Annual Report — Form 10-K — Sect. 13 / 15(d) – SEA’34 Filing Table of Contents
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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 whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files).
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. [ X]
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”“accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act.:
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, 2009,
determined using the per share closing price on the New York Stock Exchange
Composite tape of $20.70 on that date was approximately
$18,573,000,000.
As of
February 12, 2010, there were 905,090,232 shares of Halliburton Company
Common Stock, $2.50 par value per share, outstanding.
Portions
of the Halliburton Company Proxy Statement for our 2010 Annual Meeting of
Stockholders (File No. 001-03492) are incorporated by reference into Part III of
this report.
Submission
of Matters to a Vote of Security Holders
6
PART II
Item
5.
Market
for Registrant’s Common Equity, Related Stockholder
Matters,
and Issuer Purchases of Equity
Securities
7
Item
6.
Selected
Financial Data
8
Item
7.
Management’s
Discussion and Analysis of Financial Condition and
Results of
Operations
8
Item
7(a).
Quantitative
and Qualitative Disclosures About Market Risk
8
Item
8.
Financial
Statements and Supplementary Data
9
Item
9.
Changes
in and Disagreements with Accountants on Accounting and
Financial
Disclosure
9
Item
9(a).
Controls
and Procedures
9
Item
9(b).
Other
Information
9
MD&A AND FINANCIAL
STATEMENTS
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
10
Management’s
Report on Internal Control Over Financial Reporting
46
Reports
of Independent Registered Public Accounting Firm
47
Consolidated
Statements of Operations
49
Consolidated
Balance Sheets
50
Consolidated
Statements of Shareholders’ Equity
51
Consolidated
Statements of Cash Flows
52
Notes
to Consolidated Financial Statements
53
Selected
Financial Data (Unaudited)
86
Quarterly
Data and Market Price Information (Unaudited)
87
PART III
Item
10.
Directors,
Executive Officers, and Corporate Governance
88
Item
11.
Executive
Compensation
88
Item
12(a).
Security
Ownership of Certain Beneficial Owners
88
Item
12(b).
Security
Ownership of Management
88
Item
12(c).
Changes
in Control
89
Item
12(d).
Securities
Authorized for Issuance Under Equity Compensation Plans
89
Item
13.
Certain
Relationships and Related Transactions, and Director
Independence
89
Item
14.
Principal
Accounting Fees and Services
89
PART IV
Item
15.
Exhibits
90
SIGNATURES
99
(i)
PART
I
Item
1. Business.
General
description of business
Halliburton
Company’s predecessor was established in 1919 and incorporated under the laws of
the State of Delaware in 1924. We provide a variety of services and
products to customers in the energy industry related to the exploration,
development, and production of oil and natural gas. We serve major,
national, and independent oil and natural gas companies throughout the world and
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 2 to the consolidated financial
statements for further financial information related to each of our business
segments and a description of the services and products provided by each
segment.
Business
strategy
Our
business strategy is to secure a distinct and sustainable competitive position
as an 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;
-
understanding
of the geological characteristics of the hydrocarbon
reservoir;
-
product
quality;
-
warranty;
and
-
technical
proficiency.
1
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 2009, based on the location of services provided and
products sold, 36% of our consolidated revenue was from the United
States. In 2008 and 2007, 43% and 44% 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 2 to the consolidated
financial statements for additional financial information about geographic
operations in the last three years. Because the markets for our
services and products are vast and cross numerous geographic lines, a meaningful
estimate of the total number of competitors cannot be made. The
industries we serve are highly competitive, and we have many substantial
competitors. Largely, all of our services and products are marketed
through our servicing and sales organizations.
Operations
in some countries may be adversely affected by unsettled political conditions,
acts of terrorism, civil unrest, expropriation or other governmental actions,
exchange control problems, and highly inflationary currencies. We
believe the geographic diversification of our business activities reduces the
risk that loss of operations in any one country would be material to the conduct
of our operations taken as a whole.
Information
regarding our exposure to foreign currency fluctuations, risk concentration, and
financial instruments used to minimize risk is included in “Management’s
Discussion and Analysis of Financial Condition and Results of Operations –
Financial Instrument Market Risk” and in Note 12 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, such as those related to high pressure/high temperature
environments. Our expenditures for research and development
activities were $325 million in 2009, $326 million in 2008, and $301 million in
2007, 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
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:
2
-
the
severity and duration of the winter in North America can have a
significant impact on natural 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.
Employees
At
December 31, 2009, we employed approximately 51,000 people worldwide compared to
approximately 57,000 at December 31, 2008. At December 31, 2009,
approximately 20% 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. For further information related to
environmental matters and regulation, see Note 8 to the consolidated financial
statements and “Management’s Discussion and Analysis of Financial Condition and
Results of Operations—Risk Factors” under the subheadings “Customers and
Business—Environmental requirements.”
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 facility is 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 Securities and Exchange Commission
(SEC). The public may read and copy any materials we have filed with
the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580,
Washington, DC 20549. Information on the operation of the Public
Reference Room may be obtained by calling the SEC at
1-800-SEC-0330. The SEC maintains an internet site that contains our
reports, proxy and information statements, and our other SEC
filings. The address of that site is www.sec.gov. We
have posted on our web site our Code of Business Conduct, which applies to all
of our employees and Directors and serves as a code of ethics for our principal
executive officer, principal financial officer, principal accounting officer,
and other persons performing similar functions. Any amendments to our
Code of Business Conduct or any waivers from provisions of our Code of Business
Conduct granted to the specified officers above are disclosed on our web site
within four business days after the date of any amendment or waiver pertaining
to these officers. There have been no waivers from provisions of our
Code of Business Conduct for the years 2009, 2008, or 2007.
The
following table indicates the names and ages of the executive officers of
Halliburton Company as of February 12, 2010, 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 42)
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 55)
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
* Albert
O. Cornelison, Jr.
Executive
Vice President and General Counsel of Halliburton
Company,
(Age 60)
since December
2002
David S. King
President,
Completion and Production Division of Halliburton
Company,
(Age 53)
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
* David
J. Lesar
Chairman
of the Board, President, and Chief Executive Officer of
Halliburton
(Age 56)
Company, since August
2000
4
Name and Age
Offices Held and Term of
Office
Ahmed H. M.
Lotfy
President,
Eastern Hemisphere of Halliburton Company, since January
2008
(Age 55)
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
* Mark
A. McCollum
Executive
Vice President and Chief Financial Officer of Halliburton
Company,
(Age 50)
since January
2008
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 48)
since January
2007
Vice
President and Treasurer of Halliburton Company, February
2006
to January
2007
Treasurer
of Colonial Pipeline Company, November 1999 to January
2006
* Lawrence
J. Pope
Executive
Vice President of Administration and Chief Human Resources
Officer
(Age 41)
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
* Timothy
J. Probert
President,
Global Business Lines and Corporate Development of
(Age 58)
Halliburton Company, since
January 2010
President,
Drilling and Evaluation Division and Corporate
Development of Halliburton
Company, March 2009 to December 2009
Executive
Vice President, Strategy and Corporate Development of
Halliburton
Company, January 2008 to March
2009
Senior
Vice President, Drilling and Evaluation of Halliburton
Company,
July 2007 to December
2007
Senior
Vice President, Drilling and 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.
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
Completion and Production
segment:
Arbroath, United
Kingdom
Owned
Manufacturing
facility
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
Nisku, Canada
Owned
Manufacturing
facility
Singapore
Leased
Manufacturing
and technology facility
The Woodlands,
Texas
Leased
Manufacturing
facility
Shared/corporate
facilities:
Carrollton,
Texas
Owned
Manufacturing
facility
Dubai, United Arab
Emirates
Leased
Corporate
executive offices
Duncan,
Oklahoma
Owned
Manufacturing,
technology, and campus facilities
Houston, Texas
Owned
Corporate
executive offices, manufacturing,
technology,
and campus facilities
Houston, Texas
Owned
Campus
facility
Houston, Texas
Leased
Campus
facility
Pune, India
Leased
Technology
facility
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 8 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 2009.
6
PART
II
Item
5. Market for Registrant’s Common Equity, Related Stockholder
Matters, and Issuer Purchases of Equity Securities.
Halliburton
Company’s common stock is traded on the New York Stock
Exchange. Information related to the high and low market prices of
common stock and quarterly dividend payments is included under the caption
“Quarterly Data and Market Price Information” on page 87 of this annual
report. Cash dividends on common stock in the amount of $0.09 per
share were paid in March, June, September, and December of 2009 and
2008. 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, 2009, 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, 2004, and the reinvestment of all dividends. The
shareholder return set forth is not necessarily indicative of future
performance.
December
31
2004
2005
2006
2007
2008
2009
Halliburton
$
100.00
$
159.46
$
161.23
$
198.84
$
96.52
$
162.37
Standard
& Poor’s 500 Stock Index
100.00
104.91
121.48
128.16
80.74
102.11
Standard
& Poor’s Energy Composite Index
100.00
131.37
163.16
219.30
142.83
162.57
At February 12, 2010, there
were 18,101 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.
7
Following
is a summary of repurchases of our common stock during the three-month period
ended December 31, 2009.
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
36,895
$
28.10
–
November
1-30
39,386
$
30.18
–
December
1-31
73,920
$
28.43
–
Total
150,201
$
28.81
–
(a)
All
of the 150,201 shares purchased during the three-month period ended
December 31, 2009 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 86 of this annual
report.
Item
7. Management’s Discussion and Analysis of Financial Condition and
Results of Operation.
Information
related to Management’s Discussion and Analysis of Financial Condition and
Results of Operations is included on pages 10 through 45 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 – Financial Instrument Market
Risk” on page 33 of this annual report.
8
Item
8. Financial Statements and Supplementary Data.
Page No.
Management’s
Report on Internal Control Over Financial Reporting
46
Reports
of Independent Registered Public Accounting Firm
47
Consolidated
Statements of Operations for the years ended December 31, 2009, 2008,
and
Consolidated
Statements of Cash Flows for the years ended December 31, 2009, 2008,
and
52
2007
Notes
to Consolidated Financial Statements
53
Selected
Financial Data (Unaudited)
86
Quarterly
Data and Market Price Information (Unaudited)
87
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, 2009 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, 2009 that has materially affected, or
is reasonably likely to materially affect, our internal control over financial
reporting.
See
page 46 for Management’s Report on Internal Control Over Financial
Reporting and page 47 for Report of Independent Registered Public
Accounting Firm on its assessment of our internal control over financial
reporting.
Item
9(b). Other Information.
None.
9
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 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 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, testing and
subsea, software and asset solutions, and integrated 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, Malaysia, Mexico, Brazil, and Singapore. With approximately
51,000 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
2009, we produced revenue of $14.7 billion and operating income of $2 billion,
reflecting an operating margin of 14%. Revenue decreased $3.6 billion or
20% from 2008, while operating income decreased $2 billion or 50% from
2008. These decreases were caused by a significant decline in our
customers’ capital spending as a result of the global recession and its impact
on commodity prices, which resulted in lower activity, lower pricing, and severe
margin contraction.
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 industry
activity, and the current excess supply of oil and natural gas, the near-term
outlook for our business and the industry remains
uncertain. Forecasting the depth and length of the current cycle is
challenging as it is different from past cycles due to the overlay of the
financial crisis in combination with broad demand weakness.
In North
America, the industry experienced an unprecedented decline in drilling activity
during 2009 as rig counts declined approximately 43% from 2008
highs. This decline, coupled with natural gas storage levels reaching
record levels, resulted in severe margin contraction in 2009. During
the fourth quarter of 2009, we saw some rebound in rig activity as conditions
began to improve with positive seasonal withdrawals from natural gas
storage. With the trend toward increasing levels of service
intensity, our equipment utilization is improving, and prices are stabilizing
across many areas. However, this rebound will require a sustained
increase in natural gas drilling activity. In order for this to
occur, we believe it will be important that North America exits the winter
heating season with storage levels in line with historical averages and there is
increased recovery in industrial demand.
10
Outside
of North America, 2009 rig count declined approximately 8% from 2008
highs. Margins declined throughout 2009, and we have not yet felt the
full impact of pricing concessions that were renegotiated during last year’s
contract retendering process. As such, we believe margins will
continue to be under pressure in 2010. We also believe that 2010 may
be a period of transition for this market. Oil supply/demand
fundamentals are showing some improvement as weak hydrocarbon demand shows signs
of recovery, but the timing of reinvestment remains uneven across geographies
and customers. Operators remain flexible in their spending patterns
and continue to be heavily focused on restraining oilfield price and cost
inflation.
Our operating performance and business
outlook are described in more detail in “Business Environment and Results of
Operations.”
Financial markets, liquidity, and
capital resources
Since
mid-2008, the global financial markets have been volatile. While this
has created additional risks for our business, we believe we have invested our
cash balances conservatively and secured sufficient financing to help mitigate
any near-term negative impact on our operations. To provide
additional liquidity and flexibility in the current environment, we issued $2
billion in senior notes during the first quarter of 2009 and invested $1.5
billion in United States Treasury securities during the second quarter of
2009. For additional information, see “Liquidity and Capital
Resources,”“Risk Factors,”“Business Environment and Results of Operations,”
and Notes 6 and 12 to the consolidated financial statements.
LIQUIDITY
AND CAPITAL RESOURCES
We ended
2009 with cash and equivalents of $2.1 billion compared to $1.1 billion at
December 31, 2008. We also held $1.3 billion of short-term, United
States Treasury securities at December 31, 2009.
Significant
sources of cash
Cash
flows from operating activities contributed $2.4 billion to cash in
2009. Our focus on managing working capital levels during the year
helped to offset the significant reduction in income during 2009.
In March
2009, we issued $1 billion of 6.15% senior notes due 2019 and $1 billion of
7.45% senior notes due 2039.
In 2009,
we sold approximately $300 million of United States Treasury
securities.
We
received payments of $90 million for our asbestos-related insurance settlements
during 2009.
Further available sources of
cash. We have an unsecured $1.2 billion, five-year revolving
credit facility 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, 2009. In addition, we have $1.3
billion in United States Treasury securities that will be maturing at various
dates through September 2010.
Significant
uses of cash
Capital
expenditures were $1.9 billion in 2009 and were predominantly made in the
production enhancement, drilling services, wireline and perforating, and
cementing product service lines.
During
2009, we purchased approximately $1.6 billion in United States Treasury
securities, with varying maturity dates.
We paid
$417 million to the Department of Justice (DOJ) and Securities and Exchange
Commission (SEC) in 2009 related to the settlements with them and under the
indemnity provided to KBR, Inc. (KBR) upon separation.
