. This resulted in a lower discount rate and
yielded a higher projected benefit obligation than if we had used our previous
methodology. Expected long-term rates of return on plan assets are
determined annually and are based on an evaluation of our plan assets and
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 rates utilized in 2008 to determine the projected benefit obligation at
the measurement date for our qualified United States non-terminating pension
plans ranged from 5.72% to 5.77%, a decrease from the range of 6.03% to 6.19%
that was utilized in 2007. The discount rate utilized in 2008 to
determine the projected benefit obligation at the measurement date for our
United Kingdom pension plan, which constitutes 73% of our international plans
and 63% of all plans, was 5.75% compared to a discount rate of 5.70% utilized in
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 2008, $48
million in 2007, and $45 million in 2006. Included in the amounts
were earnings from our expected pension returns of $51 million in 2008, $47
million in 2007, and $37 million in 2006. Unrecognized actuarial
gains and losses are being recognized over a period of five to 24 years, which
represents 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 losses on plan assets were $144 million in 2008,
compared to actual returns on plan assets of $68 million in 2007 and $65 million
in 2006. The decline in value of plan assets in 2008 was largely due
to significant deterioration in the financial markets and broadening market
decline in the fourth quarter of 2008. 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, 2008 was
$198 million. An estimated $4 million, net of tax, of our net
actuarial loss at December 31, 2008 will be recognized as a component of our
expected 2009 pension expense. During 2008, we made contributions to
fund our defined benefit plans of $52 million, which included $18 million
contributed to our United Kingdom plan. We expect to make additional
contributions in 2009 of approximately $48 million.
The
actuarial assumptions used in determining our pension benefit obligations 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. See Note 15 to the consolidated financial statements for
further information related to defined benefit and other postretirement benefit
plans.
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
5.0%. At December 31, 2008, allowance for bad debts totaled $60
million or 1.6% of notes and accounts receivable before the allowance, and at
December 31, 2007, allowance for bad debts totaled $49 million or 1.6% 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, 2008 would have resulted in a $37 million adjustment to 2008
total operating costs and expenses.
OFF
BALANCE SHEET ARRANGEMENTS
At
December 31, 2008, we had no material off balance sheet arrangements, except for
operating leases. For information on our contractual obligations
related to operating leases, see “Management’s Discussion and Analysis of
Financial Condition and Results of Operations – Liquidity and Capital Resources
– Future uses of cash.”
36
FINANCIAL
INSTRUMENT MARKET RISK
We are
exposed to financial instrument market risk from changes in foreign currency
exchange rates, interest rates, and, to a limited extent, commodity
prices. From time to time, we may selectively manage these exposures
through the use of derivative instruments to mitigate our market risk from these
exposures. The objective of our risk management program is to protect
our cash flows related to sales or purchases of goods or services from market
fluctuations in currency rates. We do not use derivative instruments
for trading purposes. Our use of derivative instruments includes the
following types of market risk:
-
volatility
of the currency rates;
-
time
horizon of the derivative
instruments;
-
market
cycles; and
-
the
type of derivative instruments
used.
We do not
consider any of these risk management activities to be material. See
Note 1 to the consolidated financial statements for additional information on
our accounting policies related to derivative instruments. See Note
14 to the consolidated financial statements for additional disclosures related
to financial instruments.
Interest
rate risk
We
currently have no variable-rate, long-term debt that exposes us to interest rate
risk.
The
following table represents principal amounts of our long-term debt at December31, 2008 and related weighted average interest rates on the repayment amounts by
year of maturity for our long-term debt.
Millions
of dollars
2009
2010
2011
2012
2013
Thereafter
Total
Repayment amount
($US)
$
26
$
750
$
-
$
-
$
-
$
1,839
$
2,615
Weighted
average
interest rate
on
repayment
amount
5.5
%
5.5
%
-
-
-
6.9
%
6.5
%
The fair
market value of long-term debt was $2.8 billion as of December 31,2008.
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.
37
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
$64 million as of December 31, 2008 and $72 million as of December 31,2007. Our total liability related to environmental matters covers
numerous properties.
We have
subsidiaries that have been named as potentially responsible parties along with
other third parties for 8 federal and state superfund sites for which we have
established a liability. As of December 31, 2008, those 8 sites
accounted for approximately $10 million of our total $64 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
In
December 2008, the FASB issued FSP SFAS 132(R)-1 “Employers’ Disclosures about
Postretirement Benefit Plan Assets.” This FSP amends the disclosure
requirements for employer’s disclosure of plan assets for defined benefit
pensions and other postretirement plans. The objective of this FSP is to
provide users of financial statements with an understanding of how investment
allocation decisions are made, the major categories of plan assets held by the
plans, the inputs and valuation techniques used to measure the fair value of
plan assets, significant concentration of risk within the company’s plan assets,
and for fair value measurements determined using significant unobservable inputs
a reconciliation of changes between the beginning and ending balances. FSP SFAS
132(R)-1 is effective for fiscal years ending after December 15, 2009. We
will adopt the new disclosure requirements in the 2009 annual reporting
period.
38
In June
2008, the FASB issued FSP Emerging Issues Task Force (EITF) 03-6-1, “Determining
Whether Instruments Granted in Share-Based Payment Transactions Are
Participating Securities.” This FSP provides that unvested share-based
payment awards that contain nonforfeitable rights to dividends or dividend
equivalents, whether paid or unpaid, are participating securities and shall be
included in the computation of both basic and diluted earnings per share.
This EITF is effective for financial statements issued for fiscal years
beginning after December 15, 2008 and interim periods within those fiscal
years. We will adopt the provisions of FSP EITF 03-6-1 on January 1,2009, which will require us to recast prior periods’ basic and diluted earnings
per share to include outstanding unvested restricted common shares in the
weighted average shares outstanding calculation. We estimate that, had we
calculated earnings per share under these new provisions during 2008, basic
income per share would have decreased by approximately $0.02 for continuing
operations and approximately $0.01 for net income and diluted income per share
would have decreased by approximately $0.01 for both continuing operations and
net income per share.
In May
2008, the FASB issued FSP Accounting Principles Board (APB) 14-1, “Accounting
for Convertible Debt Instruments That May Be Settled in Cash upon Conversion
(Including Partial Cash Settlement).” This FSP clarifies that
convertible debt instruments that may be settled in cash upon conversion,
including partial cash settlement, should separately account for the liability
and equity components in a manner that will reflect the entity’s nonconvertible
debt borrowing rate when interest cost is recognized in subsequent
periods. This FSP is effective for financial statements issued for
fiscal years beginning after December 15, 2008 and interim periods within those
fiscal years. We will adopt the provisions of FSP APB 14-1 on January1, 2009 and will be required to retroactively apply its provisions, which means
we will restate our consolidated financial statements for prior
periods.
In
applying this FSP, we estimate approximately $60 million of the carrying value
of the convertible notes to be reclassified to equity as of the July 2003
issuance date. This amount represents the equity component of the
proceeds from the notes, calculated assuming a 4.3% non-convertible borrowing
rate. The discount will be accreted to interest expense over the
five-year term of the notes. Accordingly, approximately $13 million
of additional non-cash interest expense, or $0.01 per diluted share, will be
recorded in 2006 and 2007 and approximately $7 million of additional non-cash
interest expense will be recorded in 2008. Furthermore, under this
FSP, the $693 million loss to settle our convertible debt in the third quarter
of 2008 will be reversed and recorded to additional paid-in
capital. We estimate that diluted income per share for 2008 will
increase by approximately $0.76.
In
December 2007, the FASB issued SFAS No. 141(Revised 2007), “Business
Combinations” (SFAS No. 141(R)). SFAS No. 141(R) retains the
underlying concepts of SFAS No. 141 in that all business combinations are still
required to be accounted for at fair value under the acquisition method of
accounting, but SFAS No. 141(R) changes the method of applying the acquisition
method in a number of ways. Acquisition costs will generally be expensed as
incurred, noncontrolling interests (minority interests) will be valued at fair
value at the acquisition date, in-process research and development will be
recorded at fair value as an indefinite-lived intangible asset at the
acquisition date, restructuring costs associated with a business combination
will generally be expensed subsequent to the acquisition date, and changes in
deferred tax asset valuation allowances and income tax uncertainties after the
acquisition date generally will affect income tax expense. 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.
39
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, reporting, and disclosure 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 provisions
of SFAS No. 160 on January 1, 2009 and, beginning with our 2009 interim
reporting periods and for prior comparative periods, we will present
noncontrolling interest (minority interest) as a separate component of
shareholders’ equity.
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
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 February 2008, the FASB issued FSP SFAS 157-1, “Application
of FASB Statement No. 157 to FASB Statement No. 13 and Other
Accounting Pronouncements That Address Fair Value Measurements for Purposes of
Lease Classification or Measurement under Statement 13,” which removes certain
leasing transactions from the scope of SFAS No. 157, and FSP SFAS 157-2,
“Effective Date of FASB Statement No. 157,” which defers the effective date
of SFAS No. 157 for one year for certain nonfinancial assets and
nonfinancial liabilities, except those that are recognized or disclosed at fair
value in the financial statements on a recurring basis. In October
2008, the FASB also issued FSP SFAS 157-3, “Determining the Fair Value of a
Financial Asset When the Market for That Asset Is Not Active,” which clarifies
the application of SFAS No. 157 in an inactive market and illustrates how an
entity would determine fair value when the market for a financial asset is not
active. 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 nonfinancial
liabilities that are not required or permitted to be measured at fair value on a
recurring basis, which include those measured at fair value in goodwill
impairment testing, indefinite-lived intangible assets measured at fair value
for impairment assessment, nonfinancial long-lived assets measured at fair value
for impairment assessment, asset retirement obligations initially measured at
fair value, and those initially measured at fair value in a business
combination. We do not expect the provisions of SFAS No. 157 related
to these items to have a material impact on our consolidated financial
statements.
