Document Gz4vpwk2vad0w2OZV77xwJX7

Page 1 of 89 <DOCUMENT> <TYPE>10-K <SEQUENCE>1 <FILENAME>edl0k2001.txt <TEXT> UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) [X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2001 OR ( ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from to Commission File Number 1-3492 HALLIBURTON COMPANY (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation of organization) 75-2677995 (I.R.S. Employer Identification No.) 3600 Lincoln Plaza, 500 N. Akard St., Dallas, Texas 75201 (Address of principal executive offices) Telephone Number - Area code (214) 978-2600 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each Exchange on which registered Common Stock par value $2.50 per share Baroid Corporation 8% Guaranteed Senior Notes due 2003 New York Stock Exchange New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value of Common Stock held by nonaffiliates on February 28, 2002, determined using the per share closing price on the New York Stock Exchange Composite tape of $16.50 on that date was approximately $7,162,000.00. As of February 28, 2002, there were 435,613,251 shares of Halliburton Company Common Stock $2.50 par value per share outstanding. Portions of the Halliburton Company Proxy Statement dated March 19, 2002, are 1if+tv//www cer* crnWArrVih^c/prlaar/rlatci/zL^m 7/000004.S01 909000(31 1/<=r11 0V7001 fvt 8/71/7007 Page 2 of 89 incorporated by reference into Part III of this report. <PAGE> PART I Item 1. Business. General development of business. Halliburton Company's predecessor was established in 1919 and incorporated under the laws of the State of Delaware in 1924. Halliburton Company provides a variety of services, products, maintenance, engineering and construction to energy, industrial and governmental customers. See Note 2 to the financial statements for information related to recent acquisitions and dispositions. Financial information about business segments. We operate in two business segments: Energy Services Group; and Engineering and Construction Group. Dresser Equipment Group is presented as discontinued operations through March 31, 2001 as a result of the sale in April 2001 of its remaining businesses. See Note 4 to the financial statements for financial information about our business segments. Description of services and products. Our ability to mix, bundle or integrate products and services to meet the varied needs of our customers is of increasing importance in the highly competitive environment in which we operate. We believe that, based upon our customers' requirements, our future success will depend, in part, upon our ability to offer total capabilities and solutions on a global, industry-encompassing scale as well as discrete services and products. Our business strategy is focused on continuing to maintain global leadership in providing our customers discrete services, products, engineering, construction and maintenance which can be combined with our project management capabilities to provide our customers a wide range of integrated solutions. This strategy is dependent upon four key goals: technological leadership; operational excellence; innovative business relationships; and a dynamic workforce. We offer a broad suite of products and services through the two business segments. The following summary describes our services and products for each business segment. ENERGY SERVICES GROUP The Energy Services Group segment consists of Halliburton Energy Services, Landmark Graphics and operations through various product service lines in Surface/Subsea and major projects. This segment provides a wide range of discrete services and products, as well as integrated solutions to customers for the exploration, development and production of oil and gas. The segment serves major, national and independent oil and gas companies throughout the world. Halliburton Energy Services provides discrete products and services and integrated solutions ranging from the initial evaluation of producing formations to drilling, completion, production and well maintenance. Major product and service line offerings include: pressure pumping, including: cementing, production enhancement (fracturing and acidizing), and tools and testing; logging and perforating; drilling systems and services; drilling fluids systems; drill bits; completion products; integrated solutions; and reservoir description. Cementing is the process used to bond the well and well casing while isolating fluid zones and maximizing wellbore stability. This is accomplished by pumping cement and chemical additives to fill the space between the casing and hfftv//www cer* orv/Arrhivp<;/pr1oai7H5tn/4.^ni 9/000004.^01909000011/pH 1 0V9001 tvt ft/91 /9009 Page 3 of 89 the side of the wellbore. Our cementing service line also provides casing equipment and services. <PAGE> 1 Production enhancement optimizes oil and gas reservoirs through a variety of pressure pumping services, including: fracturing and acidizing, sand control, coiled tubing, well control, nitrogen services and specialty services. These services are used to clean out a formation or to fracture formations to allow increased oil and gas production. Tools and testing includes tubing-conveyed perforating products and services, drill stem and other well testing tools, data acquisition services and production applications. Logging products and services include our Magnetic Resonance Imaging Logging (MRIL(R)), high-temperature logging, as well as traditional open-hole and cased-hole logging tools. MRIL(R) tools apply medical diagnostic magnetic resonance imaging technology to the evaluation of subsurface rock formations in newly drilled oil and gas wells. Our high temperature logging tools combine advanced electronic and mechanical tool designs, quality materials and a telemetry system to operate in high temperature and high pressure downhole environments. Open-hole tools provide information on well visualization, formation evaluation (including resistivity, porosity, lithology and temperature), rock mechanics and sampling. Cased-hole tools provide cementing evaluation, reservoir monitoring, pipe evaluation, pipe recovery and perforating. Drilling systems and services are provided by Sperry-Sun Drilling Systems. These services include directional and horizontal drilling, measureraent-while-drilling, logging-while-drilling, multilateral wells and related completion systems, and rig site information systems. Our drilling systems feature increased bit stability, directional control, borehole quality, lower vibration, and higher rates of penetration while drilling directional wells. In 2001 we introduced the Geo-Pilot(TM), an advanced point-the-bit rotary steerable system that expands directional drilling capabilities while reducing overall drilling costs. Baroid provides fluid systems and performance additives for oil and gas drilling, completion and workover operations. In addition, Baroid sells products to a wide variety of industrial customers. Drill bits, offered by Security DBS, include roller cone rock bits, fixed cutter bits, coring equipment and services, and other downhole tools used to drill wells. Completion products include subsurface safety valves and flow control equipment, surface safety systems, packers and specialty completion equipment, production automation, well screens, well control services, and slickline equipment and services. Integrated solutions provides value-added oilfield project management and solutions to independent, integrated, and national oil companies. Integrated solutions enhance field deliverability and maximize the customer's return on investment. These services leverage all Halliburton Energy Services product service lines and technologies as well as overall project management capabilities. Reservoir description is composed of two groups - geoscience and engineering, and computed products. The geoscience and engineering group provides a comprehensive suite of products including opportunity assessment, reservoir characterization, field development planning, production enhancement, reservoir surveillance, and reservoir management. The computed products group provides interpretation for wellbore imaging, waveform sonics, cement evaluation, production, and a variety of open and cased-hole information evaluation logs. By combining reservoir description with field service capabilities and technology, Halliburton Energy Services provides complete reservoir solutions. Landmark Graphics is the leading supplier of integrated exploration and production software information systems as well as professional and data management services for the upstream oil and gas industry. Landmark's software )ittn*//ran oe*r* crmr!Arr>V>i^7pc/fv1a'>r/Hatci/4.^01 9/000004^01 90000001 1 /pdl 0L0001 f-vt S/01 /oooo Page 4 of 89 transforms vast quantities of seismic, well log and other data into detailed computer models of petroleum reservoirs to achieve optimal business and technical decisions in exploration, development and production activities. Landmark's broad range of professional services enable our worldwide customers to optimize technical, business and decision processes. Data management services provides efficient storage, browsing and retrieval of large volumes of exploration and petroleum data. The products and services offered by Landmark integrate data workflows and operational processes across disciplines including geophysics, geology, drilling, engineering, production, economics, finance and corporate planning, and key partners and suppliers. Surface/Subsea and major projects product service lines provide construction, installation and servicing of subsea facilities; flexible pipe for offshore applications; pipeline services for offshore customers; pipecoating services; feasibility, conceptual and front-end engineering and design, detailed engineering, procurement, construction site management, commissioning, start-up and debottlenecking of both onshore and offshore facilities; <PAGE> 2 and large integrated engineering, procurement, and construction projects containing both surface and sub-surface components. ENGINEERING AND CONSTRUCTION GROUP The Engineering and Construction Group segment, operating as Halliburton KBR, provides a wide range of services to energy and industrial customers and government entities worldwide. Halliburton KBR includes the following five product lines: Onshore operations comprises engineering and construction activities, including liquefied natural gas, ammonia, crude oil refineries, and natural gas plants; Offshore operations includes specialty offshore deepwater engineering and marine technology and worldwide fabrication capabilities; Government operations provides operations, maintenance and logistics activities for government facilities and installations; Operations and maintenance provides services for private sector customers, primarily industrial, hydrocarbon and commercial applications; and Asia Pacific operations, based in Australia, provides civil engineering and consulting services. Markets and competition. We are one of the world's largest diversified energy services and engineering and construction services companies. Our services and products are sold in highly competitive markets throughout the world. Competitive factors impacting sales of our services and products include: price, service (including the ability to deliver services and products on an "as needed, where needed" basis), product quality, warranty and technical proficiency. While we provide a wide range of discrete services and products, a number of customers have indicated a preference for integrated services and solutions. In the case of the Energy Services Group, integrated services and solutions relate to all phases of exploration, development and production of oil, natural gas and natural gas liquids. In the case of the Engineering and Construction Group, integrated services and solutions relate to all phases of design, procurement, construction, project management and maintenance of facilities primarily for energy and government customers. Demand for these types of integrated services and solutions is based primarily upon quality of service, technical proficiency, price and value created. We conduct business worldwide in over 100 countries. Since the markets for our services and products are vast and cross numerous geographic lines, a meaningful estimate of the number of competitors cannot be made. The industries we serve are highly competitive and we have many substantial competitors. Generally, our services and products are marketed through our own servicing and sales organizations. A small percentage of sales of the Energy Service Group's products is made through supply stores and third-party representatives. Operations in some countries may be adversely affected by unsettled littTv/Axmnv cpr rroi^/Ar^LArAo/^do-Qr/Hoto/A^ni 9/000004.