UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(Amendment No. 1)
(Mark One)
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act
of 1934 For the fiscal year ended December 31, 2002
OR
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the transition period from to
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Commission File Number 1-3492
HALLIBURTON COMPANY
(Exact name of registrant as specified in its charter)
Delaware 75-2677995
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5 Houston Center, 1401 McKinney, Suite 2400, Houston, Texas 77010
(Address of principal executive offices)
Telephone Number - Area code (713) 759-2600
Securities registered pursuant to Section 12(b) of the Act:
Name of each Exchange on
Title of each class which registered
------------------- ----------------
Common Stock par value $2.50 per share New York Stock Exchange
Baroid Corporation 8% Guaranteed Senior New York Stock Exchange
Notes due 2003
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes X No
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The aggregate market value of Common Stock held by nonaffiliates on June 28,
2002, determined using the per share closing price on the New York Stock
Exchange Composite tape of $15.94 on that date was approximately $6,928,000,000.
As of February 28, 2003, there were 437,160,510 shares of Halliburton Company
Common Stock $2.50 par value per share outstanding.
Portions of the Halliburton Company Proxy Statement dated March 25, 2003 (File
No. 1-3492), are incorporated by reference into Part III of this report.
Explanatory Note
Amendments to our Historical Segment Reporting
We are amending the segment presentation in our 2002 Form 10-K to
reflect additional segments of business. Previously, we reported two segments:
the Energy Services Group and the Engineering and Construction Group (known as
"KBR"). This amendment now reflects eight segments: Pressure Pumping, Drilling
and Formation Evaluation and Other Energy Services (collectively, referred to as
the Energy Services Group) and Onshore Operations, Offshore Operations,
Government Operations, Operations and Maintenance Services and Infrastructure
Operations (collectively, referred to as the Engineering and Construction Group,
or as KBR). This eight segment presentation reflects financial information
provided to our chief executive officer (chief operating decision maker or CODM)
during the periods presented. See Note 4 to the consolidated financial
statements for a description of the operations included in each of these
segments.
Segment Changes Beginning in the Second Quarter of 2003
In the second quarter of 2003, we reorganized our Energy Services Group
into four divisions, which is the basis for the four segments we have been
reporting within the Energy Services Group beginning with our Form 10-Q for the
quarter ended June 30, 2003. We grouped product lines in order to better align
ourselves with how our customers procure our services, and to capture new
business and achieve better integration, including joint research and
development of new products and technologies and other synergies. The new
segments mirror the way our CODM now regularly reviews the operating results,
assesses performance and allocates resources. In addition, during the same
period we changed the type of financial information provided to our CODM. The
new CODM financial report reflects relevant financial data for the four new
Energy Services Group divisions, as well as summary financial information for
KBR as a whole. As a result, we have been reporting the following five segments
since the second quarter of 2003:
- Drilling and Formation Evaluation;
- Fluids (which consists of our drilling fluids operations from
the Other Energy Services segment reported in this Form 10-K/A
and our cementing operations from the Pressure Pumping segment
reported in this Form 10-K/A);
- Production Optimization (which consists of production
enhancement services and tools and testing services from the
Pressure Pumping segment reported in this Form 10-K/A and
completion products and services from the Other Energy
Services segment reported in this Form 10-K/A);
- Landmark and Other Energy Services; and
- Engineering and Construction Group.
Collectively, Drilling and Formation Evaluation, Fluids, Production
Optimization, and Landmark and Other Energy Services make up the Energy Services
Group.
Please see our Form 10-Q for the period ended June 30, 2003 and our
Form 8-K filed on October 28, 2003 for a more detailed discussion of the new
segment structure, including an update of all segment information included in
our Form 10-K for the year ended December 31, 2002. We will continue to report
these five segments for future periods.
Changes to our 2002 Form 10-K
The sections of the Form 10-K affected by this amendment to reflect
eight segments are the following:
- Item 1. Business - "General description of business",
"Description of services and products", "Dispositions in
2002", and "Customers and backlog";
- Item 2. Properties;
- Item 6. Selected Financial Data;
- Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations:
- Business Environment;
- Results of Operations in 2002 Compared to 2001;
- Results of Operations in 2001 Compared to 2000;
- Liquidity and Capital Resources;
- Reorganization of Business Operations;
- Forward-Looking Information - "Legal"; and
- Independent Auditor's Report.
- Note 1 - "Significant Accounting Policies" under the headings
"Description of Company", "Research and development", and
"Goodwill";
- Note 2 - "Acquisitions and Dispositions" under the headings
"Magic Earth acquisition", "PES acquisition", "PGS Data
Management acquisition", "European Marine Contractors Ltd.
disposition", "Subsea 7 formation", and "Bredero-Shaw
disposition"; and
- Note 4 - "Business Segment Information".
In order to preserve the nature and character of the disclosures set
forth in such items as originally filed, this report speaks as of the date of
the original filing, and we have not updated the disclosures in this report to
the date of the amended filing. While this report primarily relates to the
historical periods covered, events may have taken place since the original
filing that might have been reflected in this report if they had taken place
prior to the original filing. All information contained in this Amendment No. 1
is subject to updating and supplementing by our reports filed with the
Securities and Exchange Commission subsequent to the date of the original filing
of the Annual Report on Form 10-K on March 28, 2003.
PART I
Item 1. Business.
General description of business. Halliburton Company's predecessor was
established in 1919 and incorporated under the laws of the State of Delaware in
1924. Halliburton Company provides a variety of services, products, maintenance,
engineering and construction to energy, industrial and governmental customers.
Our eight business segments are organized as follows: Pressure Pumping,
Drilling and Formation Evaluation, and Other Energy Services (collectively, the
"Energy Services Group"), and Onshore Operations, Offshore Operations,
Government Operations, Operations and Maintenance Services, and Infrastructure
Operations (collectively, the "Engineering and Construction Group").
Dresser Equipment Group is presented as discontinued operations through
March 31, 2001 as a result of the sale in April 2001 of this business unit. See
Note 4 to the financial statements for financial information about our business
segments.
Proposed global settlement. On December 18, 2002, we announced that we
had reached an agreement in principle that, if and when consummated, would
result in a global settlement of all asbestos and silica personal injury claims
against DII Industries, LLC (DII Industries), Kellogg, Brown & Root, Inc.
(Kellogg, Brown & Root) and their current and former subsidiaries.
The agreement in principle provides that:
- up to $2.775 billion in cash, 59.5 million Halliburton shares
(valued at $1.1 billion using the stock price at December 31,
2002 of $18.71) and notes with a net present value expected to
be less than $100 million will be paid to a trust for the
benefit of current and future asbestos personal injury
claimants and current silica personal injury claimants upon
receiving final and non-appealable court confirmation of a
plan of reorganization;
- DII Industries and Kellogg, Brown & Root will retain rights to
the first $2.3 billion of any insurance proceeds with any
proceeds received between $2.3 billion and $3.0 billion going
to the trust;
- the agreement is to be implemented through a pre-packaged
Chapter 11 filing for DII Industries, Kellogg, Brown & Root
and some of their subsidiaries; and
- the funding of the settlement amounts would occur upon
receiving final and non-appealable court confirmation of a
plan of reorganization of DII Industries and Kellogg, Brown &
Root and their subsidiaries in the Chapter 11 proceeding.
Subsequently, as of March 2003, DII Industries and Kellogg, Brown &
Root have entered into definitive written agreements finalizing the terms of the
agreement in principle.
In March 2003, we agreed with Harbison-Walker and the asbestos
creditors committee in the Harbison-Walker bankruptcy to consensually extend the
period of the stay contained in the Bankruptcy Court's temporary restraining
order until July 21, 2003. The court's temporary restraining order, which was
originally entered on February 14, 2002, stays more than 200,000 pending
asbestos claims against DII Industries. The agreement provides that if the
pre-packaged Chapter 11 filing by DII Industries, Kellogg, Brown & Root and
their subsidiaries is not made by July 14, 2003, the Bankruptcy Court will hear
motions to lift the stay on July 21, 2003. The asbestos creditors committee also
reserves the right to monitor progress toward the filing of the Chapter 11
proceeding and seek an earlier hearing to lift the stay if satisfactory progress
toward the Chapter 11 filing is not being made.
See "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Liquidity and Capital Resources - Proposed global
settlement" and Note 12 to the financial statements.
Description of services and products. We offer a broad suite of
products and services through our eight business segments. The following
summarizes our services and products for each business segment.
ENERGY SERVICES GROUP
The Energy Services Group consists of the Pressure Pumping, Drilling
and Formation Evaluation and Other Energy Services business segments. It
provides a wide range of discrete services and products, as well as integrated
solutions to customers for the exploration, development and production of oil
and gas. The Energy Services Group serves major, national and independent oil
and gas companies throughout the world.
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Pressure Pumping
The Pressure Pumping segment provides services used to complete oil and
gas wells and to increase the amount of oil or gas recoverable from those wells.
Major services and products offered include:
- production enhancement;
- cementing; and
- tools and testing services.
Production enhancement optimizes oil and gas reservoirs through a
variety of pressure pumping services, including fracturing and acidizing, sand
control, coiled tubing, hydraulic workover and pipeline and process services.
These services are used to clean out a formation or to fracture formations to
allow increased oil and gas production.
Cementing is the process used to bond the well and well casing while
isolating fluid zones and maximizing wellbore stability. This is accomplished by
pumping cement and chemical additives to fill the space between the casing and
the side of the wellbore. Our cementing service line also provides casing
equipment and services.
Tools and testing services include underbalanced applications,
tubing-conveyed perforating products and services, drill stem and other well
testing tools, data acquisition services and production applications.
Drilling and Formation Evaluation
The Drilling and Formation Evaluation segment is primarily involved in
drilling and evaluating the formations related to bore-hole construction and oil
and gas formation evaluation. Major services and products offered include:
- drilling systems and services;
- drill bits; and
- logging and perforating.
Our Sperry-Sun business line provides drilling systems and services.
These services include directional and horizontal drilling,
measurement-while-drilling, logging-while-drilling, multilateral wells and
related completion systems, and rig site information systems. Our drilling
systems feature bit stability, directional control, borehole quality, low
vibration and high rates of penetration while drilling directional wells.
Drill bits, offered by our Security DBS business line, include roller
cone rock bits, fixed cutter bits, coring equipment and services and other
downhole tools used to drill wells.
Logging and perforating products and services include our Magnetic
Resonance Imaging Logging (MRIL(R)), high-temperature logging, as well as
traditional open-hole and cased-hole logging tools. MRIL(R) tools apply magnetic
resonance imaging technology to the evaluation of subsurface rock formations in
newly drilled oil and gas wells. Open-hole tools provide information on well
visualization, formation evaluation (including resistivity, porosity, lithology
and temperature), rock mechanics and sampling. Cased-hole tools provide
cementing evaluation, reservoir monitoring, pipe evaluation, pipe recovery and
perforating.
Other Energy Services
The Other Energy Services segment provides drilling fluids systems,
completion products, integrated exploration and production software information
systems, consulting services, real-time operations, smartwells, integrated
solutions, and subsea operations.
Our Baroid business line provides drilling fluid systems and
performance additives for oil and gas drilling, completion and workover
operations. In addition, Baroid sells products to a wide variety of industrial
customers. Drilling fluids usually contain bentonite or barite in a water or oil
base. Drilling fluids primarily improve wellbore stability and facilitate the
transportation of cuttings from the bottom of a wellbore to the surface. The
fluids also help cool the drill bit, seal porous well formations and assist in
pressure control within a wellbore. Fluids are often customized by onsite
engineers for optimum stability and enhanced oil production.
Completion products include subsurface safety valves and flow control
equipment, surface safety systems, packers and specialty completion equipment,
production automation, well screens, well control services and slickline
equipment and services.
Landmark Graphics is the leading supplier of integrated exploration and
production software information systems as well as professional and data
management services for the upstream oil and gas industry. Landmark Graphics
software transforms vast quantities of seismic, well log and other data into
detailed computer models of petroleum reservoirs to achieve optimal business and
technical decisions in exploration, development and production activities.
Landmark Graphics broad range of professional services enables our worldwide
2
customers to optimize technical, business and decision processes. Data
management services provide efficient storage, browsing and retrieval of large
volumes of exploration and petroleum data. The products and services offered by
Landmark Graphics integrate data workflows and operational processes across
disciplines including geophysics, geology, drilling, engineering, production,
economics, finance and corporate planning, and key partners and suppliers.
This segment provides value-added oilfield project management and
integrated solutions to independent, integrated and national oil companies.
Integrated solutions enhance field deliverability and maximize a customer's
return on investment. These services leverage all of our products and
technologies, as well as project management capabilities.
Also included in this segment is our equity method investment in Well
Dynamics B.V., an intelligent well completions joint venture, our equity method
investment in Enventure Global Technology, LLC, which is an expandable casing
joint venture and our subsea operations conducted in our 50% owned company,
Subsea 7, Inc. Other services provide installation and servicing of subsea
facilities and pipelines.
ENGINEERING AND CONSTRUCTION GROUP
The Engineering and Construction Group, operating as KBR, provides a
wide range of services to energy and industrial customers and government
entities worldwide.
KBR offers the following:
- Onshore Operations segment provides engineering and
construction activities, including engineering and
construction of liquefied natural gas, ammonia and crude oil
refineries and natural gas plants;
- Offshore Operations segment provides deepwater engineering and
marine technology and related worldwide fabrication
capabilities;
- Government Operations segment provides construction,
maintenance and logistics activities for government facilities
and installations;
- Operations and Maintenance Services segment provides plant
operations, maintenance and start-up services for both
upstream and downstream oil, gas and petrochemical facilities
as well as operations, maintenance and logistics services for
the power, commercial and industrial markets; and
- Infrastructure Operations segment provides civil engineering,
consulting and project management services.
Dispositions in 2002. During 2002, we disposed of non-core businesses
in our Other Energy Services segment listed below:
- In January 2002, we sold our 50% interest in European Marine
Contractors Limited, an unconsolidated joint venture, which
provided offshore pipeline services, to our joint venture
partner, Saipem;
- In August 2002, we sold several properties that were located
in the United States; and
- In September 2002, we sold our 50% interest in Bredero-Shaw, a
pipecoating joint venture, to our partner ShawCor Ltd.
These dispositions will have an immaterial impact on our future
operations. In addition, in May 2002, we contributed substantially all of our
Halliburton Subsea assets for 50% of the ownership in a newly formed company,
Subsea 7, Inc.
See Note 2 to the financial statements for additional information
related to 2002 dispositions and the creation of Subsea 7, Inc.
Business strategy. Our business strategy is to maintain global
leadership in providing energy services and products and engineering and
construction services. We provide these services and products to our customers
as discrete services and products and, when combined with project management
services, as integrated solutions. Our ability to be a global leader depends on
meeting four key goals:
- establishing and maintaining technological leadership;
- achieving and continuing operational excellence;
- creating and continuing innovative business relationships; and
- preserving a dynamic workforce.
3
Markets and competition. We are one of the world's largest diversified
energy services and engineering and construction services companies. We believe
that our future success will depend in large part upon our ability to offer a
wide array of services and products on a global scale. 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), service quality, product quality, warranty and technical
proficiency. While we provide a wide range of discrete services and products, a
number of customers have indicated a preference for integrated services and
solutions. In the case of the Energy Services Group, integrated services and
solutions relate to all phases of exploration, development and production of
oil, natural gas and natural gas liquids. In the case of the Engineering and
Construction Group, integrated services and solutions relate to all phases of
design, procurement, construction, project management and maintenance of
facilities primarily for energy and government customers.
We conduct business worldwide in over 100 countries. For 2002, the
United States represented 33% of our total revenue and the United Kingdom
represented 12%. No other country accounted for more than 10% of our total
revenue. Since 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. Substantially 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, expropriation or other governmental
actions and exchange control and currency problems. 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. While Venezuela accounted for less than two percent of our
2002 revenues, the current economic and political instability in Venezuela will
negatively impact our operations until resolved. In addition, as a result of the
breadth of our businesses and the inherently unpredictable impact of the armed
conflict in the Middle East, we are unable to predict their impact on our
results of operations. Moreover, due to rising levels of civil disturbance, a
number of our customers has ceased operations in the Nigerian Delta region.
Energy Services operations in Nigeria accounted for approximately 2% of our
revenues in 2002, and these developments could negatively impact our operations
in 2003. Information regarding our exposures 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 19 to the financial
statements.
Customers and backlog. Our revenues from continuing operations during
the past three years were mainly derived from the sale of services and products
to the energy industry. Sales of services and products to the energy industry in
2002 represented 86% of revenues from continuing operations compared to 85% in
2001 and 84% in 2000.
The following schedule summarizes the backlog from continuing
operations of engineering and construction projects at December 31, 2002 and
2001:
Millions of dollars 2002 2001
-----------------------------------------------------------------------------
Firm orders $ 8,704 $ 8,118
Government orders firm but not yet funded,
letters of intent and contracts awarded
but not signed 1,330 1,794
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Total $ 10,034 $ 9,912
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Of the total backlog at December 31, 2002, $9,776 million relates to
KBR operations with the remainder arising from our Energy Services Group,
principally in the Other Energy Services segment. We estimate that 43% of the
total backlog existing at December 31, 2002 will be completed during 2003.
Approximately 37% of total backlog relates to fixed-price contracts with the
remaining 63% relating to cost reimbursable contracts. In addition, backlog
relating to engineering, procurement, installation and commissioning contracts
for the offshore oil and gas industry totaled $904 million at December 31, 2002.
For contracts that are not for a specific amount, backlog is estimated as
follows:
4
- operations and maintenance contracts that cover multiple years
are included in backlog based upon an estimate of the work to
be provided over the next twelve months; and
- government contracts that cover a broad scope of work up to a
maximum value are included in backlog at the estimated amount
of work to be completed under the contract based upon periodic
consultation with the customer.
For projects where we act as project manager, we only include our scope
of each project in backlog. For projects related to unconsolidated joint
ventures, we only include our percentage ownership of each joint venture's
backlog. Our backlog excludes contracts for recurring hardware and software
maintenance and support services offered by Landmark Graphics. Backlog is not
indicative of future operating results because backlog figures are subject to
substantial fluctuations. Arrangements included in backlog are in many instances
extremely complex, nonrepetitive in nature and may fluctuate in contract value
and timing. Many contracts do not provide for a fixed amount of work to be
performed and are subject to modification or termination by the customer. The
termination or modification of any one or more sizeable contracts or the
addition of other contracts may have a substantial and immediate effect on
backlog.
Raw materials. Raw materials essential to our business are normally
readily available. Where we rely on a single supplier for materials essential to
our business, we are confident that we could make satisfactory alternative
arrangements in the event of an interruption in supply.
Research and development costs. We maintain an active research and
development program. The program improves existing products and processes,
develops new products and processes and improves engineering standards and
practices that serve the changing needs of our customers. Our expenditures for
research and development activities totaled $233 million in both 2002 and 2001
and $231 million in 2000. Further information relating to our expenditures for
research and development is included in Note 1 to the financial statements.
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. Included in
"Other assets" are patents, net of accumulated amortization, totaling $58
million as of December 31, 2002 and $49 million as of December 31, 2001. We do
not consider any particular patent or group of patents 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:
- the severity and duration of the winter in North America can
have a significant impact on gas storage levels and drilling
activity for natural gas;
- the timing and duration of the spring thaw in Canada directly
affects activity levels due to road restrictions;
- typhoons and hurricanes can disrupt offshore operations; and
- severe weather during the winter months normally results in
reduced activity levels in the North Sea.
Employees. At December 31, 2002, we employed approximately 83,000
people worldwide compared to 85,000 at December 31, 2001. At December 31, 2002,
approximately five percent of our employees were subject to collective
bargaining agreements. Based upon the geographic diversification of these
employees, we believe any risk of loss from employee strikes or other collective
actions would not be material to the conduct of our operations taken as a whole.
Environmental regulation. We are subject to numerous environmental,
legal and regulatory requirements related to our operations worldwide. In the
United States, these laws and regulations include the Comprehensive
Environmental Response, Compensation and Liability Act, the Resources
Conservation and Recovery Act, the Clean Air Act, the Federal Water Pollution
Control Act and the Toxic Substances Control Act, among others. In addition to
the federal laws and regulations, states where we do business may have
equivalent laws and regulations with 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.
5
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. We have subsidiaries that have been named as potentially
responsible parties along with other third parties for ten federal and state
superfund sites for which we have established a liability. As of December 31,
2002, those ten sites accounted for $8 million of our total $48 million
liability. See Note 12 to the financial statements.
Website access. The Company's 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 the Company's internet website
at www.halliburton.com as soon as reasonably practicable after the Company has
electronically filed such material with, or furnished it to, the Securities and
Exchange Commission.
Item 2. Properties.
We own or lease numerous properties in domestic and foreign locations.
The following locations represent our major facilities:
Owned/
Location Leased Sq. Footage Description
----------------------------------------------------------------------------------------------------------------------
Energy Services Group
North America
Drilling and Formation
Evaluation Segment:
Dallas, Texas Owned 352,000 Manufacturing facility includes office, laboratory
and warehouse space that primarily produces roller
cone drill bits. In 2002, we announced plans to
move production from this facility to a new facility
in The Woodlands, Texas. The planned move is
expected in 2003.
Other Energy Services Segment:
Carrollton, Texas Owned 792,000 Manufacturing facility including warehouses,
engineering and sales, testing, training and
research. The manufacturing plant produces
equipment for the Other Energy Services segment,
including surface and subsurface safety valves and
packer assemblies.
Shared Facilities:
Duncan, Oklahoma Owned 1,275,000 Four locations which include manufacturing capacity
totaling 655,000 square feet. The manufacturing
facility is the main manufacturing site for
cementing, fracturing and acidizing equipment. The
Duncan facilities also include a technology and
research center, training facility, administrative
offices and warehousing. These facilities service
our Pressure Pumping, Drilling and Formation
Evaluation and Other Energy Services segments.
6
Owned/
Location Leased Sq. Footage Description
----------------------------------------------------------------------------------------------------------------------
Shared Facilities (cont'd):
Houston, Texas Owned 690,000 Two suburban campus locations utilized by our
Drilling and Formation Evaluation and Other Energy
Services segments. One campus is on 89 acres
consisting of office, training, test well,
warehouse, manufacturing and laboratory facilities.
The manufacturing facility, which occupies 115,000
square feet, produces highly specialized downhole
equipment for our Drilling and Formation Evaluation
segment. The other campus is a manufacturing
facility with limited office, laboratory and
warehouse space that primarily produces fixed cutter
drill bits.
Houston, Texas Owned 593,000 A campus facility that is the home office for the
Energy Services Group.
Alvarado, Texas Owned 238,000 Manufacturing facility including some office and
warehouse space. The manufacturing facility
produces perforating products and exploratory and
formation evaluation tools for our Drilling and
Formation Evaluation and Pressure Pumping segments.
Europe/Africa
Other Energy Services Segment:
Arbroath, United Kingdom Owned 119,000 Manufacturing site that produces completion products.
Montrose, United Kingdom Owned 213,000 Service operation center for completion products and
services equipment set on a 7.5 acre site including
office, workshop, warehouse, and yard used as open
storage. Also accommodates a development center
with two training wells.
Shared Facilities:
Aberdeen, United Kingdom Owned 1,216,000 A total of 26 sites including 866,000 square feet of
Leased 365,000 manufacturing capacity used by various business
segments.
Tananger, Norway Leased 319,000 Service center with workshops, testing facilities,
warehousing and office facilities supporting the
Norwegian North Sea operations.
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Owned/
Location Leased Sq. Footage Description
----------------------------------------------------------------------------------------------------------------------
Engineering and Construction Group
North America
Shared Facilities:
Houston, Texas Leased 851,000 Engineering and project support center which
occupies 33 full floors in 2 office buildings. One
of these buildings is owned by a joint venture in
which we have a 50% ownership. The remaining 50% of
the joint venture is owned by a subsidiary of Trizec
Properties Inc. (NYSE: TRZ). Trizec is not
affiliated with Halliburton Company or any of its
directors or executive officers.
Houston, Texas Owned 1,017,000 A campus facility occupying 135 acres utilized
primarily for administrative and support personnel.
Approximately 221,000 square feet is dedicated to
maintenance and warehousing of construction
equipment. This campus also serves as office
facilities for KBR's headquarters and our temporary
corporate headquarters.
Europe/Africa
Shared Facilities:
Leatherhead, United Kingdom Owned 226,000 Engineering and project support center on 55 acres
in suburban London.
In 2002, we closed our Dallas corporate office and temporarily
relocated it to the Houston facility that also serves as headquarters for KBR.
In 2003, the corporate headquarters will be moved from this location to offices
in downtown Houston which are currently being completed.
In addition, we have 181 international and 108 domestic field camps
from which the Energy Services Group delivers its products and services. We also
have numerous small facilities that include sales offices, project offices and
bulk storage facilities throughout the world. We own or lease marine fabrication
facilities covering approximately 761 acres in Texas, England and Scotland which
are used by the Engineering and Construction Group.
We have mineral rights to proven and probable reserves of barite and
bentonite. These rights include leaseholds, mining claims and owned property. We
process barite and bentonite for supply to many industrial markets worldwide in
addition to using it in our drilling fluids operations. Based on the number of
tons of bentonite consumed in fiscal year 2002, we estimate our 22 million tons
of proven reserves in areas of active mining are sufficient to fulfill our
internal and external needs for the next 15 years. We estimate that our 750,000
tons of proven reserves of barite in areas of active mining equate to a 27 year
supply based on current rates of production. These estimates are subject to
change based on periodic updates to reserve estimates and to the extent future
consumption differs from current levels of consumption.
We believe all properties that we currently occupy are suitable for
their intended use.
Item 3. Legal Proceedings.
Information relating to various commitments and contingencies is
described in Management's Discussion and Analysis of Financial Condition and
Results of Operations and Note 12 to the 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 2002.
8
Executive Officers of the Registrant.
The following table indicates the names and ages of the executive
officers of the registrant as of February 1, 2003, along with a listing of all
offices held by each during the past five years:
Name and Age Offices Held and Term of Office
------------ -------------------------------
Jerry H. Blurton Vice President and Treasurer of Halliburton Company, since July 1996
(Age 58)
Cedric W. Burgher Vice President - Investor Relations of Halliburton Company, since September 2001
(Age 42) Vice President of Enron Corp. and Enron Oil & Gas Company, March 1996 to
September 2001
Assistant Treasurer of Baker Hughes, Inc., March 1993 to March 1996
Margaret E. Carriere Vice President, Secretary and Corporate Counsel of Halliburton Company, since
(Age 51) September 2002
Vice President and Corporate Counsel of Halliburton Company,
May 2002 to September 2002
Vice President - Human Resources of Halliburton Company, August 2000 to May
2002
Vice President - Legal and Secretary of Halliburton Energy Services, Inc.,
February 2000 to August 2000
Law Department Manager of Integration & Development of Halliburton
Energy Services, Inc., October 1998 to February 2000
Region Chief Counsel (London) Europe/Africa Law Department of Halliburton
Energy Services, Inc., May 1994 to September 1998
* Albert O. Cornelison, Jr. Executive Vice President and General Counsel of Halliburton Company, since
(Age 53) December 2002
Vice President and General Counsel of Halliburton Company, May 2002 to
December 2002
Vice President and Associate General Counsel of Halliburton Company, October
1998 to May 2002
Staff Vice President and Associate General Counsel of Dresser Industries, Inc.,
February 1994 to September 1998
Charles E. Dominy Vice President - Government Affairs of Halliburton Company, since December 2000
(Age 62) Vice President, Business Development of Kellogg Brown & Root, Inc., September
1995 to December 2000
* Douglas L. Foshee Executive Vice President and Chief Financial Officer of Halliburton Company, since
(Age 43) August 2001
Chairman, President and CEO of Nuevo Energy Company, July 1997 to May 2001
President and Chief Executive Officer of Torch Energy Advisors, Inc., May 1995 to
July 1997
* John W. Gibson, Jr. Chief Executive Officer of Energy Services Group, since January 2003
(Age 45) President of Halliburton Energy Services, March 2002 to December 2002
President and Chief Executive Officer of Landmark, May 2000 to February 2002
Chief Operating Officer of Landmark, July 1999 to April 2000
Executive Vice President of Integrated Products Group, February 1996 to June 1999
9
Executive Officers of the Registrant (continued)
Name and Age Offices Held and Term of Office
------------ -------------------------------
* Robert R. Harl Chief Executive Officer of Kellogg Brown & Root, Inc., since March 2001
(Age 52) President of Kellogg Brown & Root, Inc., since October 2000
Vice President of Kellogg Brown & Root, Inc., March 1999 to October 2000
Chief Executive Officer and President of Brown & Root Energy Services Division
of Kellogg Brown & Root, Inc., April 2000 to February 2001
Chief Executive Officer of Brown & Root Services Division of Kellogg Brown &
Root, Inc., January 1999 to April 2000
Chief Executive Officer and President of Brown & Root Services Corporation,
November 1996 to January 1999
Vice President of Brown & Root, Inc., July 1989 to July 1998
Arthur D. Huffman Vice President and Chief Information Officer of Halliburton Company, since
(Age 50) August 2000
Chief Information Officer of Group Air Liquide, 1997 to August 2000
Vice President - Information Technology of Air Liquide America Corporation,
1995 to 1997
* David J. Lesar Chairman of the Board, President and Chief Executive Officer of Halliburton
(Age 49) Company, since August 2000
Director of Halliburton Company, since August 2000
President and Chief Operating Officer of Halliburton Company, May 1997 to
August 2000
Executive Vice President and Chief Financial Officer of Halliburton Company,
August 1995 to May 1997
Chairman of the Board of Kellogg Brown & Root, Inc., January 1999 to August 2000
President and Chief Executive Officer of Brown & Root, Inc., September 1996 to
December 1998
Weldon J. Mire Vice President - Human Resources of Halliburton Company, since May 2002
(Age 55) Division Vice President of Halliburton Energy Services, January 2001 to May 2002
Asia Pacific Sales Manager of Halliburton Energy Services, November 1999 to
January 2001
Director of Business Development, September 1999 to November 1999
Global Director of Strategic Business Development, January 1999 to November
1999
Senior Shared Service Manager Houston, November 1998 to January 1999
IS Project Manager II - Venezuela, May 1998 to November 1998
Tools and Testing and TCP Product Manager, July 1997 to May 1998
R. Charles Muchmore, Jr. Vice President and Controller of Halliburton Company, since August 1996
(Age 49)
10
Executive Officers of the Registrant (continued)
Name and Age Offices Held and Term of Office
------------ -------------------------------
David R. Smith Vice President - Tax of Halliburton Company, since May 2002
(Age 56) Vice President - Tax of Halliburton Energy Services, Inc., September 1998 to May
2002
Vice President - Tax of Dresser Industries, Inc., 1993 to September 1998
* Members of the Policy Committee of the registrant.
There are no family relationships between the executive officers of the
registrant or between any director and any executive officer of the registrant.
11
PART II
Item 5.Market for the Registrant's Common Stock and Related Stockholder Matters.
Halliburton Company's common stock is traded on the New York Stock
Exchange and the Swiss Exchange. Information relating to the high and low market
prices of common stock and quarterly dividend payment is included under the
caption "Quarterly Data and Market Price Information" on pages 99 and 100 of
this annual report. Cash dividends on common stock for 2002 and 2001 were paid
in March, June, September, and December of each year. 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.
At December 31, 2002, there were approximately 25,027 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.
Item 6. Selected Financial Data.
Information relating to selected financial data is included on pages 96
through 98 of this annual report.
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
Information relating to Management's Discussion and Analysis of
Financial Condition and Results of Operations is included on pages 14 through 46
of this annual report.
Item 7(a). Quantitative and Qualitative Disclosures About Market Risk.
Information relating to market risk is included in Management's
Discussion and Analysis of Financial Condition and Results of Operations under
the caption "Financial Instrument Market Risk" on page 39 of this annual report.
12
Item 8. Financial Statements and Supplementary Data.
Page No.
--------
Independent Auditor's Report 47-48
Consolidated Statements of Operations for the years ended December 31, 2002, 2001 and 2000 49
Consolidated Balance Sheets at December 31, 2002 and 2001 50
Consolidated Statements of Shareholders' Equity for the years ended December 31, 2002, 2001 and 2000 51-52
Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000 53-54
Notes to Annual Financial Statements 55-95
1. Significant Accounting Policies 55-58
2. Acquisitions and Dispositions 58-59
3. Discontinued Operations 59-60
4. Business Segment Information 60-63
5. Restricted Cash 63
6. Receivables 64
7. Inventories 64
8. Unapproved Claims and Long-Term Construction Contracts 64-66
9. Property, Plant and Equipment 66
10. Related Companies 66
11. Lines of Credit, Notes Payable and Long-Term Debt 67-68
12. Commitments and Contingencies 68-83
13. Income (loss) Per Share 83
14. Reorganization of Business Operations 83-84
15. Change in Accounting Method 84
16. Income Taxes 85-87
17. Common Stock 87-89
18. Series A Junior Participating Preferred Stock 89
19. Financial Instruments and Risk Management 89-91
20. Retirement Plans 91-95
21. Dresser Industries, Inc. Financial Information 95
22. Goodwill and Other Intangible Assets 95
Selected Financial Data (Unaudited) 96-98
Quarterly Data and Market Price Information (Unaudited) 99-100
The related financial statement schedules are included under Part IV,
Item 15 of this annual report.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
13
HALLIBURTON COMPANY
Management's Discussion and Analysis of Financial Condition and
Results of Operations
In this section, we discuss the business environment, operating results
and general financial condition of Halliburton Company and its subsidiaries. We
explain:
- factors and risks that impact our business;
- why our earnings and expenses for the year 2002 vary from 2001
and why our earnings and
expenses for 2001 vary from 2000;
- capital expenditures;
- factors that impacted our cash flows; and
- other items that materially affect our financial condition or
earnings.
BUSINESS ENVIRONMENT
We currently operate in over 100 countries throughout the world,
providing a comprehensive range of discrete and integrated products and services
to the energy industry and to other industrial and governmental customers. The
majority of our consolidated revenues is derived from the sale of services and
products, including engineering and construction activities to major, national
and independent oil and gas companies. These products and services are used
throughout the energy industry from the earliest phases of exploration,
development and production of oil and gas resources through refining, processing
and marketing. Our eight business segments are as follows: Pressure Pumping,
Drilling and Formation Evaluation, and Other Energy Services (collectively,
referred to as the Energy Services Group), and Onshore Operations, Offshore
Operations, Government Operations, Operations and Maintenance Services, and
Infrastructure Operations (collectively, referred to as the Engineering and
Construction Group, or as KBR).
The industries we serve are highly competitive with many substantial
competitors for each segment. In 2002, the United States represented 33% of our
total revenue and the United Kingdom represented 12%. No other country accounted
for more than 10% of our operations. Unsettled political conditions, social
unrest, acts of terrorism, force majeure, war or other armed conflict,
expropriation or other governmental actions, inflation, exchange controls or
currency devaluation may result in increased business risk in any one country.
We believe the geographic diversification of our business activities reduces the
risk that loss of business in any one country would be material to our
consolidated results of operations.
Halliburton Company
Activity levels within our business segments are significantly impacted
by the following:
- spending on upstream exploration, development and production
programs by major, national and independent oil and gas
companies;
- capital expenditures for downstream refining, processing,
petrochemical and marketing facilities by major, national and
independent oil and gas companies; and
- government spending levels.
Also impacting our activity is the status of the global economy, which
indirectly impacts oil and gas consumption, demand for petrochemical products
and investment in infrastructure projects.
Some of the more significant barometers of current and future spending
levels of oil and gas companies are oil and gas prices, exploration and
production drilling prospects, the world economy and global stability which
together drive worldwide drilling activity. As measured by rig count, high
levels of worldwide drilling activity during the first half of 2001 began to
decline in the latter part of that year. Drilling levels reached a low,
particularly in the United States for gas drilling, in April 2002. The decline
was partially due to general business conditions caused by global economic
uncertainty which was accelerated by the terrorist attacks on September 11,
2001. An abnormally warm 2001/2002 winter season in the United States also
resulted in increased working gas in storage. The high level of gas in storage
put pressure on gas prices, which resulted in reduced gas drilling activity
particularly in the Western portion of the United States.
For the year 2002, natural gas prices at Henry Hub averaged $3.33 per
million cubic feet, commonly referred to as mcf, compared to $4.07 per mcf in
2001. Gas prices continued to decline during the first two months of 2002 and
then steadily increased throughout the year ending at an average of $4.65 per
14
mcf in December. Based upon data from a leading research association at the end
of 2002, the gas price at Henry Hub was expected to average slightly above $3.73
per mcf for all of 2003 and $4.00 per mcf for the 2003 first quarter. However,
actual prices have been significantly higher averaging $6.33 per mcf during
January and February. These higher gas prices have not translated into
significantly increased gas drilling rig activity as of the end of February.
Natural gas prices have been impacted by an abnormally cold 2002/2003
winter season thus far in the United States, resulting in reduced gas storage
levels. As of January 31, 2003, working gas in storage was 1,521 billion cubic
feet, commonly referred to as bcf, according to Energy Information
Administration estimates. These stocks were 811 bcf less than last year at this
time and 287 bcf below the 5-year average of 1,808 bcf. At 1,521 bcf, total
working gas in storage is within the 5-year historical range. While gas prices
in the United States have historically varied somewhat geographically, this
winter we have seen significantly higher fluctuations in regional gas prices in
the United States. For example, while the price averaged $4.27 per mcf in the
fourth quarter at Henry Hub, it was less than $2.00 per mcf in various parts of
the Western United States. This is resulting in significant variation in gas
drilling activity by region in the United States and much lower drilling and
stimulation activity in the gas basins of the Western United States.
Crude oil prices for West Texas Intermediate, commonly referred to as
WTI, averaged $25.92 per barrel for all of 2002 compared to $26.02 per barrel
for 2001. Oil prices have continued to trend upward since the beginning of 2002.
Quarterly average WTI increased from $20.52 in the 2001 fourth quarter, to
$28.23 in the 2002 third quarter and increased slightly to $28.34 during the
2002 fourth quarter. We believe that current oil prices reflect the disruption
of supplies from Venezuela due to political unrest related to the national
strike and a war premium due to the risk of supply disruption as a result of the
armed conflict in the Middle East. OPEC, on January 12, 2003, agreed to raise
its output ceiling by 1.5 million barrels per day or 6.5% to 24.5 million
barrels per day. Prices for the first and second quarters of 2003 will be
impacted by the length of disruption of Venezuelan crude oil supplies, the
ability of OPEC to manage country production quotas, political tensions in the
Middle East, global demand and the level of production by major non-OPEC
countries, including Norway, Russia and other members of the former Soviet
Union.
Energy Services Group
Lower natural gas and crude oil drilling activity since the 2001 third
quarter has resulted in decreased demand for the services and products provided
by the Energy Services Group. The yearly average and quarterly average rig
counts based on the Baker Hughes Incorporated rig count information are as
follows:
Average Rig Counts 2002 2001 2000
--------------------------------------------------------------------------------------
United States 831 1,155 916
Canada 266 342 344
International (excluding Canada) 732 745 652
--------------------------------------------------------------------------------------
Worldwide Total 1,829 2,242 1,912
======================================================================================
Fourth Third Second First Fourth Third
Quarter Quarter Quarter Quarter Quarter Quarter
Average Rig Counts 2002 2002 2002 2002 2001 2001
--------------------------------------------------------------------------------------------------------------
United States 847 853 806 818 1,004 1,241
Canada 283 250 147 383 278 320
International
(excluding Canada) 753 718 725 731 748 757
--------------------------------------------------------------------------------------------------------------
Worldwide Total 1,883 1,821 1,678 1,932 2,030 2,318
==============================================================================================================
Worldwide rig activity started to decline in the latter part of the
third quarter 2001 and averaged 1,829 rigs in 2002 as compared to 2,242 in 2001.
The decline in rig activity was most severe in North America, particularly the
United States, where the rig count dropped 28% from an average of 1,155 in 2001
to 831 in 2002, with the majority of this decline due to reduced gas drilling.
In the past, there has generally been a good correlation between the price of
oil and gas in the United States and rig activity. However, this has not been
the case in recent months where the rig count has declined as compared to the
fourth quarter 2001, while WTI oil and Henry Hub gas prices have increased. We
believe this is due to economic uncertainty, which we expect to continue into at
least the next quarter or two, created by the following:
15
- volatility of oil and gas prices;
- disruption of oil supplies from Venezuela;
- differences in gas prices geographically in the United States;
- less spending due to current uncertain global economic
environment;
- the armed conflict in the Middle East;
- budgetary constraints of some of our customers;
- focus on debt reduction by some of our customers;
- lack of quality drilling prospects by exploration and
production companies; and
- level of United States working gas in storage during the
winter heating season.
It is common practice in the United States oilfield services industry
to sell services and products based on a price book and then apply discounts to
the price book based upon a variety of factors. The discounts applied typically
increase to partially or substantially offset price book increases in the weeks
immediately following a price increase. The discount applied normally decreases
over time if the activity levels remain strong. During periods of reduced
activity, discounts normally increase, reducing the net revenue for our services
and conversely during periods of higher activity, discounts normally decline
resulting in net revenue increasing for our services.
