Halliburton Company
Annual Report 2000

Plain-text annual report

Marc h 20, 2001 A N N U 2 A L O R E P O O R T O I S S U E INNOVATIONS 2000 03> 0 2 0 0 1 0 230017 0 www.halliburton.com comparative highlights Millions of dollars and shares except per share data 2000 1999 1998 Diluted income (loss) per share from continuing operations Diluted net income (loss) per share Cash dividends per share Shareholders’ equity per share Revenues Operating income Income (loss) from continuing operations Net income (loss) Long-term debt (including current maturities) Shareholders’ equity Capital expenditures Depreciation and amortization Diluted average shares outstanding N e t i n c o m e i n 2 0 0 0 i n c l u d e s a g a i n o n d i s p o s a l o f d i s c o n t i n u e d o p e r a t i o n s o f $ 2 1 5 m i l l i o n o r $ 0 . 4 8 p e r d i l u t e d s h a r e . N e t i n c o m e i n 1 9 9 9 i n c l u d e s a g a i n o n d i s p o s a l o f d i s c o n t i n u e d o p e r a t i o n s o f $ 1 5 9 m i l l i o n o r $ 0 . 3 6 p e r d i l u t e d s h a r e . $ 0.42 1.12 0.50 9.20 $ 11,944 462 188 501 $ 1,057 3,928 578 503 446 $ $ 0.39 0.99 0.50 9.69 $ 12,313 401 174 438 $ 1,364 4,287 520 511 443 $ $ (0.27) (0.03) 0.50 9.23 $ 14,504 170 (120) (15) $ 1,426 4,061 841 500 439 $ H A L L I B U R T O N C O M P A N Y 2 0 0 0 A N N U A L R E P O R T I N N O V A T I O N S 2 0 0 0 & A N N U A L R E P O R T E D I T I O N HALLIBURTON TODAY More than 90,000 professionals producing extraordinary results for customers worldwide. ENERGY SERVICES Through innovation and technology, impacting every aspect of the oil and gas asset. ENGINEERING & CONSTRUCTION The world’s most respected designer, builder and facilitator of energy and infrastructure projects. i nnovation is the theme of our Annual Report for the year 2000. It’s the story of the changes, great and small, technical and organizational, that our more than 90,000 men and women are delivering every day. 3 4 8 Halliburton Today Letter to Shareholders Energy Services Group We take great pride in their contributions. Naturally, the decisions of senior management 12 Technology Flagships are most often in the spotlight, because those decisions set the direction and the tone for 24 Engineering and Construction Group the organization. 30 Health, Safety and Environment But there is much more to our success – the extraordinary results produced by the 32 Financial Section scientists and software developers, the sales people and the project managers, the 76 Board of Directors roughnecks and field engineers. Their results come from having the right people and the right environment – the culture that helps them focus on the customer, on solving the most important problems, and on delivering excellent service. Creating and nurturing this culture is our most important task. We welcome this opportunity to show our shareholders and the public some of our impor- tant and dramatic innovations, and to thank the extraordinary Halliburton people who are bringing them about. H Cover illustration by C.F.Payne 1 management and corporate information CORPORATE OFFICERS David J. Lesar Chairman of the Board, President and Chief Executive Officer, Donald C. Vaughn Vice Chairman, Gary V. Morris Executive Vice President and Chief Financial Officer, Lester L. Coleman Executive Vice President and General Counsel, John W. Kennedy Executive Vice President - Global Business Development, Jerry H. Blurton Vice President and Treasurer, Margaret Carriere Vice President – Human Resources, Robert F. Heinemann Vice President and Chief Technology Officer, Arthur D. Huffman Vice President and Chief Information Officer, Susan S. Keith Vice President, Secretary and Corporate Counsel, Guy T. Marcus Vice President – Investor Relations, R. Charles Muchmore, Jr. Vice President and Controller ENERGY SERVICES GROUP Edgar Ortiz President and Chief Executive Officer ENGINEERING AND CONSTRUCTION GROUP KELLOGG BROWN & ROOT A. Jack Stanley Chairman, R. Randall Harl President and Chief Executive Officer GO TO WWW.HALLIBURTON.COM FOR A COMPLETE LISTING OF OFFICERS. SHAREHOLDER INFORMATION Corporate Office 3600 Lincoln Plaza, 500 North Akard Street, Dallas, Texas 75201-3391. Shares Listed New York Stock Exchange Symbol: HAL, Swiss Exchange. Transfer Agent and Registrar Mellon Investor Services, L.L.C., 85 Challenger Road, Overpeck Centre, Ridgefield Park, New Jersey 07660-2104 • (800) 279-1227. Form 10-K Report Shareholders can obtain a copy of the Company’s annual report to the Securities and Exchange Commission, Form 10-K, by contacting: Vice President – Investor Relations, Halliburton Company, 3600 Lincoln Plaza, 500 North Akard Street, Dallas, Texas 75201-3391. For up-to-date information on Halliburton Company, shareholders may use the Company’s toll free telephone-based information service, available 24 hours a day at: 1-888-669-3920 or contact the Halliburton Company homepage on the Internet’s World Wide Web at http://www.halliburton.com Click here for innovation. Go to www.halliburton.com and you’ll find a wealth of information about our innovative company. You can click and find our latest projects, most recent news releases, or even job opportunities. Halliburton.com. It’s an innovative site, but that’s what you should expect from a leader. 2 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT H A L L I B U R T O N C O M P A N Y 2 0 0 0 A N N U A L R E P O R T Energy Services Group offers the broadest array of products and services to upstream oil and gas customers worldwide, stretching from the manufacturing of drill bits and other downhole and completion tools and pressure pumping services to subsea engineering and fabrication. Engineering and Construction Group serves the energy industry by designing and building liquefied natural gas plants, refining and processing plants, production facilities and pipelines both onshore and offshore. The non-energy business of the group meets the engin- eering and construction needs of governments and civil infrastructure customers. H HALLIBURTON COMPANY 2000 ANNUAL REPORT 3 L E T T E R T O O U R S H A R E H O L D E R S A message from David J. Lesar, Chairman of the Board, President and Chief Executive Officer of Halliburton Company 4 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT L E T T E R T O O U R S H A R E H O L D E R S fellow shareholders alliburton initiated significant five years Halliburton has grown from a has been slower to accelerate. As changes during 2000 as we $5.7 billion company to its present $11.9 exploration and development increases h restructured the Company to profit from billion size. At the same time, we have overseas in 2001, we are in an excellent growing opportunities in the worldwide become a more closely knit organization position to continue to grow our revenues energy industry. These changes included with a more focused and unified strategy. and earnings in the upstream oil and gas the decision to divest the Dresser We’re grateful for Dick’s service and sector. Overall, oil and gas company E&P Equipment Group, and the formation of commitment to Halliburton and wish him spending was up by more than 18 our Energy Services and Engineering and well in his new role in public life. percent in 2000. Early estimates for 2001 Construction groups. In 2000, the demand for energy services are for additional spending growth of Halliburton also experienced a was particularly strong in the U.S., as both around 20 percent. transition in senior management. Dick crude oil and natural gas prices rose The demand for Engineering & Cheney retired as our chairman in August substantially, and oil and gas companies Construction (E&C) projects, however, to run for vice president of the United increased their expenditures for did not mirror that for energy services. In States, and I was elected chairman and exploration and production (E&P) 2000, higher prices for oil and gas had not chief executive officer in addition to my projects. However, historically two-thirds yet translated to increased spending by job as president. of Halliburton’s energy services business our customers on E & C projects in the Dick’s tenure was marked by a period comes from outside the U.S., and demand liquefied natural gas (LNG), refining, and of extraordinary growth for Halliburton. In for energy services in international areas petrochemical industries. This lack of H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 5 L E T T E R T O O U R S H A R E H O L D E R S market opportunities, along with a and $188 million from continuing The E&C group’s revenues were $4.0 consolidating customer base and a fiercely operations. Earnings per diluted share billion, compared to $5.3 billion in 1999, competitive environment, contributed to were $1.12, compared with $.99 per share and operating income was $14 million, my decision to restructure the E&C for 1999. Discontinued operations are compared to $203 million in 1999. This group. This change will help us gain those of the Dresser Equipment Group, decline was a reflection of the lack of new operating efficiencies and provide a which is in the process of being sold. downstream projects, and intense compe- stronger platform for consistent profitability The Energy Services Group includes tition for the few available opportunities. with improved operating margins. Current our business units providing services and Our third business segment, Dresser and projected strength in the energy products to the upstream oil and gas Equipment Group, was reclassified as services markets in the U.S. and overseas business. The group’s 2000 revenues were discontinued operations after we decided should be followed by increased $7.9 billion, compared to $7.0 billion in to sell the business. The group is spending in the E&C sector. We expect 1999, while operating income more than performing well, but their lines of this to begin in late 2001 and 2002. doubled to $526 million in 2000, business do not closely fit our core business Halliburton’s 2000 revenues from compared to $222 million in 1999. This and our long-term goals and objectives. continuing operations were $11.9 billion. dramatic improvement came from This move will bring a sharper focus on Net income for the year, including stronger demand for energy services in our core business activities. discontinued operations, was $501 million, North America. The estimated $1.1 billion net proceeds “ Our organization and our technology strategy …are designed to position Halliburton to… continue our worldwide leadership in providing discrete energy services. 6 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT ” the company, and a flatter, more responsive, management structure in both business segments. This organization will both strengthen our individual discrete product and service lines, and at the same time give us a more effective framework for developing integrated technology products, and for pursuing large integrated projects. The most significant application for integrated technologies over the next several years is in deepwater exploration and production projects. We estimate there will be about $21 billion committed annually to deepwater projects by 2004, up from $8 billion in 2000. Winning these projects requires project management skills, the ability to match the subsurface and surface work, to perform and integrate services during the project, and to develop new enabling technologies – all Halliburton strengths. And we’ve proven our ability to compete by winning the engineering, procurement and construction (EPC) contract for the $2.5 billion Barracuda/Caratinga offshore project in Brazil. Our organization and our technology will be used for working capital and to In the Energy Services Group, this strategy – the focus of this annual report repay debt, which will leave us in an even means a renewed focus on optimizing the – are designed to position Halliburton to stronger financial position to pursue value of our individual product lines – win large projects and continue our strategic acquisitions and internal invest- turning their brand name capital and worldwide leadership in providing ment opportunities. We expect a pretax strong market position into higher profit discrete energy services. I would like to profit of about $500 million from the sale margins. This will be the focus of the thank all of our employees who are and expect it to be completed in the sec- energy services management in 2001. executing the business strategies which ond quarter of 2001. Halliburton will retain At the same time, in order to make our will drive future success for the Company a 5 percent equity stake. E&C organization flatter and simpler, I and our shareholders. H The changes in our Energy Services combined all our engineering and Sincerely, and E&C groups have been driven by the construction operations into one company. same strategic goals: to improve the All engineering, construction, fabrication, competitive position of our product lines, and project management are now part of to bring a new intensity and focus to our Kellogg Brown & Root (KBR). commitment to the energy industry, and The restructuring has achieved a to improve profitability. reduction in the number of executives in David J. Lesar Chairman of the Board, President and Chief Executive Officer H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 7 E N E R G Y S E R V I C E S G R O U P ener 8 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT E N E R G Y S E R V I C E S gy G R O U P 2 t he Energy Services Group is the real- time knowledge company serving upstream petroleum industry customers worldwide. The Group consists of the Halliburton Energy Services and Landmark Graphics Corporation business units, as well as large integrated projects that include surface, subsea and subsurface components. It also includes the following businesses that were formerly part of Brown & Root Energy Services: Halliburton Subsea, Wellstream, Production Services, Granherne, and two joint ventures: Bredero-Shaw and EMC. Halliburton Energy Services provides a broad range of services for the exploration, development, and production of oil and gas wells. These services include formation evaluation, well construction, production enhancement and well maintenance for either a single well or an entire field. Landmark Graphics Corporation supplies software and services that transform data into computer models of hydrocarbon reserves and enable customers to optimize their exploration, development, and production decisions as well as integrate their technical- to-business processes. This report focuses on the company’s tech- nology strategy and the technological inno- vations for 2000. These cut across business unit boundaries and unify the diverse product and service lines. They provide a framework for understanding how Halliburton is creating value for customers and shareholders, and how that process will be enhanced in the future. Technology is a very broad term that embraces not only tools, processes, products, and services, but also the know-how, experience, and problem-solving ability of Halliburton’s employees. In a very real sense, it is this ability to apply specialized knowledge and advanced techniques to the H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 9 E N E R G Y S E R V I C E S G R O U P unique needs of customers that is the true important step in putting critical information Locator to find the right people for the job – source of value creation, and Halliburton’s at the fingertips of decision makers. the ones with the exact knowledge needed true source of competitive advantage. In addition, Halliburton acquired a 15% at that moment, anywhere in the world. Knowledge Management share of Petroleum Place, an Internet mar- On the level of individual products and Many of Halliburton’s most important ketplace serving the oil and gas property services, Baroid Drilling Fluids launched innovations are better ways to bring the right acquisition and divestiture market. Landmark Wellsight 2000,™ a central database built to experts and the right experience to bear on will provide online access to its software contain all the drilling fluids experience on the right problems at the right time. This is through Petroleum Place, and participate in all the company’s jobs worldwide. With knowledge management, and it multiplies the development of new software for Wellsight 2000, engineers can cross-refer- the value of individual technologies and the Internet-based property evaluations. This ence conditions and solutions and call on the expertise of Halliburton’s people. These venture capitalizes on the fact that the accumulated knowledge of the world’s lead- innovations include products, services, and systems for our customers as well as processes used inside Halliburton to deliver better services and solutions. Both allow the organization to use its people and their skills and knowledge more effectively. Landmark Graphics is the leader in helping customers integrate knowledge within their organiza- tions. In 2000, two major customers, Texaco and Petrobras in Colombia, signed contracts with Landmark to improve their internal information systems. Texaco will receive a broad range of integrated solutions for explo- ration and production that will create a new electronic upstream environ- ment, including development of new workflows to help Texaco execute KNOWLEDGE MANAGEMENT gives direction to a non-stop free flow of innovative ideas. ing team of drilling fluids experts. Knowledge of the best approach to any situation will be instantly available to Baroid people on any rig, anywhere in the world. Finally, the company’s knowledge management innovations blend into our e-business strategy. The most important use of the Internet, and the one that will deliver the great- est competitive advantage, is its use as a venue for collaboration, knowl- edge sharing and work sharing. Practically all the company’s knowl- edge management innovations use the Internet. Taking these ideas one step farther, helping to bring about the new world where sharing and inte- grating knowledge is the main source of value creation, Halliburton faster and with lower risk. Petrobras will receive majority of the world’s exploration and founded GrandBasin. GrandBasin is a web- services designed to integrate data, people and production data already resides in Landmark’s based unit of Landmark that will provide a processes, improve risk assessment and speed OpenWorks® digital format. Petroleum Place virtual, integrated E&P workspace for up decision-making. will allow operators to use Landmark’s upstream companies and professionals. It will iDims,™ a Landmark knowledge manage- interpretation and analysis tools to improve be the Internet site where professionals work- ment product launched in 2000, gives their acquisition and divestiture processes. ing on the same project – customers, contrac- customers online intranet access to their Landmark has also created an important tors, subcontractors – can work together using drilling and well services operations data. This knowledge management service for a secure high-performance network, techni- access via a web browser will dramatically Halliburton’s internal use – Lattix Locator, a cal applications and computing power, a com- reduce lead time for data acquisition and pro- database of the skills and experience of the munity portal and data integration. vide operators both current well data and company’s staff for all disciplines and all areas GrandBasin will market to the oil and gas historical data from any location. This is an of the business. Project managers use Lattix industry as a whole the kind of integration and 10 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT E N E R G Y S E R V I C E S G R O U P opportunity for collaboration that has proven 1) Real-time reservoir solutions – The flagships are built from excellence so effective inside Halliburton. building a complete, accurate, “picture” of in discrete products and services. Technology Architecture the reservoir from real-time data, which Excellence in advanced well construction is Halliburton’s energy services business can provides the customer with the answers built on Halliburton’s 80 years of be viewed as consisting of two complemen- needed to make the optimum development leadership in pressure pumping. tary offerings: providing discrete, individual decisions on a timely basis. Excellence in gas monetization is built on oilfield services on the one hand, and 2) Advanced well construction – services Kellogg Brown & Root’s proprietary process combining our technologies in a way to help that allow operators to reduce the cost of technologies. Continued excellence in customers taking on large integrated field drilling wells in the most challenging envi- discrete services is essential to being the development projects. The technology ronments, and to tap reservoirs that were leader in these five areas. architecture is built on a foundation of discrete previously uneconomical. As a result, about 80% of Halliburton’s technologies. These are some of Halliburton’s 3) Advanced well production – completion, 2000 investment in research and develop- core competencies – materials sci- ence, manufacturing, fabrication and service delivery. These technologies lead to the development of new and better discrete products and services, from better pressure pumping equipment to the new Anaconda drilling system. Halliburton’s Technology Flagships These discrete products can be grouped into flagship areas that cut across traditional boundaries and combine elements from the Energy Services Group and the Engineering and Construction Group. A flagship is an integrated technology area – a bundle of technologies that meet a certain set of customer needs. TECHNOLOGY ARCHITECTURE The know-how involved in materials science, manufacturing, fabrication and service delivery. ment of $231 million went into technologies aimed at improving discrete products and services. Investment decisions are based on a combination of the needs of the product/service line and its contribution to the success of the flagship. It is important to recognize that individual technologies and products may have a primary application to one flagship, but may also contribute to other flag- ships as well. For example, many drilling innovations from Sperry- Sun contribute to reservoir evaluation as well as advanced well construction systems. There is no simple one-to-one correspondence between products Halliburton’s technology flagships are the intervention, operation and maintenance and flagships; there are often multiple five areas that are most critical to Halliburton’s technologies that maximize hydro- beneficial relationships. customers, and the areas of excellence that carbon flow, increase the percentage Our technology architecture is dynamic. are needed to succeed in the company’s sec- of recoverable reserves, and compress It will evolve as new technologies lead to ond area of business – the integrated mega- production time. new products, and as the requirements for projects that will take on an increasing 4) Deepwater technologies – the key success in winning and executing mega- importance in coming years. Halliburton is products, services, and project management projects develop over time. It does, pursuing excellence in these five areas in part skills needed to develop reservoirs in water however, provide a conceptual framework because together they provide the breadth of depths greater than 1,500 feet. for understanding how Halliburton’s many capability needed to win the multibillion-dol- 5) Gas monetization – the ability to extract facets work together and how they are being lar integrated projects of the future. natural gas and convert it into economically managed to create value for customers and Halliburton’s technology flagships are: viable products, from LNG to fertilizer. shareholders. H H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 11 T E C H N O L O G Y F L A G S H I P S eservoir evaluation is the business of key decision points in the field life cycle – Similarly, Landmark signed a multi-year providing the customer with in-depth from seismic exploration to the refinery deal with 4th Wave Imaging Corporation r knowledge of the reservoir’s performance as gate. DecisionSpace is the latest in to jointly develop 4-D seismic solutions that early as possible in the development Landmark’s systems for technical-to-business support reservoir evaluation. 4-D seismic process. That knowledge is used to create (T2B™) integration. It combines reservoir technology uses multiple periodic 3-D reservoir solutions – the most economical evaluation with risk assessment to enable seismic surveys to monitor changes of fluid reservoir development plan, constantly better analysis of alternative development flow and pressure changes in reservoirs over updated during development and produc- strategies. time. HES has a complementary agreement tion to maximize hydrocarbon recovery. Landmark and Halliburton Energy with 4th Wave Imaging for reservoir Excellence in reservoir solutions depends Services (HES) have formed alliances with monitoring through borehole seismic on the technology to acquire real-time data GeoMechanics International, Inc. (GMI) to services. Reservoir monitoring helps from the field, as well as information sys- integrate GMI’s geomechanics analysis tools identify bypassed reserves and increase tems to model the reservoir and alternative with Landmark’s simulation models and hydrocarbon recoveries. development scenarios. HES’s wellsite services to address customers’ Reservoir monitoring – continuously cap- Many groups within Halliburton con- wellbore stability problems. This under- turing real-time information and modeling tribute to real-time reservoir solutions. standing of geomechanical forces is critical as the hydrocarbons are being extracted – Landmark’s DecisionSpace,™ launched in to efficient well planning and execution. saw another significant advance in 2000. 