We paid
$324 million in dividends to our shareholders in 2009.
We
contributed $99 million to fund our defined benefit plans in
2009.
11
Future uses of
cash. Capital spending for 2010 is expected to
be approximately $2.0 billion. The capital expenditures plan for
2010 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 and efficiency. 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.
We
currently intend to retire our $750 million principal amount of 5.5% senior
notes at maturity in October 2010 with available cash and
equivalents.
As a
result of the resolution of the DOJ and SEC Foreign Corrupt Practices Act (FCPA)
investigations, we will pay a total of $142 million in equal installments over
the next three quarters for the settlement with the DOJ and under the indemnity
provided to KBR upon separation. See Notes 7 and 8 to our
consolidated financial statements for more information.
Subject
to Board of Directors approval, we expect to pay quarterly dividends of
approximately $80 million during 2010. We also have approximately
$1.8 billion remaining available under our share repurchase authorization, which
may be used for open market share purchases.
The
following table summarizes our significant contractual obligations and other
long-term liabilities as of December 31, 2009:
Payments
Due
Millions
of dollars
2010
2011
2012
2013
2014
Thereafter
Total
Long-term
debt
$
750
$
–
$
–
$
–
$
–
$
3,824
$
4,574
Interest
on debt (a)
304
263
263
262
262
5,622
6,976
Operating
leases
149
112
70
42
29
142
544
Purchase
obligations (b)
1,022
72
39
15
2
6
1,156
Pension
funding obligations (c)
38
–
–
–
–
–
38
DOJ
and SEC settlement and
indemnity
142
–
–
–
–
–
142
Other
long-term liabilities
9
9
9
9
–
–
36
Total
$
2,414
$
456
$
381
$
328
$
293
$
9,594
$
13,466
(a)
Interest
on debt includes 87 years of interest on $300 million of debentures at
7.6% interest that become due in
2096.
(b)
Primarily
represents certain purchase orders for goods and services utilized in the
ordinary course of our business.
(c)
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 2010. See Note 13 to the consolidated financial
statements for further information regarding pension
contributions.
We had
$292 million of gross unrecognized tax benefits at December 31, 2009, of which
we estimate $43 million may require a cash payment. We estimate that
$12 million of the total $43 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.
12
Other
factors affecting liquidity
Letters of
credit. In the normal course of business, we have agreements
with financial institutions under which approximately $1.8 billion of letters of
credit, bank guarantees, or surety bonds were outstanding as of December 31,2009, including $380 million of surety bonds related to Venezuela. In
addition, $390 million of the total $1.8 billion relates to KBR letters of
credit, bank guarantees, or surety bonds that 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. Our $2.1 billion of cash and equivalents and $1.3
billion in investments in marketable securities as of December 31, 2009 provide
sufficient liquidity and flexibility, given the current market environment.
Our debt maturities extend over a long period of time. We
currently have a total of $1.2 billion of committed bank credit under our
revolving credit facility to support our operations and any commercial paper we
may issue in the future. We have no financial covenants or material
adverse change provisions in our bank agreements. Currently, there
are no borrowings under the revolving credit facility. Although a
portion of earnings from our foreign subsidiaries is reinvested overseas
indefinitely, we do not consider this to have a significant impact on our
liquidity.
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 line with industry practice, 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. For example, we have seen a delay in
receiving payment on our receivables from one of our primary customers in
Venezuela. However, during the fourth quarter of 2009, we reached a
settlement with this customer and received payment on approximately one-third of
our outstanding receivables. 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.
13
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 natural 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 2009, based upon the location of the services
provided and products sold, 36% of our consolidated revenue was from the United
States. In 2008, 43% of our consolidated revenue was from the United
States. No other country accounted for more than 10% of our revenue
during these periods.
Operations
in some countries may be adversely affected by unsettled political conditions,
acts of terrorism, civil unrest, force majeure, war or other armed conflict,
expropriation or other governmental actions, inflation, exchange control
problems, and highly inflationary currencies. We believe the
geographic diversification of our business activities reduces the risk that loss
of operations in any one country would be materially adverse 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 natural 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
natural gas companies are oil and natural gas prices, the world economy, the
availability of credit, 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 average oil and natural gas prices for West Texas Intermediate
(WTI), United Kingdom Brent crude oil, and Henry Hub natural gas:
Average Oil Prices
(dollars per barrel)
2009
2008
2007
West
Texas Intermediate
$
61.65
$
99.37
$
71.91
United
Kingdom Brent
$
61.49
$
96.86
$
72.21
Average United States Gas
Prices (dollars per thousand cubic
feet, or mcf)
Henry
Hub
$
4.06
$
9.13
$
7.18
14
The
historical yearly average rig counts based on the Baker Hughes Incorporated rig
count information were as follows:
Land
vs. Offshore
2009
2008
2007
United
States:
Land
1,042
1,812
1,694
Offshore (incl. Gulf of
Mexico)
44
65
73
Total
1,086
1,877
1,767
Canada:
Land
220
378
341
Offshore
1
1
3
Total
221
379
344
International
(excluding Canada):
Land
722
784
719
Offshore
275
295
287
Total
997
1,079
1,006
Worldwide
total
2,304
3,335
3,117
Land
total
1,984
2,974
2,754
Offshore
total
320
361
363
Oil
vs. Natural Gas
2009
2008
2007
United
States (incl. Gulf of Mexico):
Oil
282
384
300
Natural Gas
804
1,493
1,467
Total
1,086
1,877
1,767
Canada:
Oil
102
160
128
Natural Gas
119
219
216
Total
221
379
344
International
(excluding Canada):
Oil
776
825
776
Natural Gas
221
254
230
Total
997
1,079
1,006
Worldwide
total
2,304
3,335
3,117
Oil
total
1,160
1,369
1,204
Natural
Gas total
1,144
1,966
1,913
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.
15
WTI oil
spot prices fell from a high of approximately $145 per barrel in July 2008 to a
low of approximately $30 per barrel in December 2008. Since then
prices have rebounded. As noted above, during 2009, the WTI spot
price averaged $61.65 per barrel. As of February 12, 2010 the WTI oil
spot price was $74.13 per barrel. According to the International
Energy Agency’s (IEA) February 2010 “Oil Market Report,” 2010 world petroleum
demand is forecasted to increase 2% over 2009 levels. Despite the
overall decline in oil and natural gas prices from 2008 levels 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. In 2009, we experienced an
unprecedented decline in drilling activity as rig count dropped approximately
43% from 2008 highs. Correlating with this decline, the Henry Hub
spot price decreased from an average of $9.13 per mcf in 2008 to $4.06 per mcf
in 2009. As of February 12, 2010, the Henry Hub spot price was $5.65
per mcf. Weak domestic natural gas demand, coupled with the
productivity of new shale resources, led to natural gas storage reaching record
levels in 2009 and severe margin compression. We saw some rebound in
rig activity toward the end of 2009 as conditions began to improve with seasonal
withdrawals from natural gas storage. With the trend toward
increasing levels of service intensity, our equipment utilization is improving,
and prices are stabilizing across many areas. However, this rebound
will require a sustained increase in natural gas drilling
activity. For activity levels to improve, we believe it will be
important that North America exits the winter heating season with storage levels
in line with historical averages and there is increased recovery in industrial
demand.
International
operations
Consistent
with our long-term strategy to grow our operations outside of North America, we
expect to continue to invest capital in our international
operations. During 2009, international energy services activity
declined as well, but not to the extent the North American market
fell. As of December 31, 2009, the international rig count had
declined approximately 8% from 2008 highs. International margins
declined throughout 2009, and we have not yet felt the full impact of pricing
concessions that were renegotiated during last year’s contract retendering
process. As such, we believe margins will continue to be under
pressure in 2010. We also believe that 2010 may be a period of
transition for this market. Oil supply/demand fundamentals are
showing some improvement as weak global hydrocarbon demand shows signs of
recovery, but the timing of reinvestment remains uneven across geographies and
customers. Operators are remaining flexible in their spending
patterns and continue to be heavily focused on restraining oilfield price and
cost inflation.
Venezuela. In
January 2010, the Venezuelan government announced a devaluation of the Bolívar
Fuerte under a new two-exchange rate system; one rate for essential products and
the other rate for non-essential products. As a result of the
devaluation, we are estimating a loss of approximately $30 million in the first
quarter of 2010 based on our current understanding of how the new two-exchange
rate system will work for oil services activity. Our estimate
utilizes a 4.3 Bolívar Fuerte to United States dollar exchange
rate.
Following
is a brief discussion of some of our recent and current
initiatives:
-
leveraging
our technologies to deploy our packaged-services strategy to provide our
customers with the ability to more efficiently drill and complete their
wells, especially in service-intensive environments such as deepwater and
shale plays;
-
retaining
key investments in technology and capital to accelerate growth
opportunities;
-
increasing
our market share in unconventional and deepwater markets by enhancing our
technological position and leveraging our technical expertise and wide
portfolio of products and services;
-
lowering
our input costs from vendors by negotiating price reductions for both
materials used in our operations and those utilized in the manufacturing
of capital equipment;
-
negotiating
with our customers to trade an expansion of scope and a lengthening of
contract duration for price
concessions;
-
optimizing
headcount in locations experiencing significant changes in
activity;
-
improving
working capital, operating within our cash flow, and managing our balance
sheet to maximize our financial
flexibility;
-
continuing
the globalization of our manufacturing and supply chain processes,
preserving work at our lower-cost manufacturing centers, and utilizing our
international infrastructure to lower costs from our supply chain through
delivery;
-
expanding
our business with national oil companies;
and
-
minimizing
discretionary spending.
Contract
wins positioning us to grow our operations over the long term
include:
-
a
five-year integrated turnkey drilling contract, with an option for an
additional five-year period, which includes drilling and completion
activities in South Ghawar, Saudi Arabia;
-
a
three-year, $122 million contract, to provide drilling and completion
fluid solutions in Indonesia;
-
a
three-year technical cooperation agreement by Brazil’s state energy
company for research and development in Brazil’s subsalt
areas;
-
a
two-year, $229 million contract with multiple extension options, to
provide drilling fluids and associated services in
Norway;
-
a
three-year contract renewal for continued access to a broad suite of
software technology and petro-technical consulting services for the
development, deployment, and ongoing global support of exploration and
production technology and workflows;
-
a
five-year, $1.5 billion contract to provide a broad base of products and
services to an international oil company for its work associated with
North America;
-
several
wins totaling $1 billion, including $700 million to provide deepwater
drilling fluid services in the Gulf of Mexico, Brazil, Indonesia, Angola,
and other countries, which solidifies our position in the deepwater
drilling fluids market and $300 million for shelf- and land-related work;
and
-
a
two-year contract extension, estimated to be valued at $450 million, to
provide cementing services and completion and drilling fluids for
StatoilHydro in offshore fields on the Norwegian continental
shelf.
17
-
a
five-year, $190 million contract to provide drilling fluid, completion
fluid, and drilling waste management services for Petrobras in the
offshore markets of Brazil;
-
a
five-year, $100 million contract to provide directional-drilling and
logging-while-drilling services in the Middle
East;
-
a
contract award in Algeria to provide integrated project management
services for a number of delineation wells initially with the potential to
expand to 120 wells for full field
development;
-
a
four-year contract to provide directional-drilling,
measurement-while-drilling, and logging-while-drilling, along with
drilling fluids and cementing services in Russia;
and
-
a
multi-year contract scheduled to commence in 2010 to provide completion
products and services and drilling and completion fluids in the deepwater,
offshore fields of Angola.
18
RESULTS
OF OPERATIONS IN 2009 COMPARED TO 2008
REVENUE:
Increase
Percentage
Millions
of dollars
2009
2008
(Decrease)
Change
Completion
and Production
$
7,419
$
9,610
$
(2,191
)
(23
)%
Drilling
and Evaluation
7,256
8,669
(1,413
)
(16
)
Total
revenue
$
14,675
$
18,279
$
(3,604
)
(20
)%
By
geographic region:
Completion
and Production:
North America
$
3,589
$
5,327
$
(1,738
)
(33
)%
Latin America
887
978
(91
)
(9
)
Europe/Africa/CIS
1,771
1,938
(167
)
(9
)
Middle
East/Asia
1,172
1,367
(195
)
(14
)
Total
7,419
9,610
(2,191
)
(23
)
Drilling
and Evaluation:
North America
2,073
3,013
(940
)
(31
)
Latin America
1,294
1,447
(153
)
(11
)
Europe/Africa/CIS
2,177
2,408
(231
)
(10
)
Middle
East/Asia
1,712
1,801
(89
)
(5
)
Total
7,256
8,669
(1,413
)
(16
)
Total
revenue by region:
North America
5,662
8,340
(2,678
)
(32
)
Latin America
2,181
2,425
(244
)
(10
)
Europe/Africa/CIS
3,948
4,346
(398
)
(9
)
Middle
East/Asia
2,884
3,168
(284
)
(9
)
19
OPERATING
INCOME:
Increase
Percentage
Millions
of dollars
2009
2008
(Decrease)
Change
Completion
and Production
$
1,016
$
2,304
$
(1,288
)
(56
)%
Drilling
and Evaluation
1,183
1,970
(787
)
(40
)
Corporate
and other
(205
)
(264
)
59
22
Total
operating income
$
1,994
$
4,010
$
(2,016
)
(50
)%
By
geographic region:
Completion
and Production:
North America
$
272
$
1,426
$
(1,154
)
(81
)%
Latin America
172
214
(42
)
(20
)
Europe/Africa/CIS
315
360
(45
)
(13
)
Middle
East/Asia
257
304
(47
)
(15
)
Total
1,016
2,304
(1,288
)
(56
)
Drilling
and Evaluation:
North America
178
679
(501
)
(74
)
Latin America
187
307
(120
)
(39
)
Europe/Africa/CIS
380
497
(117
)
(24
)
Middle
East/Asia
438
487
(49
)
(10
)
Total
1,183
1,970
(787
)
(40
)
Total
operating income by region
(excluding Corporate and
other):
North America
450
2,105
(1,655
)
(79
)
Latin America
359
521
(162
)
(31
)
Europe/Africa/CIS
695
857
(162
)
(19
)
Middle
East/Asia
695
791
(96
)
(12
)
Note–
All periods presented reflect the movement of certain operations from
the Completion and Production segment to the Drilling and Evaluation
segment during the first quarter of 2009.
The 20% decline in consolidated revenue in 2009 compared to 2008 was primarily
due to pricing declines and lower demand for our products and services in North
America due to a significant reduction in rig count. As a result of
an approximate 42% reduction in average rig count in North America during 2009
compared to 2008, we experienced a 32% decline in North America revenue from
2008. Revenue outside of North America was 61% of consolidated
revenue in 2009 and 54% of consolidated revenue in 2008.