40
FORWARD-LOOKING
INFORMATION
The
Private Securities Litigation Reform Act of 1995 provides safe harbor provisions
for forward-looking information. Forward-looking information is based
on projections and estimates, not historical information. Some
statements in this Form 10-K are forward-looking and use words like “may,”“may
not,”“believes,”“do not believe,”“expects,”“do not expect,”“anticipates,”“do not anticipate,” and other expressions. We may also provide oral
or written forward-looking information in other materials we release to the
public. Forward-looking information involves risk and uncertainties
and reflects our best judgment based on current information. Our
results of operations can be affected by inaccurate assumptions we make or by
known or unknown risks and uncertainties. In addition, other factors
may affect the accuracy of our forward-looking information. As a
result, no forward-looking information can be guaranteed. Actual
events and the results of operations may vary materially.
We do not
assume any responsibility to publicly update any of our forward-looking
statements regardless of whether factors change as a result of new information,
future events, or for any other reason. You should review any
additional disclosures we make in our press releases and Forms 10-K, 10-Q, and
8-K filed with or furnished to the SEC. We also suggest that you
listen to our quarterly earnings release conference calls with financial
analysts.
While it
is not possible to identify all factors, we continue to face many risks and
uncertainties that could cause actual results to differ from our forward-looking
statements and potentially materially and adversely affect our financial
condition and results of operations.
RISK
FACTORS
Foreign
Corrupt Practices Act Investigations
In
February 2009, the FCPA investigations by the DOJ and the SEC were resolved. The
DOJ and SEC investigations resulted from allegations of improper payments to
government officials in Nigeria 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.
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).
In
addition to the DOJ and the SEC investigations, we are aware of other
investigations in France, Nigeria, Great Britain, and Switzerland regarding the
Bonny Island project.
41
We
provided indemnification in favor of KBR under the master separation agreement
for certain contingent liabilities, including our 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 the Bonny
Island project.
With
respect to the DOJ, in February 2009, a subsidiary of KBR, Inc. pleaded guilty
to conspiring to violate the FCPA and to substantive violations of the
anti-bribery provisions of the FCPA in connection with the Bonny Island project.
The DOJ investigation was resolved with respect to us with a non-prosecution
agreement in which the DOJ agreed not to bring FCPA or bid coordination-related
charges against us with respect to the matters under investigation, and in which
we agreed to continue to cooperate with the DOJ’s ongoing investigation and to
refrain from and self-report certain FCPA violations. The DOJ agreement does not
provide for a monitor for us.
As a
result of our indemnity in favor of KBR under the master separation agreement
with KBR and the KBR subsidiary’s criminal plea, we have paid $49 million and
will pay an additional $333 million in seven installments over the next seven
quarters of the $402 million criminal fine payable by KBR as part of the
resolution of the DOJ investigation, with KBR consenting to pay the remaining
$20 million.
With
respect to the SEC, without admitting or denying the allegations in an SEC
complaint, we consented to the entry of a final judgment that permanently
enjoins us from violating the record-keeping and internal control provisions of
the FCPA. KBR also entered into a related settlement with the SEC. As
part of our settlement with the SEC, we agreed to be jointly and severally
liable with KBR for, and will pay the SEC, $177 million in disgorgement in the
first quarter of 2009.
In
addition, as part of the resolution of the SEC investigation, we will retain an
independent consultant to conduct a 60-day review and evaluation of our internal
controls and record-keeping policies as they relate to the FCPA, and we will
adopt any necessary anti-bribery and foreign agent internal controls and
record-keeping procedures recommended by or agreed upon with the independent
consultant. In 2010, the independent consultant will perform a 30-day follow-up
review to confirm that we have implemented the recommendations and continued the
application of our current policies and procedures.
The
settlements and the other ongoing investigations could 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.
KBR has
agreed that Halliburton’s indemnification obligations with respect to the DOJ
and SEC FCPA investigations have been fully satisfied. Our indemnity
of KBR continues with respect to other investigations within the scope of our
indemnity.
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.
42
To
reflect the resolution of the DOJ and SEC FCPA investigations and to reflect
other adjustments to the indemnities and guarantees provided to KBR upon
separation, we recorded $420 million, net of tax, in 2008 as a loss from
discontinued operations. We did not record a tax benefit related to
the resolution of the DOJ and SEC FCPA investigations. As of December31, 2008 and December 31, 2007, $559 million and $142 million are recorded
related to our obligations regarding DOJ and SEC FCPA matters in our
consolidated balance sheets in “Department of Justice and Securities and
Exchange Commission settlement and indemnity, current” and “Other
liabilities.” See Note 2 to the consolidated financial statements for
additional information.
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, 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. Our estimation of the indemnity obligation
regarding the Barracuda-Caratinga arbitration is recorded as a liability in our
consolidated financial statements as of December 31, 2008 and December 31,2007. 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 $148 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 held an evidentiary hearing during the
week of March 31, 2008 and took evidence and arguments under
advisement.
43
Impairment
of Oil and Gas Properties
At
December 31, 2008, we had interests in oil and gas properties totaling $105
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.
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 an 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
57% of our consolidated revenue during 2008 and 56% and 55% of our consolidated
revenue during 2007 and 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:
-
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.
44
Our
operations outside the United States require us to comply with a number of
United States and international regulations. For example, our
operations in countries outside the United States are subject to the FCPA, which
prohibits United States companies or their agents and employees from providing
anything of value to a foreign official for the purposes of influencing any act
or decision of these individuals in their official capacity to help obtain or
retain business, direct business to any person or corporate entity or obtain any
unfair advantage. Our activities in countries outside the United
States create the risk of unauthorized payments or offers of payments by one of
our employees or agents that could be in violation of the FCPA, even though
these parties are not always subject to our control. We have internal control
policies and procedures and have implemented training and compliance programs
for our employees and agents with respect to the FCPA. However, we
cannot assure you that our policies, procedures and programs always will protect
us from reckless or criminal acts committed by our employees or agents. In the
event that we believe or have reason to believe that our employees or agents
have or may have violated applicable anti-corruption laws, including the FCPA,
we may be required to investigate or have outside counsel investigate the
relevant facts and circumstances. Violations of the FCPA may result
in severe criminal or civil sanctions, and we may be subject to other
liabilities, which could negatively affect our business, operating results and
financial condition.
In
addition, investigations by governmental authorities as well as legal, social,
economic, and political issues in these countries could materially and adversely
affect our 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 and the Middle East, 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 income 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 income tax liabilities for a tax year.
45
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
Worldwide
recession and effect on exploration and production activity
The
recent worldwide financial and credit crisis has reduced the availability of
liquidity and credit to fund the continuation and expansion of industrial
business operations worldwide. The shortage of liquidity and credit
combined with recent substantial losses in worldwide equity markets have led to
a worldwide economic recession that could continue for an extended period of
time. The slowdown in economic activity caused by the recession has
reduced worldwide demand for energy and resulted in lower oil and natural gas
prices. This reduction in demand could continue through 2009 and
beyond. Crude oil prices declined from record levels in July 2008 of
approximately $145 per barrel to levels as low as $30 per barrel toward the end
of 2008. As of February 10, 2009, crude oil prices were $37.54 per
barrel. Natural gas spot prices peaked at approximately $13.00 per
mmBtu in 2008 and then fell to an average of $5.83 per mmBtu toward the end of
2008. As of February 11, 2009, natural gas spot prices had fallen
even further to $4.68 per mmBtu. 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. Any
prolonged reduction in oil and natural gas prices will depress the immediate
levels of exploration, development, and production activity. Perceptions
of longer-term lower oil and natural gas prices by oil and gas companies can
similarly reduce or defer major expenditures given the long-term nature of many
large-scale development projects. Lower levels of activity result in a
corresponding decline in the demand for our oil and natural gas well services
and products, which could have a material adverse effect on our revenue and
profitability.
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.
46
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. The current low prices for oil and natural
gas have depressed the current levels of exploration, development, and
production activity, resulting in a corresponding decline in the demand for our
oil and natural gas well services and products. 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;
-
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 supply and demand for oil and natural gas, especially demand for
natural gas in the United States.
Historically,
the markets for oil and gas have been volatile and are likely to continue to be
volatile. Spending on exploration and production activities by large
oil and gas companies has a significant impact on the activity levels of our
businesses.
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.
In most cases, we bill our customers for our services in arrears and
are, therefore, subject to our customers delaying or failing to pay our
invoices. In weak economic environments, we may experience increased
delays and failures due to, among other reasons, a reduction in our customer’s
cash flow from operations and their access to the credit markets. If our
customers delay in paying or fail to pay us a significant amount of our
outstanding receivables, it could have a material adverse effect on our
liquidity, consolidated results of operations, and consolidated financial
condition.
In
addition, there is an increased risk in doing business with customers in
countries that have significant political risk or significant exposure to
falling oil and natural gas prices, such as Venezuela.
47
Business
with national oil companies
Much of
the world’s oil and gas reserves are controlled by national or state-owned oil
companies (NOCs). Several of the NOCs are among our top 20
customers. Increasingly, NOCs are turning to oilfield services companies
like us to provide the services, technologies, and expertise needed to develop
their reserves. Reserve estimation is a subjective process that involves
estimating location and volumes based on a variety of assumptions and variables
that cannot be directly measured. As such, the NOCs may provide us with
inaccurate information in relation to their reserves that may result in cost
overruns, delays, and project losses. In addition, NOCs often operate in
countries with unsettled political conditions, war, civil unrest, or other types
of community issues. These types of issues may also result in similar cost
overruns, losses, and contract delays.