During 2000 and 2001, we implemented several price book increases. In
July 2000, as a result of increased consumable materials costs and a tight labor
market causing higher labor costs, we increased prices in the United States for
most products and services on average between 2% and 12%. In January 2001, as a
result of continued labor shortages and increased labor and materials costs, we
increased prices in the United States on average between 5% and 12%. In July
2001, as a result of continuing personnel and consumable material cost
increases, we increased prices on average between 6% and 15%.
The decreased rig activity in 2002 from 2001 in the United States has
increased pressure on the Energy Services Group to discount prices. The price
increases we implemented last year have mostly been eroded by additional
discounts. Our Pressure Pumping segment has been significantly impacted by the
current economic slowdown due to its dependence on United States gas drilling.
Our deepwater activity has not been as adversely impacted as land
activity by the downturn in the energy industry, due to the level of investment
and the long-term nature of contracts. Our drilling systems and services
included in our Drilling and Formation Evaluation segment, which currently has a
large percentage of its business outside the United States and is currently
heavily involved in deepwater oil and gas exploration and development drilling
and longer term contracts, has remained relatively strong despite the overall
decline in the energy industry. Our operations have also been impacted by
political and economic instability in Indonesia and in Latin America. In Latin
America, the impact was primarily in Argentina in the earlier part of 2002 and
then in Venezuela toward the end of 2002, due to political unrest related to the
national strike. We also experienced disruptions due to Tropical Storm Isidore
and Hurricane Lili in the Gulf of Mexico.
Based upon data from Spears and Associates, drilling activity in the
United States and Canada in 2003 is expected to increase compared to overall
2002 levels and compared to the fourth quarter 2002. This reflects the current
level of oil and gas prices and tight supplies. International drilling activity
is expected to remain constant with fourth quarter 2002 levels.
At the end of 2002, two brokerage firms released exploration and
production expenditure surveys for 2003. Salomon Smith Barney reported that
worldwide exploration and production spending is expected to increase 3.8% in
2003. North America spending was forecasted to rise 1.5%. The report also noted
that a lack of quality drilling prospects and uncertainty over Iraq have also
contributed to a weaker initial spending forecast. Lehman Brothers made similar
predictions. They are projecting a 4.2% increase in worldwide exploration and
production expenditures for 2003, but a slight decrease in United States
spending. Canadian exploration and production spending is estimated to increase
7.2%. International exploration and production expenditures are estimated to
grow 5.5% in 2003, led by national oil companies and European majors. According
to the Lehman report, exploration and production company budgets were based upon
an average oil price estimate of $23.22 per barrel (WTI) and $3.42 per mcf for
natural gas (Henry Hub).
Until economic and political uncertainties impacting customer spending
become clearer, we expect oilfield services activity to be essentially flat in
the short-term and improve in the second half of 2003. The armed conflict in
16
the Middle East could disrupt our operations in the region and elsewhere for the
duration of the conflict. In the longer term, we expect increased global demand
for oil and natural gas, additional customer spending to replace depleting
reserves and our continued technological advances to provide growth
opportunities.
Engineering and Construction Group
Our engineering and construction projects are longer term in nature
than our energy services projects and are not significantly impacted by
short-term fluctuations in oil and gas prices. We believe that the global
economy's recovery is continuing, but its strength and sustainability are not
assured. Based on the uncertain economic recovery and continuing excess capacity
in petrochemical supplies, customers have continued to delay project awards or
reduce the scope of projects involving hydrocarbons and manufacturing. A number
of large-scale gas and liquefied natural gas development, offshore deepwater,
government and infrastructure projects are being awarded or actively considered.
However, in light of terrorist threats, the armed conflict and increasing
instability in the Middle East and the modest growth of the global economy, many
customers are delaying some of their capital commitments and international
investments.
We expect growth opportunities to exist for additional security and
defense support to government agencies in the United States and other countries.
Demand for these services is expected to grow as a result of the armed conflict
in the Middle East and as governmental agencies seek to control costs and
promote efficiencies by outsourcing these functions. We also expect growth due
to new demands created by increased efforts to combat terrorism and enhance
homeland security.
Engineering and construction contracts can be broadly categorized as
fixed-price, sometimes referred to as lump sum, or cost reimbursable contracts.
Some contracts can involve both fixed-price and cost reimbursable elements.
Fixed-price contracts are for a fixed sum to cover all costs and any
profit element for a defined scope of work. Fixed-price contracts entail more
risk to us as we must pre-determine both the quantities of work to be performed
and the costs associated with executing the work. The risks to us arise, among
other things, from:
- having to judge the technical aspects and effort involved to
accomplish the work within the contract schedule;
- labor availability and productivity; and
- supplier and subcontractor pricing and performance.
Fixed-price engineering, procurement and construction and fixed-price
engineering, procurement, installation and commissioning contracts involve even
greater risks including:
- bidding a fixed-price and completion date before detailed
engineering work has been performed;
- bidding a fixed-price and completion date before locking in
price and delivery of significant procurement components
(often items which are specifically designed and fabricated
for the project);
- bidding a fixed-price and completion date before finalizing
subcontractors terms and conditions;
- subcontractors individual performance and combined
interdependencies of multiple subcontractors (the majority of
all construction and installation work is performed by
subcontractors);
- contracts covering long periods of time;
- contract values generally for large amounts; and
- contracts containing significant liquidated damages
provisions.
Cost reimbursable contracts include contracts where the price is
variable based upon actual costs incurred for time and materials, or for
variable quantities of work priced at defined unit rates. Profit elements on
cost reimbursable contracts may be based upon a percentage of costs incurred
and/or a fixed amount. Cost reimbursable contracts are generally less risky,
since the owner retains many of the risks. While fixed-price contracts involve
greater risk, they also potentially are more profitable for the contractor,
since the owners pay a premium to transfer many risks to the contractor.
After careful consideration, we have decided no longer to pursue
riskier fixed-price engineering, procurement, installation and commissioning
contracts for the offshore oil and gas industry. An important aspect of our 2002
reorganization was to look closely at each of our businesses to ensure that they
are self-sufficient, including their use of capital and liquidity. In that
process, we found that the engineering, procurement, installation and
commissioning of offshore projects was using a disproportionate share of our
bonding and letter of credit capacity relative to its profit contribution, and
17
determined to not pursue those types of projects in the future. We provide a
range of engineering, fabrication and project management services to the
offshore industry, which we will continue to service through a variety of other
contracting forms. We have seven fixed-price engineering, procurement,
installation and commissioning offshore projects underway and we are fully
committed to successful completion of these projects, several of which are
substantially complete. We plan to retain our offshore engineering and services
capabilities.
The approximate percentages of revenues attributable to fixed-price and
cost reimbursable Engineering and Construction Group segments contracts are as
follows:
Fixed-Price Cost
Reimbursable
----------------------------------------------
2002 47% 53%
2001 41% 59%
2000 47% 53%
==============================================
Reorganization of Business Operations
On March 18, 2002, we announced plans to restructure our businesses
into two operating subsidiary groups, the Energy Services Group and KBR,
representing the Engineering and Construction Group. As part of this
reorganization, we are separating and consolidating the entities in our Energy
Services Group together as direct and indirect subsidiaries of Halliburton
Energy Services, Inc. We are also separating and consolidating the entities in
our Engineering and Construction Group together as direct and indirect
subsidiaries of the former Dresser Industries Inc., which became a limited
liability company during the second quarter of 2002 and was renamed DII
Industries, LLC. The reorganization of subsidiaries facilitated the separation,
organizationally and financially of our business groups, which we believe will
significantly improve operating efficiencies, while streamlining management and
easing manpower requirements. In addition, many support functions that were
previously shared were moved into the two business groups. Although we have no
specific plans currently, the reorganization would facilitate separation of the
ownership of the two business groups in the future if we identify an opportunity
that produces greater value for our shareholders than continuing to own both
business groups.
We expect only a minimal amount of restructuring costs to be incurred
in 2003. In 2002, we incurred approximately $107 million in restructuring
charges consisting of the following:
- $64 million in personnel related expense;
- $17 million of asset related write-downs;
- $20 million in professional fees related to the
restructuring; and
- $6 million related to contract terminations.
We anticipate annualized cost savings of $200 million compared to costs
prior to the corporate reorganization.
As a part of the reorganization, we decided that the operations of
Major Projects (which currently consists of the Barracuda-Caratinga project in
Brazil), Granherne and Production Services were better aligned with KBR in the
current business environment and these businesses were moved from the Energy
Services Group to the Engineering and Construction Group during the second
quarter of 2002. All prior period segment results have been restated to reflect
this change.
Asbestos and Silica
On December 18, 2002, we announced that we had reached an agreement in
principle that, if and when consummated, would result in a global settlement of
all asbestos and silica personal injury claims. The agreement in principle
covers all current and future personal injury asbestos claims against DII
Industries, Kellogg, Brown & Root and their current and former subsidiaries, as
well as all current silica claims asserted presently or in the future. We
revised our best estimate of our asbestos and silica liability based on
information obtained while negotiating the agreement in principle, and adjusted
our asbestos and silica liability to $3.425 billion, recorded additional
probable insurance recoveries resulting in a total of $2.1 billion as of
December 31, 2002 and recorded a net pretax charge of $799 million ($675 million
after-tax) in the fourth quarter of 2002.
18
Should the proposed global settlement become probable under Statement
of Financial Accounting Standards No. 5, we would adjust our accrual for
probable and reasonably estimable liabilities for current and future asbestos
and silica claims. The settlement amount initially would be up to $4.0 billion,
consisting of up to $2.775 billion in cash, 59.5 million Halliburton shares of
common stock and notes with a net present value expected to be less than $100
million. Assuming the revised liability would be $4.0 billion, we would also
increase our probable insurance recoveries to $2.3 billion. The impact on our
income statement would be an additional pretax charge of $322 million ($288
million after-tax). This accrual (which values our stock to be contributed at
$1.1 billion using our stock price at December 31, 2002 of $18.71) would then be
adjusted periodically based on changes in the market price of our common stock
until the common stock was contributed to a trust for the benefit of the
claimants.
RESULTS OF OPERATIONS IN 2002 COMPARED TO 2001
REVENUES
Increase/
Millions of dollars 2002 2001 (Decrease)
----------------------------------------------------------------------------------------------
Pressure Pumping $ 2,770 $ 3,127 $ (357)
Drilling and Formation Evaluation 1,633 1,643 (10)
Other Energy Services 2,433 3,041 (608)
----------------------------------------------------------------------------------------------
Total Energy Services Group 6,836 7,811 (975)
----------------------------------------------------------------------------------------------
Onshore Operations 1,813 1,422 391
Offshore Operations 1,457 1,156 301
Government Operations 1,217 1,436 (219)
Operations and Maintenance Services 927 956 (29)
Infrastructure Operations 322 265 57
----------------------------------------------------------------------------------------------
Total Engineering and Construction Group 5,736 5,235 501
----------------------------------------------------------------------------------------------
Total revenues $ 12,572 $ 13,046 $ (474)
==============================================================================================
Consolidated revenues for 2002 were $12.6 billion, a decrease of 4%
compared to 2001. International revenues comprised 67% of total revenues in 2002
and 62% in 2001. International revenues increased $298 million in 2002 partially
offsetting a $772 million decline in the United States where oilfield services
drilling activity declined 28%, putting pressure on pricing.
Pressure Pumping revenues decreased $357 million compared to 2001. The
decrease was attributable to reduced production enhancement services of $197
million and reduced cementing services of $160 million due to decreased rig
counts in North America which put significant pricing pressures on the segment.
On a geographic basis, the decrease in revenues was primarily due to a
$443 million decrease of North America revenues, as a result of decreased rig
counts. This was partially offset by increases in Middle East/Asia of $67
million from increased rig counts and new contracts in the region and
Europe/Africa of $22 million from increased rig counts. International revenues
were 50% in 2002 compared with 42% in 2001 for the segment.
Drilling and Formation Evaluation revenues declined slightly in 2002
compared to 2001. Approximately $62 million of the decrease was due to lower
North American logging and perforating activity. An additional $21 million of
the change resulted from decreased drill bit sales principally in North America.
These decreases were partially offset by $74 million of increased drilling
systems activity primarily in international locations such as Saudi Arabia,
Thailand, Mexico, Brazil, and the United Arab Emirates.
On a geographic basis, the decline in revenue is attributable to lower
levels of rig activity in North America, which also put pressure on pricing of
work in the United States. Latin American revenues decreased 1% as a result of
decreases in Argentina due to currency devaluation and in Venezuela due to lower
activity brought on by uncertain market and political conditions and the
national strike. International revenues were 72% of Drilling and Formation
Evaluation's revenues in 2002 compared to 66% in 2001.
Other Energy Services revenues declined $608 million, or 20%, in 2002
compared to 2001. Approximately $353 million of the decline is due to lower
revenues from subsea operations as most of the assets of Halliburton Subsea were
contributed to the formation of Subsea 7, Inc. (which was formed in May 2002 and
19
is accounted for under the equity method). In addition, approximately $117
million of the decline is from lower revenues from integrated solutions projects
as a result of the sale of several properties during 2002. Further, revenue
decreased $89 million from drilling fluid sales and $56 million from lower
completion products and services. Both reductions occurred primarily in North
America from decreased rig counts. Partially offsetting the decline is a $40
million increase in software and professional services revenues due to strong
2002 sales in all geographic areas by Landmark Graphics.
Onshore Operations segment revenues increased $391 million, or 27%, in
2002 compared to 2001. The improvement was due to increased activities on
liquefied natural gas projects in Nigeria and Egypt, startup of an oil and gas
project in Algeria, and progress on projects in Chad, Cameroon, and Belgium.
Partially offsetting the revenue increase were lower revenues of $155 million on
hydrocarbon projects in Canada and Qatar and liquefied natural gas activities in
Malaysia.
Offshore Operations segment revenues increased $301 million, or 26%, in
2002 compared to 2001. The improvement was due to progress on the
Barracuda-Caratinga project in Brazil and the Belanak project in Indonesia.
Partially offsetting the revenue increase were lower revenues of $406 million on
oil and gas projects in the Philippines, Mexico and Nigeria.
Government Operations segment revenues decreased $219 million, or 15%,
in 2002 compared to 2001. The decrease is due to completion of a major project
at our shipyard in the United Kingdom during 2002 and lower volumes of
logistical support in the Balkans in 2002 compared to 2001.
Operations and Maintenance Services segment revenues decreased $29
million, or 3%, in 2002 compared to 2001. The decrease was due to reduced
downstream maintenance activity in the United States. Partially offsetting the
decrease was increased revenue on upstream projects in Canada and in the Middle
East.
Infrastructure Operations segment revenues increased $57 million, or
22%, in 2002 compared to 2001. The improvement was due to increased progress on
the Alice Springs to Darwin Rail Line project in Australia and revenues from
Europe/Africa.
OPERATING INCOME (LOSS)
Increase/
Millions of dollars 2002 2001 (Decrease)
--------------------------------------------------------------------------------------------
Pressure Pumping $ 454 $ 676 $ (222)
Drilling and Formation Evaluation 160 171 (11)
Other Energy Services 24 189 (165)
--------------------------------------------------------------------------------------------
Total Energy Services Group 638 1,036 (398)
--------------------------------------------------------------------------------------------
Onshore Operations 43 79 (36)
Offshore Operations (179) (15) (164)
Government Operations 60 42 18
Operations and Maintenance Services 5 6 (1)
Infrastructure Operations 30 10 20
Asbestos and Silica Charges (644) (11) (633)
--------------------------------------------------------------------------------------------
Total Engineering and Construction Group (685) 111 (796)
--------------------------------------------------------------------------------------------
General corporate (65) (63) (2)
--------------------------------------------------------------------------------------------
Operating income (loss) $ (112) $ 1,084 $ (1,196)
============================================================================================
Consolidated operating loss was $112 million for 2002 compared to
operating income of $1.1 billion in 2001. In 2002, our results included:
- $564 million expense in the Engineering and Construction Group
related to asbestos and silica liabilities;
- $117 million loss in the Offshore Operations segment on the
Barracuda-Caratinga project in Brazil;
- $108 million gain in Other Energy Services on the sale of our
50% interest in European Marine Contractors;
20
- $107 million in expense related to restructuring charges, of
which $64 million related to Other Energy Services, $18
million related to the Engineering and Construction Group
segments and $25 million related to general corporate;
- $98 million expense in Other Energy Services related to patent
infringement litigation;
- $80 million expense resulting from the write-off of billed and
accrued receivables related to the Highlands Insurance Company
litigation in the asbestos and silica charges, formerly
reported in general corporate;
- $79 million loss in Other Energy Services on the sale of our
50% equity investment in the Bredero-Shaw joint venture; and
- $29 million gain for the value of stock received from the
demutualization of an insurance provider in general corporate.
In 2002, we recorded no amortization of goodwill due to the adoption of
SFAS No. 142. For 2001, we recorded $42 million in goodwill amortization ($2
million in Drilling and Formation Evaluation, $22 million in Other Energy
Services, $8 million in Onshore Operations, $5 million in Offshore Operations,
$3 million in Operations and Maintenance Services, and $2 million in
Infrastructure Operations).
Pressure Pumping operating income decreased $222 million, or 33%, in
2002 compared to 2001. Reduced production enhancement activities contributed
$149 million of the decrease and cementing services contributed $70 million,
both affected primarily by the reduced oil and gas drilling in North America.
On a geographic basis, the decline in operating income was mainly
attributable to North America, which decreased $248 million, as a result of
reduction of average rig counts in the United States of 28%. This was offset by
an increase in Europe/Africa of $21 million from increased rig activity in the
region.
Drilling and Formation Evaluation operating income declined 6% in 2002
compared to 2001. Approximately $37 million of the decrease related to reduced
operating income in logging and perforating services and $8 million related to
the drill bits business, both affected by the reduced oil and gas drilling
activity in North America. Offsetting these declines was a $22 million increase
in drilling systems operating income due to improved international activity.
On a geographic basis, the decline in operating income is attributable
to lower levels of rig activity and pricing pressures in North America. The
decrease in North America operating income was partially offset by higher
operating income from international sources in Brazil, Mexico, Algeria, Angola,
Egypt, China, and Saudi Arabia.
Other Energy Services operating income decreased $165 million in 2002
compared to 2001. Significant factors influencing the results included:
- $108 million gain on the sale of our 50% interest in European
Marine Contractors in 2002;
- $98 million charge recorded in 2002 related to patent
infringement litigation;
- $79 million loss on the sale of our 50% equity investment in
the Bredero-Shaw joint venture in 2002;
- $66 million of impairments recorded in 2002 on integrated
solutions projects primarily in the United States, Indonesia
and Columbia, partially offset by net gains of $45 million on
2002 disposals of properties in the United States; and
- $64 million in 2002 restructuring charges.
In addition, drilling fluids services contributed $35 million of the
decrease, primarily due to the reduced level of oil and gas drilling in North
America. This was partially offset by an $11 million increase in completion
products and services operating income due to higher international activity
which more than offset reduced oil and gas drilling in North America. Also
partially offsetting the decrease was $22 million in goodwill amortization
expense that was recorded in 2001 but not in 2002, as a result of our adoption
of SFAS No. 142. Landmark Graphics experienced $32 million in improved
profitability from increased sales of software and professional services.
Onshore Operations segment operating income decreased $36 million, or
46%, in 2002 compared to 2001. The decrease in income was due to completion of
an oil and gas project in Algeria during 2002 and lower progress on the
construction of a liquefied natural gas project in Malaysia. Partially
offsetting the decrease in income were earnings from liquefied natural gas
projects in Nigeria and Egypt that began in 2002.
21
Offshore Operations segment operating loss increased $164 million in
2002 compared to 2001. The increase in the loss was primarily due to losses
recorded in 2002 on the Barracuda-Caratinga project in Brazil of $117 million
and a project in the Philippines totaling $36 million.
Government Operations segment operating income increased $18 million,
or 43%, in 2002 compared to 2001. The improved results were primarily due to
activities at our shipyard in the United Kingdom and improved results from
projects in Asia Pacific and Americas. Partially offsetting the increase in 2002
is non-recurring income earned on a contract with the United Kingdom Ministry of
Defense recorded in 2001.
Operations and Maintenance Services segment operating income decreased
$1 million, or 17%, in 2002 compared to 2001. The decrease in income was
primarily due to lower volumes on downstream maintenance projects in the United
States and a loss recorded on a project in the Middle East. Slightly offsetting
these decreases was growth in facility services projects.
Infrastructure Operations segment operating income increased $20
million in 2002, tripling 2001 operating income. The improvement was primarily
due to progress on the Alice Springs to Darwin Rail Line project in Australia,
offset slightly by a loss on a road project in England.
Asbestos and silica charges of $644 million were recorded during 2002,
which represents the best estimate of our asbestos and silica liability based on
information we obtained while negotiating the global asbestos settlement and an
$80 million expense resulting from the write-off of billed and accrued
receivables related to the Highlands Insurance Company litigation.
General corporate expenses were $65 million for 2002 as compared to $63
million in 2001. Expenses in 2002 include restructuring charges of $25 million
and a gain from the value of stock received from the demutualization of an
insurance provider of $29 million.
NONOPERATING ITEMS
Interest expense of $113 million for 2002 decreased $34 million
compared to 2001. The decrease is due to repayment of debt and lower average
borrowings in 2002, partially offset by the $5 million in interest related to
the patent infringement judgment which we are appealing.
Interest income was $32 million in 2002 compared to $27 million in
2001. The increased interest income is for interest on a note receivable from a
customer which had been deferred until collection.
Foreign currency losses, net were $25 million in 2002 compared to $10
million in 2001. The increase is due to negative developments in Brazil,
Argentina and Venezuela.
Other, net was a loss of $10 million in 2002, which includes a $9.1
million loss on the sale of ShawCor Ltd. common stock acquired in the sale of
our 50% interest in Bredero-Shaw.
Provision for income taxes was $80 million in 2002 compared to a
provision for income taxes of $384 million in 2001. Exclusive of the tax effect
on the asbestos and silica accrual (net of insurance recoveries) and the loss on
sale of Bredero-Shaw, our 2002 effective tax rate from continuing operations was
38.9% for 2002 compared to 40.3% in 2001. The asbestos and silica accrual
generates a United States Federal deferred tax asset which was not fully
benefited because we anticipate that a portion of the asbestos and silica
deduction will displace foreign tax credits and those credits will expire
unutilized. As a result, we have recorded a $114 million valuation allowance in
continuing operations and $119 million in discontinued operations associated
with the asbestos and silica accrual, net of insurance recoveries. In addition,
continuing operations has recorded a valuation allowance of $49 million related
to potential excess foreign tax credit carryovers. Further, our impairment loss
on Bredero-Shaw cannot be fully benefited for tax purposes due to book and tax
basis differences in that investment and the limited benefit generated by a
capital loss carryback. Settlement of unrealized prior period tax exposures had
a favorable impact to the overall tax rate.
Minority interest in net income of subsidiaries in 2002 was $38 million
as compared to $19 million in 2001. The increase was primarily due to increased
activity in Devonport Management Limited.
Loss from continuing operations was $346 million in 2002 compared to
income from continuing operations of $551 million in 2001.
22
Loss from discontinued operations was $806 million pretax, $652 million
after-tax, or $1.51 per diluted share in 2002 compared to a loss of $62 million
pretax, $42 million after-tax, or $0.10 per diluted share in 2001. The loss in
2002 was due primarily to charges recorded for asbestos and silica liabilities.
The pretax loss for 2001 represents operating income of $37 million from Dresser
Equipment Group through March 31, 2001 offset by a $99 million pretax asbestos
accrual primarily related to Harbison-Walker.
Gain on disposal of discontinued operations of $299 million after-tax,
or $0.70 per diluted share, in 2001 resulted from the sale of our remaining
businesses in the Dresser Equipment Group in April 2001.
Cumulative effect of accounting change, net in 2001 of $1 million
reflects the impact of adoption of Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and for Hedging Activities."
After recording the cumulative effect of the change our estimated annual expense
under Financial Accounting Standards No. 133 is not expected to be materially
different from amounts expensed under the prior accounting treatment.
Net loss for 2002 was $998 million, or $2.31 per diluted share. Net
income for 2001 was $809 million, or $1.88 per diluted share.
RESULTS OF OPERATIONS IN 2001 COMPARED TO 2000
REVENUES
Increase/
Millions of dollars 2001 2000 (Decrease)
---------------------------------------------------------------------------------------------
Pressure Pumping $ 3,127 $ 2,357 $ 770
Drilling and Formation Evaluation 1,643 1,287 356
Other Energy Services 3,041 2,589 452
---------------------------------------------------------------------------------------------
Total Energy Services Group 7,811 6,233 1,578
---------------------------------------------------------------------------------------------
Onshore Operations 1,422 2,228 (806)
Offshore Operations 1,156 916 240
Government Operations 1,436 1,355 81
Operations and Maintenance Services 956 869 87
Infrastructure Operations 265 343 (78)
---------------------------------------------------------------------------------------------
Total Engineering and Construction Group 5,235 5,711 (476)
---------------------------------------------------------------------------------------------
Total revenues $ 13,046 $11,944 $ 1,102
=============================================================================================
Consolidated revenues for 2001 were $13.0 billion, an increase of 9%
compared to 2000. International revenues comprised 62% of total revenues in 2001
and 66% in 2000 as activity and pricing increased in our Energy Services Group
more rapidly in the United States than internationally particularly in the first
half of 2001. Our Energy Services Group experienced revenue growth despite a 14%
decline in oil prices and a 3% decrease in natural gas prices between December
2000 and December 2001. Our Engineering and Construction Group revenues, which
did not benefit from the positive factors contributing to the growth of the
Energy Services Group, decreased 8%. Engineering and construction projects are
long-term in nature and customers continued to delay major projects with the
slowdown in the economy occurring in the latter part of 2001.
Pressure Pumping revenues increased $770 million, or 33%, in 2001
compared to 2000. Production enhancement activities contributed $447 million of
the improvement, cementing services accounted for $257 million and sales of
tools and testing services contributed $65 million of the increase, all
positively impacted by higher drilling activity, particularly in the Gulf of
Mexico, and pricing improvements.
On a geographic basis, North America revenues increased $585 million as
a result of higher drilling activity and pricing improvements. Latin America
increased $59 million with the most significant improvements in Brazil and
Venezuela. Europe/Africa increased $58 million primarily in Norway and the
United Kingdom. International revenues were 42% of total segment revenues in
2001 compared to 48% in 2000.
Drilling and Formation Evaluation revenues increased $356 million, or
28%, in 2001 compared to 2000. Drilling systems contributed $208 million of the
increase, logging and perforating services contributed $110 million, and drill
bit sales contributed $38 million, all due to higher oil and gas rig counts and
23
pricing improvements, particularly in the United States. Geo-Pilot(TM) and other
new products introduced in drilling services improved revenue in 2001 by
approximately $50 million. We design and assemble the Geo-Pilot(TM) tool from
parts manufactured to our specifications by third parties.
On a geographic basis, United States revenues increased by $148 million
and international revenues increased $208 million, with the most significant
improvements in Brazil, Venezuela, Nigeria, Norway, the United Kingdom, and
Russia. International revenues were 66% of total segment revenues in 2001
compared to 68% in 2000.
Other Energy Services revenues increased $452 million, or 17%, in 2001
from 2000. Sales of drilling fluids accounted for $228 million of the
improvement and completion products and services contributed $91 million, which
were both positively impacted by higher drilling activity, particularly in the
Gulf of Mexico, and pricing improvements. Landmark Graphics experienced $60
million in growth in software and professional services sales of which $28
million related to the acquisition of PGS Data Management in March 2001.
Integrated solutions revenues increased $69 million due to higher oil and gas
prices in the United States in the first half of 2001. Subsea operations posted
$15 million lower revenue due to lower activity levels in Norway.
Onshore Operations segment revenues decreased $806 million, or 36%, in
2001 compared to 2000. The decrease was primarily due to completion of
hydrocarbon projects in Norway and Singapore, a power project in the United
States, a gas project nearing completion in Nigeria, and highway and paving
construction jobs in North America during 2001. Partially offsetting the revenue
decrease were earnings from a new liquefied natural gas project in Malaysia and
an oil and gas project in Algeria.
Offshore Operations segment revenues increased $240 million, or 26%, in
2001 from 2000. The increase was primarily due to progress on the
Barracuda-Caratinga project in Brazil, which began operations in the third
quarter of 2000. Partially offsetting the revenue increase were lower revenues
on oil and gas projects in Mexico.
Government Operations segment revenues increased $81 million, or 6%, in
2001 from 2000. The improvement was primarily due to increases in activities at
our shipyard in the United Kingdom of approximately $67 million which related to
a contract with the United Kingdom Ministry of Defense. Partially offsetting the
revenue increase is lower activity on the logistical contract in the Balkans.
The project moved to the sustainment phase, which involved providing support at
the facilities which were constructed during the initial phase of the contract.
Operations and Maintenance Services segment revenues increased $87
million, or 10%, in 2001 from 2000. The increase was partially due to higher
volumes on downstream maintenance activity in the United States as our customers
focused on maintaining current facilities and plant operations. There was also
increased activity on downstream projects in the United Kingdom, Middle East and
Australia.
Infrastructure Operations segment revenues decreased $78 million, or
23%, in 2001 compared to 2000. The decrease in revenue was primarily due to the
completion of the baseball stadium in Houston. Partially offsetting the decrease
were revenues from start-up of the construction of the Alice Springs to Darwin
Rail Line in Australia.
OPERATING INCOME
Increase/
Millions of dollars 2001 2000 (Decrease)
--------------------------------------------------------------------------------------------
Pressure Pumping $ 676 $ 314 $ 362
Drilling and Formation Evaluation 171 1 170
Other Energy Services 189 274 (85)
--------------------------------------------------------------------------------------------
Total Energy Services Group 1,036 589 447
--------------------------------------------------------------------------------------------
Onshore Operations 79 (45) 124
Offshore Operations (15) (63) 48
Government Operations 42 44 (2)
Operations and Maintenance Services 6 1 5
Infrastructure Operations 10 14 (4)
Asbestos and Silica Charges (11) (5) (6)
--------------------------------------------------------------------------------------------
Total Engineering and Construction Group 111 (54) 165
--------------------------------------------------------------------------------------------
General corporate (63) (73) 10
--------------------------------------------------------------------------------------------
Total operating income $1,084 $ 462 $ 622
============================================================================================
24
Consolidated operating income increased $622 million, or 135%, from
2000 to 2001. In 2000 our operating income included two significant items: an
$88 million gain on the sale of marine vessels (reflected in our Other Energy
Services segment) and a charge of $36 million related to the restructuring of
the Engineering and Construction Group segments.
Pressure Pumping operating income increased $362 million in 2001
compared to 2000. Production enhancement services contributed $214 million of
the increase, cementing services contributed $122 million and sales of tools and
testing services contributed $26 million, all benefiting from increased activity
levels, higher equipment utilization and improved pricing, particularly in the
United States in the first nine months of 2001.
On a geographic basis, the increase in operating income was primarily
in North America, which increased $290 million on increased drilling activity
and pricing improvements.
Drilling and Formation Evaluation operating income increased to $171
million in 2001 compared to a breakeven position in 2000. Drilling systems
contributed $118 million of the increase, logging and perforating services
contributed $36 million, and drill bit sales contributed $27 million, all
benefiting from increased activity levels, higher equipment utilization and
improved pricing, particularly in the United States in the first nine months of
2001. Incremental margin, which is calculated by taking the change in operating
income over the applicable periods and dividing by the change in revenues over
the same period, increased by 48% for Drilling and Formation Evaluation.
On a geographic basis, United States operating income increased by $40
million and international operating income increased $130 million, with the
largest improvements in Nigeria, the United Kingdom, Indonesia, and Russia.
Other Energy Services operating income decreased $85 million in 2001
from 2000. The primary reason for the decline in results was the recording of an
$88 million gain in 2000 related to the sale of marine vessels. Subsea
operations contributed $109 million to the decrease due to lower activity
levels, job losses and the gain on sale of marine vessels in 2000 mentioned
above. Additionally, Landmark Graphics operating income was $6 million lower in
2001 due primarily to increases in research and development costs. However,
drilling fluids increased $13 million and completion products and services
increased $37 million both benefiting from increased activity levels, higher
equipment utilization and improved pricing, particularly in the United States in
the first nine months of 2001. Integrated solutions operating income increased
$4 million, benefiting from higher gas and oil prices in the United States in
the first half of 2001.
Onshore Operations segment operating income increased $124 million in
2001 from a loss position in 2000. The increase was primarily due to significant
losses recorded in the fourth quarter of 2000 of $131 million as a result of
higher than estimated costs on specific jobs in North America, Latin America and
Algeria and unfavorable claims negotiations on other jobs.
Offshore Operations segment operating loss decreased $48 million, or
76%, in 2001 compared to 2000. The improvement was primarily due to progress on
oil and gas projects in Mexico and Nigeria and to losses recorded in the fourth
quarter of 2000 of $26 million. Partially offsetting the improvement was a $4
million loss in 2001 on an offshore oil and gas project in the Philippines and a
revised profit estimate on the Barracuda-Caratinga project in Brazil.
Government Operations segment operating income decreased $2 million, or
5%, in 2001 compared to 2000. The decrease in income was primarily due to lower
activity on the logistical contract in the Balkans. Partially offsetting the
decrease was non-recurring income from a contract with the United Kingdom
Ministry of Defense.
Operations and Maintenance Services segment operating income increased
$5 million in 2001 compared to 2000. The improvement was primarily due to
upstream projects in the United Kingdom, partially offset by increased expenses
in business development.
Infrastructure Operations segment operating income decreased $4
million, or 29%, in 2001 compared to 2000. The decrease in income was primarily
due to a loss recorded on a highway project in the United Kingdom. Partially
offsetting the decrease were earnings from the start-up of construction on the
Alice Springs to Darwin Rail Line project in Australia.
Asbestos and silica charges of $11 million were recorded in 2001.
25
General corporate expenses were $63 million for 2001 compared to $73
million in 2000. In 2000 general corporate expenses included $9 million of costs
recorded in the third quarter of 2000 related to the early retirement of our
previous chairman and chief executive officer.
NONOPERATING ITEMS
Interest expense of $147 million in 2001 was $1 million higher than in
2000. Our outstanding short-term debt was substantially higher in the first part
of 2001 due to repurchases of our common stock in the fourth quarter of 2000
under our repurchase program and borrowings associated with the acquisition of
PGS Data Management in March 2001. Cash proceeds of $1.27 billion received in
April 2001 from the sale of the remaining businesses within the Dresser
Equipment Group were used to repay our short-term borrowings; however, our
average borrowings for 2001 were slightly higher than in 2000. The impact of
higher average borrowings was mostly offset by lower interest rates on
short-term borrowings.
Interest income was $27 million in 2001, an increase of $2 million from
2000.
Foreign currency losses, net were $10 million in 2001 as compared to $5
million in 2000. Argentina's financial crisis accounted for $4 million of the $5
million increase.
Other, net was less than a $1 million gain in 2001 and a loss of $1
million in 2000.
Provision for income taxes was $384 million for an effective tax rate
of 40.3% in 2001 compared to 38.5% in 2000.
Minority interest in net income of subsidiaries in 2001 was $19 million
as compared to $18 million in 2000.
Income (loss) from discontinued operations in 2001 was a $42 million
loss, or $0.10 per diluted share, due to accrued expenses associated with
asbestos claims of disposed businesses. See Note 3. The loss was partially
offset by net income for the first quarter of 2001 from Dresser Equipment Group
of $0.05 per diluted share. Income from discontinued operations of $98 million,
or $0.22 per diluted share, represents the net income of Dresser Equipment Group
for the full year of 2000.
Gain on disposal of discontinued operations in 2001 was $299 million
after-tax, or $0.70 per diluted share. The 2001 gain resulted from the sale of
our remaining businesses within the Dresser Equipment Group in April 2001. The
gain of $215 million after-tax, or $0.48 per diluted share, in 2000 resulted
from the sale of our 51% interest in Dresser-Rand, formerly a part of Dresser
Equipment Group, in January 2000.
Cumulative effect of accounting change, net of $1 million reflects the
adoption of SFAS No. 133 "Accounting for Derivative Instruments and Hedging
Activities" in the first quarter of 2001.
Net income for 2001 was $809 million, or $1.88 per diluted share, as
compared to net income of $501 million, or $1.12 per diluted share in 2000.
LIQUIDITY AND CAPITAL RESOURCES
We ended 2002 with cash and cash equivalents of $1.1 billion compared
with $290 million at the end of 2001 and $231 million at the end of 2000.
Cash flows from operating activities provided $1.6 billion for 2002
compared to providing $1.0 billion in 2001 and using $57 million in 2000. The
net loss in 2002 was due to an after-tax asbestos and silica charge of $1.1
billion which has no effect on 2002 cash flows. Some factors which accounted for
cash flows from operations for 2002 were as follows:
- we collected large milestone payments on several long-term
contracts;
- we collected several large receivables during 2002 in our
Energy Services Group
- we sold an undivided ownership interest to unaffiliated
companies under the accounts receivable securitization
agreement for a net cash inflow of $180 million (see Note 6 to
the financial statements); and
- we managed inventory at lower levels during 2002.
Cash flows from investing activities used $473 million for 2002, $858
million for 2001 and $411 million for 2000. Capital expenditures of $764 million
in 2002 were about 4% lower than in 2001 and about 32% higher than in 2000.
Capital spending in 2002 continued to be primarily directed to the Energy
26
Services Group, for fracturing equipment and directional and
logging-while-drilling equipment. In addition, we invested $60 million in an
integrated solutions project. Included in sales of property, plant and equipment
is $130 million collected from the sale of properties and cash collected from
other asset sales. Dispositions of businesses in 2002 include $134 million
collected from the sale of our European Marine Contractors Ltd. joint venture.
Proceeds from the sale of securities of $62 million was for the sale of ShawCor
shares. Included in the restricted cash balance for 2002 are the following:
- $107 million deposit that collateralizes a bond for a patent
infringement judgment and interest, which judgment is on
appeal;
- $57 million as collateral for potential future insurance claim
reimbursements; and
- $26 million primarily related to cash collateral agreements
for outstanding letters of credit for several construction
projects.
In March 2001, we acquired the PGS Data Management division of
Petroleum Geo-Services ASA for $164 million cash. In addition we spent $56
million for various other acquisitions in 2001.
Cash flows from financing activities used $248 million in 2002, $1.4
billion in 2001 and $584 million in 2000. Proceeds from exercises of stock
options provided cash flows of less than $1 million in 2002, $27 million in 2001
and $105 million in 2000. We paid dividends of $219 million to our shareholders
in 2002, $215 million in 2001 and $221 million in 2000.
Included in payments on long-term borrowings of $81 million in 2002 is
a repayment of a $75 million medium-term note. In the fourth quarter of 2002,
our 51% owned and consolidated subsidiary, Devonport Management Limited, signed
an agreement for a credit facility of (pound)80 million ($126 million as of
December 31, 2002) maturing in September 2009. Devonport Management Limited drew
down $66 million from this facility in the fourth quarter. Proceeds from the
sale of the remaining businesses in Dresser Equipment Group in April 2001, the
sale of Dresser-Rand in early 2000 and the collection of a note from the fourth
quarter 1999 sale of Ingersoll-Dresser Pump received in early 2000 were used to
reduce short-term debt. On July 12, 2001, we issued $425 million in two and five
year medium-term notes under our medium-term note program. The notes consist of
$275 million of 6% fixed rate notes due August 1, 2006 and $150 million of
floating rate notes due July 16, 2003. Net proceeds from the two medium-term
note offerings were also used to reduce short-term debt. Net repayments of
short-term debt in 2001 used $1.5 billion.
On April 25, 2000, our Board of Directors approved plans to implement a
share repurchase program for up to 44 million shares. We repurchased 1.2 million
shares at a cost of $25 million in 2001 and 20.4 million shares at a cost of
$759 million in 2000. We currently have no plan to repurchase the remaining
shares under the approved plan. In addition, we repurchased $4 million of common
stock in 2002, $9 million in 2001 and $10 million in 2000 from employees to
settle their income tax liabilities primarily for restricted stock lapses.
Cash flows from discontinued operations provided $1.3 billion in 2001
and $826 million in 2000. No cash flows from discontinued operations were
provided in 2002. Cash flows for 2001 include proceeds from the sale of Dresser
Equipment Group of approximately $1.27 billion. Cash flows for 2000 include
proceeds from the sale of Dresser-Rand and Ingersoll-Dresser Pump of $913
million.
Capital resources from internally generated funds and access to capital
markets are sufficient to fund our working capital requirements and investing
activities. Our combined short-term notes payable and long-term debt was 30% of
total capitalization at the end of 2002, 24% at the end of 2001, and 40% at the
end of 2000. Short-term debt was reduced significantly in the second quarter of
2001 with the proceeds from the sale of Dresser Equipment Group and in the third
quarter from the issuance of $425 million of medium-term notes. In 2000 we
reduced our short-term debt with proceeds from the sales of Ingersoll-Dresser
Pump and Dresser-Rand joint ventures early in the year. We increased short-term
debt in the third quarter of 2000 to fund share repurchases. At December 31,
2002, we had $190 million in restricted cash included in "Other assets". See
Note 5 to the financial statements. In addition on April 15, 2002, we entered
into an agreement to sell accounts receivable to provide additional liquidity.