^01 000000(11 1 nVOOfll +-v+ Q/oi /onm Page 5 of 89 political conditions, acts of terrorism, expropriation or other governmental actions, and exchange control and currency problems. We believe the geographic diversification of our business activities reduces the risk that loss of operations in any one country would be material to the conduct of our operations taken as a whole. Information regarding our exposures to foreign currency fluctuations, risk concentration, and financial instruments used to minimize risk is included on pages 23 and 24 under the caption "Financial Instrument Market Risk" and in Note 16 to the financial statements. Customers and backlog. Our revenues from continuing operations during the past three years were mainly derived from the sale of products and services to the energy industry. Sales of products and services to the energy industry in 2001 represented 85% of revenues from continuing operations compared to 84% in 2000 and 83% in 1999. The following schedule summarizes the backlog from continuing operations of engineering and construction projects at December 31, 2001 and 2000: <TABLE> <CAPTION> Millions of dollars 2001 2000 <S> Firm orders Government orders firm but not yet funded, letters of intent and contracts awarded but not signed Total </TABLE> <C> $ 8,118 1,794 $ 9,912 <C> $ 7,652 1,751 $ 9,403 <PAGE> 3 We estimate that 52% of the total backlog existing at December 31, 2001 will be completed during 2002. Approximately 45% of total backlog relates to fixed-price contracts with the remaining 55% relating to cost reimbursable contracts. For contracts which are not for a specific amount, backlog is estimated as follows: operations and maintenance contracts which cover multiple years are included in backlog based upon a rolling estimate of the work to be provided over the next twelve months; and government contracts which cover a broad scope of work up to a maximum value are included in backlog at the estimated amount of work to be completed under the contract based upon periodic consultation with the customer. For projects where we act as project manager, we only include our scope of each project in backlog. For projects related to unconsolidated joint ventures, we only include our percentage ownership of each joint venture's backlog. Our backlog excludes contracts for recurring hardware and software maintenance and support services offered by Landmark. Backlog does not indicate what future operating results will be because backlog figures are subject to substantial fluctuations. Arrangements included in backlog are in many instances extremely complex, nonrepetitive in nature and may fluctuate in contract value and timing. Many contracts do not provide for a fixed amount of work to be performed and are subject to modification or termination by the customer. The termination or modification of any one or more sizeable contracts or the addition of other contracts may have a substantial and immediate effect on backlog. Raw materials. Raw materials essential to our business are normally readily available. Where we are dependent on a single supplier for materials essential to our business, we are confident that we could make satisfactory alternative arrangements in the event of an interruption in supply. Research, development and patents. We maintain an active research and development program. The program improves existing products and processes, develops new products and processes and improves engineering standards and Lftr* */Axmror c^r* cmv/Arr4iii7vae/f3r1cTcir/data/4^ni O/nAnnAA^m OHOnnOOl 1 /oH 1 Atz-OAAI fvt e/oi /onao Page 6 of 89 practices that serve the changing needs of our customers. Information relating to our expenditures for research and development is included in Note 1 and Note 4 to the financial statements. We own a large number of patents and have pending a substantial number of patent applications covering various products and processes. We are also licensed under patents owned by others. We do not consider a particular patent or group of patents to be material to our business operations. Seasonality. Weather and natural phenomena can temporarily affect the performance of our services, but the widespread geographical locations of our operations serve to mitigate these. Examples of how weather can impact our business include: the severity and duration of the winter in North America can have a significant impact on gas storage levels and drilling activity for natural gas; the timing and duration of the spring thaw in Canada directly affects activity levels due to road restrictions; typhoons and hurricanes can disrupt offshore operations; and severe weather during the winter months normally results in reduced activity levels in the North Sea. Employees. At December 31, 1001, we employed approximately 85,000 people worldwide compared to 93,000 at December 31, 2000, which included about 9,000 related to discontinued operations. Environmental regulation. We are subject to various environmental laws and regulations. Compliance with these requirements has not substantially increased capital expenditures, adversely affected our competitive position or materially affected our earnings. We do not anticipate any material adverse effects in the foreseeable future as a result of existing environmental laws and regulations. See Note 9 to the financial statements. <PAGE> 4 Item 2. Properties. We own or lease numerous properties in domestic and foreign locations. following locations represent our major facilities: The <TABLE> <CAPTI0N> Location Owned/ Leased Sq. Footage Description <S> Energy Services Group North America Duncan, Oklahoma <C> Owned <C> <C> 603,000 Four locations whic totaling 442,000 sq facility is the mai cementing, fracturi by our pressure pun Duncan facilities a research center, tr offices, and warehc Houston, Texas Owned 690,000 Two suburban campus acres consisting of warehouse, manufact The manufacturing f square feet, produc equipment for our 1 product service lin manufacturing facil laboratory and ware produces fixed cutt titfn'/Aimmr e&n rrmr/Arrliii^pc/pHaor//1ofaMA01')/0nn0ri4Am000nn001 1 /o^l OVOnOI tvt e/oi nnm Page 7 of 89 Houston, Texas Carrollton, Texas Dallas, Texas Alvarado, Texas Panama City, Florida <PAGE> Location Europe/Africa Manchester, United Kingdom Newcastle, United Kingdom Arbroath, United Kingdom Aberdeen, United Kingdom Tananger, Norway Asia Pacific Singapore Engineering and Construction Group North America Houston, Texas Owned Owned Owned Owned Leased 5 593,000 792,000 352,000 238,000 180,000 A campus facility t Energy Services Grc Manufacturing facil engineering and sal research. The manu equipment for the c service line includ safety valves and p Manufacturing facil and warehouse space cone drill bits. Manufacturing facil warehouse space. 1 produces perforatin formation evaluatic and tubing conveyed service lines. Manufacturing facil warehous e/storage s used in our Surface Owned/ Leased Sq. Footage Description Owned Owned Leased Owned Owned Leased Leased 244,000 453,000 11,000 119,000 1,216,000 365,000 319,000 Primarily a manufac positive displaceme use in general indu applications. Manufacturing facil warehouse/storage s used in our Surface Manufacturing site completions product A total of 26 sites manufacturing capac service lines. Service center with warehousing and off Norwegian North Sea Owned 102,000 A manufacturing fac subsurface safety v the completions prc Leased 851,000 Engineering and prc the home office of full floors in 2 of buildings is owned have a 50% ownershi Ti+fn'/Aimmr cpa am;/Ar^i^rAe/oHrror/^Q+oM^OI O/OnnOD/l^ni 00000001 1 /^l OVOOni +v+ P/01/0AH0 Page 8 of 89 Europe/Africa Leatherhead, United Kingdom Owned 226,000 Engineering and prc in suburban London. Corporate North America Houston, Texas Owned 1,017,000 A campus facility c primarily for admin Approximately 221,0 warehousing and con and storage facilit Dallas, Texas </TABLE> Leased 26,000 Office facilities f We have two idle manufacturing facilities that we own in Longview, Texas with 151,000 square feet. These facilities were written down to fair market value in our 1998 special charge. <PAGE> 6 In addition, we have 153 international and 125 domestic field camps from which Halliburton Energy Services delivers its products and services. We also have numerous small facilities which include sales offices, project offices and bulk storage facilities throughout the world. We own or lease marine fabrication facilities covering approximately 761 acres in Texas, England and Scotland. We have mineral rights to proven and prospective reserves of barite and bentonite. These rights include leaseholds, mining claims and property owned in fee. Based on the number of tons of each of the above minerals consumed in fiscal year 2001, we estimate our proven reserves are sufficient for operations for the foreseeable future. All properties that we currently occupy are deemed suitable for their intended use. We have office space in Dallas, Texas totaling 80,000 square feet that is fully sublet. <PAGE> 7 Item 3. Legal Proceedings. Information relating to various commitments and contingencies is described in Management1s Discussion and Analysis of Financial Condition and Results of Operations and Note 9 to the financial statements. Item 4. Submission of Matters to a Vote of Security Holders. There were no matters submitted to a vote of security holders fourth quarter of 2001. during the <PAGE> 8 Executive Officers of the Registrant. The following table indicates the names and ages of the executive officers of the registrant as of February 1, 2002, along with a listing of all offices held by each during the past five years: <TABLE> <CAPTI0N> Name and Age Offices Held and Term of Office <S> <C> httrW/www epr crmr/ Arr-Vnvpc/pdaor/rlsta/A^ni 7/000004601 90900001 1 IpA 1 flVODfll tvt smnnm Jerry H. Blurton (Age 57) Margaret E. Carriere (Age 50) * Lester L. Coleman (Age 59) * Douglas L. Foshee (Age 42) * Robert R. Harl (Age 51) Robert F. Heinemann (Age 48) Arthur D. Huffman (Age 49) Page 9 of 89 Vice President and Treasurer, since July 1996 Vice President - Human Resources, since September 20 Vice President and Secretary of Halliburton Energy to August 2000 Law Department Manager of Integration & Development Energy Services, Inc., October 1998 to February 20 Region Chief Counsel (London) Europe/Africa Law Depa Energy Services, Inc., May 1994 to September 