NOCs
often require integrated, long-term, fixed-price contracts that could require us
to provide integrated project management services outside our normal discrete
business to act as project managers as well as service
providers. Providing services on an integrated basis may require us
to assume additional risks associated with cost over-runs, operating cost
inflation, labor availability and productivity, supplier and contractor pricing
and performance, and potential claims for liquidated damages. For example,
we generally rely on third-party subcontractors and equipment providers to
assist us with the completion of our contracts. To the extent that we
cannot engage subcontractors or acquire equipment or materials, our ability to
complete a project in a timely fashion or at a profit may be impaired. If
the amount we are required to pay for these goods and services exceeds the
amount we have estimated in bidding for fixed-price work, we could experience
losses in the performance of these contracts. These delays and additional
costs may be substantial, and we may be required to compensate the NOCs for
these delays. This may reduce the profit to be realized or result in a
loss on a project. Currently, contracts with NOCs do not comprise a
significant portion of our business. However, in the future, based on
the anticipated growth of NOCs, we expect our business with NOCs to grow
relative to our other business, with these types of contracts likely comprising
a more significant portion of our business.
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;
-
use
of cash for acquisitions would not adversely affect our cash available for
capital expenditures and other
uses;
-
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.
48
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:
-
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.
49
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. Market conditions can trigger constraints in the supply
chain of certain raw materials, such as sand, cement, and specialty
metals. The majority of our risk associated with supply chain
constraints occurs in those situations where we have a relationship with a
single supplier for a particular resource.
Intellectual
property rights
We rely
on a variety of intellectual property rights that we use in our services and
products. We may not be able to successfully preserve these
intellectual property rights in the future, and these rights could be
invalidated, circumvented, or challenged. In addition, the laws of
some foreign countries in which our services and products may be sold do not
protect intellectual property rights to the same extent as the laws of the
United States. Our failure to protect our proprietary information and
any successful intellectual property challenges or infringement proceedings
against us could materially and adversely affect our competitive
position.
Technology
The
market for our services and products is characterized by continual technological
developments to provide better and more reliable performance and
services. If we are not able to design, develop, and produce
commercially competitive products and to implement commercially competitive
services in a timely manner in response to changes in technology, our business
and revenue could be materially and adversely affected, and the value of our
intellectual property may be reduced. Likewise, if our proprietary
technologies, equipment and facilities, or work processes become obsolete, we
may no longer be competitive, and our business and revenue could be materially
and adversely affected.
Reliance
on management
We depend
greatly on the efforts of our executive officers and other key employees to
manage our operations. The loss or unavailability of any of our
executive officers or other key employees could have a material adverse effect
on our business.
50
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. 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 any 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.
51
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, 2008 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, 2008, our internal control over financial reporting is
effective.
The
effectiveness of Halliburton’s internal control over financial reporting as of
December 31, 2008 has been audited by KPMG LLP, an independent registered public
accounting firm, as stated in their report that is included herein.
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, 2008 and 2007, 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, 2008. 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, 2008 and 2007, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2008, in conformity with U.S. generally accepted accounting
principles.
As
discussed in Notes 11 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 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, 2008, 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 16, 2009 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, 2008, 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, 2008, 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, 2008 and 2007, 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, 2008, and our report dated
February 16, 2009 expressed an
unqualified opinion on those consolidated financial statements.
Common
shares, par value $2.50 per share – authorized 2,000 shares, issued
1,067
and 1,063
shares
2,666
2,657
Paid-in
capital in excess of par value
1,114
1,741
Accumulated
other comprehensive loss
(215
)
(104
)
Retained
earnings
9,411
8,202
Treasury
stock, at cost – 172 and 183 shares
(5,251
)
(5,630
)
Total
shareholders’ equity
7,725
6,866
Total
liabilities and shareholders’ equity
$
14,385
$
13,135
See notes to consolidated financial
statements.
56
HALLIBURTON
COMPANY
Consolidated
Statements of Shareholders’ Equity
Millions
of dollars
2008
2007
2006
Balance
at January 1
$
6,866
$
7,376
$
6,372
Dividends
and other transactions with shareholders
(558
)
(1,499
)
(1,324
)
Sale
of stock by a subsidiary
–
–
117
Adoption
of Financial Accounting Standards Board
Interpretation No. 48 and
Statement of Financial
Accounting Standard No.
158
(10
)
(30
)
(218
)
Shares
exchanged in KBR, Inc. exchange offer
–
(2,809
)
–
Other
–
(4
)
34
Comprehensive
income:
Net income
1,538
3,499
2,348
Net cumulative translation
adjustments
1
(23
)
34
Defined benefit and other
postretirement plans adjustments
(106
)
355
2
Net unrealized gains (losses)
on investments
and derivatives
(6
)
1
11
Total
comprehensive income
1,427
3,832
2,395
Balance
at December 31
$
7,725
$
6,866
$
7,376
See notes to consolidated financial
statements.
57
HALLIBURTON
COMPANY
Consolidated
Statements of Cash Flows
Year
Ended December 31
Millions
of dollars
2008
2007
2006
Cash
flows from operating activities:
Net
income
$
1,538
$
3,499
$
2,348
Adjustments
to reconcile net income to net cash from operations:
Depreciation,
depletion, and amortization
738
583
480
Loss
on extinguishment of debt
693
–
–
(Income)
loss from discontinued operations
423
(975
)
(171
)
Provision
(benefit) for deferred income taxes, continuing operations
254
(140
)
714
Gain
on sale of business assets, net
(62
)
(52
)
(66
)
Other
changes:
Accounts
payable
161
77
96
Contributions
to pension plans
(52
)
(41
)
(75
)
Inventories
(368
)
(218
)
(309
)
Receivables
(670
)
(326
)
(327
)
Other
19
288
656
Cash
flows from discontinued operations
–
31
311
Total
cash flows from operating activities
2,674
2,726
3,657
Cash
flows from investing activities:
Sales
(purchases) of short-term investments in marketable securities,
net
388
(332
)
(20
)
Sales
of property, plant, and equipment
191
203
152
Dispositions
of business assets, net of cash disposed
81
70
98
Disposal
of KBR, Inc. cash upon separation
–
(1,461
)
–
Acquisitions
of business assets, net of cash acquired
(652
)
(563
)
(27
)
Capital
expenditures
(1,824
)
(1,583
)
(834
)
Other
investing activities
(40
)
18
(20
)
Cash
flows from discontinued operations
–
(13
)
225
Total
cash flows from investing activities
(1,856
)
(3,661
)
(426
)
Cash
flows from financing activities:
Proceeds
from long-term debt, net of offering costs
1,187
–
–
Proceeds
from exercises of stock options
120
110
159
Tax
benefit from exercise of options and restricted stock
44
29
53
Payments
of dividends to shareholders
(319
)
(314
)
(306
)
Payments
to reacquire common stock
(507
)
(1,374
)
(1,339
)
Payments
on long-term debt
(2,048
)
(7
)
(324
)
Other
financing activities
–
4
(8
)
Cash
flows from discontinued operations
–
(18
)
485
Total
cash flows from financing activities
(1,523
)
(1,570
)
(1,280
)
Effect
of exchange rate changes on cash, including $0, $0, and $50 related
to
discontinued
operations
(18
)
(27
)
37
Increase
(decrease) in cash and equivalents
(723
)
(2,532
)
1,988
Cash
and equivalents at beginning of year, including $0, $1,461, and
$390
related to discontinued
operations
1,847
4,379
2,391
Cash
and equivalents at end of year, including $0, $0, and $1,461
related
to discontinued
operations
$
1,124
$
1,847
$
4,379
Supplemental
disclosure of cash flow information for continuing
operations:
Cash
payments during the year for:
Interest
$
143
$
144
$
164
Income
taxes
$
1,057
$
941
$
289
See notes
to consolidated financial statements.
58
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.
We
believe the most significant estimates and assumptions are associated with the
valuation of income taxes, percentage-of-completion accounting for long-term
contracts, legal and environmental reserves, indemnity valuations, purchase
price allocations, pensions, goodwill, other intangible assets, and allowance
for bad debts. 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 presented as discontinued operations in the consolidated
financial statements. See Note 2 for additional
information. All 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 include fixed or determinable prices but 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, collectibility is reasonably
assured, and delivery occurs as directed by our customer. 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.
59
Percentage of
completion. Revenue from certain long-term, integrated project
management 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.”
Research
and development
Research
and development costs are expensed as incurred. Research and
development costs were $326 million in 2008, $301 million in 2007, and $254
million in 2006, of which over 96% was company sponsored in each
year.
Cash
equivalents
We
consider all highly liquid investments with an original maturity of three months
or less to be cash equivalents.
Inventories
Inventories
are stated at the lower of cost or market. Cost represents invoice or
production cost for new items and original cost less allowance for condition for
used material returned to stock. Production cost includes material,
labor, and manufacturing overhead. Some domestic manufacturing and
field service finished products and parts inventories for drill bits, completion
products, and bulk materials are recorded using the last-in, first-out
method. The remaining inventory is recorded on the average cost
method. We regularly review inventory quantities on hand and record
provisions for excess or obsolete inventory based primarily on historical usage,
estimated product demand, and technological developments.
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. Expenditures for additions, modifications, and conversions
are capitalized when they increase the value or extend the useful life of the
asset.
60
Goodwill
and other intangible assets
We record
as goodwill the excess purchase price over the fair value of the tangible and
identifiable intangible assets acquired. During the year, we recorded
an additional $274 million in goodwill arising from 2008 acquisitions, of which
$159 million related to the Completion and Production segment and $115 million
related to the Drilling and Evaluation segment. The reported amounts
of goodwill for each reporting unit are reviewed for impairment on an annual
basis, during the third quarter, 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. The
second step of the goodwill impairment test compares the implied fair value of
the reporting unit’s goodwill with the carrying amount of that
goodwill. The implied fair value of goodwill is determined in the
same manner as the amount of goodwill recognized in a business
combination. In other words, the estimated fair value of the
reporting unit is allocated to all of the assets and liabilities of that unit
(including any unrecognized intangible assets) as if the reporting unit had been
acquired in a business combination and the fair value of the reporting unit was
the purchase price paid. If the carrying amount of the reporting
unit’s goodwill exceeds the implied fair value of that goodwill, an impairment
loss is recognized in an amount equal to that excess. Our annual
impairment tests resulted in no goodwill impairment in 2008, 2007, or
2006. In addition, there were no negative conditions, or triggering
events, that occurred in 2008, 2007, or 2006 requiring us to perform additional
impairment reviews.