See Note 6 to the financial statements. Currently, we expect capital
expenditures in 2003 to be about $700 million. We have not finalized our capital
expenditures budget for 2004 or later periods.
Proposed global settlement. On December 18, 2002, we announced that we
had reached an agreement in principle that, if and when consummated, would
result in a global settlement of all asbestos and silica personal injury claims
against DII Industries, Kellogg, Brown & Root and their current and former
subsidiaries.
27
The agreement in principle provides that:
- up to $2.775 billion in cash, 59.5 million Halliburton shares
(valued at $1.1 billion using the stock price at December 31,
2002 of $18.71) and notes with a net present value expected to
be less than $100 million will be paid to a trust for the
benefit of current and future asbestos personal injury
claimants and current silica personal injury claimants upon
receiving final and non-appealable court confirmation of a
plan of reorganization;
- DII Industries and Kellogg, Brown & Root will retain rights to
the first $2.3 billion of any insurance proceeds with any
proceeds received between $2.3 billion and $3.0 billion going
to the trust;
- the agreement is to be implemented through a pre-packaged
Chapter 11 filing for DII Industries and Kellogg, Brown &
Root, and some of their subsidiaries; and
- the funding of the settlement amounts would occur upon
receiving final and non-appealable court confirmation of a
plan of reorganization of DII Industries and Kellogg, Brown &
Root and their subsidiaries in the Chapter 11 proceeding.
Subsequently, as of March 2003, DII Industries and Kellogg, Brown &
Root have entered into definitive written agreements finalizing the terms of the
agreement in principle. The proposed global settlement also includes silica
claims as a result of current or past exposure. These silica claims are less
than 1% of the personal injury claims included in the proposed global
settlement. We have approximately 2,500 open silica claims.
Among the prerequisites for reaching a conclusion of the settlement
are:
- agreement on the amounts to be contributed to the trust for
the benefit of silica claimants;
- our review of the more than 347,000 current claims to
establish that the claimed injuries are based on exposure to
products of DII Industries, Kellogg, Brown & Root, their
subsidiaries or former businesses or subsidiaries;
- completion of our medical review of the injuries alleged to
have been sustained by plaintiffs to establish a medical basis
for payment of settlement amounts;
- finalizing the principal amount of the notes to be contributed
to the trust;
- agreement with a proposed representative of future claimants
and attorneys representing current claimants on procedures for
distribution of settlement funds to individuals claiming
personal injury;
- definitive agreement with the attorneys representing current
asbestos claimants and a proposed representative of future
claimants on a plan of reorganization for the Chapter 11
filings of DII Industries, Kellogg, Brown & Root and some of
their subsidiaries; and agreement with the attorneys
representing current asbestos claimants with respect to, and
completion and mailing of, a disclosure statement explaining
the pre-packaged plan of reorganization to the more than
347,000 current claimants;
- arrangement of financing on terms acceptable to us to fund the
cash amounts to be paid in the settlement;
- Halliburton board approval;
- obtaining affirmative votes to the plan of reorganization from
at least the required 75% of known present asbestos claimants
and from a requisite number of silica claimants needed to
complete the plan of reorganization; and
- obtaining final and non-appealable bankruptcy court approval
and federal district court confirmation of the plan of
reorganization.
Many of these prerequisites are subject to matters and uncertainties
beyond our control. There can be no assurance that we will be able to satisfy
the prerequisites for completion of the settlement. If we were unable to
complete the proposed settlement, we would be required to resolve current and
future asbestos claims in the tort system or, in the case of Harbison-Walker
claims (see Note 12 to the financial statements), possibly through the
Harbison-Walker bankruptcy proceedings.
The template settlement agreement with attorneys representing current
claimants grants the attorneys a right to terminate the definitive settlement
agreement on ten days' notice if DII Industries does not file a plan of
reorganization on or before April 1, 2003. We are conducting due diligence on
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the asbestos claims, which is not expected to be completed by April 1, 2003.
Therefore, we do not expect DII Industries to file a plan of reorganization
prior to April 1. Although there can be no assurances, we do not believe the
claimants' attorneys will terminate the settlement agreements on April 1, 2003
as long as adequate progress is being made toward a Chapter 11 filing.
We have begun our due diligence review of current asbestos claims.
While these results are preliminary and not necessarily indicative of the
eventual results of a completed review of all current asbestos claims, it
appears that a substantial portion of the records for claims reviewed to date do
not provide detailed product identification. We expect that many of these
records could be supplemented by attorneys representing the claimants to provide
additional information on product identification. However, no assurance can be
given that the additional product identification documentation will be timely
provided or sufficient for us or the plaintiffs to proceed with the proposed
global settlement. In addition, although the medical information in the files we
preliminarily reviewed appears significantly more complete, if a material number
of claims ultimately do not meet the medical criteria for alleged injuries, no
assurance can be given that a sufficient number of plaintiffs would vote to
ratify the plan of reorganization that would implement the global settlement. In
such case, we would not proceed with a Chapter 11 filing.
In March 2003, we agreed with Harbison-Walker and the asbestos
creditors committee in the Harbison-Walker bankruptcy to consensually extend the
period of the stay contained in the Bankruptcy Court's temporary restraining
order until July 21, 2003. The court's temporary restraining order, which was
originally entered on February 14, 2002, stays more than 200,000 pending
asbestos claims against DII Industries. The agreement provides that if the
pre-packaged Chapter 11 filing by DII Industries, Kellogg, Brown & Root and
their subsidiaries is not made by July 14, 2003, the Bankruptcy Court will hear
motions to lift the stay on July 21, 2003. The asbestos creditors committee also
reserves the right to monitor progress toward the filing of the Chapter 11
proceeding and seek an earlier hearing to lift the stay if satisfactory progress
toward the Chapter 11 filing is not being made.
Of the up to $2.775 billion cash amount included as part of the
proposed global settlement, approximately $450 million primarily relates to
claims previously settled but unpaid by Harbison-Walker (see Note 12 to the
financial statements), but not previously agreed to by us. As part of the
proposed settlement, we have agreed that, if a Chapter 11 filing by DII
Industries, Kellogg, Brown & Root and their subsidiaries were to occur, we would
pay this amount within four years if not paid sooner pursuant to a final
bankruptcy court approved plan of reorganization for DII Industries, Kellogg,
Brown & Root and their subsidiaries. Effective November 30, 2002, we are making
cash payments in lieu of interest at a rate of 5% per annum to the holders of
these claims. These cash payments in lieu of interest are being made in arrears
at the end of February, May, August and November, beginning after certain
conditions are met, until the earlier of the date that the $450 million is paid
or the date the proposed settlement is abandoned.
Proposed bankruptcy of DII Industries, Kellogg, Brown & Root and
subsidiaries. Under the terms of the proposed global settlement, the settlement
would be implemented through a pre-packaged Chapter 11 filing for DII
Industries, Kellogg, Brown & Root and some of their subsidiaries. Other than
those debtors, none of the subsidiaries of Halliburton (including Halliburton
Energy Services, Inc.) or Halliburton itself will be a debtor in the Chapter 11
proceedings. We anticipate that Halliburton, Halliburton Energy Services, Inc.
and each of the debtors' non-debtor affiliates will continue normal operations
and continue to fulfill all of their respective obligations in the ordinary
course as they become due.
As part of any proposed plan of reorganization, the debtors intend to
seek approval of the bankruptcy court for debtor-in-possession financing to
provide for operating needs and to provide additional liquidity during the
pendency of the Chapter 11 proceeding. We currently are negotiating with several
banks and non-bank lenders over the terms of such facility. See "-Financing the
proposed settlement". Obtaining a commitment for debtor-in-possession financing
is a condition precedent to filing of any Chapter 11 proceeding.
Any plan of reorganization will provide that all of the debtors'
obligations under letters of credit, surety bonds, corporate guaranties and
indemnity agreements (except for agreements relating to asbestos claims or
silica claims) will be unimpaired. In addition, the Bankruptcy Code allows a
debtor to assume most executory contracts without regard to bankruptcy default
provisions, and it is the intention of DII Industries, Kellogg, Brown & Root and
the other filing entities to assume and continue to perform all such executory
contracts. Representatives of DII Industries, Kellogg, Brown & Root and their
subsidiaries have advised their customers of this intention.
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After filing any Chapter 11 proceeding, the debtors would seek an order
of the bankruptcy court scheduling a hearing to consider confirmation of the
plan of reorganization. In order to be confirmed, the Bankruptcy Code requires
that an impaired class of creditors vote to accept the plan of reorganization
submitted by the debtors. In order to carry a class, approval of over one-half
in number and at least two-thirds in amount are required. In addition, to obtain
an injunction under Section 524(g) of the Bankruptcy Code, at least 75% of
current asbestos claimants must vote to accept the plan of reorganization. In
addition to obtaining the required votes, the requirements for a bankruptcy
court to approve a plan of reorganization include, among other judicial
findings, that:
- the plan of reorganization complies with applicable provisions
of the Bankruptcy Code;
- the debtors have complied with the applicable provisions of
the Bankruptcy Code;
- the trust will value and pay similar present and future claims
in substantially the same manner;
- the plan of reorganization has been proposed in good faith and
not by any means forbidden by law; and
- any payment made or promised by the debtors to any person for
services, costs or expenses in or in connection with the
Chapter 11 proceeding or the plan of reorganization has been
or is reasonable.
Section 524(g) of the Bankruptcy Code authorizes the bankruptcy court
to enjoin entities from taking action to collect, recover or receive payment or
recovery with respect to any asbestos claim or demand that is to be paid in
whole or in part by a trust created by a plan of reorganization that satisfies
the requirements of the Bankruptcy Code. Section 105 of the Bankruptcy Code
authorizes a similar injunction for silica claims. The injunction also may bar
any action based on such claims or demands against the debtors that are directed
at third parties. The order confirming the plan must be issued or affirmed by
the federal district court that has jurisdiction over the case. After the
expiration of the time for appeal of the order, the injunction becomes valid and
enforceable.
The debtors believe that, if they proceed with a Chapter 11 filing,
they will be able to satisfy all the requirements of Section 524(g), so long as
the requisite number of holders of asbestos claims vote in favor of the plan of
reorganization. If the 524(g) and 105 injunctions are issued, all unsettled
current asbestos claims, all future asbestos claims and all silica claims based
on exposure that has already occurred will be channeled to a trust for payment,
and the debtors and related parties (including Halliburton, Halliburton Energy
Services, Inc. and other subsidiaries and affiliates of Halliburton and the
debtors) will be released from any further liability under the plan of
reorganization.
A prolonged Chapter 11 proceeding could adversely affect the debtor's
relationships with customers, suppliers and employees, which in turn could
adversely affect the debtors' competitive position, financial condition and
results of operations. A weakening of the debtors' financial condition and
results of operations could adversely affect the debtors' ability to implement
the plan of reorganization.
Financing the proposed settlement. The plan of reorganization through
which the proposed settlement will be implemented will require us to contribute
up to $2.775 billion in cash to the Section 524(g)/105 trust established for the
benefit of claimants, which we will need to finance on terms acceptable to us.
We are pursuing a number of financing alternatives for the cash amount to be
contributed to the trust. The availability of these alternatives depend in large
part on market conditions. We are currently negotiating with several banks and
non-bank lenders over the terms of multiple credit facilities. A proposed
banking syndicate is currently performing due diligence in an effort to make a
funding commitment before the bankruptcy filing. We will not proceed with the
Chapter 11 filing for DII Industries, Kellogg, Brown & Root and some of their
subsidiaries until financing commitments are in place.
The anticipated credit facilities include:
- debtor-in-possession financing to provide for the operating
needs of the filing entities;
- a revolving line of credit for general working capital
purposes;
- a master letter of credit facility intended to ensure that
existing letters of credit supporting our contracts remain in
place during the filing; and
- a delayed-draw term facility to be available for funding of up
to $2.775 billion to the trust for the benefit of claimants.
The delayed-draw term facility is intended to eliminate uncertainty the
capital markets might have concerning our ability to meet our funding
requirement once final and non-appealable court confirmation of a plan of
reorganization has been obtained.
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None of these credit facilities are currently in place, and there can
be no assurances that we will complete these facilities. We are not obligated to
enter into these facilities if the terms are not acceptable to us. Moreover,
these facilities would only be available for limited periods of time. As a
result, if we were delayed in filing the Chapter 11 proceeding or delayed in
completing the plan of reorganization after a Chapter 11 filing, the credit
facilities may expire and no longer be available. In such circumstances, we
would have to terminate the proposed settlement if replacement financing were
not available on acceptable terms.
We have sufficient authorized and unrestricted shares to issue 59.5
million shares to the trust. No shareholder approval is required for issuance of
the shares.
Credit ratings. Late in 2001 and early in 2002, Moody's Investors'
Services lowered its ratings of our long-term senior unsecured debt to Baa2 and
our short-term credit and commercial paper ratings to P-2. In addition, Standard
& Poor's lowered its ratings of our long-term senior unsecured debt to A- and
our short-term credit and commercial paper ratings to A-2 in late 2001. In
December 2002, Standard & Poor's lowered these ratings to BBB and A-3. These
ratings were lowered primarily due to our asbestos exposure, and both agencies
have indicated that the ratings continue under consideration for possible
downgrade pending the results of the proposed global settlement. Although our
long-term ratings continue at investment grade levels, the cost of new borrowing
is higher and our access to the debt markets is more volatile at the new rating
levels. Investment grade ratings are BBB- or higher for Standard & Poor's and
Baa3 or higher for Moody's Investors' Services. Our current ratings are one
level above BBB- on Standard & Poor's and one level above Baa3 on Moody's
Investors' Services.
We have $350 million of committed lines of credit from banks that are
available if we maintain an investment grade rating. This facility expires on
August 16, 2006. As of December 31, 2002, no amounts have been borrowed under
these lines.
If our debt ratings fall below investment grade, we would also be in
technical breach of a bank agreement covering $160 million of letters of credit
at December 31, 2002, which might entitle the bank to set-off rights. In
addition, a $151 million letter of credit line, of which $121 million has been
issued, includes provisions that allow the banks to require cash
collateralization for the full line if debt ratings of either rating agency fall
below the rating of BBB by Standard & Poor's or Baa2 by Moody's Investors'
Services, one downgrade from our current ratings. These letters of credit and
bank guarantees generally relate to our guaranteed performance or retention
payments under our long-term contracts and self-insurance.
In the event the ratings of our debt by either agency fall, we may have
to issue additional debt or equity securities or obtain additional credit
facilities in order to satisfy the cash collateralization requirements under the
instruments referred to above and meet our other liquidity needs. We anticipate
that any such new financing would not be on terms as attractive as those we have
currently and that we would also be subject to increased borrowing costs and
interest rates. Our Halliburton Elective Deferral Plan has a provision which
states that if the Standard & Poor's rating falls below BBB the amounts credited
to the participants' accounts will be paid to the participants in a lump-sum
within 45 days. At December 31, 2002 this was approximately $49 million.
Letters of credit. In the normal course of business, we have agreements
with banks under which approximately $1.4 billion of letters of credit or bank
guarantees were issued, including at least $204 million which relate to our
joint ventures' operations. The agreements with these banks contain terms and
conditions that define when the banks can require cash collateralization of the
entire line. Agreements with banks covering at least $150 million of letters of
credit allow the bank to require cash collateralization for the full line for
any reason, and agreements covering another at least $890 million of letters of
credit allow the bank to require cash collateralization for the entire line in
the event of a bankruptcy or insolvency event involving one of our subsidiaries.
Our letters of credit also contain terms and conditions that define
when they may be drawn. At least $230 million of letters of credit permit the
beneficiary of such letters of credit to draw against the line for any reason
and another at least $560 million of letters of credit permit the beneficiary of
such letters of credit to draw against the line in the event of a bankruptcy or
insolvency event involving one of our subsidiaries who will be party to the
proposed reorganization.
Our anticipated credit facilities described above would include a
master letter of credit facility intended to replace any cash collateralization
rights of issuers of substantially all our existing letters of credit during the
pendency of the anticipated Chapter 11 proceedings by DII Industries and
Kellogg, Brown & Root. The master letter of credit facility is also intended to
provide reasonably sufficient credit lines for us to be able to fund any such
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cash requirements. If any of such existing letters of credit are drawn during
the bankruptcy and we are required to provide cash to collateralize or reimburse
for such draws, it is anticipated that the letter of credit facility would
provide the cash needed for such draws, with any borrowings being converted into
term loans. However, this letter of credit facility is not currently in place,
and, if we were required to cash collateralize letters of credit prior to
obtaining the facility, we would be required to use cash on hand or existing
credit facilities. We will not enter into the pre-packaged Chapter 11 filing
without having this credit facility in place. In addition, representatives of
DII Industries, Kellogg, Brown & Root and their subsidiaries have been in
discussions with their customers in order to reduce the possibility that any
material draw on the existing letters of credit will occur due to the
anticipated Chapter 11 proceedings.
Effective October 9, 2002, we amended an agreement with banks under
which $261 million of letters of credit have been issued on the
Barracuda-Caratinga project. The amended agreement removes the provision that
previously allowed the banks to require collateralization if ratings of
Halliburton debt fell below investment grade ratings. The revised agreement
includes provisions that require us to maintain ratios of debt to total capital
and of total earnings before interest, taxes, depreciation and amortization to
interest expense. The definition of debt includes our asbestos liability. The
definition of total earnings before interest, taxes, depreciation and
amortization excludes any non-cash charges related to the proposed global
settlement through December 31, 2003.
In the past, no significant claims have been made against letters of
credit issued on our behalf.
Barracuda-Caratinga Project. In June 2000, KBR entered into a contract
with the project owner, Barracuda & Caratinga Leasing Company B.V., to develop
the Barracuda and Caratinga crude oil fields, which are located off the coast of
Brazil. The project manager and owner representative is Petrobras, the Brazilian
national oil company. See Note 12 to the financial statements.
KBR's performance under the contract is secured by:
- two performance letters of credit, which together have an
available credit of approximately $261 million and which
represent approximately 10% of the contract amount, as amended
to date by change orders;
- a retainage letter of credit in an amount equal to $121
million as of December 31, 2002 and which will increase in
order to continue to represent 10% of the cumulative cash
amounts paid to KBR; and
- a guarantee of KBR's performance of the contract by
Halliburton Company in favor of the project owner.
As of December 31, 2002, the project was approximately 63% complete and
KBR had recorded a loss of $117 million related to the project. The probable
recovery from unapproved claims included in determining the loss on the project
was $182 million as of December 31, 2002.
The project owner has procured project finance funding obligations from
various banks to finance the payments due to KBR under the contract. The project
owner currently has no other committed source of funding on which we can
necessarily rely other than the project finance funding for the project. While
we believe the banks have an incentive to complete the financing of the project,
there is no assurance that they would do so. If the banks ceased funding the
project, we believe that Petrobras would provide for or secure other funding to
complete the project, although there is no assurance that it will do so. To
date, the banks have made funds available, and the project owner has continued
to disburse funds to KBR as payment for its work on the project, even though the
project completion has been delayed.
In the event that KBR is alleged to be in default under the contract,
the project owner may assert a right to draw upon the letters of credit. If the
letters of credit were drawn, KBR would be required to fund the amount of the
draw to the issuing bank. In the event that KBR was determined after an
arbitration proceeding to have been in default under the contract, and if the
project was not completed by KBR as a result of such default (i.e., KBR's
services are terminated as a result of such default), the project owner may seek
direct damages (including completion costs in excess of the contract price and
interest on borrowed funds, but excluding consequential damages) against KBR for
up to $500 million plus the return of up to $300 million in advance payments
that would otherwise have been credited back to the project owner had the
contract not been terminated.
In addition, although the project financing includes borrowing capacity
in excess of the original contract amount, only $250 million of this additional
borrowing capacity is reserved for increases in the contract amount payable to
KBR and its subcontractors other than Petrobras. Because our claims, together
32
with change orders that are currently under negotiation, exceed this amount, we
cannot give assurance that there is adequate funding to cover current or future
KBR claims. Unless the project owner provides additional funding or permits us
to defer repayment of the $300 million advance, and assuming the project owner
does not allege default on our part, we may be obligated to fund operating cash
flow shortages over the remaining project life in an amount we currently
estimate to be up to approximately $400 million.
The possible Chapter 11 pre-packaged bankruptcy filing by KBR in
connection with the settlement of its asbestos and silica claims would
constitute an event of default under the loan documents with the banks unless
waivers are obtained. KBR believes that it is unlikely that the banks will
exercise any right to cease funding given the current status of the project and
the fact that a failure to pay KBR may allow KBR to cease work on the project
without Petrobras having a readily available substitute contractor.
Current maturities. We have approximately $295 million of current
maturities of long-term debt as of December 31, 2002. This includes a repayment
of a $139 million senior note due April 2003 and a $150 million medium-term note
due July 2003.
Cash and cash equivalents. We ended 2002 with cash and equivalents of
$1.1 billion.
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 judgments about future events and
related estimations and how they can impact our financial statements. A critical
accounting policy is one that requires our most difficult, subjective or complex
estimates and assessments and is fundamental to our results of operations. We
identified our most critical accounting policies to be:
- percentage of completion accounting for our long-term
engineering and construction contracts;
- allowance for bad debts;
- forecasting our effective tax rate, including our ability to
utilize foreign tax credits and the realizability of deferred
tax assets; and
- loss contingencies, primarily related to:
- asbestos litigation; and
- other litigation.
We base our estimates on historical experience and on various other
assumptions we believe to be reasonable under the 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. This
discussion and analysis should be read in conjunction with our consolidated
financial statements and related notes included in this report.
Percentage of completion
We account for our revenues on long-term engineering and construction
contracts on the percentage-of-completion method. This method of accounting
requires us to calculate job profit to be recognized in each reporting period
for each job based upon our predictions of future outcomes which include:
- estimates of the total cost to complete the project;
- estimates of project schedule and completion date;
- estimates of the percentage the project is complete; and
- amounts of any probable unapproved claims and change orders
included in revenues.
At the onset of each contract, we prepare a detailed analysis of our
estimated cost to complete the project. Risks relating to service delivery,
usage, productivity and other factors are considered in the estimation process.
Our project personnel periodically evaluate the estimated costs, claims and
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 contract revenue, change orders and claims, less costs incurred
and estimated costs to complete. Anticipated losses on contracts are recorded in
full in the period in which they become evident. Profits are recorded based upon
the total estimated contract profit times the current percentage complete for
the contract.
When calculating the amount of total profit or loss on a long-term
contract, we include unapproved claims as revenue when the collection is deemed
probable based upon the four criteria for recognizing unapproved claims under
the American Institute of Certified Public Accountants' Statement of Position
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81-1 "Accounting for Performance of Construction-Type and Certain
Production-Type Contracts." Including probable unapproved claims in this
calculation increases the operating income or decreases 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 substantially 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. We actively
engage in claims negotiations with our customers and the success of claims
negotiations have a direct impact on the profit or loss recorded for any related
long-term contract. Unsuccessful claims negotiations could result in decreases
in estimated contract profits or additional contract losses and successful
claims negotiations could result in increases in estimated contract profits or
recovery of previously recorded contract losses.
Significant projects are reviewed in detail by senior engineering and
construction management at least quarterly. Preparing project cost estimates and
percentages of completion is a core competency within our engineering and
construction businesses. We have a long history of dealing with multiple types
of projects and in preparing cost estimates. However, there are many factors
that impact future costs, including but not limited to weather, inflation, labor
disruptions and timely availability of materials, and other factors as outlined
in our "Forward-Looking Information" section. These factors can affect the
accuracy of our estimates and materially impact our future reported earnings.
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 comprises a thorough review of historical collection experience, current
aging status of the customer accounts, financial condition of our customers, and
other factors such as whether the receivables involve retentions or billing
disputes. 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.
Tax accounting
We account for our income taxes in accordance with Statement of
Financial Accounting Standards No. 109 "Accounting for Income Taxes", which
requires the recognition of the amount of taxes payable or refundable for the
current year; and an asset and liability approach in recognizing the amount of
deferred tax liabilities and assets for the future tax consequences of events
that have been recognized in our financial statements or tax returns. We apply
the following basic principles in accounting for our income taxes at the date of
the financial statements:
- a current tax liability or asset is recognized for the
estimated taxes payable or refundable on tax returns for the
current year;
- a deferred tax liability or asset is recognized for the
estimated future tax effects attributable to temporary
differences and carryforwards;
- the measurement of current and deferred tax liabilities and
assets is based on provisions of the enacted tax law and the
effects of potential future changes in tax laws or rates are
not considered; and
- the value of deferred tax assets is reduced, if necessary, by
the amount of any tax benefits that, based on available
evidence, are not expected to be realized.
We determine deferred taxes separately for each tax-paying component
(an entity or a group of entities that is consolidated for tax purposes) in each
tax jurisdiction. That determination includes the following procedures:
- identify the types and amounts of existing temporary
differences;
- measure the total deferred tax liability for taxable temporary
differences using the applicable tax rate;
- measure the total deferred tax asset for deductible temporary
differences and operating loss carryforwards using the
applicable tax rate;
- measure the deferred tax assets for each type of tax credit
carryforward; and
- reduce 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 prior to expiration, or that future deductibility is
uncertain.
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This methodology requires a significant amount of judgment regarding
assumptions and the use of estimates, which can create significant variances
between actual results and estimates. Examples include the forecasting of our
effective tax rate and the potential realization of deferred tax assets in the
future, such as utilization of foreign tax credits. This process involves making
forecasts of current and future years' United States taxable income, foreign
taxable income and related taxes in order to estimate the foreign tax credits.
Unforeseen events, such as the timing of asbestos or silica settlements, and
other tax timing issues may significantly affect these estimates. These factors
can affect the accuracy of our tax account balances and impact our future
reported earnings.
Loss contingencies
Asbestos. Prior to June 2002, we provided for known outstanding
asbestos and silica claims because we did not have sufficient information to
make a reasonable estimate of future unknown asbestos and silica claims
liability. DII Industries retained Dr. Francine F. Rabinovitz of Hamilton,
Rabinovitz & Alschuler, Inc. to estimate the probable number and value,
including defense costs, of unresolved current and future asbestos and silica
related bodily injury claims asserted against DII Industries and its
subsidiaries. Dr. Rabinovitz is a nationally renowned expert in conducting such
analyses.
The methodology utilized by Dr. Rabinovitz to project DII Industries'
and its subsidiaries' asbestos and silica related liabilities and defense costs
relied upon and included:
- an analysis of historical asbestos and silica settlements and
defense costs;
- an analysis of the pending inventory of asbestos and silica
related claims;
- an analysis of the claims filing history for asbestos and
silica related claims since January 2000 (two-year claim
history) and alternatively since January 1997 (five-year claim
history);
- an analysis of the population likely to have been exposed or
claim exposure to specific products or construction and
renovation projects; and
- epidemiological studies to estimate the number of people who
might allege exposure to products.
Dr. Rabinovitz's estimates are based on historical data supplied by DII
Industries, Kellogg, Brown & Root and Harbison-Walker and publicly available
studies, including annual surveys by the National Institutes of Health
concerning the incidence of mesothelioma deaths. In her analysis, Dr. Rabinovitz
projected that the elevated and historically unprecedented rate of claim filings
of the last two years (particularly in 2000 and 2001), especially as expressed
by the ratio of nonmalignant claim filings to malignant claim filings, would
continue into the future for five more years. After that, Dr. Rabinovitz
projected that the ratio of nonmalignant claim filings to malignant claim
filings will gradually decrease for a 10 year period ultimately returning to the
historical claiming rate and claiming ratio. In making her calculation, Dr.
Rabinovitz alternatively assumed a somewhat lower rate of claim filings, based
on an average of the last five years of claims experience, would continue into
the future for five more years and decrease thereafter.
Other important assumptions utilized in Dr. Rabinovitz's estimates,
which we relied upon in making our accrual are:
- an assumption that there will be no legislative or other
systemic changes to the tort system;
- that we will continue to aggressively defend against asbestos
and silica claims made against us;
- an inflation rate of 3% annually for settlement payments and
an inflation rate of 4% annually for defense costs; and
- we would receive no relief from our asbestos obligation due to
actions taken in the Harbison-Walker bankruptcy.
Through 2052, Dr. Rabinovitz estimated the current and future total
undiscounted liability for personal injury asbestos and silica claims, including
defense costs, would be a range between $2.2 billion and $3.5 billion as of June
30, 2002 (which includes payments related to the approximately 347,000 claims
currently pending). The lower end of the range is calculated by using an average
of the last five years of asbestos and silica claims experience and the upper
end of the range is calculated using the more recent two-year elevated rate of
asbestos and silica claim filings in projecting the rate of future claims.
Proposed global settlement. On December 18, 2002, we announced that we
had reached an agreement in principle that, if and when consummated, would
result in a global settlement of all asbestos and silica personal injury claims
against DII Industries, Kellogg, Brown & Root and their current and former
subsidiaries. The agreement in principle provides that:
35
- up to $2.775 billion in cash, 59.5 million Halliburton shares
(valued at $1.1 billion using the stock price at December 31,
2002 of $18.71) and notes with a net present value expected to
be less than $100 million will be paid to a trust for the
benefit of current and future asbestos personal injury
claimants and current silica personal injury claimants upon
receiving final and non-appealable court confirmation of a
plan of reorganization;
- DII Industries and Kellogg, Brown & Root will retain rights to
the first $2.3 billion of any insurance proceeds with any
proceeds received between $2.3 billion and $3.0 billion going
to the trust;
- the agreement is to be implemented through a pre-packaged
Chapter 11 filing for DII Industries, Kellogg, Brown & Root
and some of their subsidiaries; and
- the funding of the settlement amounts would occur upon
receiving final and non-appealable court confirmation of a
plan of reorganization of DII Industries, Kellogg, Brown &
Root and their subsidiaries in the Chapter 11 proceeding.
Subsequently, as of March 2003, DII Industries and Kellogg, Brown &
Root have entered into definitive written agreements finalizing the terms of the
agreement in principle.
Please see "Liquidity and Capital Resources" for a discussion of the
prerequisites to reaching a conclusion of the settlement.
Asbestos and Silica Liability Estimate as of December 31, 2002. We
currently do not believe that completion of the proposed global settlement is
probable as defined by Statement of Financial Accounting Standards No. 5. If the
proposed global settlement is not completed, we will continue to resolve
asbestos and silica claims in the tort system or, in the case of Harbison-Walker
claims (see Note 12 to the financial statements), possibly through the
Harbison-Walker bankruptcy proceedings. Given the uncertainties surrounding the
completion of the global settlement and the uncertainty as to the amounts that
could be paid under the proposed global settlement, we believe Dr. Rabinovitz's
study continues to provide the best possible range of estimated loss associated
with known and future asbestos and silica claims liabilities. As a result of
negotiating the proposed global settlement, we have determined that the best
estimate of the probable loss is $3.4 billion ($3.5 billion estimate as of June
30, 2002 in Dr. Rabinovitz's study less $50 million in payments in the third and
fourth quarter of 2002) and we have adjusted our liability to this amount at
December 31, 2002.
Insurance Recoveries. In 2002, we retained Peterson Consulting, a
nationally-recognized consultant in liability and insurance, to work with us to
project the amount of probable insurance recoveries using the current and future
asbestos and silica liabilities recorded by us at December 31, 2002. Using Dr.
Rabinovitz's estimate of liabilities through 2052 using the two-year elevated
rate of asbestos and silica claim filings, Peterson Consulting assisted us in
conducting an analysis to determine the amount of insurance that we estimate is
probable that we will recover in relation to the projected claims and defense
costs. In conducting this analysis, Peterson Consulting:
- reviewed DII Industries historical course of dealings with its
insurance companies concerning the payment of asbestos and
silica related claims, including DII Industries 15 year
litigation and settlement history;
- reviewed the terms of DII Industries' prior and current
coverage-in-place settlement agreements;
- reviewed the status of DII Industries' and Kellogg, Brown &
Root's current insurance-related lawsuits and the various
legal positions of the parties in those lawsuits in relation
to the developed and developing case law and the historic
positions taken by insurers in the earlier filed and settled
lawsuits;
- engaged in discussions with our counsel; and
- analyzed publicly-available information concerning the ability
of the DII Industries insurers to meet their obligations.
Based on these reviews, analyses and discussions, Peterson Consulting
assisted us in making judgments concerning insurance coverage that we believe
are reasonable and consistent with our historical course of dealings with our
insurers and the relevant case law to determine the probable insurance
recoveries for asbestos and silica liabilities. This analysis factored in the
probable effects of self-insurance features, such as self-insured retentions,
policy exclusions, liability caps and the financial status of applicable
insurers, and various judicial determinations relevant to DII Industries
insurance programs.
36
Based on Peterson Consulting analysis of the probable insurance
recoveries, we increased our insurance receivable to $2.1 billion at December
31, 2002. The insurance receivable recorded by us does not assume any recovery
from insolvent carriers and assumes that those carriers which are currently
solvent will continue to be solvent throughout the period of the applicable
recoveries in the projections. However, there can be no assurance that these
assumptions will be accurate. The insurance receivables recorded at December 31,
2002 do not exhaust applicable insurance coverage for asbestos and silica
related liabilities.
Projecting future events is subject to many uncertainties that could
cause the asbestos and silica related liabilities and insurance recoveries to be
higher or lower than those projected and accrued, such as:
- the number of future asbestos and silica related lawsuits to
be filed against DII Industries and Kellogg, Brown & Root;
- the average cost to resolve such future lawsuits;
- coverage issues among layers of insurers issuing different
policies to different policyholders over extended periods of
time;
- the impact on the amount of insurance recoverable in light of
the Harbison-Walker and Federal-Mogul bankruptcies; and
- the continuing solvency of various insurance companies.
Possible Additional Accruals. Should the proposed global settlement
become probable as defined by Statement of Financial Accounting Standards No. 5,
we would adjust our accrual for probable and reasonably estimable liabilities
for current and future asbestos and silica claims. The settlement amount would
be up to $4.0 billion, consisting of up to $2.775 billion in cash, 59.5 million
Halliburton shares and notes with a net present value expected to be less than
$100 million. Assuming the revised liability would be $4.0 billion, we would
also increase our probable insurance recoveries to $2.3 billion. The impact on
our income statement would be an additional pretax charge of $322 million ($288
million after-tax). This accrual (which values our stock to be contributed at
$1.1 billion using our stock price at December 31, 2002 of $18.71) would then be
adjusted periodically based on changes in the market price of our common stock
until the common stock is contributed to a trust for the benefit of the
claimants.
Continuing Review. Given the inherent uncertainty in making future
projections, we plan to have the projections periodically reexamined, and update
them based on our experience and other relevant factors such as changes in the
tort system, the resolution of the bankruptcies of various asbestos defendants,
and our proposed global settlement. Similarly, we will re-evaluate our
projections concerning our probable insurance recoveries in light of any updates
to Dr. Rabinovitz's projections, developments in DII Industries and Kellogg,
Brown & Root's various lawsuits against their insurance companies, factors
related to the global settlement, if consummated, and other developments that
may impact the probable insurance recoveries.
Litigation. We are currently involved in other legal proceedings not
involving asbestos and silica. As discussed in Note 12 of our consolidated
financial statements, as of December 31, 2002, we have accrued an estimate of
the probable costs for the resolution of these claims. Attorneys in our legal
department specializing in litigation claims, monitor and manage all claims
filed against us. The estimate of probable costs related to these claims is
developed in consultation with outside legal counsel representing us in the
defense of these claims. Our estimates are based upon an analysis of potential
results, assuming a combination of litigation and settlement strategies. We
attempt to resolve claims through mediation and arbitration where possible. If
the actual settlement costs and final judgments, after appeals, differ from our
estimates, our future financial results may be adversely affected.
OFF BALANCE SHEET RISK
On April 15, 2002, we entered into an agreement to sell certain of our
accounts receivable to a bankruptcy-remote limited-purpose funding subsidiary.
Under the terms of the agreement, new receivables are added on a continuous
basis to the pool of receivables, and collections reduce previously sold
accounts receivable. This funding subsidiary sells an undivided ownership
interest in this pool of receivables to entities managed by unaffiliated
financial institutions under another agreement. Sales to the funding subsidiary
have been structured as "true sales" under applicable bankruptcy laws, and the
assets of the funding subsidiary are not available to pay any creditors of
37
Halliburton or of its subsidiaries or affiliates, until such time as the
agreement with the unaffiliated companies is terminated following sufficient
collections to liquidate all outstanding undivided ownership interests. The
funding subsidiary retains the interest in the pool of receivables that are not
sold to the unaffiliated companies, and is fully consolidated and reported in
our financial statements.
The amount of undivided interests, which can be sold under the program,
varies based on the amount of eligible Energy Services Group receivables in the
pool at any given time and other factors. The funding subsidiary sold a $200
million undivided ownership interest to the unaffiliated companies, and may from
time to time sell additional undivided ownership interests. No additional
amounts were received from our accounts receivable facility since the second
quarter of 2002. The total amount outstanding under this facility was $180
million as of December 31, 2002. We continue to service, administer and collect
the receivables on behalf of the purchaser. The amount of undivided ownership
interest in the pool of receivables sold to the unaffiliated companies is
reflected as a reduction of accounts receivable in our consolidated balance
sheet and as an increase in cash flows from operating activities in our
consolidated statement of cash flows.
LONG-TERM CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
The following table summarizes our various long-term contractual
obligations:
Payments due
------------------------------------------------
Millions of dollars 2003 2004 2005 2006 2007 Thereafter Total
----------------------------------------------------------------------------------------------------
Long-term debt $ 295 $ 21 $ 20 $ 293 $ 8 $ 826 $ 1,463
Operating leases 119 83 63 55 40 249 609
Capital leases 1 1 1 - - - 3
----------------------------------------------------------------------------------------------------
Total contractual
obligations $ 415 $105 $ 84 $ 348 $ 48 $ 1,075 $ 2,075
====================================================================================================
Included in long-term debt is an additional $13 million at December 31,
2002 related to the terminated interest rate swaps.
We also have $350 million of committed lines of credit from banks that
are available if we maintain an investment grade rating. Investment grade
ratings are BBB- or higher for Standard & Poor's and Baa3 or higher for Moody's
Investors' Services and we are currently above these levels. In the normal
course of business we have agreements with banks under which approximately $1.4
billion of letters of credit or bank guarantees were issued, including $204
million which relate to our joint ventures' operations.
Effective October 9, 2002, we amended an agreement with banks under
which $261 million of letters of credit have been issued. The amended agreement
removes the provision that previously allowed the banks to require
collateralization if ratings of Halliburton debt fell below investment grade
ratings. The revised agreements include provisions that require us to maintain
ratios of debt to total capital and of total earnings before interest, taxes,
depreciation and amortization to interest expense. The definition of debt
includes our asbestos and silica liability. The definition of total earnings
before interest, taxes, depreciation and amortization excludes any non-cash
charges related to the proposed global settlement through December 31, 2003.
If our debt ratings fall below investment grade, we would also be in
technical breach of a bank agreement covering another $160 million of letters of
credit at December 31, 2002, which might entitle the bank to set-off rights. In
addition, a $151 million letter of credit line, of which $121 million has been
issued, includes provisions that allow the banks to require cash
collateralization for the full line if debt ratings of either rating agency fall
below the rating of BBB by Standard & Poor's or Baa2 by Moody's Investors'
Services, one downgrade from our current ratings. These letters of credit and
bank guarantees generally relate to our guaranteed performance or retention
payments under our long-term contracts and self-insurance.
38
FINANCIAL INSTRUMENT MARKET RISK
We are exposed to financial instrument market risk from changes in
foreign currency exchange rates, interest rates and to a limited extent,
commodity prices. 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 program is to protect our cash flows related to
sales or purchases of goods or services from market fluctuations in currency
rates. Our use of derivative instruments includes the following types of market
risk:
- volatility of the currency rates;
- time horizon of the derivative instruments;
- market cycles; and
- the type of derivative instruments used.
We do not use derivative instruments for trading purposes. We do not
consider any of these risk management activities to be material. See Note 1 to
the financial statements for additional information on our accounting policies
on derivative instruments. See Note 19 to the financial statements for
additional disclosures related to derivative instruments.
Interest rate risk. We have exposure to interest rate risk from our
long-term debt and related interest rate swaps.
The following table represents principal amounts of our long-term debt
at December 31, 2002 and related weighted average interest rates by year of
maturity for our long-term debt.
Millions of dollars 2003 2004 2005 2006 2007 Thereafter Total
------------------------------------------------------------------------------------------------------
Long-term debt:
Fixed rate debt $ 140 $ 2 $ 1 $ 274 $ - $ 825 $ 1,242
Weighted average
interest rate 8.0% 7.7% 7.0% 6.0% - 7.4% 7.1%
Variable rate debt $ 155 $ 19 $ 19 $ 19 $ 8 $ 1 $ 221
Weighted average
interest rate 2.3% 5.4% 5.4% 5.4% 5.4% 5.8% 3.2%
======================================================================================================
Fair market value of long-term debt was $1.3 billion as of December 31,
2002.