1998 Executive Vice President and General Counsel, since Executive Vice President and Chief Financial Officer Chairman, President and CEO of Nuevo Energy Company, President and CEO of Torch Energy Advisors, Inc., Ma Chief Executive Officer of Kellogg Brown & Root, Inc President of Kellogg Brown & Root, Inc., since Octol Vice President of Kellogg Brown & Root, Inc., March Chief Executive Officer and President of Brown & Roc of Kellogg Brown & Root, Inc., April 2000 to Febru Chief Executive Officer of Brown & Root Services Div Root, Inc., January 1999 to April 2000 Chief Executive Officer and President of Brown & Roc November 1996 to January 1999 Vice President of Brown & Root, Inc., July 1989 to J Vice President and Chief Technology Officer, since F Vice President of Mobil Technology Company and Genet Mobil Exploration and Producing Technical Center, Manager of Surface Engineering and Upstream Strategi Technology Company, 1996 to 1997 Vice President and Chief Information Officer, since Chief Information Officer of Group Air Liquide, 1997 Vice President - Information Technology of Air Liqui 1995 to 1997 <PAGE> 9 Executive Officers of the Registrant (continued) Name and Age Offices Held and Term of Office * David J. Lesar (Age 48) Chairman of the Board, President,and Chief Executive Director of Registrant, since August 2000 President and Chief Operating Officer, May 1997 to Executive Vice President and Chief Financial Officer Chairman of the Board of Kellogg Brown & Root, Inc., President and Chief Executive Officer of Brown & Roc December 1998 * Gary V. Morris (Age 48) Executive Vice President, since August 2001 Executive Vice President and Chief Financial Officer Senior Vice President - Finance, February 1997 to Ma Senior Vice President, May 1996 to February 1997 R. Charles Muchmore, Jr. Vice President and Controller, since August 1996 (Age 48) ffxxmm7 Qf>n nr/vw/ ArM'nx7Ao/^r1rrcr//,1ato/4^ni 0/000004^0100000001 1 A=/11 0V0001 fvf 9/01/0000 Edgar Ortiz (Age 59) Page 10 of 89 Chief Executive Officer and President of Energy Serv since April 2000 Executive Vice President of Halliburton Energy Servi Senior Vice President of Halliburton Energy Services June 2000 Vice President of Halliburton Energy Services, Inc., December 1997 President of Halliburton Energy Services Division of Services, Inc., November 1997 to March 2000 Senior Vice President - Global Operations of Hallibu Division of Halliburton Energy Services, Inc., Apr Vice President - Latin America Region of Halliburton Division of Halliburton Energy Services, Inc., Oct <FN> * Members of the Policy Committee of the registrant. There are no family relationships between the executive officers of the registrant. </FN> </TABLE> <PAGE> 10 PART II Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters. Halliburton Company's common stock is traded on the New York Stock Exchange and the Swiss Exchange. Information relating to market prices of common stock and quarterly dividend payment is included under the caption "Quarterly Data and Market Price Information" on pages 72 and 73 of this annual report. Cash dividends on common stock for 2001 and 2000 were paid in March, June, September, and December of each year. Our Board of Directors intends to consider the payment of quarterly dividends on the outstanding shares of our common stock in the future. The declaration and payment of future dividends, however, will be at the discretion of the board of directors and will depend upon, among other things: future earnings; general financial condition and liquidity; success in business activities; capital requirements; and general business conditions. At December 31, 2001, there were approximately 25,100 shareholders of Vittr**/A*mnir opn rrr'u/A-Y'1'macAp/1rr?jr/d?ita/4501 7/000004501 70700001 1 /padl 01-7001 Q/71 77007 Page 11 of 89 record. In calculating the number of shareholders, we consider clearing agencies and security position listings as one shareholder for each agency or listing. Item 6. Selected Financial Data. Information relating to selected through 71 of this annual report. financial data is included on pages 69 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Information relating to management's discussion and analysis of financial condition and results of operations is included on pages 13 through 27 of this annual report. Item 7(a). Quantitative and Qualitative Disclosures About Market Risk. Information relating to market risk is included in management's discussion and analysis of financial condition and results of operations under the caption "Financial Instrument Market Risk" on pages 23 and 24 of this annual report. <PAGE> 11 Item 8. Financial Statements and Supplementary Data. <TABLE> <CAPTION> <S> Responsibility for Financial Reporting Report of Arthur Andersen LLP, Independent Public Accountants Consolidated Statements of Income for the years ended December 31, 2001, 2000 and 1 Consolidated Balance Sheets at December 31, 2001 and 2000 Consolidated Statements of Shareholders' Equity for the years ended December 31, 20 Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 a Notes to Annual Financial Statements 1. Significant Accounting Policies 2. Acquisitions and Dispositions 3. Discontinued Operations 4. Business Segment Information 5. Inventories 6. Property, Plant and Equipment 7. Related Companies 8. Lines of Credit, Notes Payable and Long-Term Debt 9. Commitments and Contingencies 10. Income Per Share 11. Engineering and ConstructionReorganization 12. Change in Accounting Method 13. Income Taxes 14. Common Stock 15. Series A JuniorParticipating Preferred Stock 16. Financial Instruments and Risk Management 17. Retirement Plans 18. Dresser Industries, Inc.Financial Information Quarterly Data and Market Price Information (Unaudited) </TABLE> The related financial statement schedules are included under Part IV, Item 14 of this annual report. Item 9. Changes in and Financial Disclosure. None. Disagreements with Accountants on Accounting and <PAGE> 12 cpp rrmr/ A rpIllTrac/o^ rro-r/rloto//1 ^A1 9/AAAAA/l ^01 OAOAAAA1 1 /aA 1 AVOAA1 fvt O/OI /OAAO Page 12 of 89 HALLIBURTON COMPANY Management's Discussion and Analysis of Financial Condition and Results of Operations In this section, we discuss the operating results and general financial condition of Halliburton Company and its subsidiaries. We explain: factors and risks that impact our business; why our earnings and expenses for the year 2001 differ from 2000 and why our earnings and expenses for 2000 differ from 1999; capital expenditures; factors that impacted our cash flows; and other items that materially affect our financial condition or earnings. BUSINESS ENVIRONMENT Our business is organized around two business segments: Energy Services Group; and Engineering and Construction Group. We currently operate in over 100 countries throughout the world, providing a comprehensive range of discrete and integrated products and services to the energy industry, and to other industrial and governmental customers. The majority of our consolidated revenues is derived from the sale of services and products, including engineering and construction activities, to large oil and gas companies. These services and products are used throughout the energy industry, from 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, acts of terrorism, expropriation or other governmental actions, exchange controls or currency devaluation may result in increased business risk in any one country. We believe the geographic diversification of our business activities reduces the risk that loss of business in any one country material to our consolidated results of operations. Halliburton Company would be Spending on exploration and production activities and investments in capital expenditures for refining and distribution facilities by large oil and gas companies have a significant impact on the activity levels within our two business segments. Throughout the first part of 2001, increased spending by large oil and gas companies contributed to higher levels of worldwide drilling activity, especially gas drilling in the United States. General business conditions in the United States began to decline during the third quarter. The events of September 11 accelerated a global economic recession which in turn adversely impacted the energy industry, particularly in the United States. Reduced demand for aviation fuel and increasing natural gas storage levels, due to weakened demand for industrial and residential natural gas, resulted in significant decreases in North American oil and natural gas drilling. Although down, crude oil prices have remained above threshold levels that our customers use to justify their spending on capital and drilling projects. Generally, major oil and gas field development projects, particularly deepwater projects in the Gulf of Mexico, West Africa and Brazil as well as downstream energy projects, have longer lead times. The economics of these projects are based on longer-term commodity prices. Once started, projects of this type are less likely to be delayed due to fluctuating short-term prices. We expect United States gas drilling activity to continue declining into the second quarter of 2002 due to the slow global economy and unseasonably warm winter. We expect gas drilling activity to begin recovering in the latter part of the year. If prices for oil remain stable as compared to year-end prices, we expect major oilfield development projects to continue providing international opportunities. Over the longer-term, we expect increased global demand for oil and natural gas, additional customer spending to replace depleting reserves and our continued technological advances to provide growth opportunities for our htttv//www cpr oov/ArrhwpQ/pdonr/rlnta/A^fn 9/000004^0190900001 1 /pd 1OV9001 tvt s/oi/onno Page 13 of 89 products and services. <PAGE> 13 Energy Services Group Strong natural gas and crude oil drilling activity during the first nine months contributed to increased demand for the products and services provided by the Energy Services Group. Activity was especially strong in oilfield services within the United States, reflecting increased levels of drilling for natural gas. The rotary rig count in the United States continued to increase throughout the first half of the year and averaged 1,206 rigs in the first nine months of 2001. This represents an increase of 40% over the average for the first nine months of 2000. In the United States drilling activity for gas remained strong, posting a 44% increase over the average for the first nine months of 2000. Henry Hub gas prices for the first nine months of 2001 averaged $4.62/MCF as compared to $3.54/MCF average for the first nine months of 2000. Increases in international rig activity also continued through the first nine months of 2001, up 19% compared to the first nine months of 2000. All geographic regions experienced higher activity levels, which allowed us to increase our utilization of equipment and personnel. This higher utilization resulted in better profitability and opportunities to increase prices, especially within the United States. During the latter part of 2001, drilling activity within the United States, primarily land-based gas rigs, began to significantly decline. Henry Hub gas prices for the fourth quarter of 2001 averaged $2.42/MCF, almost 50% lower than the average for the first nine months of 2001. For the month of December 2001, the United States natural gas rig count averaged 754, down 100 rigs from December 2000 and down 304 rigs from the peak in July 2001. United States rotary rig count for the fourth quarter of 2001 was down 