We
amortize other identifiable intangible assets with a finite life on a
straight-line basis over the period which the asset is expected to contribute to
our future cash flows, ranging from three years to 20 years. The
components of these other intangible assets generally consist of patents,
license agreements, non-compete agreements, trademarks, and customer lists and
contracts.
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.
Insurance
The
company is self-insured up to certain retention limits for general liability,
vehicle liability, group medical, and for workers’ compensation claims for
certain of its employees. The amounts in excess of the self-insured
levels are fully insured, up to a limit. Self-insurance accruals are
based on claims filed and an estimate for significant claims incurred but not
reported.
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.
61
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 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” 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 “Other, net” 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 “Net cumulative translation adjustments.”
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
(SFAS) No. 123 (revised 2004), “Share-Based Payment”, 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.
Total
stock-based compensation expense for continuing operations, net of related tax
effects, was $67 million in 2008, $62 million in 2007, and $49 million in
2006. Total income tax benefit recognized in continuing operations
for stock-based compensation arrangements was $36 million in 2008, $35 million
in 2007, and $27 million in 2006.
62
The
majority of our options are generally issued during the second quarter of the
year. 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 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 term of options granted
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
2008
2007
2006
Expected
term (in years)
5.20
5.14
5.24
Expected
volatility
32.30
%
35.70
%
42.20
%
Expected
dividend yield
0.71 – 2.38
%
0.89 – 1.14
%
0.76 – 1.06
%
Risk-free
interest rate
1.57 – 3.32
%
3.37 – 5.00
%
4.30 – 5.03
%
Weighted
average grant-date fair value per share
$
12.28
$
11.35
$
14.20
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
2008
2007
2006
Expected
term (in years)
0.5
0.5
0.5
Expected
volatility
28.88
%
29.49
%
37.77
%
Expected
dividend yield
0.67
%
1.03
%
0.80
%
Risk-free
interest rate
2.17
%
4.98
%
5.29
%
Weighted
average grant-date fair value per share
$
12.58
$
7.97
$
9.32
Offering
period January 1 through June 30
2008
2007
2006
Expected
term (in years)
0.5
0.5
0.5
Expected
volatility
24.69
%
34.91
%
35.65
%
Expected
dividend yield
0.93
%
1.00
%
0.75
%
Risk-free
interest rate
3.40
%
5.09
%
4.38
%
Weighted
average grant-date fair value per share
$
8.64
$
7.20
$
7.91
See Note
12 for further detail on stock incentive plans.
63
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. During 2008, adjustments of
$420 million, net of tax, to our liability for indemnities and guarantees were
reflected as a loss in “Income (loss) from discontinued operations, net of
income tax.”
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.
Year
Ended December 31
Millions
of dollars
2007
2006
Revenue
$
2,250
$
9,621
Operating
income
$
62
$
239
Net
income
$
23
(a)
$
180
(a)
Net
income for 2007 represents our 81% share of KBR’s results
from
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 our
responsibility for liabilities unrelated to KBR’s business. We
provide indemnification in favor of KBR under the master separation agreement
for certain contingent liabilities, including our indemnification of KBR and any
of its greater than 50%-owned subsidiaries as of November 20, 2006, the date of
the master separation agreement, for:
-
fines
or other monetary penalties or direct monetary damages, including
disgorgement, as a result of a claim made or assessed by a governmental
authority in the United States, the United Kingdom, France, Nigeria,
Switzerland, and/or Algeria, or a settlement thereof, related to alleged
or actual violations occurring prior to November 20, 2006 of the United
States Foreign Corrupt Practices Act (FCPA) or particular, analogous
applicable foreign statutes, laws, rules, and regulations in connection
with investigations pending as of that date, including with respect to the
construction and subsequent expansion by a consortium of engineering firms
comprised of Technip SA of France, Snamprogetti Netherlands B.V., JGC
Corporation of Japan, and Kellogg Brown & Root LLC (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.
64
Additionally,
we provide 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 there under;
(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 us for these guarantees. We
have also provided a limited indemnity, with respect to FCPA and anti-trust
governmental and third-party claims, to the lender parties under KBR’s revolving
credit agreement expiring in December 2010. KBR has agreed to
indemnify us, other than for the FCPA and Barracuda-Caratinga bolts matter, if
we are 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.
During
the second quarter of 2007, 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. During 2008, we recorded $420 million, net of tax, as a loss
to discontinued operations to reflect the resolution of the Department of
Justice (DOJ) and Securities and Exchange Commission (SEC) FCPA investigations
and the impact of our most recent assumptions regarding the resolution of the
Barracuda-Caratinga bolt arbitration matter under the indemnities and guarantees
provided to KBR upon separation. We did not record a tax benefit
related to the resolution of the DOJ and SEC investigations. These
indemnities and guarantees are primarily included in “Department of Justice and
Securities and Exchange Commission settlement and indemnity, current” and “Other
liabilities” on the consolidated balance sheets and totaled $631 million at
December 31, 2008. Excluding the DOJ and SEC matters noted above, our
estimation of the remaining obligation for other indemnities and guarantees
provided to KBR upon separation was $72 million at December 31,2008. See Note 10 for further discussion of the FCPA and
Barracuda-Caratinga matters.
The tax
sharing agreement provides for allocations of United States and certain other
jurisdiction tax liabilities between us and KBR.
Note
3. Acquisitions and Dispositions
We have
completed various acquisitions for cash payments in the aggregate of
approximately $652 million during 2008, $563 million during 2007, and $27
million during 2006. None of these acquisitions were significant on
an individual basis.
WellDynamics
B.V.
In July
2008, we acquired the remaining 49% equity interest in WellDynamics B.V.
(WellDynamics) from Shell Technology Ventures Fund 1 B.V. (STV Fund), resulting
in our 100% ownership of WellDynamics. WellDynamics is a provider of
intelligent well completion technology and its results of operations are
included in our Completion and Production segment.
65
PSL
Energy Services Limited
In July
2007, we acquired the entire share capital of PSL Energy Services Limited
(PSLES), a leading 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 $335 million for PSLES, consisting of $331 million
in cash and $4 million in debt assumed. We have recorded goodwill of
$158 million and intangible assets of $61 million associated with the
acquisition. 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.
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.
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
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.” KBR
results are presented 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.
66
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.
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 well
construction solutions that enable customers to model, measure, and optimize
their well placement, stability, and reservoir evaluation
activities. This segment consists of fluid services, drilling
services, drill bits, wireline and perforating services, software and asset
solutions, and project management services.
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.
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 for precise wellbore placement while
providing important measurements about the characteristics of the drill string
and geological formations while drilling wells. Real-time operating
capabilities enable the monitoring of well progress and aid decision-making
processes.
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, 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,
perforating, and borehole seismic services. Perforating services
include tubing-conveyed perforating services and products. Borehole
seismic services include fracture analysis and mapping.
Software
and asset solutions 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 under the equity method is included in revenue and operating income of the
applicable segment.
67
The
following tables present information on our business segments.
Operations
by business segment
Year
Ended December 31
Millions
of dollars
2008
2007
2006
Revenue:
Completion
and Production
$
9,935
$
8,386
$
7,221
Drilling
and Evaluation
8,344
6,878
5,734
Total
$
18,279
$
15,264
$
12,955
Operating
income:
Completion
and Production
$
2,409
$
2,199
$
2,140
Drilling
and Evaluation
1,865
1,485
1,328
Corporate
and other
(264
)
(186
)
(223
)
Total
$
4,010
$
3,498
$
3,245
Capital
expenditures:
Completion
and Production
$
797
$
791
$
441
Drilling
and Evaluation
1,021
759
390
Corporate
and other
6
33
3
Total
$
1,824
$
1,583
$
834
Depreciation,
depletion, and amortization:
Completion
and Production
$
366
$
288
$
239
Drilling
and Evaluation
372
295
241
Total
$
738
$
583
$
480
December
31
Millions
of dollars
2008
2007
2006
Total
assets:
Completion
and Production
$
6,045
$
4,842
$
3,636
Drilling
and Evaluation
6,096
4,606
3,566
Shared
assets
648
672
1,216
Corporate
and other
1,596
3,015
3,047
Discontinued
operations
–
–
5,395
Total
$
14,385
$
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
2008
2007
2006
Revenue:
United
States
$
7,775
$
6,673
$
5,869
Other
countries
10,504
8,591
7,086
Total
$
18,279
$
15,264
$
12,955
68
December
31
Millions
of dollars
2008
2007
2006
Long-lived
assets:
United
States
$
3,571
$
2,733
$
2,045
Other
countries
3,027
2,263
1,413
Total
$
6,598
$
4,996
$
3,458
Note
5. Receivables
Our trade
receivables are generally not collateralized. At December 31, 2008,
34% of our gross trade receivables were from customers in the United
States. At December 31, 2007, 35% 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 $92 million at December 31, 2008 and
$71 million at December 31, 2007. If the average cost method had been
used, total inventories would have been $31 million higher than reported at
December 31, 2008 and $25 million higher than reported at December 31,2007. The cost of the remaining inventory was recorded on the average
cost method. Inventories consisted of the following:
December
31
Millions
of dollars
2008
2007
Finished
products and parts
$
1,312
$
1,042
Raw
materials and supplies
446
325
Work
in process
70
92
Total
$
1,828
$
1,459
Finished
products and parts are reported net of obsolescence reserves of $81 million at
December 31, 2008 and $65 million at December 31, 2007.