In the second quarter 2002, we terminated our interest rate swap
agreement on our 8% senior notes. The notional amount of the swap agreement was
$139 million. This interest rate swap was designated as a fair value hedge under
SFAS No. 133. Upon termination, the fair value of the interest rate swap was
$0.5 million. In the fourth quarter 2002, we terminated our interest rate swap
agreement on our 6% fixed rate medium-term notes. The notional amount of the
swap agreement was $150 million. This interest rate swap was designated as a
fair value hedge under SFAS No. 133. Upon termination, the fair value of the
interest rate swap was $13 million. These swaps had previously been classified
in "Other assets" on the balance sheet. The fair value adjustment to these debt
instruments that were hedged will remain and be amortized as a reduction in
interest expense using the "Effective Yield Method" over the remaining life of
the notes.
REORGANIZATION OF BUSINESS OPERATIONS
On March 18, 2002 we announced plans to restructure our businesses into
two operating subsidiary groups, the Energy Services Group and KBR, representing
the Engineering and Construction Group. As part of this reorganization, we are
separating and consolidating the entities in our Energy Services Group together
as direct and indirect subsidiaries of Halliburton Energy Services, Inc. We are
also separating and consolidating the entities in our Engineering and
Construction Group together as direct and indirect subsidiaries of the former
Dresser Industries, Inc., which became a limited liability company during the
second quarter of 2002 and was renamed DII Industries, LLC. The reorganization
of subsidiaries facilitated the separation, organizationally and financially of
our business groups, which we believe will significantly improve operating
efficiencies, while streamlining management and easing manpower requirements. In
addition, many support functions, which were previously shared, were moved
39
into the two business groups. As a result, we took actions during 2002 to reduce
our cost structure by reducing personnel, moving previously shared support
functions into the two business groups and realigning ownership of international
subsidiaries by group. In 2002, we incurred approximately $107 million for the
year of personnel reduction costs and asset related write-offs. Of this amount,
$8 million remains in accruals for severance arrangements and approximately $2
million for other items. We expect these remaining payments will be made during
2003. Reorganization charges for 2002 consisted of the following:
- $64 million in personnel related expense;
- $17 million of asset related write-downs;
- $20 million in professional fees related to the
restructuring; and
- $6 million related to contract terminations.
Although we have no specific plans currently, the reorganization would
facilitate separation of the ownership of the two business groups in the future
if we identify an opportunity that produces greater value for our shareholders
than continuing to own both business groups. See Note 14 to the financial
statements.
In the fourth quarter of 2000 we approved a plan to reorganize our
engineering and construction businesses into one business unit. This
restructuring was undertaken because our engineering and construction businesses
continued to experience delays in customer commitments for new upstream and
downstream projects. With the exception of deepwater projects, short-term
prospects for increased engineering and construction activities in either the
upstream or downstream businesses were not positive. As a result of the
reorganization of the engineering and construction businesses, we took actions
to rationalize our operating structure, including write-offs of equipment and
licenses of $10 million, engineering reference designs of $4 million and
capitalized software of $6 million, and recorded severance costs of $16 million.
Of these charges, $30 million was reflected under the captions cost of services
and $6 million as general and administrative in our 2000 consolidated statements
of income. Severance and related costs of $16 million were for the reduction of
approximately 30 senior management positions. In January 2002, the last of the
personnel actions was completed and we have no remaining accruals related to the
2000 restructuring. See Note 14 to the financial statements.
ENVIRONMENTAL MATTERS
We are subject to numerous environmental, legal and regulatory
requirements related to our operations worldwide. In the United States, these
laws and regulations include the Comprehensive Environmental Response,
Compensation and Liability Act, the Resources Conservation and Recovery Act, the
Clean Air Act, the Federal Water Pollution Control Act and the Toxic Substances
Control Act, among others. In addition to the federal laws and regulations,
states where we do business may have equivalent laws and regulations by which we
must also 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.
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. We have subsidiaries that have been named as potentially
responsible parties along with other third parties for ten federal and state
superfund sites for which we have established a liability. As of December 31,
2002, those ten sites accounted for $8 million of our total $48 million
liability. See Note 12 to the 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," "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 risks and uncertainties and reflects our
best judgment based on current information. Our results of operations can be
40
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.
While it is not possible to identify all factors, we continue to face
many risks and uncertainties that could cause actual results to differ from our
forward-looking statements and potentially adversely affect our financial
condition and results of operations, including risks relating to:
Asbestos
- completion of the proposed global settlement, prerequisites to
which include:
- agreement on the amounts to be contributed to the
trust for the benefit of current silica claimants;
- our due diligence review for product exposure and
medical basis for claims;
- agreement on procedures for distribution of settlement
funds to individuals claiming personal injury;
- definitive agreement on a plan of reorganization and
disclosure statement relating to the proposed
settlement;
- arrangement of acceptable financing to fund the
proposed settlement;
- Board of Directors approval;
- obtaining approval from 75% of current asbestos
claimants to the plan of reorganization implementing
the proposed global settlement; and
- obtaining final and non-appealable bankruptcy court
approval and federal district court confirmation of
the plan of reorganization;
- the results of being unable to complete the proposed global
settlement, including:
- continuing asbestos and silica litigation against us,
which would include the possibility of substantial
adverse judgments, the timing of which could not be
controlled or predicted, and the obligation to provide
appeals bonds pending any appeal of any such judgment,
some or all of which may require us to post cash
collateral;
- current and future asbestos claims settlement and
defense costs, including the inability to completely
control the timing of such costs and the possibility
of increased costs to resolve personal injury claims;
- the possibility of an increase in the number and type
of asbestos and silica claims against us in the
future;
- future events in the Harbison-Walker bankruptcy
proceeding, including the possibility of
discontinuation of the temporary restraining order
entered by the Harbison-Walker bankruptcy court that
applies to over 200,000 pending claims against DII
Industries; and
- any adverse changes to the tort system allowing
additional claims or judgments against us;
- the results of being unable to recover, or being delayed in
recovering, insurance reimbursement in the amounts anticipated
to cover a part of the costs incurred defending asbestos and
silica claims, and amounts paid to settle claims or as a
result of court judgments, due to:
- the inability or unwillingness of insurers to timely
reimburse for claims in the future;
- disputes as to documentation requirements for DII
Industries in order to recover claims paid;
- the inability to access insurance policies shared
with, or the dissipation of shared insurance assets
by, Harbison-Walker Refractories Company or
Federal-Mogul Products, Inc.;
- the insolvency or reduced financial viability of
insurers;
- the cost of litigation to obtain insurance
reimbursement; and
- adverse court decisions as to our rights to obtain
insurance reimbursement;
- the results of recovering, or agreeing in settlement of
litigation to recover, less insurance reimbursement than the
insurance receivable recorded in our financial statements;
41
- continuing exposure to liability even after the proposed
settlement is completed, including exposure to:
- any claims by claimants exposed outside of the United
States;
- possibly any claims based on future exposure to
silica;
- property damage claims as a result of asbestos and
silica use; or
- any claims against any other subsidiaries or business
units of Halliburton that would not be released in the
Chapter 11 proceeding through the 524(g) injunction;
- liquidity risks resulting from being unable to complete a
global settlement or timely recovery of insurance
reimbursement for amounts paid, each as discussed further
below; and
- an adverse effect on our financial condition or results of
operations as a result of any of the foregoing;
Liquidity
- adverse financial developments that could affect our available
cash or lines of credit, including:
- the effects described above of not completing the
proposed global settlement or not being able to
timely recover insurance reimbursement relating to
amounts paid as part of a global settlement or as a
result of judgments against us or settlements paid in
the absence of a global settlement;
- our inability to provide cash collateral for letters
of credit or any bonding requirements from customers
or as a result of adverse judgments that we are
appealing; and
- a reduction in our credit ratings as a result of the
above or due to other adverse developments;
- requirements to cash collateralize letters of credit and
surety bonds by issuers and beneficiaries of these instruments
in reaction to:
- our plans to place DII Industries, Kellogg, Brown &
Root and some of their subsidiaries into a
pre-packaged Chapter 11 bankruptcy as part of the
proposed global settlement;
- in the absence of a global settlement, one or more
substantial adverse judgments;
- not being able to timely recover insurance
reimbursement; or
- a reduction in credit ratings;
- our ability to secure financing on acceptable terms to fund
our proposed global settlement;
- defaults that could occur under our and our subsidiaries' debt
documents as a result of a Chapter 11 filing unless we are
able to obtain consents or waivers to those events of default,
which events of default could cause defaults under other of
our credit facilities and possibly result in an obligation to
immediately pay amounts due thereunder;
- actions by issuers and beneficiaries of current letters of
credit to draw under such letters of credit prior to our
completion of a new letter of credit facility that is intended
to provide reasonably sufficient credit lines for us to be
able to fund any such cash requirements;
- obtaining debtor-in-possession financing for DII Industries,
Kellogg, Brown & Root and their subsidiaries prior to filing a
Chapter 11 proceeding;
- reductions in our credit ratings by rating agencies, which
could result in:
- the unavailability of borrowing capacity under our
existing $350 million line of credit facility, which
is only available to us if we maintain an investment
grade credit rating;
- reduced access to lines of credit, credit markets and
credit from suppliers under acceptable terms;
- borrowing costs in the future; and
- inability to issue letters of credit and surety bonds
with or without cash collateral;
- debt and letter of credit covenants;
- volatility in the surety bond market;
- availability of financing from the United States Export/Import
Bank;
- ability to raise capital via the sale of stock; and
- an adverse effect on our financial condition or results of
operations as a result of any of the foregoing;
42
Legal
- litigation, including, for example, class action shareholder
and derivative lawsuits, contract disputes, patent
infringements, and environmental matters;
- any adverse outcome of the SEC's current investigation into
Halliburton's accounting policies, practices and procedures
that could result in sanctions and the payment of fines or
penalties, restatement of financials for years under review or
additional shareholder lawsuits;
- trade restrictions and economic embargoes imposed by the
United States and other countries;
- restrictions on our ability to provide products and services
to Iran, Iraq and Libya, all of which are significant
producers of oil and gas;
- protective government regulation in many of the countries
where we operate, including, for example, regulations that:
- encourage or mandate the hiring of local
contractors; and
- require foreign contractors to employ citizens of, or
purchase supplies from, a particular jurisdiction;
- potentially adverse reaction, and time and expense responding
to, the increased scrutiny of Halliburton by regulatory
authorities, the media and others;
- potential liability and adverse regulatory reaction in Nigeria
to the theft from us of radioactive material used in wireline
logging operations;
- environmental laws and regulations, including, for example,
those that:
- require emission performance standards for
facilities; and
- the potential regulation in the United States of our
Pressure Pumping segment's hydraulic fracturing
services and products as underground injection; and
- the proposed excise tax in the United States targeted at heavy
equipment of the type we own and use in our operations would
negatively impact our Energy Services Group operating income;
Effect of Chapter 11 Proceedings
- the adverse effect on the ability of the subsidiaries that are
proposed to file a Chapter 11 proceeding to obtain new orders
from current or prospective customers;
- the potential reluctance of current and prospective customers
and suppliers to honor obligations or continue to transact
business with the Chapter 11 filing entities;
- the potential adverse effect of the Chapter 11 filing of
negotiating favorable terms with customers, suppliers and
other vendors;
- a prolonged Chapter 11 proceeding that could adversely affect
relationships with customers, suppliers and employees, which
in turn could adversely affect our competitive position,
financial condition and results of operations and our ability
to implement the proposed plan of reorganization; and
- the adverse affect on our financial condition or results of
operations as a result of the foregoing;
Geopolitical
- armed conflict in the Middle East that could:
- impact the demand and pricing for oil and gas;
- disrupt our operations in the region and
elsewhere; and
- increase our costs for security worldwide;
- unsettled political conditions, consequences of war or other
armed conflict, the effects of terrorism, civil unrest,
strikes, currency controls and governmental actions in many
oil producing countries and countries in which we provide
governmental logistical support that could adversely affect
our revenues and profit. Countries where we operate which have
significant amounts of political risk include Afghanistan,
Algeria, Angola, Colombia, Indonesia, Libya, Nigeria, Russia,
and Venezuela. For example, the national strike in Venezuela
as well as seizures of offshore oil rigs by protestors and
cessation of operations by some of our customers in Nigeria
have disrupted our Energy Services Group's ability to provide
services and products to our customers in these countries
during 2002 and likely will continue to do so in 2003; and
43
- changes in foreign exchange rates and exchange controls as
were experienced in Argentina in late 2001 and early 2002. For
example, the changes in Argentina exchange rates in late 2001
and early 2002 were detrimental to results of our Energy
Services Group operations in Argentina;
Weather related
- severe weather that impacts our business, particularly in the
Gulf of Mexico where we have significant operations. Impacts
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;
- inability to deliver materials to jobsites in
accordance with contract schedules; and
- loss of productivity; and
- demand for natural gas in the United States drives a
disproportionate amount of our Energy Services Group's United
States business. As a result, warmer than normal winters in
the United States are detrimental to the demand for our
services to gas producers. Conversely, colder than normal
winters in the United States result in increased demand for
our services to gas producers;
Customers
- the magnitude of governmental spending and outsourcing for
military and logistical support of the type that we provide,
including, for example, support services in the Balkans;
- changes in capital spending by customers in the oil and gas
industry for exploration, development, production, processing,
refining, and pipeline delivery networks;
- changes in capital spending by governments for infrastructure
projects of the sort that we perform;
- consolidation of customers including, for example, the merger
of Conoco and Phillips Petroleum, has caused customers to
reduce their capital spending which has negatively impacted
the demand for our services and products;
- potential adverse customer reaction, including potential draws
upon letters of credit, due to their concerns about our plans
to place DII Industries, Kellogg, Brown & Root and some of
their subsidiaries into a pre-packaged bankruptcy as part of
the global settlement;
- customer personnel changes due to mergers and consolidation
which impacts the timing of contract negotiations and
settlements of claims;
- claim negotiations with engineering and construction customers
on cost and schedule variances and change orders on major
projects, including, for example, the Barracuda-Caratinga
project in Brazil; and
- ability of our customers to timely pay the amounts due us;
Industry
- changes in oil and gas prices, among other things, result
from:
- the armed conflict in the Middle East;
- OPEC's ability to set and maintain production levels
and prices for oil;
- the level of oil production by non-OPEC countries;
- the policies of governments regarding exploration for
and production and development of their oil and
natural gas reserves; and
- the level of demand for oil and natural gas,
especially natural gas in the United States;
- obsolescence of our proprietary technologies, equipment and
facilities, or work processes;
- changes in the price or the availability of commodities that
we use;
- our ability to obtain key insurance coverage on acceptable
terms;
- nonperformance, default or bankruptcy of joint venture
partners, key suppliers or subcontractors;
- performing fixed-price projects, where failure to meet
schedules, cost estimates or performance targets could result
in reduced profit margins or losses;
- entering into complex business arrangements for technically
demanding projects where failure by one or more parties could
result in monetary penalties; and
44
- the use of derivative instruments of the sort that we use
which could cause a change in value of the derivative
instruments as a result of:
- adverse movements in foreign exchange rates, interest
rates, or commodity prices; or
- the value and time period of the derivative being
different than the exposures or cash flows being
hedged;
Systems
- the successful identification, procurement and installation of
a new financial system to replace the current system for the
Engineering and Construction Group;
Personnel and mergers/reorganizations/dispositions
- integration of acquired businesses into Halliburton,
including:
- standardizing information systems or integrating data
from multiple systems;
- maintaining uniform standards, controls, procedures,
and policies; and
- combining operations and personnel of acquired
businesses with ours;
- effectively restructuring operations and personnel within
Halliburton including, for example, the segregation of our
business into two operating subsidiary groups under
Halliburton;
- ensuring acquisitions and new products and services add value
and complement our core businesses; and
- successful completion of planned dispositions.
In addition, future trends for pricing, margins, revenues and
profitability remain difficult to predict in the industries we serve. 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-Q and 8-K filed with the
United States Securities and Exchange Commission. We also suggest that you
listen to our quarterly earnings release conference calls with financial
analysts.
No assurance can be given that our financial condition or results of
operations would not be materially and adversely affected by some of the events
described above, including:
- the inability to complete a global settlement;
- in the absence of a global settlement, adverse developments in
the tort system, including adverse judgments and increased
defense and settlement costs relating to claims against us;
- liquidity issues resulting from failure to complete a global
settlement, adverse developments in the tort system, including
adverse judgments and increased defense and settlement costs,
and resulting or concurrent credit ratings downgrades and/or
demand for cash collateralization of letters of credit or
surety bonds;
- the filing of Chapter 11 proceedings by some of our
subsidiaries or a prolonged Chapter 11 proceeding; and
- adverse geopolitical developments, including armed conflict,
civil disturbance and unsettled political conditions in
foreign countries in which we operate.
NEW ACCOUNTING PRONOUNCEMENTS
In August 2001, the Financial Accounting Standards Board issued SFAS
No. 143, "Accounting for Asset Retirement Obligations" which addresses the
financial accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated assets' retirement
costs. SFAS No. 143 requires that the fair value of a liability associated with
an asset retirement be recognized in the period in which it is incurred if a
reasonable estimate of fair value can be made. The associated retirement costs
are capitalized as part of the carrying amount of the long-lived asset and
subsequently depreciated over the life of the asset. We currently account for
liabilities associated with asset retirement obligations under existing
accounting standards, such as SFAS 19, SFAS 5, SOP 96-1, and EITF 89-30, which
do not require the asset retirement obligations to be recorded at fair value and
in some instances do not require the costs to be recognized in the carrying
amount of the related asset. The new standard is effective for us beginning
January 1, 2003, and the effects of this standard will be immaterial to our
future financial condition and we estimate will require a charge of less than
$10 million after-tax as a cumulative effect of a change in accounting
principle.
45
In July 2002 the Financial Accounting Standards Board issued SFAS No.
146, "Accounting for Costs Associated with Exit or Disposal Activities". The
standard requires companies to recognize costs associated with exit or disposal
activities when the liabilities are incurred rather than at the date of a
commitment to an exit or disposal plan. Examples of costs covered by the
standard include lease termination costs and some employee severance costs that
are associated with a restructuring, discontinued operation, plant closing, or
other exit or disposal activity. SFAS No. 146 is to be applied prospectively to
exit or disposal activities initiated after December 31, 2002 and would only
affect the timing of charges associated with any future exit or disposal
activity.
In November 2002, the Financial Accounting Standards Board issued FASB
Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45).
This statement requires that a liability be recorded in the guarantor's balance
sheet upon issuance of a guarantee. In addition, FIN 45 requires disclosures
about the guarantees that an entity has issued, including a rollforward of the
entity's product warranty liabilities. We will apply the recognition provisions
of FIN 45 prospectively to guarantees issued after December 31, 2002. The
disclosure provisions of FIN 45 are effective for financial statements of
interim and annual periods ending after December 15, 2002. The adoption of FIN
45 will not have a material effect on our consolidated financial position and
results of operations.
In January 2003, the Financial Accounting Standards Board issued FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities, an
Interpretation of ARB No. 51" (FIN 46). This statement requires specified
variable interest entities to be consolidated by the primary beneficiary of the
entity if the equity investors in the entity do not have the characteristics of
a controlling financial interest or do not have sufficient equity at risk for
the entity to finance its activities without additional subordinated financial
support from other parties. FIN 46 is effective for all new variable interest
entities created or acquired after January 31, 2003 and beginning July 1, 2003
for variable interest entities created or acquired prior to February 1, 2003.
Our exposure to variable interest entities is limited and, therefore, the
adoption of FIN 46 is not expected to have a material impact on our consolidated
financial position and results of operations.
46
INDEPENDENT AUDITORS' REPORT
TO THE SHAREHOLDERS AND
BOARD OF DIRECTORS OF HALLIBURTON COMPANY:
We have audited the accompanying consolidated balance sheet of Halliburton
Company and subsidiaries as of December 31, 2002, and the related consolidated
statements of operations, shareholders' equity, and cash flows for the year then
ended. 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 audit. The accompanying 2001 and
2000 consolidated financial statements of Halliburton Company and subsidiaries
were audited by other auditors who have ceased operations. Those auditors
expressed an unqualified opinion on those consolidated financial statements,
before the restatement described in Note 4 to the consolidated financial
statements and before the revision described in Note 22 to the consolidated
financial statements, in their report dated January 23, 2002 (except with
respect to matters discussed in Note 9 to those financial statements, as to
which the date was February 21, 2002).
We conducted our audit in accordance with auditing standards generally accepted
in the United States of America. 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 audit provides a
reasonable basis for our opinion.
In our opinion, the 2002 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Halliburton
Company and subsidiaries as of December 31, 2002, and the results of their
operations and their cash flows for the year then ended in conformity with
accounting principles generally accepted in the United States of America.
As discussed in Note 4, disclosures included in the 2002, 2001 and 2000
consolidated financial statements relating to the Company's reportable business
segments have been restated.
As discussed above, the 2001 and 2000 consolidated financial statements of
Halliburton Company and subsidiaries were audited by other auditors who have
ceased operations. As described in Note 4, the amounts in the 2001 and 2000
consolidated financial statements relating to reportable segments have been
restated. We audited the adjustments that were applied to restate the
disclosures for reportable segments reflected in the 2001 and 2000 consolidated
financial statements. In our opinion, such adjustments are appropriate and have
been properly applied. Also, as described in Note 22, these consolidated
financial statements have been revised to include the transitional disclosures
required by Statement of Financial Accounting Standards No. 142, Goodwill and
Other Intangible Assets, which was adopted by the Company as of January 1, 2002.
In our opinion, the disclosures for 2001 and 2000 in Note 22 are appropriate.
However, we were not engaged to audit, review, or apply any procedures to the
2001 and 2000 consolidated financial statements of Halliburton Company and
subsidiaries other than with respect to such adjustments and revisions and,
accordingly, we do not express an opinion or any other form of assurance on the
2001 and 2000 consolidated financial statements taken as a whole.
/s/ KPMG LLP
------------
KPMG LLP
Houston, Texas
March 13, 2003, except for Notes 1, 2 and 4 as to which the date is January 14,
2004
47
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
This report is a copy of a previously issued report, the predecessor auditor has
not reissued this report, the previously issued report refers to financial
statements not physically included in this document, and the prior-period
financial statements have been revised or restated.
TO THE SHAREHOLDERS AND
BOARD OF DIRECTORS OF HALLIBURTON COMPANY:
We have audited the accompanying consolidated balance sheets of Halliburton
Company (a Delaware corporation) and subsidiary companies as of December 31,
2001 and 2000, and the related consolidated statements of income, cash flows,
and shareholders' equity for each of the three years in the period ended
December 31, 2001. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. 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 financial statements referred to above present fairly, in
all material respects, the financial position of Halliburton Company and
subsidiary companies as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States of America.
Arthur Andersen LLP
Dallas, Texas
January 23, 2002 (Except with respect to certain matters discussed in Note 9, as
to which the date is February 21, 2002.)
48
Halliburton Company
Consolidated Statements of Operations
(Millions of dollars and shares except per share data)
Years ended December 31
-------------------------------------------------
2002 2001 2000
-----------------------------------------------------------------------------------------------------------------
Revenues:
Services $ 10,658 $ 10,940 $ 10,185
Product sales 1,840 1,999 1,671
Equity in earnings of unconsolidated affiliates 74 107 88
-----------------------------------------------------------------------------------------------------------------
Total revenues $ 12,572 $ 13,046 $ 11,944
-----------------------------------------------------------------------------------------------------------------
Operating costs and expenses:
Cost of services $ 10,737 $ 9,831 $ 9,755
Cost of sales 1,642 1,744 1,463
General and administrative 335 387 352
Gain on sale of marine vessels - - (88)
Gain on sale of business assets (30) - -
-----------------------------------------------------------------------------------------------------------------
Total operating costs and expenses $ 12,684 $ 11,962 $ 11,482
-----------------------------------------------------------------------------------------------------------------
Operating income (loss) (112) 1,084 462
Interest expense (113) (147) (146)
Interest income 32 27 25
Foreign currency losses, net (25) (10) (5)
Other, net (10) - (1)
-----------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations before income taxes,
minority interest, and change in accounting method, net (228) 954 335
Provision for income taxes (80) (384) (129)
Minority interest in net income of subsidiaries (38) (19) (18)
-----------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations before change in
accounting method, net (346) 551 188
-----------------------------------------------------------------------------------------------------------------
Discontinued operations:
Income (loss) from discontinued operations, net of tax
(provision) benefit of $154, $20, and ($60) (652) (42) 98
Gain on disposal of discontinued operations, net of tax
provision
of $0, $199, and $141 - 299 215
-----------------------------------------------------------------------------------------------------------------
Income (loss) from discontinued operations, net (652) 257 313
-----------------------------------------------------------------------------------------------------------------
Cumulative effect of change in accounting method, net - 1 -
-----------------------------------------------------------------------------------------------------------------
Net income (loss) $ (998) $ 809 $ 501
=================================================================================================================
Basic income (loss) per share:
Income (loss) from continuing operations before change
in accounting method, net $ (0.80) $ 1.29 $ 0.42
Income (loss) from discontinued operations (1.51) (0.10) 0.22
Gain on disposal of discontinued operations - 0.70 0.49
-----------------------------------------------------------------------------------------------------------------
Net income (loss) $ (2.31) $ 1.89 $ 1.13
==================================================================================================================
Diluted income (loss) per share:
Income (loss) from continuing operations before change
in accounting method, net $ (0.80) $ 1.28 $ 0.42
Income (loss) from discontinued operations (1.51) (0.10) 0.22
Gain on disposal of discontinued operations - 0.70 0.48
------------------------------------------------------------------------------------------------ ----------------
Net income (loss) $ (2.31) $ 1.88 $ 1.12
=================================================================================================================
Basic average common shares outstanding 432 428 442
Diluted average common shares outstanding 432 430 446
See notes to annual financial statements.
49
Halliburton Company
Consolidated Balance Sheets
(Millions of dollars and shares except per share data)
December 31
--------------------------
2002 2001
-----------------------------------------------------------------------------------------------------------
Assets
Current assets:
Cash and equivalents $ 1,107 $ 290
Receivables:
Notes and accounts receivable (less allowance for bad debts of $157 and $131) 2,533 3,015
Unbilled work on uncompleted contracts 724 1,080
-----------------------------------------------------------------------------------------------------------
Total receivables 3,257 4,095
Inventories 734 787
Current deferred income taxes 200 154
Other current assets 262 247
-----------------------------------------------------------------------------------------------------------
Total current assets 5,560 5,573
Net property, plant and equipment 2,629 2,669
Equity in and advances to related companies 413 551
Goodwill 723 720
Noncurrent deferred income taxes 607 410
Insurance for asbestos and silica related liabilities 2,059 612
Other assets 853 431
-----------------------------------------------------------------------------------------------------------
Total assets $ 12,844 $ 10,966
===========================================================================================================
Liabilities and Shareholders' Equity
Current liabilities:
Short-term notes payable $ 49 $ 44
Current maturities of long-term debt 295 81
Accounts payable 1,077 917
Accrued employee compensation and benefits 370 357
Advance billings on uncompleted contracts 641 611
Deferred revenues 100 99
Income taxes payable 148 194
Other current liabilities 592 605
-----------------------------------------------------------------------------------------------------------
Total current liabilities 3,272 2,908
Long-term debt 1,181 1,403
Employee compensation and benefits 756 570
Asbestos and silica related liabilities 3,425 737
Other liabilities 581 555
Minority interest in consolidated subsidiaries 71 41
-----------------------------------------------------------------------------------------------------------
Total liabilities 9,286 6,214
-----------------------------------------------------------------------------------------------------------
Shareholders' equity:
Common shares, par value $2.50 per share - authorized 600 shares,
issued 456 and 455 shares 1,141 1,138
Paid-in capital in excess of par value 293 298
Deferred compensation (75) (87)
Accumulated other comprehensive income (281) (236)
Retained earnings 3,110 4,327
-----------------------------------------------------------------------------------------------------------
4,188 5,440
Less 20 and 21 shares of treasury stock, at cost 630 688
-----------------------------------------------------------------------------------------------------------
Total shareholders' equity 3,558 4,752
-----------------------------------------------------------------------------------------------------------
Total liabilities and shareholders' equity $ 12,844 $ 10,966
===========================================================================================================
See notes to annual financial statements.
50
Halliburton Company
Consolidated Statements of Shareholders' Equity
(Millions of dollars and shares)
Years ended December 31
-------------------------------------------
2002 2001 2000
-----------------------------------------------------------------------------------------------------------
Common stock (number of shares)
Balance at beginning of year 455 453 448
Shares issued under compensation and incentive stock plans,
net of forfeitures -* 1 4
Shares issued for acquisition 1 1 1
-----------------------------------------------------------------------------------------------------------
Balance at end of year 456 455 453
===========================================================================================================
Common stock (dollars)
Balance at beginning of year $ 1,138 $ 1,132 $ 1,120
Shares issued under compensation and incentive stock plans,
net of forfeitures 1 2 9
Shares issued for acquisition 2 4 3
-----------------------------------------------------------------------------------------------------------
Balance at end of year $ 1,141 $ 1,138 $ 1,132
===========================================================================================================
Paid-in capital in excess of par value
Balance at beginning of year $ 298 $ 259 $ 68
Shares issued under compensation and incentive stock plans,
net of forfeitures (24) 30 109
Tax benefit (5) (2) 38
Shares issued for acquisition, net 24 11 44
-----------------------------------------------------------------------------------------------------------
Balance at end of year $ 293 $ 298 $ 259
===========================================================================================================
Deferred compensation
Balance at beginning of year $ (87) $ (63) $ (51)
Current year awards, net of tax 12 (24) (12)
-----------------------------------------------------------------------------------------------------------
Balance at end of year $ (75) $ (87) $ (63)
===========================================================================================================
Accumulated other comprehensive income
Cumulative translation adjustment $ (121) $ (205) $ (275)
Pension liability adjustment (157) (27) (12)
Unrealized loss on investments and derivatives (3) (4) (1)
-----------------------------------------------------------------------------------------------------------
Balance at end of year $ (281) $ (236) $ (288)
===========================================================================================================
Cumulative translation adjustment
Balance at beginning of year $ (205) $ (275) $ (185)
Sales of subsidiaries 15 102 11
Current year changes 69 (32) (101)
-----------------------------------------------------------------------------------------------------------
Balance at end of year $ (121) $ (205) $ (275)
===========================================================================================================
Pension liability adjustment
Balance at beginning of year $ (27) $ (12) $ (19)
Sale of subsidiary - 12 7
Current year change, net of tax (130) (27) -
-------------------------------------------------------------------------------------------------------------
Balance at end of year $ (157) $ (27) $ (12)
=============================================================================================================
* Actual shares issued in 2002 were 357,000.
(continued on next page)
51
Halliburton Company
Consolidated Statements of Shareholders' Equity
(Millions of dollars and shares)
(continued)
Years ended December 31
--------------------------------------------
2002 2001 2000
--------------------------------------------------------------------------------------------------------------
Unrealized gain (loss) on investments
Balance at beginning of year $ (4) $ (1) $ -
Current year unrealized gain (loss) on investments and
derivatives 1 (3) (1)
--------------------------------------------------------------------------------------------------------------
Balance at end of year $ (3) $ (4) $ (1)
==============================================================================================================
Retained earnings
Balance at beginning of year $ 4,327 $ 3,733 $ 3,453
Net income (loss) (998) 809 501
Cash dividends paid (219) (215) (221)
--------------------------------------------------------------------------------------------------------------
Balance at end of year $ 3,110 $ 4,327 $ 3,733
==============================================================================================================
Treasury stock (number of shares)
Beginning of year 21 26 6
Shares issued under benefit, dividend reinvestment plan and
incentive stock plans, net (2) (2) -
Shares issued for acquisition - (4) -
Shares purchased 1 1 20
--------------------------------------------------------------------------------------------------------------
Balance at end of year 20 21 26
==============================================================================================================
Treasury stock (dollars)
Beginning of year $ 688 $ 845 $ 99
Shares issued under benefit, dividend reinvestment plan and
incentive stock plans, net (62) (51) (23)
Shares issued for acquisition - (140) -
Shares purchased 4 34 769
--------------------------------------------------------------------------------------------------------------
Balance at end of year $ 630 $ 688 $ 845
==============================================================================================================
Comprehensive income (loss)
Net income (loss) $ (998) $ 809 $ 501
--------------------------------------------------------------------------------------------------------------
Cumulative translation adjustment, net of tax 69 (32) (101)
Less reclassification adjustments for losses included in
net income 15 102 11
--------------------------------------------------------------------------------------------------------------
Net cumulative translation adjustment 84 70 (90)
--------------------------------------------------------------------------------------------------------------
Current year adjustment to minimum pension liability, net of tax (130) (15) 7
Unrealized gain/(loss) on investments and derivatives 1 (3) (1)
--------------------------------------------------------------------------------------------------------------
Total comprehensive income (loss) $(1,043) $ 861 $ 417
==============================================================================================================
See notes to annual financial statements.
52
Halliburton Company
Consolidated Statements of Cash Flows
(Millions of dollars)
Years ended December 31
-----------------------------------------
2002 2001 2000
----------------------------------------------------------------------------------------------------------------
Cash flows from operating activities:
Net income (loss) $ (998) $ 809 $ 501
Adjustments to reconcile net income to net cash from operations:
Loss (income) from discontinued operations 652 (257) (313)
Depreciation, depletion and amortization 505 531 503
Provision (benefit) for deferred income taxes (151) 26 (6)
Distributions from (advances to) related companies, net of equity 3 8 (64)
in (earnings) losses
Change in accounting method, net - (1) -
Gain on sale of assets (22) - -
Gain on option component of joint venture sale (3) - -
Asbestos and silica related liabilities, net 588 96 4
Accrued special charges - (6) (63)
Other non-cash items 101 (3) (22)
Other changes, net of non-cash items:
Receivables and unbilled work on uncompleted contracts 675 (199) (896)
Sale of receivables, net 180 - -
Inventories 62 (91) 8
Accounts payable 71 118 170
Other working capital, net (78) 122 155
Other operating activities (23) (124) (34)
----------------------------------------------------------------------------------------------------------------
Total cash flows from operating activities 1,562 1,029 (57)
----------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Capital expenditures (764) (797) (578)
Sales of property, plant and equipment 266 120 209
Acquisitions of businesses, net of cash acquired - (220) (10)
Dispositions of businesses, net of cash disposed 170 61 19
Proceeds from sale of securities 62 - -
Investments - restricted cash (187) 4 5
Other investing activities (20) (26) (56)
----------------------------------------------------------------------------------------------------------------
Total cash flows from investing activities (473) (858) (411)
----------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Proceeds from long-term borrowings 66 425 -
Payments on long-term borrowings (81) (13) (308)
(Repayments) borrowings of short-term debt, net (2) (1,528) 629
Payments of dividends to shareholders (219) (215) (221)
Proceeds from exercises of stock options - 27 105
Payments to reacquire common stock (4) (34) (769)
Other financing activities (8) (17) (20)
----------------------------------------------------------------------------------------------------------------
Total cash flows from financing activities (248) (1,355) (584)
----------------------------------------------------------------------------------------------------------------
Effect of exchange rate changes on cash (24) (20) (9)
Net cash flows from discontinued operations (1) - 1,263 826
----------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and equivalents 817 59 (235)
Cash and equivalents at beginning of year 290 231 466
----------------------------------------------------------------------------------------------------------------
Cash and equivalents at end of year $ 1,107 $ 290 $ 231
----------------------------------------------------------------------------------------------------------------
(continued on next page)
53
Halliburton Company
Consolidated Statements of Cash Flows
(Millions of dollars)
(continued)
Years ended December 31
------------------------------------------
2002 2001 2000
----------------------------------------------------------------------------------------------------------------
Supplemental disclosure of cash flow information:
Cash payments during the year for:
Interest $ 104 $ 132 $ 144
Income taxes $ 94 $ 382 $ 310
Non-cash investing and financing activities:
Liabilities assumed in acquisitions of businesses $ - $ 92 $ 95
Liabilities disposed of in dispositions of businesses $ - $ 500 $ 499
----------------------------------------------------------------------------------------------------------------
(1) Net cash flows from discontinued operations in 2001 include proceeds of
$1.27 billion from the sale of the remaining businesses in Dresser
Equipment Group and in 2000 proceeds of $913 million from the sales of
Dresser-Rand in 2000 and Ingersoll-Dresser Pump in 1999. See Note 3.
See notes to annual financial statements.
54
HALLIBURTON COMPANY
Notes to Annual Financial Statements
Note 1. Significant Accounting Policies
We employ accounting policies that are in accordance with accounting
principles generally accepted in the United States of America. The preparation
of financial statements in conformity with accounting principles generally
accepted in the United States of America requires 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 revenues and expenses during the
reporting period.
Ultimate results could differ from those estimates.
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 and a
leading provider of engineering and construction services. We have eight
business segments that are as follows: Pressure Pumping, Drilling and Formation
Evaluation, and Other Energy Services (collectively, the "Energy Services
Group"), and Onshore Operations, Offshore Operations, Government Operations,
Operations and Maintenance Services, and Infrastructure Operations
(collectively, the "Engineering and Construction Group"). Through our Energy
Services Group, we provide a comprehensive range of discrete and integrated
products and services for the exploration, development and production of oil and
gas. We serve major national and independent oil and gas companies throughout
the world. Our Engineering and Construction Group (known as KBR) provides a wide
range of services to energy and industrial customers and governmental entities
worldwide. See Note 4 for further discussion of our business segments.
Principles of consolidation. The consolidated financial statements
include the accounts of our company and all of our subsidiaries in which we own
greater than 50% interest or control. All material intercompany accounts and
transactions are eliminated. Investments in companies in which we own a 50%
interest or less and have a significant influence are accounted for using the
equity method and if we do not have significant influence we use the cost
method. Prior year amounts have been reclassified to conform to the current year
presentation.
Revenue recognition. We recognize revenues as services are rendered or
products are shipped. Generally the date of shipment corresponds to the date
upon which the customer takes title to the product and assumes all risk and
rewards of ownership. The distinction between services and product sales is
based upon the overall activity of the particular business operation. Training
and consulting service revenues are recognized as the services are performed.
Sales of perpetual software licenses, net of deferred maintenance fees, are
recorded as revenue upon shipment. Sales of use licenses are recognized as
revenue over the license period. Post-contract customer support agreements are
recorded as deferred revenues and recognized as revenue ratably over the
contract period of generally one year's duration.
Engineering and construction contracts. Revenues from engineering and
construction contracts are reported on the percentage of completion method of
accounting using measurements of progress toward completion appropriate for the
work performed. Progress is generally based upon physical progress, man-hours or
costs incurred based upon the appropriate method for the type of job. When
revenue and costs are recorded from engineering and construction contracts, we
comply with paragraph 81 of American Institute of Certified Public Accountants
Statement of Position 81-1, also known as SOP 81-1. Under this method, revenues
are recognized as the sum of costs incurred during the period plus the gross
profit earned, measured using the percentage of completion method of accounting.
All known or anticipated losses on contracts are provided for when they become
evident in accordance with paragraph 85 of SOP 81-1. Claims and change orders
which 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. For more details of revenue recognition, including other aspects of
engineering and construction accounting, including billings, claims and change
orders and liquidated damages, see Note 8 and Note 12.
Research and development. Research and development expenses are charged
to income as incurred. Research and development expenses were $233 million in
2002 and 2001 and $231 million in 2000.
Software development costs. Costs of developing software for sale are
charged to expense when incurred, as research and development, until
technological feasibility has been established for the product. Once
technological feasibility is established, software development costs are
capitalized until the software is ready for general release to customers. We
55
capitalized costs related to software developed for resale of $11 million in
2002, $19 million in 2001 and $7 million in 2000. Amortization expense of
software development costs was $19 million for 2002, $16 million for 2001 and
$12 million for 2000. Once the software is ready for release, amortization of
the software development costs begins. Capitalized software development costs
are amortized over periods which do not exceed five years.
Income per share. Basic income per share is based on the weighted
average number of common shares outstanding during the year. Diluted income per
share includes additional common shares that would have been outstanding if
potential common shares with a dilutive effect had been issued. See Note 13 for
a reconciliation of basic and diluted income per share.
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 United States
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 cost of over 90% of the remaining inventory is
recorded on the average cost method, with the remainder on the first-in,
first-out method. See Note 7.
Property, plant and equipment. 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. Some
assets are depreciated on accelerated methods. 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. When events or changes in
circumstances indicate that assets may be impaired, an evaluation is performed.
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. We follow the successful efforts method of accounting for oil
and gas properties. See Note 9.
Maintenance and repairs. Expenditures for maintenance and repairs are
expensed; expenditures for renewals and improvements are generally capitalized.
We use the accrue-in-advance method of accounting for major maintenance and
repair costs of marine vessel dry docking expense and major aircraft overhauls
and repairs. Under this method we anticipate the need for major maintenance and
repairs and charge the estimated expense to operations before the actual work is
performed. At the time the work is performed, the actual cost incurred is
charged against the amounts that were previously accrued with any deficiency or
excess charged or credited to operating expense.