The
decrease in consolidated operating income compared to 2008 primarily stemmed
from a 79% decrease in North America due to a decline in rig count and severe
margin contraction, a $73 million charge associated with employee separation
costs, and a $15 million charge related to the settlement of a customer
receivable in Venezuela. Operating income in 2008 was favorably
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 approximately $52 million as a result of hurricanes in the Gulf of Mexico, a
$23 million impairment charge related to an oil and natural gas property in
Bangladesh, and a $22 million acquisition-related charge for
WellDynamics.
20
Following
is a discussion of our results of operations by reportable segment.
Completion and Production
decrease in revenue compared to 2008 was primarily a result of overall pricing
declines and lower demand for our products and services in North
America. More specifically, North America revenue fell 33% as a
result of pricing declines and a drop in demand for production enhancement
services and cementing services. Latin America revenue decreased 9%
as increased activity for all product service lines in Mexico and Colombia was
outweighed by lower activity across all product service lines in Venezuela and
Argentina. Europe/Africa/CIS revenue decreased 9% on lower demand for
completion tools and services in Africa. In addition, production
enhancement services in Europe were negatively impacted by job delays in the
North Sea. Middle East/Asia revenue fell 14% due to job delays and a
decrease in demand for all products and services in the Middle
East. Revenue outside of North America was 52% of total segment
revenue in 2009 and 45% of total segment revenue in 2008.
The
Completion and Production segment operating income decrease compared to 2008 was
primarily due to the North America region, where operating income fell 81%
largely due to pricing declines and significant reductions in rig count
resulting in lower demand for our products and services. Results in
2009 were adversely impacted by $34 million in employee separation
costs. In 2008, North America was negatively impacted by
approximately $25 million due to Gulf of Mexico hurricanes but benefited from a
$35 million gain on the sale of a joint venture interest. Latin
America operating income decreased 20% driven by lower activity across all
product service lines in Venezuela and Argentina. Europe/Africa/CIS
operating income decreased 13% as improved cost management and higher demand for
cementing services across the region were outweighed by job delays and lower
demand for completion tools and services in Africa and production enhancement
services in the North Sea and Angola. Middle East/Asia
operating income decreased 15% primarily due to lower completion tools sales in
Saudi Arabia and lower demand for production enhancement services in Oman and
Malaysia.
Drilling and Evaluation
revenue decrease compared to 2008 was primarily a result of pricing declines and
decreased demand for our products and services stemming from a reduction in rig
count in North America, where revenue fell 31%. Latin America revenue
fell 11% as increased drilling activity in Brazil was outweighed by lower demand
for all product service lines in Venezuela, Argentina, and
Colombia. Europe/Africa/CIS revenue decreased 10% as increases in
software sales and consulting services in Algeria were offset by decreased
demand for drilling fluids services in Nigeria and Angola and drilling services
in Europe. Pricing pressure also had a significant impact on revenue
in Europe and Russia. Middle East/Asia revenue decreased 5% as
increased demand for drilling fluid services and testing and subsea services in
Asia Pacific were outweighed by lower drilling activity in the Middle East and
declines in software sales and consulting services and wireline and perforating
services in Asia Pacific. Revenue outside of North America was 71% of
total segment revenue in 2009 and 65% of total segment revenue in
2008.
21
The
decrease in segment operating income compared to 2008 was primarily due to a 74%
decrease in North America operating income related to pricing declines and rig
count reductions. Results in 2009 were also adversely impacted by $34
million in employee separation costs. In 2008, this segment’s results
were negatively impacted by approximately $27 million due to Gulf of Mexico
hurricanes and a $23 million impairment charge related to an oil and natural gas
property in Bangladesh, but benefited from $25 million of gains related to the
sale of two investments in the United States. Latin America operating
income fell 39% primarily due to lower activity across all product service lines
in Venezuela and decreased demand and pricing pressure for drilling services and
wireline and perforating services in Argentina, Colombia, and
Mexico. The region was also adversely affected by a $12 million
charge related to the settlement of a customer receivable in
Venezuela. The Europe/Africa/CIS region operating income fell 24% as
increased demand for drilling fluid services in Norway and Kazakhstan and
increased software sales and consulting services in Africa were outweighed by
pricing pressures and decreased drilling activity in Europe and lower demand for
drilling fluid services in Africa. Middle East/Asia operating income
decreased 10% over 2008 as declines in drilling activity in Saudi Arabia and
China outweighed an increase in software sales and consulting services in the
Middle East and higher demand for testing and subsea services in
Asia. This region was negatively impacted by the impairment charge
related to an oil and natural gas property in Bangladesh in 2008.
Corporate and other expenses
were $205 million in 2009 compared to $264 million in 2008. The 2009
results include $5 million in employee separation costs. The 22%
reduction was primarily attributable to our 2009 focus on reducing discretionary
spending and optimizing headcount and a $22 million acquisition-related charge
for WellDynamics related to employee incentive compensation awards in
2008. 2008 also included a net $5 million gain on the settlement of
two patent disputes.
NONOPERATING
ITEMS
Interest expense increased
$130 million in 2009 compared to 2008 primarily due to the issuance of $2
billion in senior notes during the first quarter of 2009, partially offset by
the redemption of our convertible senior notes early in the third quarter of
2008.
Interest income decreased $27
million in 2009 compared to 2008 due to a general decline in market interest
rates.
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
assumption changes during that period regarding the resolution of the
Barracuda-Caratinga bolt arbitration matter under the indemnities and guarantees
provided to KBR upon separation.
Noncontrolling interest in net
income of subsidiaries increased $19 million compared to 2008, primarily
related to the impact of a change in effective ownership of a joint venture in
2008.
22
RESULTS
OF OPERATIONS IN 2008 COMPARED TO 2007
REVENUE:
Percentage
Millions
of dollars
2008
2007
Increase
Change
Completion
and Production
$
9,610
$
8,138
$
1,472
18
%
Drilling
and Evaluation
8,669
7,126
1,543
22
Total
revenue
$
18,279
$
15,264
$
3,015
20
%
By
geographic region:
Completion
and Production:
North America
$
5,327
$
4,632
$
695
15
%
Latin America
978
668
310
46
Europe/Africa/CIS
1,938
1,689
249
15
Middle
East/Asia
1,367
1,149
218
19
Total
9,610
8,138
1,472
18
Drilling
and Evaluation:
North America
3,013
2,501
512
20
Latin America
1,447
1,130
317
28
Europe/Africa/CIS
2,408
2,011
397
20
Middle
East/Asia
1,801
1,484
317
21
Total
8,669
7,126
1,543
22
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
$
2,304
$
2,119
$
185
9
%
Drilling
and Evaluation
1,970
1,565
405
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
$
1,426
$
1,418
$
8
1
%
Latin America
214
133
81
61
Europe/Africa/CIS
360
300
60
20
Middle
East/Asia
304
268
36
13
Total
2,304
2,119
185
9
Drilling
and Evaluation:
North America
679
538
141
26
Latin America
307
216
91
42
Europe/Africa/CIS
497
444
53
12
Middle
East/Asia
487
367
120
33
Total
1,970
1,565
405
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
Note–
All periods presented reflect the movement of certain operations from
the Completion and Production segment to the Drilling and Evaluation
segment during the first quarter of 2009
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. Revenue outside of North America was 54% of consolidated
revenue in 2008 and 53% 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 natural 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 natural 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 15% 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 46% 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. Revenue
outside of North America was 45% of total segment revenue in 2008 and 43% in
2007.
The
increase in segment operating income in 2008 compared to 2007 spanned all
regions. Europe/Africa/CIS operating income increased 20% from
increased completion tools sales and services in Africa and higher production
enhancement activity in Europe. Middle East/Asia operating income
increased 13% primarily due to increased sales and service revenue from
completion tools and increased production enhancement activity in the
region. North America operating income was essentially 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 61% 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 20% 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 20% 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 28% 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. Revenue outside of North America was 65% of
total segment revenue in 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 12% 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 33% 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 natural gas property in
Bangladesh. North America operating income increased 26% 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 42% 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 a $31 million
loss on foreign exchange due to the general weakening of the United States
dollar against certain foreign currencies.
Provision for income taxes
from continuing operations of $1.2 billion in 2008 resulted in an effective tax
rate of 31% compared to an effective tax rate of 26% in 2007. The
lower tax rate in 2007 is primarily related to a $205 million favorable income
tax impact from the ability to recognize foreign tax credits previously
estimated not to be fully utilizable.
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 assumption changes during that period 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.
Noncontrolling interest in net
income of subsidiaries decreased $59 million compared to 2007, primarily
related to a change in effective ownership of a joint venture in
2008.
26
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;
-
legal
and investigation matters;
-
valuations
of indemnities;
-
valuations
of long-lived assets, including intangible
assets;
-
purchase
price allocation for acquired
businesses;
-
pensions;
-
allowance
for bad debts; and
-
percentage-of-completion
accounting for long-term, construction-type
contracts.
We base
our estimates on historical experience and on various other assumptions we
believe to be reasonable according to the current facts and circumstances, the
results of which form the basis for making judgments about the carrying values
of assets and liabilities that are not readily apparent from other
sources. We believe the following are the critical accounting
policies used in the preparation of our consolidated financial statements, as
well as the significant estimates and judgments affecting the application of
these policies. This discussion and analysis should be read in
conjunction with our consolidated financial statements and related notes
included in this report.
We have
discussed the development and selection of these critical accounting policies
and estimates with the Audit Committee of our Board of Directors, and the Audit
Committee has reviewed the disclosure presented below.
Income
tax accounting
We
recognize the amount of taxes payable or refundable for the current year and use
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.
27
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.
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 current accounting standards,
which prescribe 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. They also
provide guidance for derecognition classification, interest and penalties,
accounting in interim periods, disclosure, and transition.
28
Legal
and investigation matters
As
discussed in Note 8 of our consolidated financial statements, as of December 31,2009, 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 7 and 8 to the consolidated financial statements for
further information. Accounting standards require recognition of
third-party indemnities at their inception. Therefore, 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. The
accounting standards state that the subsequent measurement of such liabilities
should not necessarily be based on fair value. The standards
reference accounting for subsequent adjustments to these types of liabilities as
you would under the current accounting guidance for 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.
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, goodwill, and other intangibles. 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. 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.
29
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. 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 2009, 2008, and 2007. 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.
Pensions
Our
pension benefit obligations and expenses are calculated using actuarial models
and methods. 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 long-term rate of return on
plan assets used in determining net periodic pension expense. Other
critical assumptions and estimates used in determining benefit obligations and
plan expenses, including demographic factors such as retirement age, mortality,
and turnover, are also evaluated periodically and updated accordingly to reflect
our actual experience.
Discount
rates are determined annually and are based on the prevailing market rate of a
portfolio of high-quality debt instruments with maturities matching the expected
timing of the payment of the benefit obligations. Expected long-term
rates of return on plan assets are determined annually and are based on an
evaluation of our plan assets 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.
30
The
discount rates utilized in 2009 to determine the projected benefit obligation at
the measurement date for our qualified United States continuing pension plans
ranged from 5.5% to 6.0%, compared to a range of 5.7% to 5.8% in
2008. The discount rate utilized in 2009 to determine the projected
benefit obligation at the measurement date for our United Kingdom pension plan,
which constitutes 74% of our international plans’ pension obligations and 65% of
our entire pension obligation, was 5.9%, compared to a discount rate of 5.8%
utilized in 2008. The expected long-term rate of return assumption
used for determining 2009 and 2008 net periodic pension expense for our
qualified United States pension plans was 8.0%. The expected
long-term rate of return assumption used for our United Kingdom pension plan
expense was 6.5% in 2009 and 7.0% in 2008. The following table
illustrates the sensitivity to changes in certain assumptions, holding all other
assumptions constant, for the United Kingdom pension plan.
25-basis-point
decrease in expected long-term rate of return
$
1
NA
25-basis-point
increase in expected long-term rate of return
$
(1)
NA
Our
defined benefit plans reduced pretax income by $36 million in 2009 and $48
million in both 2008 and 2007. Included in these amounts was income
from our expected pension returns of $45 million in 2009, $51 million in 2008,
and $47 million in 2007. Actual returns on plan assets were $121
million in 2009, compared to actual losses on plan assets of $144 million in
2008. 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 and the impact of changes to assumptions affecting the benefit
obligations are deferred and recorded net of tax in other comprehensive income
as actuarial gain or loss and are recognized as future pension
expense. Our net actuarial loss, net of tax, related to pension plans
at December 31, 2009 was $185 million. In our international plans
where employees continue to earn additional benefits for continued service,
unrecognized actuarial gains and losses are being recognized over a period of 6
to 19 years, which represents the expected average remaining service of the
participant group expected to receive benefits. In our international
plans where benefits are not accrued for continued service, unrecognized
actuarial gains and losses are being recognized over a period of 20 to 36 years,
which represents the average remaining life expectancy of the participant group
expected to receive benefits.
During
2009, we made contributions of $99 million to fund our defined benefit
plans. Of this amount, we contributed $71 million to our United
Kingdom plan in 2009, $66 million of which was a discretionary contribution in
conjunction with amending the plan to cease benefit accruals for service after
June 30, 2009. We expect to make contributions of approximately $38
million to our defined benefit plans in 2010.
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 13 to the consolidated financial statements for
further information related to defined benefit and other postretirement benefit
plans.
31
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 retainages. 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
3.0%. At December 31, 2009, allowance for bad debts totaled $90
million or 3.0% of notes and accounts receivable before the allowance, and at
December 31, 2008, allowance for bad debts totaled $60 million or 1.6% of notes
and accounts receivable before the allowance. A 1% change in our
estimate of the collectability of our notes and accounts receivable balance as
of December 31, 2009 would have resulted in a $30 million adjustment to 2009
total operating costs and expenses.
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.
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 current
accounting standards. 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.
32
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.
OFF
BALANCE SHEET ARRANGEMENTS
At
December 31, 2009, we had no material off balance sheet arrangements, except for
operating leases. For information on our contractual obligations
related to operating leases, see “Management’s Discussion and Analysis of
Financial Condition and Results of Operations – Liquidity and Capital Resources
– Future uses of cash.”
FINANCIAL
INSTRUMENT MARKET RISK
We are
exposed to market risk from changes in foreign currency exchange rates, interest
rates, and commodity prices. We selectively manage these exposures
through the use of derivative instruments to mitigate our market risk from these
exposures. The objective of our risk management strategy is to
minimize the volatility from fluctuations in foreign currency
rates. Our use of derivative instruments entails the following types
of market risk:
-
volatility
of the currency rates;
-
counterparty
credit risk;
-
time
horizon of the derivative instruments;
and
-
the
type of derivative instruments
used.