Note
7. 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, 2008, we held no investments in marketable
securities.
69
Note
8. Property, Plant, and Equipment
Property,
plant, and equipment were composed of the following:
December
31
Millions
of dollars
2008
2007
Land
$
58
$
46
Buildings
and property improvements
1,082
869
Machinery,
equipment, and other
8,208
6,841
Total
9,348
7,756
Less
accumulated depreciation
4,566
4,126
Net
property, plant, and equipment
$
4,782
$
3,630
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
2008
2007
1 – 10 years
17
%
17
%
11
– 20 years
46
%
50
%
21 –
30 years
12
%
13
%
31 –
40 years
25
%
20
%
Machinery,
Equipment,
and
Other
2008
2007
1 – 5
years
19
%
22
%
6 – 10 years
74
%
72
%
11 –
20 years
7
%
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
2008
2007
6.7%
senior notes due September 2038
$
800
$
–
5.5%
senior notes due October 2010
749
749
5.9%
senior notes due September 2018
400
–
7.6%
senior debentures due August 2096
294
294
8.75%
senior debentures due February 2021
185
185
3.125%
convertible senior notes due July 2023
–
1,200
Other
184
358
Total
long-term debt
2,612
2,786
Less
current portion
26
159
Noncurrent
portion of long-term debt
$
2,586
$
2,627
70
Convertible
notes
Our
3.125% convertible senior notes due July 2023 became redeemable at our option on
July 15, 2008. On July 30, 2008, we gave notice of redemption on the
convertible notes. In lieu of redemption, the holders of the convertible
notes could convert each $1,000 principal amount of convertible notes into
53.4069 shares of our common stock. Substantially all of the holders
timely elected to convert during the third quarter of 2008. Upon
conversion, we settled the principal amount of our convertible notes in cash and
the premium on the notes with a combination of $693 million in cash and
approximately $840 million, or 20 million shares, of our treasury stock.
The settlement of the principal amount was funded with the proceeds from the
issuance of 6.7% and 5.9% senior notes. We recorded a non-tax
deductible loss of $693 million in the third quarter of 2008, in “Other, net” on
our consolidated statement of operations, related to the portion of the premium
settled in cash.
Other
senior debt
We have
issued various senior notes and debentures, all of which rank equally with our
existing and future senior unsecured indebtedness, have semiannual interest
payments, and no sinking fund requirements. We may redeem some of the
6.7% and 5.9% senior notes from time to time or all of the notes of each series
at any time at the redemption prices, plus accrued and unpaid interest. Our
5.5% senior notes are redeemable by us, in whole or in part, at any time,
subject to a redemption price equal to the greater of 100% of the principal
amount of 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. Our 7.6% and 8.75%
senior debentures may not be redeemed prior to maturity.
Revolving
credit facilities
We have
an unsecured, $1.2 billion credit facility expiring 2012 whose purpose is to
provide commercial paper support, general working capital, and credit for other
corporate purposes. On October 10, 2008, we entered into an
unsecured, six-month revolving credit facility, with current commitments of $400
million, to give us additional liquidity and for other general corporate
purposes. We are able to draw on the facility once we have used all of our
existing $1.2 billion, five-year revolving credit facility. There
were no cash drawings under the revolving credit facilities as of December 31,2008.
Maturities
Our debt
matures as follows: $26 million in 2009; $749 million in 2010; and
$1.8 billion in 2017 and thereafter.
Note
10. Commitments and Contingencies
Foreign
Corrupt Practices Act investigations
In
February 2009, the FCPA investigations by the DOJ and the SEC were resolved. The
DOJ and SEC investigations resulted from allegations of improper payments to
government officials in Nigeria 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.
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).
71
In
addition to the DOJ and the SEC investigations, we are aware of other
investigations in France, Nigeria, Great Britain, and Switzerland regarding the
Bonny Island project.
We
provided indemnification in favor of KBR under the master separation agreement
for certain contingent liabilities, including our 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 the Bonny
Island project.
With
respect to the DOJ, in February 2009, a subsidiary of KBR, Inc. pleaded guilty
to conspiring to violate the FCPA and to substantive violations of the
anti-bribery provisions of the FCPA in connection with the Bonny Island
project. The DOJ investigation was resolved with respect to us with a
non-prosecution agreement in which the DOJ agreed not to bring FCPA or bid
coordination-related charges against us with respect to the matters under
investigation, and in which we agreed to continue to cooperate with the DOJ’s
ongoing investigation and to refrain from and self-report certain FCPA
violations. The DOJ agreement does not provide for a monitor for
us.
As a
result of our indemnity in favor of KBR under the master separation agreement
with KBR and the KBR subsidiary’s criminal plea, we have paid $49 million and
will pay an additional $333 million in seven installments over the next seven
quarters of the $402 million criminal fine payable by KBR as part of the
resolution of the DOJ investigation, with KBR consenting to pay the remaining
$20 million.
With
respect to the SEC, without admitting or denying the allegations in an SEC
complaint, we consented to the entry of a final judgment that permanently
enjoins us from violating the record-keeping and internal control provisions of
the FCPA. KBR also entered into a related settlement with the SEC. As
part of our settlement with the SEC, we agreed to be jointly and severally
liable with KBR for, and will pay the SEC, $177 million in disgorgement in the
first quarter of 2009.
In
addition, as part of the resolution of the SEC investigation, we will retain an
independent consultant to conduct a 60-day review and evaluation of our internal
controls and record-keeping policies as they relate to the FCPA, and we will
adopt any necessary anti-bribery and foreign agent internal controls and
record-keeping procedures recommended by or agreed upon with the independent
consultant. In 2010, the independent consultant will perform a 30-day follow-up
review to confirm that we have implemented the recommendations and continued the
application of our current policies and procedures.
The
settlements and the other ongoing investigations could 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.
KBR has
agreed that Halliburton’s indemnification obligations with respect to the DOJ
and SEC FCPA investigations have been fully satisfied. Our indemnity
of KBR continues with respect to other investigations within the scope of our
indemnity.
72
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.
To
reflect the resolution of the DOJ and SEC FCPA investigations and to reflect
other adjustments to the indemnities and guarantees provided to KBR upon
separation, we recorded $420 million, net of tax, in 2008 as a loss from
discontinued operations. We did not record a tax benefit related to
the resolution of the DOJ and SEC FCPA investigations. As of December31, 2008 and December 31, 2007, $559 million and $142 million are recorded
related to our obligations regarding DOJ and SEC FCPA matters in our
consolidated balance sheets in “Department of Justice and Securities and
Exchange Commission settlement and indemnity, current” and “Other
liabilities.” See Note 2 for additional information.
Bidding
practices investigation
In
connection with the investigation into payments relating to the Bonny Island
project in Nigeria, information was uncovered suggesting that, possibly
beginning as early as the mid-1980s, former Kellogg Brown & Root, Inc.
employees may have engaged in coordinated bidding with one or more competitors
on certain foreign construction projects. Halliburton’s indemnity to
KBR does not extend to liabilities for governmental fines or third-party claims
arising out of these activities. The settlement with the DOJ included an
agreement by the DOJ not to bring bid coordination-related charges against
us.
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, 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. Our estimation of the indemnity obligation
regarding the Barracuda-Caratinga arbitration is recorded as a liability in our
consolidated financial statements as of December 31, 2008 and December 31,2007. 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 $148 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 held an evidentiary hearing during the
week of March 31, 2008 and took evidence and arguments under
advisement.
73
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 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.
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 Chief Executive Officer
(CEO). The court ordered that the case proceed against our CEO and
Halliburton.
In
September 2007, AMSF filed a motion for class certification, and our response
was filed in November 2007. The court held a hearing in March 2008,
and issued an order November 3, 2008 denying AMSF’s motion for class
certification. AMSF then filed a motion with the Fifth Circuit Court
of Appeals requesting permission to appeal the district court’s order denying
class certification. The Fifth Circuit granted AMSF’s motion and the
order denying class certification is currently on appeal. The case
will remain stayed in the district court pending the outcome of the appeal. As
of December 31, 2008, 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 31,2008, we had not recorded any liability associated with these
indemnifications.
74
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 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
$64 million as of December 31, 2008 and $72 million as of December 31,2007. Our total liability related to environmental matters covers
numerous properties.
We have
subsidiaries that have been named as potentially responsible parties along with
other third parties for 8 federal and state superfund sites for which we have
established a liability. As of December 31, 2008, those 8 sites
accounted for approximately $10 million of our total $64 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.
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, 2008, including approximately
$828 million 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 $561 million in 2008, $487 million in
2007, and $402 million in 2006.
Future
total rentals on noncancellable operating leases are as follows: $183
million in 2009; $161 million in 2010; $130 million in 2011; $84 million in
2012; $66 million in 2013; and $175 million thereafter.