Goodwill. For acquisitions occurring prior to July 1, 2001, goodwill
was amortized on a straight-line basis over periods not exceeding 40 years
through December 31, 2001. Effective July 1, 2001, we adopted SFAS No. 141,
"Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible
Assets", which precludes amortization of goodwill related to acquisitions
completed subsequent to June 30, 2001. Additionally, SFAS No. 142 precludes the
amortization of existing goodwill related to acquisitions completed prior to
July 1, 2001 for periods beginning January 1, 2002. See Note 22 for discussion
of this accounting change. SFAS No. 142 requires an entity to segregate its
operations into "reporting units." Additionally, all goodwill has been assigned
to one of these reporting units for purposes of determining impairment of the
goodwill. Because goodwill and some intangible assets are no longer amortized,
the reported amounts of goodwill and intangible assets are reviewed for
impairment on an annual basis and more frequently when negative conditions such
as significant current or projected operating losses exist. The annual
impairment test 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.
Income taxes. 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 either
expire before we are able to realize their benefit, or that future deductibility
is uncertain.
56
Derivative instruments. We enter into derivative financial transactions
to hedge existing or projected exposures to changing foreign currency exchange
rates, interest rates and commodity prices. We do not enter into derivative
transactions for speculative or trading purposes. Effective January 1, 2001, we
adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging
Activities." SFAS No. 133 requires that we recognize all derivatives on the
balance sheet at fair value. Derivatives that are not hedges must be adjusted to
fair value and reflected immediately through the results of operations. If the
derivative is designated as a hedge under SFAS No. 133, depending on the nature
of the hedge, changes in the fair value of derivatives are either offset
against:
- the change in fair value of the hedged assets, liabilities or
firm commitments through earnings; or
- recognized in other comprehensive income until the hedged item
is recognized in earnings.
The ineffective portion of a derivative's change in fair value is
immediately recognized in earnings. Recognized gains or losses on derivatives
entered into to manage foreign exchange risk are included in foreign currency
gains and losses on the consolidated statements of income. Gains or losses on
interest rate derivatives are included in interest expense and gains or losses
on commodity derivatives are included in operating income. During the three
years ended December 31, 2002, we did not enter into any significant
transactions to hedge commodity prices. See Note 11 for discussion of interest
rate swaps and Note 19 for further discussion of foreign currency exchange
derivatives.
Foreign currency translation. Foreign entities whose functional
currency is the United States dollar translate monetary assets and liabilities
at year-end exchange rates, and non-monetary 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 revenues,
and expenses associated with non-monetary balance sheet accounts which are
translated at historical rates. Gains or losses from changes in exchange rates
are recognized in consolidated income in the year of occurrence. Foreign
entities whose functional currency is the local currency 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 under "Cumulative translation adjustment".
Loss contingencies. We accrue for loss contingencies based upon our
best estimates in accordance with SFAS No. 5, "Accounting for Contingencies".
See Note 12 for discussion of our significant loss contingencies.
Stock-Based Compensation. At December 31, 2002, we have six stock-based
employee compensation plans, which are described more fully in Note 17. We
account for those plans under the recognition and measurement principles of APB
Opinion No. 25, "Accounting for Stock Issued to Employees", and related
Interpretations. No cost for stock options granted is reflected in net income,
as all options granted under our plans have an exercise price equal to the
market value of the underlying common stock on the date of grant.
The fair value of options at the date of grant was estimated using the
Black-Scholes option pricing model. The weighted average assumptions and
resulting fair values of options granted are as follows:
Assumptions
--------------------------------------------------------------------- Weighted Average
Risk-Free Expected Expected Expected Fair Value of
Interest Rate Dividend Yield Life (in years) Volatility Options Granted
------------------------------------------------------------------------------------------------------
2002 2.9% 2.7% 5 63% $ 6.89
2001 4.5% 2.3% 5 58% $ 19.11
2000 5.2% 1.3% 5 54% $ 21.57
======================================================================================================
The following table illustrates the effect on net income and earnings
per share if we had applied the fair value recognition provisions of FASB
Statement No. 123, "Accounting for Stock-Based Compensation", to stock-based
employee compensation.
57
Years ended December 31
----------------------------------------
Millions of dollars except per share data 2002 2001 2000
---------------------------------------------------------------------------------------
Net income (loss), as reported $ (998) $ 809 $ 501
Total stock-based employee compensation
expense determined under fair value
based method for all awards, net of
related tax effects (26) (42) (41)
---------------------------------------------------------------------------------------
Net income (loss), pro forma $(1,024) $ 767 $ 460
=======================================================================================
Basic earnings (loss) per share:
As reported $ (2.31) $ 1.89 $ 1.13
Pro forma $ (2.37) $ 1.79 $ 1.04
Diluted earnings (loss) per share:
As reported $ (2.31) $ 1.88 $ 1.12
Pro forma $ (2.37) $ 1.77 $ 1.03
======================================================================================-
Note 2. Acquisitions and Dispositions
Magic Earth acquisition. We acquired Magic Earth, Inc., a 3-D
visualization and interpretation technology company with broad applications in
the area of data interpretation in November 2001 for common shares with a value
of $100 million. At the consummation of the transaction, we issued 4.2 million
shares, valued at $23.93 per share, to complete the purchase. Magic Earth became
a wholly-owned subsidiary and is reported within our Other Energy Services
segment. We recorded goodwill of $71 million, all of which is nondeductible for
tax purposes. In addition, we recorded intangible assets of $19 million, which
are being amortized based on a five-year life.
PES acquisition. In February 2000, we acquired the remaining 74% of the
shares of PES (International) Limited that we did not already own for a value of
$126.7 million. This was based on 3.3 million shares of Halliburton common stock
valued at $37.75 per share which was the closing stock price on January 12,
2000. PES is based in Aberdeen, Scotland, and has developed technology that
complements Halliburton's real time reservoir solutions. To acquire the
remaining 74% of PES, we issued 1.2 million shares of Halliburton common stock
in February 2002, and we also issued rights that resulted in the issuance of 2.1
million additional shares of Halliburton common stock between February 2001 and
February 2002. We issued 1 million shares in February 2001; 400,000 shares in
June 2001; and the remaining 700,000 shares in February 2002 under these rights.
These shares were included in the cost of the acquisition as a contingent
liability. We recorded $115 million of goodwill, all of which is non-deductible
for tax purposes.
During the second quarter of 2001, we contributed the majority of PES'
assets and technologies, including $130 million of goodwill associated with the
purchase of PES, to a newly formed joint venture with Shell Technology Ventures
BV, WellDynamics. We received $39 million in cash as an equity equalization
adjustment, which we recorded as a reduction in our investment in the joint
venture. We own 50% of WellDynamics and account for this investment in our Other
Energy Services segment using the equity method. The formation of WellDynamics
resulted in a difference of $90 million between the carrying amount of our
investment and our equity in the underlying net assets of the joint venture,
which has been recorded as goodwill under "Equity in and advances to related
companies." The remaining assets and goodwill of PES relating to completions and
well intervention products are reported in our Other Energy Services segment.
PGS Data Management acquisition. In March 2001, we acquired the PGS
Data Management division of Petroleum Geo-Services ASA (PGS) for $164 million in
cash. The acquisition agreement also calls for Landmark to provide, for a fee,
strategic data management and distribution services to PGS for three years from
the date of acquisition. We recorded intangible assets of $14 million and
goodwill of $149 million in our Other Energy Services segment, $9 million of
which is non-deductible for tax purposes. The intangible assets are being
amortized based on a three-year life.
58
European Marine Contractors Ltd. disposition. In January 2002, we sold
our 50% interest in European Marine Contractors Ltd., an unconsolidated joint
venture reported within our Other Energy Services segment, to our joint venture
partner, Saipem. At the date of sale, we received $115 million in cash and a
contingent payment option valued at $16 million resulting in a pretax operating
income gain of $108 million. The contingent payment option was based on a
formula linked to performance of the Oil Service Index. In February 2002, we
exercised our option receiving an additional $19 million and recorded a pretax
gain of $3 million in "Other, net" in the statement of operations as a result of
the increase in value of this option. The total transaction resulted in an
after-tax gain of $68 million, or $0.16 per diluted share.
Subsea 7 formation. In May 2002, we contributed substantially all of
our Halliburton Subsea assets to a newly formed company, Subsea 7, Inc. We
contributed assets with a book value of approximately $82 million. The
contributed assets were recorded by the new company at a fair value of
approximately $94 million. The $12 million difference is being amortized over
ten years representing the average remaining useful life of the assets
contributed. We own 50% of Subsea 7, Inc. and account for this investment in our
Other Energy Services segment using the equity method. The remaining 50% is
owned by DSND Subsea ASA.
Bredero-Shaw disposition. On September 30, 2002 we sold our 50%
interest in the Bredero-Shaw joint venture to our partner ShawCor Ltd. The
purchase price of $149 million is comprised of $53 million in cash, a short-term
note for $25 million and 7.7 million of ShawCor Class A Subordinate shares. In
addition to our second quarter impairment charge of $61 million ($0.14 per
diluted share after-tax) related to the pending sale of Bredero-Shaw, we
recorded a third quarter pretax loss on sale of $18 million, or $0.04 per
diluted share, which is reflected in our Other Energy Services segment. Included
in this loss was $15 million of cumulative translation adjustment loss which was
realized upon the disposition of our investment in Bredero-Shaw. During the 2002
fourth quarter, we recorded in "Other, net" a $9.1 million loss on the sale of
ShawCor shares, or $0.02 per diluted share.
Dresser Equipment Group disposition. In April 2001, we disposed of the
remaining businesses in the Dresser Equipment Group. See Note 3.
Note 3. Discontinued Operations
For the twelve months ended December 31, 2002, we recorded a $806
million pretax charge in discontinued operations. The $806 million charge is
primarily comprised of the following:
- a $567 million charge during the fourth quarter due to a
revision of our best estimate of our asbestos and silica
liability based upon knowledge gained throughout the
development of the agreement in principle for our proposed
global settlement. The charge consisted of $1,047 million
related to the asbestos and silica claims gross liability,
which was offset by $480 million in anticipated related
insurance recoveries;
- a $153 million charge during the second quarter in connection
with our econometric study. The charge consisted of $1,176
million related to the gross liability on our asbestos and
silica claims, which was offset by $1,023 million in
anticipated insurance recoveries;
- a $40 million payment associated with the Harbison-Walker
bankruptcy filing recorded in the first quarter; and
- $46 million in costs primarily related to the negotiation of
the agreement in principle.
During the second and third quarters of 2001, we recorded a $95 million
pretax expense to discontinued operations. This amount was comprised of a $632
million charge related to the gross liability on Harbison-Walker asbestos
claims, which was offset by $537 million in anticipated related insurance
recoveries. See Note 12.
In late 1999 and early 2000 we sold our interest in two joint ventures
that were a significant portion of our Dresser Equipment Group. These sales
prompted a strategic review of the remaining businesses within the Dresser
Equipment Group. As a result of this review, we determined that these remaining
businesses did not closely fit with our core businesses, long-term goals and
strategic objectives. In April 2000, our Board of Directors approved plans to
sell all the remaining businesses within the Dresser Equipment Group. We sold
these businesses on April 10, 2001 and we recognized a pretax gain of $498
million ($299 million after-tax) during the second quarter of 2001. The
financial results of the Dresser Equipment Group through March 31, 2001 are
presented as discontinued operations in our financial statements. As part of the
terms of the transaction, we retained a 5.1% equity interest of Class A common
59
stock in the Dresser Equipment Group, which has been renamed Dresser, Inc. In
July 2002, Dresser, Inc. announced a reorganization, and we have exchanged our
shares for shares of Dresser Ltd. Our equity interest is accounted for under the
cost method.
Income (loss) from Operations
of Discontinued Businesses Years ended December 31
-----------------------------------------
Millions of dollars 2002 2001 2000
--------------------------------------------------------------------------
Revenues $ - $ 359 $ 1,400
==========================================================================
Operating income $ - $ 37 $ 158
Asbestos litigation claims,
net of insurance recoveries (806) (99) -
Tax benefit (expense) 154 20 (60)
--------------------------------------------------------------------------
Net income (loss) $ (652) $ (42) $ 98
==========================================================================
Gain on disposal of discontinued operations reflects the gain on the
sale of the remaining businesses within the Dresser Equipment Group in the
second quarter of 2001 and the gain on the sale of Dresser-Rand in February
2000.
Gain on Disposal of Discontinued Operations
Millions of dollars 2001 2000
------------------------------------------------------------------------------
Proceeds from sale, less intercompany settlement $ 1,267 $ 536
Net assets disposed (769) (180)
------------------------------------------------------------------------------
Gain before taxes 498 356
Income taxes (199) (141)
------------------------------------------------------------------------------
Gain on disposal of discontinued operations $ 299 $ 215
==============================================================================
Note 4. Business Segment Information
Disclosures regarding business segments have been restated to reflect
eight business segments. Previously we reported two segments, the Energy
Services Group and the Engineering and Construction Group (known as "KBR"). The
following eight segment presentation reflects financial information provided to
our chief executive officer (chief operating decision maker) during the periods
presented:
- Pressure Pumping;
- Drilling and Formation Evaluation;
- Other Energy Services;
- Onshore Operations;
- Offshore Operations;
- Government Operations;
- Operations and Maintenance Services; and
- Infrastructure Operations.
Pressure Pumping, Drilling and Formation Evaluation and Other Energy
Services are collectively referred to as the Energy Services Group, and Offshore
Operations, Onshore Operations, Government Operations, Operations and
Maintenance Services and Infrastructure Operations are collectively referred to
as the Engineering and Construction Group, or KBR.
Pressure Pumping. The Pressure Pumping segment provides services used
to complete oil and gas wells and to increase the amount of oil or gas
recoverable from those wells. Major services and products offered include:
- production enhancement services (including fracturing,
acidizing, coiled tubing, hydraulic workover, sand control,
and pipeline and process services);
- cementing services provide zonal isolation to prevent fluid
movement between formations, ensure a bond to provide support
for the casing, and provide wellbore reliability; and
- tools and testing services (including underbalanced
applications and tubing-conveyed perforating testing
services).
60
Drilling and Formation Evaluation. The Drilling and Formation
Evaluation segment is primarily involved in bore-hole construction and initial
oil and gas formation evaluation. The products and services in this segment
incorporate integrated technologies, which offer synergies related to drilling
activities and data gathering. The segment consists of drilling services,
including directional drilling and measurement-while-drilling/logging-while
-drilling; logging services; and drill bits. Included in this business segment
are Sperry-Sun, logging and perforating and Security DBS. Also included is our
Mono Pumps business, which we disposed of in the first quarter of 2003.
Other Energy Services. This segment provides drilling fluids systems,
completion products, integrated exploration and production software information
systems, consulting services, real-time operations, smartwells, and subsea
operations. Drilling fluids are used to provide for well control, drilling
efficiency, and as a means of removing wellbore cuttings. Completion products
and services include well completion equipment, slickline and safety systems.
Included in this business segment are Baroid, Landmark Graphics, Integrated
Solutions, Real Time Operations, our equity method investment in Enventure
Global Technology, LLC, an expandable casing joint venture, subsea operations
and our equity method investment in WellDynamics B.V., an intelligent well
completions joint venture. Also included are Wellstream, Bredero-Shaw and
European Marine Contractors Ltd., all of which have been sold.
Onshore Operations. The Onshore Operations segment provides engineering
and construction activities, including engineering and construction of liquefied
natural gas, ammonia and crude oil refineries and natural gas plants.
Offshore Operations. The Offshore Operations segment provides deepwater
engineering and marine technology and worldwide fabrication capabilities.
Government Operations. The Government Operations segment provides
construction, maintenance and logistics activities for government facilities and
installations.
Operations and Maintenance Services. The Operations and Maintenance
Services segment provides plant operations, maintenance, and start-up services
for both upstream and downstream oil, gas and petrochemical facilities as well
as operations, maintenance and logistics services for the power, commercial and
industrial markets.
Infrastructure Operations. The Infrastructure Operations segment
provides civil engineering, consulting and project management services.
Asbestos and Silica Charges. Asbestos and silica charges related to our
Engineering and Construction Group are not allocated to a specific segment as
these charges are reviewed by management in total.
General corporate. General corporate represents assets not included in
a business segment and is primarily composed of cash and cash equivalents,
deferred tax assets and insurance for asbestos and silica litigation claims.
Intersegment revenues included in the revenues of the business segments
and revenues between geographic areas are immaterial. Our equity in pretax
earnings and losses of unconsolidated affiliates that are accounted for on the
equity method is included in revenues and operating income of the applicable
segment.
The tables below present information on our continuing operations
business segments.
Operations by Business Segment
Years ended December 31
------------------------------------------
Millions of dollars 2002 2001 2000
-------------------------------------------------------------------------------------------
Revenues:
Pressure Pumping $ 2,770 $ 3,127 $ 2,357
Drilling and Formation Evaluation 1,633 1,643 1,287
Other Energy Services 2,433 3,041 2,589
-------------------------------------------------------------------------------------------
Total Energy Services Group 6,836 7,811 6,233
-------------------------------------------------------------------------------------------
Onshore Operations 1,813 1,422 2,228
Offshore Operations 1,457 1,156 916
Government Operations 1,217 1,436 1,355
Operations and Maintenance Services 927 956 869
Infrastructure Operations 322 265 343
-------------------------------------------------------------------------------------------
Total Engineering and Construction Group 5,736 5,235 5,711
-------------------------------------------------------------------------------------------
Total $ 12,572 $13,046 $ 11,944
===========================================================================================
61
Operations by Business Segment (cont'd)
Years ended December 31
------------------------------------------
Millions of dollars 2002 2001 2000
-------------------------------------------------------------------------------------------
Operating income (loss):
Pressure Pumping $ 454 $ 676 $ 314
Drilling and Formation Evaluation 160 171 1
Other Energy Services 24 189 274
-------------------------------------------------------------------------------------------
Total Energy Services Group 638 1,036 589
-------------------------------------------------------------------------------------------
Onshore Operations 43 79 (45)
Offshore Operations (179) (15) (63)
Government Operations 60 42 44
Operations and Maintenance Services 5 6 1
Infrastructure Operations 30 10 14
Asbestos and Silica Charges (644) (11) (5)
-------------------------------------------------------------------------------------------
Total Engineering and Construction Group (685) 111 (54)
-------------------------------------------------------------------------------------------
General corporate (65) (63) (73)
-------------------------------------------------------------------------------------------
Total $ (112) $ 1,084 $ 462
===========================================================================================
Capital expenditures:
Pressure Pumping $ 155 $ 272 $ 153
Drilling and Formation Evaluation 190 225 154
Other Energy Services Group 167 134 155
Shared Energy Services Assets 91 112 71
-------------------------------------------------------------------------------------------
Total Energy Services Group 603 743 533
-------------------------------------------------------------------------------------------
Onshore Operations 17 9 17
Offshore Operations 8 2 7
Government Operations 129 40 13
Operations and Maintenance Services 5 2 6
Infrastructure Operations 2 1 1
-------------------------------------------------------------------------------------------
Total Engineering and Construction Group 161 54 44
-------------------------------------------------------------------------------------------
General corporate - - 1
-------------------------------------------------------------------------------------------
Total $ 764 $ 797 $ 578
===========================================================================================
Depreciation, depletion and amortization:
Pressure Pumping $ 119 $ 112 $ 100
Drilling and Formation Evaluation 137 126 118
Other Energy Services 140 170 148
Shared Energy Services Assets 79 66 69
-------------------------------------------------------------------------------------------
Total Energy Services Group 475 474 435
-------------------------------------------------------------------------------------------
Onshore Operations 12 24 30
Offshore Operations 3 11 11
Government Operations 14 15 18
Operations and Maintenance Services - 3 4
Infrastructure Operations - 3 2
-------------------------------------------------------------------------------------------
Total Engineering and Construction Group 29 56 65
-------------------------------------------------------------------------------------------
General corporate 1 1 3
-------------------------------------------------------------------------------------------
Total $ 505 $ 531 $ 503
===========================================================================================
Within the Energy Services Group, only certain assets are associated
with specific segments. Those assets 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 and the remaining property, plant and equipment (including shared
62
facilities) are not associated with a segment but are considered to be shared
among the segments within the Energy Services Group. For segment operating
income presentation the depreciation expense associated with these shared Energy
Services Group assets is allocated to the Energy Services Group segments and
general corporate.
Total Assets by Business Segment
Years ended December 31
------------------------------------------
Millions of dollars 2002 2001 2000
-------------------------------------------------------------------------------------------
Total assets:
Pressure Pumping $ 1,322 $ 1,475 $ 1,240
Drilling and Formation Evaluation 1,163 1,253 1,168
Other Energy Services 2,272 2,764 2,499
Shared Energy Services Assets 1,187 1,072 1,057
-------------------------------------------------------------------------------------------
Total Energy Services Group 5,944 6,564 5,964
-------------------------------------------------------------------------------------------
Onshore Operations 1,084 1,200 1,049
Offshore Operations 896 1,011 886
Government Operations 620 564 498
Operations and Maintenance Services 277 271 303
Infrastructure Operations 227 141 149
-------------------------------------------------------------------------------------------
Total Engineering and Construction Group 3,104 3,187 2,885
-------------------------------------------------------------------------------------------
Net assets of discontinued operations - - 690
General corporate 3,796 1,215 653
-------------------------------------------------------------------------------------------
Total $ 12,844 $10,966 $10,192
============================================================================================
Operations by Geographic Area
Years ended December 31
------------------------------------------
Millions of dollars 2002 2001 2000
--------------------------------------------------------------------------------------------
Revenues:
United States $ 4,139 $ 4,911 $ 4,073
United Kingdom 1,521 1,800 1,512
Other areas (numerous countries) 6,912 6,335 6,359
--------------------------------------------------------------------------------------------
Total $ 12,572 $ 13,046 $ 11,944
============================================================================================
Long-lived assets:
United States $ 4,617 $ 3,030 $ 2,068
United Kingdom 691 617 525
Other areas (numerous countries) 711 744 776
--------------------------------------------------------------------------------------------
Total $ 6,019 $ 4,391 $ 3,369
============================================================================================
Note 5. Restricted Cash
At December 31, 2002, we had restricted cash of $190 million included
in Other assets. Restricted cash consists of:
- $107 million deposit that collateralizes a bond for a patent
infringement judgment on appeal;
- $57 million as collateral for potential future insurance claim
reimbursements; and
- $26 million primarily related to cash collateral agreements
for outstanding letters of credit for various construction
projects.
At December 31, 2001, we had $3 million in restricted cash in Other
assets.
63
Note 6. Receivables
Our receivables are generally not collateralized. Included in notes and
accounts receivable are notes with varying interest rates totaling $53 million
at December 31, 2002 and $19 million at December 31, 2001.
On April 15, 2002, we entered into an agreement to sell accounts
receivable to a bankruptcy-remote limited-purpose funding subsidiary. Under the
terms of the agreement, new receivables are added on a continuous basis to the
pool of receivables, and collections reduce previously sold accounts receivable.
This funding subsidiary sells an undivided ownership interest in this pool of
receivables to entities managed by unaffiliated financial institutions under
another agreement. Sales to the funding subsidiary have been structured as "true
sales" under applicable bankruptcy laws, and the assets of the funding
subsidiary are not available to pay any creditors of Halliburton or of its
subsidiaries or affiliates, until such time as the agreement with the
unaffiliated companies is terminated following sufficient collections to
liquidate all outstanding undivided ownership interests. The funding subsidiary
retains the interest in the pool of receivables that are not sold to the
unaffiliated companies, and is fully consolidated and reported in our financial
statements.
The amount of undivided interests, which can be sold under the program,
varies based on the amount of eligible Energy Services Group receivables in the
pool at any given time and other factors. The funding subsidiary sold a $200
million undivided ownership interest to the unaffiliated companies, and may from
time to time sell additional undivided ownership interests. No additional
amounts were received from our accounts receivable facility since the second
quarter of 2002. The total amount outstanding under this facility was $180
million as of December 31, 2002. We continue to service, administer and collect
the receivables on behalf of the purchaser. The amount of undivided ownership
interest in the pool of receivables sold to the unaffiliated companies is
reflected as a reduction of accounts receivable in our consolidated balance
sheet and as an increase in cash flows from operating activities in our
consolidated statement of cash flows.
Note 7. Inventories
Inventories are stated at the lower of cost or market. Some United
States 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, totaling $43 million at December 31, 2002 and $54
million at December 31, 2001. If the average cost method had been used, total
inventories would have been $17 million higher than reported at December 31,
2002 and $20 million higher than reported at December 31, 2001.
Over 90% of remaining inventory is recorded on the average cost method,
with the remainder on the first-in, first-out method.
Inventories at December 31, 2002 and December 31, 2001 are composed of
the following:
December 31 December 31
Millions of dollars 2002 2001
-----------------------------------------------------------------------
Finished products and parts $ 545 $ 520
Raw materials and supplies 141 192
Work in process 48 75
-----------------------------------------------------------------------
Total $ 734 $ 787
=======================================================================
Note 8. Unapproved Claims and Long-Term Construction Contracts
Billing practices for engineering and construction projects are
governed by the contract terms of each project based upon costs incurred,
achievement of milestones or pre-agreed schedules. Billings do not necessarily
correlate with revenues recognized under the percentage of completion method of
accounting. Billings in excess of recognized revenues are recorded in "Advance
billings on uncompleted contracts". When billings are less than recognized
revenues, the difference is recorded in "Unbilled work on uncompleted
contracts". With the exception of claims and change orders which are in the
process of being negotiated with customers, unbilled work is usually billed
during normal billing processes following achievement of the contractual
requirements.
64
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 contract revenue, change orders and claims
reduced by costs incurred and estimated costs to complete. Anticipated losses on
contracts are recorded in full in the period they become evident. Profits are
recorded based upon the total estimated contract profit multiplied by the
current percentage complete for the contract.
When calculating the amount of total profit or loss on a long-term
contract, we include unapproved claims as revenue when the collection is deemed
probable based upon the four criteria for recognizing unapproved claims under
the American Institute of Certified Public Accountants Statement of Position
81-1, "Accounting for Performance of Construction-Type and Certain
Production-Type Contracts." Including 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.
Unapproved claims are recorded to the extent of costs incurred and include no
profit element. In substantially 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.
When recording the revenue and the associated unbilled receivable for
unapproved claims, we only accrue an amount equal to the costs incurred related
to probable unapproved claims. Therefore, the difference between the probable
unapproved claims included in determining contract profit or loss and the
probable unapproved claims recorded in unbilled work on uncompleted contracts
relates to forecasted costs which have not yet been incurred. The amounts
included in determining the profit or loss on contracts, and the amounts booked
to "Unbilled work on uncompleted contracts" for each period are as follows:
Years ended December 31
--------------------------------
Millions of dollars 2002 2001
------------------------------------------------------------------------------
Probable unapproved claims (included
in determining contract profit or loss) $ 279 $ 137
Unapproved claims in unbilled work on
uncompleted contracts $ 210 $ 102
==============================================================================
The claims at December 31, 2002 listed in the above table relate to ten
contracts, most of which are complete or substantially complete. We are actively
engaged in claims negotiation with the customer in all but one case, and in that
case we have initiated the arbitration process. The probable unapproved claim in
arbitration is $2 million. The largest claim relates to the Barracuda-Caratinga
contract which was approximately 63% complete at the end of 2002. The probable
unapproved claims included in determining this contract's loss were $182 million
at December 31, 2002 and $43 million at December 31, 2001. As the claim for this
contract most likely will not be settled within one year, amounts in unbilled
work on uncompleted contracts of $115 million at December 31, 2002 and $10
million at December 31, 2001 included in the table above have been recorded to
long-term unbilled work on uncompleted contracts which is included in "Other
assets" on the balance sheet. All other claims included in the table above have
been recorded to Unbilled work on uncompleted contracts included in the "Total
receivables" amount on the balance sheet.
A summary of unapproved claims activity for the years ended December
31, 2002 and 2001 is as follows:
Total Probable Unapproved Probable Unapproved Claims
Claims Accrued Revenue
-------------------------------------------------------------------
Millions of dollars 2002 2001 2002 2001
--------------------------------------------------------------------------------------------------------
Beginning balance $ 137 $ 93 $ 102 $ 92
Additions 158 92 105 58
Costs incurred during period - - 19 -
Approved claims (4) (15) (4) (15)
Write-offs (7) (33) (7) (33)
Other * (5) - (5) -
--------------------------------------------------------------------------------------------------------
Ending balance $ 279 $ 137 $ 210 $102
========================================================================================================
* Other primarily relates to claims in which the customer has agreed to
a change order relating to the scope of work.
65
In addition, our unconsolidated related companies include probable
unapproved claims as revenue to determine the amount of profit or loss for their
contracts. Our "Equity in earnings of unconsolidated affiliates" includes our
equity percentage of unapproved claims related to unconsolidated projects.
Amounts for unapproved claims from our related companies are included in "Equity
in and advances to related companies" and totaled $9 million at December 31,
2002 and $0.3 million at December 31, 2001.
Note 9. Property, Plant and Equipment
Property, plant and equipment at December 31, 2002 and 2001 are
composed of the following:
Millions of dollars 2002 2001
---------------------------------------------------------------------
Land $ 86 $ 82
Buildings and property improvements 1,024 942
Machinery, equipment and other 4,842 4,926
---------------------------------------------------------------------
Total 5,952 5,950
Less accumulated depreciation 3,323 3,281
---------------------------------------------------------------------
Net property, plant and equipment $ 2,629 $ 2,669
=====================================================================
Buildings and property improvements are depreciated over 5-40 years;
machinery, equipment and other are depreciated over 3-25 years.
Machinery, equipment and other includes oil and gas investments of $356
million at December 31, 2002 and $423 million at December 31, 2001.
Note 10. Related Companies
We conduct some of our operations through various joint ventures which
are in partnership, corporate and other business forms, and are principally
accounted for using the equity method. Financial information pertaining to
related companies for our continuing operations is set out below. This
information includes the total related company balances and not our proportional
interest in those balances.
Our larger unconsolidated entities include Subsea 7, Inc., a 50% owned
subsidiary, formed in May of 2002 and the partnerships created to construct the
Alice Springs to Darwin rail line in Australia. During 2002, we sold our 50%
interest in European Marine Contractors and Bredero-Shaw. See Note 2.
Combined summarized financial information for all jointly owned
operations that are not consolidated is as follows:
Combined Operating Results Years ended December 31
---------------------------------------
Millions of dollars 2002 2001 2000
-------------------------------------------------------------------------
Revenues $ 1,948 $ 1,987 $ 3,098
=========================================================================
Operating income $ 200 $ 231 $ 192
=========================================================================
Net income $ 159 $ 169 $ 169
=========================================================================
Combined Financial Position December 31
-----------------------------
Millions of dollars 2002 2001
---------------------------------------------------------------
Current assets $ 1,404 $ 1,818
Noncurrent assets 1,876 1,672
---------------------------------------------------------------
Total $ 3,280 $ 3,490
===============================================================
Current liabilities $ 1,155 $ 1,522
Noncurrent liabilities 1,367 1,272
Minority interests - 2
Shareholders' equity 758 694
---------------------------------------------------------------
Total $ 3,280 $ 3,490
===============================================================
66
Note 11. Lines of Credit, Notes Payable and Long-Term Debt
At December 31, 2002, we had committed lines of credit totaling $350
million which expire in August 2006. There were no borrowings outstanding under
these lines of credit. These lines are not available if our senior unsecured
long-term debt is rated lower than BBB- by Standard & Poor's Ratings Service
Group or lower than Baa3 by Moody's Investors' Services. Fees for committed
lines of credit were immaterial.
Short-term debt at December 31, 2002 consists primarily of $37 million
in overdraft facilities and $12 million of other facilities with varying rates
of interest.
Long-term debt at the end of 2002 and 2001 consists of the following:
Millions of dollars 2002 2001
------------------------------------------------------------------------------------
7.6% debentures due August 2096 $ 300 $ 300
8.75% debentures due February 2021 200 200
8% senior notes due April 2003 139 139
Variable interest credit facility maturing
September 2009 66 -
Medium-term notes due 2002 through 2027 750 825
Effect of interest rate swaps 13 3
Term loans at LIBOR (GBP) plus 0.75% payable in
semiannual installments through March 2002 - 4
Other notes with varying interest rates 8 13
------------------------------------------------------------------------------------
Total long-term debt 1,476 1,484
Less current portion 295 81
------------------------------------------------------------------------------------
Noncurrent portion of long-term debt $1,181 $ 1,403
====================================================================================
The 7.6% debentures due 2096, 8.75% debentures due 2021, and 8% senior
notes due 2003 may not be redeemed prior to maturity and do not have sinking
fund requirements.
In the fourth quarter of 2002, our 51% owned and consolidated
subsidiary, Devonport Management Limited (DML), signed an agreement for a credit
facility of (pound)80 million ($126 million as of December 31, 2002) maturing in
September 2009. This credit facility has a variable interest rate that was equal
to 5.375% on December 31, 2002. There are various financial covenants which must
be maintained by DML. DML has drawn down an initial amount of $66 million as of
December 31, 2002. Under this agreement, payments of approximately $4.5 million
are due in quarterly installments. As of December 31, 2002, the available credit
under this facility was approximately $60 million.
On July 12, 2001, we issued $425 million of two and five-year notes
under our medium-term note program. The notes consist of $275 million 6% fixed
rate notes due August 2006 and $150 million LIBOR + 0.15% floating rate notes
due July 2003. At December 31, 2002, we have outstanding notes under our
medium-term note program as follows:
Amount Due Rate Issue Price
-----------------------------------------------------------------
$ 150 million 07/2003 Floating% Par
$ 275 million 08/2006 6.00% 99.57%
$ 150 million 12/2008 5.63% 99.97%
$ 50 million 05/2017 7.53% Par
$ 125 million 02/2027 6.75% 99.78%
=================================================================
Each holder of the 6.75% medium-term notes has the right to require us
to repay the holder's notes in whole or in part on February 1, 2007. We may
redeem the 5.63% and 6.00% medium-term notes in whole or in part at any time.
Other notes issued under the medium-term note program may not be redeemed prior
to maturity. The medium-term notes do not have sinking fund requirements.
67
In the second quarter of 2002, we terminated our interest rate swap
agreement on our 8% senior note. The notional amount of the swap agreement was
$139 million. This interest rate swap was designated as a fair value hedge under
SFAS No. 133. Upon termination, the fair value of the interest rate swap was
$0.5 million. In the fourth quarter 2002, we terminated the interest rate swap
agreement on our 6% fixed rate medium-term note. The notional amount of the swap
agreement was $150 million. This interest rate swap was designated as a fair
value hedge under SFAS No. 133. Upon termination, the fair value of the interest
rate swap was $13 million. These swaps had previously been classified in "Other
assets" on the balance sheet. The fair value adjustment to these debt
instruments that were hedged will remain and be amortized as a reduction in
interest expense using the "Effective Yield Method" over the remaining life of
the notes.
Our debt excluding the effects of our interest rate swaps matures as
follows: $295 million in 2003; $21 million in 2004; $20 million in 2005; $293
million in 2006; $8 million in 2007; and $826 million thereafter.
Note 12. Commitments and Contingencies
Leases. At year-end 2002, we were obligated under noncancelable
operating leases, principally for the use of land, offices, equipment, field
facilities and warehouses. Total rentals, net of sublease rentals, for
noncancelable leases in 2002, 2001 and 2000 were as follows:
Millions of dollars 2002 2001 2000
------------------------------------------------------------------
Rental expense $ 149 $ 172 $ 149
==================================================================
Future total rentals on noncancelable operating leases are as follows:
$119 million in 2003; $83 million in 2004; $63 million in 2005; $55 million in
2006; $40 million in 2007; and $249 million thereafter.
Asbestos litigation. Several of our subsidiaries, particularly DII
Industries, LLC (DII Industries) and Kellogg, Brown & Root, Inc. (Kellogg, Brown
& Root), are defendants in a large number of asbestos-related lawsuits. The
plaintiffs allege injury as a result of exposure to asbestos in products
manufactured or sold by former divisions of DII Industries or in materials used
in construction or maintenance projects of Kellogg, Brown & Root. These claims
are in three general categories:
- refractory claims;
- other DII Industries claims; and
- construction claims.
Refractory claims. Asbestos was used in a small number of products
manufactured or sold by Harbison-Walker Refractories Company, which DII
Industries acquired in 1967. The Harbison-Walker operations were conducted as a
division of DII Industries (then named Dresser Industries, Inc.) until those
operations were transferred to another then-existing subsidiary of DII
Industries in preparation for a spin-off. Harbison-Walker was spun-off by DII
Industries in July 1992. At that time, Harbison-Walker assumed liability for
asbestos claims filed after the spin-off and it agreed to defend and indemnify
DII Industries from liability for those claims, although DII Industries
continues to have direct liability to tort claimants for all post spin-off
refractory claims. DII Industries retained responsibility for all asbestos
claims pending as of the date of the spin-off. The agreement governing the
spin-off provided that Harbison-Walker would have the right to access DII
Industries historic insurance coverage for the asbestos-related liabilities that
Harbison-Walker assumed in the spin-off. After the spin-off, DII Industries and
Harbison-Walker jointly negotiated and entered into coverage-in-place agreements
with a number of insurance companies that had issued historic general liability
insurance policies which both DII Industries and Harbison-Walker had the right
to access for, among other things, bodily injury occurring between 1963 and
1985. These coverage-in-place agreements provide for the payment of defense
costs, settlements and court judgments paid to resolve refractory asbestos
claims.
As Harbison-Walker's financial condition worsened in late 2000 and
2001, Harbison-Walker began agreeing to pay more in settlement of the post
spin-off refractory claims than it historically had paid. These increased
settlement amounts led to Harbison-Walker making greater demands on the shared
insurance asset. By July 2001, DII Industries determined that the demands that
Harbison-Walker was making on the shared insurance policies were not acceptable
to DII Industries and that Harbison-Walker probably would not be able to fulfill
its indemnification obligation to DII Industries. Accordingly, DII Industries
took up the defense of unsettled post spin-off refractory claims that name it as
68
a defendant in order to prevent Harbison-Walker from unnecessarily eroding the
insurance coverage both companies access for these claims. These claims are now
stayed in the Harbison-Walker bankruptcy proceeding.
As of December 31, 2002, there were approximately 6,000 open and
unresolved pre-spin-off refractory claims against DII Industries. In addition,
there were approximately 142,000 post spin-off claims that name DII Industries
as a defendant.
Other DII Industries claims. As of December 31, 2002, there were
approximately 147,000 open and unresolved claims alleging injuries from asbestos
used in other products formerly manufactured by DII Industries. Most of these
claims involve gaskets and packing materials used in pumps and other industrial
products.
Construction claims. Our Engineering and Construction Group includes
engineering and construction businesses formerly operated by The M.W. Kellogg
Company and Brown & Root, Inc., now combined as Kellogg, Brown & Root. As of
December 31, 2002, there were approximately 52,000 open and unresolved claims
alleging injuries from asbestos in materials used in construction and
maintenance projects, most of which were conducted by Brown & Root, Inc.
Approximately 2,200 of these claims are asserted against The M.W. Kellogg
Company. We believe that Kellogg, Brown & Root has a good defense to these
claims, and a prior owner of The M.W. Kellogg Company provides Kellogg, Brown &
Root a contractual indemnification for claims against The M.W. Kellogg Company.
Harbison-Walker Chapter 11 bankruptcy. On February 14, 2002,
Harbison-Walker filed a voluntary petition for reorganization under Chapter 11
of the United States Bankruptcy Code in the Bankruptcy Court in Pittsburgh,
Pennsylvania. In its bankruptcy-related filings, Harbison-Walker said that it
would seek to utilize Sections 524(g) and 105 of the Bankruptcy Code to propose
and seek confirmation of a plan of reorganization that would provide for
distributions for all legitimate, pending and future asbestos claims asserted
directly against Harbison-Walker or asserted against DII Industries for which
Harbison-Walker is required to indemnify and defend DII Industries.
Harbison-Walker's failure to fulfill its indemnity obligations, and its
erosion of insurance coverage shared with DII Industries, required DII
Industries to assist Harbison-Walker in its bankruptcy proceeding in order to
protect the shared insurance from dissipation. At the time that Harbison-Walker
filed its bankruptcy, DII Industries agreed to provide up to $35 million of
debtor-in-possession financing to Harbison-Walker during the pendency of the
Chapter 11 proceeding, of which $5 million was advanced during the first quarter
of 2002. On February 14, 2002, in accordance with the terms of a letter
agreement, DII Industries also paid $40 million to Harbison-Walker's United
States parent holding company, RHI Refractories Holding Company. This payment
was charged to discontinued operations in our financial statements in the first
quarter of 2002.
The terms of the letter agreement also requires DII Industries to pay
to RHI Refractories an additional $35 million if a plan of reorganization is
proposed in the Harbison-Walker bankruptcy proceedings, and an additional $85
million if a plan is confirmed in the Harbison-Walker bankruptcy proceedings, in
each case acceptable to DII Industries in its sole discretion. The letter
agreement provides that a plan acceptable to DII Industries must include an
injunction channeling to a Section 524(g)/105 trust all present and future
asbestos claims against DII Industries, arising out of the Harbison-Walker
business or other DII Industries' businesses that share insurance with
Harbison-Walker.
By contrast, the proposed global settlement being pursued by
Halliburton contemplates that DII Industries and Harbison-Walker, among others
including Halliburton, would receive in a DII Industries and Kellogg, Brown &
Root bankruptcy the benefits of an injunction channeling to a Section 524(g)/105
trust all present and future asbestos claims, including with respect to DII
Industries, Kellogg, Brown & Root and Halliburton, claims that do not relate to
the Harbison-Walker business or share insurance with Harbison-Walker.