We do not
use derivative instruments for trading purposes. 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 12 to
the consolidated financial statements for additional disclosures related to
financial instruments.
Interest
rate risk
We
currently do not have any 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, 2009 and related weighted average interest rates on the repayment amounts by
year of maturity for our long-term debt.
2017
and
Millions
of dollars
2010
Thereafter
Total
Repayment amount
($US)
$
750
$
3,834
$
4,584
Weighted
average
interest rate
on
repayment
amount
5.5
%
6.9
%
6.6
%
The fair
market value of long-term debt was $5.3 billion as of December 31,2009.
33
ENVIRONMENTAL
MATTERS
We are
subject to numerous environmental, legal, and regulatory requirements related to
our operations worldwide. For information related to environmental
matters, see Note 8 to the consolidated financial statements and “Risk
Factors—Customers and Business” under the subheading “Environmental
requirements.”
NEW
ACCOUNTING PRONOUNCEMENTS
In
October 2009, the FASB issued an update to existing guidance on revenue
recognition for arrangements with multiple deliverables. This update
will allow companies to allocate consideration received for qualified separate
deliverables using estimated selling price for both delivered and undelivered
items when vendor-specific objective evidence or third-party evidence is
unavailable. Additional disclosures discussing the nature of multiple
element arrangements, the types of deliverables under the arrangements, the
general timing of their delivery, and significant factors and estimates used to
determine estimated selling prices are required. We will adopt this
update for new revenue arrangements entered into or materially modified
beginning January 1, 2011. We have not yet determined the impact on
our consolidated financial statements.
In June
2009, the FASB issued a new accounting standard which provides amendments to
previous guidance on the consolidation of variable interest
entities. This standard clarifies
the characteristics that identify a variable interest entity (VIE) and changes
how a reporting entity identifies a primary beneficiary that would consolidate
the VIE from a quantitative risk and rewards calculation to a qualitative
approach based on which variable interest holder has controlling financial
interest and the ability to direct the most significant activities that impact
the VIE’s economic performance. This standard requires the primary
beneficiary assessment to be performed on a continuous basis. It also
requires additional disclosures about an entity’s involvement with a VIE,
restrictions on the VIE’s assets and liabilities that are included in the
reporting entity’s consolidated balance sheet, significant risk exposures due to
the entity’s involvement with the VIE, and how its involvement with a VIE
impacts the reporting entity’s consolidated financial statements. The standard
is effective for fiscal years beginning after November 15, 2009. We
adopted the standard on January 1, 2010, and it will not have a material impact
on our consolidated financial statements.
FORWARD-LOOKING
INFORMATION
The
Private Securities Litigation Reform Act of 1995 provides safe harbor provisions
for forward-looking information. Forward-looking information is based
on projections and estimates, not historical information. Some
statements in this Form 10-K are forward-looking and use words like “may,”“may
not,”“believes,”“do not believe,”“expects,”“do not expect,”“anticipates,”“do not anticipate,” and other expressions. We may also provide oral
or written forward-looking information in other materials we release to the
public. Forward-looking information involves risk and uncertainties
and reflects our best judgment based on current information. Our
results of operations can be affected by inaccurate assumptions we make or by
known or unknown risks and uncertainties. In addition, other factors
may affect the accuracy of our forward-looking information. As a
result, no forward-looking information can be guaranteed. Actual
events and the results of operations may vary materially.
We do not
assume any responsibility to publicly update any of our forward-looking
statements regardless of whether factors change as a result of new information,
future events, or for any other reason. You should review any
additional disclosures we make in our press releases and Forms 10-K, 10-Q, and
8-K filed with or furnished to the SEC. We also suggest that you
listen to our quarterly earnings release conference calls with financial
analysts.
34
RISK
FACTORS
While it
is not possible to identify all risk factors, we continue to face many risks and
uncertainties that could cause actual results to differ from our forward-looking
statements and could otherwise have a material adverse effect on our liquidity,
consolidated results of operations, and consolidated financial
condition.
Foreign
Corrupt Practices Act Investigations
Background. As a
result of an ongoing FCPA investigation at the time of the KBR separation, 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 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% beneficial interest in
the venture. Part of KBR’s ownership in TSKJ was held through M.W.
Kellogg Limited (MWKL), a United Kingdom joint venture and subcontractor on the
Bonny Island project, in which KBR beneficially owns a 55%
interest. 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).
DOJ and SEC investigations
resolved. In February 2009, the FCPA investigations by the DOJ
and the SEC were resolved with respect to KBR and us. 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 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 did not provide a monitor for us.
As part
of the resolution of the SEC investigation, we retained 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 agreed to adopt
any necessary anti-bribery and foreign agent internal controls and
record-keeping procedures recommended by the independent
consultant. The review and evaluation were completed during the
second quarter of 2009, and we have implemented the consultant’s immediate
recommendations and will implement the remaining long-term recommendations by
mid-year 2010. As a result of the substantial enhancement of our
anti-bribery and foreign agent internal controls and record-keeping procedures
prior to the review of the independent consultant, we do not expect the
implementation of the consultant’s recommendations to materially impact our
long-term strategy to grow our international operations. 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 and to recommend any additional
improvements.
35
KBR has
agreed that our indemnification obligations with respect to the DOJ and SEC FCPA
investigations have been fully satisfied.
Other matters. In
addition to the DOJ and the SEC investigations, we are aware of other
investigations in France, Nigeria, the United Kingdom, and Switzerland regarding
the Bonny Island project. In the United Kingdom, the Serious Fraud
Office (SFO) is considering civil claims or criminal prosecution under various
United Kingdom laws and appears to be focused on the actions of MWKL, among
others. Violations of these laws could result in fines, restitution
and confiscation of revenues, among other penalties, some of which could be
subject to our indemnification obligations under the master separation
agreement. Our indemnity for penalties under the master separation agreement
with respect to MWKL is limited to 55% of such penalties, which is KBR’s
beneficial ownership interest in MWKL. MWKL is cooperating with the
SFO’s investigation. Whether the SFO pursues civil or criminal
claims, and the amount of any fines, restitution, confiscation of revenues or
other penalties that could be assessed would depend on, among other factors, the
SFO’s findings regarding the amount, timing, nature and scope of any improper
payments or other activities, whether any such payments or other activities were
authorized by or made with knowledge of MWKL, the amount of revenue involved,
and the level of cooperation provided to the SFO during the
investigations. MWKL has informed the SFO that it intends to
self-report corporate liability for corruption-related offenses arising out of
the Bonny Island project. Based on discussions with the SFO, MWKL
expects to receive confirmation that it will be admitted into the plea
negotiation process under the Guidelines on Plea Discussions in Cases of Complex
or Serious Fraud, which have been issued by the Attorney General for England and
Wales.
The DOJ
and SEC 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.
Our
indemnity of KBR and its majority-owned subsidiaries 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.
At this
time, other than the claims being considered by the SFO, no claims by
governmental authorities in foreign jurisdictions have been asserted against the
indemnified parties. Therefore, we are unable to estimate the maximum
potential amount of future payments that could be required to be made under our
indemnity to KBR and its majority-owned subsidiaries related to these
matters. An adverse determination or result against us or any party
indemnified by us in any investigation or third-party claim related to these
FCPA matters could have a material adverse effect on our liquidity, consolidated
results of operations, and consolidated financial condition. See Note
7 to our consolidated financial statements for additional
information.
36
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.
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. We understand KBR believes several possible solutions may
exist, including replacement of the bolts. Initial estimates by KBR
indicated that costs of these various solutions ranged 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 this matter and has submitted a counterclaim in the arbitration
seeking the recovery of $22 million. The arbitration panel held an
evidentiary hearing in March 2008 to determine which party is responsible for
the designation of the material used for the bolts. On May 13, 2009,
the arbitration panel held that KBR and not Petrobras selected the material to
be used for the bolts. Accordingly, the arbitration panel held
that there is no implied warranty by Petrobras to KBR as to the suitability
of the bolt material and that the parties' rights are to be governed by the
express terms of their contract. The arbitration panel set the final
hearing on liability and damages for early May 2010. 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, 2009 and December 31, 2008. An adverse
determination or result against KBR in the arbitration could have a material
adverse effect on our liquidity, consolidated results of operations, and
consolidated financial condition. See Note 7 to our consolidated
financial statements for additional information regarding the KBR
indemnification.
Impairment
of Oil and Natural Gas Properties
We have
interests in oil and natural gas properties in Bangladesh and North America
totaling approximately $175 million, net of accumulated depletion, which we
account for under the successful efforts method. These oil and
natural 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 have an adverse effect on our results of operations and might
result in an impairment of or higher depletion rate on our oil and natural gas
properties.
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.
37
Our
operations in countries other than the United States accounted for approximately
64% of our consolidated revenue during 2009, 57% of our consolidated revenue in
2008, and 56% of our consolidated revenue in 2007. 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, Iraq, Nigeria, Russia, Kazakhstan,
Venezuela, and Yemen. In addition, military action or continued
unrest in the Middle East could impact the supply and pricing for oil and
natural gas, disrupt our operations in the region and elsewhere, and increase
our costs for security worldwide.
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 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.
38
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 wars and ongoing military action in the Middle East, 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.
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.
39
Customers
and Business
Exploration
and production activity
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. Demand is directly affected by trends in oil and natural
gas prices, which, historically, have been volatile and are likely to continue
to be volatile.
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 economic factors that are beyond our
control. Any prolonged reduction in oil and natural gas prices will
depress the immediate levels of exploration, development, and production
activity. Perceptions of longer-term lower oil and natural gas prices by
oil and natural gas companies can similarly reduce or defer major expenditures
given the long-term nature of many large-scale development
projects.
The
recent worldwide recession has reduced the levels of economic activity and the
expansion of industrial business operations. This has negatively
impacted worldwide demand for energy, resulting in lower oil and natural gas
prices, a lowering of the level of exploration, development, and production
activity, and a corresponding decline in the demand for our well services and
products. This reduction in demand could continue through 2010 and
beyond, which could have an adverse effect on revenue and
profitability.
Factors
affecting the prices of oil and natural gas include:
-
governmental
regulations, including the policies of governments regarding the
exploration for and production and development of their oil and natural
gas reserves;
-
global
weather conditions and natural
disasters;
-
worldwide
political, military, and economic
conditions;
-
the
level of oil production by non-OPEC countries and the available excess
production capacity within OPEC;
-
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 natural
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.
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 natural 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.
40
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.
Risks
related to our business in Venezuela
We
believe there are risks associated with our operations in Venezuela. For
example, the Venezuela National Assembly enacted legislation that allows the
Venezuelan government, directly or through its state-owned oil company, to
assume control over the operations and assets of certain oil service providers
in exchange for reimbursement of the book value of the assets adjusted for
certain liabilities. Venezuelan government officials have stated this
legislation is not applicable to our company.
However,
we continue to see a delay in receiving payment on our receivables from our
primary customer in Venezuela. If our customer further delays in
paying or fails 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.
As of
December 31, 2009, our total net investment in Venezuela was approximately $236
million. In addition to this amount, we also have $380 million of surety
bond guarantees outstanding relating to our Venezuelan operations.
We
historically have remeasured our net Bolívar Fuerte-denominated monetary asset
position at the official exchange rate. In January 2010, the
Venezuelan government announced a devaluation of the Bolívar Fuerte under a new
two-exchange rate system: one rate for essential products and the other rate for
non-essential products.
The
future results of our Venezuelan operations will be affected by many factors,
including our ability to take actions to mitigate the effect of the devaluation,
further actions of the Venezuelan government, and general economic conditions
such as continued inflation and future customer payments and
spending.
Business
with national oil companies
Much of
the world’s oil and natural 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.
Customers,
primarily 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, long-term, fixed price 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, including under the FCPA, 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.
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.
42
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.
43
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). State, national, and international governments and
agencies have been evaluating climate-related legislation and other regulatory
initiatives that would restrict emissions of greenhouse gases in areas in which
we conduct business. Because our business depends on the
level of activity in the oil and natural gas industry, existing or future laws,
regulations, treaties or international agreements related to greenhouse gases
and climate change, including incentives to conserve energy or use alternative
energy sources, could have a negative impact on our business if such laws,
regulations, treaties, or international agreements reduce the worldwide demand
for oil and natural gas. Likewise, such restrictions may result
in additional compliance obligations with respect to the release, capture, and
use of carbon dioxide that could have an adverse effect on our results of
operations, liquidity, and financial condition.
We are a
leading provider of hydraulic fracturing services, a process that creates
fractures extending from the well bore through the rock formation to enable
natural gas or oil to move more easily through the rock pores to a production
well. Bills pending in the United States House and Senate have
asserted that chemicals used in the fracturing process could adversely affect
drinking water supplies. The proposed legislation would require the
reporting and public disclosure of chemicals used in the fracturing
process. This legislation, if adopted, could establish an additional
level of regulation at the federal level that could lead to operational delays
and increased operating costs. The adoption of any future federal or state laws
or implementing regulations imposing reporting obligations on, or otherwise
limiting, the hydraulic fracturing process could make it more difficult to
complete natural gas and oil wells and could have an adverse impact on our
future results of operations, liquidity, and financial condition.
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.
44
Technology
The
market for our services and products is characterized by continual technological
developments to provide better and more reliable performance and
services. If we are not able to design, develop, and produce
commercially competitive products and to implement commercially competitive
services in a timely manner in response to changes in technology, our business
and revenue could be materially and adversely affected, and the value of our
intellectual property may be reduced. Likewise, if our proprietary
technologies, equipment and facilities, or work processes become obsolete, we
may no longer be competitive, and our business and revenue could be materially
and adversely affected.
Reliance
on management
We depend
greatly on the efforts of our executive officers and other key employees to
manage our operations. The loss or unavailability of any of our
executive officers or other key employees could have a material adverse effect
on our business.
Technical
personnel
Many of
the services that we provide and the products that we sell are complex and
highly engineered and often must perform or be performed in harsh
conditions. We believe that our success depends upon our ability to
employ and retain technical personnel with the ability to design, utilize, and
enhance these services and products. In addition, our ability to
expand our operations depends in part on our ability to increase our skilled
labor force. 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 natural gas producers.
45
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, 2009 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, 2009, our internal control over financial reporting is
effective.
The
effectiveness of Halliburton’s internal control over financial reporting as of
December 31, 2009 has been audited by KPMG LLP, an independent registered public
accounting firm, as stated in their report that is included herein.