75
Note
11. Income Taxes
The
components of the provision for income taxes on continuing operations
were:
Year
Ended December 31
Millions
of dollars
2008
2007
2006
Current
income taxes:
Federal
$
(561
)
$
(560
)
$
(156
)
Foreign
(346
)
(449
)
(122
)
State
(50
)
(38
)
(11
)
Total
current
(957
)
(1,047
)
(289
)
Deferred
income taxes:
Federal
(303
)
129
(600
)
Foreign
64
7
(95
)
State
(15
)
4
(19
)
Total
deferred
(254
)
140
(714
)
Provision
for income taxes
$
(1,211
)
$
(907
)
$
(1,003
)
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
2008
2007
2006
United
States
$
1,988
$
2,219
$
2,280
Foreign
1,175
1,241
919
Total
$
3,163
$
3,460
$
3,199
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
2008
2007
2006
United
States statutory rate
35.0
%
35.0
%
35.0
%
Repurchase premium paid in
cash to retire debt
8.0
-
-
Adjustments of prior year
taxes
(2.3
)
(0.3
)
(2.1
)
Impact of foreign income taxed
at different rates
(1.4
)
(2.3
)
(1.3
)
Other impact of foreign
operations
(1.3
)
(3.9
)
3.1
Valuation
allowance
0.1
(2.0
)
(3.3
)
Other items,
net
0.2
(0.3
)
-
Total
effective tax rate on continuing operations
38.3
%
26.2
%
31.4
%
76
The major
component of the difference between the 2008 statutory rate compared to the
effective rate was related to our inability to recognize a benefit for the $693
million loss on the settlement of our convertible debt, as United States tax law
generally prohibits a company from recognizing a tax deduction for a repurchase
premium paid to retire debt that is convertible into the stock of the issuing
company. The major component of the difference between the 2007
statutory rate compared to the effective rate was the favorable impact of the
ability to recognize United States foreign tax credits of approximately $205
million. This amount consisted 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. The major component of the difference
between the 2006 statutory tax rate compared to the effective tax rate was the
release of the remaining valuation allowance for future tax attributes related
to United States net operating losses established in prior years, the majority
of which was released in 2005.
The
primary components of our deferred tax assets and liabilities and the related
valuation allowances were as follows:
December
31
Millions
of dollars
2008
2007
Gross
deferred tax assets:
Employee compensation and
benefits
$
324
$
262
Accrued
liabilities
81
80
Foreign tax credit
carryforward
79
61
Capitalized research and
experimentation
74
94
Net operating loss
carryforwards
50
24
Insurance
accruals
47
46
Software revenue
recognition
31
37
Inventory
26
63
Alternative minimum tax credit
carryforward
–
19
Other
49
176
Total
gross deferred tax assets
761
862
Gross
deferred tax liabilities:
Depreciation and
amortization
303
164
Joint ventures, partnerships,
and unconsolidated affiliates
25
34
Other
38
55
Total
gross deferred tax liabilities
366
253
Valuation
allowances:
Net operating loss
carryforwards
14
22
Other
–
7
Total
valuation allowances
14
29
Net
deferred income tax asset
$
381
$
580
At
December 31, 2008, we had a total of $137 million of foreign net operating loss
carryforwards, of which $66 million will expire from 2009 through 2021 and $71
million will not expire due to indefinite expiration dates. At
December 31, 2008, we had $40 million of domestic net operating loss
carryforwards that will expire from 2021 through 2028. At December31, 2008, we had United States foreign tax credit carryforwards of $79 million
that are expected to expire beginning in 2018.
We
established a valuation allowance on certain foreign operating loss
carryforwards on the basis that we believe these assets will not be utilized in
the statutory carryover period. The majority of the 2008 valuation
allowance change was recorded as an adjustment to goodwill.
77
Effective
January 1, 2007, we adopted FASB Interpretation (FIN) No. 48, “Accounting for
Uncertainty in Income Taxes, an interpretation of FASB Statement No.
109.” FIN 48, as amended May 2007 by FASB Staff Position (FSP) 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. The cumulative effect of this
change in accounting principle related to FIN 48 was immaterial.
The
following presents a rollforward of our unrecognized tax benefits and associated
interest and penalties.
Tax
benefits associated with United States foreign tax credits of $19 million and
$99 million as of December 31, 2008 and December 31, 2007 were included in the
balance of unrecognized tax benefits that could be resolved within the next 12
months. Tax benefits associated with United States research and
development tax credits of $30 million were included in the balance of
unrecognized tax benefits that could be resolved within the next 12 months as of
December 31, 2008. Also, as of December 31, 2008 and 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, 2008 and December 31, 2007, we estimated
that $163 million and $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 2007.
78
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
(151
)
(45
)
(400
)
Unrealized
gains (losses) on investments and derivatives
(4
)
2
1
Total
accumulated other comprehensive loss
$
(215
)
$
(104
)
$
(437
)
Shares
of common stock
December
31
Millions
of shares
2008
2007
2006
Issued
1,067
1,063
1,060
In
treasury
(172
)
(183
)
(62
)
Total
shares of common stock outstanding
895
880
998
Our stock
repurchase program has an authorization of $5.0 billion, of which $1.8 billion
remained available at December 31, 2008. The 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 in February 2006
through December 31, 2008, we have repurchased approximately 92 million shares
of our common stock for approximately $3.2 billion at an average price per share
of $34.30. These numbers include the repurchases of approximately 13
million shares of our common stock for approximately $481 million at an average
price per share of $36.61 during 2008.
Preferred
Stock
Our
preferred stock consists of five million total authorized shares at December 31,2008, of which none are 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, 2008, approximately 12 million shares were
available for future grants under the 1993 Plan, of which approximately 6
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.
81
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 2008.
The total
intrinsic value of options exercised was $106 million in 2008, $68 million in
2007, and $123 million in 2006. As of December 31, 2008, there was
$37 million of unrecognized compensation cost, net of estimated forfeitures,
related to nonvested stock options, which is expected to be recognized over a
weighted average period of approximately 1.8 years.
Cash
received from option exercises was $120 million during 2008, $110 million during
2007, and $159 million during 2006. The tax benefit realized from the
exercise of stock options was $33 million in 2008, $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 their 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, 2008, 122,400 shares had
been issued to non-employee directors under this plan. There were
7,200 shares, 8,800 shares, and 8,000 shares of restricted stock awarded under
the Directors Plan in 2008, 2007, and 2006. In addition, during 2008,
our non-employee directors were awarded 18,416 shares of restricted stock under
the 1993 Plan, which are included in the table below.
82
The
following table represents our 1993 Plan and Directors Plan restricted stock
awards and restricted stock units granted, vested, and forfeited during
2008.
The
weighted average grant-date fair value of shares granted during 2007 was $32.24
and during 2006 was $34.39. The total fair value of shares vested
during 2008 was $81 million, during 2007 was $79 million, and during 2006 was
$64 million. As of December 31, 2008, there was $224 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 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, 2008, 15.9 million shares have been sold
through the ESPP.
Note
13. Income (Loss) per Share
Basic
income (loss) 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 (loss) per share includes additional common
shares that would have been outstanding if potential common shares with a
dilutive effect had been issued. A reconciliation of the number of
shares used for the basic and diluted income (loss) per share calculation is as
follows:
Millions
of shares
2008
2007
2006
Basic
weighted average common shares outstanding
877
913
1,014
Dilutive
effect of:
Convertible senior notes
premium
22
29
29
Stock options
4
6
9
Restricted
stock
1
2
2
Diluted
weighted average common shares outstanding
904
950
1,054
83
In 2004,
we entered into a supplemental indenture that required 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 2008, 2007, and 2006. In
2008, we redeemed our 3.125% convertible senior notes. See Note 9 for
additional information regarding the redemption of our convertible senior
notes.
Excluded
from the computation of diluted income per share were options to purchase four
million shares of common stock that were outstanding in 2008, three million
shares of common stock that were outstanding in 2007, and two million shares of
common stock that were outstanding in 2006. These options were
outstanding during these years but were excluded because the option exercise
price was greater than the average market price of the common
shares.
Note
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 foreign exchange forward
contracts and option contracts were $324 million at December 31, 2008 and $272
million at December 31, 2007. 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 either December 31, 2008 or December 31,2007.
84
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
outstanding debt instruments have fixed interest rates.
Fair market value of financial
instruments. The estimated fair market value of long-term debt
was $2.8 billion at December 31, 2008 and $4.1 billion at December 31, 2007, as
compared to the carrying amount of $2.6 billion at December 31, 2008 and $2.8
billion at December 31, 2007. 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
foreign 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 $178 million in 2008,
$162 million in 2007, and $138 million in
2006;
85
-
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, and/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. Plan participants share the total
cost for all benefits provided above our fixed
contributions. Participants’ contributions are adjusted as
required to cover benefit payments. We have made no commitment
to adjust the amount of our contributions; therefore, the computed
accumulated postretirement benefit obligation amount for these plans 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).” Effective for our fiscal year ended
December 31, 2008, we adopted the requirements to measure plan assets and
benefit obligations as of the date of the employer’s fiscal
year-end. Effective for our fiscal year ended December 31, 2006, we
adopted the requirement to recognize the funded status of a benefit plan and the
standard’s additional disclosure requirements.
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 obligations for retirement
plans of our continuing operations.