Harbison-Walker has not yet submitted a proposed plan of reorganization
to the Bankruptcy Court. Moreover, although possible, at this time we do not
believe it likely that Harbison-Walker will propose or ultimately there would be
confirmed a plan of reorganization in its bankruptcy proceeding that is
acceptable to DII Industries. In general, in order for a Harbison-Walker plan of
reorganization involving a Section 524(g)/105 trust to be confirmed, among other
things the creation of the trust would require the approval of 75% of the
asbestos claimant creditors of Harbison-Walker. There can be no assurance that
any plan proposed by Harbison-Walker would obtain the necessary approval or
69
that it would provide for an injunction channeling to a Section 524(g)/105 trust
all present and future asbestos claims against DII Industries arising out of the
Harbison-Walker business or that share insurance with Harbison-Walker.
In addition, we anticipate that a significant financial contribution to
the Harbison-Walker estate could be required from DII Industries to obtain
confirmation of a Harbison-Walker plan of reorganization if that plan were to
include an injunction channeling to a Section 524(g)/105 trust all present and
future asbestos claims against DII Industries arising out of the Harbison-Walker
business or that have claims to shared insurance with the Harbison-Walker
business. This contribution to the estate would be in addition to DII
Industries' contribution of its interest to insurance coverage for refractory
claims to the Section 524(g)/105 trust. At this time, we are not able to
quantify the amount of this contribution in light of numerous uncertainties.
These include the amount of Harbison-Walker assets available to satisfy its
asbestos and trade creditors and the results of negotiations that must be
completed among Harbison-Walker, the asbestos claims committee under its Chapter
11 proceeding, a legal representative for future asbestos claimants (which has
not yet been appointed by the Bankruptcy Court), DII Industries and the relevant
insurance companies.
Whether or not Halliburton has completed, is still pursuing or has
abandoned its previously announced global settlement, DII Industries would be
under no obligation to make a significant financial contribution to the
Harbison-Walker estate, although Halliburton intends to consider all of its
options if in the future it ceased pursuing the global settlement.
For the reasons outlined above among others, we do not believe it
probable that DII Industries will be obligated to make either of the additional
$35 million and $85 million payments to RHI Refractories described above. During
February 2003, representatives of RHI A.G., the ultimate corporate parent of RHI
Refractories, met with representatives of DII Industries and indicated that they
believed that DII Industries would be obligated to pay RHI Refractories the $35
million and the $85 million in the event that our proposed global settlement
were to be consummated. For a number of reasons, DII Industries believes that
the global settlement would not be the cause of a failure of a Harbison-Walker
plan to be acceptable to DII Industries and intends vigorously to defend against
this claim if formally asserted.
In connection with the Chapter 11 filing by Harbison-Walker, the
Bankruptcy Court on February 14, 2002 issued a temporary restraining order
staying all further litigation of more than 200,000 asbestos claims currently
pending against DII Industries in numerous courts throughout the United States.
The period of the stay contained in the temporary restraining order has been
extended to July 21, 2003.Currently, there is no assurance that a stay will
remain in effect beyond July 21, 2003, that a plan of reorganization will be
proposed or confirmed for Harbison-Walker, or that any plan that is confirmed
will provide relief to DII Industries.
The stayed asbestos claims are those covered by insurance that DII
Industries and Harbison-Walker each access to pay defense costs, settlements and
judgments attributable to both refractory and non-refractory asbestos claims.
The stayed claims include approximately 142,000 post-1992 spin-off refractory
claims, 6,000 pre-spin-off refractory claims and approximately 135,000 other
types of asbestos claims pending against DII Industries. Approximately 51,000 of
the claims in the third category are claims made against DII Industries based on
more than one ground for recovery and the stay affects only the portion of the
claim covered by the shared insurance. The stay prevents litigation from
proceeding while the stay is in effect and also prohibits the filing of new
claims. One of the purposes of the stay is to allow Harbison-Walker and DII
Industries time to develop and propose a plan of reorganization.
Asbestos insurance coverage. DII Industries has substantial insurance
for reimbursement for portions of the costs incurred defending asbestos and
silica claims, as well as amounts paid to settle claims and court judgments.
This coverage is provided by a large number of insurance policies written by
dozens of insurance companies. The insurance companies wrote the coverage over a
period of more than 30 years for DII Industries, its predecessors or its
subsidiaries and their predecessors. Large amounts of this coverage are now
subject to coverage-in-place agreements that resolve issues concerning amounts
and terms of coverage. The amount of insurance available to DII Industries and
its subsidiaries depends on the nature and time of the alleged exposure to
asbestos or silica, the specific subsidiary against which an asbestos or silica
claim is asserted and other factors.
Refractory claims insurance. DII Industries has approximately $2.1
billion in aggregate limits of insurance coverage for refractory asbestos and
silica claims, of which over one-half is with Equitas or other London-based
insurance companies. Most of this insurance is shared with Harbison-Walker. Many
of the issues relating to the majority of this coverage have been resolved by
70
coverage-in-place agreements with dozens of companies, including Equitas and
other London-based insurance companies. Coverage-in-place agreements are
settlement agreements between policyholders and the insurers specifying the
terms and conditions under which coverage will be applied as claims are
presented for payment. These agreements in an asbestos claims context govern
such things as what events will be deemed to trigger coverage, how liability for
a claim will be allocated among insurers and what procedures the policyholder
must follow in order to obligate the insurer to pay claims. Recently, however,
Equitas and other London-based companies have attempted to impose new
restrictive documentation requirements on DII Industries and other insureds.
Equitas and the other London-based companies have stated that the new
requirements are part of an effort to limit payment of settlements to claimants
who are truly impaired by exposure to asbestos and can identify the product or
premises that caused their exposure.
On March 21, 2002, Harbison-Walker filed a lawsuit in the United States
Bankruptcy Court for the Western District of Pennsylvania in its Chapter 11
bankruptcy proceeding. This lawsuit is substantially similar to DII Industries
lawsuit filed in Texas State Court in 2001 and seeks, among other relief, a
determination as to the rights of DII Industries and Harbison-Walker to the
shared general liability insurance. The lawsuit also seeks damages against
specific insurers for breach of contract and bad faith, and a declaratory
judgment concerning the insurers' obligations under the shared insurance.
Although DII Industries is also a defendant in this lawsuit, it has asserted its
own claim to coverage under the shared insurance and is cooperating with
Harbison-Walker to secure both companies' rights to the shared insurance. The
Bankruptcy Court has ordered the parties to this lawsuit to engage in
non-binding mediation. The first mediation session was held on July 26, 2002 and
additional sessions have since taken place and further sessions are scheduled to
take place, provided the Bankruptcy Court's mediation order remains in effect.
Given the early stages of these negotiations, DII Industries cannot predict
whether a negotiated resolution of this dispute will occur or, if such a
resolution does occur, the precise terms of such a resolution.
Prior to the Harbison-Walker bankruptcy, on August 7, 2001, DII
Industries filed a lawsuit in Dallas County, Texas, against a number of these
insurance companies asserting DII Industries rights under an existing
coverage-in-place agreement and under insurance policies not yet subject to
coverage-in-place agreements. The coverage-in-place agreements allow DII
Industries to enter into settlements for small amounts without requiring
claimants to produce detailed documentation to support their claims, when DII
Industries believes the settlements are an effective claims management strategy.
DII Industries believes that the new documentation requirements are inconsistent
with the current coverage-in-place agreements and are unenforceable. The
insurance companies that DII Industries has sued have not refused to pay larger
claim settlements where documentation is obtained or where court judgments are
entered.
On May 10, 2002, the London-based insuring entities and companies
removed DII Industries' Dallas County State Court Action to the United States
District Court for the Northern District of Texas alleging that federal court
jurisdiction existed over the case because it is related to the Harbison-Walker
bankruptcy. DII Industries has filed an opposition to that removal and has asked
the federal court to remand the case back to the Dallas County state court. On
June 12, 2002, the London-based insuring entities and companies filed a motion
to transfer the case to the federal court in Pittsburgh, Pennsylvania. DII
Industries has filed an opposition to that motion to transfer. The federal court
in Dallas has yet to rule on any of these motions. Regardless of the outcome of
these motions, because of the similar insurance coverage lawsuit filed by
Harbison-Walker in its bankruptcy proceeding, it is unlikely that DII Industries
case will proceed independently of the bankruptcy.
Other DII Industries claims insurance. DII Industries has substantial
insurance to cover other non-refractory asbestos claims. Two coverage-in-place
agreements cover DII Industries for companies or operations that DII Industries
either acquired or operated prior to November 1, 1957. Asbestos claims that are
covered by these agreements are currently stayed by the Harbison-Walker
bankruptcy because the majority of this coverage also applies to refractory
claims and is shared with Harbison-Walker. Other insurance coverage is provided
by a number of different policies that DII Industries acquired rights to access
when it acquired businesses from other companies. Three coverage-in-place
agreements provide reimbursement for asbestos claims made against DII Industries
former Worthington Pump division. There is also other substantial insurance
coverage with approximately $2.0 billion in aggregate limits that has not yet
been reduced to coverage-in-place agreements.
On August 28, 2001, DII Industries filed a lawsuit in the 192nd
Judicial District of the District Court for Dallas County, Texas against
specific London-based insuring entities that issued insurance policies that
provide coverage to DII Industries for asbestos-related liabilities arising out
of the historical operations of Worthington Corporation or its successors. This
71
lawsuit raises essentially the same issue as to the documentation requirements
as the August 7, 2001 Harbison-Walker lawsuit filed in the same court. The
London-based insuring entities filed a motion in that case seeking to compel the
parties to binding arbitration. The trial court denied that motion and the
London-based insuring entities appealed that decision to the state appellate
court. The state appellate courts denied the appeal and, most recently, the
London-based insuring entities have removed the case from the state court to the
federal court. DII Industries was successful in remanding the case back to the
state court.
A significant portion of the insurance coverage applicable to
Worthington claims is alleged by Federal-Mogul Products, Inc. to be shared with
it. In 2001, Federal-Mogul Products, Inc. and a large number of its affiliated
companies filed a voluntary petition for reorganization under Chapter 11 of the
Bankruptcy Code in the Bankruptcy Court in Wilmington, Delaware.
In response to Federal-Mogul's allegations, on December 7, 2001, DII
Industries filed a lawsuit in the Delaware Bankruptcy Court asserting its rights
to insurance coverage under historic general liability policies issued to
Studebaker-Worthington, Inc. and its successor for asbestos-related liabilities
arising from, among other operations, Worthington's and its successors' historic
operations. This lawsuit also seeks a judicial declaration concerning the
competing rights of DII Industries and Federal-Mogul, if any, to this insurance
coverage. DII Industries recently filed a second amended complaint in that
lawsuit and the parties are now beginning the discovery process. The parties to
this litigation, including Federal-Mogul, have agreed to mediate this dispute.
The first mediation session is scheduled for April 2, 2003. Unlike the
Harbison-Walker insurance coverage litigation, in which the litigation is stayed
while the mediation proceeds, the insurance coverage litigation concerning the
Worthington-related asbestos liabilities has not been stayed and such litigation
will proceed simultaneously with the mediation.
At the same time, DII Industries filed its insurance coverage action in
the Federal-Mogul bankruptcy, DII Industries also filed a second lawsuit in
which it has filed a motion for preliminary injunction seeking a stay of all
Worthington asbestos-related lawsuits against DII Industries that are scheduled
for trial within the six months following the filing of the motion. The stay
that DII Industries seeks, if granted, would remain in place until the competing
rights of DII Industries and Federal-Mogul to the allegedly shared insurance are
resolved. The Court has yet to schedule a hearing on DII Industries motion for
preliminary injunction.
A number of insurers who have agreed to coverage-in-place agreements
with DII Industries have suspended payment under the shared Worthington policies
until the Federal-Mogul Bankruptcy Court resolves the insurance issues.
Consequently, the effect of the Federal-Mogul bankruptcy on DII Industries
rights to access this shared insurance is uncertain.
Construction claims insurance. Nearly all of our construction asbestos
claims relate to Brown & Root, Inc. operations before the 1980s. Our primary
insurance coverage for these claims was written by Highlands Insurance Company
during the time it was one of our subsidiaries. Highlands was spun-off to our
shareholders in 1996. On April 5, 2000, Highlands filed a lawsuit against us in
the Delaware Chancery Court. Highlands asserted that the insurance it wrote for
Brown & Root, Inc. that covered construction asbestos claims was terminated by
agreements between Halliburton and Highlands at the time of the 1996 spin-off.
In March 2001, the Chancery Court ruled that a termination did occur and that
Highlands was not obligated to provide coverage for Brown & Root, Inc.'s
asbestos claims. This decision was affirmed by the Delaware Supreme Court on
March 13, 2002. As a result of this ruling, we wrote-off approximately $35
million in accounts receivable for amounts paid for claims and defense costs and
$45 million of accrued receivables in relation to estimated insurance recoveries
claims settlements from Highlands in the first quarter 2002. In addition, we
dismissed the April 24, 2000 lawsuit we filed against Highlands in Harris
County, Texas.
As noted in our 2001 Form 10-K, the amount of the billed insurance
receivable related to Highlands Insurance Company included in accounts
receivable was $35 million.
As a consequence of the Delaware Supreme Court's decision, Kellogg,
Brown & Root no longer has primary insurance coverage from Highlands for
asbestos claims. However, Kellogg, Brown & Root has significant excess insurance
coverage. The amount of this excess coverage that will reimburse us for an
asbestos claim depends on a variety of factors. On March 20, 2002, Kellogg,
Brown & Root filed a lawsuit in the 172nd Judicial District of the District
Court of Jefferson County, Texas, against Kellogg, Brown & Root's historic
insurers that issued these excess insurance policies. In the lawsuit, Kellogg,
Brown & Root seeks to establish the specific terms under which it can seek
72
reimbursement for costs it incurs in settling and defending asbestos claims from
its historic construction operations. On January 6, 2003, this lawsuit was
transferred to the 11th Judicial District of the District Court of Harris
County, Texas. Until this lawsuit is resolved, the scope of the excess insurance
will remain uncertain. We do not expect the excess insurers will reimburse us
for asbestos claims until this lawsuit is resolved.
Significant asbestos judgments on appeal. During 2001, there were
several adverse judgments in trial court proceedings that are in various stages
of the appeal process. All of these judgments concern asbestos claims involving
Harbison-Walker refractory products. Each of these appeals, however, has been
stayed by the Bankruptcy Court in the Harbison-Walker Chapter 11 bankruptcy.
On November 29, 2001, the Texas District Court in Orange, Texas,
entered judgments against Dresser Industries, Inc. (now DII Industries) on a $65
million jury verdict rendered in September 2001 in favor of five plaintiffs. The
$65 million amount includes $15 million of a $30 million judgment against DII
Industries and another defendant. DII Industries is jointly and severally liable
for $15 million in addition to $65 million if the other defendant does not pay
its share of this judgment. Based upon what we believe to be controlling
precedent, which would hold that the judgment entered is void, we believe that
the likelihood of the judgment being affirmed in the face of DII Industries'
appeal is remote. As a result, we have not accrued any amounts for this
judgment. However, a favorable outcome from the appeal is not assured.
On November 29, 2001, the same District Court in Orange, Texas, entered
three additional judgments against Dresser Industries, Inc. (now DII Industries)
in the aggregate amount of $35.7 million in favor of 100 other asbestos
plaintiffs. These judgments relate to an alleged breach of purported settlement
agreements signed early in 2001 by a New Orleans lawyer hired by
Harbison-Walker, which had been defending DII Industries pursuant to the
agreement by which Harbison-Walker was spun-off by DII Industries in 1992. These
settlement agreements expressly bind Harbison-Walker Refractories Company as the
obligated party, not DII Industries, which is not a party to the agreements. For
that reason, and based upon what we believe to be controlling precedent, which
would hold that the judgment entered is void, we believe that the likelihood of
the judgment being affirmed in the face of DII Industries' appeal is remote. As
a result, we have not accrued any amounts for this judgment. However, a
favorable outcome from the appeal is not assured.
On December 5, 2001, a jury in the Circuit Court for Baltimore County,
Maryland, returned verdicts against Dresser Industries, Inc. (now DII
Industries) and other defendants following a trial involving refractory asbestos
claims. Each of the five plaintiffs alleges exposure to Harbison-Walker
products. DII Industries portion of the verdicts was approximately $30 million,
which we have fully accrued at December 31, 2002. DII Industries intends to
appeal the judgment to the Maryland Supreme Court. While we believe we have a
valid basis for appeal and intend to vigorously pursue our appeal, any favorable
outcome from that appeal is not assured.
On October 25, 2001, in the Circuit Court of Holmes County,
Mississippi, a jury verdict of $150 million was rendered in favor of six
plaintiffs against Dresser Industries, Inc. (now DII Industries) and two other
companies. DII Industries share of the verdict was $21.3 million which we have
fully accrued at December 31, 2002. The award was for compensatory damages. The
jury did not award any punitive damages. The trial court has entered judgment on
the verdict. While we believe we have a valid basis for appeal and intend to
vigorously pursue our appeal, any favorable outcome from that appeal is not
assured.
Asbestos claims history. Since 1976, approximately 578,000 asbestos
claims have been filed against us. Almost all of these claims have been made in
separate lawsuits in which we are named as a defendant along with a number of
other defendants, often exceeding 100 unaffiliated defendant companies in total.
During the fourth quarter of 2002, we received approximately 32,000 new claims
and we closed approximately 13,000 claims. The number of open claims pending
against us is as follows:
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Total Open
Period Ending Claims
---------------------------------------------------
December 31, 2002 347,000
September 30, 2002 328,000
June 30, 2002 312,000
March 31, 2002 292,000
December 31, 2001 274,000
September 30, 2001 146,000
June 30, 2001 145,000
March 31, 2001 129,000
December 31, 2000 117,000
===================================================
The claims include approximately 142,000 at December 31, 2002 and
September 30, 2002, 139,000 at June 30, 2002, 133,000 at March 31, 2002 and
125,000 at December 31, 2001 of post spin-off Harbison-Walker refractory related
claims that name DII Industries as a defendant. All such claims have been
factored into the calculation of our asbestos liability.
We manage asbestos claims to achieve settlements of valid claims for
reasonable amounts. When reasonable settlement is not possible, we contest
claims in court. Since 1976, we have closed approximately 231,000 claims through
settlements and court proceedings at a total cost of approximately $202 million.
We have received or expect to receive from our insurers all but approximately
$93 million of this cost, resulting in an average net cost per closed claim of
about $403.
Asbestos study and the valuation of unresolved current and future
asbestos claims.
Asbestos Study. In late 2001, DII Industries retained Dr. Francine F.
Rabinovitz of Hamilton, Rabinovitz & Alschuler, Inc. to estimate the probable
number and value, including defense costs, of unresolved current and future
asbestos and silica-related bodily injury claims asserted against DII Industries
and its subsidiaries. Dr. Rabinovitz is a nationally renowned expert in
conducting such analyses, has been involved in a number of asbestos-related and
other toxic tort-related valuations of current and future liabilities, has
served as the expert for three representatives of future claimants in asbestos
related bankruptcies and has had her valuation methodologies accepted by
numerous courts. Further, the methodology utilized by Dr. Rabinovitz is the same
methodology that is utilized by the expert who is routinely retained by the
asbestos claimants committee in asbestos-related bankruptcies. Dr. Rabinovitz
estimated the probable number and value of unresolved current and future
asbestos and silica-related bodily injury claims asserted against DII Industries
and its subsidiaries over a 50 year period. The report took approximately seven
months to complete.
Methodology. The methodology utilized by Dr. Rabinovitz to project DII
Industries and its subsidiaries' asbestos-related liabilities and defense costs
relied upon and included:
- an analysis of DII Industries, Kellogg, Brown & Root's and
Harbison-Walker Refractories Company's historical asbestos
settlements and defense costs to develop average settlement
values and average defense costs for specific asbestos-related
diseases and for the specific business operation or entity
allegedly responsible for the asbestos-related diseases;
- an analysis of DII Industries, Kellogg, Brown & Root's and
Harbison-Walker Refractories Company's pending inventory of
asbestos-related claims by specific asbestos-related diseases
and by the specific business operation or entity allegedly
responsible for the asbestos-related disease;
- an analysis of the claims filing history for asbestos-related
claims against DII Industries, Kellogg, Brown & Root and
Harbison-Walker Refractories Company for the approximate
two-year period from January 2000 to May 31, 2002, and for the
approximate five-year period from January 1997 to May 31, 2002
by specific asbestos-related disease and by business operation
or entity allegedly responsible for the asbestos-related
disease;
- an analysis of the population likely to have been exposed or
claim exposure to products manufactured by DII Industries, its
predecessors and Harbison-Walker or to Brown & Root
construction and renovation projects; and
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- epidemiological studies to estimate the number of people who
might allege exposure to products manufactured by DII
Industries, its predecessors and Harbison-Walker or to Brown &
Root construction and renovation projects that would be likely
to develop asbestos-related diseases. Dr. Rabinovitz's
estimates are based on historical data supplied by DII
Industries, Kellogg, Brown & Root and Harbison-Walker and
publicly available studies, including annual surveys by the
National Institutes of Health concerning the incidence of
mesothelioma deaths.
In her estimates, Dr. Rabinovitz relied on the source data provided by
our management; she did not independently verify the accuracy of the source
data. The source data provided by us was based on our 24-year history in
gathering claimant information and defending and settling asbestos claims.
In her analysis, Dr. Rabinovitz projected that the elevated and
historically unprecedented rate of claim filings of the last several years
(particularly in 2000 and 2001), especially as expressed by the ratio of
nonmalignant claim filings to malignant claim filings, would continue into the
future for five more years. After that, Dr. Rabinovitz projected that the ratio
of nonmalignant claim filings to malignant claim filings will gradually decrease
for a 10 year period ultimately returning to the historical claiming rate and
claiming ratio. In making her calculation, Dr. Rabinovitz alternatively assumed
a somewhat lower rate of claim filings, based on an average of the last five
years of claims experience, would continue into the future for five more years
and decrease thereafter.
Other important assumptions utilized in Dr. Rabinovitz's estimates,
which we relied upon in making our accrual are:
- there will be no legislative or other systemic changes to the
tort system;
- that we will continue to aggressively defend against asbestos
claims made against us;
- an inflation rate of 3% annually for settlement payments and
an inflation rate of 4% annually for defense costs; and
- we would receive no relief from our asbestos obligation due to
actions taken in the Harbison-Walker bankruptcy.
Range of Liabilities. Based upon her analysis, Dr. Rabinovitz estimated
total, undiscounted asbestos and silica liabilities, including defense costs, of
DII Industries, Kellogg, Brown & Root and some of their current and former
subsidiaries. Through 2052, Dr. Rabinovitz estimated the current and future
total undiscounted liability for personal injury asbestos and silica claims,
including defense costs, would be a range between $2.2 billion and $3.5 billion
as of June 30, 2002 (which includes payments related to the claims currently
pending). The lower end of the range is calculated by using an average of the
last five years of asbestos claims experience and the upper end of the range is
calculated using the more recent two-year elevated rate of asbestos claim
filings in projecting the rate of future claims.
2nd Quarter 2002 Accrual. Based on that estimate, in the second quarter
of 2002, we accrued asbestos and silica claims liability and defense costs for
both known outstanding and future refractory, other DII Industries, and
construction asbestos and silica claims using the low end of the range of Dr.
Rabinovitz's study, or approximately $2.2 billion. In establishing our liability
for asbestos, we included all post spin-off claims against Harbison-Walker that
name DII Industries as a defendant. Our accruals are based on an estimate of
personal injury asbestos claims through 2052 based on the average claims
experience of the last five years. At the end of the second quarter of 2002, we
did not believe that any point in the expert's range was better than any other
point, and accordingly, based our accrual on the low end of the range in
accordance with FIN 14.
Agreement Regarding Proposed Global Settlement. In December 2002, we
announced that we had reached an agreement in principle that could result in a
global settlement of all personal injury asbestos and silica claims against us.
The proposed settlement provides that up to $2.775 billion in cash, 59.5 million
shares of our common stock (with a value of $1.1 billion using the stock price
at December 31, 2002 of $18.71) and notes with a net present value expected to
be less than $100 million would be paid to a trust for the benefit of current
and future asbestos personal injury claimants and current silica personal injury
claimants. Under the proposed agreement, Kellogg, Brown & Root and DII
Industries will retain the rights to the first $2.3 billion of any insurance
proceeds with any proceeds received between $2.3 billion and $3.0 billion going
to the trust. The proposed settlement will be implemented through a pre-packaged
Chapter 11 filing of DII Industries and Kellogg, Brown & Root as well as some
other DII Industries and Kellogg, Brown & Root subsidiaries with U.S.
operations. The funding of the settlement amounts would occur upon receiving
final and non-appealable court confirmation of a plan of reorganization of DII
Industries and Kellogg, Brown & Root and their subsidiaries in the Chapter 11
proceeding.
75
Subsequently, as of March 2003, DII Industries and Kellogg, Brown &
Root have entered into definitive written agreements finalizing the terms of the
agreement in principle. The proposed global settlement also includes silica
claims as a result of current or past exposure. These silica claims are less
than 1% of the personal injury claims included in the proposed global
settlement. We have approximately 2,500 open silica claims.
The agreement contemplated that we would conduct due diligence on the
asbestos claims, and that we and attorneys for the claimants would use
reasonable efforts to execute definitive settlement agreements. While all the
required settlement agreements have not yet been executed, we and attorneys for
some of the asbestos claimants have now reached agreement on what they believe
will be a template for such settlement agreements. These agreements are subject
to a number of conditions, including agreement on a Chapter 11 plan of
reorganization for DII Industries, Kellogg, Brown & Root and some of their
subsidiaries, approval by 75% of current asbestos claimants to the plan of
reorganization, the negotiation of financing acceptable to us, approval by
Halliburton's Board of Directors, and confirmation of the plan of reorganization
by a bankruptcy court. The template settlement agreement also grants the
claimants' attorneys a right to terminate the definitive settlement agreement on
ten days' notice if Halliburton's DII Industries subsidiary does not file a plan
of reorganization under the bankruptcy code on or before April 1, 2003.
We are conducting due diligence on the asbestos claims, which is not
expected to be completed by April 1, 2003. Therefore, we do not expect DII
Industries, Kellogg, Brown & Root and some of their subsidiaries to file a plan
of reorganization prior to April 1. Although there can be no assurances, we do
not believe the claimants' attorneys will terminate the settlement agreements on
April 1, 2003 as long as adequate progress is being made toward a Chapter 11
filing. In March 2003, we agreed with Harbison-Walker and the asbestos creditors
committee in the Harbison-Walker bankruptcy to consensually extend the period of
the stay contained in the Bankruptcy Court's temporary restraining order until
July 21, 2003. The court's temporary restraining order, which was originally
entered on February 14, 2002, stays more than 200,000 pending asbestos claims
against DII Industries. The agreement provides that if the pre-packaged Chapter
11 filing by DII Industries, Kellogg, Brown & Root and their subsidiaries is not
made by July 14, 2003, the Bankruptcy Court will hear motions to lift the stay
on July 21, 2003. The asbestos creditors committee also reserves the right to
monitor progress toward the filing of the Chapter 11 proceeding and seek an
earlier hearing to lift the stay if satisfactory progress toward the Chapter 11
filing is not being made.
Review of Accruals. As a result of the proposed settlement, in the
fourth quarter of 2002, we re-evaluated our accruals for known outstanding and
future asbestos claims. Although we have reached an agreement in principle with
respect to a proposed settlement, we do not believe the settlement is "probable"
under SFAS No. 5 at the current time. Among the prerequisites to reaching a
conclusion of the settlement are:
- agreement on the amounts to be contributed to the trust for
the benefit of silica claimants;
- our review of the more than 347,000 current claims to
establish that the claimed injuries are based on exposure to
products of DII Industries, Kellogg, Brown & Root, their
subsidiaries or former businesses or subsidiaries;
- completion of our medical review of the injuries alleged to
have been sustained by plaintiffs to establish a medical basis
for payment of settlement amounts;
- finalizing the principal amount of the notes to be contributed
to the trust;
- agreement with a proposed representative of future claimants
and attorneys representing current claimants on procedures for
distribution of settlement funds to individuals claiming
personal injury;
- definitive agreement with the attorneys representing current
asbestos claimants and a proposed representative of future
claimants on a plan of reorganization for the Chapter 11
filings of DII Industries, Kellogg, Brown & Root and some of
their subsidiaries; and agreement with the attorneys
representing current asbestos claimants with respect to, and
completion and mailing of, a disclosure statement explaining
the pre-packaged plan of reorganization to the more than
347,000 current claimants;
- arrangement of financing on terms acceptable to us to fund the
cash amounts to be paid in the settlement;
- Halliburton board approval;
76
- obtaining affirmative votes to the plan of reorganization from
at least the required 75% of known present asbestos claimants
and from a requisite number of silica claimants needed to
complete the plan of reorganization; and
- obtaining final and non-appealable bankruptcy court approval
and federal district court confirmation of the plan of
reorganization.
Because we do not believe the settlement is currently probable as
defined by Statement of Financial Standards No. 5, we have continued to
establish our accruals in accordance with the analysis performed by Dr.
Rabinovitz. However, as a result of the settlement and the payment amounts
contemplated thereby, we believed it appropriate to adjust our accrual to use
the upper end of the range of probable and reasonably estimable liabilities for
current and future asbestos liabilities contained in Dr. Rabinovitz's study,
which estimated liabilities through 2052 and assumed the more recent two-year
elevated rate of claim filings in projecting the rate of future claims.
As a result, in the fourth quarter of 2002, we have determined that the
best estimate of the probable loss is the $3.5 billion estimate in Dr.
Rabinovitz's study, and accordingly, we have increased our accrual for probable
and reasonably estimable liabilities for current and future asbestos and silica
claims to $3.4 billion.
Insurance. In 2002, we retained Peterson Consulting, a
nationally-recognized consultant in asbestos liability and insurance, to work
with us to project the amount of insurance recoveries probable in light of the
projected current and future liabilities accrued by us. Using Dr. Rabinovitz's
projection of liabilities through 2052 using the two-year elevated rate of
asbestos claim filings, Peterson Consulting assisted us in conducting an
analysis to determine the amount of insurance that we estimate is probable that
we will recover in relation to the projected claims and defense costs. In
conducting this analysis, Peterson Consulting:
- reviewed DII Industries historical course of dealings with its
insurance companies concerning the payment of asbestos-related
claims, including DII Industries 15 year litigation and
settlement history;
- reviewed our insurance coverage policy database containing
information on key policy terms as provided by outside
counsel;
- reviewed the terms of DII Industries prior and current
coverage-in-place settlement agreements;
- reviewed the status of DII Industries and Kellogg, Brown &
Root's current insurance-related lawsuits and the various
legal positions of the parties in those lawsuits in relation
to the developed and developing case law and the historic
positions taken by insurers in the earlier filed and settled
lawsuits;
- engaged in discussions with our counsel; and
- analyzed publicly-available information concerning the ability
of the DII Industries insurers to meet their obligations.
Based on that review, analyses and discussions, Peterson Consulting
assisted us in making judgments concerning insurance coverage that we believe
are reasonable and consistent with our historical course of dealings with our
insurers and the relevant case law to determine the probable insurance
recoveries for asbestos liabilities. This analysis factored in the probable
effects of self-insurance features, such as self-insured retentions, policy
exclusions, liability caps and the financial status of applicable insurers, and
various judicial determinations relevant to the applicable insurance programs.
The analysis of Peterson Consulting is based on its best judgment and
information provided by us.
Probable Insurance Recoveries. Based on this analysis of the probable
insurance recoveries, in the second quarter of 2002, we recorded a receivable of
$1.6 billion for probable insurance recoveries.
In connection with our adjustment of our accrual for asbestos liability
and defense costs in the fourth quarter of 2002, Peterson Consulting assisted us
in re-evaluating our receivable for insurance recoveries deemed probable through
2052, assuming $3.5 billion of liabilities for current and future asbestos
claims using the same factors cited above through that date. Based on Peterson
Consulting analysis of the probable insurance recoveries, we increased our
insurance receivable to $2.1 billion as of the fourth quarter of 2002. The
insurance receivable recorded by us does not assume any recovery from insolvent
carriers and assumes that those carriers which are currently solvent will
continue to be solvent throughout the period of the applicable recoveries in the
projections. However, there can be no assurance that these assumptions will be
correct. These insurance receivables do not exhaust the applicable insurance
coverage for asbestos-related liabilities.
77
Current Accruals. The current accrual of $3.4 billion for probable and
reasonably estimable liabilities for current and future asbestos and silica
claims and the $2.1 billion in insurance receivables are included in noncurrent
assets and liabilities due to the extended time periods involved to settle
claims. In the second quarter of 2002, we recorded a pretax charge of $483
million, and, in the fourth quarter of 2002, we recorded a pretax charge of $799
million ($675 million after-tax).
In the fourth quarter of 2002, we recorded pretax charges of $232
million ($212 million after-tax) for claims related to Brown & Root construction
and renovation projects under the Engineering and Construction Group segments.
The balance of $567 million ($463 million after-tax) related to claims
associated with businesses no longer owned by us and was recorded as
discontinued operations. The low effective tax rate on the asbestos charge is
due to the recording of a valuation allowance against the United States Federal
deferred tax asset associated with the accrual as the deferred tax asset may not
be fully realizable based upon future taxable income projections.
The total estimated claims through 2052, including the 347,000 current
open claims, are approximately one million. A summary of our accrual for all
claims and corresponding insurance recoveries is as follows:
December 31
----------------------------------------
Millions of dollars 2002 2001
----------------------------------------------------------------------------------------------------
Gross liability - beginning balance $ 737 $ 80
Accrued liability 2,820 696
Payments on claims (132) (39)
----------------------------------------------------------------------------------------------------
Gross liability - ending balance $ 3,425 $ 737
====================================================================================================
Estimated insurance recoveries:
Highlands Insurance Company - beginning balance $ (45) $ (39)
Accrued insurance recoveries - (18)
Write-off of recoveries 45 -
Insurance billings - 12
----------------------------------------------------------------------------------------------------
Highlands Insurance Company - ending balance - $ (45)
====================================================================================================
Other insurance carriers - beginning balance $ (567) $ (12)
Accrued insurance recoveries (1,530) (563)
Insurance billings 38 8
----------------------------------------------------------- ------------------- --------------------
Other insurance carriers - ending balance $(2,059) $ (567)
====================================================================================================
Total estimated insurance recoveries $(2,059) $ (612)
====================================================================================================
Net liability for known asbestos claims $ 1,366 $ 125
====================================================================================================
Accounts receivable for billings to insurance companies for payments
made on asbestos claims were $44 million at December 31, 2002, and $18 million
at December 31, 200l, excluding $35 million in accounts receivable written off
at the conclusion of the Highlands litigation.
Possible Additional Accruals. When and if the currently proposed global
settlement becomes probable under SFAS No. 5, we would increase our accrual for
probable and reasonably estimable liabilities for current and future asbestos
claims up to $4.0 billion, reflecting the amount in cash and notes we would pay
to fund the settlement combined with the value of 59.5 million shares of
Halliburton common stock using $18.71, which was trading value of the stock at
the end of the fourth quarter of 2002. In addition, at such time as the
settlement becomes probable, we would adjust our accrual for liabilities for
current and future asbestos claims and we would expect to increase the amount of
our insurance receivables to $2.3 billion. As a result, we would record at such
time an additional pretax charge of $322 million ($288 million after-tax).
Beginning in the first quarter in which the settlement becomes probable, the
accrual would then be adjusted from period to period based on positive and
negative changes in the market price of our common stock until the payment of
the shares into the trust.
Continuing Review. Projecting future events is subject to many
uncertainties that could cause the asbestos-related liabilities and insurance
recoveries to be higher or lower than those projected and booked such as:
- the number of future asbestos-related lawsuits to be filed
against DII Industries and Kellogg, Brown & Root;
- the average cost to resolve such future lawsuits;
78
- coverage issues among layers of insurers issuing different
policies to different policyholders over extended periods of
time;
- the impact on the amount of insurance recoverable in light of
the Harbison-Walker and Federal-Mogul bankruptcies; and
- the continuing solvency of various insurance companies.
Given the inherent uncertainty in making future projections, we plan to
have the projections of current and future asbestos and silica claims
periodically reexamined, and we will update them if needed based on our
experience and other relevant factors such as changes in the tort system, the
resolution of the bankruptcies of various asbestos defendants and the
probability of our settlement of all claims becoming effective. Similarly, we
will re-evaluate our projections concerning our probable insurance recoveries in
light of any updates to Dr. Rabinovitz's projections, developments in DII
Industries and Kellogg, Brown & Root's various lawsuits against its insurance
companies and other developments that may impact the probable insurance.
Barracuda-Caratinga Project. In June 2000, KBR entered into a contract
with the project owner, Barracuda & Caratinga Leasing Company B.V., to develop
the Barracuda and Caratinga crude oil fields, which are located off the coast of
Brazil. The project manager and owner representative is Petrobras, the Brazilian
national oil company. When completed, the project will consist of two converted
supertankers which will be used as floating production, storage and offloading
platforms, or FPSO's, 33 hydrocarbon production wells, 18 water injection wells,
and all sub-sea flow lines and risers necessary to connect the underwater wells
to the FPSO's.
KBR's performance under the contract is secured by:
- two performance letters of credit, which together have an
available credit of approximately $261 million and which
represent approximately 10% of the contract amount, as amended
to date by change orders;
- a retainage letter of credit in an amount equal to $121
million as of December 31, 2002 and which will increase in
order to continue to represent 10% of the cumulative cash
amounts paid to KBR; and
- a guarantee of KBR's performance of the agreement by
Halliburton Company in favor of the project owner.
The project owner has procured project finance funding obligations from
various banks to finance the payments due to KBR under the contract.
As of December 31, 2002, the project was approximately 63% complete and
KBR had recorded a loss of $117 million related to the project. The probable
unapproved claims included in determining the loss on the project were $182
million as of December 31, 2002. The claims for the project most likely will not
be settled within one year. Accordingly, probable unapproved claims of $115
million at December 31, 2002 have been recorded to long-term unbilled work on
uncompleted contracts. Those amounts are included in "Other assets" on the
balance sheet. KBR has asserted claims for compensation substantially in excess
of $182 million. The project owner, through its project manager, Petrobras, has
denied responsibility for all such claims. Petrobras has, however, agreed in
principle to the scope, but not yet the amount, of issues valued by KBR of
approximately $29 million which are not related to the $182 million in probable
unapproved claims. Additionally we are in discussion with Petrobras about
responsibility for $78 million of new tax costs that were not foreseen in the
contract price.
KBR expects the project will likely be completed more than 12 months
later than the original contract completion date. KBR believes that the
project's delay is due primarily to the actions of Petrobras. In the event that
any portion of the delay is determined to be attributable to KBR and any phase
of the project is completed after the milestone dates specified in the contract,
KBR could be required to pay liquidated damages. These damages would be
calculated on an escalating basis of up to $1 million per day of delay caused by
KBR subject to a total cap on liquidated damages of 10% of the final contract
amount (yielding a cap of approximately $263 million as of December 31, 2002).
We are in discussions with Petrobras regarding a settlement of the amount of
unapproved claims. There can be no assurance that we will reach any settlement
regarding these claims. We expect any settlement, if reached, will result in a
schedule extension that would eliminate liability for liquidated damages based
on the currently forecasted schedule. We have not accrued any amounts for
liquidated damages, since we consider the imposition of liquidated damages to be
unlikely.
79
The project owner currently has no other committed source of funding on
which we can necessarily rely other than the project finance funding for the
project. If the banks cease to fund the project, the project owner may not have
the ability to continue to pay KBR for its services. The original bank documents
provide that the banks are not obligated to continue to fund the project if the
project has been delayed for more than 6 months. In November 2002, the banks
agreed to extend the 6-month period to 12 months. Other provisions in the bank
documents may provide for additional time extensions. However, delays beyond 12
months may require bank consent in order to obtain additional funding. While we
believe the banks have an incentive to complete the financing of the project,
there is no assurance that they would do so. If the banks did not consent to
extensions of time or otherwise ceased funding the project, we believe that
Petrobras would provide for or secure other funding to complete the project,
although there is no assurance that it would do so. To date, the banks have made
funds available, and the project owner has continued to disburse funds to KBR as
payment for its work on the project even though the project completion has been
delayed. In the event that KBR is alleged to be in default under the contract,
the project owner may assert a right to draw upon the letters of credit. If the
letters of credit were drawn, KBR would be required to fund the amount of the
draw to the issuing bank. In the event that KBR was determined after an
arbitration proceeding to have been in default under the contract, and if the
project was not completed by KBR as a result of such default (i.e., KBR's
services are terminated as a result of such default), the project owner may seek
direct damages (including completion costs in excess of the contract price and
interest on borrowed funds, but excluding consequential damages) against KBR for
up to $500 million plus the return of up to $300 million in advance payments
that would otherwise have been credited back to the project owner had the
contract not been terminated.