2000, is the first of a modular suite of Wellbore stability problems are estimated to The RMT Elite™ is a pulsed neutron software products that offers web-enabled cost the industry upwards of $6 billion carbon oxygen logging system that allows project integration capabilities for all the annually during drilling operations alone. time-lapse performance evaluation of 12 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT T E C H N O L O G Y F L A G S H I P S REAL TIME RESERVOIR SOLUTIONS teams and technologies enable Halliburton experts and customers to literally “look beneath the surface” in real time to make better, faster reservoir decisions. producing reservoirs without the costly step of removing the tubing from the well. Together with Halliburton’s Sperry-Sun, Landmark released RESolution 3D,™ a real-time 3-D drilling and reservoir understanding system that enables visualization and updating of earth models in both rig and office settings. Now, drilling information can be instantly shared, allowing faster and better decisions both for drilling the current well and in planning future wells. NUMAR, a division of HES, continued its breakthroughs in the use of magnetic resonance imaging logging (MRIL®). NUMAR unveiled MRIL PrimeTime, a significant enhancement to its MRIL- Prime logging service. MRIL PrimeTime while drilling, instead of later via a A typical RTRS job may bring together delivers answers in real time, as the tool is wireline run, will allow operators to save production enhancement engineers, being run, providing in minutes the critical costly rig time in challenging environments completion products experts, log analysts reservoir information that previously took such as deepwater. and customers, all looking at the same days to process and interpret. Reservoir evaluation and knowledge real-time information from different loca- An even greater advance was the devel- management come together in Halliburton’s tions and different perspectives. As the job opment of MRIL-WD™ (MRIL While Real Time Reservoir Solutions (RTRS). unfolds, everyone can see exactly what’s Drilling) by NUMAR and Sperry-Sun, RTRS combines real-time data collection, happening, in real time, and make which can provide total porosity, free fluid Real Time Operations, reservoir modeling, recommendations that can be acted upon and bound fluid indices in the while- and satellite communications to enable instantly. Quick decisions plus access to drilling and reconnaissance logging mode, experts in different locations to Halliburton’s best minds make RTRS a as well as other MRIL information in the participate in controlling jobs in real time. large contributor to customers’ success in wiping and evaluation logging mode. Being RTRS brings the people with the right difficult environments. In 2000, Halliburton able to collect this reservoir description data knowledge to bear at the critical time. performed 1,675 real-time jobs. H SHERRI ROGERS Sherri Rogers coordinates service delivery for Halliburton’s Real Time Operations, the visualization rooms where specialists and customers monitor and control jobs taking place anywhere in the world. “We’re bringing the field into the office, erasing the boundaries. We even have a Webcam, so people in the control rooms can see the actual conditions at the job site. At the same time, our field people are seeing the interplay between different disciplines, becoming more empowered to innovate and find new ways to add value. Knowledge sharing and cross-fertilization is happening at every level. And many workers are drawn to the idea of drilling wells by remote control, so it’s helping our recruiting. The cultural changes are enormous.” H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 13 ADVANCED WELL CONSTRUCTION is comprised of breakthrough technologies and tools that place the well in precisely the right location and dramatically cut well costs. range of economical wells. Enventure expands the diameter of steel casings by as much as 25% after they are placed. This allows operators to work with smaller hole sizes, enabling them to drill deeper to reservoirs that were previously inaccessible. This capability is becoming increasingly important in deepwater developments. A premiere breakthrough in this area for 2000 is the Anaconda Well Construction System. Anaconda will change the way wells are drilled, and pro- vide operators with a new capability to find and develop isolated pockets of oil and gas. Anaconda is an innovative drilling system using carbon-fiber composite spoolable tubing, called SmartPipe.™ It includes conductors for two-way communication, and a downhole Advanced Drilling, Evaluation and Propulsion Tool (ADEPT) assembly. ADEPT sends enormous amounts of real- time information up the SmartPipe to the operators on the surface, who are then able to remotely direct the path of the well, allowing precise placement of the well bore within a given hydrocarbon zone. Anaconda wells will be guided using real-time updates of the earth model. They will bring together formation evalu- ation experts, drilling engineers, reservoir engineers, geologists and geophysicists to make instant drilling decisions. Anaconda can practically turn on a dime to probe for additional reserves or to access multiple reservoirs. The first commercial de- ployment is in the Gulf of Mexico, to be followed by work with Statoil in the North Sea. Statoil has been a partner in developing Anaconda over the last three years. H T E C H N O L O G Y F L A G S H I P S Minimum hole spiraling in turn improves hole cleaning, logging, and the quality of the cement jobs. Geo-Pilot enables precise, economical drilling of difficult well paths and will help push the limits of extended-reach drilling. Cementing and zonal isolation, a Halliburton strength since its founding, saw the release of the third version of OptiCem™ simulation system for design- ing optimum cementing operations, and OptiCem RT™ (Real Time), that allows onsite specialists to monitor a job in progress and make adjustments immediately. In addition, two new advanced pressure pumping units were introduced: Halliburton Precision,™ a single pump unit, and Halliburton Elite,™ a twin pump cementing trailer. These new units feature the RCM® IIE mixing system that ensures accurate mixing over a broad range of conditions, and ADC,™ the system that automatically controls ell construction is the heart of the developed jointly with Japan National Oil slurry density throughout the job. traditional energy services Corporation, as the industry’s first true Expandable tubing, a product of w business. It encompasses drill bits, point-the-bit rotary steerable drilling tool. Halliburton’s Enventure partnership drilling, drilling fluids, cementing and The system produces clean, straight and with Shell Technology Ventures, is an formation evaluation. Advanced well smooth wellbores with less vibration. important technology that is extending the construction includes the breakthrough technologies that will enable radically less expensive and more productive wells in environments such as deepwater. Halliburton’s Security DBS revolution- ized its production process in 2000 for roller cone bits. Onsite engineers were empowered to modify standard designs to meet unique conditions and take the design directly to prototyping and manu- facturing. The result is custom-designed bits in a third the time required by traditional methods. Besides the RESolution 3-D system already mentioned, Sperry-Sun introduced Geo-Pilot™ rotary steering system, DIAMOND HEADED DRILL BITS are used in a variety of scenarios to achieve a lower cost per foot. These revolutionary bits also can achieve greater drilling rates than roller cone bits, resulting in fewer trips. 14 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT LANDMARK is developing 4-D seismic technology, which uses multiple periodic 3-D survey solutions to continually monitor fluid and pressure changes in reservoirs. T E C H N O L O G Y F L A G S H I P S t he goals of well production technolo- when Halliburton received a patent for a gies are to maximize the rate of hydro- neural network method of controlling carbon production, increase the recovery reservoir development. Developed jointly rate from the reservoir, and reduce produc- with BioComp Systems, Inc., of Redmond, tion costs. Included in this flagship are com- Washington, and using their self-optimiz- pletions, multilaterals, stimulation ing neural network technologies, this system technologies, and intervention systems. will provide better ways to determine the opti- Some of the new technologies discussed mum method of completing a reservoir, under reservoir solutions, such as RMT optimizing production with stimulation and Elite, also contribute to advancing the art treatment, and predicting the output. of well production. BioComp’s neural networks can learn the Intelligent completion technologies provide downhole sensing, communication and remote control of completion tools. This allows operators on the surface and in remote locations to optimize reservoir per- formance by interpreting downhole data in real time and operating flow control devices. Halliburton developed SmartWell™ tech- nology for intelligent completions with PES (International). In February 2000, Halliburton acquired the remaining 74 percent of PES, and it is now a wholly owned subsidiary. In April, Halliburton announced plans to form WellDynamics, a joint venture with Shell International Exploration and Production B.V., to further develop and market this technology. WellDynamics will combine Halliburton’s SmartWell intelligent completions tech- nology with Shell’s iWell™ intelligent well technology. Together, they will be the state of the art in downhole measurement, inflow control, downhole processing, and commu- WELLDYNAMICS TECHNOLOGY will enable operators to remotely reconfigure a well’s architecture in real time to boost production. nications technologies that will enable relationships among the variables that affect operators to reconfigure a well’s architecture future production, such as the geological at will using real-time data. The net result formation and drilling, completion, and will be maximized fluids production stimulation methods. Halliburton’s without intervention, and improved total engineers can use this information in recovery – a combination that will have a conjunction with reservoir understanding to dramatic impact on a well’s economics for perform the delicate balancing act involved Halliburton’s customers. in choosing optimum completion strategies. Another important tool for boosting This technology has been incorporated into reservoir performance debuted in 2000 Halliburton’s SigmaSM service. H H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 17 l l e w d e c n a v d a T E C H N O L O G Y F L A G S H I P S w a t e r 18 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT T E C H N O L O G Y F L A G S H I P S eep water – depths greater than 1,500 specialized technolo- feet – is the arena with the greatest gies for deepwater d number of large untapped reservoirs and work in recent years, greatest revenue growth potential for such as faster Halliburton. As oil and gas companies move Remotely Operated into ever-deeper water to meet the demand Vehicles (ROVs) with for energy, they are predicted to spend about greater mechanical $84 billion in deepwater development over abilities; flexible riser the next five years. Most of this spending systems made from will be on multibillion-dollar projects, where carbon fiber compos- the preferred contractors will be large ites that lift the integrated service companies who are able hydrocarbons to the to supply the necessary combination of key surface and reduce the technologies and project management skills. need for surface Halliburton aims to be the uniquely equipment; and smart qualified contractor for such developments. tie-backs and smart Deepwater development has special control buoys that challenges. Reservoirs in a field tend to be can make remote- widely dispersed, and for cost reasons must controlled adjust- be developed with relatively few wells ments in producing requiring minimal intervention. This is why fields spread over a Halliburton’s deepwater flagship includes wide area. All of these many of the advanced technologies already areas will see further mentioned. Real-time reservoir description, development in com- Enventure expandable tubing, Anaconda, ing years. Together multilaterals, advanced stimulation and they are making possible deepwater work vention to restore the flow. Wax Eater,TM SmartWells are all key enablers for the deep- that was out of reach just a few years ago. Halliburton’s new system currently being water environment. In fact, it is the com- The year’s most promising deepwater field tested, is installed at the wellhead and bined excellence of the other four flagships breakthrough comes from the field of breaks up the wax, removing it from the that make Halliburton a leader in pursuing flow assurance – technologies that allow mixture. Wax Eater will eliminate the need deepwater work. improved uninterrupted flow of hydro- for far more expensive alternative treat- In addition, the company has introduced carbons over time. Specifically, sending ments, and enable the extended tie-backs crude oil through long tie- that are critical to developing fields of backs in cold, deep water smaller, widely dispersed reservoirs. creates the danger of wax In addition to specific technologies, and gas hydrates forming success in this arena also depends on the deposits. This in turn ability to treat deepwater projects with a requires expensive inter- total systems approach, matching all the sur- IN THE HOSTILE DEEPWATER environment, specialized Halliburton technologies like the mechanically adept Remotely Operated Vehicles pictured on this page can perform the most intricate of mechanical maneuvers. face and subsurface components, while reducing cycle times, capital expenditures and operating expenditures. These capabilities are based on Halliburton’s innovative products and services, as well as its roster of skilled project managers, who H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 19 T E C H N O L O G Y F L A G S H I P S mooring facility and the largest FPSO built The first two wells were completed in in the last five years. All of these projects January, 2001. require the global resources and innovative The subsea work will involve the manu- project management that few organizations facture of 28,000 tons of flowlines by besides Halliburton can offer. By far the Halliburton’s Wellstream unit. Halliburton biggest and most important deepwater Subsea will install the risers, flowlines, umbil- development in the world today is the $2.5 icals and seabed fixtures in water depths from billion Petrobras Barracuda/Caratinga pro- 2,500 feet to 4,000 feet. ject offshore Brazil. This EPIC contract is Halliburton will supply two FPSOs, believed to be the largest ever awarded to a which together will produce 300,000 single contractor. barrels per day. One will be converted This project began with a breakthrough in Brazil’s Rio State Shipyards. Detail in project finance, as foreign banks and design for the topsides, along with the trading companies came together to form a fabrication and installation of 100,000 tons special purpose company, Barracuda & of process and utility modules, will also Caratinga Leasing Company B.V. be done by Brazilian contractors. This Halliburton is lending its project manage- high degree of local content, under HALLIBURTON SUBSEA places a pre-fabricated offshore pipeline bundle with its Controlled Depth Tow Method. have proven their worth in managing huge ment and project finance expertise as the Halliburton’s project management, will development and fabrication jobs all over EPIC contractor to facilitate the financing fulfill one of Rio State’s important the world. arrangements for Petrobras. objectives – the growth and revitalization of Recent projects include Exxon Diana in The size and scope of the project are also key sectors of its economy. Halliburton will the Gulf of Mexico, which involved fabri- precedent-setting. The development of also hook up the wells to the FPSOs, com- cating a record-sized production platform these two fields, which together have mission both vessels and subsea and executing horizontal well completions; reserves estimated at 1.2 billion barrels, will systems, and operate the field for the first and the $2 billion Terra Nova field offshore take from late 2000 to the spring of 2004. three months. Newfoundland, which included building Halliburton’s work includes subsurface well Barracuda/Caratinga is the first deepwater one of the largest floating, production, stor- construction and completion, subsea mega-project to be managed by one compa- age and offloading (FPSO) vessels built to manufacturing and installation, and float- ny under one EPIC contract. It solves a cru- date, plus drilling and completing six ing production. cial development and energy supply complex subsea wells. This year saw the The subsurface work will be on 51 wells. problem for the customer, Brazil’s national start of engineering, procurement, installa- Virtually every Halliburton product and oil company, and serves as a demonstration tion and construction (EPIC) work for a service line will take part, with Sperry-Sun of Halliburton’s end-to-end project $300 million offshore oil and gas facility in drilling services and the completions group management and execution capability Nigeria for Shell, including fabrication of a performing the lion’s share of the work. in deep water. H RICHARD D’SOUZA Richard D’Souza joined Halliburton with a clear mission: develop a premier engineering team for deepwater floating production and subsea systems. With his 25 years of experience, his reputation with customers for technical excellence and his team-building success, Richard was the natural choice. “Breakthroughs in deep water will come from a focused, elite engineering group creating technology and execution strategies that will accelerate development. That makes the magic that brings the customers to us. I’m excited to be working with a wonderful team on these challenging projects. Ever since I came to the U.S. as a student from India, I’ve lived by the maxim that some- times you have to go out on a limb, because that’s where the fruit is.” 20 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT DEEP SEA PLATFORM fabrication is just part of Halliburton’s ability to treat deepwater projects with a total systems approach. T E C H N O L O G Y F L A G S H I P S 22 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT T E C H N O L O G Y F L A G S H I P S t KBR’S LNG CAPABILITIES KBR’s unparalleled proprietary process technology, engineering skills and construction infrastructure make it the leader in worldwide gas monetization. urning the world’s abundant supply of of fuel cell technology. Both of these value of efficient, low-cost drilling systems, natural gas into commercial products will emerging industries could further increase such as Geo-Pilot and Anaconda, and grow in importance over the next decade. the demand for natural gas. efficient production technologies, including Clean-burning natural gas is becoming the Increased demand for gas will spur intelligent completions and management of fuel of choice for generating electric power demand for virtually all of Halliburton’s reservoirs to maximize the recovery rate. In in North America. In other regions, liquefied services – energy services as well as addition, the floating technologies used in natural gas (LNG) offers a way to engineering and construction. The tech- deep water – FPSOs, mooring and docking commercialize gas without building a nologies described in the other flagships systems, pipeline and terminal design and pipeline infrastructure. Demand for natural will be valuable in the gas monetization construction – play a large role in developing gas for downstream products, such as business. In addition, the technology lead- natural gas reserves. ammonia, ethylene, and propylene, will ership of the Engineering and Construction However, the largest part of the gas continue to be strong in all regions. Group in gas processing plant technology is monetization flagship is the proprietary And just over the horizon is the prospect a critical part of this flagship. processing technology, the engineering skill of gas to liquids (GTL) technology – the Natural gas exploration and production and the construction infrastructure of conversion of natural gas into premium requires drilling many wells, because the Halliburton’s Kellogg Brown & Root liquid hydrocarbons and other specialty wells often experience rapid rates of business unit, which is described in the products – and the continued development declining production. This points to the following section. H MANFRED PRAMMER Dr. Manfred Prammer is president of NUMAR, the Halliburton division that brought magnetic resonance (MR) technology to the oilfield. An Austrian by birth, a physicist by training, and a teacher by disposition, Manfred heads NUMAR’s team of scientists and engineers developing a range of “disruptive technologies” – paradigm-breaking ideas like MR logging. “NUMAR is unique within Halliburton. This group is not about making incremental improvements to existing technologies – the industry already does that very well. We are looking for breakthroughs that will have a profound, non-linear effect on the energy business. This is exciting, challenging work, and that helps us attract top people.” H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 23 E N G I N E E R I N G & C O N S T R U C T I O N G R O U P 24 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT E N G I N E E R I N G & C O N S T R U C T I O N G R O U P t he Engineering and Construction Group was consolidated into a single busi- ness unit, Kellogg Brown & Root, at the end of 2000. Beginning in 2001, the reor- ganization will be complete, and the com- pany’s financial statements will reflect this change. Energy-related work accounts for the largest portion of the Group’s business. This segment principally serves a wide range of needs in the petroleum industry – designing and building refining and pro- cessing plants, surface facilities and pipelines. This work complements the business of our Energy Services Group, forming a unique, integrated end-to-end capability serving the petroleum industry – subsurface, surface, facilities, and process- ing. The non-energy business of the group uses the same skill set and the same deep corporate resources to meet the needs of governments and civil infrastructure cus- tomers. With the inclusion of the engineering and construction business of Brown & Root Energy Services, KBR has added design, fabrication and installation of offshore production facilities and extensive oil and gas production background to its leadership position in hydrocarbon processing. This combination will be particularly valuable to natural gas customers. KBR already has a strong position in LNG and onshore gas production. Now customers with offshore gas fields have the advantage of dealing with just one company to help them develop, process and transport their gas production, onshore or off. KBR’s competitive advantages begin H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 25 E N G I N E E R I N G & C O N S T R U C T I O N G R O U P with the expertise of its people. The depth in most of the world, especially Asia, where liquefaction plants using a new dynamic and breadth of their experience, and their there are large natural gas reserves to be simulation program that eliminates the ability to marshal that experience to meet developed. inherent over-design that is characteristic of customers’ needs today and in the future are KBR has built, either alone or in joint traditional methods. unmatched in the industry. This pool of ventures, the majority of the world’s LNG Another aspect of natural gas use is in intellectual capital has proven its value by complexes. It is currently working on converting natural gas feedstocks into developing proprietary process technologies large-scale projects at Bonny Island, ammonia for fertilizer. In this area, KBR’s in key areas, and by creating innovations in Nigeria, as well as in Malaysia, Algeria, technologies account for more than half the technology of project execution that Qatar, Australia, Egypt and the Americas. the worldwide production capacity. Recent help KBR design and build faster and Technological advances in LNG are innovations in this area include KAAPplus™ better. Added to this intellectual capital is typically efficiencies in the engineering of – a complete, state-of-the art process tech- the financial strength and the ability to take large plants and equipment rather than nology that combines the KBR Advanced on large lump-sum projects that are beyond breakthroughs in process technologies. In Ammonia Process (KAAP), the KBR the range of other competitors. this area, KBR’s breadth of experience and Reforming Exchanger System (KRES™), Natural Gas roster of specialists put it in an excellent and the Braun Purifier. Monetization of natural gas is a critical need for the energy industry as a whole, a flagship technology for Halliburton, and a particular area of expertise for KBR. Natural gas development includes liquefied natural gas (LNG), ammonia, and olefins – ethylene and propylene. LNG is particularly important, as it represents the only current commercially feasible way of using stranded gas – natural gas where pipeline infrastructure does not exist and is not practical. This is the case UNMATCHED IN THE INDUSTRY, KBR people provide the clear advantage in the most important area: intellectual capital. EXACTING CRAFTSMANSHIP is never compromised, no matter where in the world KBR works. For decades, non-stop innovation and quality – coupled with an unrivaled dedication to health, safety and environmental protection – have kept KBR out in front. position to continue capturing a major In olefins, KBR’s Selective Cracking share of future LNG engineering and Optimum Recovery (SCORE™) process, construction business. combining portions of KBR’s and KBR has established a position as one of ExxonMobil Chemical’s ethylene tech- the preferred providers due to its reputation nologies, will be licensed to Thai Olefins. for helping clients deliver the lowest cost This plant, which will be built in partner- LNG. In 2000, KBR added to its position ship with Chiyoda of Japan, will be the first with a