19% compared to third quarter of 2001 and down 6% compared to the fourth quarter of 2000. At the same time, the international rig count averaged 748 rigs for the fourth quarter of 2001 and was down 1% compared to the third quarter of 2001, and increased 5% compared to the fourth quarter of 2000. Natural gas prices for 2002 are expected to continue to be weak in the first half of the year due to current high gas storage levels, caused by an abnormally warm winter and a slow economy in the United States, but then improve in the second half of the year. Timing of the recovery of natural gas prices, which will lead to increased drilling activity depends, upon depletion of existing reserves and future gas storage levels. We expect oil prices to range between $17 and $22 per barrel in 2002. We believe this range will support international activity at or just below current levels. The outlook for world oil demand growth is highly uncertain due to the slowdown in the global economy and the length of the recession in the United States. In 2002 worldwide exploration and production spending is expected to decrease with most of the decrease occurring in the United States and Canada. We expect that recent declines in United States rig counts and economic uncertainty within the United States will result in short-term declines in revenues and operating income within the segment. The price increases we implemented in late 2000 and during 2001 combined with our efforts to manage costs should partially offset lower activity levels and pressures by competitors and customers to increase discounts. The production enhancement product service line, due to its dependence on United States gas drilling, is expected to be significantly impacted by the current slow down in natural gas drilling. Our drilling systems and completion products product service lines have a large percentage of their business outside the United States and are also heavily involved in deepwater oil and gas developments. These product service lines are expected to remain relatively strong. Engineering and Construction Group Our Engineering and Construction Group did not benefit from the positive factors which provided opportunities for growth in the Energy Services Group in the first part of 2001. Both groups provide products and services to many of the same customers. However, oilfield service activities, especially land-based gas drilling activity in the United States, is more short-term focused as compared to the long-term nature of most major engineering and construction projects. The Tittr'/Aimm7 cpp 70000001 1 /aAI nVOOOl tvt c/oi /onno Page 14 of 89 downturn in the energy industry that began in 1998 led our customers to severely curtail many large engineering and construction projects during 2000 and into 2001. During this time, a series of mergers and consolidations among our major customers also reduced our customers' levels of investment in refining and distribution facilities as they evaluated and maximized use of combined capacities. Due to the lack of opportunities existing throughout 2000, combined with an extremely competitive global engineering and construction environment, we restructured our Engineering and Construction Group in late 2000 and the first quarter of 2001 to facilitate operational efficiencies and reduce costs. Engineering, construction, fabrication, and project management capabilities are now part of one operating group - Halliburton KBR. <PAGE> 14 In the latter part of the third quarter and throughout the fourth quarter of 2001 we saw a slowdown of the economy. The current global economic slowdown is expected to last until the second half of 2002. Soft demand in the first half of 2002 will continue to delay energy related project awards, or reduce the scope of existing projects, especially for olefins and chemicals projects. Although slower economies and lower oil and gas prices may delay some projects, we expect an increasing need for security and government defense and infrastructure projects. Worldwide tightening of sulfur content in gasoline and diesel and other new environmental regulations are likely to require changes in refinery configurations and the addition of new process units in the long-term. We remain optimistic about our opportunities in liquefied natural gas and gas-to-liquids. Our optimism is based on anticipated new projects as well as the front-end engineering and initial work contracts for liquefied natural gas projects we received in late 2001. We expect activity levels within the Engineering and Construction Group to remain about the same in 2002 as compared with 2001. This expectation is based upon our: technologies and proven capabilities on complex projects; recent and pending project awards; and current backlog and prospects, especially for onshore and government operations and infrastructure projects. RESULTS OP OPERATIONS IN 2001 COMPARED TO 2000 REVENUES <TABLE> <CAPTI0N> Millions of dollars 2001 2000 Increase/ (Decrease) <S> Energy Services Group Engineering and Construction Group <C> $ 8,722 4,324 <C> $ 6,776 5,168 <C> $ 1,946 (844) Total revenues </TABLE> $ 13,046 $ 11,944 $ 1,102 Consolidated revenues for 2001 were $13.0 billion, an increase of 9% compared to 2000. International revenues comprised 62% of total revenues in 2001 and 66% in 2000 as activity and pricing increased in our Energy Services Group more rapidly in the United States particularly in the first half of 2001. Our Engineering and Construction Group revenues, which did not benefit from the positive factors contributing to the growth of the Energy Services Group decreased 16%. Engineering and construction projects are long-term in nature and customers continue to delay major projects with the slowdown in the economy occurring in the latter part of 2001. Energy Services Group revenues increased by $1.9 billion, or 29%, in 2001 from 2000. International revenues were 58% of the total segment revenues in 2001 Vittn*//w\*7w rrnv/Aiv'1nN7<=>o/<v1r>r/dat'i/4^01 9/000004^101 OOOOOOOI 1 /od 1 01-0O01 tvt P/OI /OOOO Page 15 of 89 compared to 62% in 2000. Revenues in 2001 from our oilfield services product service lines were $6.8 billion. Our oilfield services product service lines experienced revenue growth of 29% despite a 14% decline in oil prices and a 3% decrease in natural gas prices between December 2000 and December 2001. The revenue increase was primarily due to higher drilling activity and pricing improvements, particularly in the United States. Revenues increased across all product service lines and geographic regions. Our pressure pumping product service lines experienced growth of 34% in 2001 as compared to 2000. Logging, drilling services and drilling fluids revenues increased approximately 28%, and drill bit revenues were 19% higher in 2001 as compared to 2000. Completion products revenues increased 13%. Logging and drilling services revenues increases occurred primarily in the United States, as the product service lines benefited from higher prices and increased drilling activity. Geo-Pilot(TM) and other new products introduced in the drilling services product service line further contributed to the improved revenue in 2001. Drilling fluid revenues increased in 2001 with higher activity levels in the Gulf of Mexico. Geographically, all regions within the oilfield service product service lines prospered with North America revenues increasing 37% from 2000 to 2001. Pressure pumping revenues in North America were 48% higher in 2001 compared to 2000 primarily due to higher levels of drilling activity. Revenues from Latin America increased 27% with significant increases in Venezuela and Brazil. Europe/Africa and Middle East revenues were about 20% higher in 2001 than 2000, particularly in Russia and Egypt. Revenues for the remainder of the segment of $1.9 billion increased by $400 million, or 27%, primarily due to a large multi-year project in Brazil which began in the third quarter of 2000. Integrated exploration and <PAGE> 15 production information systems revenues were higher by 19% partially due to the acquisition of PGS Data Management as well as growth in software sales and professional services. Engineering and Construction Group revenues decreased $844 million, or 16%, from 2000 to 2001. The decline is primarily due to the completion of several large international onshore and offshore projects which have not yet been fully replaced with new project awards and delays in start-ups of new projects. International revenues were approximately 71% in 2001 as compared to 72% in 2000. On a percentage basis, revenues declined about the same inside and outside of North America. Revenues for the Asia/Pacific region were down over 40% due to the effects of completing two major projects, partially offset by a new liquefied natural gas project and the start-up of construction on a railway in Australia. In Europe/Africa, revenues were down 6%. The decline was primarily due to the completion of a major project in Norway and lower activity on the logistical support contract in the Balkans which moved to the sustainment phase in late 2000. The decline was partially offset by increases in activities at our shipyard in the United Kingdom. North American revenues declined in 2001 partially due to the completion of highway and paving construction jobs and the baseball stadium in Houston. These declines in North America were partially offset by a slight increase in operations and maintenance revenues as our customers focus on maintaining current facilities and plant operations rather than adding new facilities. OPERATING INCOME <TABLE> <CAPTI0N> Millions of dollars 2001 2000 Increase/ (Decrease) <S> Energy Services Group Engineering and Construction Group General corporate <C> $ 1,015 143 (74) <C> $ 582 (42) (78) <C> $ 433 185 4 httrv//www opr orw/Arr`Tiivf`c/f>donr/dat?iM<ini 7/000004^0170700001 1 !r*r\ 1 OL7001 tvt SJ/71 /9007 Page 16 of 89 Operating income $ 1,084 $ 462 $ 622 </TABLE> Consolidated operating income increased $622 million, or 135%, from 2000 to 2001. In 2000 our results of operations include two significant items: an $88 million pretax gain on the sale of marine vessels and a pretax charge of $36 million related to the restructuring of the engineering and construction businesses. Excluding these items, operating income increased by more than 160%. Energy Services Group operating income increased $433 million, or 74%, in 2001 over 2000. Excluding the sale of marine vessels, operating income increased more than 100% compared to 2000. Increased operating income reflects increased activity levels, higher equipment utilization and improved pricing, particularly in the United States in the first nine months of 2001. Our oilfield services product service lines operating income in 2001 exceeded $1 billion, more than double from 2000. Operating margins for our oilfield services product service lines increased from 8.6% in 2000 to 14.8% in 2001, resulting in an incremental margin of 37%. Operating income was higher in 2001 as compared to 2000 in all product service lines and geographic regions. The largest increase was in pressure pumping in North America, which rose by over 130%. Substantial increases in operating income were also made in the logging, drill bits and drilling services product service lines. Operating income in North America was higher by 78% in 2001 as compared to 2000. International regions, particularly Latin America and Europe/Africa, made significant improvements in operating income. Excluding the sale of marine vessels in 2000, operating income for the remainder of the segment decreased $41 million, primarily due