Pension
Benefits
Other
United
United
Postretirement
Benefit
obligation
States
Int’l
States
Int’l
Benefits
Millions
of dollars
2008
2007
2008
2007
Change
in benefit obligation
Benefit
obligation at beginning of period
$
110
$
874
$
127
$
814
$
104
$
155
Service
cost
–
29
–
26
1
1
Interest
cost
6
50
7
44
6
8
Plan
participants’ contributions
–
5
–
4
5
5
Plan
amendments
–
1
–
2
–
(4
)
Settlements/curtailments
–
(42
)
–
(16
)
–
–
Divestitures
–
(1
)
–
–
–
–
Business
combinations
–
1
–
–
–
–
Currency
fluctuations
–
(201
)
–
38
–
–
Actuarial
gain
–
(18
)
(9
)
(22
)
(13
)
(50
)
Transfers
–
–
–
1
–
–
Benefits
paid
(9
)
(28
)
(15
)
(17
)
(12
)
(11
)
Retained
earnings adjustment – SFAS No. 158
adoption
1
20
–
–
1
–
Projected
benefit obligation at end of period
$
108
$
690
$
110
$
874
N/A
N/A
Accumulated
benefit obligation at end of period
$
108
$
533
$
110
$
678
$
92
$
104
86
Pension
Benefits
Other
United
United
Postretirement
States
Int’l
States
Int’l
Benefits
Millions
of dollars
2008
2007
2008
2007
Change
in plan assets
Fair
value of plan assets at beginning of period
$
107
$
724
$
105
$
622
$
–
$
–
Actual
return on plan assets
(33
)
(111
)
15
53
–
–
Employer
contributions
1
51
2
39
7
7
Settlements
–
(42
)
–
(9
)
–
–
Divestitures
–
(1
)
–
–
–
–
Business
combinations
–
1
–
–
–
–
Plan
participants’ contributions
–
5
–
4
5
4
Currency
fluctuations
–
(181
)
–
32
–
–
Benefits
paid
(9
)
(28
)
(15
)
(17
)
(12
)
(11
)
Retained
earnings adjustment – SFAS No. 158
adoption
–
12
–
–
–
–
Fair
value of plan assets at end of period
$
66
$
430
$
107
$
724
$
–
$
–
Funded
status
$
(42
)
$
(260
)
$
(3
)
$
(150
)
$
(92
)
$
(104
)
Employer
contribution
–
–
–
5
–
1
Net
amount recognized
$
(42
)
$
(260
)
$
(3
)
$
(145
)
$
(92
)
$
(103
)
Pension
Benefits
Other
United
United
Postretirement
States
Int’l
States
Int’l
Benefits
Millions
of dollars
2008
2007
2008
2007
Amounts
recognized on the consolidated
balance sheets
Other
assets
$
–
$
1
$
2
$
9
$
–
$
–
Accrued
employee compensation and benefits
(2
)
(12
)
(1
)
(11
)
(9
)
(10
)
Employee
compensation and benefits
(40
)
(249
)
(4
)
(143
)
(83
)
(93
)
Pension
plans in which projected benefit
obligation exceeded plan assets
at December 31
Projected
benefit obligation
$
107
$
675
$
20
$
835
N/A
N/A
Fair
value of plan assets
65
414
15
677
N/A
N/A
Pension
plans in which accumulated benefit
obligation exceeded plan assets
at December 31
Accumulated
benefit obligation
$
107
$
477
$
20
$
65
N/A
N/A
Fair
value of plan assets
65
360
15
7
N/A
N/A
Weighted-average
assumptions used to determine
benefit obligations at
measurement date
Discount
rate
4.68-5.77
%
2.2-9.0
%
4.61-6.19
%
2.50-8.75
%
5.57-5.61
%
5.77-5.81
%
Rate
of compensation increase
N/A
2.0-10.0
%
4.5
%
2.0-10.0
%
N/A
N/A
87
Pension
Benefits
Other
United
United
Postretirement
States
Int’l
States
Int’l
Benefits
2008
2007
2008
2007
Asset
allocation at December 31
Asset
category Target
Allocation
Equity
securities 50%-70%
59
%
49
%
64
%
57
%
N/A
N/A
Debt
securities 30%-50%
40
%
35
%
35
%
32
%
N/A
N/A
Other 0%-5%
1
%
16
%
1
%
11
%
N/A
N/A
Total 100%
100
%
100
%
100
%
100
%
N/A
N/A
Assumed
health care cost trend rates at December 31
2008
2007
2006
Health
care cost trend rate assumed for next year
9.0
%
9.0
%
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
2016
2015
2011
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 certain international 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. Considering the recent financial markets
downturn, we elected to modify our methodology for selecting discount rates at
December 31, 2008 for our United States pension and postretirement
plans. This resulted in a lower discount rate and yielded a higher
projected benefit obligation than if we had used our previous
methodology. For our United Kingdom pension plan, which constituted
73% of our international pension plans’ projected benefit obligation at December31, 2008, the discount rate utilized at the measurement date in 2008 was 5.75%,
compared to 5.70% at the measurement date in 2007. The overall
expected long-term rate of return on plan assets was determined based upon an
evaluation of our plan assets and 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.
88
Amounts
recognized in accumulated other comprehensive (gain) loss, net of tax, were as
follows at December 31:
Pension
Benefits
Other
United
United
Postretirement
States
Int’l
States
Int’l
Benefits
Millions
of dollars
2008
2007
2008
2007
Net
actuarial (gain) loss
$
37
$
161
$
13
$
72
$
(43
)
$
(39
)
Prior
service cost (benefit)
–
(2
)
–
2
(2
)
(3
)
Total
recognized in accumulated other comprehensive (gain)
loss
$
37
$
159
$
13
$
74
$
(45
)
$
(42
)
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 $35 million to our
international pension plans in 2009. We do not have a required
minimum contribution for our domestic plans; however, we currently expect to
contribute $13 million to these plans in 2009 and 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
2009
$
11
$
21
$
10
$
(1
)
2010
8
17
10
(1
)
2011
8
20
11
(1
)
2012
8
22
11
(1
)
2013
7
26
10
(1
)
Years
2014 – 2018
37
183
45
(5
)
89
Net
periodic cost
Pension
Benefits
Other
United
United
United
Postretirement
States
Int’l
States
Int’l
States
Int’l
Benefits
Millions
of dollars
2008
2007
2006
2008
2007
2006
Components
of net periodic
benefit cost
Service
cost
$
–
$
29
$
–
$
26
$
–
$
23
$
1
$
1
$
1
Interest
cost
6
50
7
45
7
37
6
8
9
Expected
return on plan assets
(7
)
(44
)
(7
)
(40
)
(7
)
(30
)
–
–
–
Amortization
of prior service cost
–
–
–
–
–
–
(1
)
–
–
Settlements/curtailments
–
5
2
–
–
1
–
–
–
Recognized
actuarial (gain) loss
3
6
6
9
6
8
(5
)
–
–
Net
periodic benefit cost
$
2
$
46
$
8
$
40
$
6
$
39
$
1
$
9
$
10
Weighted-average
assumptions used
to determine net periodic
benefit
cost for years ended December
31
Discount
rate
4.61-6.19
%
2.50-8.75
%
5.75
%
2.25-8.75
%
5.75
%
2.25-8.0
%
5.77-5.81
%
5.5
%
5.75
%
Expected
return on plan assets
8.00
%
4.0-9.0
%
8.25
%
4.0-9.0
%
8.25
%
4.0-7.0
%
N/A
N/A
N/A
Rate
of compensation increase
4.50
%
2.0-10.0
%
4.5
%
2.0-10.0
%
4.5
%
2.0-5.0
%
N/A
N/A
N/A
Estimated
amounts that will be amortized from accumulated other comprehensive loss into
net periodic benefit cost in 2009 are immaterial.
Note
16. New Accounting Standards
In
December 2008, the FASB issued FSP SFAS 132(R)-1 “Employers’ Disclosures about
Postretirement Benefit Plan Assets.” This FSP amends the disclosure
requirements for employer’s disclosure of plan assets for defined benefit
pensions and other postretirement plans. The objective of this FSP is to
provide users of financial statements with an understanding of how investment
allocation decisions are made, the major categories of plan assets held by the
plans, the inputs and valuation techniques used to measure the fair value of
plan assets, significant concentration of risk within the company’s plan assets,
and for fair value measurements determined using significant unobservable inputs
a reconciliation of changes between the beginning and ending balances. FSP SFAS
132(R)-1 is effective for fiscal years ending after December 15, 2009. We
will adopt the new disclosure requirements in the 2009 annual reporting
period.
In June
2008, the FASB issued FSP Emerging Issues Task Force (EITF) 03-6-1, “Determining
Whether Instruments Granted in Share-Based Payment Transactions Are
Participating Securities.” This FSP provides that unvested share-based
payment awards that contain nonforfeitable rights to dividends or dividend
equivalents, whether paid or unpaid, are participating securities and shall be
included in the computation of both basic and diluted earnings per share.
This EITF is effective for financial statements issued for fiscal years
beginning after December 15, 2008 and interim periods within those fiscal
years. We will adopt the provisions of FSP EITF 03-6-1 on January 1,2009, which will require us to recast prior periods’ basic and diluted earnings
per share to include outstanding unvested restricted common shares in the
weighted average shares outstanding calculation. We estimate that, had we
calculated earnings per share under these new provisions during 2008, basic
income per share would have decreased by approximately $0.02 for continuing
operations and approximately $0.01 for net income and diluted income per share
would have decreased by approximately $0.01 for both continuing operations and
net income per share.
90
In May
2008, the FASB issued FSP Accounting Principles Board (APB) 14-1, “Accounting
for Convertible Debt Instruments That May Be Settled in Cash upon Conversion
(Including Partial Cash Settlement).” This FSP clarifies that
convertible debt instruments that may be settled in cash upon conversion,
including partial cash settlement, should separately account for the liability
and equity components in a manner that will reflect the entity’s nonconvertible
debt borrowing rate when interest cost is recognized in subsequent
periods. This FSP is effective for financial statements issued for
fiscal years beginning after December 15, 2008 and interim periods within those
fiscal years. We will adopt the provisions of FSP APB 14-1 on January1, 2009 and will be required to retroactively apply its provisions, which means
we will restate our consolidated financial statements for prior
periods.
In
applying this FSP, we estimate approximately $60 million of the carrying value
of the convertible notes to be reclassified to equity as of the July 2003
issuance date. This amount represents the equity component of the
proceeds from the notes, calculated assuming a 4.3% non-convertible borrowing
rate. The discount will be accreted to interest expense over the
five-year term of the notes. Accordingly, approximately $13 million
of additional non-cash interest expense, or $0.01 per diluted share, will be
recorded in 2006 and 2007 and approximately $7 million of additional non-cash
interest expense will be recorded in 2008. Furthermore, under this
FSP, the $693 million loss to settle our convertible debt in the third quarter
of 2008 will be reversed and recorded to additional paid-in
capital. We estimate that diluted income per share for 2008 will
increase by approximately $0.76.
In December 2007, the FASB issued SFAS
No. 141(Revised 2007), “Business Combinations” (SFAS No.
141(R)). SFAS No. 141(R) retains the underlying concepts of SFAS No.
141 in that all business combinations are still required to be accounted for at
fair value under the acquisition method of accounting, but SFAS No. 141(R)
changes the method of applying the acquisition method in a number of ways.