HALLIBURTON
COMPANY
by
/s/
David J. Lesar
/s/
Mark A. McCollum
David
J. Lesar
Mark
A. McCollum
Chairman
of the Board,
Executive
Vice President and
President,
and Chief Executive Officer
Chief
Financial Officer
46
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, 2009 and 2008, 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, 2009. 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, 2009 and 2008, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2009, in conformity with U.S. generally accepted accounting
principles.
As
discussed in Note 14, to the consolidated financial statements, the Company
changed its method of accounting for instruments granted in share-based payment
transactions as participating securities, its method of accounting for
convertible debt, and its method of accounting for non-controlling interests
beginning on January 1, 2009.
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, 2009, 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 17, 2010 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, 2009, 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, 2009, 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, 2009 and 2008, 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, 2009, and our report dated
February 17, 2010 expressed an
unqualified opinion on those consolidated financial statements.
Millions
of dollars and shares except per share data
2009
2008
2007
Revenue:
Services
$
10,832
$
13,391
$
11,256
Product
sales
3,843
4,888
4,008
Total
revenue
14,675
18,279
15,264
Operating
costs and expenses:
Cost
of services
9,224
10,079
8,167
Cost
of sales
3,255
3,970
3,358
General
and administrative
207
282
293
Gain
on sale of assets, net
(5
)
(62
)
(52
)
Total
operating costs and expenses
12,681
14,269
11,766
Operating
income
1,994
4,010
3,498
Interest
expense
(297
)
(167
)
(168
)
Interest
income
12
39
124
Other,
net
(27
)
(33
)
(7
)
Income
from continuing operations before
income taxes
1,682
3,849
3,447
Provision
for income taxes
(518
)
(1,211
)
(907
)
Income
from continuing operations
1,164
2,638
2,540
Income
(loss) from discontinued operations, net of
income tax (provision) benefit
of $5, $3, and $(15)
(9
)
(423
)
996
Net
income
$
1,155
$
2,215
$
3,536
Noncontrolling
interest in net income of subsidiaries
(10
)
9
(50
)
Net
income attributable to company
$
1,145
$
2,224
$
3,486
Amounts
attributable to company shareholders:
Income
from continuing operations
$
1,154
$
2,647
$
2,511
Income
(loss) from discontinued operations, net
(9
)
(423
)
975
Net
income attributable to company
$
1,145
$
2,224
$
3,486
Basic
income per share attributable to company
shareholders:
Income
from continuing operations
$
1.28
$
3.00
$
2.73
Income
(loss) from discontinued operations, net
(0.01
)
(0.48
)
1.06
Net
income per share
$
1.27
$
2.52
$
3.79
Diluted
income per share attributable to company
shareholders:
Income
from continuing operations
$
1.28
$
2.91
$
2.63
Income
(loss) from discontinued operations, net
(0.01
)
(0.46
)
1.02
Net
income per share
$
1.27
$
2.45
$
3.65
Basic
weighted average common shares outstanding
900
883
919
Diluted
weighted average common shares outstanding
902
909
955
See notes to consolidated financial
statements.
49
HALLIBURTON
COMPANY
Consolidated
Balance Sheets
December
31
Millions
of dollars and shares except per share data
2009
2008
Assets
Current
assets:
Cash
and equivalents
$
2,082
$
1,124
Receivables
(less allowance for bad debts of $90 and $60)
2,964
3,795
Inventories
1,598
1,828
Investments
in marketable securities
1,312
–
Current
deferred income taxes
210
246
Other
current assets
472
418
Total
current assets
8,638
7,411
Property,
plant, and equipment (net of accumulated depreciation of $5,230 and
$4,566)
5,759
4,782
Goodwill
1,100
1,072
Other
assets
1,041
1,120
Total
assets
$
16,538
$
14,385
Liabilities
and Shareholders’ Equity
Current
liabilities:
Accounts
payable
$
787
$
898
Current
maturities of long-term debt
750
26
Accrued
employee compensation and benefits
514
643
Deferred
revenue
215
231
Department
of Justice (DOJ) and Securities and Exchange Commission (SEC)
settlement
and indemnity,
current
142
373
Other
current liabilities
481
610
Total
current liabilities
2,889
2,781
Long-term
debt
3,824
2,586
Employee
compensation and benefits
462
539
Other
liabilities
606
735
Total
liabilities
7,781
6,641
Shareholders’
equity:
Common
shares, par value $2.50 per share – authorized 2,000 shares, issued
1,067
2,669
2,666
Paid-in
capital in excess of par value
411
484
Accumulated
other comprehensive loss
(213
)
(215
)
Retained
earnings
10,863
10,041
Treasury
stock, at cost – 165 and 172 shares
(5,002
)
(5,251
)
Company
shareholders’ equity
8,728
7,725
Noncontrolling
interest in consolidated subsidiaries
29
19
Total
shareholders’ equity
8,757
7,744
Total
liabilities and shareholders’ equity
$
16,538
$
14,385
See notes to consolidated financial
statements.
50
HALLIBURTON
COMPANY
Consolidated
Statements of Shareholders’ Equity
Millions
of dollars
2009
2008
2007
Balance
at January 1
$
7,744
$
6,966
$
7,465
Dividends
and other transactions with shareholders
(144
)
(623
)
(1,529
)
Adoption
of new accounting standards
–
(703
)
(30
)
Shares
exchanged in KBR, Inc. exchange offer
–
–
(2,809
)
Comprehensive
income:
Net income
1,155
2,215
3,536
Net cumulative translation
adjustments
(5
)
1
(23
)
Defined benefit and other
postretirement plans adjustments
2
(106
)
355
Net unrealized gains (losses)
on investments
5
(6
)
1
Total
comprehensive income
1,157
2,104
3,869
Balance
at December 31
$
8,757
$
7,744
$
6,966
See notes to consolidated financial
statements.
51
HALLIBURTON
COMPANY
Consolidated
Statements of Cash Flows
Year
Ended December 31
Millions
of dollars
2009
2008
2007
Cash
flows from operating activities:
Net
income
$
1,155
$
2,215
$
3,536
Adjustments
to reconcile net income to net cash from operations:
Depreciation,
depletion, and amortization
931
738
583
Payments
of DOJ and SEC settlement and indemnity
(417
)
–
–
Provision
(benefit) for deferred income taxes, continuing operations
274
254
(140
)
(Income)
loss from discontinued operations
9
423
(996
)
Other
changes:
Receivables
869
(670
)
(326
)
Inventories
232
(368
)
(218
)
Accounts
payable
(118
)
161
77
Other
(529
)
(79
)
210
Total
cash flows from operating activities
2,406
2,674
2,726
Cash
flows from investing activities:
Capital
expenditures
(1,864
)
(1,824
)
(1,583
)
Purchases
of investments in marketable securities
(1,620
)
–
(1,360
)
Sales
of investments in marketable securities
300
388
1,028
Sales
of property, plant, and equipment
203
191
203
Acquisitions
of assets, net of cash acquired
(55
)
(652
)
(563
)
Disposal
of KBR, Inc. cash upon separation
–
–
(1,461
)
Other
investing activities
(49
)
41
75
Total
cash flows from investing activities
(3,085
)
(1,856
)
(3,661
)
Cash
flows from financing activities:
Proceeds
from long-term borrowings, net of offering costs
1,975
1,187
–
Payments
of dividends to shareholders
(324
)
(319
)
(314
)
Payments
on long-term borrowings
(31
)
(2,048
)
(7
)
Payments
to reacquire common stock
(17
)
(507
)
(1,374
)
Other
financing activities
67
164
125
Total
cash flows from financing activities
1,670
(1,523
)
(1,570
)
Effect
of exchange rate changes on cash
(33
)
(18
)
(27
)
Increase
(decrease) in cash and equivalents
958
(723
)
(2,532
)
Cash
and equivalents at beginning of year
1,124
1,847
4,379
Cash
and equivalents at end of year
$
2,082
$
1,124
$
1,847
Supplemental
disclosure of cash flow information:
Cash
payments during the year for:
Interest
$
251
$
143
$
144
Income
taxes
$
485
$
1,057
$
941
See notes
to consolidated financial statements.
52
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 natural 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 forecasting of our effective income tax rate and the valuation of deferred
taxes, legal and environmental reserves, indemnity valuations, long-lived asset
valuations, purchase price allocations, pensions, allowance for bad debts,
and percentage-of-completion accounting for long-term
contracts. 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.
We report
two business segments. In the first quarter of 2009, we reclassified
certain services between our operating segments to re-establish a new service
offering. See Note 2 for further information. Additionally, KBR, Inc.
(KBR), formerly a wholly owned subsidiary, is presented as discontinued
operations in the consolidated financial statements. See Note 7 for
additional information.
In 2009,
we adopted the provisions of new accounting standards. See Note 14
for further information. All periods presented reflect these
changes.
We have
evaluated subsequent events through February 17, 2010, the date of issuance of
the consolidated financial statements.
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, collectability 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 collectability 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.
53
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.
Research
and development
Research
and development costs are expensed as incurred. Research and
development costs were $325 million in 2009, $326 million in 2008, and $301
million in 2007.
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.
54
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 2009, we recorded an
immaterial amount of goodwill from acquisitions. During 2008, 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. The fair value
of each of our reporting units exceeded its carrying amount by a significant
margin for 2009, 2008, and 2007. In addition, there were no triggering events
that occurred in 2009, 2008, or 2007 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 3 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.
Income
taxes
We
recognize the amount of taxes payable or refundable for the year. In
addition, deferred tax assets and liabilities are recognized for the expected
future tax consequences of events that have been recognized in the financial
statements or tax returns. A valuation allowance is provided for
deferred tax assets if it is more likely than not that these items will not be
realized.
In
assessing the realizability of deferred tax assets, management considers whether
it is more likely than not that some portion or all of the deferred tax assets
will not be realized. The ultimate realization of deferred tax assets
is dependent upon the generation of future taxable income during the periods in
which those temporary differences become deductible. Management
considers the scheduled reversal of deferred tax liabilities, projected future
taxable income, and tax planning strategies in making this
assessment. Based upon the level of historical taxable income and
projections for future taxable income over the periods in which the deferred tax
assets are deductible, management believes it is more likely than not that we
will realize the benefits of these deductible differences, net of the existing
valuation allowances.
55
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. 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” in our consolidated statements of
operations. 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 our consolidated statements of operations 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
Stock-based
compensation cost is measured at the date of grant, based on the calculated fair
value of the award, and is recognized as expense over the employee’s service
period, which is generally the vesting period of the equity grant. Additionally,
compensation cost is recognized based on awards ultimately expected to vest,
therefore, we have reduced the cost for estimated forfeitures based on
historical forfeiture rates. Forfeitures are estimated at the time of grant and
revised in subsequent periods to reflect actual forfeitures. See Note
10 for additional information related to stock-based compensation.
Note
2. Business Segment and Geographic Information
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. In the first quarter of 2009, we moved a portion
of our completion tools and services from the Completion and Production segment
to the Drilling and Evaluation segment to re-establish our testing and subsea
services offering, which resulted in a change to our operating
segments. All periods presented reflect reclassifications related to
the change in operating segments.
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.
56
Production
enhancement services include stimulation services, pipeline process services,
sand control services, and well intervention services. Stimulation
services optimize oil and natural 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.
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, testing and subsea
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 natural 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 natural 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.
Testing
and subsea services provide acquisition and analysis of dynamic reservoir
information and reservoir optimization solutions to the oil and natural gas
industry utilizing downhole test tools, data acquisition services using
telemetry and electronic memory recording, fluid sampling, surface well testing,
subsea safety systems, and reservoir engineering services.
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 natural gas
industry.
57
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 natural 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.
The
following tables present information on our business segments.
Operations
by business segment
Year
Ended December 31
Millions
of dollars
2009
2008
2007
Revenue:
Completion
and Production
$
7,419
$
9,610
$
8,138
Drilling
and Evaluation
7,256
8,669
7,126
Total
revenue
$
14,675
$
18,279
$
15,264
Operating
income:
Completion
and Production
$
1,016
$
2,304
$
2,119
Drilling
and Evaluation
1,183
1,970
1,565
Total
operations
2,199
4,274
3,684
Corporate
and other
(205
)
(264
)
(186
)
Total
operating income
$
1,994
$
4,010
$
3,498
Interest
expense
$
(297
)
$
(167
)
$
(168
)
Interest
income
12
39
124
Other,
net
(27
)
(33
)
(7
)
Income
from continuing operations before
income taxes
$
1,682
$
3,849
$
3,447
Capital
expenditures:
Completion
and Production
$
900
$
787
$
787
Drilling
and Evaluation
959
1,031
763
Corporate
and other
5
6
33
Total
$
1,864
$
1,824
$
1,583
Depreciation,
depletion, and amortization:
Completion
and Production
$
437
$
358
$
282
Drilling
and Evaluation
490
376
294
Corporate
and other
4
4
7
Total
$
931
$
738
$
583
58
December
31
Millions
of dollars
2009
2008
2007
Total
assets:
Completion
and Production
$
5,920
$
5,936
$
4,763
Drilling
and Evaluation
6,204
6,205
4,685
Shared
assets
914
648
672
Corporate
and other
3,500
1,596
3,015
Total
$
16,538
$
14,385
$
13,135
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
2009
2008
2007
Revenue:
United
States
$
5,248
$
7,775
$
6,673
Other
countries
9,427
10,504
8,591
Total
$
14,675
$
18,279
$
15,264
December
31
Millions
of dollars
2009
2008
2007
Long-lived
assets:
United
States
$
4,274
$
3,571
$
2,733
Other
countries
3,401
3,027
2,263
Total
$
7,675
$
6,598
$
4,996
Note
3. Receivables
Our trade
receivables are generally not collateralized. At December 31, 2009,
26% of our gross trade receivables were from customers in the United
States. At December 31, 2008, 34% of our gross trade receivables were
from customers in the United States. No other country or single
customer accounted for more than 10% of our gross trade receivables at these
dates.
The
following table presents a rollforward of our allowance for bad debts for 2007,
2008, and 2009.
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 $68 million at December 31, 2009 and
$92 million at December 31, 2008. If the average cost method had been
used, total inventories would have been $33 million higher than reported at
December 31, 2009 and $31 million higher than reported at December 31,2008. The cost of the remaining inventory was recorded on the average
cost method. Inventories consisted of the following:
December
31
Millions
of dollars
2009
2008
Finished
products and parts
$
1,090
$
1,312
Raw
materials and supplies
480
446
Work
in process
28
70
Total
$
1,598
$
1,828
Finished
products and parts are reported net of obsolescence reserves of $94 million at
December 31, 2009 and $81 million at December 31, 2008.