to lower operating margins in our Surface/Subsea product service line and revised profit estimates on a major project. Engineering and Construction Group operating income increased $185 million from 2000 to 2001. Operating margins improved to 3.3% in 2001. This increase is primarily due to the $167 million recorded in the fourth quarter of 2000 as a result of higher than estimated costs on specific jobs and unfavorable claims negotiations on other jobs. We also recorded a restructuring charge of $36 million in the fourth quarter of 2000 related to the reorganization of the engineering and construction businesses under Halliburton KBR. Excluding these fourth quarter 2000 charges, operating income decreased $18 million, or 11%, consistent with the decline in revenues. General corporate expenses were $74 million for 2001 as compared to $78 million in 2000. <PAGE> 16 NONOPERATING ITEMS Interest expense of $147 million in 2001 was $1 million higher than in 2000. Our outstanding short-term debt was substantially higher in the first part of 2001 due to repurchases of our common stock in the fourth quarter of 2000 under our repurchase program and borrowings associated with the acquisition of PGS Data Management in March 2001. Cash proceeds of $1.27 billion received in April 2001 from the sale of the remaining businesses within the Dresser Equipment Group were used to repay our short-term borrowings; however, our average borrowings for 2001 were slightly higher than in 2000. The impact of higher average borrowings was mostly offset by lower interest rates on short-term borrowings. Interest income was $27 million in 2001, an increase of $2 million from 2000. Foreign currency losses were $10 million in 2001 as compared to $5 million in 2000. Other, net was a loss of $1 million in 2000 and less than $1 million gain in 2001. Provision for income taxes was $384 million for an effective tax rate of 40.3% in 2001 compared to 38.5% in 2000. Minority interest in net income of subsidiaries in 2001 was $19 million as 1ithv//wnim; ccm\rlArr>1ir(riso/i=`/4rrcir/d'>ti/4601 7/000004^01 90700001 1 1 0P7001 1-vf- S/71 77007 Page 17 of 89 compared to $18 million in 2000. Income (loss) from discontinued operations in 2001 was a $42 million loss, or $0.10 per diluted share, due to accrued expenses associated with asbestos claims of disposed businesses. See Note 3. The loss was partially offset by net income for the first quarter of 2001 from Dresser Equipment Group of $0.05 per diluted share. Income from discontinued operations of $98 million, or $0.22 per diluted share, represents the net income of Dresser Equipment Group for the full year of 2000. Gain on disposal of discontinued operations in 2001 was $299 million after-tax, or $0.70 per diluted share. The 2001 gain resulted from the sale of our remaining businesses within the Dresser Equipment Group in April 2001. The gain of $215 million after-tax, or $0.48 per diluted share, in 2000 resulted from the sale of our 51% interest in Dresser-Rand, formerly a part of Dresser Equipment Group, in January 2000. Cumulative effect of accounting change, net of $1 million reflects the adoption of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" in the first quarter of 2001. Net income for 2001 was $809 million, or $1.88 per diluted share, as compared to net income of $501 million, or $1.12 per diluted share in 2000. RESULTS OF OPERATIONS IN 2000 COMPARED TO 1999 REVENUES <TABLE> <CAPTION> Millions of dollars 2000 1999 Increase/ (Decrease) <S> Energy Services Group Engineering and Construction Group <C> $ 6,776 5,168 <C> $ 5,921 6,392 <C> $ 855 (1,224) Total revenues </TABLE> $ 11,944 $ 12,313 $ (369) Consolidated revenues for 2000 were $11.9 billion, a decrease of 3% from 1999 revenues of $12.3 billion. Lower levels of Engineering and Construction Group revenues were partially offset by increased oilfield services revenues within the Energy Services Group, particularly in the United States. International revenues were 66% of our consolidated revenues in 2000, compared with 70% in 1999. Energy Services Group revenues were $6.8 billion for 2000, an increase of 14% from 1999 revenues of $5.9 billion. International revenues were 62% of total segment revenues in 2000 compared with 68% in 1999. 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. After a slight seasonal decline in the first quarter of 2000, revenues increased consecutively each quarter across all product service lines throughout the year. Revenues from our oilfield services product service lines were $5.3 billion. Increased demand for natural gas and increased drilling activity benefited our oilfield services product service lines. The pressure pumping product service line revenues increased 30% compared to 1999. The logging product service line revenues increased 26% compared to <PAGE> 17 1999. Drilling fluids increased over 20%, while drill bits and completion products service lines increased about 14%. Drilling systems product service line revenues increased by 9%. 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 Trf+rv//www <5er. orw/Arphivp.<j/fv1onr/Hata/A^ni 7/000004S01909000011 /prt 1 0L7001 tvt 8/91/7007 Page 18 of 89 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 increased by 16% in the Middle East region and 12% in the Latin America region 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 the remainder of the segment of $1.5 billion decreased 7% compared to 1999. Lower revenues within the Surface/Subsea product service lines were partially offset by record revenues within the integrated exploration and production information systems product service line which increased 13% compared to 1999. Increases in 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. Engineering and Construction Group revenues were $5.2 billion for 2000, down 19% from $6.4 billion in 1999. 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. Revenues in 1999 benefited from 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 onshore and offshore engineering and construction projects, particularly major projects in Europe and Africa, which were winding down. OPERATING INCOME <TABLE> <CAPTION> Millions of dollars 2000 1999 Increase/ (Decrease) <S> Energy Services Group Engineering and Construction Group General corporate Special credits <C> $ 582 (42) (78) <C> $ 250 175 (71) 47 <C> $ 332 (217) (7) (47) Operating income </TABLE> $ 462 $ 401 $ 61 Consolidated operating income was $462 million for 2000 compared to $401 million for 1999. Engineering and Construction segment results include restructuring charges of $36 million in 2000 related to the restructuring of the engineering and construction businesses. See Note 11. Excluding the restructuring charge in 2000 and the special credits of $47 million in 1999, operating income for 2000 increased by 41% from 1999. Energy Services Group operating income in 2000 was $582 million, an increase of 133% from 1999 operating income of $250 million. Operating margins were 8.6% in 2000, up from 4.2% in 1999. Operating income from our oilfield services product service lines was $452 million. During 2000, strengthening North American drilling and oilfield activity resulted in increased equipment TtHtW/www cpr orw/ArpVnvpc/prlcrflr/dflt{i//l^ni 7/000004^0170900001 1 IpA 1 DVOnni tvt /7i nnm Page 19 of 89 utilization and improved pricing within the oilfield services product service lines. Pressure pumping operating income increased about 135% compared to 1999 levels, while logging services operating income increased by 170% 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 <PAGE> 18 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. However, fourth quarter 2000 operating income increased across all international geographic regions compared to the third quarter of 2000, reflecting increased international spending by our customers. Operating income in 2000 for the remainder of the segment was $130 million. Operating income benefited in 2000 from a third quarter $88 million pretax gain on sale of two semi-submersible vessels and one multipurpose support vessel and increasing profitability in the integrated exploration and production information systems product service line. Excluding the gain of the sale of the vessels, operating income declined in the Surface/Subsea product service lines. Lower activity levels in the North Sea United Kingdom sector and under-utilization of manufacturing and subsea equipment and vessels, which carry large fixed costs, were the primary factors for the decline in operating income. Operating income from integrated exploration and production information systems in 2000 increased almost 200% compared to 1999, reflecting higher software and professional services revenues. Engineering and Construction Group recorded an operating loss for 2000 of $42 million compared to operating income of $175 million in 1999, a decrease of 124%. The operating margin was 2.7% in 1999. 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. 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 large projects of $171 million in 2000, including $167 million in the fourth quarter. At the same time, the group recorded $36 million of restructuring charges. Lower activity due to the trend in delayed new projects, which continued through 2000, 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. Special credits in 1999 are the result of a change in estimate on some components of the 1998 special charges. 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. General corporate expenses for 2000 were $78 million, an increase of $7 million from 1999. 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. NONOPERATING ITEMS L+fn'/Aimnir o*=>/- rrnir/ A v'Li-i/iaeAarlrra-r/rlofa 74^01 0/000004^01 70000001 1 /aril OlrOnfil fv-t q n i /onm Page 20 of 89 Interest expense was $146 million for 2000 compared to $141 million in 1999. 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 of 2000. 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 in 2000 declined $49 million from 1999. 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 losses were $5 million in 2000, down from a loss of $8 million in 1999. The losses in 2000 were primarily in Asia Pacific currencies and the euro. Losses in 1999 occurred primarily in Russian and Latin American currencies. Other, net was a net loss of $1 million in 2000 compared to $19 million in 1999. The net loss in 1999 includes a $26 million charge in the second quarter relating to an impairment of Halliburton KBR's net investment in Bufete Industriale, S.A. de C.V., a large specialty engineering, procurement and construction company in Mexico. <PAGE> 19 Provision for income taxes on continuing operations in 2000 was $129 million for an effective tax rate of 38.5%, compared to 37.8% in 1999. Excluding our special charges and related taxes, the effective rate was 38.8% in 1999. Minority interest in net income of subsidiaries was $18 million in 2000 compared to $17 million in 1999. Income from discontinued operations was $98 million in 2000 and $124 million in 1999. 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 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 12. Net income was $501 million, or $1.12 per diluted share, in 2000 and $438 million, or $0.99 per diluted share, in 1999. LIQUIDITY AND CAPITAL RESOURCES We ended 2001 with cash and equivalents of $290 million compared with $231 million at the end of 2000 and $466 million at the end of 1999. Cash flows from operating activities provided $1.0 billion for 2001 compared to using $57 million in 2000 and using $58 million in 1999. Working capital items, which include receivables, inventories, accounts payable and other working capital, net, used $50 million of cash in 2001 compared to using $563 million in 2000 and providing $2 million in 1999. 