In addition, although the project financing includes borrowing capacity
in excess of the original contract amount, only $250 million of this additional
borrowing capacity is reserved for increases in the contract amount payable to
KBR and its subcontractors other than Petrobras. Because our claims, together
with change orders that are currently under negotiation, exceed this amount, we
cannot give assurance that there is adequate funding to cover current or future
KBR claims. Unless the project owner provides additional funding or permits us
to defer repayment of the $300 million advance, and assuming the project owner
does not allege default on our part, we may be obligated to fund operating cash
flow shortages over the remaining project life in an amount we currently
estimate to be up to approximately $400 million.
The possible Chapter 11 pre-packaged bankruptcy filing by KBR in
connection with the settlement of its asbestos claims would constitute an event
of default under the loan documents with the banks unless waivers are obtained.
KBR believes that it is unlikely that the banks will exercise any right to cease
funding given the current status of the project and the fact that a failure to
pay KBR may allow KBR to cease work on the project without Petrobras having a
readily available substitute contractor.
KBR and Petrobras are currently attempting to resolve any disputes
through ongoing negotiations between the parties and each has appointed a
high-level team for this purpose.
Securities and Exchange Commission ("SEC") Investigation and Fortune
500 Review. In late May 2002, we received a letter from the Fort Worth District
Office of the Securities and Exchange Commission stating that it was initiating
a preliminary inquiry into some of our accounting practices. In mid-December
2002, we were notified by the SEC that a formal order of investigation had been
issued. Since that time, the SEC has issued subpoenas calling for the production
of documents and requiring the appearance of a number of witnesses to testify
regarding those accounting practices, which relate to the recording of revenues
associated with cost overruns and unapproved claims on long-term engineering and
construction projects. Throughout the informal inquiry and during the pendency
of the formal investigation, we have provided approximately 300,000 documents to
the SEC. The production of documents is essentially complete and the process of
providing witnesses to testify is ongoing. To our knowledge, the SEC's
investigation has focused on the compliance with generally accepted accounting
principles of our recording of revenues associated with cost overruns and
unapproved claims for long-term engineering and construction projects, and the
disclosure of our accrual practice. Accrual of revenue from unapproved claims is
an accepted and widely followed accounting practice for companies in the
engineering and construction business. Although we accrued revenue related to
unapproved claims in 1998, we first made disclosures regarding the accruals in
our 1999 Annual Report on Form 10-K. We believe we properly applied the required
methodology of the American Institute of Certified Public Accountants' Statement
of Position 81-1, "Accounting for Performance of Construction-Type and Certain
Production-Type Contracts," and satisfied the relevant criteria for accruing
this revenue, although the SEC may conclude otherwise.
80
On December 21, 2001, the SEC's Division of Corporation Finance
announced that it would review the annual reports of all Fortune 500 companies
that file periodic reports with the SEC. We received the SEC's initial comments
in letter form dated September 20, 2002 and responded on October 31, 2002. Since
then, we have received and responded to three follow-up sets of comments, most
recently in March 2003.
Securities and related litigation. On June 3, 2002, a class action
lawsuit was filed against us in the United States District Court for the
Northern District of Texas on behalf of purchasers of our common stock alleging
violations of the federal securities laws. After that date, approximately twenty
similar class actions were filed against us in that or other federal district
courts. Several of those lawsuits also named as defendants Arthur Andersen, LLP
("Arthur Andersen"), our independent accountants for the period covered by the
lawsuit, and several of our present or former officers and directors. Those
lawsuits allege that we violated federal securities laws in failing to disclose
a change in the manner in which we accounted for revenues associated with
unapproved claims on long-term engineering and construction contracts, and that
we overstated revenue by accruing the unapproved claims. One such action was
subsequently dismissed voluntarily, without prejudice, upon motion by the filing
plaintiff. The federal securities fraud class actions have all been transferred
to the U.S. District Court for the Northern District of Texas and consolidated
before the Honorable Judge David Godbey. The amended consolidated class action
complaint in that case, styled Richard Moore v. Halliburton, was scheduled to be
filed in February 2003, but that date has been extended by agreement of the
parties. It is unclear as of this time when the amended consolidated class
action complaint will be filed. However, we believe that we have meritorious
defenses to the claims and intend to vigorously defend against them.
Another case, also filed in the United States District Court for the
Northern District of Texas on behalf of three individuals, and based upon the
same revenue recognition practices and accounting treatment that is the subject
of the securities class actions, alleges only common law and statutory fraud in
violation of Texas state law. We moved to dismiss that action on October 24,
2002, as required by the court's scheduling order, on the bases of lack of
federal subject matter jurisdiction and failure to plead with that degree of
particularity required by the rules of procedure. That motion has now been fully
briefed and is before the court awaiting ruling.
In addition to the securities class actions, one additional class
action, alleging violations of ERISA in connection with the Company's Benefits
Committee's purchase of our stock for the accounts of participants in our 401
(k) retirement plan during the period we allegedly knew or should have known
that our revenue was overstated as a result of the accrual of revenue in
connection with unapproved claims, was filed and subsequently voluntarily
dismissed.
Finally, on October 11, 2002, a shareholder derivative action against
present and former directors and our former CFO was filed alleging breach of
fiduciary duty and corporate waste arising out of the same events and
circumstances upon which the securities class actions are based. We have moved
to dismiss that action and a hearing on that motion is presently scheduled to
take place in March 2003. We believe the action is without merit and we intend
to vigorously defend it.
BJ Services Company patent litigation. On April 12, 2002, a federal
court jury in Houston, Texas, returned a verdict against Halliburton Energy
Services, Inc. in a patent infringement lawsuit brought by BJ Services Company,
or BJ. The lawsuit alleged that our Phoenix fracturing fluid infringed a patent
issued to BJ in January 2000 for a method of well fracturing using a specific
fracturing fluid. The jury awarded BJ approximately $98 million in damages, plus
pre-judgment interest, which was less than one-quarter of BJ's claim at the
beginning of the trial. A total of $102 million was accrued in the first
quarter, which was comprised of the $98 million judgment and $4 million in
pre-judgment interest costs. The jury also found that there was no intentional
infringement by Halliburton Energy Services, Inc.. As a result of the jury's
determination of infringement, the court has enjoined us from further use of our
Phoenix fracturing fluid. We have posted a supersedeas bond in the amount of
approximately $107 million to cover the damage award, pre-judgment and
post-judgment interest, and awardable costs. We timely appealed the judgment and
the appeal has now been fully briefed and we are awaiting notice of a date of
hearing before the United States Court of Appeals for the Federal Circuit, which
hears all appeals of patent cases. While we believe we have a valid basis for
appeal and intend to vigorously pursue our appeal, any favorable outcome from
that appeal is not assured. We have alternative products to use in our
fracturing operations, and do not expect the loss of the use of the Phoenix
fracturing fluid to have a material adverse impact on our overall energy
services business.
81
Anglo-Dutch (Tenge). We have been sued in the District Court of Harris
County, Texas by Anglo-Dutch (Tenge) L.L.C. and Anglo-Dutch Petroleum
International, Inc. for allegedly breaching a confidentiality agreement related
to an investment opportunity we considered in the late 1990s in an oil field in
the former Soviet republic of Kazakhstan. While we believe the claims raised in
that lawsuit are without merit and are vigorously defending against them, the
plaintiffs have announced their intention to seek approximately $680 million in
damages. We have moved for summary judgment and a hearing on that motion was
held on March 12, 2003. The court's ruling on this motion is still pending.
Trial is set for April 21, 2003.
Improper payments reported to the Securities and Exchange Commission.
We have reported to the SEC that one of our foreign subsidiaries operating in
Nigeria made improper payments of approximately $2.4 million to an entity owned
by a Nigerian national who held himself out as a tax consultant when in fact he
was an employee of a local tax authority. The payments were made to obtain
favorable tax treatment and clearly violated our Code of Business Conduct and
our internal control procedures. The payments were discovered during an audit of
the foreign subsidiary. We have conducted an investigation assisted by outside
legal counsel. Based on the findings of the investigation we have terminated
several employees. None of our senior officers were involved. We are cooperating
with the SEC in its review of the matter. We plan to take further action to
ensure that our foreign subsidiary pays all taxes owed in Nigeria, which may be
as much as an additional $3 million, which amount was fully accrued as of March
31, 2002. The integrity of our Code of Business Conduct and our internal control
procedures are essential to the way we conduct business.
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 the Comprehensive Environmental
Response, Compensation and Liability Act, the Resources Conservation and
Recovery Act, the Clean Air Act, the Federal Water Pollution Control Act and the
Toxic Substances Control Act, among others. In addition to the federal laws and
regulations, states where we do business may have equivalent laws and
regulations by which we must also 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.
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
$48 million as of December 31, 2002 and $49 million as of December 31, 2001. The
liability covers numerous properties and no individual property accounts for
more than 10% of the current liability balance. In some instances, we have been
named a potentially responsible party by a regulatory agency, but in each of
those cases, we do not believe we have any material liability. We have
subsidiaries that have been named as potentially responsible parties along with
other third parties for ten federal and state superfund sites for which we have
established liabilities. As of December 31, 2002, those ten sites accounted for
$8 million of our total $48 million liability.
Letters of credit. In the normal course of business, we have agreements
with banks under which approximately $1.4 billion of letters of credit or bank
guarantees were issued, including $204 million which relate to our joint
ventures' operations. Effective October 9, 2002, we amended an agreement with
banks under which $261 million of letters of credit have been issued. The
amended agreement removes the provision that previously allowed the banks to
require collateralization if ratings of Halliburton debt fell below investment
grade ratings. The revised agreements include provisions that require us to
maintain ratios of debt to total capital and of total earnings before interest,
taxes, depreciation and amortization to interest expense. The definition of debt
includes our asbestos liability. The definition of total earnings before
interest, taxes, depreciation and amortization excludes any non-cash charges
related to the proposed global asbestos settlement through December 31, 2003.
If our debt ratings fall below investment grade, we would be in
technical breach of a bank agreement covering another $160 million of letters of
credit at December 31, 2002, which might entitle the bank to set-off rights. In
addition, a $151 million letter of credit line, of which $121 million has been
issued, includes provisions that allow the bank to require cash
collateralization for the full line if debt ratings of either rating agency fall
below the rating of BBB by Standard & Poor's or Baa2 by Moody's Investors'
Services. These letters of credit and bank guarantees generally relate to our
guaranteed performance or retention payments under our long-term contracts and
self-insurance.
82
In the past, no significant claims have been made against letters of
credit we have issued. We do not anticipate material losses to occur as a result
of these financial instruments.
Liquidated damages. Many of our engineering and construction contracts
have milestone due dates that must be met or we may be subject to penalties for
liquidated damages if claims are asserted and we were responsible for the
delays. These generally relate to specified activities within a project by a set
contractual date or achievement of a specified level of output or throughput of
a plant we construct. Each contract defines the conditions under which a
customer may make a claim for liquidated damages. In most instances, liquidated
damages are never asserted by the customer but the potential to do so is used in
negotiating claims and closing out the contract. We had not accrued a liability
for $364 million at December 31, 2002 and $97 million at December 31, 2001 of
possible liquidated damages as we consider the imposition of liquidated damages
to be unlikely. We believe we have valid claims for schedule extensions against
the customers which would eliminate any liability for liquidated damages. Of the
total liquidated damages, $263 million at December 31, 2002 and $77 million at
December 31, 2001 relate to unasserted liquidated damages for the
Barracuda-Caratinga project. The estimated schedule impact of change orders
requested by the customer is expected to cover approximately one-half of the
$263 million exposure at December 31, 2002 and claims for schedule extension are
expected to cover the remaining exposure.
Other. We are a party to various other legal proceedings. We expense
the cost of legal fees related to these proceedings as incurred. We believe any
liabilities we may have arising from these proceedings will not be material to
our consolidated financial position or results of operations.
Note 13. Income (Loss) Per Share
Millions of dollars and shares except per share data 2002 2001 2000
----------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations before
change in accounting method, net $ (346) $ 551 $ 188
==========================================================================================================
Basic weighted average shares 432 428 442
Effect of common stock equivalents - 2 4
----------------------------------------------------------------------------------------------------------
Diluted weighted average shares 432 430 446
==========================================================================================================
Income (loss) per common share from continuing operations before change in
accounting method, net:
Basic $ (0.80) $ 1.29 $ 0.42
==========================================================================================================
Diluted $ (0.80) $ 1.28 $ 0.42
==========================================================================================================
Basic income (loss) per share is based on the weighted average number
of common shares outstanding during the period. Diluted income (loss) per share
includes additional common shares that would have been outstanding if potential
common shares with a dilutive effect had been issued. For 2002, we have used the
basic weighted average shares in the calculation as the effect of the common
stock equivalents would be antidilutive based upon the net loss from continuing
operations. Included in the computation of diluted income per share in 2001 and
2000 are rights we issued in connection with the PES acquisition for between
850,000 and 2.1 million shares of Halliburton common stock. Excluded from the
computation of diluted income per share are options to purchase 10 million
shares of common stock in 2001 and 1 million shares in 2000. These options were
outstanding during these years, but were excluded because the option exercise
price was greater than the average market price of the common shares.
Note 14. Reorganization of Business Operations
On March 18, 2002 we announced plans to restructure our businesses into
two operating subsidiary groups, the Energy Services Group and the Engineering
and Construction Group. As part of this reorganization, we separated and
consolidated the entities in our Energy Services Group together as direct and
indirect subsidiaries of Halliburton Energy Services, Inc. We also separated and
consolidated the entities in our Engineering and Construction Group together as
direct and indirect subsidiaries of the former Dresser Industries, Inc., which
83
became a limited liability company during the second quarter of 2002 and was
renamed DII Industries. The reorganization of subsidiaries facilitated the
separation, organizationally and financially of our business groups, which we
believe will significantly improve operating efficiencies in both, while
streamlining management and easing manpower requirements. In addition, many
support functions, which were previously shared, were moved into the two
business groups. As a result, we took actions during 2002 to reduce our cost
structure by reducing personnel, moving previously shared support functions into
the two business groups and realigning ownership of international subsidiaries
by group.
In 2002, we incurred costs related to the restructuring of
approximately $107 million which consisted of the following:
- $64 million in personnel related expense;
- $17 million of asset related write-downs;
- $20 million in professional fees related to the
restructuring; and
- $6 million related to contract terminations.
Of this amount, $8 million remains in accruals for severance
arrangements and approximately $2 million for other items. We expect these
remaining payments will be made during 2003.
Although we have no specific plans currently, the reorganization would
facilitate separation of the ownership of the two business groups in the future
if we identify an opportunity that produces greater value for our shareholders
than continuing to own both business groups.
In the fourth quarter of 2000 we approved a plan to reorganize our
engineering and construction businesses into one business unit. This
restructuring was undertaken because our engineering and construction businesses
continued to experience delays in customer commitments for new upstream and
downstream projects. With the exception of deepwater projects, short-term
prospects for increased engineering and construction activities in either the
upstream or downstream businesses were not positive. As a result of the
reorganization of the engineering and construction businesses, we took actions
to rationalize our operating structure including write-offs of equipment and
licenses of $10 million, engineering reference designs of $4 million,
capitalized software of $6 million, and recorded severance costs of $16 million.
Of these charges, $30 million was reflected under the captions Cost of services
and $6 million as General and administrative in our 2000 consolidated statements
of income. Severance and related costs of $16 million were for the reduction of
approximately 30 senior management positions. In January 2002, the last of the
personnel actions was completed and we have no remaining accruals related to the
2000 restructuring.
Note 15. Change in Accounting Method
In July 2001, the Financial Accounting Standards Board issued SFAS No.
142, "Goodwill and Other Intangible Assets." Effective January 1, 2002, goodwill
is no longer amortized but is tested for impairment as set forth in the
statement. We now perform our goodwill impairment test for each of our reporting
units in accordance with SFAS No. 142 and those tests indicate that none of the
goodwill we currently have recorded is impaired. Amortization of goodwill for
2001 totaled $42 million pretax and $38 million after-tax.
In July 2001, the Financial Accounting Standards Board issued SFAS No.
141, "Business Combinations" which requires the purchase method of accounting
for business combination transactions initiated after June 30, 2001. The
statement requires that goodwill recorded on acquisitions completed prior to
July 1, 2001 be amortized through December 31, 2001. Goodwill amortization is
precluded on acquisitions completed after June 30, 2001. We ceased amortization
of goodwill on December 31, 2001.
84
Note 16. Income Taxes
The components of the (provision) benefit for income taxes are:
Years ended December 31
-------------------------------------------
Millions of dollars 2002 2001 2000
-----------------------------------------------------------------------------------------
Current income taxes:
Federal $ 71 $ (146) $ (16)
Foreign (173) (157) (114)
State 4 (20) (5)
-----------------------------------------------------------------------------------------
Total (98) (323) (135)
-----------------------------------------------------------------------------------------
Deferred income taxes:
Federal (11) (58) (20)
Foreign and state 29 (3) 26
-----------------------------------------------------------------------------------------
Total 18 (61) 6
-----------------------------------------------------------------------------------------
Total continuing operations $ (80) $ (384) $ (129)
-----------------------------------------------------------------------------------------
Discontinued operations:
Current income taxes 21 (15) (60)
Deferred income taxes 133 35 -
Disposal of discontinued operations - (199) (141)
-----------------------------------------------------------------------------------------
Total $ 74 $ (563) $ (330)
=========================================================================================
Included in the current (provision) benefit for income taxes are
foreign tax credits of $89 million in 2002, $106 million in 2001 and $113
million in 2000. The United States and foreign components of income before
income taxes, minority interests, discontinued operations, and change in
accounting method are as follows:
Years ended December 31
---------------------------------------
Millions of dollars 2002 2001 2000
---------------------------------------------------------------
United States $ (537) $ 565 $ 128
Foreign 309 389 207
---------------------------------------------------------------
Total $ (228) $ 954 $ 335
===============================================================
The primary components of our deferred tax assets and liabilities and
the related valuation allowances, including federal deferred tax assets of
discontinued operations are as follows:
85
December 31
--------------------------------
Millions of dollars 2002 2001
----------------------------------------------------------------------------------
Gross deferred tax assets:
Employee compensation and benefits $ 282 $ 214
Capitalized research and experimentation 75 46
Accrued liabilities 102 121
Insurance accruals 78 82
Construction contract accounting methods 114 100
Inventory 46 53
Asbestos and silica related liabilities 1,201 258
Intercompany profit 32 54
Net operating loss carryforwards 81 44
Foreign tax credit carryforward 49 -
AMT credit carryforward 5 -
Intangibles 6 18
Allowance for bad debt 40 36
Other 23 41
----------------------------------------------------------------------------------
Total $2,134 $ 1,067
----------------------------------------------------------------------------------
Gross deferred tax liabilities:
Insurance for asbestos and silica related
liabilities $ 724 $ 214
Depreciation and amortization 188 106
Nonrepatriated foreign earnings 36 36
All other 13 101
----------------------------------------------------------------------------------
Total $ 961 $ 457
----------------------------------------------------------------------------------
Valuation allowances:
Net operating loss carryforwards $ 77 $ 38
Future tax attributes related to asbestos
litigation 233 -
Foreign tax credit limitation 49 -
All other 7 8
----------------------------------------------------------------------------------
Total 366 46
----------------------------------------------------------------------------------
Net deferred income tax asset $ 807 $ 564
==================================================================================
We have $158 million of net operating loss carryforwards that expire
from 2003 through 2011 and net operating loss carryforwards of $71 million with
indefinite expiration dates. The federal alternative minimum tax credits are
available to reduce future U.S. federal income taxes on an indefinite basis.
We have accrued for the potential repatriation of undistributed
earnings of our foreign subsidiaries and consider earnings above the amounts on
which tax has been provided to be permanently reinvested. While these additional
earnings could become subject to additional tax if repatriated, repatriation is
not anticipated. Any additional amount of tax is not practicable to estimate.
We have established a $49 million valuation allowance against the 2002
foreign tax credit carryovers, on the basis that we believe these credits will
not be utilized in the statutory carryover period. We also have recorded a $233
million valuation allowance on the asbestos liabilities based on the anticipated
impact of the future asbestos deductions on our ability to utilize future
foreign tax credits. We anticipate that a portion of the asbestos deductions
will displace future foreign tax credits and those credits will expire
unutilized.
Pension liability adjustment included in Other comprehensive income is
net of a tax benefit of $69 million in 2002, and $15 million in 2001.
Reconciliations between the actual provision for income taxes and that
computed by applying the United States statutory rate to income from continuing
operations before income taxes and minority interest are as follows:
86
Years ended December 31
--------------------------------------
Millions of dollars 2002 2001 2000
---------------------------------------------------------------------------------------------------
(Provision) benefit computed at statutory rate $ 83 $ (334) $ (117)
Reductions (increases) in taxes resulting from:
Rate differentials on foreign earnings (4) (32) (14)
State income taxes, net of federal income tax benefit 2 (13) (3)
Prior years 33 - -
Loss on disposals of equity method investee (28) - -
Non-deductible goodwill - (11) (11)
Valuation allowance (163) - -
Other items, net (3) 6 16
---------------------------------------------------------------------------------------------------
Total continuing operations (80) (384) (129)
Discontinued operations 154 20 (60)
Disposal of discontinued operations - (199) (141)
---------------------------------------------------------------------------------------------------
Total $ 74 $ (563) $ (330)
===================================================================================================
We have recognized a $114 million valuation allowance in continuing
operations and $119 million in discontinued operations associated with the
asbestos charges net of insurance recoveries. In addition, continuing operations
has recorded a valuation allowance of $49 million related to potential excess
foreign tax credit carryovers. Further, our impairment loss on Bredero-Shaw
cannot be fully benefited for tax purposes due to book and tax basis differences
in that investment and the limited benefit generated by a capital loss
carryback. Settlement of unrealized prior period tax exposures had a favorable
impact to the overall tax rate.
Exclusive of the asbestos and silica charges net of insurance
recoveries and the impairment loss on Bredero-Shaw, our 2002 effective tax rate
from continuing operations would be 38.9% for fiscal 2002 compared to 40.3% in
2001.
Note 17. Common Stock
Our 1993 Stock and Long-Term Incentive Plan provides for the grant of
any or all of the following types of awards:
- stock options, including incentive stock options and
non-qualified stock options;
- stock appreciation rights, in tandem with stock options or
freestanding;
- restricted stock;
- performance share awards; and
- stock value equivalent awards.
Under the terms of the 1993 Stock and Long-Term Incentive Plan as amended, 49
million shares of common stock have been reserved for issuance to key employees.
The plan specifies that no more than 16 million shares can be awarded as
restricted stock. At December 31, 2002, 19 million shares were available for
future grants under the 1993 Stock and Long-Term Incentive Plan of which 10
million shares remain available for restricted stock awards.
In connection with the acquisition of Dresser Industries, Inc. in 1998,
we assumed the outstanding stock options under the stock option plans maintained
by Dresser Industries, Inc. Stock option transactions summarized below include
amounts for the 1993 Stock and Long-Term Incentive Plan and stock plans of
Dresser Industries, Inc. and other acquired companies. No further awards are
being made under the stock plans of acquired companies.
The following table represents our stock options granted, exercised and
forfeited during the past three years:
87
Number of Exercise Weighted Average
Shares Price per Exercise Price
Stock Options (in millions) Share per Share
---------------------------------------------------------------------------------------------
Outstanding at December 31, 1999 17.1 $ 3.10 - 61.50 $ 32.03
---------------------------------------------------------------------------------------------
Granted 1.7 34.75 - 54.00 41.61
Exercised (3.6) 3.10 - 45.63 25.89
Forfeited (0.5) 12.20 - 54.50 37.13
---------------------------------------------------------------------------------------------
Outstanding at December 31, 2000 14.7 $ 8.28 - 61.50 $ 34.54
---------------------------------------------------------------------------------------------
Granted 3.6 12.93 - 45.35 35.56
Exercised (0.7) 8.93 - 40.81 25.34
Forfeited (0.5) 12.32 - 54.50 36.83
---------------------------------------------------------------------------------------------
Outstanding at December 31, 2001 17.1 $ 8.28 - 61.50 $ 35.10
---------------------------------------------------------------------------------------------
Granted 2.6 9.10 - 19.75 12.57
Exercised - * 8.93 - 17.21 11.39
Forfeited (1.2) 8.28 - 54.50 31.94
---------------------------------------------------------------------------------------------
Outstanding at December 31, 2002 18.5 $ 9.10 - 61.50 $ 32.10
=============================================================================================
* Actual exercises for 2002 were approximately 30,000 shares.
Options outstanding at December 31, 2002 are composed of the following:
Outstanding Exercisable
---------------------------------------------- --------------------------------
Weighted
Average Weighted Weighted
Number of Remaining Average Number of Average
Range of Shares Contractual Exercise Shares Exercise
Exercise Prices (in millions) Life Price (in millions) Price
------------------------------------------------------------------------------------------------------------
$ 9.10 - 19.27 3.2 7.4 $ 13.41 0.7 $ 16.96
$ 19.28 - 30.14 5.1 4.8 27.50 4.8 27.79
$ 30.15 - 39.54 6.3 6.5 37.30 4.8 38.55
$ 39.55 - 61.50 3.9 6.7 45.28 2.2 48.34
------------------------------------------------------------------------------------------------------------
$ 9.10 - 61.50 18.5 6.2 $ 32.10 12.5 $ 34.98
============================================================================================================
There were 10.7 million options exercisable with a weighted average
exercise price of $34.08 at December 31, 2001, and 8.8 million options
exercisable with a weighted average exercise price of $32.81 at December 31,
2000.
All stock options under the 1993 Stock and Long-Term Incentive Plan,
including options granted to employees of Dresser Industries, Inc. since its
acquisition, are granted at the fair market value of the common stock at the
grant date.
Stock options generally expire 10 years from the grant date. Stock
options under the 1993 Stock and Long-Term Incentive Plan vest ratably over a
three or four year period. Other plans have vesting periods ranging from three
to 10 years. Options under the Non-Employee Directors' Plan vest after six
months. Restricted shares awarded under the 1993 Stock and Long-Term Incentive
Plan were 1,706,643 in 2002, 1,484,034 in 2001, and 695,692 in 2000. The shares
awarded are net of forfeitures of 46,894 in 2002, 170,050 in 2001, and 69,402 in
2000. The weighted average fair market value per share at the date of grant of
shares granted was $14.95 in 2002, $30.90 in 2001, and $42.25 in 2000.
Our Restricted Stock Plan for Non-Employee Directors allows for each
non-employee director to receive an annual award of 400 restricted shares of
common stock as a part of compensation. We reserved 100,000 shares of common
stock for issuance to non-employee directors. Under this plan we issued 4,400
restricted shares in 2002, 4,800 restricted shares in 2001, and 3,600
88
restricted shares in 2000. At December 31, 2002, 38,000 shares have been issued
to non-employee directors under this plan. The weighted average fair market
value per share at the date of grant of shares granted was $12.56 in 2002,
$34.35 in 2001, and $46.81 in 2000.
Our Employees' Restricted Stock Plan was established for employees who
are not officers, for which 200,000 shares of common stock have been reserved.
At December 31, 2002, 152,650 shares (net of 42,750 shares forfeited) have been
issued. Forfeitures were 400 in 2002, 800 in 2001, and 6,450 in 2000. No further
grants are being made under this plan.
Under the terms of our Career Executive Incentive Stock Plan, 15
million shares of our common stock were reserved for issuance to officers and
key employees at a purchase price not to exceed par value of $2.50 per share. At
December 31, 2002, 11.7 million shares (net of 2.2 million shares forfeited)
have been issued under the plan. No further grants will be made under the Career
Executive Incentive Stock Plan.
Restricted shares issued under the 1993 Stock and Long-Term Incentive
Plan, Restricted Stock Plan for Non-Employee Directors, Employees' Restricted
Stock Plan and the Career Executive Incentive Stock Plan are limited 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 in 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 issuance, is being amortized and charged to income
(with similar credits to paid-in capital in excess of par value) generally over
the average period during which the restrictions lapse. At December 31, 2002,
the unamortized amount is $75 million. We recognized compensation costs of $38
million in 2002, $23 million in 2001, and $18 million in 2000.
During 2002, our Board of Directors approved the 2002 Employee Stock
Purchase Plan (ESPP) and reserved 12 million shares for issuance. 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 6-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. There were approximately 541,000 shares sold through the ESPP
in 2002.
On April 25, 2000, our Board of Directors approved plans to implement a
share repurchase program for up to 44 million shares. No shares were repurchased
in 2002. We repurchased 1.2 million shares at a cost of $25 million in 2001 and
20.4 million shares at a cost of $759 million in 2000.
Note 18. Series A Junior Participating Preferred Stock
We previously declared a dividend of one preferred stock purchase right
on each outstanding share of common stock. The dividend is also applicable to
each share of our common stock that was issued subsequent to adoption of the
Rights Agreement entered into with Mellon Investor Services LLC. Each preferred
stock purchase right entitles its holder to buy one two-hundredth of a share of
our Series A Junior Participating Preferred Stock, without par value, at an
exercise price of $75. These preferred stock purchase rights are subject to
anti-dilution adjustments, which are described in the Rights Agreement entered
into with Mellon. The preferred stock purchase rights do not have any voting
rights and are not entitled to dividends.
The preferred stock purchase rights become exercisable in limited
circumstances involving a potential business combination. After the preferred
stock purchase rights become exercisable, each preferred stock purchase right
will entitle its holder to an amount of our common stock, or in some
circumstances, securities of the acquirer, having a total market value equal to
two times the exercise price of the preferred stock purchase right. The
preferred stock purchase rights are redeemable at our option at any time before
they become exercisable. The preferred stock purchase rights expire on December
15, 2005. No event during 2002 made the preferred stock purchase rights
exercisable.
Note 19. Financial Instruments and Risk Management
In June 1998, the Financial Accounting Standards Board issued SFAS No.
133 "Accounting for Derivative Instruments and for Hedging Activities",
subsequently amended by SFAS No. 137 and SFAS No. 138. This standard requires
entities to recognize all derivatives on the balance sheet as assets or
liabilities and to measure the instruments at fair value. Accounting for gains
89
and losses from changes in those fair values is specified in the standard
depending on the intended use of the derivative and other criteria. We adopted
SFAS No. 133 effective January 2001 and recorded a $1 million after-tax credit
for the cumulative effect of adopting the change in accounting method. We do not
expect future measurements at fair value under the new accounting method to have
a material effect on our financial condition or results of operations.
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 products and services in foreign
currencies will be adversely affected by changes in exchange rates. We do not
hold or issue derivative financial instruments for trading or speculative
purposes.
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 for which we do the majority of our international
business. These contracts 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.
Assets, liabilities and forecasted cash flows denominated in foreign
currencies. We utilize the derivative instruments described above to manage the
foreign currency exposures related to specific assets and liabilities, which are
denominated in foreign currencies; however, we have not elected to account for
these instruments as hedges for accounting purposes. Additionally, we utilize
the derivative instruments described above to manage forecasted cash flows
denominated in foreign currencies generally related to long-term engineering and
construction projects. While we enter into these instruments to manage the
foreign currency risk on these projects, we have chosen not to seek hedge
accounting treatment for these contracts. The fair value of these contracts was
immaterial as of the end of 2002 and 2001.
Notional amounts and fair market values. The notional amounts of open
forward contracts and options for continuing operations were $609 million at
December 31, 2002 and $505 million at December 31, 2001. 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 relating 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.
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 revenues from sales and services, including
engineering and construction, 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 and the
United Kingdom. We maintain an allowance for losses based upon the expected
collectibility of all trade accounts receivable.
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.
90
Interest rate risk. We have several debt instruments outstanding which
have both fixed and variable interest rates. We manage our ratio of fixed to
variable-rate debt through the use of different types of debt instruments and
derivative instruments.
Fair market value of financial instruments. The estimated fair market
value of long-term debt at year-end for both 2002 and 2001 was $1.3 billion as
compared to the carrying amount of $1.5 billion at year-end for both 2002 and
2001. The fair market value of fixed rate long-term debt is based on quoted
market prices for those or similar instruments. The carrying amount of variable
rate long-term debt approximates fair market value because these instruments
reflect market changes to interest rates. See Note 11. The carrying amount of
short-term financial instruments, cash and equivalents, receivables, short-term
notes payable and accounts payable, as reflected in the consolidated balance
sheets approximates fair market value due to the short maturities of these
instruments. The currency derivative instruments are carried on the balance
sheet at fair value and are based upon third-party quotes. The fair market
values of derivative instruments used for fair value hedging and cash flow
hedging were immaterial.
Note 20. Retirement Plans
Our Company and subsidiaries have various plans which cover a
significant number of their employees. These plans include defined contribution
plans, which provide retirement contributions in return for services rendered,
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 both
continuing and discontinued operations totaled $80 million in 2002 compared to
$129 million in 2001 and $140 million in 2000. Other retirement plans include
defined benefit plans, which define an amount of pension benefit to be provided,
usually as a function of age, years of service or compensation. These plans are
funded to operate on an actuarially sound basis. Plan assets are primarily
invested in cash, short-term investments, real estate, equity and fixed income
securities of entities domiciled in the country of the plan's operation. Plan
assets, expenses and obligations for retirement plans in the following tables
include both continuing and discontinued operations.
2002 2001
----------------------------------------------------------------------
Millions of dollars United States International United States International
-------------------------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $ 140 $ 1,968 $ 288 $ 1,670
Service cost 1 72 2 60
Interest cost 9 102 13 89
Plan participants' contributions - 14 - 14
Effect of business combinations and new plans - 70 - -
Amendments 1 (4) - -
Divestitures - (5) (111) (90)
Settlements/curtailments (1) (1) (46) -
Currency fluctuations - 102 - 15
Actuarial gain/(loss) 5 (27) 8 270
Benefits paid (11) (52) (14) (60)
-------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year $ 144 $ 2,239 $ 140 $ 1,968
=========================================================================================================================
91
2002 2001
---------------------------------------------------------------------
Millions of dollars United States International United States International
-------------------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $ 130 $ 1,827 $ 313 $ 2,165
Actual return on plan assets (6) (69) (22) (294)
Employer contribution 1 36 7 30
Settlements (1) - (46) -
Plan participants' contributions - 14 1 14
Effect of business combinations and new plans - 45 - -
Divestitures - (5) (109) (45)
Currency fluctuations - 89 - 15
Benefits paid (11) (51) (14) (58)
-------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 113 $ 1,886 $ 130 $ 1,827
=========================================================================================================================
Funded status $ (31) $ (353) $ (10) $ (141)
Unrecognized transition obligation/(asset) - (2) (1) (3)
Unrecognized actuarial (gain)/loss 56 477 34 308
Unrecognized prior service cost/(benefit) 1 (70) (2) (96)
-------------------------------------------------------------------------------------------------------------------------
Net amount recognized $ 26 $ 52 $ 21 $ 68
=========================================================================================================================
We recognized an additional minimum pension liability for the
underfunded defined benefit plans. The additional minimum liability is equal to
the excess of the accumulated benefit obligation over plan assets and accrued
liabilities. A corresponding amount is recognized as either an intangible asset
or a reduction of shareholders' equity. For the year ended December 31, 2002 we
recognized $212 million in additional minimum pension liability of which $130
million was recorded as Other comprehensive income, net of tax.
2002 2001
---------------------------------------------------------------------
Millions of dollars United States International United States International
----------------------------------------------------------------------------------------------------------------------
Amounts recognized in the consolidated
balance sheets
Prepaid benefit cost $ 30 $ 102 $ 7 $ 85
Accrued benefit liability including
additional minimum liability (59) (250) (10) (36)
Intangible asset 2 12 1 1
Accumulated other comprehensive income,
net of tax 35 122 15 12
Deferred tax asset 18 66 8 6
----------------------------------------------------------------------------------------------------------------------
Net amount recognized $ 26 $ 52 $ 21 $ 68
======================================================================================================================
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 rates used are
as follows:
92
Weighted-average assumptions 2002 2001 2000
-------------------------------------------------------------------------------------
Expected return on plan assets:
United States plans 9.0% 9.0% 9.0%
International plans 5.5% to 8.16% 5.5% to 9.0% 3.5% to 9.0%
Discount rate:
United States plans 7.0% 7.25% 7.5%
International plans 5.25% to 20.0% 5.0% to 8.0% 4.0% to 8.0%
Rate of compensation increase:
United States plans 4.5% 4.5% 4.5%
International plans 3.0% to 21.0% 3.0% to 7.0% 3.0% to 7.6%
=====================================================================================
2002 2001 2000
------------------------------------- ------------------------------------------
United United United
Millions of dollars States International States International States International
----------------------------------------------------------------------------------------------------------------------
Components of net periodic
benefit cost
Service cost $ 1 $ 72 $ 2 $ 60 $ 4 $ 57
Interest cost 9 102 13 89 20 87
Expected return on plan assets (13) (106) (18) (95) (26) (99)
Transition amount - (2) - (2) - -
Amortization of prior service cost (2) (6) (2) (6) (1) (6)
Settlements/curtailments - (2) 16 - 10 -
Recognized actuarial (gain)/loss 1 3 (1) (9) - (10)
----------------------------------------------------------------------------------------------------------------------
Net periodic benefit (income) cost $ (4) $ 61 $ 10 $ 37 $ 7 $ 29
======================================================================================================================
The projected benefit obligation, accumulated benefit obligation, and
fair value of plan assets for the pension plans with accumulated benefit
obligations in excess of plan assets as of December 31, 2002 and 2001 are as
follows:
Millions of dollars 2002 2001
----------------------------------------------------------------
Projected benefit obligation $ 2,319 $ 235
Accumulated benefit obligation $ 2,121 $ 215
Fair value of plan assets $ 1,942 $ 175
================================================================
Postretirement medical plan. We offer postretirement medical plans to
specific eligible employees. For some plans, our liability is limited to a fixed
contribution amount for each participant or dependent. The plan participants
share the total cost for all benefits provided above our fixed contribution and
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 is not
affected by the expected future health care cost inflation rate.
Other postretirement medical plans are contributory but we generally
absorb the majority of the costs. We may elect to adjust the amount of our
contributions for these plans. As a result, the expected future health care cost
inflation rate affects the accumulated postretirement benefit obligation amount.
These plans have assumed health care trend rates (weighted based on the current
year benefit obligation) for 2002 of 13% which are expected to decline to 5% by
2007.
Obligations and expenses for postretirement medical plans in the
following tables include both continuing and discontinued operations.
93
Millions of dollars 2002 2001
------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $ 157 $ 296
Service cost 1 2
Interest cost 11 15
Plan participants' contributions 11 12
Settlements/curtailments - (144)
Actuarial gain 33 5
Benefits paid (27) (29)
------------------------------------------------------------------------------------
Benefit obligation at end of year $ 186 $ 157
====================================================================================
Change in plan assets
Fair value of plan assets at beginning of year $ - $ -
Employer contribution 16 17
Plan participants' contributions 11 12
Benefits paid (27) (29)
------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ - $ -
====================================================================================
Funded status $ (186) $ (157)
Employer contribution 2 2
Unrecognized actuarial gain 20 (14)
Unrecognized prior service cost 2 3
------------------------------------------------------------------------------------
Net amount recognized $ (162) $ (166)
====================================================================================
Millions of dollars 2002 2001
------------------------------------------------------------------------------------
Amounts recognized in the consolidated
balance sheets
Accrued benefit liability $ (162) $ (166)
------------------------------------------------------------------------------------
Net amount recognized $ (162) $ (166)
====================================================================================
Weighted-average assumptions 2002 2001 2000
------------------------------------------------------------------------------------
Discount rate 7.0% 7.25% 7.50%
====================================================================================
Millions of dollars 2002 2001 2000
------------------------------------------------------------------------------------
Components of net periodic benefit cost
Service cost $ 1 $ 2 $ 3
Interest cost 11 15 20
Amortization of prior service cost - (3) (7)
Settlements/curtailments - (221) -
Recognized actuarial gain (1) (1) (1)
------------------------------------------------------------------------------------
Net periodic benefit cost $ 11 $ (208) $ 15
====================================================================================
Assumed health care cost trend rates have a significant effect on the
amounts reported for the total of the health care plans. A one-percentage-point
change in assumed health care cost trend rates would have the following effects:
94
One-Percentage-Point
----------------------------
Millions of dollars Increase (Decrease)
--------------------------------------------------------------------------------------
Effect on total of service and interest cost components $ 1 $ (1)
Effect on the postretirement benefit obligation $ 10 $ (9)
======================================================================================
Note 21. Dresser Industries, Inc. Financial Information
Since becoming a wholly owned subsidiary of Halliburton, DII Industries
(formerly Dresser Industries, Inc.) has ceased filing periodic reports with the
United States Securities and Exchange Commission. DII Industries 8% guaranteed
senior notes, which were initially issued by Baroid Corporation, remain
outstanding and are fully and unconditionally guaranteed by Halliburton. Under
the terms of a Fourth Supplemental Indenture, Halliburton Company in December
2002 assumed as co-obligor the payment of principle and interest on the notes,
and the performance of all of the covenants and conditions of the related
indenture.