Acquisition costs will generally be expensed as incurred, noncontrolling
interests (minority interests) will be valued at fair value at the acquisition
date, in-process research and development will be recorded at fair value as an
indefinite-lived intangible asset at the acquisition date, restructuring costs
associated with a business combination will generally be expensed subsequent to
the acquisition date, and changes in deferred tax asset valuation allowances and
income tax uncertainties after the acquisition date generally will affect income
tax expense. 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, reporting, and disclosure 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 provisions
of SFAS No. 160 on January 1, 2009 and, beginning with our 2009 interim
reporting periods and for prior comparative periods, we will present
noncontrolling interest (minority interest) as a separate component of
shareholders’ equity.
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.
91
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 February 2008, the FASB issued FSP SFAS 157-1, “Application
of FASB Statement No. 157 to FASB Statement No. 13 and Other
Accounting Pronouncements That Address Fair Value Measurements for Purposes of
Lease Classification or Measurement under Statement 13,” which removes certain
leasing transactions from the scope of SFAS No. 157, and FSP SFAS 157-2,
“Effective Date of FASB Statement No. 157,” which defers the effective date
of SFAS No. 157 for one year for certain nonfinancial assets and
nonfinancial liabilities, except those that are recognized or disclosed at fair
value in the financial statements on a recurring basis. In October
2008, the FASB also issued FSP SFAS 157-3, “Determining the Fair Value of a
Financial Asset When the Market for That Asset Is Not Active,” which clarifies
the application of SFAS No. 157 in an inactive market and illustrates how an
entity would determine fair value when the market for a financial asset is not
active. 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 nonfinancial
liabilities that are not required or permitted to be measured at fair value on a
recurring basis, which include those measured at fair value in goodwill
impairment testing, indefinite-lived intangible assets measured at fair value
for impairment assessment, nonfinancial long-lived assets measured at fair value
for impairment assessment, asset retirement obligations initially measured at
fair value, and those initially measured at fair value in a business
combination. We do not expect the provisions of SFAS No. 157 related
to these items 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.
93
HALLIBURTON
COMPANY
Quarterly
Data and Market Price Information (1)
(Unaudited)
Quarter
Millions
of dollars except per share data
First
Second
Third
Fourth
Year
2008
Revenue
$
4,029
$
4,487
$
4,853
$
4,910
$
18,279
Operating
income
847
949
1,051
1,163
4,010
Income
(loss) from continuing operations
583
623
(21
)
776
1,961
Income
(loss) from discontinued operations
1
(116
)
–
(308
)
(423
)
Net
income (loss)
584
507
(21
)
468
1,538
Earnings
per share:
Basic income (loss) per
share:
Income (loss) from continuing
operations
0.67
0.72
(0.02
)
0.87
2.24
Loss from discontinued
operations
–
(0.14
)
–
(0.34
)
(0.49
)
Net income
(loss)
0.67
0.58
(0.02
)
0.53
1.75
Diluted income (loss) per
share:
Income (loss) from continuing
operations
0.64
0.68
(0.02
)
0.87
2.17
Loss from discontinued
operations
–
(0.13
)
–
(0.34
)
(0.47
)
Net income
(loss)
0.64
0.55
(0.02
)
0.53
1.70
Cash
dividends paid per share
0.09
0.09
0.09
0.09
0.36
Common
stock prices (2)
High
39.98
53.97
55.38
32.09
55.38
Low
30.00
38.56
29.00
12.80
12.80
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
(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.
94
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 2009 Annual Meeting
of Stockholders (File No. 1-3492), under the captions “Election of Directors”
and “Involvement in Certain Legal Proceedings.” 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 2009 Annual Meeting of Stockholders (File No. 1-3492),
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 2009 Annual Meeting of Stockholders (File No. 1-3492), under
the caption “Corporate Governance.”
Audit
Committee financial experts
In the
business judgment of the Board of Directors, all four members of the Audit
Committee, Alan M. Bennett, S. Malcolm Gillis, James T. Hackett, 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 2009 Annual Meeting of Stockholders (File No. 1-3492) under
the captions “Compensation Discussion and Analysis,”“Compensation Committee
Report,”“Summary Compensation Table,”“Grants of Plan-Based Awards in Fiscal
2008,”“Outstanding Equity Awards at Fiscal Year End 2008,”“2008 Option
Exercises and Stock Vested,”“2008 Nonqualified Deferred Compensation,”“Pension
Benefits Table,”“Employment Contracts and Change-in-Control Arrangements,”“Post-Termination Payments,”“Equity Compensation Plan Information,” and “2008
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 2009 Annual Meeting of Stockholders (File No. 1-3492) under
the caption “Stock Ownership of Certain Beneficial Owners and
Management.”
Item
12(b). Security Ownership of Management.
This
information is incorporated by reference to the Halliburton Company Proxy
Statement for our 2009 Annual Meeting of Stockholders (File No. 1-3492) under
the caption “Stock Ownership of Certain Beneficial Owners and
Management.”
95
Item
12(c). Changes in Control.
Not
applicable.
Item
12(d). Securities Authorized for Issuance Under Equity Compensation
Plans.
This
information is incorporated by reference to the Halliburton Company Proxy
Statement for our 2009 Annual Meeting of Stockholders (File No. 1-3492) under
the caption “Equity Compensation Plan Information.”
Item
13. Certain Relationships and Related Transactions, and Director
Independence.
This
information is incorporated by reference to the Halliburton Company Proxy
Statement for our 2009 Annual Meeting of Stockholders (File No. 1-3492) under
the caption “Corporate Governance” to the extent any disclosure is required and
under the caption “The Board of Directors and Standing Committees of
Directors.”
Item
14. Principal Accounting Fees and Services.
This
information is incorporated by reference to the Halliburton Company Proxy
Statement for our 2009 Annual Meeting of Stockholders (File No. 1-3492) under
the caption “Fees Paid to KPMG LLP.”
96
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 53 and 54 and pages 55 through 92 of
this annual report. See index on page
(i).
Form
of debt security of 8.75% Debentures due February 12, 2021 (incorporated
by reference to Exhibit 4(a) to the Form 8-K of Halliburton Company, now
known as Halliburton Energy Services, Inc. (the Predecessor) dated as of
February 20, 1991, File No.
1-3492).
4.2
Senior
Indenture dated as of January 2, 1991 between the Predecessor and 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.
1-3492).
97
4.3
Resolutions
of the Predecessor’s Board of Directors adopted at a meeting held on
February 11, 1991 and of the special pricing committee of the Board of
Directors of the Predecessor adopted at a meeting held on February 11,
1991 and the special pricing committee’s consent in lieu of meeting dated
February 12, 1991 (incorporated by reference to Exhibit 4(c) to the
Predecessor’s Form 8-K dated as of February 20, 1991, File No.
1-3492).
4.4
Second
Senior Indenture dated as of December 1, 1996 between the Predecessor and
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.
1-3492).
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. 1-3492).
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, 2008, have not been filed with the
Commission. Halliburton agrees to furnish copies of these
instruments upon request.
4.11
Form
of debt security of 7.53% Notes due May 12, 2017 (incorporated by
reference to Exhibit 4.4 to Halliburton’s Form 10-Q for the quarter ended
March 31, 1997, File No. 1-3492)
4.12
Form
of 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).
Form
of Global Note for Halliburton’s 5.90% Senior Notes due 2018 (included as
part of Exhibit 4.22).
4.24
Form
of Global Note for Halliburton’s 6.70% Senior Notes due 2038 (included as
part of Exhibit 4.22).
10.1
Halliburton
Company Career Executive Incentive Stock Plan as amended November 15, 1990
(incorporated by reference to Exhibit 10(a) to the Predecessor’s Form 10-K
for the year ended December 31, 1992, File No.
1-3492).
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. 1-3492).
Form
of Nonstatutory Stock Option Agreement for Non-Employee Directors
(incorporated by reference to Exhibit 10.3 to Halliburton’s Form 10-Q for
the quarter ended September 30, 2000, File No.
1-3492).
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. 1-3492).
Revolving
Bridge Facility Credit Agreement among Halliburton, as Borrower, the Banks
party thereto, and Citibank, N.A., as Agent (incorporated by reference to
Exhibit 10.1 to Halliburton’s Form 10-Q for the quarter ended June 30,2008, File No. 1-3492).
10.29
Underwriting
Agreement, dated September 9, 2008, among Halliburton and Citigroup Global
Markets Inc., Greenwich Capital Markets, Inc. and HSBC Securities (USA)
Inc., as representatives of the several underwriters identified therein
(incorporated by reference to Exhibit 1.1 to Halliburton’s Form 8-K filed
September 12, 2008, File No.
1-3492).
10.30
Six
Month Revolving Credit Agreement among Halliburton, as Borrower, the Banks
party thereto, and HSBC Bank (USA) N.A., as Administrative Agent
(incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed
October 16, 2008, File No. 1-3492).
Powers
of attorney for the following directors signed in January 2007
(incorporated by reference to Exhibit 24.1 to Halliburton’s Form 10-K for
the year ended December 31, 2006, File No.
1-3492):
Alan
M. Bennett
James
R. Boyd
Milton
Carroll
Kenneth
T. Derr
S.
Malcolm Gillis
J.
Landis Martin
Jay
A. Precourt
Debra
L. Reed
*
24.2
Power
of attorney for James T. Hackett signed in January
2009.
*
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.
104
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON
SUPPLEMENTAL SCHEDULE
The Board
of Directors and Shareholders
Halliburton
Company:
Under
date of February 16, 2009, we reported on the consolidated balance sheets of
Halliburton Company and subsidiaries as of December 31, 2008 and 2007, 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, 2008,
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 and
accounting for defined benefit and other postretirement plans as of December 31,2006.
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 18th day of
February, 2009.
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 18th day of
February, 2009.