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 $6 million in 2001, $54 million in 2000 and $202 million in 1999. Cash flows used in investing activities were $858 million for 2001, $411 million for 2000 and $107 million for 1999. Capital expenditures of $797 million in 2001 were about 38% higher than in 2000 and about 53% higher than in 1999. Capital spending in 2001 was mostly directed to Halliburton Energy Services, primarily for pressure pumping equipment, directional drilling tools and logging-while-drilling equipment. In March 2001 we acquired PGS Data Management division of Petroleum Geo-Services ASA for $164 million cash. In addition we spent $56 million for various acquisitions in 2001. 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. Tittrv//www cpc orw/Arr-lm/pc/pdcror/rlatciM.^ni 9/000004^01 90700001 1 /<=><-) 1 01-7001 fvt 8/71 /7n<T> Page 21 of 89 Cash flows from financing activities used $1.4 billion in 2001 and $584 million in 2000 and provided $189 million in 1999. Proceeds from exercises of stock options provided cash flows of $27 million in 2001 compared to $105 million in 2000 and $49 million in 1999. Dividends to shareholders used $215 million of cash in 2001 and $221 million in 1999 and 2000. We used the proceeds from the sale of the remaining businesses in Dresser Equipment Group in April 2001, the sale of Dresser-Rand in early 2000 and the collection of a note from the fourth quarter 1999 sale of Ingersoll-Dresser Pump received in early 2000 to reduce short-term debt. On July 12, 2001, we issued $425 million in two and five year medium-term notes under our medium-term note program. The notes consist of $275 million of 6% fixed rate notes due August 1, 2006 and $150 million of floating rate notes due July 16, 2003. Net proceeds from the two medium-term note offerings were also used to reduce short-term debt. Net repayments of short-term debt in 2001 used $1.5 billion. On April 25, 2000, our Board of Directors approved plans to implement a share repurchase program for up to 44 million shares. We repurchased 1.2 million shares at a cost of $25 million in 2001 and 20.4 million shares at a cost of $759 million in 2000. We currently have no plan to repurchase the remaining shares under the approved plan. In addition, we repurchased $9 million of common stock in 2001 and $10 million in both 2000 and 1999 from employees to settle their income tax liabilities primarily for restricted stock lapses. Cash flows from discontinued operations provided $1.3 billion in 2001 as compared to $826 million in 2000 and $234 million in 1999. Cash flows for 2001 include proceeds from the sale of Dresser Equipment Group of approximately $1.27 billion. Cash flows for 2000 include proceeds from the sale of Dresser-Rand and Ingersoll-Dresser Pump of $913 million. <PAGE> 20 Capital resources generally are derived from internally generated cash flows and access to capital markets when appropriate. Our combined short-term notes payable and long-term debt was 24% of total capitalization at the end of 2001, 40% at the end of 2000, and 35% at the end of 1999. Short-term debt was reduced significantly in the second quarter of 2001 with the proceeds from the sale of Dresser Equipment Group and in the third quarter from the issuance of $425 million of medium-term notes. In 2000 we reduced our short-term debt with proceeds from the sales of Ingersoll-Dresser Pump and Dresser-Rand joint ventures early in the year. We increased short-term debt in the third quarter of 2000 to fund share repurchases. Late in 2001 and early in 2002, Moody's Investors' Services lowered its ratings of our long-term senior unsecured debt to Baa2 and our short-term credit and commercial paper ratings to P-2. In addition, Standard & Poor's lowered its ratings of our long-term senior unsecured debt to A- and our short-term credit and commercial paper ratings to A-2. The ratings were lowered primarily due to the agencies' concerns about asbestos litigation. Although the long-term ratings continue at investment grade levels and the short-term ratings allow participation in the commercial paper market, the cost of new borrowing is higher and our access to the debt markets is more volatile at the new rating levels. Reduced ratings and concerns about asbestos litigation, along with recent changes in the banking and insurance markets, will also result in higher cost and more limited access to markets for other credit products including letters of credit and surety bonds. At this time, it is not possible to compute the increased costs of credit products we may need in the future but it is not expected to be material based upon the current forecast of our credit needs. We ended 2001 with cash and equivalents of $290 million and we are projecting strong cash flow from operations in 2002. We also have $700 million of committed lines of credit from banks that are available if we maintain an investment grade rating. Investment grade ratings are BBB- or higher for Standard & Poor's and Baa3 or higher for Moody's Investors' Services and we are currently above these levels. Nothing has been borrowed under these lines and no borrowings are anticipated during 2002. In the normal course of business we have agreements with banks under which approximately $1.4 billion of letters of credit or bank guarantees were issued, including $241 million which relate to Vittrv//www cpr CTnv/Arrhivpc/pdanr/HntnM.^017/000004.^01909000011 /erll 0V9001 tvt /91 /onoo Page 22 of 89 our joint ventures' operations. In addition, $320 million of these financial instruments include provisions that allow the banks to require cash collateralization if debt ratings of either rating agency falls below the rating of BBB by Standard & Poor's or Baa2 by Moody's Investors' Sevices and $149 million where banks may require cash collateralization if either debt rating falls below investment grade. CRITICAL ACCOUNTING POLICIES The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our judgments about future events and related estimations and how they can impact our financial statements. A critical accounting policy is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations. We identified our most critical accounting policies to be: percentage of completion accounting for our long-term engineering and construction contracts; and loss contingencies, primarily related to asbestos litigation; and other litigation. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this report. Percentage of completion We account for our revenues on long-term engineering and construction contracts on the percentage of completion method. This method of accounting requires us to calculate job profit to be recognized in each reporting period for each job based upon our predictions of future outcomes which include: estimates of the total cost to complete the contract; estimates of project schedule and completion date; estimates of the percentage the project is complete; and amounts of any probable unapproved claims and change orders included in revenues. At the onset of each contract, we prepare a detailed step-by-step analysis of our estimated cost to complete the project. Our project personnel continuously evaluate the estimated costs, claims and change orders, and percentage of <PAGE> 21 completion at the project level. Significant projects are reviewed in detail by senior engineering and construction management at least quarterly. Preparing project cost estimates and percentages of completion is a core competency within our engineering and construction businesses. We have a long history of dealing with multiple types of projects and in preparing accurate cost estimates. However, there are many factors, including but not limited to weather, inflation, labor disruptions and timely availability of materials, and other factors as outlined in our "Forward-Looking Information" section. These factors can affect the accuracy of our estimates and impact our future reported earnings. Loss contingencies Asbestos. We have approximately 274,000 open asbestos claims pending against us at December 31, 2001 for which we have accrued $737 million for estimated settlements and $612 million for estimated recoveries from insurance companies. Computing our liability for open asbestos claims requires us to make judgments as to the most likely outcome of litigation, future settlements and judgments to be paid for open .claims. We estimate settlement payments for open claims by applying our average historical settlement costs by type of claim to the corresponding open claims. We believe our average historical settlement costs are a reasonable estimate of the cost of resolving open claims. We estimate the cost of final judgments by reviewing with our legal counsel the probable outcome of pending appeals. If the actual cost of settlements and final judgments differs from our estimates, our reserves for open claims may not be sufficient. If so, any deficiency would be a loss we would be required to httiWAx/ww cpr onv/Arr>hivpc/fv1cra7dfitn/4S01 7/000004^01 70700001 1 lpi11 01-7001 tvt R/71/7007 Page 23 of 89 recognize at the time it becomes reasonably estimable. Estimating amounts we will recover from insurance companies for open claims involves making assumptions about the ability of the companies to meet their obligations under our policies. If our estimates of recoveries differ from actual recoveries, we may have uncollectible receivables that we may be required to write-off and we will have reduced amounts of insurance coverage for future claims. Dozens of insurance companies provide our insurance coverage for non-refractory and non-engineering and construction asbestos claims. We believe this reduces our risk associated with the failure of any one insurance company. On the other hand, a majority of our coverage for refractory asbestos claims is with Equitas. Although we believe Equitas is currently able to meet its obligations to us, its failure to meet its commitments in the future could have a material adverse affect on our financial condition at that time. We have also estimated the amount we will recover from the insurance written by Highlands Insurance Company that covers our engineering and construction asbestos claims. If our assumptions concerning our ability to collect amounts owed to us by Highlands are incorrect, we may have up to $80 million of billed and accrued receivables from Highlands which will not be collectible as of December 31, 2001. See Note 9 of our consolidated financial statements as of December 31, 2001 for further discussion of the status and history of our asbestos claim litigation and our insurance coverage. Uncertainty about future asbestos claims and jury awards has caused much of the recent volatility in our stock price and recent downgrades in our credit ratings. We have not accrued reserves for unknown claims that may be asserted against us in the future. We have not had sufficient information to make a reasonable estimate of future claims. However, we recently retained a leading claim evaluation firm to assist us in making an estimate of our potential liability for asbestos claims that may be asserted against us in the future. When the evaluation firm's analysis is completed it is likely that we will accrue a material liability for future claims that may be asserted against us. We expect the analysis will be completed during the second quarter of 2002 and that we will accrue the liability at the end of the quarter. At the same time