series of design firsts for the Ras new ethylene project in Asia since the Laffan Onshore Facilities Project in Qatar, recent recession. A letter of intent was including built-in reliability and maintain- signed in 2000, and project completion is ability in the design. KBR engineers also scheduled for 2004. developed a new way of designing LNG This year also saw the mechanical com- 26 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT E N G I N E E R I N G & C O N S T R U C T I O N G R O U P KELLOGG BROWN & ROOT pletion of the ExxonMobil Olefins Project low-value, low-octane light gasoline streams were selected by OMV Deutschland in Singapore. KBR and Chiyoda provided into propylene and ethylene by a catalytic GmbH for production of premium diesel the basic design, engineering, procurement process. This new offering responds to fuel in its refinery at Burghausen, Germany. and construction for this 800,000-ton-a-year customer needs to find alternative uses for When completed, the plant will process ethylene plant under a lump-sum contract the feedstocks that are now producing atmospheric distillate and gas oil feedstocks which, along with ancillary work, was about methyl tertiary butylether (MTBE) for to produce high-quality diesel fuel with less half the $2 billion Singapore Chemical gasoline. As MTBE is phased out for than 10 ppmw sulfur content. KBR per- Plant. This project uses the ExxonMobil environmental reasons, Superflex will formed basic engineering design for the low-residence-time cracking technology provide customers a valuable option for unit as part of its work with the Alliance. that is now part of KBR’s SCORE offering. upgrading these low-value products. KBR In 2000, KBR formed an alliance with In propylene, KBR acquired an exclusive has made this technology available for license, Fortrum Oil and Gas Oy of Finland to offer license in 2000 from Lyondell for its with the first contracts expected in 2001. NExOCTANE, a new process technology SuperflexSM technology. Superflex converts Clean Fuels The production of clean fuels for high-octane gasoline. NExOCTANE CHARLES DURR Charlie Durr has spent over 30 years helping to make KBR the leading builder of LNG plants. From his current position as Technology Vice President for LNG, Gas Processing and Gas to Liquids, he oversees strategy, technology, and risk manage- is another area of focus solves the problem of how to eliminate for proprietary tech- MTBE in gasoline production. The new nology. Increasingly technology allows refiners to convert their stringent standards in existing MTBE production facilities the U.S., European to isooctane, a cost-effective replacement Union and elsewhere for MTBE. KBR will offer this require refiners to technology for license and will provide continuously improve engineering and continuing technical sup- particulate and gaseous port to licensees. ment. “We’re successful because our people can build complex pro- emissions. Innovative Business Processes jects in challenging locations. We know every part of the business – The MAKfining™ KBR is also offering a broader range of designing and building the plants, and dealing with the realities of s c h e d u l e , vendors, and client expectations. We learn how to manage risks, and how to look for opportunities to innovate. Each project is an occasion Premium Distillate services aimed at creating and structuring Technologies intro- successful engineering and construction duced in 1999 by the projects. The company has joined to develop our people. That’s what I learned playing stickball in MAKfining Alliance with Mitsubishi Corporation to offer cus- H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 27 E N G I N E E R I N G & C O N S T R U C T I O N G R O U P KBR'S PROJECT EXECUTION TECHNOLOGY helps win EPC contracts in many petrochemical processing industries. comprehensive, innovative approaches to choosing process technologies, securing project funding, building plants and infrastructure, and developing markets. Project Execution Technology Project execution technology – finding ways to remove time and cost from projects through better ways to use the organization’s intellectual capital – is the extra dimension that complements KBR’s excellence in process engineering and creates value in unexpected ways. In 2000, KBR developed a breakthrough in high-tech work processes with 3-D Conceptual™ – a collaborative work environment that enables a multidisciplinary team to visual- ize front-end engineering designs in 3-D. It is a work process that uses KBR’s historical database of design experience to tomers a range of innovative business relationships through KBR Development Corporation (KBRDC), which landed its THE FARMLAND MISSCHEM LTD. AMMONIA PLANT in Trinidad produces 1,850 metric tons of ammonia per day. first project in 2000. KBRDC brings together owners of feedstocks, funding sources, and potential end users to put together workable projects. As a facilitator or developer, KBRDC draws on the global resources of its partners to support the development of projects in all the industries served by KBR. The first fruit of the KBRDC effort was in Trinidad, where KBR was awarded multiple contracts from Ferrostaal Aktiegensellschaft of Germany and Caribbean Nitrogen Company Ldg. of Trinidad and Tobago to provide technology licenses, basic engineering design and other services for an ammonia plant using KBR’s KAAP process. KBRDC is using the same approach in other parts of the world where feedstocks exist and customers need 3-D CONCEPTUAL enables a design team to visualize front-end engineering designs in 3-D. create a 3-D model that enables early collaboration at the start of the design process. It brings together the knowledge and experience of KBR engineers in applying low-cost reference designs. The 3-D visualization gives early and improved feed- back to determine the cost implications of design decisions, and allows the process engineer to interact with construction, maintenance, piping, and other engineering groups at project conception. 3-D Conceptual has the potential to drastically reduce the time required for the engineering process, collapsing sequential steps that traditionally take months into parallel activities that take weeks. Similarly, it offers a better way to determine and control project costs, 80% of which are determined in the front- end phase. H 28 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT E N G I N E E R I N G & C O N S T R U C T I O N G R O U P THE LNG PLANT AT WOODSIDE, Northwestshelf, Australia, designed by a KBR joint venture, uses air instead of water as the primary cooling medium – a first in LNG production. H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 29 H E A L T H , S A F E T Y & E N V I R O N M E N T 30 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT H E A L T H , S A F E T Y & E N V I R O N M E N T alliburton’s customers, especially strong implications for stock price H A business model that integrates HSE those working in new and remote performance. Back-test evidence indicates into the core company business develop- h areas, need a service company that will help that a diversified portfolio of environmen- ment activities. them reduce their risks, and they are plac- tally high-performing companies can be H Highly regarded HSE Management ing increasing emphasis on environmental expected to outperform its less efficient System. matters when issuing contracts. Customers competitors. It has been estimated that H Superior performance on emissions also need a service company that will help environmental excellence turns out to be an and spills. them achieve their goals in the areas of the extraordinarily good proxy for — and H Taking the lead in setting emission triple bottom line — financial performance, predictor of — superior corporate manage- reduction goals via energy conservation social benefit, and environmental protec- ment, which in turn generates financial measures. tion. Halliburton is committed to integrat- outperformance and shareholder value. H Developing the world’s first biodegradable ing social equity concerns into its business Halliburton’s outstanding environmen- invert emulsion drilling fluid system. decision-making, capturing of the value tal performance is demonstrated by: through improved stakeholder relations, H Genuine commitment by Board and H Engaging in R&D for CO2 sequestration and the reduction of flaring in gas and reducing the company’s overall senior management. processing. H environmental footprint. Halliburton’s con- tinuing commitment to being the environ- mental partner of choice is an asset in competing for business. And for investors, environmental performance can be a source of hidden value potential. Among other things, it measures environmental risk exposure, the ability to manage risk, and the ability to capitalize on environmentally driven business opportunities. These in turn have Lost Time Incident Rates (per 200,000 work hours) Halliburton Company vs. OSHA Industry Sector Averages* Recordable Incident Rates (per 200,000 work hours) Halliburton Company vs. OSHA Industry Sector Averages* 1.02 1997 0.88 1998 0.65 1999 0.56 2000 Halliburton 1.8 9 9 9 1 s a G & l i O 3.8 9 9 9 1 . s n o C & . g n E 4.6 g 9 n 9 i 9 r u 1 t c a f u n a M 3.12 1997 2.21 1998 1.77 1999 1.72 2000 Halliburton 3.5 9 9 9 1 s a G & l i O 7.8 9 9 9 1 . s n o C & . g n E 9.2 g 9 n 9 i 9 r u 1 t c a f u n a M In 2000, Halliburton continued to make improvements in both recordable and lost-time incident rates. Our performance, frequently in harsh and hazardous working conditions, compares very favorably with that of our industry peers. *1999 OSHA data is most recent data available H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 31 H A L L I B U R T O N C O M P A N Y F I N A N C I A L I N F O R M A T I O N financial information 32 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S In this section, we discuss the operating results and general financial condition of Halliburton Company and its subsidiaries. We explain: these factors to cause increasing demand for oil and gas needed for refined products, petrochemicals, fertilizers, power, and other needs. • factors and risks that impact our business; • why our earnings and expenses for the year 2000 differ from the years 1999 and 1998; • capital expenditures; • factors that impacted our cash flows; and • other items that materially affect our financial condition or earnings. BUSINESS ENVIRONMENT Our continuing business is organized around two business segments: • Energy Services Group; and • Engineering and Construction Group. We also report the results of a third business segment, Dresser Equipment Group, as discontinued operations. As the largest provider of products and services to the petroleum and energy industries, the majority of the consolidated revenues are derived from the sale of services and products to large oil and gas companies. We conduct business in over 120 countries with energy, industrial and governmental customers. These services and products are used in the earliest phases of exploration and development of oil and gas reserves through the refining and distribution process. The industries we serve are highly competitive with many substantial competitors for each segment. No country other than the United States or the United Kingdom accounts for more than 10% of our operations. Unsettled political conditions, expropriation or other governmental actions, exchange controls and currency devaluations may result in increased business risk in any one country, including, among others, Algeria, Angola, Libya, Nigeria, and Russia. 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 The year 2000 showed increased activity in the North American energy services environment. The international recovery from 1999 levels is expected to materialize in 2001. The engineering and construction business remains hampered by lower customer commitments; however, we believe the long-term fundamentals remain sound. Rising populations in many countries and greater industrialization efforts should continue to propel worldwide economic expansion, especially in developing nations. We expect Energy Services Group During 2000, the demand for the group’s oilfield services and products recovered from lower levels in 1999 and late 1998. Consistent with past history, the activity levels in the United States were the first to rebound with increased demand for products and services and an improved pricing environment. International activity began to improve in the second half of 2000. Growth in our business was driven primarily by increased rotary rig count on natural gas wells in North America. The rotary rig count, which is an indicator of activity, hit near-term record highs for the third and fourth quarters after a brief drop in the first half of the year. Some experts project that the average rig count for 2001 will increase over 20% as compared to 2000. If forecasts prove to be accurate, this would be the highest level of activity in North America since 1985. This growth should have a favorable impact for the Energy Services Group. Crude oil prices remained at or near record highs throughout 2000, with West Texas Intermediate ending the year at over $32 per barrel. Natural gas prices continued to climb as a result of North America experiencing the coldest weather in recent years and low volumes of gas in storage. Henry Hub gas prices averaged $6.20/MCF in the fourth quarter of 2000 and $8.12/MCF for the month of December with occasional spikes over $10.00/MCF during the month. For the year, Henry Hub gas prices averaged $4.20/MCF compared to $2.27/MCF in 1999. We believe the continued high commodity prices bode well for the industry and should encourage our customers to increase investments in exploration and production. Internationally, our business activity levels have not increased as much as in North America, although customers who are focused on oil projects are now starting to increase their global capital spending. The turnaround in international rig activity continued in the fourth quarter, with the highest average rig count since 1998 at 710 rigs working compared to 576 in 1999. However, we do not expect to see any significant increase in larger capital-intensive field development projects outside North America until the second half of 2001. The merger and consolidation activities of a number of large customers over the past two years have affected the demand for our products and services. The companies that have merged continue to evaluate their oil and gas properties, refining and distribution facilities, and organizations. This evaluation process has translated into a short-term reluctance to undertake new investments resulting in a lower demand for some of our products and services in 2000, especially outside North America. H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 33 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S Engineering and Construction Group Most of the factors that adversely affected the Energy Services Group in 1999 and 1998 also affected the Engineering and Construction Group since over half of the group’s revenues come from customers in the oil and gas industry. We believe the higher rig counts experienced in the second half of 2000 and expected for 2001 should begin to positively impact the Engineering and Construction Group six to 12 months after the Energy Services Group. Customers of the group are more reluctant to start large capital projects, including refineries and petrochemical plants, during periods of uncertain oil prices. Merged customers ration- alizing and optimizing their existing capabilities have further delayed project starts. The group has seen a number of large potential projects deferred because of uncertain prices for petroleum products. The group is beginning to experience an increase in inquiries for bids and proposals for potential new projects, including several large international liquefied natural gas projects. The Engineering and Construction Group has continued to expand its services to the military – both in the United States and abroad. The group sees improving opportu- nities to provide additional support services to other United States agencies and to government agencies of other countries, including the United Kingdom. The demand for these services is expected to grow as governments at all levels seek to control costs and improve services by outsourcing various functions. RESULTS OF OPERATIONS IN 2000 COMPARED TO 1999 AND 1998 REVENUES Millions of dollars Energy Services Group Engineering and Construction Group Total revenues 2 0 0 0 $ 7 , 9 1 6 1999 $ 6,999 1998 $ 9,009 4 , 0 2 8 $ 11 , 9 4 4 5,314 $12,313 5,495 $14,504 Revenues for 2000 were $11,944 million, a decrease of 3% from 1999 revenues of $12,313 million and a decrease of 18% from 1998 revenues of $14,504 million. In regard to 2000 compared to 1999, lower levels of engineering and construction revenues in both segments were partially offset by increased oilfield services revenues within the Energy Services Group, particularly in the United States. In regard to 2000 compared to 1998, the decline was experienced in both segments. While our oilfield services business recovered substantially during 2000, activity levels were still about 10% lower than in 1998. The 2000 total engineering and construction activity within both segments was off almost 25% as compared to 1998 as customers continued to postpone most major new investments. International revenues were 66% of our consolidated revenues in 2000, compared with 70% in 1999 and 68% in 1998. Energy Services Group revenues were $7,916 million for 2000, an increase of 13% from 1999 revenues of $6,999 million and a decrease of 12% from 1998 revenues of $9,009 million. International revenues were 66% of total segment revenues in 2000 compared with 71% in 1999 and 67% in 1998. Revenues for the group were positively impacted in late 1999 and throughout 2000 by increased rig counts and customer spending, particularly within North America, following increases in oil and gas prices that began in 1999. Increased demand for natural gas and increased drilling activity positively benefited our oilfield services product service lines. The pressure pumping and logging product service lines achieved revenue growth of 30% and 27%, respectively, compared to 1999. Drilling fluids increased over 20%, while drill bits and completion products service lines increased about 14%. Drilling systems service line revenues increased by 7%. Geographically, strong North American activity resulted in revenue growth of 43%, with growth experienced across all product service lines in that region compared to 1999. North America generated 52% of total oilfield service product service line revenues for 2000 compared to 44% in 1999. Pressure pumping accounted for approximately 50% of the increase in revenues within North America, reflecting higher activity levels in all work areas, particularly the Gulf of Mexico, South Texas, Canada, and Rocky Mountains. Revenues in the Middle East and Latin America regions increased 16% and 12%, respectively, compared to 1999. Europe/Africa revenues were up slightly while revenues in the Asia Pacific region declined by 3%. Activity was slower to increase internationally throughout 2000 despite higher oil and gas prices. The turnaround in international rig activity, which started late in the second quarter of 2000, continued into the fourth quarter of 2000 when international rig counts reached the highest levels since late 1998. Revenues also increased across all regions outside North America during the fourth quarter of 2000, as customer spending for exploration and production began to increase outside North America. Revenues from upstream oil and gas engineering and construction services declined 2% in 2000 compared to 1999 and about 20% compared to 1998. The decrease in 2000 reflects the continued delay in engineering and construction project spending by our customers. Upstream engineering and construction business revenues benefited in 2000 from deepwater projects in Latin America, particularly Mexico, and Africa, reflecting the continued shift in work out of the North Sea and into Latin America, Africa and Asia Pacific. In 1998, revenues from upstream oil and gas engineering and construction services benefited from large projects and from activities in the subsea, pipecoating and flexible pipe product service lines. for Revenues integrated exploration and production information systems reached record high levels in 2000, breaking the previous high set in 1998. Revenues from integrated exploration and production information systems increased 13% compared to 1999, and increased slightly over 1998. Increases in 34 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S software and professional services revenues were partially offset by lower hardware revenues, which have been de-emphasized. Software sales contributed just over 19% in revenue growth, while professional services increased over 7% compared to 1999. In 1999 many customers for our information system product lines put off software purchases due to customers’ consolidations, lower activity levels and internal focus on Year 2000 issues. Engineering and Construction Group revenues were $4,028 million for 2000, down 24% from $5,314 million in 1999 and down 27% from 1998 revenues of $5,495 million. Higher oil and gas prices during 2000 did not translate into customers proceeding with new awards of large downstream projects. Many other large projects, primarily gas and liquefied natural gas projects, were also delayed, continuing a trend that started in 1999. In 1999 the group increased logistics support services to military peacekeeping efforts in the Balkans and increased activities at the Devonport Dockyard in the United Kingdom. The logistics support services to military peacekeeping efforts in the Balkans peaked in the fourth quarter of 1999 as the main construction and procurement phases of the contract were completed. These increases partially offset lower revenues from engineering and construction projects, particularly major projects in Europe and Africa, which were winding down. Revenues for the group in 1998 reflect higher liquefied natural gas project revenues in Asia and Africa, an enhanced oil recovery project in Africa, and a major ethylene project in Singapore. OPERATING INCOME Millions of dollars Energy Services Group Engineering and Construction Group General corporate Special charges and credits Operating income 2 0 0 0 $ 5 2 6 1 4 ( 7 8 ) (cid:209) $ 4 6 2 1999 $222 203 (71) 47 $401 1998 $971 237 (79) (959) $170 Operating income was $462 million for 2000 compared to $401 million for 1999 and $170 million for 1998. Business segment results include restructuring charges of $36 million in 2000 related to the restructuring of the engineering and construction businesses. See Note 11. Excluding special credits of $47 million in 1999 and special charges of $959 million during 1998, operating income for 2000 increased by 31% from 1999 and decreased 59% from 1998. See Note 12. Energy Services Group operating income in 2000 was $526 million, an increase of 137% from 1999 operating income of $222 million and a decrease of 46% compared to 1998 operating income of $971 million. Operating margins were 6.6% in 2000, up from 3.2% in 1999 and down from 10.8% in 1998. Approximately 33% of the Energy Services Group’s operating income was derived from international activities for 2000, compared with 54% in 1999 and 1998. During 2000, strengthening North American drilling and oilfield activity resulted in increased equipment utilization and improved pricing within the oilfield services product service lines. Pressure pumping operating income increased about 135% compared to 1999 levels, which were down about 70% compared to 1998, while logging services operating income increased by over 200% compared to 1999. Drilling fluids, drilling systems and completion products were impacted by slow recovery in international activity. During the fourth quarter of 2000, oilfield services recorded an $8 million reversal of bad debts related to claims settled by the United Nations against Iraq dating from the invasion of Kuwait in 1990. Geographically, strong oil and gas prices throughout 2000 led to higher levels of deepwater and onshore gas drilling within North America. Activity increases in the Gulf of Mexico, South Texas, Canada, and Rocky Mountain work areas were greater than most other areas. Operating income outside North America continued to lag the performance noted within North America, reflecting continued delays in international exploration and production for oil and gas. On a positive note, fourth quarter 2000 operating income increased across all international geographic regions compared to the third quarter, reflecting increased international spending by our customers. Operating income in 2000 for upstream oil and gas engineering and construction activities declined by 5% compared to 1999 and 73% compared to 1998. Projects and workloads are increasingly shifting from the North Sea to Latin America, Africa and Asia Pacific. Operating income benefited in 2000 from a third quarter $88 million gain on sale of two semi-submersible vessels and one multipurpose support vessel. Lower activity levels in the North Sea, particularly in the United Kingdom sector, negatively impacted operating income in 2000 and 1999 through lower utilization of engineering staff, as well as under utilization of manufacturing and fabricating capacity and subsea equipment and vessels, which carry large fixed costs. Given the number and technical complexity of the engineering and construction projects we perform, some project losses are normal occurrences. However, the environment for negotiations with customers on claims and change orders has become more difficult in the past few years. This environment, combined with performance issues on a few large, technically complex jobs, contributed to unusually high job losses on major projects of $82 million in 2000, including $48 million in the fourth quarter, $77 million in 1999 and $99 million in 1998. In addition, the upstream oil and gas engineering and construction business recorded $11 million of restructuring charges