Note 22. Goodwill and Other Intangible Assets
We adopted the SFAS No. 142 "Goodwill and Other Intangible Assets", and
in accordance with the statement, amortization of goodwill has been
discontinued. Goodwill for the Energy Services Group was $402 million (net of
$118 million accumulated amortization) in 2002, $386 million (net of $118
million accumulated amortization) in 2001, and $310 million (net of $97 million
accumulated amortization) in 2000. Goodwill for the Engineering and Construction
Group was $321 million (net of $152 million accumulated amortization) in 2002,
$334 million (net of $151 million accumulated amortization) in 2001, and $287
million (net of $134 million accumulated amortization) in 2000.
Had we been accounting for our goodwill under SFAS No. 142 for all
periods presented, our net income (loss) and earnings (loss) per share would
have been as follows:
Years ended December 31
--------------------------------------
Millions of dollars except per share data 2002 2001 2000
------------------------------------------------------------------------------------
Reported net income (loss) $ (998) $ 809 $ 501
Goodwill amortization, net of tax - 38 36
------------------------------------------------------------------------------------
Adjusted net income (loss) $ (998) $ 847 $ 537
====================================================================================
Basic earnings (loss) per share:
Reported net income (loss) $ (2.31) $ 1.89 $ 1.13
Goodwill amortization, net of tax - 0.09 0.08
------------------------------------------------------------------------------------
Adjusted net income (loss) $ (2.31) $ 1.98 $ 1.21
====================================================================================
Diluted earnings (loss) per share:
Reported net income (loss) $ (2.31) $ 1.88 $ 1.12
Goodwill amortization, net of tax - 0.09 0.08
------------------------------------------------------------------------------------
Adjusted net income (loss) $ (2.31) $ 1.97 $ 1.20
====================================================================================
95
Halliburton Company
Selected Financial Data
(Unaudited)
Years ended December 31
Millions of dollars and shares ----------------------------------------------------------------------
except per share and employee data 2002 2001 2000 1999 1998
---------------------------------------------------------------------------------------------------------------------
Total revenues $ 12,572 $ 13,046 $ 11,944 $ 12,313 $ 14,504
=====================================================================================================================
Total operating income (loss) (1) (112) 1,084 462 401 170
Nonoperating income (expense), net (2) (116) (130) (127) (94) (115)
---------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations
before income taxes and minority interest (228) 954 335 307 55
Provision for income taxes (3) (80) (384) (129) (116) (155)
Minority interest in net income of
consolidated
subsidiaries (38) (19) (18) (17) (20)
---------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations $ (346) $ 551 $ 188 $ 174 $ (120)
=====================================================================================================================
Income (loss) from discontinued operations $ (652) $ 257 $ 313 $ 283 $ 105
=====================================================================================================================
Net income (loss) $ (998) $ 809 $ 501 $ 438 $ (15)
=====================================================================================================================
Basic income (loss) per common share
Continuing operations $ (0.80) $ 1.29 $ 0.42 $ 0.40 $ (0.27)
Net income (loss) (2.31) 1.89 1.13 1.00 (0.03)
Diluted income (loss) per common share
Continuing operations (0.80) 1.28 0.42 0.39 (0.27)
Net income (loss) (2.31) 1.88 1.12 0.99 (0.03)
Cash dividends per share 0.50 0.50 0.50 0.50 0.50
Return on average shareholders' equity (24.02)% 18.64% 12.20% 10.49% (0.35)%
---------------------------------------------------------------------------------------------------------------------
Financial position
Net working capital $ 2,288 $ 2,665 $ 1,742 $ 2,329 $ 2,129
Total assets 12,844 10,966 10,192 9,639 10,072
Property, plant and equipment, net 2,629 2,669 2,410 2,390 2,442
Long-term debt (including current maturities) 1,476 1,484 1,057 1,364 1,426
Shareholders' equity 3,558 4,752 3,928 4,287 4,061
Total capitalization 5,083 6,280 6,555 6,590 5,990
Shareholders' equity per share 8.16 10.95 9.20 9.69 9.23
Average common shares outstanding (basic) 432 428 442 440 439
Average common shares outstanding (diluted) 432 430 446 443 439
---------------------------------------------------------------------------------------------------------------------
Other financial data
Capital expenditures $ (764) $ (797) $ (578) $ (520) $ (841)
Long-term borrowings (repayments), net (15) 412 (308) (59) 122
Depreciation, depletion and amortization
expense 505 531 503 511 500
Goodwill amortization included in
depreciation,
depletion and amortization expense:
Energy Services Group - 24 19 12 22
Engineering and Construction Group - 18 25 21 14
Payroll and employee benefits (4) (4,875) (4,818) (5,260) (5,647) (5,880)
Number of employees (4), (5) 83,000 85,000 93,000 103,000 107,800
=====================================================================================================================
(continued on next page)
96
Halliburton Company
Selected Financial Data
(Unaudited)
(continued)
Years ended December 31
Millions of dollars and shares --------------------------------------------------------------------------
except per share and employee data 1997 1996 1995 1994 1993
------------------------------------------------------------------------------------------------------------------------
Total revenues $ 13,498 $ 11,236 $ 9,045 $ 8,540 $ 9,145
========================================================================================================================
Total operating income (loss) (1) 1,178 674 562 402 8
Nonoperating income (expense), net (2) (82) (70) (34) 333 (61)
------------------------------------------------------------------------------------------------------------------------
Income from continuing operations
before income taxes and minority interest 1,096 604 528 735 (53)
Provision for income taxes (3) (406) (158) (167) (275) (18)
Minority interest in net income of
consolidated
subsidiaries (30) - (1) (14) (24)
------------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations $ 660 $ 446 $ 360 $ 446 $ (95)
========================================================================================================================
Income from discontinued operations $ 112 $ 112 $ 36 $ 97 $ 81
========================================================================================================================
Net income (loss) $ 772 $ 558 $ 381 $ 543 $ (14)
========================================================================================================================
Basic income (loss) per common share
Continuing operations $ 1.53 $ 1.04 $ 0.83 $ 1.04 $ (0.23)
Net income (loss) 1.79 1.30 0.88 1.26 (0.04)
Diluted income (loss) per common share
Continuing operations 1.51 1.03 0.83 1.03 (0.23)
Net income (loss) 1.77 1.29 0.88 1.26 (0.04)
Cash dividends per share 0.50 0.50 0.50 0.50 0.50
Return on average shareholders' equity 19.16% 15.25% 10.44% 15.47% (0.43)%
------------------------------------------------------------------------------------------------------------------------
Financial position
Net working capital $ 1,985 $ 1,501 $ 1,477 $ 2,197 $ 1,563
Total assets 9,657 8,689 7,723 7,774 8,087
Property, plant and equipment, net 2,282 2,047 1,865 1,631 1,747
Long-term debt (including current maturities) 1,303 957 667 1,119 1,129
Shareholders' equity 4,317 3,741 3,577 3,723 3,296
Total capitalization 5,647 4,828 4,378 4,905 4,746
Shareholders' equity per share 9.86 8.78 8.29 8.63 7.70
Average common shares outstanding (basic) 431 429 431 431 422
Average common shares outstanding (diluted) 436 432 432 432 422
------------------------------------------------------------------------------------------------------------------------
Other financial data
Capital expenditures $ (804) $ (612) $ (474) $ (358) $ (373)
Long-term borrowings (repayments), net 285 286 (481) (120) 192
Depreciation, depletion and amortization
expense 465 405 380 387 574
Goodwill amortization included in
depreciation, depletion and amortization
expense:
Energy Services Group 20 19 17 14 11
Engineering and Construction Group 12 7 7 7 7
Payroll and employee benefits (4) (5,479) (4,674) (4,188) (4,222) (4,429)
Number of employees (4), (5) 102,000 93,000 89,800 86,500 90,500
========================================================================================================================
(continued on next page)
97
Halliburton Company
Selected Financial Data
(Unaudited)
(continued)
(1) Operating income includes the following special charges and credits:
1999 - $47 million: reversal of a portion of the 1998 special charges.
1998 - $959 million: asset related charges ($491 million), personnel
reductions ($234 million), facility consolidations ($124 million), merger
transaction costs ($64 million), and other related costs ($46 million).
1997 - $11 million: merger costs ($9 million), write-downs on impaired
assets and early retirement incentives ($10 million), losses from the sale
of assets ($12 million), and gain on extension of joint venture ($42
million).
1996 - $86 million: merger costs ($13 million), restructuring, merger and
severance costs ($62 million), and write-off of acquired in-process
research and development costs ($11 million).
1995 - $8 million: restructuring costs ($5 million) and write-off of
acquired in-process research and development costs ($3 million).
1994 - $19 million: merger costs ($27 million), litigation ($10 million),
and litigation and insurance recoveries ($18 million).
1993 - $419 million: loss on sale of business ($322 million), merger costs
($31 million), restructuring ($5 million), litigation ($65 million), and
gain on curtailment of medical plan ($4 million).
(2) Nonoperating income in 1994 includes a gain of $276 million from the sale
of an interest in Western Atlas International, Inc. and a gain of $102
million from the sale of our natural gas compression business.
(3) Provision for income taxes in 1996 includes tax benefits of $44 million due
to the recognition of net operating loss carryforwards and the settlement
of various issues with the Internal Revenue Service.
(4) Includes employees of Dresser Equipment Group which is accounted for as
discontinued operations for the years 1993 through 2000.
(5) Does not include employees of less than 50%-owned affiliated companies.
98
HALLIBURTON COMPANY
Quarterly Data and Market Price Information
(Unaudited)
Quarter
---------------------------------------------------------
Millions of dollars except per share data First Second Third Fourth Year
----------------------------------------------------------------------------------------------------------------------------
2002
Revenues $ 3,007 $ 3,235 $ 2,982 $ 3,348 $12,572
Operating income (loss) 123 (405) 191 (21) (112)
Income (loss) from continuing operations 50 (358) 94 (132) (346)
Loss from discontinued operations (28) (140) - (484) (652)
Net income (loss) 22 (498) 94 (616) (998)
Earnings per share:
Basic income (loss) per common share:
Income (loss) from continuing operations 0.12 (0.83) 0.22 (0.30) (0.80)
Loss from discontinued operations (0.07) (0.32) - (1.12) (1.51)
Net income (loss) 0.05 (1.15) 0.22 (1.42) (2.31)
Diluted income (loss) per common share:
Income (loss) from continuing operations 0.12 (0.83) 0.22 (0.30) (0.80)
Loss from discontinued operations (0.07) (0.32) - (1.12) (1.51)
Net income (loss) 0.05 (1.15) 0.22 (1.42) (2.31)
Cash dividends paid per share 0.125 0.125 0.125 0.125 0.50
Common stock prices (1)
High 18.00 19.63 16.00 21.65 21.65
Low 8.60 14.60 8.97 12.45 8.60
============================================================================================================================
2001
Revenues $ 3,144 $ 3,339 $ 3,391 $ 3,172 $13,046
Operating income 198 272 342 272 1,084
Income from continuing operations before
change in accounting method, net 86 143 181 141 551
Income (loss) from discontinued operations 22 (60) (2) (2) (42)
Gain on disposal of discontinued operations - 299 - - 299
Change in accounting method, net 1 - - - 1
Net income 109 382 179 139 809
============================================================================================================================
(continued on next page)
99
HALLIBURTON COMPANY
Quarterly Data and Market Price Information
(Unaudited)
(continued)
Quarter
------------------------------------------------------
Millions of dollars except per share data First Second Third Fourth Year
-----------------------------------------------------------------------------------------------------------------------------
2001
Earnings per share:
Basic income (loss) per common share:
Income from continuing operations 0.20 0.34 0.42 0.33 1.29
Income (loss) from discontinued operations 0.05 (0.14) - (0.01) (0.10)
Gain on disposal of discontinued operations - 0.70 - - 0.70
Net income 0.25 0.90 0.42 0.32 1.89
Diluted income (loss) per common share:
Income from continuing operations 0.20 0.33 0.42 0.33 1.28
Income (loss) from discontinued operations 0.05 (0.14) - (0.01) (0.10)
Gain on disposal of discontinued operations - 0.70 - - 0.70
Net income 0.25 0.89 0.42 0.32 1.88
Cash dividends paid per share 0.125 0.125 0.125 0.125 0.50
Common stock prices (1)
High 45.91 49.25 36.79 28.90 49.25
Low 34.81 32.20 19.35 10.94 10.94
=============================================================================================================================
(1) New York Stock Exchange - composite transactions high and low intraday
price.
100
PART III
Item 10. Directors and Executive Officers of Registrant.
The information required for the directors of the Registrant is
incorporated by reference to the Halliburton Company Proxy Statement dated March
25, 2003 (File No. 1-3492), under the caption "Election of Directors." The
information required for the executive officers of the Registrant is included
under Part I on pages 9 through 11 of this annual report.
Item 11. Executive Compensation.
This information is incorporated by reference to the Halliburton
Company Proxy Statement dated March 25, 2003 (File No. 1-3492), under the
captions "Compensation Committee Report on Executive Compensation," "Comparison
of Cumulative Total Return," "Summary Compensation Table," "Option Grants For
Fiscal 2002," "Aggregated Option Exercises in Fiscal 2002 and December 31, 2002
Option Values," "Employment Contracts and Change-in-Control Arrangements" and
"Directors' Compensation."
Item 12(a). Security Ownership of Certain Beneficial Owners and Management.
This information is incorporated by reference to the Halliburton
Company Proxy Statement dated March 25, 2003 (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 dated March 25, 2003 (File No. 1-3492), under the
caption "Stock Ownership of Certain Beneficial Owners and Management."
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 dated March 25, 2003 (File No. 1-3492), under the
caption "Equity Compensation Plan Information."
Item 13. Certain Relationships and Related Transactions.
This information is incorporated by reference to the Halliburton
Company Proxy Statement dated March 25, 2003 (File No. 1-3492), under the
caption "Certain Relationships and Related Transactions."
Item 14. Controls and Procedures
Under the supervision and with the participation of our management,
including our principal executive officer and principal financial officer, we
have evaluated the effectiveness of the design and operation of our disclosure
controls and procedures within 90 days of the filing date of this annual report,
and, based on their evaluation, our principal executive officer and principal
financial officer have concluded that these controls and procedures are
effective. There were no significant changes in our internal controls or in
other factors that could significantly affect these controls subsequent to the
date of their evaluation.
Disclosure controls and procedures are our controls and other
procedures that are designed to ensure that information required to be disclosed
by us in the reports that we file or submit 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. Disclosure controls and
procedures include, without limitation, controls and procedures designed to
ensure that information required to be disclosed by us in the reports that we
file under the Exchange Act is accumulated and communicated to our management,
including our principal executive officer and principal financial officer, as
appropriate to allow timely decisions regarding required disclosure.
101
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
(a) 1. Financial Statements:
The reports of Independent Public Accountants and the financial
statements of the Company as required by Part II, Item 8, are
included on pages 47 through 95 and pages 99 and 100 of this annual
report. See index on page 13.
2. Financial Statement Schedules: Page No.
Report on supplemental schedule of KPMG LLP 113
Schedule II - Valuation and qualifying accounts
for the three years ended December 31, 2002 114
Note: All schedules not filed with this report required by
Regulation S-X have been omitted as not applicable or not required
or the information required has been included in the notes to
financial statements.
3. Exhibits:
Exhibit
Number Exhibits
3.1 Restated Certificate of Incorporation of Halliburton
Company filed with the Secretary of State of Delaware on
July 23, 1998 (incorporated by reference to Exhibit 3(a)
to Halliburton's Form 10-Q for the quarter ended June 30,
1998, File No. 1-3492).
3.2 By-laws of Halliburton revised effective February 12,
2003 (incorporated by reference to Exhibit 3.2 to
Halliburton's Form 10-K for the year ended December 31,
2002, File No. 1-3492).
4.1 Form of debt security of 8.75% Debentures due February 12,
2021 (incorporated by reference to Exhibit 4(a) to the
Predecessor's Form 8-K dated as of February 20, 1991, File
No. 1-3492).
4.2 Senior Indenture dated as of January 2, 1991 between the
Predecessor and 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).
102
4.4 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 February 11, 1997, File No. 1-3492).
4.5 Second Senior Indenture dated as of December 1, 1996
between the Predecessor and 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).
4.6 Third Supplemental Indenture dated as of August 1, 1997
between Halliburton and Texas Commerce Bank National
Association, as Trustee, to the Second Senior Indenture
dated as of December 1, 1996 (incorporated by reference to
Exhibit 4.7 to Halliburton's Form 10-K for the year ended
December 31, 1998, File No. 1-3492).
4.7 Fourth Supplemental Indenture dated as of September 29,
1998 between Halliburton and Chase Bank of Texas, National
Association (formerly Texas Commerce Bank National
Association), as Trustee, to the Second Senior Indenture
dated as of December 1, 1996 (incorporated by reference to
Exhibit 4.8 to Halliburton's Form 10-K for the year ended
December 31, 1998, File No. 1-3492).
4.8 Resolutions of Halliburton's Board of Directors adopted by
unanimous consent dated December 5, 1996 (incorporated by
reference to Exhibit 4(g) of Halliburton's Form 10-K for
the year ended December 31, 1996, File No. 1-3492).
4.9 Resolutions of Halliburton's Board of Directors adopted at
a special meeting held on September 28, 1998 (incorporated
by reference to Exhibit 4.10 to Halliburton's Form 10-K
for the year ended December 31, 1998, File No. 1-3492).
4.10 Restated Rights Agreement dated as of December 1, 1996
between Halliburton and Mellon Investor Services LLC
(formerly ChaseMellon Shareholder Services, L.L.C.)
(incorporated by reference to Exhibit 4.4 of Halliburton's
Registration Statement on Form 8-B dated December 12,
1996, File No. 1-3492).
4.11 Copies of instruments that define the rights of holders of
miscellaneous long-term notes of Halliburton and its
subsidiaries, totaling $8 million in the aggregate at
December 31, 2002, have not been filed with the
Commission. Halliburton agrees to furnish copies of these
instruments upon request.
4.12 Form of debt security of 7.53% Notes due May 12, 2017
(incorporated by reference to Exhibit 4.4 to Halliburton's
Form 10-Q for the quarter ended March 31, 1997, File No.
1-3492).
4.13 Form of debt security of 6.30% Notes due August 5, 2002
(incorporated by reference to Exhibit 4.1 to Halliburton's
Form 8-K dated as of August 5, 1997, File No. 1-3492).
4.14 Form of debt security of 5.63% Notes due December 1, 2008
(incorporated by reference to Exhibit 4.1 to Halliburton's
Form 8-K dated as of November 24, 1998, File No. 1-3492).
103
4.15 Form of Indenture, between Baroid Corporation and Texas
Commerce Bank National Association, as Trustee, for 8%
Senior Notes due 2003 (incorporated by reference to
Exhibit 4.01 to the Registration Statement on Form S-3
filed by Baroid Corporation, Registration No. 33-60174),
as supplemented and amended by Form of Supplemental
Indenture, between Dresser, Baroid Corporation and Texas
Commerce Bank N.A. as Trustee, for 8% Guaranteed Senior
Notes due 2003 (incorporated by reference to Exhibit 4.3
to Registration Statement on Form S-4 filed by Baroid
Corporation and Dresser Industries, Inc., Registration No.
33-53077).
4.16 Second Supplemental Indenture dated October 30, 1997
between Dresser and Texas Commerce Bank National
Association, as Trustee, for 8% Senior Notes due 2003
(incorporated by reference to Exhibit 4.19 to
Halliburton's Form 10-K for the year ended December 31,
1998, File No. 1-3492).
4.17 Third Supplemental Indenture dated September 29, 1998
between Dresser, Halliburton, as Guarantor, and Chase Bank
of Texas, National Association, as Trustee, for 8% Senior
Notes due 2003 (incorporated by reference to Exhibit 4.20
to Halliburton's Form 10-K for the year ended December 31,
1998, File No. 1-3492).
4.18 Form of Indenture, between Dresser and 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 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).
4.19 Form of debt security of floating rate Notes due July 16,
2003 (incorporated by reference to Exhibit 4.1 to
Halliburton's Form 8-K dated January 8, 2002, File No.
1-3492).
4.20 Form of debt security of 6% Notes due August 1, 2006
(incorporated by reference to Exhibit 4.2 to Halliburton's
Form 8-K dated January 8, 2002, File No. 1-3492).
4.21 Fourth Supplemental Indenture dated December 20, 2002
between DII Industries, LLC (formerly Dresser Industries,
Inc.), Halliburton and JPMorgan Chase Bank, a New York
banking corporation (formerly Chase Bank of Texas,
National Association and before that Texas Commerce Bank
National Association), as Trustee, for 8% Senior Notes due
2003 (incorporated by reference to Exhibit 4.21 to
Halliburton's Form 10-K for the year ended December 31,
2002, File No. 1-3492).
4.22 Credit Facility in the amount of (pound)80 million dated
November 29, 2002 between Devonport Royal Dockyard Limited
and Devonport Management Limited and The Governor and
Company of the Bank of Scotland, HSBC Bank plc and The
Royal Bank of Scotland Plc (incorporated by reference
to Exhibit 4.22 to Halliburton's Form 10-K for the year
ended December 31, 2002, File No. 1-3492).
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 Retirement Plan for the Directors of Halliburton Company,
as amended and restated effective May 16, 2000
(incorporated by reference to Exhibit 10.2 to
Halliburton's Form 10-Q for the quarter ended September
30, 2000, File No. 1-3492).
104
10.3 Halliburton Company Directors' Deferred Compensation Plan
as amended and restated effective February 1, 2001
(incorporated by reference to Exhibit 10.3 to
Halliburton's Form 10-K for the year ended December 31,
2000, File No. 1-3492).
10.4 Halliburton Company 1993 Stock and Long-Term Incentive
Plan, as amended and restated effective May 16, 2000
(incorporated by reference to Exhibit 10.3 to
Halliburton's Form 10-Q for the quarter ended June 30,
2000, File No. 1-3492).
10.5 Halliburton Company Restricted Stock Plan for Non-Employee
Directors (incorporated by reference to Appendix B of the
Predecessor's proxy statement dated March 23, 1993, File
No. 1-3492).
10.6 Employment agreement (David J. Lesar) (incorporated by
reference to Exhibit 10(n) to the Predecessor's Form 10-K
for the year ended December 31, 1995, File No. 1-3492).
10.7 Employment agreement (Lester L. Coleman) (incorporated by
reference to Exhibit 10.16 to Halliburton's Form 10-K for
the year ended December 31, 1998, File No. 1-3492).
10.8 Employment agreement (Gary V. Morris) (incorporated by
reference to Exhibit 10.19 to Halliburton's Form 10-K for
the year ended December 31, 1998, File No. 1-3492).
10.9 Dresser Industries, Inc. Deferred Compensation Plan, as
amended and restated effective January 1, 2000
(incorporated by reference to Exhibit 10.16 to
Halliburton's Form 10-K for the year ended December 31,
2000, File No. 1-3492).
10.10 Dresser Industries, Inc. 1982 Stock Option Plan
(incorporated by reference to Exhibit A to Dresser's Proxy
Statement dated February 12, 1982, File No. 1-4003).
10.11 ERISA Excess Benefit Plan for Dresser Industries, Inc., as
amended and restated effective June 1, 1995 (incorporated
by reference to Exhibit 10.7 to Dresser's Form 10-K for
the year ended October 31, 1995, File No. 1-4003).
10.12 ERISA Compensation Limit Benefit Plan for Dresser
Industries, Inc., as amended and restated effective June
1, 1995 (incorporated by reference to Exhibit 10.8 to
Dresser's Form 10-K for the year ended October 31, 1995,
File No. 1-4003).
10.13 Supplemental Executive Retirement Plan of Dresser
Industries, Inc., as amended and restated effective
January 1, 1998 (incorporated by reference to Exhibit 10.9
to Dresser's Form 10-K for the year ended October 31,
1997, File No. 1-4003).
10.14 Stock Based Compensation Arrangement of Non-Employee
Directors (incorporated by reference to Exhibit 4.4 to
Dresser's Registration Statement on Form S-8, Registration
No. 333-40829).
10.15 Dresser Industries, Inc. Deferred Compensation Plan for
Non-employee Directors, as restated and amended effective
November 1, 1997 (incorporated by reference to Exhibit 4.5
to Dresser's Registration Statement on Form S-8,
Registration No. 333-40829).
10.16 Long-Term Performance Plan for Selected Employees of The
M. W. Kellogg Company, as amended and restated effective
September 1, 1999 (incorporated by reference to Exhibit
10.23 to Halliburton's Form 10-K for the year ended
December 31, 2000, File No. 1-3492).
105
10.17 Dresser Industries, Inc. 1992 Stock Compensation Plan
(incorporated by reference to Exhibit A to Dresser's Proxy
Statement dated February 7, 1992, File No. 1-4003).
10.18 Amendments No. 1 and 2 to Dresser Industries, Inc. 1992
Stock Compensation Plan (incorporated by reference to
Exhibit A to Dresser's Proxy Statement dated February 6,
1995, File No. 1-4003).
10.19 Amendment No. 3 to the Dresser Industries, Inc. 1992 Stock
Compensation Plan (incorporated by reference to Exhibit
10.25 to Dresser's Form 10-K for the year ended October
31, 1997, File No. 1-4003).
10.20 Amendment No. 1 to the Supplemental Executive Retirement
Plan of Dresser Industries, Inc. (incorporated by
reference to Exhibit 10.1 to Dresser's Form 10-Q for the
quarter ended April 30, 1998, File No. 1-4003).
10.21 Employment agreement (Robert F. Heineman) (incorporated by
reference to Exhibit 10.2 to Halliburton's Form 10-Q for
the quarter ended June 30, 2000, File No. 1-3492).
10.22 Employment agreement (Arthur D. Huffman) (incorporated by
reference to Exhibit 10.1 to Halliburton's Form 10-Q for
the quarter ended September 30, 2000, File No. 1-3492).
10.23 Form of Nonstatutory Stock Option Agreement for
Non-Employee Directors (incorporated by reference to
Exhibit 10.3 to Halliburton's Form 10-Q for the quarter
ended September 30, 2000, File No. 1-3492).
10.24 Employment agreement (Margaret E. Carriere) (incorporated
by reference to Exhibit 10.39 to Halliburton's Form 10-K
for the year ended December 31, 2000, File No. 1-3492).
10.25 Agreement and Plan of Recapitalization, as amended and
restated effective April 10, 2001 (incorporated by
reference to Halliburton's Form 8-K/A dated as of May 10,
2001, File No. 1-3492).
10.26 Halliburton Company Supplemental Executive Retirement Plan
(formerly part of Halliburton Company Senior Executives'
Deferred Compensation Plan), as amended and restated
effective January 1, 2001 (incorporated by reference to
Exhibit 10.1 to Halliburton's Form 10-Q for the quarter
ended June 30, 2001, File No. 1-3492).
10.27 Halliburton Company Benefit Restoration Plan (formerly
part of Halliburton Company Senior Executives' Deferred
Compensation Plan), as amended and restated effective
January 1, 2001 (incorporated by reference to Exhibit 10.2
to Halliburton's Form 10-Q for the quarter ended June 30,
2001, File No. 1-3492).
10.28 Employment agreement (Douglas L. Foshee) (incorporated by
reference to Exhibit 10.3 to Halliburton's Form 10-Q for
the quarter ended June 30, 2001, File No. 1-3492).
10.29 Halliburton Annual Performance Pay Plan, as amended and
restated effective January 1, 2001 (incorporated by
reference to Exhibit 10.1 to Halliburton's Form 10-Q for
the quarter ended September 30, 2001, File No. 1-3492).
10.30 Halliburton Company Performance Unit Program (incorporated
by reference to Exhibit 10.2 to Halliburton's Form 10-Q
for the quarter ended September 30, 2001, File No.
1-3492).
106
10.31 Employment agreement (R. Randall Harl) (incorporated by
reference to Exhibit 10.32 to Halliburton's Form 10-K for
the year ended December 31, 2001, File No. 1-3492).
10.32 Employment agreement (Edgar Ortiz) (incorporated by
reference to Exhibit 10.33 to Halliburton's Form 10-K for
the year ended December 31, 2001, File No. 1-3492).
10.33 Halliburton Elective Deferral Plan, as amended and
restated effective January 1, 2002 (incorporated by
reference to Exhibit 4.1 to Halliburton's Registration
Statement on Form S-8, Registration No. 333-73046).
10.34 Halliburton Elective Deferral Plan as amended and restated
effective May 1, 2002 (incorporated by reference to
Exhibit 10.1 to Halliburton's Form 10-Q for the quarter
ended June 30, 2002, File No. 1-3492).
10.35 Halliburton Company 2002 Employee Stock Purchase Plan
(incorporated by reference to Exhibit 10.2 to
Halliburton's Form 10-Q for the quarter ended June 30,
2002, File No. 1-3492).
10.36 Halliburton Company Directors' Deferred Compensation Plan
as amended and restated effective as of October 22, 2002
(incorporated by reference to Exhibit 10.1 to
Halliburton's Form 10-Q for the quarter ended September
30, 2002, File No. 1-3492).
10.37 Employment Agreement (Albert O. Cornelison) (incorporated
by reference to Exhibit 10.3 to Halliburton's Form 10-Q
for the quarter ended June 30, 2002, File No. 1-3492).
10.38 Employment Agreement (Weldon J. Mire) (incorporated by
reference to Exhibit 10.4 to Halliburton's Form 10-Q for
the quarter ended June 30, 2002, File No. 1-3492).
10.39 Employment Agreement of David R. Smith (incorporated by
reference to Exhibit 10.39 to Halliburton's Form 10-K
for the year ended December 31, 2002, File No. 1-3492).
10.40 Employment Agreement of John W. Gibson (incorporated by
reference to Exhibit 10.40 to Halliburton's Form 10-K
for the year ended December 31, 2002, File No. 1-3492).
21 Subsidiaries of the Registrant(incorporated by reference
to Exhibit 21 to Halliburton's Form 10-K for the year
ended December 31, 2002, File No. 1-3492).
* 23.1 Consent of KPMG LLP.
23.2 Notice Regarding Consent of Arthur Andersen LLP
(incorporated by reference to Exhibit 23.2 to
Halliburton's Form 10-K for the year ended December 31,
2002, File No. 1-3492).
24.1 Powers of attorney for the following directors signed in
February, 1997 (incorporated by reference to Exhibit 24 to
Halliburton's Form 10-K for the year ended December 31,
1996, File No. 1-3492):
Robert L. Crandall
W. R. Howell
C. J. Silas
24.2 Power of attorney signed in December, 1997 for Charles J.
DiBona (incorporated by reference to Exhibit 24(b) to
Halliburton's Form 10-K for the year ended December 31,
1997, File No. 1-3492).
107
24.3 Powers of attorney for the following directors signed in
October, 1998 (incorporated by reference to Exhibit 24.3
to Halliburton's Form 10-K for the year ended December 31,
1998, File No. 1-3492):
Lawrence S. Eagleburger
Ray L. Hunt
J. Landis Martin
Jay A. Precourt
24.4 Powers of attorney for the following directors signed in
May, 2001 (incorporated by reference to Exhibit 24.1 to
Halliburton's Form 10-Q for the quarter ended June 30,
2001, File No. 1-3492):
Kenneth T. Derr
Aylwin B. Lewis
Debra L. Reed
* 31.1 Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
* 31.2 Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
* 32.1 Certification of Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
* 32.2 Certification of Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
* Filed with this Form 10-K/A.
(b) Reports on Form 8-K:
Date of
Date Filed Earliest Event Description of Event
-------------------------------------------------------------------------------------------------------------------
During the fourth quarter of 2002:
October 2, 2002 October 1, 2002 Item 5. Other Events for a press release announcing a conference
call to discuss third quarter financial results.
November 5, 2002 November 4, 2002 Item 9. Regulation FD Disclosure for a press release announcing
the revision of credit rating agreements.
November 13, 2002 November 7, 2002 Item 9. Regulation FD Disclosure for a press release announcing
2002 third quarter results.
November 13, 2002 November 7, 2002 Item 9. Regulation FD Disclosure for a press release announcing
asbestos plaintiffs agree to extend current stay on asbestos
claims until December 11, 2002
November 14, 2002 November 12, 2002 Item 9. Regulation FD Disclosure furnishing Certifications to the
SEC, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to
Section 906 of the Sarbanes-Oxley act of 2002, signed by David J.
Lesar and Douglas L. Foshee.
November 15, 2002 November 14, 2002 Item 9. Regulation FD Disclosure for a press release announcing
the 2002 fourth quarter dividend.
108
Date of
Date Filed Earliest Event Description of Event
-------------------------------------------------------------------------------------------------------------------
During the fourth quarter of 2002 (continued):
December 12, 2002 December 11, 2002 Item 9. Regulation FD Disclosure for a press release announcing
the Harbison-Walker bankruptcy court has agreed to extend the
current stay on asbestos claims until December 13, 2002.
December 12, 2002 December 11, 2002 Item 9. Regulation FD Disclosure for a press release announcing
the Company is close to an agreement in principle with asbestos
plaintiffs' attorneys representing more than 300,000 claimants.
December 13, 2002 December 13, 2002 Item 9. Regulation FD Disclosure for a press release announcing
the Harbison-Walker bankruptcy court has agreed to extend the
current stay on asbestos claims until December 18, 2002.
December 18, 2002 December 17, 2002 Item 9. Regulation FD Disclosure for a press release announcing
completion of the sale of ShawCor shares.
December 19, 2002 December 18, 2002 Item 9. Regulation FD Disclosure for a press release announcing a
conference call to discuss the global asbestos settlement.
December 19, 2002 December 18, 2002 Item 9. Regulation FD Disclosure for a press release announcing
asbestos plaintiffs agree to extend current stay on asbestos
claims until January 17, 2003
December 20, 2002 December 18, 2002 Item 9. Regulation FD Disclosure for a press release announcing
agreement in principle to achieve global settlement of asbestos
claims.
December 20, 2002 December 19, 2002 Item 9. Regulation FD Disclosure for a press release announcing
the SEC has formalized its investigation of the Company's
disclosure and accounting for cost overruns on certain
engineering and construction jobs.
During the first quarter of 2003:
January 3, 2003 January 2, 2003 Item 9. Regulation FD Disclosure for a press release announcing
an analyst and investor meeting on January 13, 2003.
January 7, 2003 January 7, 2003 Item 9. Regulation FD Disclosure for a press release announcing a
conference call on February 20, 2003 to discuss 2002 fourth
quarter financial results.
January 13, 2003 January 13, 2003 Item 9. Regulation FD Disclosure for submission of presentation
content at analyst and investor meeting on January 13, 2003.
January 21, 2003 January 17, 2003 Item 9. Regulation FD Disclosure for a press release announcing
asbestos plaintiffs agree to extend current stay on asbestos
claims until February 18, 2003.
109
Date of
Date Filed Earliest Event Description of Event
-------------------------------------------------------------------------------------------------------------------
During the first quarter of 2003 (continued):
February 14, 2003 February 12, 2003 Item 9. Regulation FD Disclosure for a press release announcing
2003 first quarter dividend.
February 14, 2003 February 12, 2003 Item 9. Regulation FD Disclosure for a press release announcing
C. Christopher Gaut named executive vice president and chief
financial officer and Doug Foshee promoted to chief operating
officer.
February 21, 2003 February 18, 2003 Item 9. Regulation FD Disclosure for a press release announcing
the Harbison-Walker bankruptcy court extended the current stay on
asbestos claims until March 21, 2003. The court also ruled that
the Company must file an affidavit by March 14, 2003 stating
settlement agreements have been signed by attorneys representing
75% of DII Industries' current asbestos claimants.
February 21, 2003 February 20, 2003 Item 9. Regulation FD Disclosure for a press release announcing
2002 fourth quarter results.
March 12, 2003 March 11, 2003 Item 9. Regulation FD Disclosure for a press release announcing
the selling of Wellstream.
March 17, 2003 March 14, 2003 Item 9. Regulation FD Disclosure for a press release announcing
DII Industries' filing of an affidavit on the global asbestos
settlement, stating that it believes it has complied with the
March 14, 2003 court-imposed deadline requiring signed agreements
by an estimated 75% of DII Industries' asbestos plaintiffs.
March 24, 2003 March 21, 2003 Item 9. Regulation FD Disclosure for a press release announcing
an agreement with Harbison-Walker Refractories Company and the
Official Committee of Asbestos Creditors in the Harbison-Walker
bankruptcy to consensually extend the period of the stay
contained in the Bankruptcy Court's temporary restraining order
until July 21, 2003.
March 26, 2003 March 21, 2003 Item 9. Regulation FD Disclosure for a press release announcing
2003 first quarter results.
110
This report is a copy of a previously issued report, the predecessor auditor has
not reissued this report, and the previously issued report refers to financial
statements not physically included in this document.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
ON SUPPLEMENTAL SCHEDULE
To the Shareholders and
Board of Directors of Halliburton Company:
We have audited in accordance with auditing standards generally accepted in the
United States of America, the consolidated financial statements included in this
Form 10-K, and have issued our report thereon dated January 23, 2002. Our audits
were made for the purpose of forming an opinion on those statements taken as a
whole. The supplemental schedule (Schedule II) is the responsibility of
Halliburton Company's management and is presented for purposes of complying with
the Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, is fairly stated in all material respects in relation to the basic
financial statements taken as a whole.
Arthur Andersen LLP
Dallas, Texas
January 23, 2002 (Except with respect to certain matters discussed in Note 9, as
to which the date is February 21, 2002.)
111
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Halliburton Company:
Under date of March 13, 2003, except for Notes 1, 2 and 4 as to which the date
is January 14, 2004, we reported on the consolidated balance sheet of
Halliburton Company and subsidiaries as of December 31, 2002, and the related
consolidated statements of operations, shareholders' equity, and cash flows for
the year ended December 31, 2002, which are included in the Form 10-K/A. Our
report includes an explanatory paragraph regarding the restatement of
disclosures included in the 2002, 2001 and 2000 consolidated financial
statements relating to the Company's reportable business segments. In connection
with our audits of the aforementioned consolidated financial statements, we also
audited the related consolidated financial statement schedule (Schedule II)
included in Form 10-K/A. These financial statement schedule is the
responsibility of the Company's management. Our responsibility is to express an
opinion on the consolidated financial statement schedule based on our audit. The
accompanying 2001 and 2000 consolidated financial statement schedule of
Halliburton Company and subsidiaries were audited by other auditors who have
ceased operations. Those auditors expressed an unqualified opinion on those
consolidated financial statements and schedule, before the restatement described
in Note 4 to the consolidated financial statements and before the revision
described in Note 22 to the consolidated financial statements, in their report
dated January 23, 2002 (except with respect to certain matters discussed in Note
9 to those financial statements, as to which the date was February 21, 2002).
In our opinion, such financial statement schedule, when considered in relation
to the basic consolidated financial statements taken as a whole, presents
fairly, in all material respects, the information set forth therein.
/s/ KPMG LLP
------------
KPMG LLP
Houston, Texas
March 13, 2003
112
HALLIBURTON COMPANY
Schedule II - Valuation and Qualifying Accounts
(Millions of Dollars)
The table below presents valuation and qualifying accounts for continuing
operations.
Additions
------------------------------
Balance at Charged to Charged to Balance at
Beginning Costs and Other End of
Descriptions of Period Expenses Accounts Deductions Period
-------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2000:
Deducted from accounts and notes receivable:
Allowance for bad debts $ 94 $ 39 $ - $ (8) (a) $ 125
-------------------------------------------------------------------------------------------------------------------------------
Liability for major repairs and maintenance $ 15 $ 4 $ - $ (5) $ 14
-------------------------------------------------------------------------------------------------------------------------------
Accrued special charges $ 69 $ - $ - $ (63) (b) $ 6
-------------------------------------------------------------------------------------------------------------------------------
Accrued reorganization charges $ - $ 36 $ - $ (20) $ 16
===============================================================================================================================
Year ended December 31, 2001:
Deducted from accounts and notes receivable:
Allowance for bad debts $ 125 $ 70 $ - $ (64) (a) $ 131
-------------------------------------------------------------------------------------------------------------------------------
Liability for major repairs and maintenance $ 14 $ 4 $ - $ (5) $ 13
-------------------------------------------------------------------------------------------------------------------------------
Accrued special charges $ 6 $ - $ - $ (6) $ -
-------------------------------------------------------------------------------------------------------------------------------
Accrued reorganization charges $ 16 $ - $ - $ (15) (c) $ 1
===============================================================================================================================
Year ended December 31, 2002:
Deducted from accounts and notes receivable:
Allowance for bad debts $ 131 $ 82 $ $ (56) (a) $ 157
-------------------------------------------------------------------------------------------------------------------------------
Liability for major repairs and maintenance $ 13 $ 4 $ $ (10) $ 7
-------------------------------------------------------------------------------------------------------------------------------
Accrued reorganization charges $ 1 $ 29 $ $ (20) $ 10
===============================================================================================================================
(a) Receivable write-offs and reclassifications, net of recoveries.
(b) Includes $9 million for items of a long-term nature reclassified to other
liabilities in 2000.
(c) Includes $4 million estimate to actual adjustment.
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SIGNATURES
As required by Section 13 or 15(d) of the Securities Exchange Ace of 1934, the
registrant has authorized this report to be signed on its behalf by the
undersigned authorized individual, on this 15th day of January 2004.
HALLIBURTON COMPANY
By /s/ C. Christopher Gaut
-------------------------------
C. Christopher Gaut
Executive Vice President and
Chief Financial Officer
114