we will accrue a receivable for related insurance proceeds we expect to collect when future claims are actually paid. Litigation. We are currently involved in other legal proceedings not involving asbestos. As discussed in Note 9 of our consolidated financial statements, as of December 31, 2001, we have accrued an estimate of the probable costs for the resolution of these claims. Attorneys in our legal department specializing in litigation claims, monitor and manage all claims filed against us. The estimate of probable costs related to these claims is developed in consultation with outside legal counsel representing us in the defense of these claims. Our estimates are based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. We attempt to resolve claims through mediation and arbitration where possible. If the actual settlement costs and final judgments, after appeals, differ from our estimates, our future financial results may be adversely affected. <PAGE> 22 LONG-TERM CONTRACTURAL OBLIGATIONS AND COMMERCIAL COMMITMENTS The following obligations: table summarizes our various long-term contractual <TABLE> <CAPTION> Millions of dollars <S> Long-term debt Operating leases 2002 <C> $ 81 97 Payments due 2003 2004 2005 <C> $ 291 83 <C> $2 59 <C> $2 43 2006 <C> $ 277 30 Thereaf <c> $a ppp rrrti,/0/^0000/1^01 9^000001 1 /oA 1 fv+ o/oi /onno Page 24 of 89 Total contractual cash $ 178 $ 374 $ 61 $ 45 $ 307 $ </TABLE> In addition to these long-term contractual obligations, we have other commercial commitments that could become contractual obligations. We also have $700 million of committed lines of credit from banks that are available if we maintain an investment grade rating. Investment grade ratings are BBB- or higher for Standard & Poor's and Baa3 or higher for Moody's Investors' Services and we are currently above these levels. In the normal course of business we have agreements with banks under which approximately $1.4 billion of letters of credit or bank guarantees were issued, including $241 million which relate to our joint ventures' operations. In addition, $320 million of these financial instruments include provisions that allow the banks to require cash collateralization if debt ratings of either rating agency falls below the rating of BBB by Standard & Poor's or Baa2 by Moody's Investors' Services and $149 million where banks may require cash collateralization if either debt rating falls below investment grade. These letters of credit and bank guarantees relate to our guaranteed performance or retention payments under our long-term contracts and self-insurance. In the past, no significant claims have been made against these financial instruments. We do not anticipate material losses to occur as a result of these financial instruments. FINANCIAL INSTRUMENT MARKET RISK We are exposed to financial instrument market risk from changes in foreign currency exchange rates, interest rates and to a limited extent, commodity prices. We selectively manage these exposures through the use of derivative instruments to mitigate our market risk from these exposures. The objective of our risk management program is to protect our cash flows related to sales or purchases of goods or services from market fluctuations in currency rates. Our use of derivative instruments includes the following types of market risk: volatility of the currency rates; time horizon of the derivative instruments; market cycles; and the type of derivative instruments used. We do not use derivative instruments for trading purposes. We do not consider any of these risk management activities to be material. See Note 1 for additional information on our accounting policies on derivative instruments. See Note 16 for additional disclosures related to derivative instruments. Interest rate risk. We have exposure to interest rate risk from our long-term debt and related interest rate swaps. The following table represents principal amounts of our long-term debt at December 31, 2001 and related weighted average interest rates by year of maturity for our long-term debt. <PAGE> 23 <TABLE> <CAPTI0N> Millions of dollars <S> Long-term debt: Fixed rate debt Weighted average interest rate Variable rate debt 2002 <C> $ 75 6.3% $6 2003 <C> $ 139 8.0% $ 152 2004 <C> _ $2 2005 <C> _ $2 2006 The <C> <C $ 275 $ 6.0% $2 $ htfn'/Aimnv cw* (T/vw/ArrhJ-u#ae/Arfnrcir7data/14^ni 7/000004^101 70700001 1 lt*A"\ OVO/lfll fvt 9/01 /O/l/lO Page 25 of 89 Weighted average interest rate 3.5% 2.6% 4.2% 4.2% 4.2% </TABLE> Fair market value of long-term debt was $1.3 billion as of December 31, 2001. We have two interest rate swaps which convert fixed rate debt to variable rate debt. One of our interest rate swaps hedges $150 million of the 6% fixed rate medium-term notes and has a fair value of $3.4 million at December 31, 2001. Under this interest rate swap agreement, the counter party pays a fixed rate of 6% interest and we pay a variable interest rate based on published 6-month LIBOR interest rates. The payments under the agreement are settled on February 1 and August 1 of each year until August 2006, and coincide with the interest payment dates on the hedged debt instrument. The other interest rate swap hedges $139 million of our 8% long-term debt and has a fair value of a loss of $0.2 million at December 31, 2001. Under this interest rate swap agreement, the counter party pays a fixed rate of 8% interest and we pay a variable interest rate based on published 6-month LIBOR interest rates. The payments under the agreement are settled on April 15 and October 15 of each year until April 2003, and coincide with the interest payment dates on the hedged debt instrument. RESTRUCTURING ACTIVITIES In the fourth quarter of 2000 we approved a plan to reorganize our engineering and construction businesses into one business unit. This restructuring was undertaken because our engineering and construction businesses continued to experience delays in customer commitments for new upstream and downstream projects. With the exception of deepwater projects, short-term prospects for increased engineering and construction activities in either the upstream or downstream businesses were not positive. As a result of the reorganization of the engineering and construction businesses, we took actions to rationalize our operating structure including write-offs of equipment, engineering reference designs and capitalized software of $20 million and recorded severance costs of $16 million. See Note 11. . During the second quarter of 1999, we reversed $47 million of our 1998 special charges related to the acquisition of Dresser Industries, Inc., and industry downturn. This was based on our reassessment of total costs to be incurred to complete the actions covered in the charges. 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 Form 10-K are forward-looking and use words like "may," "may not," "believes," "do not believe," "expects," "do not expect," "do not anticipate," and similar expressions. We may also provide oral or written forward-looking information in other materials we release to the public. Forward-looking information involves risks and uncertainties and reflects our best judgment based on current information. Our results of operations can be affected by <PAGE> 24 htfr*//wmnT7 eor\-u/AtY'hi''i7Ao/(=drrav/rl9t9/A4ni 9/000004^101 90900001 1 /orll flVOnm +-v+ cm nnm Page 26 of 89 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: Legal asbestos litigation including the recent judgments against us and related appeals; asbestos related insurance litigation including our litigation with Highlands Insurance Company; other litigation, including, for example, contract disputes, patent infringements and environmental matters; trade restrictions and economic embargoes imposed by the United States and other countries; changes in governmental regulations in the numerous countries in which we operate including, for example, regulations that: encourage or mandate the hiring of local contractors; and require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction; and environmental laws, including, for example, those that require emission performance standards for facilities; Geopolitical unsettled political conditions, war, the effects of terrorism, 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, Argentina, Libya, Nigeria, and Russia; and changes in foreign exchange rates and exchange controls as were experienced in Argentina in late 2001 and early 2002; Liquidity reductions in debt ratings by rating agencies such as our recent reductions by Standard & Poor's and Moody's Investors' Services; access to lines of credit and credit markets; ability to issue letters of credit; and ability to raise capital via the sale of stock; Weather related the effects of severe weather conditions, including, for example, hurricanes and typhoons, on offshore 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 the magnitude of governmental spending and outsourcing for military and logistical support of the type that we provide, including, for example, support services in Bosnia; 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 such as the proposed merger of Conoco and Phillips Petroleum; 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 that impact the demand for oil and gas such as the slowdown in the global economy following the terrorist attacks on the United States on September 11, 2001; changes in the price of oil and natural gas, resulting from: Httn'/Aiirurw crcwr/Arr'\\\'\Tt*c/e>AcTwlA'xi'>/A^C\'\ 0/00000/1^01 1 OVOnOI +-v+ 8/iihnm Page 27 of 89 OPEC's ability to set and maintain production levels and prices for oil; <PAGE> 25 the level of oil production by non-OPEC countries; the policies of governments regarding exploration for and production and development of their oil and natural gas reserves; and the level of demand for oil and natural gas, especially natural gas in the United States where demand is currently below prior year usage; 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, such as the Barracuda-Caratinga project in Brazil, 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 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: adverse movements in foreign exchange rates, interest rates, or commodity prices; or the value and time period of the derivative being different than the exposures or cash flows being hedged; Personnel and raergers/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, such as our 2001 acquisition of Magic Earth, Inc. and PGS Data Management, 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 such as the reorganization of our engineering and construction business in early 2001; ensuring acquisitions and new products and services add value and complement our core businesses; and successful completion of planned dispositions. In addition, future trends for pricing, margins, revenues and profitability remain difficult to predict in the industries we serve. We do not assume any responsibility to publicly update any of our forward-looking statements regardless of whether factors change as a result of new information, future events or for any other reason. You should review any additional disclosures we make in our press releases and Forms 10-Q, 8-K and 10-K to the United States Securities and Exchange Commission. We also suggest that you listen to our quarterly earnings release conference calls with financial analysts. OTHER ISSUES 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 htttW/www cpr onv/Arrhivps/pHcrar/dsitn/jl^OI 7/000004S01709000011 /pH 10V7001 tvt 8/71/7007 Page 28 of 89 Union's common currency (euro). This was the first step towards transition