in 2000. Operating income from integrated exploration and production information systems in 2000 increased almost 200% compared to 1999. Operating income in 2000 and 1999 was lower than 1998 due to lower software sales volumes in 1999 and change in the software license product mix from perpetual license sales for which income is recognized at the time of sale to annual access H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 35 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S licenses where income is recognized over the license period. Engineering and Construction Group operating income for 2000 of $14 million decreased $189 million, or 93% from 1999 and about $223 million, or 94% from 1998. The operating margin was just above zero in 2000 down from 3.8% in 1999 and 4.3% for 1998. Operating margins in 2000 declined both internationally and in North America due to losses on projects as a result of higher than estimated costs on selected jobs and claims negotiations on other jobs not progressing as anticipated. In the fourth quarter of 2000, job losses of $109 million were recorded as a result of these conditions. At the same time, the group recorded $25 million of restructuring charges. Lower activity due to the trend in delayed new projects, which continued through the year, also negatively impacted operating income. Operating income in 1999 benefited from higher activity levels supporting United States military peacekeeping efforts in the Balkans, offset by reduced engineering and construction project profits due to the timing of project awards and revenue recognition. Operating income in 1998 includes $16 million favorable settlement of a claim on a Middle Eastern construction project. Special credits in 1999 are the result of a change in estimate on some components of the 1998 special charges. We continuously monitor the actual costs incurred and reexamine our estimates of future costs. In the second quarter of 1999, we concluded that total costs, particularly for severance and facility exit costs, were lower than previously estimated. Therefore, we reversed $47 million of the $959 million special charge that was originally recorded. See Note 12. General corporate expenses for 2000 were $78 million, an increase of $7 million from 1999 and down $1 million compared to 1998. In 2000 general corporate expenses increased primarily as a result of costs related to the early retirement of our previous chairman and chief executive officer. In 1998 general corporate expenses of $79 million included expenses for operating Dresser’s corporate offices as well as our corporate offices. As a percent of consolidated revenues, general corporate expenses were 0.7% in 2000, 0.6% in 1999 and 0.5% in 1998. NONOPERATING ITEMS Interest expense was $146 million for 2000 compared to $141 million in 1999 and $134 million in 1998. Interest expense was up in 2000 due to higher average interest rates on short-term borrowings and additional short-term debt used to repurchase $759 million of our common stock under our share repurchase program, mostly during the fourth quarter. These increases offset the benefits from our lower borrowings earlier in 2000 due to the use of the proceeds from the sale of Ingersoll-Dresser Pump and Dresser-Rand to repay short-term debt. Interest income of $25 million declined $49 million from 1999 and was about the same as 1998. Interest income in 1999 included settlement of income tax issues in the United States and United Kingdom and imputed interest income on the note receivable from the sale of our ownership in M-I L.L.C. Foreign currency gains (losses) netted to a loss of $5 million, down from losses of $8 million in 1999 and $10 million in 1998. The losses in 2000 were primarily in Asia Pacific currencies and the euro. Losses in 1999 occurred primarily in Russian and Latin American currencies. Losses in 1998 occurred primarily in Asia Pacific currencies. Other, net in 2000 was a net loss of $1 million compared to a net loss of $19 million in 1999 and a net gain of $3 million in 1998. The net loss in 1999 includes a $26 million charge in the second quarter relating to an impairment of Kellogg Brown & Root’s net investment in Bufete Industriale, S.A. de C.V., a large specialty engineering, procurement and construction company in Mexico. Provision for income taxes on continuing operations was $129 million for an effective tax rate of 38.5%, compared to 37.8% in 1999 and 281.8% in 1998. Excluding our special charges and related taxes, the effective rate was 38.8% in 1999 and 37.8% in 1998. Minority interest in net income of subsidiaries was $18 million in 2000 compared to $17 million in 1999 and $20 million in 1998. Income from continuing operations was $188 million in 2000 and $174 million in 1999. In 1998 continuing operations was a loss of $120 million. Income from discontinued operations was $98 million in 2000, $124 million in 1999 and $105 million in 1998. Gain on disposal of discontinued operations resulting from the sale of our 51% interest in Dresser-Rand was $215 million after-tax or $0.48 per diluted share in 2000. In 1999 we recorded a gain on the sale of our 49% interest in Ingersoll-Dresser Pump of $159 million after-tax or $0.36 per diluted share. Cumulative effect of change in accounting method in 1999 of $19 million after-tax, or $0.04 per diluted share, reflects our adoption of Statement of Position 98-5, “Reporting on the Costs of Start-Up Activities.” See Note 13. Net income in 2000 was $501 million or $1.12 per diluted share and in 1999 was $438 million or $0.99 per diluted share. In 1998 the net loss of $15 million resulted in $0.03 loss per diluted share. LIQUIDITY AND CAPITAL RESOURCES We ended 2000 with cash and equivalents of $231 million compared with $466 million in 1999 and $203 million in 1998. Cash flows from operating activities used $57 million for 2000 compared to $58 million used for 1999 and provided $150 million for 1998. Working capital items, which include receivables, inventories, accounts payable and other working capital, net, used $563 million of cash in 2000 compared to 36 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S providing $2 million in 1999 and using $533 million in 1998. Included in changes to working capital and other net changes are special charge usage for personnel reductions, facility closures, merger transaction costs, and integration costs of $54 million in 2000 and $202 million in 1999 and $112 million in 1998. Cash flows used in investing activities were $411 million for 2000, $107 million for 1999 and $790 million for 1998. Capital expenditures of $578 million in 2000 were about 11% higher than in 1999 and about 31% lower than in 1998. Capital spending was mostly for equipment for Halliburton Energy Services, which included investing in cementing equipment designed to integrate our pumping and mixing systems with new safety and technological features. Cash flows from investing activities in 1999 include $254 million collected on the receivables from the sale of our 36% interest in M-I L.L.C. Imputed interest on this receivable of $11 million is included in operating cash flows. In 1998, net cash used for investing activities includes various acquisitions of businesses of approximately $40 million. Cash flows from financing activities used $584 million in 2000 and provided $189 million in 1999 and $267 million in 1998. We repaid $308 million on our long-term debt in 2000. Net short- term borrowings consisting of commercial paper and bank loans provided $629 million in 2000. Proceeds from exercises of stock options provided cash flows of $105 million in 2000 compared to $49 million in 1999 and 1998. Dividends to shareholders used $221 million of cash in 2000 and 1999. In April 2000 our Board of Directors approved a plan to implement a share repurchase program. As of December 31, 2000 we had repurchased over 20 million shares at a cost of $759 million. In addition, we repurchased $10 million of common stock both in 2000 and 1999 and $20 million in 1998 from employees to settle their income tax liabilities primarily for restricted stock lapses. We may periodically repurchase our common stock as we deem appropriate. Cash flows from discontinued operations provided $826 million in 2000 as compared to $234 million and $235 million in 1999 and 1998, respectively. Cash flows for 2000 include proceeds from the sale of Dresser-Rand and Ingersoll- Dresser Pump of approximately $913 million. Capital resources from internally generated funds and access to capital markets are sufficient to fund our working capital requirements, share repurchases and investing activities. Our combined short-term notes payable and long- term debt was 40%, 35% and 32% of total capitalization at the end of 2000, 1999 and 1998, respectively. 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 and increased short-term debt in the fourth quarter to fund share repurchases. We plan to use proceeds from the Dresser Equipment Group sale to pay down debt recently incurred for the repurchase of our shares. This should return the debt-to-capitalization ratio to the 30% to 35% range by the end of the second quarter of 2001. 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 hedge these exposures through the use of derivative instruments to mitigate our market risk from these exposures. The objective of our hedging is to protect our cash flows related to sales or purchases of goods or services from 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 our hedging activities to be material. See Note 1 for additional information on our accounting policies on derivative instruments. See Note 17 for additional disclosures related to derivative instruments. RESTRUCTURING ACTIVITIES While oil and gas prices have continued to maintain the strength that provides positive uplift to our oilfield services and integrated exploration and production information systems businesses, our engineering and construction businesses continue 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 are not positive. The continued delays of upstream and downstream projects, and the resulting decrease in our backlog and levels of work, will make it difficult to achieve acceptable margins in 2001 in our engineering and construction businesses. Accordingly, in the fourth quarter of 2000 we approved a plan to re-combine all of our engineering and construction businesses into one business unit. As a result of the reorgani- zation of the engineering and construction businesses, we took actions to rationalize our operating structure including write- offs of equipment, engineering reference designs and capitalized software of $20 million and recorded severance costs of $16 million. During the third and fourth quarters of 1998, we incurred special charges totaling $980 million related to the Dresser merger and industry downturn, of which $21 million has been recorded in discontinued operations. During the second quarter of 1999, we reversed $47 million of our 1998 special charges based on our reassessment of total costs to be incurred to complete the actions covered in the charges. H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 37 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S We have in process a program to exit approximately 500 properties, including service, administrative and manufacturing facilities. We accrued expenses to exit approximately 400 of these properties in the 1998 special charges. Most of these properties are within the Energy Services Group. Through December 31, 2000 we have vacated 97% of the approximate 500 total facilities. We have sold or returned to the owner 94% of the vacated properties. ENVIRONMENTAL MATTERS We are subject to numerous environmental legal and regulatory requirements related to our operations worldwide. As a result of those obligations, we are involved in specific environmental litigation and claims, the clean-up of properties we own or have operated, and efforts to meet or correct compliance-related matters. See Note 9. 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 annual report are forward-looking. 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. Forward-looking information we provide reflects our best judgement based on current information. Our results of operations can be affected by inaccurate assumptions we make or by known or unknown risks and uncertainties. In addition, other factors may affect the accuracy of our forward-looking information. As a result, no forward-looking information can be guaranteed. Actual events and the results of operations may vary materially. 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 including: Geopolitical and legal. • trade restrictions and economic embargoes imposed by the United States and other countries; • unsettled political conditions, war, civil unrest, currency controls and governmental actions in the numerous countries in which we operate; • operations in countries with significant amounts of political risk, including, for example, Algeria, Angola, Libya, Nigeria, and Russia; - encourage or mandate hiring local contractors; and - require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction; • litigation, including, for example, asbestos litigation and environmental litigation; and • environmental laws, including, for example, those that require emission performance standards for facilities; Weather related. • the effects of severe weather conditions, including, for example, hurricanes and tornadoes, on operations and facilities; and • the impact of prolonged severe or mild weather conditions on the demand for and price of oil and natural gas; Customers and vendors. • the magnitude of governmental spending and outsourcing for military and logistical support of the type that we provide; • 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 in the oil and gas industry; and • claim negotiations with engineering and construction customers on cost variances and change orders on major projects; Industry. • technological and structural changes in the industries that we serve; • changes in the price of oil and natural gas, including: - 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; - - - • changes in the price or the availability of commodities that we use; • risks that result from entering into fixed fee engineering, procurement and construction projects of the types that we provide where failure to meet schedules, cost estimates or performance targets could result in non-reimbursable costs which cause the project not to meet our expected profit margins; • risks that result from entering into complex business arrangements for technically demanding projects where failure by one or more parties could result in monetary penalties; and • changes in foreign exchange rates; • changes in governmental regulations in the numerous countries in which we operate including, for example, regulations that: • the risk inherent in 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: 38 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S - adverse movements in foreign exchange rates, interest OTHER ISSUES - rates, or commodity prices, or the value and time period of the derivative being different than the exposures or cash flows being hedged; Personnel and mergers/reorganizations/dispositions. • increased competition in the hiring and retention of employees in specific areas, including, for example, energy services operations, accounting and finance; • 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 reorganizing operations and personnel within Halliburton; • replacing discontinued lines of businesses with acquisitions that 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. We do advise you to review any additional disclosures we make in our 10-Q, 8-K and 10-K reports to the Securities and Exchange Commission. We also suggest that you listen to our quarterly earnings release conference calls with financial analysts. Conversion to the Euro Currency On January 1, 1999, some member countries of the European Union established fixed conversion rates between their existing currencies and the European Union’s common currency (euro). This was the first step toward transition from existing national currencies to the use of the euro as a common currency. The transition period for the introduction of the euro ends June 30, 2002. Issues resulting from the introduction of the euro include converting information technology systems, reassessing currency risk, negotiating and amending existing contracts and processing tax and accounting records. We are addressing these issues and do not expect the euro to have a material effect on our financial condition or results of operations. Implementation of SAB 101 The Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin (SAB) 101, “Revenue Recognition in Financial Statements,” in December 1999. The SAB summarizes some of the SEC staff’s views in applying generally accepted accounting principles to revenue recognition in financial statements. We have completed a thorough review of our revenue recognition policies and determined that our policies are consistent with SAB 101. Accounting Change In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (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 statement of financial position as assets or liabilities and to measure the instruments at fair value. Accounting for gains and losses from changes in those fair values are specified in the standard depending on the intended use of the derivative and other criteria. We have completed our review of contracts for embedded derivatives and evaluated our accounting policies for derivatives and hedging activities. We adopted SFAS 133 effective January 2001 and determined the initial adoption did not have a material effect on our financial condition or results of operations. H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 39 R E P O R T O F I N D E P E N D E N T P U B L I C A C C O U N T A N T S TO THE SHAREHOLDERS AND BOARD OF DIRECTORS HALLIBURTON COMPANY: We have audited the accompanying consolidated balance sheets of Halliburton Company (a Delaware corporation) and subsidiary companies as of December 31, 2000 and 1999, and the related consolidated statements of income, cash flows, and shareholders’ equity for each of the three years in the period ended December 31, 2000. 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. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Halliburton Company and subsidiary companies as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Dallas, Texas, January 30, 2001 (Except with respect to the matters discussed in Notes 9 and 19, as to which the date is March 23, 2001.) 40 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT R E S P O N S I B I L I T Y F O R F I N A N C I A L R E P O R T I N G We are responsible for the preparation and integrity of our published financial statements. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States and, accordingly, include amounts based on judgements and estimates made by our management. We also prepared the other information included in the annual report and are responsible for its accuracy and consistency with the financial statements. The financial statements have been audited by the independent accounting firm, Arthur Andersen LLP. Arthur Andersen was given unrestricted access to all financial records and related data, including minutes of all meetings of stockholders, the Board of Directors and committees of the Board. Halliburton’s Audit Committee of the Board of Directors consists of directors who, in the business judgement of the Board of Directors, are independent under the New York Exchange listing standards. The Board, operating through its Audit Committee, provides oversight to the financial reporting process. Integral to this process is the Audit Committee’s review and discussion with management and the external auditors of the quarterly and annual financial statements prior to their respective filing. We maintain a system of internal control over financial reporting, which is intended to provide reasonable assurance to our management and Board of Directors regarding the reliability of our financial statements. The system includes: report recommendations Internal auditors monitor the operation of the internal control system and to findings and management and the Board of Directors. Corrective actions are taken to address control deficiencies and other opportunities for improving the system as they are identified. In accordance with the Securities and Exchange Commission’s new rules to improve the reliability of financial statements, our interim financial statements are reviewed by Arthur Andersen LLP. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even an effective internal control system can provide only reasonable assurance with respect to the reliability of our financial statements. Also, the effectiveness of an internal control system may change over time. We have assessed our internal control system in relation to criteria for effective internal control over financial reporting described in “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon that assessment, we believe that, as of December 31, 2000, our system of internal control over financial reporting met those criteria. HALLIBURTON COMPANY by • a documented organizational structure and division of responsibility; • established policies and procedures, including a code of conduct to foster a strong ethical climate which is communicated throughout the company; and • the careful selection, training and development of our people. David J. Lesar Chairman of the Board, President and Chief Executive Officer Gary V. Morris Executive Vice President and Chief Financial Officer H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 41 C O N S O L I D A T E D S T A T E M E N T S O F I N C O M E Years ended December 31 (Millions of dollars and shares except per share data) REVENUES: Services Sales Equity in earnings of unconsolidated affiliates Total revenues OPERATING COSTS AND EXPENSES: Cost of services Cost of sales General and administrative Gain on sale of marine vessels Special charges and credits Total operating costs and expenses OPERATING INCOME Interest expense Interest income Foreign currency losses, net Other, net INCOME FROM CONTINUING OPERATIONS BEFORE TAXES, MINORITY INTEREST, AND CHANGE IN ACCOUNTING METHOD Provision for income taxes Minority interest in net income of subsidiaries Income (loss) from continuing operations before change in accounting method DISCONTINUED OPERATIONS: Income from discontinued operations, net of tax of $60, $98, and $90 Gain on disposal of discontinued operations, net of tax of $141 and $94 Income from discontinued operations Cumulative effect of change in accounting method, net of tax benefit of $11 Net income (loss) BASIC INCOME (LOSS) PER SHARE: Income (loss) from continuing operations before change in accounting method Income from discontinued operations Gain on disposal of discontinued operations Change in accounting method Net income (loss) DILUTED INCOME (LOSS) PER SHARE: Income (loss) from continuing operations before change in accounting method Income from discontinued operations Gain on disposal of discontinued operations Change in accounting method Net income (loss) Basic average common shares outstanding Diluted average common shares outstanding 2 0 0 0 1999 1998 $ 1 0 , 1 8 5 1 , 6 7 1 8 8 $ 11 , 9 4 4 $ 9 , 7 5 5 1 , 4 6 3 3 5 2 ( 8 8 ) (cid:209) $ 11 , 4 8 2 4 6 2 ( 1 4 6 ) 2 5 ( 5 ) ( 1 ) 3 3 5 ( 1 2 9 ) ( 1 8 ) 1 8 8 9 8 2 1 5 3 1 3 (cid:209) 5 0 1 0 . 4 2 0 . 2 2 0 . 4 9 (cid:209) 1 . 1 3 0 . 4 2 0 . 2 2 0 . 4 8 (cid:209) 1 . 1 2 4 4 2 4 4 6 $ $ $ $ $ $10,826 1,388 99 $12,313 $10,368 1,240 351 — (47) $11,912 401 (141) 74 (8) (19) 307 (116) (17) 174 124 159 283 (19) 438 0.40 0.28 0.36 (0.04) 1.00 0.39 0.28 0.36 (0.04) 0.99 440 443 $ $ $ $ $ $12,089 2,261 154 $14,504 $11,127 1,895 437 — 875 $14,334 170 (134) 26 (10) 3 55 (155) (20) (120) 105 — 105 — (15) $ $ (0.27) 0.24 — — $ (0.03) $ (0.27) 0.24 — — $ (0.03) 439 439 See notes to annual financial statements. 42 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT C O N S O L I D A T E D B A L A N C E S H E E T S December 31 (Millions of dollars and shares except per share data) 2 0 0 0 1999 CURRENT ASSETS: Cash and equivalents Receivables: Notes and accounts receivable (less allowance for bad debts of $125 and $94) Unbilled work on uncompleted contracts ASSETS TOTAL RECEIVABLES Inventories Current deferred income taxes Net current assets of discontinued operations Other current assets TOTAL CURRENT ASSETS Net property, plant and equipment Equity in and advances to related companies Excess of cost over net assets acquired (net of accumulated amortization of $231 and $189) Noncurrent deferred income taxes Net noncurrent assets of discontinued operations Other assets TOTAL ASSETS LIABILITIES AND SHAREHOLDERS’ EQUITY CURRENT LIABILITIES: Short-term notes payable Current maturities of long-term debt Accounts payable Accrued employee compensation and benefits Advance billings on uncompleted contracts Deferred revenues Income taxes payable Accrued special charges Other current liabilities TOTAL CURRENT LIABILITIES Long-term debt Employee compensation and benefits Other liabilities Minority interest in consolidated subsidiaries TOTAL LIABILITIES SHAREHOLDERS’ EQUITY: Common shares, par value $2.50 per share – authorized 600 shares, issued 453 and 448 shares Paid-in capital in excess of par value Deferred compensation Accumulated other comprehensive income Retained earnings Less 26 and 6 shares of treasury stock, at cost TOTAL SHAREHOLDERS’ EQUITY TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY See notes to annual financial statements. $ 2 3 1 3 , 0 2 9 8 1 6 3 , 8 4 5 7 2 3 2 3 5 2 9 8 2 3 6 5 , 5 6 8 2 , 4 1 0 4 0 0 5 9 7 3 4 0 3 9 1 3 9 7 $ 1 0 , 1 0 3 $ 1 , 5 7 0 8 7 8 2 2 6 7 2 8 8 9 8 11 3 6 6 9 4 3 , 8 2 6 1 , 0 4 9 6 6 2 6 0 0 3 8 6 , 1 7 5 1 , 1 3 2 2 5 9 ( 6 3 ) ( 2 8 8 ) 3 , 7 3 3 4 , 7 7 3 8 4 5 3 , 9 2 8 $ 1 0 , 1 0 3 $ 466 2,349 625 2,974 723 171 793 235 5,362 2,390 384 505 398 310 290 $9,639 $ 939 308 665 137 286 44 120 69 465 3,033 1,056 672 547 44 5,352 1,120 68 (51) (204) 3,453 4,386 99 4,287 $9,639 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 43 C O N S O L I D A T E D S T A T E M E N T S O F S H A R E H O L D E R S ’ E Q U I T Y Years ended December 31 (Millions of dollars and shares) COMMON STOCK (NUMBER OF SHARES) Balance at beginning of year Shares issued under compensation and incentive stock plans, net of forfeitures Shares issued for acquisition Cancellation of treasury stock Balance at end of year COMMON STOCK (DOLLARS) Balance at beginning of year Shares issued under compensation and incentive stock plans, net of forfeitures Shares issued for acquisition Cancellation of treasury stock Balance at end of year PAID-IN CAPITAL IN EXCESS OF PAR VALUE Balance at beginning of year Shares issued under compensation and incentive stock plans, net of forfeitures Tax benefit Shares issued for acquisition Cancellation of treasury stock Balance at end of year DEFERRED COMPENSATION Balance at beginning of year Current year awards, net Balance at end of year ACCUMULATED OTHER COMPREHENSIVE INCOME Cumulative translation adjustment Pension liability adjustment Unrealized gain (loss) on investments Balance at end of year CUMULATIVE TRANSLATION ADJUSTMENT Balance at beginning of year Conforming fiscal years Sales of subsidiaries Current year changes, net of tax Balance at end of year 2 0 0 0 1999 1998 4 4 8 4 1 (cid:209) 4 5 3 $ 1 , 1 2 0 9 3 (cid:209) $ 1 , 1 3 2 $ 6 8 1 0 9 3 8 4 4 (cid:209) 2 5 9 ( 5 1 ) ( 1 2 ) ( 6 3 ) $ $ $ $ ( 2 7 5 ) ( 1 2 ) ( 1 ) $ ( 2 8 8 ) $ ( 1 8 5 ) (cid:209) 11 ( 1 0 1 ) $ ( 2 7 5 ) 446 2 — — 448 $1,115 5 — — $1,120 $ 8 47 13 — — 68 (51) — (51) $ $ $ $ (185) (19) — $ (204) $ (142) — (17) (26) $ (185) 454 1 — (9) 446 $1,134 3 — (22) $1,115 $ 168 37 12 — (209) 8 (45) (6) (51) $ $ $ $ (142) (7) — $ (149) $ (127) (15) 9 (9) $ (142) See notes to annual financial statements. 