Note
5. Property, Plant, and Equipment
Property,
plant, and equipment were composed of the following:
December
31
Millions
of dollars
2009
2008
Land
$
86
$
58
Buildings
and property improvements
1,306
1,082
Machinery,
equipment, and other
9,597
8,208
Total
10,989
9,348
Less
accumulated depreciation
5,230
4,566
Net
property, plant, and equipment
$
5,759
$
4,782
The
percentages of total buildings and property improvements and total machinery,
equipment, and other, excluding oil and natural gas investments, are depreciated
over the following useful lives:
Buildings
and Property
Improvements
2009
2008
1 – 10
years
13
%
17
%
11 – 20
years
47
%
46
%
21 – 30
years
11
%
12
%
31 – 40
years
29
%
25
%
Machinery,
Equipment,
and
Other
2009
2008
1 – 5
years
19
%
19
%
6 – 10
years
75
%
74
%
11 – 20
years
6
%
7
%
60
Note
6. Debt
Long-term
debt consisted of the following:
December
31
Millions
of dollars
2009
2008
6.15% senior notes due
September 2019
$
997
$
–
7.45% senior notes due
September 2039
995
–
6.7% senior notes due September
2038
800
800
5.5% senior notes due October
2010
750
749
5.9% senior notes due September
2018
400
400
7.6% senior debentures due
August 2096
294
294
8.75% senior debentures due
February 2021
185
185
Other
153
184
Total
long-term debt
4,574
2,612
Less
current maturities of long-term debt
750
26
Noncurrent
portion of long-term debt (due 2017 and
thereafter)
$
3,824
$
2,586
Senior
debt
In the
first quarter of 2009, we issued new senior notes totaling $2 billion at a
discount. All of our senior notes and debentures rank equally with
our existing and future senior unsecured indebtedness, have semiannual interest
payments, and no sinking fund requirements. We may redeem all of our
senior notes, except for our 5.5% 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. There were no cash drawings under the revolving
credit facilities as of December 31, 2009 or 2008.
In March
2009, we terminated the $400 million unsecured, six-month revolving credit
facility established in October 2008 to provide additional liquidity and for
other general corporate purposes.
Note
7. KBR Separation
In 2007,
we completed the separation of KBR from us by exchanging the shares of KBR
common stock owned by us on that date for 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.”
61
The
following table presents the 2007 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
Revenue
$
2,250
Operating
income
$
62
Net
income
$
23
(a)
(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 and a tax sharing
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.
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 contracts, credit agreements, letters of
credit, and other KBR credit instruments. These indemnities and
guarantees will continue until they expire at the earlier of: (1) the
termination of the underlying project contract or KBR obligations thereunder;
(2) the expiration of the relevant credit support instrument in accordance with
its terms or release of such instrument by the customer; or (3) the expiration
of the credit agreements. 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.
62
In
February 2009, the United States Department of Justice (DOJ) and Securities and
Exchange Commission (SEC) FCPA investigations were resolved. The
total of fines and disgorgement was $579 million, of which KBR consented to pay
$20 million. As of December 31, 2009, we had paid $417 million,
consisting of $240 million as a result of the DOJ settlement and the indemnity
we provided to KBR upon separation and $177 million as a result of the SEC
settlement. Our KBR indemnities and guarantees are primarily included
in “Department of Justice (DOJ) and Securities and Exchange Commission (SEC)
settlement and indemnity, current” and “Other liabilities” on the consolidated
balance sheets and totaled $214 million at December 31, 2009 and $631 million at
December 31, 2008. Excluding the remaining amounts necessary to
resolve the DOJ and SEC investigations and under the indemnity we provided to
KBR, our estimation of the remaining obligation for other indemnities and
guarantees provided to KBR upon separation was $72 million at December 31,2009. See Note 8 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
8. Commitments and Contingencies
Foreign
Corrupt Practices Act investigations
Background. As a
result of an ongoing FCPA investigation at the time of the KBR separation, 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 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% beneficial interest in
the venture. Part of KBR’s ownership in TSKJ was held through M.W.
Kellogg Limited (MWKL), a United Kingdom joint venture and subcontractor on the
Bonny Island project, in which KBR beneficially owns a 55%
interest. 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).
DOJ and SEC investigations
resolved. In February 2009, the FCPA investigations by the DOJ
and the SEC were resolved with respect to KBR and us. 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 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 did not provide a monitor for us.
63
As part
of the resolution of the SEC investigation, we retained 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 agreed to adopt
any necessary anti-bribery and foreign agent internal controls and
record-keeping procedures recommended by the independent
consultant. The review and evaluation were completed during the
second quarter of 2009, and we have implemented the consultant’s immediate
recommendations and will implement the remaining long-term recommendations by
mid-year 2010. As a result of the substantial enhancement of our
anti-bribery and foreign agent internal controls and record-keeping procedures
prior to the review of the independent consultant, we do not expect the
implementation of the consultant’s recommendations to materially impact our
long-term strategy to grow our international operations. 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 and to recommend any additional
improvements.
KBR has
agreed that our indemnification obligations with respect to the DOJ and SEC FCPA
investigations have been fully satisfied.
Other matters. In
addition to the DOJ and the SEC investigations, we are aware of other
investigations in France, Nigeria, the United Kingdom, and Switzerland regarding
the Bonny Island project. In the United Kingdom, the Serious Fraud
Office (SFO) is considering civil claims or criminal prosecution under various
United Kingdom laws and appears to be focused on the actions of MWKL, among
others. Violations of these laws could result in fines, restitution
and confiscation of revenues, among other penalties, some of which could be
subject to our indemnification obligations under the master separation
agreement. Our indemnity for penalties under the master separation agreement
with respect to MWKL is limited to 55% of such penalties, which is KBR’s
beneficial ownership interest in MWKL. MWKL is cooperating with the
SFO’s investigation. Whether the SFO pursues civil or criminal
claims, and the amount of any fines, restitution, confiscation of revenues or
other penalties that could be assessed would depend on, among other factors, the
SFO’s findings regarding the amount, timing, nature and scope of any improper
payments or other activities, whether any such payments or other activities were
authorized by or made with knowledge of MWKL, the amount of revenue involved,
and the level of cooperation provided to the SFO during the
investigations. MWKL has informed the SFO that it intends to
self-report corporate liability for corruption-related offenses arising out of
the Bonny Island project. Based on discussions with the SFO, MWKL
expects to receive confirmation that it will be admitted into the plea
negotiation process under the Guidelines on Plea Discussions in Cases of Complex
or Serious Fraud, which have been issued by the Attorney General for England and
Wales.
The DOJ
and SEC 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.
Our
indemnity of KBR and its majority-owned subsidiaries 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.
64
At this
time, other than the claims being considered by the SFO, no claims by
governmental authorities in foreign jurisdictions have been asserted against the
indemnified parties. Therefore, we are unable to estimate the maximum
potential amount of future payments that could be required to be made under our
indemnity to KBR and its majority-owned subsidiaries related to these matters.
See Note 7 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.
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. We understand KBR believes several possible solutions may
exist, including replacement of the bolts. Initial estimates by KBR
indicated that costs of these various solutions ranged 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 this matter and has submitted a counterclaim in the arbitration
seeking the recovery of $22 million. The arbitration panel held an
evidentiary hearing in March 2008 to determine which party is responsible for
the designation of the material used for the bolts. On May 13, 2009,
the arbitration panel held that KBR and not Petrobras selected the material to
be used for the bolts. Accordingly, the arbitration panel held
that there is no implied warranty by Petrobras to KBR as to the suitability
of the bolt material and that the parties' rights are to be governed by the
express terms of their contract. The arbitration panel set the final
hearing on liability and damages for early May 2010. 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, 2009 and December 31, 2008. See Note 7 for
additional information regarding the KBR indemnification.
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.
65
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. Both parties filed briefs, and the Fifth Circuit heard oral
argument in December of 2009. The Fifth Circuit affirmed the district
court’s order denying class certification. AMSF will have the opportunity
to request additional review by the Fifth Circuit and the United States Supreme
Court. As of December 31, 2009, 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.
Shareholder
derivative cases
In May
2009, two shareholder derivative lawsuits involving us and KBR were filed in
Harris County, Texas naming as defendants various current and retired
Halliburton directors and officers and current KBR directors. These
cases allege that the individual Halliburton defendants violated their fiduciary
duties of good faith and loyalty to the detriment of Halliburton and its
shareholders by failing to properly exercise oversight responsibilities and
establish adequate internal controls. The District Court consolidated
the two cases and the plaintiffs filed a consolidated petition against current
and former Halliburton directors and officers only containing various
allegations of wrongdoing including violations of the FCPA, claimed KBR offenses
while acting as a government contractor in Iraq, claimed KBR offenses and fraud
under United States government contracts, Halliburton activity in Iran, and
illegal kickbacks. As of
December 31, 2009, 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, 2009, we
had not recorded any liability associated with these
indemnifications.
66
Environmental
We are
subject to numerous environmental, legal, and regulatory requirements related to
our operations worldwide. In the United States, these laws and
regulations include, among others:
-
the
Comprehensive Environmental Response, Compensation, and Liability
Act;
-
the
Resource Conservation and Recovery
Act;
-
the
Clean Air Act;
-
the
Federal Water Pollution Control Act;
and
-
the
Toxic Substances Control Act.
In
addition to the federal laws and regulations, states and other countries where
we do business often have numerous environmental, legal, and regulatory
requirements by which we must abide. We evaluate and address the
environmental impact of our operations by assessing and remediating contaminated
properties in order to avoid future liabilities and comply with environmental,
legal, and regulatory requirements. On occasion, we are involved in
specific environmental litigation and claims, including the remediation of
properties we own or have operated, as well as efforts to meet or correct
compliance-related matters. Our Health, Safety and Environment group
has several programs in place to maintain environmental leadership and to
prevent the occurrence of environmental contamination.
We do not
expect costs related to these remediation requirements to have a material
adverse effect on our consolidated financial position or our results of
operations. Our accrued liabilities for environmental matters were
$53 million as of December 31, 2009 and $64 million as of December 31,2008. 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 10 federal and state superfund sites for which we have
established a liability. As of December 31, 2009, those 10 sites
accounted for approximately $14 million of our total $53 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 financial institutions under
which approximately $1.8 billion of letters of credit, bank guarantees, or
surety bonds were outstanding as of December 31, 2009, including $380 million of
surety bonds related to Venezuela. In addition, $390 million of the
total $1.8 billion relates to KBR letters of credit, bank guarantees, or surety
bonds that 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 $528 million in 2009, $561 million in
2008, and $487 million in 2007.
Future
total rentals on noncancellable operating leases are as follows: $149
million in 2010; $112 million in 2011; $70 million in 2012; $42 million in 2013;
$29 million in 2014; and $142 million thereafter.
67
Note
9. Income Taxes
The
components of the (provision)/benefit for income taxes on continuing operations
were:
Year
Ended December 31
Millions
of dollars
2009
2008
2007
Current
income taxes:
Federal
$
30
$
(561
)
$
(560
)
Foreign
(250
)
(346
)
(449
)
State
(24
)
(50
)
(38
)
Total
current
(244
)
(957
)
(1,047
)
Deferred
income taxes:
Federal
(237
)
(303
)
129
Foreign
(31
)
64
7
State
(6
)
(15
)
4
Total
deferred
(274
)
(254
)
140
Provision
for income taxes
$
(518
)
$
(1,211
)
$
(907
)
The
United States and foreign components of income from continuing operations before
income taxes were as follows:
Year
Ended December 31
Millions
of dollars
2009
2008
2007
United
States
$
589
$
2,674
$
2,206
Foreign
1,093
1,175
1,241
Total
$
1,682
$
3,849
$
3,447
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 were as follows:
Year
Ended December 31
2009
2008
2007
United
States statutory rate
35.0
%
35.0
%
35.0
%
Impact of foreign income taxed
at different rates
(3.3
)
(1.1
)
(2.3
)
Adjustments of prior year
taxes
(2.1
)
(1.9
)
(0.3
)
Other impact of foreign
operations
(0.4
)
(1.1
)
(3.9
)
Valuation
allowance
–
0.1
(2.0
)
Other items,
net
1.6
0.5
(0.2
)
Total
effective tax rate on continuing operations
30.8
%
31.5
%
26.3
%
68
The major
component of the difference between the 2009 statutory rate compared to the
effective rate was the decline in our United States operating results, which are
generally subject to higher income tax rates than most of our foreign
jurisdictions. This decline resulted in a higher mix of foreign
income taxed at lower rates. 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
primary components of our deferred tax assets and liabilities were as
follows:
December
31
Millions
of dollars
2009
2008
Gross
deferred tax assets:
Employee compensation and
benefits
$
266
$
324
Accrued
liabilities
75
81
Net operating loss
carryforwards
64
50
Capitalized research
and experimentation
56
74
Insurance
accruals
48
47
Software revenue
recognition
35
31
Inventory
29
26
Other
80
114
Total
gross deferred tax assets
653
747
Gross
deferred tax liabilities:
Depreciation and
amortization
447
303
Joint ventures, partnerships,
and unconsolidated affiliates
33
25
Other
55
38
Total
gross deferred tax liabilities
535
366
Net
deferred income tax asset
$
118
$
381
At
December 31, 2009, we had a total of $218 million of foreign net operating loss
carryforwards, of which $73 million will expire from 2010 through 2020 and $145
million that will not expire due to indefinite expiration
dates.
69
The
following table presents a rollforward of our unrecognized tax benefits and
associated interest and penalties.
Includes
$149 million and $137 million as of December 31, 2009 and 2008 in amounts
to be settled in accordance with our tax sharing agreement with KBR and
foreign unrecognized tax benefits that would give rise to a United States
tax credit. The remaining balance of $114 million and $163
million as of December 31, 2009 and 2008, if resolved in our favor, would
positively impact the effective tax rate, and therefore, be recognized as
additional tax benefits in our statements of
operations.
(b)
Includes
$99 million that could be resolved within the next 12
months.
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.
70
Note
10. 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 (a)
(149
)
(151
)
(45
)
Unrealized
gains (losses) on investments
1
(4
)
2
Total
accumulated other comprehensive loss
$
(213
)
$
(215
)
$
(104
)
(a)
Includes
net actuarial losses of $36 million for our United States pension plans
and $149 million for our international pension plans at December 31, 2009,
$37 million for our United States pension plans and $161 million for our
international pension plans at December 31, 2008, and $13 million for our
United States pension plans and $72 million for our international pension
plans at December 31, 2007.