44 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT C O N S O L I D A T E D S T A T E M E N T S O F S H A R E H O L D E R S ’ E Q U I T Y ( C O N T I N U E D ) Years ended December 31 (Millions of dollars and shares) PENSION LIABILITY ADJUSTMENT Balance at beginning of year Sale of subsidiary Current year adjustment Balance at end of year UNREALIZED GAIN (LOSS) ON INVESTMENTS Current year unrealized gain (loss) on investments Balance at end of year RETAINED EARNINGS Balance at beginning of year Net income (loss) Cash dividends paid Cancellation of treasury stock Conforming fiscal years Balance at end of year TREASURY STOCK (NUMBER OF SHARES) Beginning of year Shares issued under benefit, dividend reinvestment plan and incentive stock plans, net Shares purchased Cancellation of treasury stock Balance at end of year TREASURY STOCK (DOLLARS) Beginning of year Shares issued under benefit, dividend reinvestment plan and incentive stock plans, net Shares purchased Cancellation of treasury stock Balance at end of year COMPREHENSIVE INCOME Net income (loss) Translation rate changes, net of tax Current year adjustment to minimum pension liability Unrealized gain (loss) on investments Total comprehensive income 2 0 0 0 1999 1998 $ $ $ $ ( 1 9 ) 7 (cid:209) ( 1 2 ) ( 1 ) ( 1 ) $ 3 , 4 5 3 5 0 1 ( 2 2 1 ) (cid:209) (cid:209) $ 3 , 7 3 3 6 (cid:209) 2 0 (cid:209) 2 6 $ $ (7) — (12) (19) $ — $ — $3,236 438 (221) — — $3,453 6 — — — 6 $ $ (4) — (3) (7) $ — $ — $ 3,563 (15) (254) (61) 3 $ 3,236 16 (1) — (9) 6 $ 9 9 $ 98 $ 374 ( 2 3 ) 7 6 9 (cid:209) 8 4 5 5 0 1 ( 1 0 1 ) (cid:209) ( 1 ) 3 9 9 $ $ $ (9) 10 — 99 $ $ 438 (26) (12) — $ 400 (26) 20 (270) 98 (15) (9) (3) — (27) $ $ $ See notes to annual financial statements. H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 45 C O N S O L I D A T E D S T A T E M E N T S O F C A S H F L O W S Years ended December 31 (Millions of dollars) CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) Adjustments to reconcile net income to net cash from operations: Income from discontinued operations Depreciation, depletion and amortization (Benefit) provision for deferred income taxes Change in accounting method, net Distributions from (advances to) related companies, net of equity in (earnings) losses Accrued special charges Other non-cash items Other changes, net of non-cash items: Receivables and unbilled work Inventories Accounts payable Other working capital, net Other, net Total cash flows from operating activities CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures Sales of property, plant and equipment Acquisitions of businesses, net of cash acquired Dispositions of businesses, net of cash disposed Other investing activities Total cash flows from investing activities CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings of long-term debt Payments on long-term borrowings Net borrowings of short-term debt Payments of dividends to shareholders Proceeds from exercises of stock options Payments to reacquire common stock Other financing activities Total cash flows from financing activities Effect of exchange rate changes on cash Net cash flows from discontinued operations (1) Increase (decrease) in cash and equivalents Cash and equivalents at beginning of year CASH AND EQUIVALENTS AT END OF YEAR 2 0 0 0 1999 1998 $ 5 0 1 $ 438 $ (15) ( 3 1 3 ) 5 0 3 ( 6 ) (cid:209) ( 6 4 ) ( 6 3 ) ( 2 2 ) ( 8 9 6 ) 8 1 7 0 1 5 5 ( 3 0 ) ( 5 7 ) ( 5 7 8 ) 2 0 9 ( 1 0 ) 1 9 ( 5 1 ) ( 4 11 ) (cid:209) ( 3 0 8 ) 6 2 9 ( 2 2 1 ) 1 0 5 ( 7 6 9 ) ( 2 0 ) ( 5 8 4 ) ( 9 ) 8 2 6 ( 2 3 5 ) 4 6 6 $ 2 3 1 (283) 511 187 19 24 (290) 19 616 (3) (179) (432) (685) (58) (520) 118 (7) 291 11 (107) — (59) 436 (221) 49 (10) (6) 189 5 234 263 203 $ 466 (105) 500 (297) — 9 359 5 (215) (38) (25) (255) 227 150 (841) 83 (40) 7 1 (790) 150 (28) 386 (254) 49 (20) (16) 267 (5) 235 (143) 346 $ 203 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash payments during the year for: Interest Income taxes Non-cash investing and financing activities: $ 1 4 4 $ 3 1 0 $ 145 98 $ $ 137 $ 535 Liabilities assumed in acquisitions of businesses Liabilities disposed of in dispositions of businesses 5 24 (1) Net cash flows from discontinued operations in 2000 include proceeds of approximately $913 million from the sales of Dresser- $ 9 5 $ 4 9 9 $ 90 $ 111 $ $ Rand in 2000 and Ingersoll-Dresser Pump in 1999. See Note 2. See notes to annual financial statements. 46 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S NOTE 1. SIGNIFICANT ACCOUNTING POLICIES We employ accounting policies that are in accordance with generally accepted accounting principles in the United States. The preparation of financial statements in conformity with generally accepted accounting principles 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. Principles of consolidation. The consolidated financial statements include the accounts of our company and all of our majority-owned subsidiaries. All material intercompany accounts and transactions are eliminated. Investments in other companies in which we own a 20% to 50% interest are accounted for using the equity method. Specific prior year amounts have been reclassified to conform to the current year presentation. Revenues and income recognition. We recognize revenues as services are rendered or products are shipped. The distinction between services and product sales is based upon the overall activity of the particular business operation. Revenues from engineering and construction contracts are reported on the percentage of completion method of accounting using measure- ments of progress towards completion appropriate for the work performed. All known or anticipated losses on contracts are provided for currently. 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. 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. 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. Research and development. Research and development expenses are charged to income as incurred. See Note 4 for research and development expense by business segment. 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 capitalized costs related to software developed for resale of $7 million in 2000, $12 million in 1999 and $13 million in 1998. Amortization expense of software development costs was $12 million for 2000, $15 million for 1999 and $18 million for 1998. 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 three 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 10 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. Receivables. Our receivables are generally not collateralized. With the exception of claims and change orders which are in the process of being negotiated with customers, unbilled work on uncompleted contracts generally represents work currently billable, and this work is usually billed during normal billing processes in the next month. These claims and change orders, included in unbilled receivables, amounted to $113 million and $98 million at December 31, 2000 and 1999, respectively, and are generally expected to be collected in the following year. Included in notes and accounts receivable are notes with varying interest rates. Notes receivable totaled $38 million at December 31, 2000 and $41 million at December 31, 1999. 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. The cost of most inventories is determined using either the first-in, first-out method or the average cost method, although the cost of some United States manufacturing and field service inventories is determined using the last-in, first-out method. Inventories of sales items owned by foreign subsidiaries and inventories of operating supplies and parts are generally valued at average cost. 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 market value or discounted cash flow value is required. We follow the successful efforts method of accounting for oil and gas properties. H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 47 N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S Maintenance and repairs. Expenditures for maintenance and repairs are generally 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. Excess of cost over net assets acquired. The excess of cost over net assets acquired is amortized on a straight-line basis over periods not exceeding 40 years. The excess of cost over net assets acquired is continually monitored for potential impairment. When negative conditions such as significant current or projected operating losses exist, a review is performed to determine if the projected undiscounted future cash flows indicate that an impairment exists. If an impairment exists, the excess of cost over net assets acquired, and, if appropriate, the associated assets are reduced to reflect the estimated discounted cash flows to be generated by the underlying business. This is consistent with methodologies in Statement of Financial Accounting Standards No. 121 “Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to be Disposed of.” Income taxes. A valuation allowance is provided for deferred tax assets if it is more likely than not these items will either expire before we are able to realize their benefit, or that future deductibility is uncertain. Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been realized in the financial statements or tax returns. Derivative instruments. We enter into derivative financial transactions to hedge existing or projected exposures to changing foreign exchange rates, interest rates and commodity prices. We do not enter into derivative transactions for speculative or trading purposes. Derivative financial instruments to hedge exposure with an indeterminable maturity date are generally carried at fair value with the resulting gains and losses reflected in the results of operations. Gains or losses on hedges of identifiable commitments are deferred and recognized when the offsetting gains or losses on the related hedged items are recognized. Deferred gains or losses for hedges which are terminated prior to the transaction date are recognized when the underlying hedged transactions are recognized. In the event an identifiable commitment is no longer expected to be realized, any deferred gains or losses on hedges associated with the commitment are recognized currently. Costs associated with entering into these contracts are presented in other assets, while deferred gains or losses are included in other liabilities or other assets, respec- tively, on the consolidated balance sheets. 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 and commodity derivatives are included in interest expense and operating income, respectively. During the years ended December 31, 2000, 1999 and 1998, we did not enter into any significant transactions to hedge interest rates or commodity prices. 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 consoli- dated 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 titled “cumulative translation adjustment.” NOTE 2. ACQUISITIONS AND DISPOSITIONS PES acquisition. In February 2000, our offer to acquire the remaining 74% of the shares of PES (International) Limited that we did not already own was accepted by PES shareholders. PES is based in Aberdeen, Scotland, and has developed technology that complements Halliburton Energy Services’ real-time reservoir solutions. To acquire the remaining 74% of PES, we issued 1.2 million shares of Halliburton common stock. We also issued rights that will result in the issuance of between 850,000 and 2.1 million additional shares of Halliburton common stock between February 2001 and February 2003. We issued 1 million shares in February 2001 under the rights. We have preliminarily recorded, subject to the final valuation of intangible assets and other costs, $115 million of goodwill which will be amortized over 20 years. PES is part of the Energy Services Group. Dresser merger. On September 29, 1998 we completed the acquisition of Dresser Industries, Inc. by converting the outstanding Dresser common stock into approximately 176 million shares of our common stock. We also reserved approx- imately 7 million shares of common stock for outstanding Dresser stock options and other employee and directors plans. The merger qualified as a tax-free exchange to Dresser’s shareholders for United States federal income tax purposes and was accounted for using the pooling of interests method of accounting for business combinations. Financial statements have been restated to include the results of these Dresser operations for all periods presented. 48 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S Combined and separate company results of Halliburton Company and Dresser Industries, Inc. for the period preceding the merger are as follows: Nine Months ended September 30 Millions of dollars REVENUES: Halliburton Company Dresser Industries, Inc. Amounts reclassified to discontinued operations Combined continuing operations INCOME (LOSS): Halliburton Company Dresser Industries, Inc. Amounts reclassified to discontinued operations 1998 special charges, net of tax Amounts reclassified to discontinued operations Combined continuing operations 1998 $ 7,045 3,949 $10,994 $ 359 $ 6,019 (2,070) $ 282 (93) (722) 189 15 (707) (159) $ Other acquisitions. We acquired other businesses in 2000, 1999 and 1998 for $10 million, $13 million and $42 million, respectively. These businesses did not have a significant effect on revenues or earnings. Joint venture divestitures. In October 1999, we announced the sales of our 49% interest in the Ingersoll-Dresser Pump joint venture and our 51% interest in the Dresser-Rand joint venture to Ingersoll-Rand. See Note 3. The sales were triggered by Ingersoll-Rand’s exercise of its option under the joint venture agreements to cause us to either buy their interests or sell ours. Both joint ventures were part of the Dresser Equipment Group segment. Our Ingersoll-Dresser Pump interest was sold in December 1999 for approximately $515 million. We recorded a gain on disposition of discontinued operations of $253 million before tax, or $159 million after-tax, for a net gain of $0.36 per diluted share in 1999 from the sale of Ingersoll-Dresser Pump. Proceeds from the sale, after payment of our intercompany balance, were received in the form of a $377 million promissory note with an annual interest rate of 3.5%, which was collected on January 14, 2000. On February 2, 2000 we completed the sale of our 51% interest in Dresser-Rand for a price of approximately $579 million. Proceeds from the sale, net of intercompany amounts payable to the joint venture, were $536 million, resulting in a gain on disposition of discontinued operations of $356 million before tax, or $215 million after-tax, for a net gain of $0.48 per diluted share in the first quarter of 2000. The proceeds from these sales were used to repay short-term borrowings and for other general corporate purposes. LWD divestiture. In March 1999, in connection with the Dresser merger, we sold the majority of our pre-merger worldwide logging-while-drilling business and a portion of the pre-merger measurement-while-drilling business. The sale was in accordance with a consent decree with the United States Department of Justice. The financial impact of the sale was reflected in the third quarter 1998 special charge. See Note 12. This business was previously part of the Energy Services Group. We continue to provide separate logging-while-drilling services through our Sperry-Sun Drilling Systems business line, which was acquired as part of the merger with Dresser and is now part of the Energy Services Group. In addition, we will continue to provide sonic logging-while-drilling services using technologies we had before the merger with Dresser. M-I L.L.C. drilling divestiture. In August 1998, we sold our 36% interest in M-I L.L.C. to Smith International, Inc. for $265 million. Payment was made in the form of a non-interest-bearing promissory note which was collected in April 1999. The sale completed our commitment to the United States Department of Justice to sell our M-I interest in connection with our merger with Dresser. M-I was previously part of the Energy Services Group. We continue to offer drilling fluid products and services through our Baroid Drilling Fluids business line which was acquired as part of the merger with Dresser and is now part of the Energy Services Group. NOTE 3. DISCONTINUED OPERATIONS The Dresser Equipment Group in 1999 was comprised of six operating divisions and two joint ventures that manufacture and market equipment used primarily in the energy, petrochemical, power and transportation industries. In late 1999 we announced our intentions to sell, and have subsequently sold, our interests in the two joint ventures within this segment. These joint ventures represented nearly half of the group’s revenues and operating profit in 1999. See Note 2. The sale of our interests in the segment’s joint ventures prompted a strategic review of the remaining businesses within the Dresser Equipment Group segment. As a result of this review, we determined that these businesses do 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 our Dresser Equipment Group segment. In January 2001, we signed a definitive agreement and expect to close the sale of these businesses in the second quarter of 2001. Total consider- ation under the agreement is $1.55 billion in cash, less assumed liabilities, and is subject to adjustments at closing for changes in net assets. As part of the terms of the transaction, we will retain a 5% equity interest in Dresser Equipment Group after closing. H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 49 N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S NOTE 4. BUSINESS SEGMENT INFORMATION We have two business segments. These segments are organized around the products and services provided to the customers they serve. See the following tables for information on our business segments. The Energy Services Group segment provides pressure pumping equipment and services, logging and perforating, drilling systems and services, drilling fluids systems, drill bits, specialized completion and production equipment and services, well control, integrated solutions, and reservoir description. Also included in the Energy Services Group are upstream oil and gas engineering, construction and maintenance services, specialty pipe- coating, insulation, underwater engineering services, integrated exploration and production information systems, and professional services to the petroleum industry. The Energy Services Group has three business units: Halliburton Energy Services, Brown & Root Energy Services and Landmark Graphics. The long-term performance for these business units is linked to the long-term demand for oil and gas. The products and services the group provides are designed to help discover, develop and produce oil and gas. The customers for this segment are major oil companies, national oil companies and independent oil and gas companies. The Engineering and Construction Group segment provides engineering, procurement, construction, project management, and facilities operation and maintenance for hydrocarbon processing and other industrial and governmental customers. The Engineering and Construction Group has two business units: Kellogg Brown & Root and Brown & Root Services. Both business units are engaged in the delivery of engineering and construction services. Our equity in pretax income or losses for unconsolidated related companies that are accounted for on the equity method is included in revenues and operating income of the applicable segment. Intersegment revenues included in the revenues of the other business segments and sales between geographic areas are immaterial. General corporate assets not included in a business segment are primarily composed of receivables, deferred tax assets and other shared assets, including the investment in an enterprise-wide information system. The financial results of the Dresser Equipment Group segment are presented as discontinued operations in our financial statements. Prior periods are restated to reflect this presentation. Income from Operations of Discontinued Businesses Years ended December 31 Millions of dollars Revenues Operating income Other income and expense Taxes Minority interest Net income 2 0 0 0 $ 1 , 4 0 0 1 5 8 $ (cid:209) ( 6 0 ) (cid:209) 9 8 1999 $2,585 $ 249 (1) (98) (26) $ 124 1998 $2,849 $ 227 (3) (90) (29) $ 105 $ Gain on disposal of discontinued operations reflects the gain on the sale of Dresser-Rand in February 2000 and the gain on the sale of Ingersoll-Dresser Pump in December 1999. Gain on Disposal of Discontinued Operations 2 0 0 0 Millions of dollars Proceeds from sale, less intercompany settlement Net assets disposed Gain before taxes Income taxes Gain on disposal of $ 5 3 6 ( 1 8 0 ) 3 5 6 ( 1 4 1 ) 1999 $ 377 (124) 253 (94) discontinued operations $ 2 1 5 $ 159 Net assets of discontinued operations at December 31, 2000 and 1999 are composed of the following items: Millions of dollars Receivables Inventories Other current assets Accounts payable Other current liabilities Net current assets of discontinued operations Net property, plant and equipment Net goodwill Other assets Employee compensation and benefits Other liabilities Minority interest in consolidated subsidiaries Net noncurrent assets of discontinued operations 2 0 0 0 $ 2 8 6 2 5 5 2 2 ( 1 0 4 ) ( 1 6 1 ) $ 2 9 8 $ 2 1 9 2 5 7 3 0 ( 11 3 ) ( 2 ) 1999 $ 904 515 34 (267) (393) $ 793 $ 401 263 74 (313) (5) (cid:209) (110) $ 3 9 1 $ 310 Revenues, assets, and liabilities declined from 1999 primarily due to the sales of Dresser-Rand and Ingersoll-Dresser Pump joint ventures. 50 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S The tables below present information on our continuing operations business segments. Operations by Business Segment Years ended December 31 Millions of dollars 2 0 0 0 1999 1998 REVENUES: Energy Services Group Engineering and Construction Group Total OPERATING INCOME: Energy Services Group Engineering and Construction Group Special charges and credits General corporate Total CAPITAL EXPENDITURES: Energy Services Group Engineering and Construction Group General corporate and shared assets Total Construction Group General corporate and shared assets Total TOTAL ASSETS: Energy Services Group Engineering and Construction Group Net assets of $ 7 , 9 1 6 $ 6,999 $ 9,009 4 , 0 2 8 $ 11 , 9 4 4 5,314 $12,313 5,495 $14,504 $ 5 2 6 $ 222 $ 971 1 4 (cid:209) ( 7 8 ) 4 6 2 4 9 5 3 2 5 1 5 7 8 $ $ $ 3 6 4 7 5 0 3 $ 203 47 (71) 401 414 34 72 520 421 43 47 511 $ $ $ $ $ $ $ $ $ $ 34 100 841 405 49 46 500 $ 7 , 1 4 8 $ 6,167 $ 6,618 1 , 2 5 8 1,282 1,405 DEPRECIATION AND AMORTIZATION: 4 2 0 Energy Services Group Engineering and $ discontinued operations 6 8 9 1,103 950 General corporate and shared assets Total 1 , 0 0 8 $ 1 0 , 1 0 3 1,087 $ 9,639 1,099 $10,072 RESEARCH AND DEVELOPMENT: Energy Services Group Engineering and $ 2 2 4 $ 207 $ 220 Years ended December 31 Millions of dollars SPECIAL CHARGES AND CREDITS: Energy Services Group Engineering and Construction Group General corporate Total 2 0 0 0 1999 1998 $ (cid:209) $(45) $721 (cid:209) (cid:209) $ (cid:209) — (2) $(47) 40 198 $959 Operations by Geographic Area Years ended December 31 Millions of dollars 2 0 0 0 1999 1998 237 (959) (79) 170 REVENUES: United States United Kingdom Other areas $ 4 , 0 7 3 1 , 5 1 2 $ 3,727 1,656 $ 4,642 2,153 (over 120 countries) 707 Total 6 , 3 5 9 $ 11 , 9 4 4 6,930 $12,313 7,709 $14,504 LONG-LIVED ASSETS: United States United Kingdom Other areas (numerous countries) Total $ 2 , 0 6 8 5 2 5 $ 1,801 684 $ 1,788 579 7 7 6 $ 3 , 3 6 9 643 $ 3,128 920 $ 3,287 NOTE 5. INVENTORIES Inventories to support continuing operations at December 31, 2000 and 1999 are composed of the following: Millions of dollars Finished products and parts Raw materials and supplies Work in process Total 2 0 0 0 $ 4 8 6 1 7 8 5 9 $ 7 2 3 1999 $619 79 25 $723 Inventories on the last-in, first-out method were $66 million at December 31, 2000 and 1999. If the average cost method had been used, total inventories would have been about $28 million higher than reported at December 31, 2000, and $35 million higher than reported at December 31, 1999. Construction Group Total 7 2 3 1 4 211 $ 4 224 $ $ H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 51 N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S NOTE 6. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment to support continuing operations at December 31, 2000 and 1999 are composed of the following: Millions of dollars Land Buildings and property improvements Machinery, equipment and other Total Less accumulated depreciation Net property, plant and equipment $ 2 0 0 0 8 3 9 6 8 4 , 5 0 9 5 , 5 6 0 3 , 1 5 0 $ 2 , 4 1 0 1999 $ 110 959 4,443 5,512 3,122 $ 2,390 At December 31, 2000 and 1999, machinery, equipment and other property includes oil and gas investments of approximately $363 million and $309 million, respectively, and software developed for an information system of $223 million and $197 million, respectively. NOTE 7. 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. Information pertaining to related companies for our continuing operations is set out below. The larger unconsolidated entities include European Marine Contractors, Limited, and Bredero-Shaw which are both part of the Energy Services Group. European Marine Contractors, Limited, which is 50%-owned, specializes in engineering, procurement and construction of marine pipelines. Bredero-Shaw, which is 50%-owned, specializes in pipecoating. We sold our 36% ownership interest in M-I to Smith International, Inc. on August 31, 1998. This transaction completed our commitment to the United States Department of Justice to sell our M-I interest in connection with our merger with Dresser Industries, Inc. See Note 2 for further information on the sale of M-I. Prior to the sale of our interest, we accounted for our interest in M-I on the equity method. Combined summarized financial information for all jointly owned operations which are not consolidated is as follows: Combined Operating Results Years ended December 31 Millions of dollars Revenues Operating income Net income 2 0 0 0 $ 3 , 0 9 8 1 9 2 $ 1 6 9 $ 1999 $3,215 $ 193 $ 127 1998 $4,262 $ 398 $ 276 Combined Financial Position December 31 Millions of dollars Current assets Noncurrent assets Total Current liabilities Noncurrent liabilities Minority interests Shareholders’ equity Total 2 0 0 0 $ 1 , 6 0 4 1 , 3 0 7 $ 2 , 9 11 $ 1 , 2 3 8 9 4 7 2 7 2 4 $ 2 , 9 11 1999 $1,718 1,455 $3,173 $1,301 1,135 4 733 $3,173 NOTE 8. LINES OF CREDIT, NOTES PAYABLE AND LONG-TERM DEBT At December 31, 2000, we had committed short-term lines of credit totaling $1.85 billion. There were no borrowings outstanding under these lines of credit. Fees for committed lines of credit were immaterial. Short-term debt consists primarily of $1.54 billion in commercial paper with an effective interest rate of 6.6% and $30 million of other facilities with varying rates of interest. Long-term debt at the end of 2000 and 1999 consists of the following: Millions of dollars 6.25% notes due June 2000 7.6% debentures due August 2096 8.75% debentures due February 2021 8% senior notes due April 2003 Medium-term notes due 2002 $ 2 0 0 0 1999 (cid:209) $ 300 300 200 139 3 0 0 2 0 0 1 3 9 through 2027 4 0 0 400 Term loans at LIBOR (GBP) plus 0.75% payable in semiannual installments through March 2002 Other notes with varying interest rates Total long-term debt Less current portion Noncurrent portion of long-term debt 11 7 1 , 0 5 7 8 $ 1 , 0 4 9 20 5 1,364 308 $1,056 We repaid $300 million on our 6.25% notes which came due in June 2000. 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. 52 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S At December 31, 2000, we have outstanding notes under our medium-term note program as follows: Amount $ 75 million $150 million $ 50 million $125 million Due 08/2002 12/2008 05/2017 02/2027 Issue Rate 6.30)% 5.63)% 7.53)% 6.75)% Price Par 99.97)% Par 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% 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. Our debt matures as follows: $8 million in 2001; $84 million in 2002; $139 million in 2003; none in 2004 and 2005; and $825 million thereafter. NOTE 9. COMMITMENTS AND CONTINGENCIES Leases. At year end 2000, we were obligated under noncancelable operating leases, expiring on various dates through 2021, principally for the use of land, offices, equipment, field facilities, and warehouses. Total rentals charged to continuing operations for noncancelable leases in 2000, 1999 and 1998 were as follows: Millions of dollars Rental expense 2 0 0 0 $ 1 4 9 1999 $139 1998 $156 Future total rentals on noncancelable operating leases are as follows: $94 million in 2001; $80 million in 2002; $66 million in 2003; $45 million in 2004; $32 million in 2005; and $84 million thereafter. Asbestos litigation. Since 1976, our subsidiary, Dresser Industries, Inc. and its former divisions or subsidiaries have been involved in litigation alleging some products they manufactured contained asbestos that injured persons that inhaled the fibers. Dresser has entered into agreements with insurance carriers, that cover, in whole or in part, indemnity payments, legal fees and expenses for specific categories of claims. Dresser is negotiating with insurance carriers for coverage for the remaining categories of claims. Because these agreements are governed by exposure dates, payment type and the product involved, the covered amount varies by claim. In addition, lawsuits are pending against several carriers seeking to recover additional amounts related to these claims. Our Engineering and Construction Group is also involved in asbestos litigation. Third parties allege they sustained injuries from the inhalation of asbestos fibers contained in some of the materials used in various construction and renovation projects involving our Brown & Root subsidiary, now named Kellogg Brown & Root, Inc. The insurance coverage for Kellogg Brown & Root for the applicable periods was written by Highlands Insurance Company. Highlands was a subsidiary of Halliburton prior to its spin-off to our shareholders in early 1996. Our negoti- ations with Highlands have not produced an agreement on the amount of insurance coverage for asbestos and defense costs. On April 5, 2000, Highlands filed suit in Delaware Chancery Court alleging that, as part of the spin-off in 1996, Halliburton assumed liability for all asbestos claims filed against Halliburton after the spin-off. Highlands also alleges that Halliburton did not adequately disclose to Highlands the existence of Halliburton’s subsidiaries’ potential asbestos liability. On August 23, 2000 Highlands issued a letter denying coverage under the policies based on the claims asserted in the Delaware action. We believe that Highlands is contractually obligated to provide insurance coverage for the asbestos claims filed against Kellogg Brown & Root and that Highlands’ lawsuit and its denial of coverage are without merit. We intend to assert our right to the insurance coverage vigorously. On April 24, 2000, Halliburton filed suit against Highlands in Harris County, Texas, claiming that Highlands breached its contractual obligation to provide insurance coverage. We have asked the court to order Highlands to provide coverage for asbestos claims under the guaranteed cost policies issued by Highlands to Kellogg Brown & Root. On March 21, 2001 the Delaware Chancery Court ruled that Highlands is not obligated to provide insurance coverage for asbestos claims filed against Kellogg Brown & Root because, in the court’s opinion, the agreements entered into by Highlands and Halliburton at the time of the spin-off terminated the policies previously written by Highlands that would otherwise cover such claims.This ruling, if it is not reversed on appeal, would eliminate our primary insurance covering asbestos claims against Kellogg Brown & Root for periods prior to the spin-off. Most claims filed against Kellogg Brown & Root allege exposure to asbestos prior to the spin-off and are disposed of for less than the limits of the Highlands policies. However, we and our legal counsel, Vinson & Elkins L.L.P., believe the court’s ruling is wrong. We intend to appeal the ruling to the Delaware Supreme Court as soon as possible. Vinson & Elkins has opined to us that it is very likely that the ruling of the Chancery Court will be reversed because the ruling clearly contravenes the provisions of the applicable agreements between Highlands and Halliburton. Vinson & Elkins has also opined to us that it is likely that we will ultimately prevail in this litigation. Since 1976, approximately 282,000 claims have been filed against various current and former divisions and subsidiaries. About 25,000 of these claims relate to Kellogg Brown & Root and the balance of these claims relate to Dresser, its former divisions and subsidiaries. Approximately 165,000 of these claims have H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 53 N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S Accounts receivable for billings to other insurance carriers for payments made on claims were $13 million at December 31, 2000 and $9 million at December 31, 1999. We recognize the uncertainties of litigation and the possibility that a series of adverse court rulings or new legislation affecting the claims settlement process could materially impact the expected resolution of asbestos related claims. However, based upon: • our historical experience with similar claims; • the time elapsed since Dresser and its former divisions or subsidiaries discontinued sale of products containing asbestos; • the time elapsed since Kellogg Brown & Root used asbestos in any construction process; and • our understanding of the facts and circumstances that gave rise to asbestos claims, we believe that the pending asbestos claims will be resolved without material effect on our financial position or results of operations. Resolution of dispute with Global Industrial Technologies, Inc. We previously reported that under an agreement entered into at the time of the spin-off of Global Industrial Technologies, Inc., formerly INDRESCO, Inc., from Dresser Industries, Inc., Global assumed liability for all asbestos related claims filed against Dresser after July 31, 1992 relating to refractory products manufactured or marketed by the former Harbison-Walker Refractories division of Dresser. Those business operations were transferred to Global in the spin-off. These asbestos claims are subject to agreements with Dresser’s insurance carriers that cover expense and indemnity payments. However, the insurance coverage is incomplete and Global has to-date paid the uncovered portion of asbestos claims with its own funds. been settled or disposed of at a gross cost of approximately $124 million, with insurance carriers paying all but approximately $32 million. Claims continue to be filed, with about 45,000 claims filed in 2000. We have established an accrual estimating our liability for known asbestos claims. Our estimate is based on our historical litigation experience, settlements and expected recoveries from insurance carriers. Our expected insurance recoveries are based on agreements with carriers or, where agreements are still under negotiation or litigation, our estimate of recoveries. We believe that the insurance carriers with which we have signed agreements will be able to meet their share of future obligations under the agreements. Prior to the Chancery Court’s ruling, Highlands Insurance Group Inc., the parent of Highlands Insurance Company, stated in its SEC filings that if it lost the litigation with us and was required to pay the asbestos claims against Kellogg Brown & Root, there could be a material adverse impact on Highlands Insurance Group’s financial position. Highlands Insurance Company reported statutory capital surplus of $152 million to the Texas Insurance Commission in its Quarterly Statement as of September 30, 2000. On March 12, 2001 Highlands Insurance Group, Inc. announced that it expected to report a significant loss for the fourth quarter of 2000 and for the full year 2000. Although we do not know the extent of the impact of this loss on Highlands Insurance Company, we believe that Highlands has the ability to pay substantially all of these asbestos claims when this litigation is resolved in our favor. At December 31, 2000, there were about 117,000 open claims, including about 23,000 associated with recoveries we expect from Highlands. Open claims at December 31, 2000 also include 9,000 for which settlements are pending. The number of open claims at the end of 2000 compares with approximately 107,700 open claims at the end of the prior year. The accrued liabilities for these claims and corresponding billed and estimated recoveries from carriers are as follows: December 31 Millions of dollars Accrued liability Estimated insurance recoveries: Highlands Insurance Company Other insurance carriers Net asbestos liability 2 0 0 0 $ 8 0 ( 3 9 ) ( 1 2 ) $ 2 9 1999 $ 71 (28) (18) $ 25 As of December 31, 2000, we have accounts receivable from Highlands Insurance Company of $11 million for payments we have made on asbestos claims. If our appeal of the Chancery Court’s ruling in the Highlands litigation is unsuccessful, we will be unable to collect this account receivable or the $39 million estimated recovery from Highlands for asbestos claims. This may have a material adverse impact on the results of our operations and our financial position at that time. 54 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S We also reported that a dispute arose with Global concerning those agreements, which led to arbitration and litigation proceedings. We have now resolved the dispute and agreed with Global that: • the arbitration, and all related litigation, is dismissed; • Global acknowledges its obligation to assume responsibility for new asbestos claims filed after the date of the spin-off; • Global agrees to continue to cooperate with Dresser on Dresser’s remaining refractory claims; and, • Dresser continues to make available its direct insurance program for the Global assumed asbestos liabilities. Fort Ord litigation. Brown & Root Services is a defendant in civil litigation pending in federal court in Sacramento, California. The lawsuit alleges that Brown & Root Services violated provisions of the False Claims Act while performing work for the United States Army at Fort Ord in California. This lawsuit was filed by a former employee in 1997. Brown & Root Services has denied the allegations and is preparing to defend itself at trial. Further proceedings in this civil lawsuit have been stayed while the investigation referred to in the next paragraph is ongoing. We believe that it is remote that this civil litigation will result in any material amount of damages being assessed against the company, although the cost of our defense could well exceed $1 million before the matter is brought to a conclusion. Although in 1998 the United States Department of Justice declined to join this litigation, it has advised us that Brown & Root Services is the target of a federal grand jury investigation regarding the contract administration issues raised in the civil litigation. Brown & Root Services has been served with grand jury subpoenas, which required the production of documents relating to the Fort Ord contract and similar contracts at other locations. We have also been informed that several current and former employees will be called to testify before the grand jury. We have retained independent counsel for these employees. We are cooperating in this investigation. The United States Department of Justice has not made any specific allegations against Brown & Root Services. Environmental. We are subject to numerous environmental legal and regulatory requirements related to our operations worldwide. We take a proactive approach to evaluating and addressing the environmental impact of our operations. Each year we assess and remediate contaminated properties in order to avoid future liabilities and comply with legal and regulatory require- ments. On occasion we are involved in specific environmental litigation and claims, including the clean-up of properties we own or have operated as well as efforts to meet or correct compliance-related matters. Some of our subsidiaries and former operating entities are involved as a potentially responsible party or PRP in remedial activities to clean-up several “Superfund” sites under United States federal law and comparable state laws. Kellogg Brown & Root, Inc., one of our subsidiaries, is one of nine PRPs named at the Tri-State Mining District “Superfund” Site, also known as the Jasper County “Superfund” Site, which we have reported in the past. Based on our negotiations with federal regulatory authorities and our evaluation of our responsibility for remediation at small portions of this site, we do not believe we will be compelled to make expenditures which will have a material adverse effect on our financial position or results of operations. However, the United States Department of the Interior and the State of Missouri have indicated that they might make a separate claim against Kellog Brown & Root for natural resource damages. Discussions with them have not been concluded and we are unable to make a judgement about the amount of damages they may seek. We also incur costs related to compliance with ever-changing environmental legal and regulatory requirements in the jurisdic- tions where we operate. It is very difficult to quantify the potential liabilities. We do not expect these expenditures to have a material adverse effect on our consolidated financial position or our results of operations. Our accrued liabilities for environmental matters were $31 million as of December 31, 2000 and $29 million as of December 31, 1999. Other. We are a party to various other legal proceedings. We expense the costs of legal fees related to these proceedings. We believe any liabilities we may have arising from these proceedings will not be material to our consolidated financial position or our results of operations. NOTE 10. INCOME PER SHARE Millions of dollars and shares except per share data Income (loss) from continuing operations before change in accounting method Basic weighted average shares Effect of common stock equivalents Diluted weighted average shares Income (loss) per common share from continuing operations before change in accounting method: 2 0 0 0 1999 1998 $ 1 8 8 4 4 2 $ 174 440 $ (120) 439 4 3 4 4 6 443 — 439 Basic Diluted $ 0 . 4 2 $ 0 . 4 2 $0.40 $0.39 $(0.27) $(0.27) Income per common share from discontinued operations: Basic Diluted $ 0 . 7 1 $ 0 . 7 0 $0.64 $0.64 $ 0.24 $ 0.24 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 55 N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S Income per share from discontinued operations includes $0.49 and $0.36 basic and $0.48 and $0.36 diluted from the gain on the sale of discontinued operations in 2000 and 1999, respectively. Basic income per share is based on the weighted average number of common shares outstanding during the period. Diluted income per share includes additional common shares that would have been outstanding if potential common shares with a dilutive effect had been issued. Included in the computation of diluted income per share 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 1 million shares of common stock in 2000; 2 million shares in 1999; and 1 million shares in 1998. These options were outstanding during these respective years, but were excluded because the option exercise price was greater than the average market price of the common shares. Since we incurred a loss in 1998, diluted earnings per share for that year excludes 3 million potential common shares which were antidilutive for earnings per share purposes. Asset Related Charges As a result of the reorganization of the engineering and construction businesses, we took actions to rationalize our cost structure including write-offs of equipment, engineering reference designs and capitalized software. Cost of services includes $20 million of charges for equipment, licenses and engineering reference designs related to specific projects that were discontinued as a result of the reorganization. Equipment and licenses with a net book value of $10 million were abandoned. Engineering reference designs specific to a project with a net book value of $4 million were written off. Software developed for internal use with a net book value of $6 million which we no longer plan to use due to standardization of systems was also written off. Personnel Charges Personnel charges of $16 million include severance and related costs incurred for the planned reduction of approximately 30 senior management positions, most of which will be terminated in the first quarter of 2001. We expect payments under the severance agreements to be completed by mid-2001. NOTE 11. ENGINEERING AND CONSTRUCTION REORGANIZATION NOTE 12. SPECIAL CHARGES AND CREDITS The table below summarizes non-recurring charges of $36 million pretax recorded in December 2000 related to the reorganization of our engineering and construction businesses. The table below summarizes the 1998 pretax expenses for special charges and the accrued amounts utilized and adjusted through December 31, 2000. Millions of dollars Charges Charges Total 1998 CHARGES TO EXPENSE Asset Related Personnel Millions of dollars Asset Related Charges Facility Merger Personnel Charges Consolidation Transaction Charges Charges Other Charges Total $ 2 $ 9 $ 11 Group $ 453 $ 157 $ 93 $ — $ 18 $ 721 BY BUSINESS SEGMENT Energy Services 2000 CHARGES TO EXPENSE BY BUSINESS SEGMENT Energy Services Group Engineering and Construction Group Total Utilized in 2000 Balance December 31, 2000 18 20 (20) $ — 7 16 — $ 16 25 36 (20) $ 16 These charges were reflected in the following captions of the consolidated statements of income: Year ended December 31 Millions of dollars Cost of services General and administrative Total 2 0 0 0 $ 3 0 6 $ 3 6 Engineering and Construction Group 8 19 Discontinued operations General corporate Total Utilized in 1998 18 30 509 1 58 235 8 2 23 126 — — 64 64 5 40 — 23 46 21 198 980 and 1999 (509) (196) (77) (63) (19) (864) Adjustments to 1998 charges — (30) (16) (1) — (47) Balance December 31, 1999 $ — $ Utilized in 2000 — 9 (9) $ 33 (28) $ — $ 27 $ 69 — (26) (63) Balance December 31, 2000 $ (cid:209) $ (cid:209) $ 5 $ (cid:209) $ 1 $ 6 56 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S Our 1998 results of operations reflect special charges totaling $980 million to provide for costs associated with the Dresser Industries, Inc. merger and industry downturn due to declining oil and gas prices. These charges were reflected in the following captions of the consolidated statements of income: Year ended December 31 Millions of dollars Cost of services Cost of sales Special charges Discontinued operations Total 1998 $ 68 16 875 21 $980 Most restructuring activities accrued for in the 1998 special charges were completed and expended by the end of 1999. We utilized $63 million in 2000 for sales of facilities and other actions that were initiated in 1999 but were concluded in 2000. From inception through December 31, 2000, we used $368 million in cash for items associated with the 1998 special charges. The unutilized special charge reserve balance at December 31, 2000 is expected to result in future cash outlays of $6 million. At December 31, 2000, no adjustments or reversals to the remaining accrued special charges are planned. During the second quarter of 1999, we reversed $47 million of the 1998 special charge based on our reassessment of total costs to be incurred to complete the actions covered in our special charges. The components of the reversal are as follows: • $30 million in personnel charges primarily due to a reduction in estimated legal costs associated with employee layoffs, lower than anticipated average severance per person and fewer than expected terminations due to voluntary employee resignations; • $16 million in facility consolidation charges due to fewer than initially estimated facility exits, resulting in an estimated $7 million reduction in facilities consolidation costs, combined with other factors including more favorable exit costs than anticipated; and • $1 million of merger transaction costs primarily as a result of lower than previously estimated legal and other professional costs. Asset Related Charges Asset related charges include impairments and write-offs of intangible assets and excess and/or duplicate machinery, equipment, inventory, and capitalized software. Charges also include write-offs and lease cancellation costs related to acquired information technology equipment replaced with our standard common office equipment and exit costs on other leased assets. As a result of the merger, Halliburton Company’s and Dresser Industries, Inc.’s completion products operations and formation evaluation businesses have been combined. Excluded is Halliburton’s logging-while-drilling business and a portion of our measurement-while-drilling business which were required to be disposed of in connection with the United States Department of Justice consent decree. See Note 2. We recorded impairments based upon anticipated future cash flows in accordance with Statement of Financial Accounting Standards No. 121. This was based on the change in strategic direction, the outlook for the industry, the decision to standardize equipment product offerings and the expected loss on the disposition of the logging-while- drilling business. The following table summarizes the resulting write-downs of excess of cost over net assets acquired and long- lived assets associated with: • the directional drilling and formation evaluation businesses acquired in 1993 from Smith International, Inc.; • the formation evaluation business acquired in the 1988 acquisition of Gearhart Industries, Inc.; and • Mono Pumps and AVA acquired in 1990 and 1992. Millions of dollars Drilling operations of pre-merger Halliburton Energy Services Logging operations of pre-merger Halliburton Energy Services Mono Pump industrial and oilfield pump operations of Dresser AVA completion products Excess of Cost Over Net Assets Related Long- Lived Assets Total $125 $ 96 $221 51 43 54 — 3 — $ 153 105 43 37 1 $407 business of Dresser Oil Tools Abandonment of a trademark Total 34 1 $ 254 As discussed below, the merger caused management to reevaluate the realizability of excess cost over net assets acquired and related long-lived assets of these product service lines. Each business was considered to be impaired under SFAS No. 121 guidance. The overall market assumptions on which the impairment computations were made assumed that 1999 calendar year drilling activity as measured by worldwide rig count would be 1,900 rigs which was up from the 1,700 level in the third quarter of 1998. Rig count for calendar year 2000 and beyond was assumed to H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 57 N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S increase about 3% per year based upon estimated long-term growth in worldwide demand for oil and gas. These assumptions were based on market data available at the time of the merger. In addition to these assumptions, management utilized a 10- year timeframe for future projected cash flows, a discount rate that approximates its average cost of capital, and specific assumptions for the future performance of each product service line. The most significant assumptions are discussed below. In each case, these analyses represented management’s best estimate of future results for these product service lines. Drilling operations of pre-merger Halliburton Energy Services. Our pre-merger drilling business consisted of logging-while-drilling, measurement-while-drilling and directional drilling services. The majority of the pre-merger logging-while- drilling business and a portion of the pre-merger measurement- while-drilling business were required to be sold under the United States Department of Justice consent decree. We have integrated the remaining drilling business with the Sperry-Sun operations of Dresser. Our strategy focuses generally on operating under the Sperry-Sun name and using Sperry-Sun’s superior technology, tools and industry reputation. Our remaining pre-merger drilling assets and technology are being de-emphasized as they wear out or become obsolete. These tools will not be replaced resulting in significant decreases in future cash flows and an impairment of the excess of cost over net assets and related long-lived assets. Significant forecast assumptions included a revenue decline in the remaining pre-merger drilling business due to the measurement-while-drilling sale in the first year. Related revenue and operating income over the following 10 years were projected to decline due to reduced business opportunities resulting from our shift in focus toward Sperry-Sun’s tools and technologies. We determined that there was a $125 million impairment of excess of cost over net assets acquired. In addition, related long-lived asset impairments consisted of $61 million of property and equipment and $14 million of related spare parts, the value of which was estimated using the “held for use” model during the forecast period. An impairment of $3 million was recorded related to property and equipment and $18 million of spare parts using the “held for sale” model sold in accordance with the consent decree with the United States Department of Justice. See Note 2. Logging operations of pre-merger Halliburton Energy Services. The merger of Halliburton Company and Dresser Industries, Inc. enabled the acceleration of a formation evaluation strategy. This strategy takes advantage of Sperry-Sun’s logging- while-drilling competitive position and reputation for reliability combined with our Magnetic Resonance Imaging Logging (MRIL®) technology acquired with the NUMAR acquisition in 1997. Prior to the merger, we were focused on growing the traditional logging business while working toward development of new systems to maximize the MRIL® technology. The merger allowed us to implement the new strategy and place the traditional logging business in a sustaining mode. This change in focus and strategy resulted in a shift of operating cash flows away from our traditional logging business. This created an impairment of the excess of cost over net assets and related long-lived assets related to our logging business. included Significant forecast assumptions revenues decreasing slowly over the 10-year period, reflecting the decline in the traditional logging markets. Operating income initially was forecasted to increase due to cost cutting activity, and then decline as revenue decreased due to the significant fixed costs in this product service line. We calculated $51 million impairment of the excess of cost over net assets acquired. In addition, related long-lived asset impairments consisted of $22 million of property and equipment and $32 million of spare parts which management estimated using the “held for use” model during the forecast period. Mono Pump operations of pre-merger Dresser. The amount of the impairment is $43 million, all of which represents excess of cost over net assets acquired associated with the business. Our strategy for Mono Pump is to focus primarily on the oilfield business including manufacturing power sections for drilling motors. The prior strategy included emphasis on non- oilfield related applications of their pumping technology and the majority of Mono Pump revenues were related to non- oilfield sales. The change in strategy will result in reduced future cash flows resulting in an impairment of the excess of costs over net assets acquired. Significant forecast assumptions included stable revenue for several years and then slowly declining due to decreasing emphasis of industrial market applications. Operating income was forecasted to initially be even with current levels but then decline over the period as revenues declined and fixed costs per unit increased. AVA operations of Dresser Oil Tools. The amount of the impairment is $37 million of which $34 million relates to excess of costs over net assets acquired. The plan for Dresser’s AVA business line (which supplies subsurface safety valves and other completion equipment) was to rationalize product lines which overlap with our pre-existing completion equipment business line. The vast majority of the AVA product lines were de-emphasized except for supporting the installed base of AVA equipment and specific special order requests from customers. AVA products were generally aimed at the high-end custom completion products market. Our strategy was to focus on standardized high-end products based upon pre-merger Halliburton designs thus reducing future AVA cash flows and impairing its assets and related excess of costs over net assets acquired. 58 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S Additional asset related charges. Additional asset related charges include: • $37 million for various excess fixed assets as a result of merging similar product lines. We have no future use for these assets and they have been scrapped; • $33 million for other assets related to capitalized software, which became redundant with the merger. Major components included redundant computer aided design systems and capitalized costs related to a portion of our enterprise-wide information system abandoned due to changed requirements of the post merger company. The redundant computer aided design systems were used in both the Energy Services Group and the Engineering and Construction Group and were immediately abandoned and replaced by superior systems required to meet the needs of the merged company; • $ 26 million for the inventory charge relates to excess inventory as a result of merging similar product lines and/or industry downturn. This included approximately $17 million related to overlapping product lines and excess inventory in the completion products business and $9 million related to various Dresser Equipment Group divisions due to excess inventory related to industry downturn. Inventory that was overlapping due to the merger was segregated and has been scrapped. Inventory reserves were increased to cover the estimated write-down to market for inventory with future use determined to be excess as a result of the industry downturn. Any future sales are expected to approximate the new lower carrying value of the inventory; • $5 million for the impairment of excess of cost over net assets acquired related to well construction technology that became redundant once the merger was complete due to similar but superior technology offered by Sperry-Sun. This technology will no longer be used as part of our integrated service offerings, thus reducing future cash flows. We will, however, continue to market this technology individually to third parties. An impairment based on a “held for use” model was calculated using a 10-year discounted cash flow model with a discount rate which approximates our average cost of capital; and • $1 million write-off of excess of cost over net assets acquired related to the Steamford product line in the Dresser Equipment Group valve and control division. Management made the strategic decision to exit this product line. Asset related charges have been reflected as direct reductions of the associated asset balances. Personnel Charges Personnel charges include severance and related costs incurred for announced employee reductions of 10,850 affecting all business segments, corporate and shared service functions. Personnel charges also include personnel costs related to change of control. In June 1999, management revised the planned employee reductions to 10,100 due in large part to higher than anticipated voluntary employee resignations. As of December 31, 2000, terminations of employees, consultants and contract personnel related to the 1998 special charge have been completed. Facility Consolidation Charges Facility consolidation charges include costs to dispose of owned properties or exit leased facilities. As a result of the merger with Dresser and the industry downturn, we recorded a charge for costs to vacate, sell or close excess and redundant service, manufacturing and administrative facilities throughout the world. The majority of these facilities are within the Energy Services Group. Expenses of $126 million included: • $85 million write-down of owned facilities for anticipated losses on planned disposals based upon the difference between the assets’ net book values and anticipated future net realizable value based upon the “to be disposed of” method; • $37 million lease buyout costs or early lease termination cost including: - estimated costs to buy out leases; - facility refurbishment/restoration expenses as required by the lease in order to exit property; - sublease differentials, as applicable; and - related broker/agent fees to negotiate and close buyouts; • $4 million facility maintenance costs to maintain vacated facilities between the abandonment date and the expected disposition date. Maintenance costs include lease expense, depreciation, maintenance, utilities, and third-party adminis- trative costs. As of December 31, 2000, we have substantially completed the work to vacate, sell or close the service, manufacturing and administrative facilities related to the 1998 special charge. The majority of the sold, returned or vacated properties are located in North America and have been eliminated from the Energy Services Group. The remaining expenditures will be made as the remaining properties are vacated and sold. Merger Transaction Charges Merger transaction costs include investment banking, filing fees, legal and professional fees and other merger related costs. We estimated our merger transaction costs to be $64 million. H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 59 N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S Other Charges Other charges of $46 million include the estimated contract exit costs associated with the elimination of duplicate agents and suppliers in various countries throughout the world. Through December 31, 2000, we have utilized substantially all of the estimated amount of other special charge costs. NOTE 13. CHANGE IN ACCOUNTING METHOD In April 1998, the American Institute of Certified Public Accountants issued Statement of Position 98-5 “Reporting on the Costs of Start-Up Activities.” This Statement requires costs of start-up activities and organization costs to be expensed as incurred. We adopted Statement of Position 98-5 effective January 1, 1999 and recorded expense of $30 million pretax or $19 million after-tax or $0.04 per diluted share. The components of the $30 million pretax cost, all contained within the Energy Services Group, that were previously deferred include: • $23 million for mobilization costs associated with specific contracts and for installation of offshore cementing equipment onto third party marine drilling rigs or vessels; and • $7 million for costs incurred opening a new manufacturing facility in the United Kingdom. NOTE 14. INCOME TAXES The components of the (provision) benefit for income taxes are: Years ended December 31 Millions of dollars Current income taxes: Federal Foreign State Total Deferred income taxes: Federal Foreign and state Total Continuing operations Discontinued operations Disposal of discontinued operations Benefit for change in accounting method Total 2 0 0 0 1999 1998 $ ( 1 6 ) ( 11 4 ) ( 5 ) ( 1 3 5 ) ( 2 0 ) 2 6 6 ( 1 2 9 ) ( 6 0 ) $ 137 (64) (2) 71 (175) (12) (187) (116) (98) $(260) (185) (7) (452) 293 4 297 (155) (90) ( 1 4 1 ) (94) — (cid:209) $ ( 3 3 0 ) 11 $(297) — $ (245) Included in federal income taxes for continuing operations are foreign tax credits of $113 million in 2000, $52 million in 1999 and $94 million in 1998. The United States and foreign components of income (loss) from continuing operations before income taxes and minority interests are as follows: Years ended December 31 Millions of dollars United States Foreign Total 2 0 0 0 $ 1 2 8 2 0 7 $ 3 3 5 1999 $131 176 $307 1998 $(428) 483 $ 55 The primary components of our deferred tax assets and liabilities and the related valuation allowances are as follows: December 31 Millions of dollars Gross deferred tax assets: Employee benefit plans Accrued liabilities Construction contract accounting methods Insurance accruals Inventory Intercompany profit Net operating loss carryforwards Basis in joint ventures Intangibles Special charges Alternative minimum tax carryforward All other Total Gross deferred tax liabilities: Depreciation and amortization Unrepatriated foreign earnings Safe harbor leases All other Total Valuation allowances: Net operating loss carryforwards All other Total Net deferred income tax asset 2 0 0 0 1999 $ 2 6 1 11 8 $250 116 11 7 1 0 9 4 3 4 2 3 5 3 3 2 0 6 (cid:209) 6 0 8 4 4 1 2 8 2 9 9 6 6 2 3 2 98 98 31 26 34 92 28 25 7 69 874 135 29 10 99 273 2 9 8 3 7 $ 5 7 5 31 1 32 $569 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. 60 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S We have net operating loss carryforwards of $44 million which expire in 2001 through 2005. We also have net operating loss carryforwards of $75 million with indefinite expiration dates. 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: In connection with the acquisition of Dresser in 1998, we assumed the outstanding stock options under the stock option plans maintained by Dresser. See Note 2. Stock option transac- tions summarized below include amounts for the 1993 Stock and Long-Term Incentive Plan and stock plans of Dresser and other aquired companies. No further awards are being made under the stock plans of aquired companies. Years ended December 31 Millions of dollars Provision computed at 2 0 0 0 1999 1998 statutory rate $ ( 11 7 ) $ (99) $ (13) Reductions (increases) in taxes resulting from: Tax differentials on foreign earnings State income taxes, net of federal income tax benefit Special charges Nondeductible goodwill Other items, net Continuing operations Discontinued operations Disposal of discontinued operations Benefit for change in accounting method Total ( 1 4 ) (14) (17) ( 3 ) (cid:209) ( 11 ) 1 6 ( 1 2 9 ) ( 6 0 ) (1) — (10) 8 (116) (98) (7) (109) (11) 2 (155) (90) ( 1 4 1 ) (94) — (cid:209) $ ( 3 3 0 ) 11 $(297) — $(245) Stock Options Outstanding at December 31, 1997 Granted Exercised Forfeited Outstanding at December 31, 1998 Granted Exercised Forfeited Outstanding at December 31, 1999 Granted Exercised Forfeited Outstanding at Number of Shares (in millions) Exercise Price per Share 12.4 4.2 (2.4) (0.4) 13.8 5.6 (1.7) (0.6) 17.1 1.7 (3.6) (0.5) $ 3.10 – 61.50 26.19 – 46.50 3.10 – 37.88 5.40 – 54.50 $ 3.10 – 61.50 28.50 – 48.31 3.10 – 54.50 8.28 – 54.50 $ 3.10 – 61.50 34.75 – 54.00 3.10 – 45.63 12.20 – 54.50 Weighted Average Exercise Price per Share $26.55 33.07 20.84 33.64 $29.37 36.46 24.51 35.61 $32.03 41.61 25.89 37.13 December 31, 2000 14.7 $ 8.28 – 61.50 $34.54 NOTE 15. COMMON STOCK Options outstanding at December 31, 2000 are composed of On June 25, 1998, our shareholders voted to increase the number of authorized shares from 400 million to 600 million. 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, 2000, 27 million shares were available for future grants under the 1993 Stock and Long-Term Incentive Plan with 12.7 million shares remaining available for restricted stock awards. the following: Range of Exercise Prices $ 8.28 – 28.13 28.50 – 34.75 35.00 – 39.50 39.56 – 61.50 Outstanding Weighted Exercisable Number of Shares (in millions) Average Weighted Average Exercise Price Remaining Contractual Life Number of Shares (in millions) 3.8 3.8 5.0 2.1 5.8 7.5 8.0 7.6 7.2 $23.60 30.58 39.08 50.42 $34.54 3.2 1.8 2.4 1.4 8.8 Weighted Average Exercise Price $22.76 29.50 38.77 50.87 $32.81 $ 8.28 – 61.50 14.7 There were 9.5 million options exercisable with a weighted average exercise price of $28.96 at December 31, 1999, and 7.8 million options exercisable with a weighted average exercise price of $25.72 at December 31, 1998. H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 61 N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S All stock options under the 1993 Stock and Long-Term Incentive Plan, including options granted to employees of Dresser since its acquisition, are granted at the fair market value of the common stock at the grant date. 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 Risk-Free Interest Rate Expected Dividend Yield Expected Life (in years) 5.2% 5.8% 1.3% 1.3% 5 5 Expected Volatility 54.0% 56.0% 4.3 – 5.3% 1.2 – 2.7% 5 – 6.5 20.1 – 38.0% Weighted Average Fair Value of Options Granted $21.57 $19.77 $11.63 2000 1999 1998 Stock options generally expire 10 years from the grant date. Stock options under the 1993 Stock and Long-Term Incentive Plan vest over a three-year period, with one-third of the shares becoming exercisable on each of the first, second and third anniversaries of the grant date. Other plans have vesting periods ranging from three to 10 years. Options under the Non- Employee Directors’ Plan vest after six months. We account for the option plans in accordance with Accounting Principles Board Opinion No. 25, under which no compensation cost has been recognized for stock option awards. Compensation cost for the stock option programs calculated consistent with Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation,” is set forth on a pro forma basis below: Years ended December 31 Millions of dollars except per share data Net income: As reported Pro forma Diluted earnings per share: As reported Pro forma 2 0 0 0 1999 1998 $ 5 0 1 4 6 0 $ 1 . 1 2 1 . 0 3 $ 438 406 $0.99 0.92 $ (15) (43) $(0.03) (0.10) Restricted shares awarded under the 1993 Stock and Long-Term Incentive Plan were 695,692 in 2000, 352,267 in 1999 and 414,510 in 1998. The shares awarded are net of forfeitures of 69,402 in 2000, 72,483 in 1999 and 136,540 in 1998. The weighted average fair market value per share at the date of grant of shares granted was $42.25 in 2000, $43.41 in 1999 and $34.77 in 1998. 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 3,600 restricted shares in 2000, 4,800 restricted shares in 1999 and 3,200 restricted shares in 1998. At December 31, 2000, 28,800 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 $46.81 in 2000, $46.13 in 1999 and $36.31 in 1998. 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, 2000, 152,850 shares (net of 42,550 shares forfeited) have been issued. Forfeitures were 7,450 in 2000, 8,400 in 1999 and 1,900 in 1998. 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, 2000, 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 ten years. Restrictions may also lapse for early retirement and other conditions in accordance with our established policies. 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 restric- tions lapse. At December 31, 2000, the unamortized amount is $63 million. We recognized compensation costs in income of $18 million in 2000, $11 million in 1999 and $8 million in 1998. NOTE 16. 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 antidilution 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. 62 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S 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 2000 made the preferred stock purchase rights exercisable. NOTE 17. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT Foreign exchange risk. Techniques in managing foreign exchange risk include, but are not limited to, foreign currency borrowing and investing and the use of currency derivative instruments. We selectively hedge significant exposures to potential foreign exchange losses considering current market conditions, future operating activities and the cost of hedging the exposure in relation to the perceived risk of loss. The purpose of our foreign currency hedging 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 hedge our currency exposure through the use of currency derivative instruments. 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 hedge identifiable foreign currency commitments. Losses of $1 million for identifiable foreign currency commitments were deferred at December 31, 2000. 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 hedge foreign currency commitments with an indeterminable maturity date. None of the forward or option contracts are exchange traded. While hedging instruments are subject to fluctuations in value, the fluctuations are generally offset by the value of the underlying exposures being hedged. The use of some contracts may limit our ability to benefit from favorable fluctuations in foreign exchange rates. The notional amounts of open forward contracts and options for continuing operations were $281 million and $297 million at year-end 2000 and 1999, respectively. Amounts related to discontinued operations were $61 million and $96 million at December 31, 2000 and 1999, respectively. 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. We actively monitor our foreign currency exposure and adjust the amounts hedged as appropriate. Exposures to some currencies are generally not hedged 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. 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 or groups of counterparties related to our derivative contracts. We select counterparties based on creditworthiness, which we continually monitor, and on the counterparties’ ability to perform their obligations under the terms of the transactions. We do not expect any counterparties to fail to meet their obligations under these contracts given their high credit ratings. Therefore, we consider the credit risk associated with our derivative contracts to be minimal. Fair market value of financial instruments. The estimated fair market value of long-term debt at year-end 2000 and 1999 was $1,066 million and $1,352 million, respectively, as compared to the carrying amount of $1,057 million at year- end 2000 and $1,364 million at year-end 1999. 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 8. The carrying amount of short-term financial instruments, cash and equivalents, receivables, short-term notes payable and accounts payable, as reflected in the consol- idated balance sheets approximates fair market value due to the short maturities of these instruments. The fair market value of currency derivative instruments generally approxi- mates their carrying amount based upon third-party quotes. H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 63 N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S The fair market values of derivative instruments used for fair value hedging and cash flow hedging were immaterial. Millions of dollars 2 0 0 0 1999 U.S. Int’l. U.S. Int’l. NOTE 18. RETIREMENT PLANS at beginning of year $ 466 $ 2,134 $445 $1,817 CHANGE IN PLAN ASSETS Fair value of plan assets Our company and subsidiaries have various plans which cover a significant number of their employees. These plans include defined contribution plans, which provide retirement contribu- tions 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 $182 million, $146 million, and $152 million in 2000, 1999 and 1998, respectively. 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. Actual return on plan assets Employer contribution Settlements Plan participants’ contributions Divestitures Currency fluctuations Benefits paid 18 17 (14) (cid:209) (153) (cid:209) (21) 262 25 (cid:209) 13 (47) (199) (58) Fair value of plan assets at end of year $ 313 $ 2,130 $ 25 $ 493 65 22 (13) — — — (53) $466 $ 53 376 26 — 15 — (47) (53) $2,134 $ 387 Funded status Unrecognized transition obligation/(asset) Unrecognized actuarial (gain)/loss Unrecognized prior (1) 4 17 (378) — (31) (6) (275) service cost/(benefit) 13 (79) 7 (41) Net amount recognized $ 41 $ 53 $ 29 $ 65 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. Millions of dollars 2 0 0 0 1999 Millions of dollars 2 0 0 0 1999 U.S. Int’l. U.S. Int’l. U.S. Int’l. U.S. Int’l. CHANGE IN BENEFIT OBLIGATION AMOUNTS RECOGNIZED Benefit obligation at beginning of year $ 413 $ 1,747 $430 $1,716 IN THE CONSOLIDATED Service cost Interest cost Plan participants’ contributions Effect of business combinations Amendments Divestitures Settlements/curtailments Currency fluctuations Actuarial gain/(loss) Benefits paid 4 20 (cid:209) (cid:209) 5 (138) (8) (cid:209) 13 (21) 53 85 13 32 (cid:209) (61) (cid:209) (163) (11) (58) 7 30 — — 5 — (3) — (3) (53) 66 96 15 — 11 — — (44) (60) (53) Benefit obligation at end of year $ 288 $ 1,637 $413 $1,747 BALANCE SHEETS Prepaid benefit cost Accrued benefit liability Intangible asset Deferred tax asset Accumulated other comprehensive income $ 54 (28) 10 1 4 $ 93 (49) 1 (cid:209) 8 Net amount recognized $ 41 $ 53 $ 43 (38) 11 — 13 $ 29 $ 98 (40) 1 — 6 $ 65 64 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S 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: Weighted-average assumptions 2 0 0 0 1999 1998 Expected return on plan assets: United States plans 9.0% 9.0% 8.5% to 9.0% 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 2000 of 10.0% which are expected to decline to 5.0% by 2005. Obligations and expenses for postretirement medical plans in the following tables include both continuing and discontinued operations. International plans 3.5% to 8.0% 7.25% to 8.0% 7.0% to 11.0% Millions of dollars 2 0 0 0 1999 Discount rate: United States plans 7.5% 7.5% 7.25% to 8.0% International plans 4.0% to 5.5% 2.5% to 7.5% 2.0% to 12.5% Rate of compensation increase: United States plans 4.5% 4.5% to 5.0% 4.5% to 5.0% International plans 3.5% to 7.6% 1.0% to 10.5% 2.0% to 11.0% Millions of dollars 2 0 0 0 1999 1998 U.S. Int’l. U.S. Int’l. U.S. Int’l. COMPONENTS OF NET PERIODIC BENEFIT COST Service cost Interest cost Expected return on $ 4 $ 20 53 85 $ 7 $ 66 $ 5 $ 57 30 96 27 111 plan assets (26) (135) (33) (145) (30) (123) Transition amount (cid:209) (cid:209) 1 (2) 1 (2) Amortization of prior service cost (1) (6) (2) (7) (4) (7) Settlements/curtailments loss/(gain) 10 (cid:209) 14 — (4) (2) Recognized actuarial (gain)/loss (cid:209) (10) (1) (11) — — Net periodic benefit cost $ 7 $ (13) $ 16 $ (3) $ (5) $ 34 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 were $172 million, $154 million, and $82 million, respectively, as of December 31, 2000. They were $205 million, $199 million, and $183 million, respectively, as of December 31, 1999. 