Shares
of common stock
December
31
Millions
of shares
2009
2008
2007
Issued
1,067
1,067
1,063
In
treasury
(165
)
(172
)
(183
)
Total
shares of common stock outstanding
902
895
880
Our stock
repurchase program has an authorization of $5.0 billion, of which $1.8 billion
remained available at December 31, 2009. The program does not require
a specific number of shares to be purchased and the program may be affected
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, 2009, 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. There were no stock repurchases under the program in
2009.
Preferred
Stock
Our
preferred stock consists of five million total authorized shares at December 31,2009, of which none are issued.
Stock
Incentive Plans
The
following table summarizes stock-based compensation costs for the years ended
December 31, 2009, 2008 and 2007.
Year
Ended December 31
Millions
of dollars
2009
2008
2007
Stock-based
compensation cost
$
143
$
103
$
97
Tax
benefit
$
(50
)
$
(36
)
$
(35
)
Stock-based
compensation cost, net of tax
$
93
$
67
$
62
Our Stock
and Incentive Plan, as amended (Stock 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.
73
Under the
terms of the Stock Plan, approximately 133 million shares of common stock have
been reserved for issuance to employees and non-employee
directors. At December 31, 2009, approximately 34 million shares were
available for future grants under the Stock Plan. The stock to be
offered pursuant to the grant of an award under the Stock Plan may be authorized
but unissued common shares or treasury shares.
In
addition to the provisions of the Stock Plan, we also have stock-based
compensation provisions under our Restricted Stock Plan for Non-Employee
Directors and our Employee Stock Purchase Plan (ESPP).
Each of
the active stock-based compensation arrangements is discussed
below.
Stock
options
The
majority of our options are generally issued during the second quarter of the
year. All stock options under the Stock 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 2009.
The total
intrinsic value of options exercised was $10 million in 2009, $106 million in
2008, and $68 million in 2007. As of December 31, 2009, there was $40
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 2 years.
Cash
received from option exercises was $74 million during 2009, $120 million during
2008, and $110 million during 2007. The tax benefit realized from the
exercise of stock options was $3 million in 2009, $33 million in 2008, and $22
million in 2007.
74
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
2009
2008
2007
Expected
term (in years)
5.18
5.20
5.14
Expected
volatility
53.06
%
32.30
%
35.70
%
Expected
dividend yield
1.23 – 2.55
%
0.71 – 2.38
%
0.89 – 1.14
%
Risk-free
interest rate
1.38 – 2.47
%
1.57 – 3.32
%
3.37 – 5.00
%
Weighted
average grant-date fair value per share
$
9.36
$
12.28
$
11.35
Restricted
stock
Restricted
shares issued under the Stock 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, 2009, 130,400 shares had
been issued to non-employee directors under this plan. There were
8,000 shares, 7,200 shares, and 8,800 shares of restricted stock awarded under
the Directors Plan in 2009, 2008, and 2007. In addition, during 2009,
our non-employee directors were awarded 53,170 shares of restricted stock under
the Stock Plan, which are included in the table below.
The
following table represents our Stock Plan and Directors Plan restricted stock
awards and restricted stock units granted, vested, and forfeited during
2009.
The
weighted average grant-date fair value of shares granted during 2008 was $36.78
and during 2007 was $32.24. The total fair value of shares vested
during 2009 was $62 million, during 2008 was $81 million, and during 2007 was
$79 million. As of December 31, 2009, there was $277 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.
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, 44 million shares of common stock have been reserved for
issuance. They may be authorized but unissued shares or treasury
shares. As of December 31, 2009, 19.5 million shares have been sold
through the ESPP.
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
2009
2008
2007
Expected
term (in years)
0.5
0.5
0.5
Expected
volatility
80.41
%
28.88
%
29.49
%
Expected
dividend yield
1.74
%
0.67
%
1.03
%
Risk-free
interest rate
0.33
%
2.17
%
4.98
%
Weighted
average grant-date fair value per share
$
7.66
$
12.58
$
7.97
Offering
period January 1 through June 30
2009
2008
2007
Expected
term (in years)
0.5
0.5
0.5
Expected
volatility
70.91
%
24.69
%
34.91
%
Expected
dividend yield
1.85
%
0.93
%
1.00
%
Risk-free
interest rate
0.27
%
3.40
%
5.09
%
Weighted
average grant-date fair value per share
$
6.69
$
8.64
$
7.20
Note
11. Income per Share
Basic
income per share is based on the weighted average number of common shares
outstanding during the period. Diluted income per share includes
additional common shares that would have been outstanding if potential common
shares with a dilutive effect had been issued.
76
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. A reconciliation of the number of shares used for the
basic and diluted income per share calculations is as follows:
Millions
of shares
2009
2008
2007
Basic
weighted average common shares outstanding
900
883
919
Dilutive
effect of:
Convertible senior notes
premium (a)
–
22
29
Stock options
2
4
7
Diluted
weighted average common shares outstanding
902
909
955
(a) 3.125%
convertible senior notes due 2023, which were settled during the third quarter
of 2008.
Excluded
from the computation of diluted income per share are options to purchase seven
million shares of common stock that were outstanding in 2009, four million
shares of common stock that were outstanding in 2008, and three million shares
of common stock that were outstanding in 2007. These options were
outstanding during these years but were excluded because they were antidilutive,
as the option exercise price was greater than the average market price of the
common shares.
Note
12. 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.
77
Notional amounts and fair market
values. The notional amounts of open foreign exchange forward
contracts and option contracts were $318 million at December 31, 2009 and $324
million at December 31, 2008. 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, 2009 or December 31,2008.
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 collectability of all trade accounts
receivable. In addition, see Note 3 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.
At
December 31, 2009, we held $1.3 billion in United States Treasury securities
with maturities that extend through September 2010. These securities
are accounted for as available-for-sale and recorded at fair value in
“Investments in marketable securities.”
Fair market value of financial
instruments. The carrying amount of 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 following table presents the
fair values of our other material financial assets and liabilities and the basis
for determining their fair values:
(a) Calculated
based on the fair value of other actively-traded, Halliburton
debt.
78
Note
13. 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 $186 million in 2009,
$178 million in 2008, and $162 million in
2007;
-
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. The liability at the balance sheet dates presented and
the annual cost for these plans are not
material.
Effective
for our fiscal year ended December 31, 2009, we adopted an update to existing
accounting standards that amends the requirements for employers’ disclosures
about plan assets for defined benefit pension and other postretirement
plans. The objectives of this update are to provide users of financial
statements with an understanding of how investment allocation decisions are
made, the major categories of 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.
Effective
for our fiscal year ended December 31, 2008, we adopted the requirements of a
new accounting standard to measure plan assets and benefit obligations as of the
date of the employer’s fiscal year-end.
The
discontinued operations of KBR have been excluded from all of the following
tables and disclosures.
79
Funded
status
The
following table presents a reconciliation of the beginning and ending balances
of benefit obligations and fair value of plan assets and the funded status of
our pension plans.
2009
2008
Millions
of dollars
United
States
International
United
States
International
Benefit
obligation
Benefit
obligation at beginning of period
$
108
$
690
$
110
$
874
Service
cost
–
21
–
29
Interest
cost
5
44
6
50
Plan
participants’ contributions
–
2
–
5
Plan
amendments
–
–
–
1
Settlements/curtailments
(8
)
(35
)
–
(42
)
Divestitures
–
–
–
(1
)
Business
combinations
–
–
–
1
Currency
fluctuations
–
57
–
(201
)
Actuarial
(gain) loss
11
81
–
(18
)
Benefits
paid
(6
)
(27
)
(9
)
(28
)
Retained
earnings adjustment – Adoption of
accounting
standard
–
–
1
20
Projected
benefit obligation at end of period
$
110
$
833
$
108
$
690
Accumulated
benefit obligation at end of period
$
110
$
764
$
108
$
533
2009
2008
Millions
of dollars
United
States
International
United
States
International
Plan
assets
Fair
value of plan assets at beginning of period
$
66
$
430
$
107
$
724
Actual
return on plan assets
14
107
(33
)
(111
)
Employer
contributions
14
85
1
51
Settlements/curtailments
(8
)
(3
)
–
(42
)
Divestitures
–
–
–
(1
)
Business
combinations
–
–
–
1
Plan
participants’ contributions
–
2
–
5
Currency
fluctuations
–
48
–
(181
)
Benefits
paid
(6
)
(27
)
(9
)
(28
)
Retained
earnings adjustment – Adoption of
accounting
standard
–
–
–
12
Fair
value of plan assets at end of period
$
80
$
642
$
66
$
430
Funded
status at end of period
$
(30
)
$
(191
)
$
(42
)
$
(260
)
80
2009
2008
Millions
of dollars
United
States
International
United
States
International
Amounts
recognized on the Consolidated Balance
Sheets
Other
assets
$
–
$
1
$
–
$
1
Accrued
employee compensation and benefits
–
(15
)
(2
)
(12
)
Employee
compensation and benefits
(30
)
(177
)
(40
)
(249
)
Pension
plans in which projected benefit
obligation exceeded plan assets
at December 31
Projected
benefit obligation
$
110
$
821
$
107
$
675
Fair
value of plan assets
80
629
65
414
Pension
plans in which accumulated benefit
obligation exceeded plan assets
at December 31
Accumulated
benefit obligation
$
110
$
690
$
107
$
477
Fair
value of plan assets
80
562
65
360
Fair
value measurements of plan assets
The
following tables set forth the fair value of our United States and international
plan assets at December 31, 2009.
United
States Pension Plans
Quoted
Prices
Significant
in
Active
Observable
Markets
for
Inputs
for
Millions
of dollars
Identical
Assets
Similar
Assets
Total
United
States equity securities
$
31
$
–
$
31
Non-United
States equity securities
18
–
18
Other
assets
1
30
31
Fair
value of plan assets
$
50
$
30
$
80
International
Pension Plans
Quoted
Prices
Significant
in
Active
Observable
Significant
Markets
for
Inputs
for
Unobservable
Millions
of dollars
Identical
Assets
Similar
Assets
Inputs
Total
United
States equity securities
$
41
$
–
$
–
$
41
Non-United
States equity securities
126
–
–
126
Government
bonds
–
78
–
78
Corporate
bonds
–
87
–
87
Common
collective trust funds (a)
–
202
–
202
Other
assets
35
2
71
108
Fair
value of plan assets
$
202
$
369
$
71
$
642
(a)
This
asset category includes 84% of investments in non-United States equity
securities, 14% of investments in United States equity securities, and 2%
of investments in fixed income
securities.
81
At
December 31, 2008, 59% of our United States pension plan assets were invested in
equity securities, 40% were invested in debt securities, and 1% were in other
investments. At December 31 2008, 49% of the assets in our
international pension plans were invested in equity securities, 35% were
invested in debt securities, and 16% were in other investments.
Equity
securities are traded in active markets and valued based on their quoted fair
value by independent pricing vendors. Government bonds and corporate
bonds are valued using quotes from independent pricing vendors based on recent
trading activity and other relevant information, including market interest rate
curves, referenced credit spreads, and estimated prepayment
rates. Common collective trust funds are valued at the net asset
value of units held by the plans at year-end.
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. The fixed income
allocation is generally invested with a similar maturity profile to that of the
benefit obligations to ensure that changes in interest rates are adequately
reflected in the assets of the plan. Risk management practices include
diversification by issuer, industry, and geography, as well as the use of
multiple asset classes and investment managers within each asset
class.
For our
United States pension plans, the target asset allocation is 50% to 75% equity
securities and 30% to 45% fixed income securities. For our United
Kingdom pension plan, which constituted 74% of our international pension plans’
projected benefit obligations at December 31, 2009, the target asset allocation
is 60% to 70% equity securities and 30% to 40% fixed income
securities.
Net
periodic benefit cost
The
components of net periodic benefit cost for our pension plans for the years
ended December 31 were as follows:
2009
2008
2007
Millions
of dollars
United
States
International
United
States
International
United
States
International
Service
cost
$
–
$
21
$
–
$
29
$
–
$
26
Interest
cost
5
44
6
50
7
45
Expected
return on plan assets
(7)
(38)
(7)
(44)
(7)
(40)
Settlements/curtailments
4
2
–
5
2
–
Recognized
actuarial loss
2
3
3
6
6
9
Net
periodic benefit cost
$
4
$
32
$
2
$
46
$
8
$
40
Actuarial
assumptions
Certain
weighted-average actuarial assumptions used to determine benefit obligations at
December 31 were as follows:
2009
2008
Discount
rate:
United States pension
plans
4.9-6.0
%
4.7-5.8
%
International pension plans
(a)
5.3-8.5
%
2.2-9.0
%
Rate
of compensation increase:
International pension
plans
3.3-7.5
%
2.0-10.0
%
(a)
For
our United Kingdom pension plan, which constituted 74% of our
international pension plans’
projected
benefit
obligations at December 31, 2009, the discount rate utilized at the
measurement date in 2009 was
5.9%,
compared to 5.8% at the measurement date in
2008.
82
Certain
weighted-average actuarial assumptions used to determine net periodic benefit
cost for the years ended December 31 were as follows:
2009
2008
2007
Discount
rate:
United States pension
plans
4.7-5.8
%
4.6-6.2
%
5.8
%
International pension
plans
5.7-8.8
%
2.5-8.8
%
2.3-8.8
%
Expected
long-term return on plan assets:
United States pension
plans
8.0
%
8.0
%
8.3
%
International pension
plans
4.1-9.0
%
4.0-9.0
%
4.0-9.0
%
Rate
of compensation increase:
United States pension
plans
N/A
4.5
%
4.5
%
International pension
plans
3.3-10.0
%
2.0-10.0
%
2.0-10.0
%
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 rates of a portfolio of high-quality debt
instruments with maturities matching the expected timing of the payment of the
benefit obligations. The overall expected long-term rates of return
on plan assets were determined based upon an evaluation of our plan assets and
historical trends and experience, taking into account current and expected
market conditions.
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 $34 million to our
international pension plans and $4 million to our United States pension plans in
2010.
Benefit
payments. Expected benefit payments over the next 10 years are
approximately $10 million annually for our United States pension plans and
approximately $25 million annually for our international pension
plans.
Note
14. Accounting Standards Recently Adopted
For the
2009 annual reporting period, we adopted an update to existing accounting
standards related to an employer’s disclosures about postretirement benefit plan
assets. This update amends the disclosure requirements for
employer’s disclosure of plan assets for defined benefit pensions and other
postretirement plans. The objective of this update 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.
On
January 1, 2009, we adopted the provisions of a new accounting standard, which
establishes new accounting, reporting, and disclosure standards for the
noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. This standard requires the recognition of a
noncontrolling interest as equity in the consolidated financial statements and
separate from the parent’s equity. Noncontrolling interest has been
presented as a separate component of shareholders’ equity for the current
reporting period and prior comparative period in our consolidated financial
statements.