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 CHANGE IN BENEFIT OBLIGATION Benefit obligation at beginning of year Service cost Interest cost Plan participants’ contributions Amendments Acquisitions/divestitures, net Settlements/curtailments Actuarial gain/(loss) Benefits paid Benefit obligation at end of year CHANGE IN PLAN ASSETS Fair value of plan assets at beginning of year Employer contribution Plan participants’ contributions Benefits paid Fair value of plan assets at end of year Funded status Employer contribution Unrecognized actuarial (gain)/loss Unrecognized prior service cost Net amount recognized $ 3 9 2 3 2 0 11 (cid:209) ( 11 0 ) (cid:209) 11 ( 3 1 ) $ 2 9 6 $ (cid:209) 2 0 11 ( 3 1 ) $ (cid:209) $ ( 2 9 6 ) 3 ( 2 0 ) ( 7 8 ) $ ( 3 9 1 ) $403 5 28 8 1 — (1) (15) (37) $392 $ — 29 8 (37) $ — $(392) 1 (72) (98) $(561) Millions of dollars AMOUNTS RECOGNIZED IN THE CONSOLIDATED BALANCE SHEETS Accrued benefit liability Net amount recognized 2 0 0 0 1999 $ ( 3 9 1 ) $ ( 3 9 1 ) $(561) $(561) Weighted-average assumptions 2 0 0 0 Discount rate 1998 7.50% 7.50% 7.0% to 8.0% 1999 Millions of dollars 2 0 0 0 1999 1998 COMPONENTS OF NET PERIODIC BENEFIT COST $ 3 Service cost 2 0 Interest cost ( 7 ) Amortization of prior service cost Settlements/curtailments loss/(gain) (cid:209) ( 1 ) Recognized actuarial (gain)/loss $ 1 5 Net periodic benefit cost $ 5 28 (9) (2) (5) $17 $ 4 28 (10) — (8) $ 14 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 65 N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S NOTE 20. DRESSER FINANCIAL INFORMATION Since becoming a wholly owned subsidiary, Dresser Industries, Inc. has ceased filing periodic reports with the Securities and Exchange Commission. Dresser’s 8% guaranteed senior notes, which were initially issued by Baroid Corporation, remain outstanding and are fully and unconditionally guaranteed by Halliburton. In January 1999, as part of the legal reorganization associated with the merger, Halliburton Delaware, Inc., a first- tier holding company subsidiary, was merged into Dresser. The majority of our operating assets and activities are included in Dresser and its subsidiaries. In August 2000 the Securities and Exchange Commission released a new rule governing the financial statements of guarantors and issuers of guaranteed securities registered with the SEC. The following condensed consolidating financial information presents Halliburton and our subsidiaries on a stand-alone basis using the equity method and as if our current organizational structure were in place for all periods presented. 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: Millions of dollars Effect on total of service and interest cost components Effect on the postretirement benefit obligation One-Percentage-Point (Decrease) Increase $ 2 22 $ (2) (22) NOTE 19. SUBSEQUENT EVENT In March 2001 our offer to acquire the PGS Data Management division of Petroleum Geo-Services ASA (PGS) was accepted by the PGS shareholders. PGS Data Management has developed cost effective internet enabled storage, browsing and retrieval of large volumes of exploration and production data and information. Terms of the agreement include a cash transfer of $175 million prior to working capital contribution and a contract where Landmark will manage the seismic library of PGS for three years. PGS Data Management will become part of the Landmark Graphics business that is included in the Energy Services Group. Condensed Consolidating Statements of Income Millions of dollars YEAR ENDED DECEMBER 31, 2000 Total revenues Cost of revenues General and administrative Gain on sale of marine vessels Interest expense Interest income Other, net Income from continuing operations before taxes and minority interest Provision for income taxes Minority interest in net income of subsidiaries Income from continuing operations Income from discontinued operations Gain on disposal of discontinued operations, net of tax Net income Non-issuer/ Non-guarantor Subsidiaries Dresser Industries, Inc. (Issuer) Halliburton Company (Guarantor) Consolidating Adjustments Consolidated Halliburton Company $ 11 , 9 4 4 11 , 2 1 8 3 5 2 ( 8 8 ) ( 2 9 ) 2 1 3 4 5 7 ( 1 6 3 ) ( 1 8 ) 2 7 6 9 8 (cid:209) 3 7 4 $ $ 3 7 4 (cid:209) (cid:209) (cid:209) ( 4 5 ) 1 8 1 2 9 4 7 6 8 (cid:209) 4 8 4 (cid:209) 2 1 5 $ 6 9 9 $ 6 9 9 (cid:209) (cid:209) (cid:209) ( 8 7 ) 1 5 5 6 6 8 2 6 (cid:209) 6 9 4 (cid:209) $ ( 1 , 0 7 3 ) (cid:209) (cid:209) (cid:209) 1 5 ( 1 5 ) ( 1 9 3 ) ( 1 , 2 6 6 ) (cid:209) (cid:209) ( 1 , 2 6 6 ) (cid:209) (cid:209) $ 6 9 4 (cid:209) $ ( 1 , 2 6 6 ) $ $ 11 , 9 4 4 11 , 2 1 8 3 5 2 ( 8 8 ) ( 1 4 6 ) 2 5 ( 6 ) 3 3 5 ( 1 2 9 ) ( 1 8 ) 1 8 8 9 8 2 1 5 5 0 1 66 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S Condensed Consolidating Statements of Income Non-issuer/ Non-guarantor Subsidiaries Dresser Industries, Inc. (Issuer) Halliburton Company (Guarantor) Consolidating Adjustments Consolidated Halliburton Company Millions of dollars YEAR ENDED DECEMBER 31, 1999 Total revenues Cost of revenues General and administrative Special charges and credits Interest expense Interest income Other, net Income from continuing operations before taxes, minority interest, and change in accounting method Provision for income taxes Minority interest in net income of subsidiaries Income from continuing operations before change in accounting method Income from discontinued operations Gain on disposal of discontinued operations, net of tax $12,313 11,608 351 (47) (33) 77 (29) 416 (92) (17) 307 124 159 Cumulative effect of change in accounting method, net of tax benefit Net income (19) 571 $ Condensed Consolidating Statements of Income $571 — — — (50) 26 105 652 2 — 654 — — — $654 $654 — — — (87) — 183 750 (26) — 724 — — $ (1,225) — — — 29 (29) (286) (1,511) — — (1,511) — — $ 12,313 11,608 351 (47) (141) 74 (27) 307 (116) (17) 174 124 159 — $724 — $ (1,511) (19) 438 $ Millions of dollars YEAR ENDED DECEMBER 31, 1998 Total revenues Cost of revenues General and administrative Special charges and credits Interest expense Interest income Other, net Income from continuing operations before taxes and minority interest Provision for income taxes Minority interest in net income of subsidiaries Income from continuing operations Income from discontinued operations Net income (loss) Non-issuer/ Non-guarantor Subsidiaries Dresser Industries, Inc. (Issuer) Halliburton Company (Guarantor) Consolidating Adjustments Consolidated Halliburton Company $14,504 13,022 438 875 (20) 52 (1) 200 (127) (20) 53 105 158 $ $ 158 — (1) — (225) 4 (1) (63) (8) — (71) — $ (71) $ (71) — — — (52) 133 (5) 5 (20) — (15) — $ (15) $ (87) — — — 163 (163) — (87) — — (87) — $ (87) $14,504 13,022 437 875 (134) 26 (7) 55 (155) (20) (120) 105 (15) $ H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 67 $ 2 1 6 $ 11 $ 4 $ N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S Condensed Consolidating Balance Sheets Non-issuer/ Non-guarantor Subsidiaries Dresser Industries, Inc. (Issuer) Halliburton Company (Guarantor) Consolidating Adjustments Consolidated Halliburton Company Millions of dollars DECEMBER 31, 2000 ASSETS Current assets: Cash and equivalents Receivables: Notes and accounts receivable, net Unbilled work on uncompleted contracts Total receivables Inventories Other current assets Total current assets Property, plant and equipment, net Equity in and advances to unconsolidated affiliates Intercompany receivable from consolidated affiliates Equity in and advances to consolidated affiliates Net goodwill Other assets Total assets LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accounts and notes payable Other current liabilities Total current liabilities Long-term debt Intercompany payable from consolidated affiliates Other liabilities Minority interest in consolidated subsidiaries Total liabilities Shareholders’ equity: Common shares Other shareholders’ equity Total shareholders’ equity Total liabilities and shareholders’ equity 2 , 9 6 6 8 1 6 3 , 7 8 2 7 2 3 7 5 3 5 , 4 7 4 2 , 4 1 0 2 5 8 6 8 (cid:209) 5 1 0 1 , 1 0 9 $ 9 , 8 2 9 $ 7 5 6 1 , 3 7 4 2 , 1 3 0 2 0 5 (cid:209) 1 , 11 8 3 8 3 , 4 9 1 3 9 1 5 , 9 4 7 6 , 3 3 8 $ 9 , 8 2 9 6 3 (cid:209) 6 3 (cid:209) 1 7 5 (cid:209) 1 4 2 (cid:209) 6 , 5 5 8 8 7 5 $ 6 , 8 6 7 $ 6 4 3 6 1 0 0 4 4 4 2 , 2 0 6 2 6 (cid:209) 2 , 7 7 6 (cid:209) 4 , 0 9 1 4 , 0 9 1 $ 6 , 8 6 7 (cid:209) (cid:209) (cid:209) (cid:209) 1 5 1 9 (cid:209) (cid:209) (cid:209) (cid:209) (cid:209) (cid:209) (cid:209) (cid:209) (cid:209) (cid:209) (cid:209) $ 2 3 1 3 , 0 2 9 8 1 6 3 , 8 4 5 7 2 3 7 6 9 5 , 5 6 8 2 , 4 1 0 4 0 0 (cid:209) 2 , 1 3 8 ( 2 , 2 0 6 ) 4 , 2 2 0 (cid:209) 1 4 $ 6 , 3 9 1 ( 1 0 , 7 7 8 ) (cid:209) (cid:209) $ ( 1 2 , 9 8 4 ) (cid:209) 5 9 7 1 , 1 2 8 $ 1 0 , 1 0 3 $ 1 , 5 4 0 5 6 1 , 5 9 6 4 0 0 (cid:209) 11 8 (cid:209) 2 , 11 4 1 , 1 3 2 3 , 1 4 5 4 , 2 7 7 $ 6 , 3 9 1 $ (cid:209) (cid:209) (cid:209) (cid:209) ( 2 , 2 0 6 ) (cid:209) (cid:209) ( 2 , 2 0 6 ) $ 2 , 3 6 0 1 , 4 6 6 3 , 8 2 6 1 , 0 4 9 (cid:209) 1 , 2 6 2 3 8 6 , 1 7 5 ( 3 9 1 ) ( 1 0 , 3 8 7 ) ( 1 0 , 7 7 8 ) $ ( 1 2 , 9 8 4 ) 1 , 1 3 2 2 , 7 9 6 3 , 9 2 8 $ 1 0 , 1 0 3 68 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S Condensed Consolidating Balance Sheets Non-issuer/ Non-guarantor Subsidiaries Dresser Industries, Inc. (Issuer) Halliburton Company (Guarantor) Consolidating Adjustments Consolidated Halliburton Company $ 315 $ 44 $ 107 $ Millions of dollars DECEMBER 31, 1999 ASSETS Current assets: Cash and equivalents Receivables: Notes and accounts receivable, net Unbilled work on uncompleted contracts Total receivables Inventories Other current assets Total current assets Property, plant and equipment, net Equity in and advances to unconsolidated affiliates Intercompany receivable from consolidated affiliates Equity in and advances to consolidated affiliates Net goodwill Other assets Total assets LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accounts and notes payable Other current liabilities Total current liabilities Long-term debt Intercompany payable from consolidated affiliates Other liabilities Minority interest in consolidated subsidiaries Total liabilities Shareholders’ equity: Common shares Other shareholders’ equity Total shareholders’ equity Total liabilities and shareholders’ equity 2,282 625 2,907 723 1,198 5,143 2,390 384 — — 411 993 $9,321 $ 758 671 1,429 213 628 1,136 44 3,450 391 5,480 5,871 $9,321 61 — 61 — — 105 — — — 6,126 94 5 $ 6,330 $ 228 425 653 443 1,897 29 — 3,022 — 3,308 3,308 $ 6,330 6 — 6 — 1 114 — — — — — — — — — — — 2,525 (2,525) 3,308 — — $5,947 $ 926 25 951 400 — 54 — 1,405 1,120 3,422 4,542 $ 5,947 (9,434) — — $ (11,959) $ — — — — (2,525) — — (2,525) (391) (9,043) (9,434) $(11,959) $ 466 2,349 625 2,974 723 1,199 5,362 2,390 384 — — 505 998 $ 9,639 $ 1,912 1,121 3,033 1,056 — 1,219 44 5,352 1,120 3,167 4,287 $9,639 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 69 N O T E S T O A N N U A L F I N A N C I A L S T A T E M E N T S Condensed Consolidating Statements of Cash Flows Millions of dollars Non-issuer/ Non-guarantor Subsidiaries Dresser Industries, Inc. (Issuer) Halliburton Company (Guarantor) Consolidating Adjustments Consolidated Halliburton Company YEAR ENDED DECEMBER 31, 2000 Net cash flows from operating activities Capital expenditures Sales of property, plant and equipment Other investing activities Payments on long-term borrowings Net borrowings (repayments) of short-term debt Payments of dividends to shareholders Proceeds from exercises of stock options Payments to reacquire common stock Other financing activities Effect of exchange rate on cash Net cash flows from discontinued operations Increase (decrease) in cash and equivalents $ ( 2 3 2 ) ( 5 7 8 ) 2 0 9 ( 4 2 ) ( 8 ) 1 7 (cid:209) (cid:209) (cid:209) ( 2 8 2 ) ( 9 ) 8 2 6 $ ( 9 9 ) YEAR ENDED DECEMBER 31, 1999 Net cash flows from operating activities Capital expenditures Sales of property, plant and equipment Other investing activities Payments on long-term borrowings Net borrowings (repayments) of short-term debt Payments of dividends to shareholders Proceeds from exercises of stock options Payments to reacquire common stock Other financing activities Effect of exchange rate on cash Net cash flows from discontinued operations Increase (decrease) in cash and equivalents YEAR ENDED DECEMBER 31, 1998 Net cash flows from operating activities Capital expenditures Sales of property, plant and equipment Other investing activities Borrowings of long-term debt Payments on long-term borrowings Net borrowings (repayments) of short-term debt Payments of dividends to shareholders Proceeds from exercises of stock options Payments to reacquire common stock Other financing activities Effect of exchange rate on cash Net cash flows from discontinued operations Increase (decrease) in cash and equivalents $ (203) (520) 118 295 (9) (27) — — — 237 5 234 130 $ $ $ 409 (839) 83 (23) — (17) (77) — — — 143 (5) 235 (91) $ 11 4 (cid:209) (cid:209) (cid:209) ( 3 0 0 ) (cid:209) (cid:209) (cid:209) (cid:209) 1 5 3 (cid:209) (cid:209) $ ( 3 3 ) $ $ 53 — — — — — — — — (12) — — 41 $ (337) (2) — — — (11) — (100) — (16) 466 — — $ — $ 6 1 (cid:209) (cid:209) 1 0 9 (cid:209) 6 1 2 ( 2 2 1 ) 1 0 5 ( 7 6 9 ) (cid:209) (cid:209) (cid:209) $ ( 1 0 3 ) $ $ $ $ 92 — — (231) (50) 463 (221) 49 (10) — — — 92 78 — — (634) 150 — 463 (154) 49 (4) — — — (52) $ (cid:209) (cid:209) (cid:209) ( 1 0 9 ) (cid:209) (cid:209) (cid:209) (cid:209) (cid:209) 1 0 9 (cid:209) (cid:209) $ (cid:209) $ — — — 231 — — — — — (231) — — $ — $ — — — 625 — — — — — — (625) — — $ — $ ( 5 7 ) ( 5 7 8 ) 2 0 9 ( 4 2 ) ( 3 0 8 ) 6 2 9 ( 2 2 1 ) 1 0 5 ( 7 6 9 ) ( 2 0 ) ( 9 ) 8 2 6 $ ( 2 3 5 ) $ $ (58) (520) 118 295 (59) 436 (221) 49 (10) (6) 5 234 263 $ 150 (841) 83 (32) 150 (28) 386 (254) 49 (20) (16) (5) 235 $ (143) 70 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT S E L E C T E D F I N A N C I A L D A T A ( U N A U D I T E D ) We have restated our prior year information to display Dresser Equipment Group as discontinued operations. 2 0 0 0 1999 1998 1997 1996 $ 7 , 9 1 6 4 , 0 2 8 $ 11 , 9 4 4 $ 6,999 5,314 $12,313 $ 9,009 5,495 $ 14,504 Years ended December 31 Millions of dollars and shares except per share and employee data OPERATING RESULTS Net revenues Energy Services Group Engineering and Construction Group Total revenues OPERATING INCOME Energy Services Group Engineering and Construction Group Special charges and credits (1) General corporate Total operating income (1) Nonoperating income (expense), net (2) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST (Provision) benefit for income taxes (3) Minority interest in net income of consolidated subsidiaries Income (loss) from continuing operations Income (loss) from discontinued operations Net income (loss) BASIC INCOME (LOSS) PER COMMON SHARE Continuing operations Net income (loss) $ $ $ $ $ 5 2 6 1 4 (cid:209) ( 7 8 ) 4 6 2 ( 1 2 7 ) 3 3 5 ( 1 2 9 ) ( 1 8 ) 1 8 8 3 1 3 5 0 1 0 . 4 2 1 . 1 3 $ $ $ $ $ 222 203 47 (71) 401 (94) 307 (116) (17) 174 283 438 0.40 1.00 DILUTED INCOME (LOSS) PER COMMON SHARE Continuing operations Net income (loss) Cash dividends per share Return on average shareholders’ equity FINANCIAL POSITION Net working capital Total assets Property, plant and equipment, net Long-term debt (including current maturities) Shareholders’ equity Total capitalization Shareholders’ equity per share Average common shares outstanding (basic) Average common shares outstanding (diluted) OTHER FINANCIAL DATA Capital expenditures Long-term borrowings (repayments), net Depreciation and amortization expense Payroll and employee benefits (4) Number of employees (4), (5) 0 . 4 2 1 . 1 2 0 . 5 0 1 2 . 2 0 )% 0.39 0.99 0.50 10.49)% $ 1 , 7 4 2 1 0 , 1 0 3 2 , 4 1 0 1 , 0 5 7 3 , 9 2 8 6 , 5 5 5 9 . 2 0 4 4 2 4 4 6 $ ( 5 7 8 ) ( 3 0 8 ) 5 0 3 ( 5 , 2 6 0 ) 9 3 , 0 0 0 $ 2,329 9,639 2,390 1,364 4,287 6,590 9.69 440 443 $ (520) (59) 511 (5,647) 103,000 continued on next page $ 8,505 4,993 $ 13,498 $ 1,019 219 11 (71) 1,178 (82) 1,096 (406) (30) 660 112 772 1.53 1.79 $ $ $ $ $ 6,515 4,721 $11,236 $ $ $ $ $ 698 134 (86) (72) 674 (70) 604 (158) — 446 112 558 1.04 1.30 1.51 1.77 0.50 19.16)% 1.03 1.29 0.50 15.25)% $ 1,985 9,657 2,282 1,303 4,317 5,647 9.86 431 436 $ (804) 285 465 (5,479) 102,000 $ 1,501 8,689 2,047 957 3,741 4,828 8.78 429 432 $ (612) 286 405 (4,674) 93,000 $ $ $ $ 971 237 (959) (79) 170 (115) 55 (155) (20) (120) 105 (15) $ (0.27) (0.03) (0.27) (0.03) 0.50 (0.35)% $ 2,129 10,072 2,442 1,426 4,061 5,990 9.23 439 439 $ (841) 122 500 (5,880) 107,800 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 71 S E L E C T E D F I N A N C I A L D A T A ( U N A U D I T E D ) ( C O N T I N U E D ) We have restated our prior year information to display Dresser Equipment Group as discontinued operations. Years ended December 31 Millions of dollars and shares except per share and employee data OPERATING RESULTS Net revenues Energy Services Group Engineering and Construction Group Total revenues OPERATING INCOME Energy Services Group Engineering and Construction Group Special charges and credits (1) General corporate Total operating income (1) Nonoperating income (expense), net (2) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST (Provision) benefit for income taxes (3) Minority interest in net income of consolidated subsidiaries Income (loss) from continuing operations Income (loss) from discontinued operations Net income (loss) BASIC INCOME (LOSS) PER COMMON SHARE Continuing operations Net income (loss) DILUTED INCOME (LOSS) PER COMMON SHARE Continuing operations Net income (loss) Cash dividends per share Return on average shareholders’ equity FINANCIAL POSITION Net working capital Total assets Property, plant and equipment, net Long-term debt (including current maturities) Shareholders’ equity Total capitalization Shareholders’ equity per share Average common shares outstanding (basic) Average common shares outstanding (diluted) OTHER FINANCIAL DATA Capital expenditures Long-term borrowings (repayments), net Depreciation and amortization expense Payroll and employee benefits (4) Number of employees (4), (5) 1995 1994 1993 1992 1991 $5,308 3,737 $9,045 $ 544 97 (8) (71) 562 (34) 528 (167) (1) $ 360 $ 36 $ 381 $ 0.83 0.88 0.83 0.88 0.50 10.44)% $1,477 7,723 1,865 667 3,577 4,378 8.29 431 432 $ (474) (481) 380 (4,188) 89,800 $ 4,978 3,562 $8,540 $ 406 71 (19) (56) 402 333 735 (275) (14) $ 446 $ 97 $ 543 $ 1.04 1.26 1.03 1.26 0.50 15.47)% $2,197 7,774 1,631 1,119 3,723 4,905 8.63 431 432 $ (358) (120) 387 (4,222) 86,500 $5,470 3,675 $9,145 $ 414 76 (419) (63) 8 (61) (53) (18) (24) (95) 81 (14) $ $ $ $ (0.23) (0.04) $5,038 4,410 $ 9,448 $ 303 32 (294) (58) (17) (63) (80) (30) (9) $ (119) $ 49 $ (483) $ (0.29) (1.18) $5,156 4,721 $ 9,877 $ 378 48 (142) (56) 228 (23) 205 (117) (19) $ 69 $ 106 $ 182 $ 0.17 0.45 (0.23) (0.04) 0.50 (0.43)% (0.29) (1.18) 0.50 (12.72)% 0.17 0.45 0.50 4.16)% $ 1,563 8,087 1,747 1,129 3,296 4,746 7.70 422 422 $ (373) 192 574 (4,429) 90,500 $1,423 7,480 1,741 872 3,277 4,179 7.99 408 408 $ (405) (187) 470 (4,590) 96,400 $1,775 8,029 1,754 927 4,315 5,266 10.61 405 406 $ (572) 460 396 (4,661) 104,500 72 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT S E L E C T E D F I N A N C I A L D A T A ( U N A U D I T E D ) ( C O N T I N U E D ) (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). 1992 – $294 million: merger costs ($273 million) and restructuring and severance ($21 million). 1991 – $142 million: restructuring ($121 million) and loss on sale of business ($21 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. (5) Does not include employees of 50% or less owned affiliated companies. H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 73 Q U A R T E R L Y D A T A A N D M A R K E T P R I C E I N F O R M A T I O N ( U N A U D I T E D ) Millions of dollars except per share data First Second Third Fourth Year Quarter 2000 Revenues Operating income (1) Income (loss) from continuing operations Income from discontinued operations Gain on disposal of discontinued operations Net income Earnings per share: Basic income (loss) per common share: Income (loss) from continuing operations Income from discontinued operations Gain on disposal of discontinued operations Net income Diluted income (loss) per common share: Income (loss) from continuing operations Income from discontinued operations Gain on disposal of discontinued operations Net income Cash dividends paid per share Common stock prices (2) High Low 1999 (3) Revenues Operating income (4) Income from continuing operations before change in accounting method (4) Income from discontinued operations Gain on disposal of discontinued operations Change in accounting method Net income (4) Earnings per share: Basic income per common share: Income from continuing operations before change in accounting method (4) Income from discontinued operations Gain on disposal of discontinued operations Change in accounting method Net income Diluted income per common share: Income from continuing operations before change in accounting method (4) Income from discontinued operations Gain on disposal of discontinued operations Change in accounting method Net income Cash dividends paid per share Common stock prices (2) High Low $ 2 , 8 5 9 8 1 2 7 2 2 2 1 5 2 6 4 0 . 0 6 0 . 0 5 0 . 4 9 0 . 6 0 0 . 0 6 0 . 0 5 0 . 4 8 0 . 5 9 0 . 1 2 5 4 4 . 5 0 3 3 . 6 9 $ 2 , 8 6 8 1 2 6 5 2 2 3 (cid:209) 7 5 0 . 1 2 0 . 0 5 (cid:209) 0 . 1 7 0 . 1 2 0 . 0 5 (cid:209) 0 . 1 7 0 . 1 2 5 5 1 . 5 6 3 7 . 7 5 $ 3 , 0 2 4 2 4 8 1 3 0 2 7 (cid:209) 1 5 7 0 . 2 9 0 . 0 6 (cid:209) 0 . 3 5 0 . 2 9 0 . 0 6 (cid:209) 0 . 3 5 0 . 1 2 5 5 4 . 6 9 4 1 . 6 9 $ 3 , 1 9 3 7 ( 2 1 ) 2 6 (cid:209) 5 $ 11 , 9 4 4 4 6 2 1 8 8 9 8 2 1 5 5 0 1 ( 0 . 0 5 ) 0 . 0 6 (cid:209) 0 . 0 1 ( 0 . 0 5 ) 0 . 0 6 (cid:209) 0 . 0 1 0 . 1 2 5 5 0 . 3 8 3 3 . 3 8 0 . 4 2 0 . 2 2 0 . 4 9 1 . 1 3 0 . 4 2 0 . 2 2 0 . 4 8 1 . 1 2 0 . 5 0 5 4 . 6 9 3 3 . 3 8 $ 3,261 98 $ 3,053 143 $ 2,973 81 $ 3,026 79 $ 12,313 401 53 28 — (19) 62 0.12 0.06 — (0.04) 0.14 0.12 0.06 — (0.04) 0.14 0.125 41.19 28.25 55 28 — — 83 0.13 0.06 — — 0.19 0.13 0.06 — — 0.19 0.125 47.94 35.00 38 20 — — 58 0.09 0.04 — — 0.13 0.09 0.04 — — 0.13 0.125 51.44 39.06 28 48 159 — 235 0.06 0.11 0.36 — 0.53 0.06 0.11 0.36 — 0.53 0.125 44.13 33.88 174 124 159 (19) 438 0.40 0.28 0.36 (0.04) 1.00 0.39 0.28 0.36 (0.04) 0.99 0.50 51.44 28.25 74 H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT Q U A R T E R L Y D A T A A N D M A R K E T P R I C E I N F O R M A T I O N ( U N A U D I T E D ) ( C O N T I N U E D ) (1) Includes pretax job losses and severance for engineering and construction contracts and related restructuring of $193 million ($118 million after-tax or $0.27 per diluted share) in the fourth quarter of 2000. (2) New York Stock Exchange – composite transactions high and low closing price. (3) Amounts for revenues, operating income, net income, and earnings per share have been restated to show Dresser Equipment Group as discontinued operations. (4) Includes pretax special charge credit of $47 million ($32 million after-tax or $0.07 per diluted share) in the second quarter of 1999. H A L L I B U R T O N C O M PA N Y 2000 ANNUAL REPORT 75 H A L L I B U R T O N C O M P A N Y 2 0 0 0 A N N U A L R E P O R T H A L L I B U R T O N C O M P A N Y 76 HALLIBURTON COMPANY 2000 ANNUAL REPORT H A L L I B U R T O N C O M P A N Y 2 0 0 0 A N N U A L R E P O R T Lord Clitheroe (1987) (a) (b) (d) (e) Retired Chairman, The Yorkshire Bank, PLC London, England Charles J. DiBona (1997) (a) (b) (d) Retired President and Chief Executive Officer, American Petroleum Institute Great Falls, Virginia Ray L. Hunt (1998) (a) (b) (c) Chairman of the Board and Chief Executive Officer, Hunt Oil Company Dallas, Texas J. Landis Martin (1998) (a) (d) (e) President and Chief Executive Officer, NL Industries, Inc. Denver, Colorado Lawrence S. Eagleburger (1998) (a) (b) (c) (e) Senior Foreign Policy Advisor, Baker, Donelson, Bearman & Caldwell Washington, D.C. Robert L. Crandall (1986) (a) (b) (c) (e) Chairman Emeritus, AMR Corporation/ American Airlines, Inc. Irving, Texas W. R. Howell (1991) (a) (b) (c) Chairman Emeritus, J. C. Penny Company, Inc. Dallas, Texas David J. Lesar (2000) Chairman of the Board, President and Chief Executive Officer, Halliburton Company Dallas, Texas Jay A. Precourt (1998) (a) (b) (d) Chairman of the Board, Hermes Consolidated, Inc. Vail, Colorado C. J. Silas (1993) (a) (b) (c) Retired Chairman of the Board and Chief Executive Officer, Phillips Petroleum Company Bartlesville, Oklahoma (a) Member of the Management Oversight Committee, (b) Member of the Compensation Committee, (c) Member of the Audit Committee, (d) Member of the Health, Safety and Environment Committee, (e) Member of the Nominating and Corporate Governance Committee HALLIBURTON COMPANY 2000 ANNUAL REPORT 77 s s s s s s s s s s H02770 C O R P O R AT E O F F I C E : 3600 Lincoln Plaza, 500 North Akard Street, Dallas, Texas 75201-3391 USA www.halliburton.com 

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