83
On
January 1, 2009, we adopted an update to existing accounting standards for
business combinations with acquisition dates on or after that
date. The update changes the accounting for business combinations in
a number of areas. Acquisition costs are no longer considered part of
the fair value of an acquisition and will generally be expensed as incurred,
noncontrolling interests are valued at fair value at the acquisition date,
in-process research and development is recorded at fair value as an
indefinite-lived intangible asset at the acquisition date, restructuring costs
associated with a business combination are generally 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. On April 1, 2009, we adopted an additional update
relating to accounting for assets acquired and liabilities assumed in a business
combination that arise from contingencies.
On
January 1, 2009, we adopted an update to accounting standards related to
convertible debt instruments that may be settled in cash upon conversion
(including partial cash settlement). The update 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. Upon adopting the update, we retroactively applied its
provisions and restated our consolidated financial statements for prior
periods.
In
applying this update, $63 million of the carrying value of our 3.125%
convertible senior notes due July 2023 was 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 was taken to interest expense over the
five-year term of the notes. Accordingly, $14 million of additional
non-cash interest expense, or $0.01 per diluted share, was recorded in 2006 and
2007 and $7 million of additional non-cash interest expense was recorded in
2008, all during the first six months of the year. Furthermore, under the
provisions of this update, the $693 million loss to settle our convertible debt
recorded in the third quarter of 2008 was reversed and recorded to additional
paid-in capital. This resulted in an increase of $686 million to
income from continuing operations and net income attributable to company in 2008
and a net increase of $630 million to beginning retained earnings as of January1, 2009. Diluted income per share for 2008 increased by $0.76 as a result of the
adoption. These notes were converted and settled during the third
quarter of 2008.
On
January 1, 2009, we adopted an update to accounting standards related to
accounting for instruments granted in share-based payment transactions as
participating securities. This update 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. According to the provisions of this update, we restated prior
periods’ basic and diluted earnings per share to include such outstanding
unvested restricted shares of our common stock in the basic weighted average
shares outstanding calculation. Upon adoption, basic income per share
for 2008 decreased by $0.02 for continuing operations and diluted income per
share decreased by $0.01 for continuing operations. In addition,
basic loss per share decreased by $0.01 for discontinued
operations. Both basic and diluted earnings per share decreased by
$0.01 for net income attributable to company shareholders.
84
In
September 2006, the FASB issued a new accounting standard for 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. In February 2008, the FASB issued an update to defer
the effective date of the fair value standard for certain nonfinancial assets
and nonfinancial liabilities for an additional year. In October 2008,
the FASB also issued an update to the original standard related to determining
the fair value of a financial asset when the market for that asset is not
active. On January 1, 2008, we adopted without material impact on our
consolidated financial statements the provisions of the fair value measurement
standard related to financial assets and liabilities and to nonfinancial assets
and liabilities measured at fair value on a recurring basis. On
January 1, 2009, we adopted without material impact on our consolidated
financial statements the provisions of the fair value measurement standard
related to nonfinancial assets and nonfinancial liabilities that are not
required or permitted to be measured at fair value on a recurring
basis.
In April
2009, the FASB further updated the fair value measurement standard to provide
additional guidance for estimating fair value when the volume and level of
activity for the asset or liability have significantly decreased. We
adopted this update on June 30, 2009 prospectively to all fair value
measurements as appropriate without material impact on our consolidated
financial statements.
85
HALLIBURTON
COMPANY
Selected
Financial Data (1)
(Unaudited)
Millions
of dollars and shares
Year
Ended December 31
except
per share and employee data
2009
2008
2007
2006
2005
Total
revenue
$
14,675
$
18,279
$
15,264
$
12,955
$
10,100
Total
operating income
$
1,994
$
4,010
$
3,498
$
3,245
$
2,164
Nonoperating
expense, net
(312
)
(161
)
(51
)
(59
)
(179
)
Income
from continuing operations before income taxes
1,682
3,849
3,447
3,186
1,985
(Provision)
benefit for income taxes
(518
)
(1,211
)
(907
)
(1,003
)
125
Income
from continuing operations
$
1,164
$
2,638
$
2,540
$
2,183
$
2,110
Income
(loss) from discontinued operations
$
(9
)
$
(423
)
$
996
$
185
$
251
Net
income
$
1,155
$
2,215
$
3,536
$
2,368
$
2,361
Noncontrolling
interest in net income of subsidiaries
(10
)
9
(50
)
(33
)
(15
)
Net
income attributable to company
$
1,145
$
2,224
$
3,486
$
2,335
$
2,346
Amounts
attributable to company shareholders:
Continuing
operations
$
1,154
$
2,647
$
2,511
$
2,164
$
2,095
Discontinued
operations
(9
)
(423
)
975
171
251
Net income
1,145
2,224
3,486
2,335
2,346
Basic
income per share attributable to shareholders:
Continuing
operations
$
1.28
$
3.00
$
2.73
$
2.12
$
2.06
Net income
1.27
2.52
3.79
2.28
2.31
Diluted
income per share attributable to shareholders:
Continuing
operations
1.28
2.91
2.63
2.04
2.01
Net income
1.27
2.45
3.65
2.20
2.25
Cash
dividends per share
0.36
0.36
0.35
0.30
0.25
Return
on average shareholders’ equity
13.88
%
30.24
%
48.31
%
33.61
%
45.28
%
Financial
position:
Net
working capital
$
5,749
$
4,630
$
5,162
$
6,456
$
4,959
Total
assets
16,538
14,385
13,135
16,860
15,073
Property,
plant, and equipment, net
5,759
4,782
3,630
2,557
2,203
Long-term
debt (including current maturities)
4,574
2,612
2,779
2,789
3,106
Total
shareholders’ equity
8,757
7,744
6,966
7,465
6,429
Total
capitalization
13,331
10,369
9,756
10,255
9,549
Basic
weighted average common shares
outstanding
900
883
919
1,022
1,017
Diluted
weighted average common shares
outstanding
902
909
955
1,059
1,043
Other
financial data:
Capital
expenditures
$
1,864
$
1,824
$
1,583
$
834
$
575
Long-term
borrowings (repayments), net
1,944
(861
)
(7
)
(324
)
(779
)
Depreciation,
depletion, and amortization expense
931
738
583
480
448
Payroll
and employee benefits
4,783
5,264
4,585
3,853
3,211
Number
of employees
51,000
57,000
51,000
45,000
39,000
(1)
All
periods presented reflect the adoption of new accounting standards in 2009
and the reclassification of KBR, Inc. to discontinued operations in the
first quarter of 2007.
86
HALLIBURTON
COMPANY
Quarterly
Data and Market Price Information (1)
(Unaudited)
Quarter
Millions
of dollars except per share data
First
Second
Third
Fourth
Year
2009
Revenue
$
3,907
$
3,494
$
3,588
$
3,686
$
14,675
Operating
income
616
476
474
428
1,994
Net
income
380
265
266
244
1,155
Amounts
attributable to company shareholders:
Income from continuing
operations
379
263
265
247
1,154
Loss from discontinued
operations
(1
)
(1
)
(3
)
(4
)
(9
)
Net income attributable to
company
378
262
262
243
1,145
Basic
income per share attributable to company shareholders:
Income from continuing
operations
0.42
0.29
0.29
0.27
1.28
Loss from discontinued
operations
–
–
–
–
(0.01
)
Net income
0.42
0.29
0.29
0.27
1.27
Diluted
income per share attributable to company shareholders:
Income from continuing
operations
0.42
0.29
0.29
0.27
1.28
Loss from discontinued
operations
–
–
–
–
(0.01
)
Net income
0.42
0.29
0.29
0.27
1.27
Cash
dividends paid per share
0.09
0.09
0.09
0.09
0.36
Common
stock prices (2)
High
21.47
24.76
28.58
32.00
32.00
Low
14.68
14.82
18.11
25.50
14.68
2008
Revenue
$
4,029
$
4,487
$
4,853
$
4,910
$
18,279
Operating
income
847
949
1,051
1,163
4,010
Net
income
587
510
675
443
2,215
Amounts
attributable to company shareholders:
Income from continuing
operations
579
620
672
776
2,647
Income (loss) from discontinued
operations
1
(116
)
–
(308
)
(423
)
Net income attributable to
company
580
504
672
468
2,224
Basic
income per share attributable to company shareholders:
Income from continuing
operations
0.66
0.71
0.76
0.87
3.00
Loss from discontinued
operations
–
(0.13
)
–
(0.35
)
(0.48
)
Net income
0.66
0.58
0.76
0.52
2.52
Diluted
income per share attributable to company shareholders:
Income from continuing
operations
0.63
0.68
0.74
0.87
2.91
Loss from discontinued
operations
–
(0.13
)
–
(0.35
)
(0.46
)
Net income
0.63
0.55
0.74
0.52
2.45
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
(1) All
periods presented reflect the adoption of new accounting standards in the first
quarter of 2009.
(2) New
York Stock Exchange – composite transactions high and low intraday
price.
87
PART
III
Item
10. Directors, Executive Officers, and Corporate
Governance.
The
information required for the directors of the Registrant is incorporated by
reference to the Halliburton Company Proxy Statement for our 2010 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 4 through 5 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 2010 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 2010 Annual Meeting of Stockholders (File No. 1-3492) under
the caption “Corporate Governance.” The information regarding our
Audit Committee and the independence of its members, along with information
about the audit committee financial expert(s) serving on the Audit Committee, is
incorporated by reference to the Halliburton Company Proxy Statement for our
2010 Annual Meeting of Stockholders (File No. 1-3492) under the caption “The
Board of Directors and Standing Committees of Directors.”
Item
11. Executive Compensation.
This
information is incorporated by reference to the Halliburton Company Proxy
Statement for our 2010 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
2009,”“Outstanding Equity Awards at Fiscal Year End 2009,”“2009 Option
Exercises and Stock Vested,”“2009 Nonqualified Deferred Compensation,”“Pension
Benefits Table,”“Employment Contracts and Change-in-Control Arrangements,”“Post-Termination Payments,”“Equity Compensation Plan Information,” and
“Directors’ Compensation.”
Item
12(a). Security Ownership of Certain Beneficial Owners.
This
information is incorporated by reference to the Halliburton Company Proxy
Statement for our 2010 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 2010 Annual Meeting of Stockholders (File No. 1-3492) under
the caption “Stock Ownership of Certain Beneficial Owners and
Management.”
88
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 2010 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 2010 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 2010 Annual Meeting of Stockholders (File No. 1-3492) under
the caption “Fees Paid to KPMG LLP.”
89
PART
IV
Item
15. Exhibits
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 47 and 48 and pages 49 through 85 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).
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).
90
4.4
Second
Senior Indenture dated as of December 1, 1996 between the Predecessor and
The Bank of New York Trust Company, N.A. (as successor to Texas Commerce
Bank National Association), as Trustee, as supplemented and amended by the
First Supplemental Indenture dated as of December 5, 1996 between the
Predecessor and the Trustee and the Second Supplemental Indenture dated as
of December 12, 1996 among the Predecessor, Halliburton and the Trustee
(incorporated by reference to Exhibit 4.2 of Halliburton’s Registration
Statement on Form 8-B dated December 12, 1996, File No.
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 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)
91
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 6.15% Senior Notes due 2019 (included as
part of Exhibit 4.23).
4.25
Form
of Global Note for Halliburton’s 7.45% Senior Notes due 2039 (included as
part of Exhibit 4.23).
10.1
Halliburton
Company Career Executive Incentive Stock Plan as amended November 15, 1990
(incorporated by reference to Exhibit 10(a) to the Predecessor’s Form 10-K
for the year ended December 31, 1992, File No.
1-3492).
10.2
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).
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).
10.23
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).
10.24
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).
Underwriting
Agreement, dated March 10, 2009, among Halliburton and Citigroup
Global Markets Inc., Deutsche Bank Securities Inc., HSBC Securities
(USA) Inc. and Greenwich Capital Markets, Inc., as representatives of
the several underwriters identified therein (incorporated by reference to
Exhibit 1.1 to Halliburton’s Form 8-K filed March 13, 2009, File No.
1-3492).
Form
of Non-Employee Director Restricted Stock Agreement (incorporated by
reference to Exhibit 99.5 of Halliburton’s Form S-8 filed May 21, 2009,
Registration No. 333-159394).
10.35
First
Amendment to Halliburton Company Supplemental Executive Retirement Plan,
as amended and restated effective January 1, 2008 (incorporated by
reference to Exhibit 10.1 to Halliburton’s Form 8-K filed September 21,2009, File No. 1-3492).
Amendment
to Executive Employment Agreement (David S. King) (incorporated by
reference to Exhibit 10.38 to Halliburton’s Form 10-K for the year ended
December 31, 2008, File No.
1-3492).
10.43
Amendment
to Executive Employment Agreement (James S. Brown) (incorporated by
reference to Exhibit 10.39 to Halliburton’s Form 10-K for the year ended
December 31, 2008, File No.
1-3492).
10.44
Amendment
to Executive Employment Agreement (Albert O. Cornelison) (incorporated by
reference to Exhibit 10.40 to Halliburton’s Form 10-K for the year ended
December 31, 2008, File No.
1-3492).
10.45
Amendment
to Executive Employment Agreement (C. Christopher Gaut) (incorporated by
reference to Exhibit 10.41 to Halliburton’s Form 10-K for the year ended
December 31, 2008, File No.
1-3492).
10.46
Amendment
to Executive Employment Agreement (David S. King) (incorporated by
reference to Exhibit 10.42 to Halliburton’s Form 10-K for the year ended
December 31, 2008, File No.
1-3492).
*
*
*
10.47
12.1
21.1
23.1
Amendment
to Executive Employment Agreement (Mark A. McCollum) (incorporated by
reference to Exhibit 10.43 to Halliburton’s Form 10-K for the year ended
December 31, 2008, File No. 1-3492).
Statement of Computation of Ratio of Earnings to Fixed
Charges.
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
S. Malcolm Gillis
J. Landis Martin
Jay A. Precourt
Debra L. Reed
Power
of attorney for James T. Hackett signed in January 2009 (incorporated by
reference to Exhibit 24.2 to Halliburton’s Form 10-K for the year ended
December 31, 2008, File No. 1-3492).
Power
of attorney for Nance K. Dicciani, signed in July 2009.
Power
of attorney for Robert A. Malone, signed in June 2009.
Certification
of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
Certification
of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
Certification
of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
Certification
of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
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 17th day
of February, 2010.
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 17th day
of February, 2010.