from existing national currencies to the use of the euro as a common currency. Euro notes and coins were introduced on January 1, 2002 and the transition period for the introduction of the euro ends February 28, 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 addressed these issues prior to December 31, 2001. In addition, our operations in the eurozone countries began transacting most of their businesses in euros prior to December 31, 2001. Thus far in 2002, we have not experienced any major issues related to converting to the euro and do not anticipate any material impacts in the future. <PAGE> 26 New pronouncements In August 2001, the Financial Accounting Standards Board issued SFAS No. 143 "Accounting for Asset Retirement Obligations" which addresses the financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated assets' retirement costs. The new standard will be effective for us beginning January 1, 2003, and we are currently reviewing and evaluating the effects this standard will have on our future financial condition, results of operations, and accounting policies and practices. In October 2001, the Financial Accounting Standards Board issued SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets." This statement supercedes: SFAS No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"; and the accounting and reporting provisions of APB 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, Extraordinary, Unusual and Infrequently Occurring Events and Transactions". The new standard will be effective for us beginning January 1, 2002, and we do not believe the effects of this standard will have a material effect on our future financial condition or operations. <PAGE> 27 RESPONSIBILITY FOR FINANCIAL REPORTING 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 of America and, accordingly, include amounts based on judgments 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 LLP 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 judgment of the Board of Directors, are independent under the New York Exchange listing standards. The Board of Directors, 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: httr>`//www qpp crrwrlATY'Vnw'cAvlo-'vr/Htita/J^OI 9/000004^01 90900001 1 !pc\'\ 0L9001 tvt S/91/9009 Page 29 of 89 a documented organizational structure and division of responsibi1ity; 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. Internal auditors monitor the operation of the internal control system and report findings and recommendations to 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 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, 2001, our system of internal control over financial reporting met those criteria. HALLIBURTON COMPANY by /s/ DAVID J. LESAR Is/ DOUGLAS L. FOSHEE David J. Lesar Chairman of the Board, President and Chief Executive Officer Douglas L.Foshee Executive Vice President and Chief Financial Officer <PAGE> 28 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS 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, 2001 and 2000, and the related consolidated statements of income, cash flows, and shareholders1 equity for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. htttWAxnvw cPf onWArr'Iiivpc/prlCTnr/dntnAl^ni9/000004^0190900(1011 /pdlDHOOI tvt R/ii nnco Page 30 of 89 In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Halliburton Company and subsidiary companies as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Dallas, Texas, January 23, 2002 (Except with respect to certain matters discussed in 9, as to which the date is February 21, 2002.) Note <PAGE> <TABLE> <CAPTI0N> 29 Halliburton Company Consolidated Statements of Income (Millions of dollars and shares except per share data) <s> Revenues: Services Product 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 credits Total operating costs and expenses Operating income Interest expense Interest income Foreign currency losses, Other, net net Income from continuing operations before taxes, minority interest, and change in accounting method, net Provision for income taxes Minority interest in net income of subsidiaries Income from continuing operations before change in accounting method, net 1 2001 <c> $ 10,940 1,999 107 $ 13,046 $ 9,831 1,744 387 $ 11,962 1,084 (147) 27 (10) 954 (384) (19) 551 Viffr*`/Axrunnf opr otav/ArrTvJx7fpc/pdnrar/dota/^1^01 9/(3(30004^(31 90900001 1 /pd1 0V9001 +vt 9/91/9009 Page 31 of 89 Discontinued operations: Income (loss) from discontinued operations, net of tax (provision) benefit of $20, ($60), and ($98) Gain on disposal of discontinued operations, net of tax of ($199), ($141), and ($94) (provision) Income from discontinued operations, net Cumulative effect of change in accounting method, net of tax benefit of $11 in 1999 Net income Basic income (loss) per share: Income from continuing operations before change in accounting method, net Income (loss) from discontinued operations Gain on disposal of discontinued operations Change in accounting method, net Net income Diluted income (loss) per share: Income from continuing operations before change in accounting method, net Income (loss) from discontinued operations Gain on disposal of discontinued operations Change in accounting method, net Net income Basic average common shares outstanding Diluted average common shares outstanding <FN> See notes to annual financial statements. </FN> </TABLE> <PAGE> 30 <TABLE> <CAPTI0N> Halliburton CompanyConsolidated Balance Sheets (Millions of dollars and shares except per share data) (42) 299 257 1 $ 809 $ 1.29 (0.10) 0.70 $ 1.89 $ 1.28 (0.10) 0.70 $ 1.88 428 430 Assets <S> Current assets: Cash and equivalents Receivables: Notes and accounts receivable (less allowance for bad debts of $131 and $125) Unbilled work on uncompleted contracts Total receivables Inventories lif+n'/Aimm; ppr crrwif A rrliA/pp /pH nror/Apto //14010 /OOOOO/1401 OOOOOOOI 1 !c*A 1 Ot-OOOl +v+ 0/01 /oooo 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 Goodwill (net of accumulated amortization of $269 Noncurrent deferred income taxes Net noncurrent assets of discontinued operations Insurance for asbestos litigation claims Other assets and $231) Total assets Liabilities and Shareholders' 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 Other current liabilities Equity Total current liabilities Long-term debt Employee compensation and benefits Asbestos litigation claims Other liabilities Minority interest in consolidated subsidiaries Total liabilities Shareholders' equity: Common shares, par value $2.50 per share - authorized 600 shares, issued 455 and 453 shares Paid-in capital in excess of par value Deferred compensation Accumulated other comprehensive income Retained earnings Less 21 and 26 shares of treasury stock, at cost Total shareholders' equity Total liabilities and shareholders' equity <FN> See notes to annual financial statements. </FN> </TABLE> <PAGE> 31 <TABLE> <CAPTION> Halliburton Company Consolidated Statements of Shareholders' Equity (Millions of dollars and shares) Page 32 of 89 Httr>'/Asrwm7 opr rrrw/Arr*1'i'i7*=c/7*7lrr9T*//'1ata/4401 0/000004401 OOOOOOOI 1 le^A'X 01/-0001 +vf C/OI /OOOO <S> Common stock (number of shares) Balance at beginning of year Shares issued under compensation net of forfeitures Shares issued for acquisition and incentive stock plans, Balance at end of year Common stock (dollars) Balance at beginning of year Shares issued under compensation net of forfeitures Shares issued for acquisition and incentive stock plans, Balance at end of year Paid-in capital in excess of par value Balance at beginning of year Shares issued under compensation and incentive net of forfeitures Tax benefit Shares issued for acquisition, net stock plans, 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 loss on investments and derivatives Balance at end of year Cumulative translation adjustment Balance at beginning of year Sales of subsidiaries Current year changes Balance at end of year (continued on next page) Page 33 of 89 Years en 2001 <C> 453 1 1 455 $ 1,132 2 4 $ 1,138 $ 259 30 (2) 11 $ 298 $ (63) (24) $ (87) $ (205) (27) (4) $ (236) $ (275) 102 (32) $ (205) <FN> See notes to annual financial statements. </FN> </TABLE> <PAGE> 32 <TABLE> <CAPTION> Tittrv/Avww cpr orw/ArphivpG/pdcrnr/datsiAlSOI 9/000004^01909000011 /pHI 01-9001 tvt R/91 /9009 Page 34 of 89 Halliburton CompanyConsolidated Statements of Shareholders' (Millions of dollars and shares) (continued) Equity Years e <s> Pension liability adjustment Balance at beginning of year Sale of subsidiary Current year change, net of tax 2001 <c> $ (12) 12 (27) Balance at end of year $ (27) Unrealized loss on investments Balance at beginning of year Current year unrealized loss on investments and derivatives $ (1) (3) Balance at end of year $ (4) Retained earnings Balance at beginning of year Net income Cash dividends paid $ 3,733 809 (215) Balance at end of year $ 4,327 Treasury stock (number of shares) Beginning of year Shares issued under benefit, dividend reinvestment plan and incentive stock plans, net Shares issued for acquisition Shares purchased 26 (2) (4) 1 Balance at end of year 21 Treasury stock (dollars) Beginning of year Shares issued under benefit, dividend reinvestment plan and incentive stock plans, net Shares issued for acquisition Shares purchased $ 845 (51) (140) 34 Balance at end of year $ 688 Comprehensive income Net income $ 809 Cumulative translation adjustment, net of tax Less reclassification adjustments for (gains) losses included in net income (32) 102 Net cumulative translation adjustment 70 Current year adjustment to minimum pension liability Unrealized loss on investments and derivatives (15) (3) Total comprehensive income $ 861 <FN> httr\*/A*rorw cpp rrrvw/ Arr4vAr*o/i=tr1rTar/r1atc/4S01 7/0000(14601 70700001 1 /o41 0V7001 S/71 /7007 Page 35 of 89 See notes to annual financial statements. </FN> </TABLE> <PAGE> 33 <TABLE> <CAPTION> Halliburton Company Consolidated Statements of Cash Flows (Millions of dollars) Year 2001 <S> Cash flows from operating activities: Net income Adjustments to reconcile net income to net cash from operations: Income from discontinued operations Depreciation, depletion and amortization (Benefit) provision for deferred income taxes Distributions from (advances to) related companies, net of equity in (earnings) losses Change in accounting method, net Accrued special charges Other non-cash items Other changes, net of non-cash items: Receivables and unbilled work on uncompleted contracts Inventories Accounts payable Other working capital, net Other operating activities <C> $ 809 (257) 531 26 8 (1) (6) (3) (199) (91) 118 122 (28) Total cash flows from operating activities 1,029 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 (797) 120 (220) 61 (22) Total cash flows from investing activities (858) Cash flows from financing activities: Proceeds from long-term borrowings Payments on long-term borrowings (Repayments) borrowings of short-term debt, Payments of dividends to shareholders Proceeds from exercises of stock options Payments to reacquire common stock Other financing activities net 425 (13) (1,528) (215) 27 (34) (17) Total cash flows from financing activities (1,355) Effect of exchange rate changes on cash Net cash flows from discontinued operations (1) (20) 1,263 Increase (decrease) in cash and equivalents Cash and equivalents at beginning of year 59 231 Cash and equivalents at end of year $ 290 httrv/Axmm, rrrtxr/Arr*bii-irf*Q/&r\cro-r/r\ci+&/A^r\'l 7/000/104^101 70700001 1 1 0V7001 tvt S/71 /7007 Page 36 of 89 Supplemental disclosure of cash flow information: Cash payments during the year for: Interest $ Income taxes $ Non-cash investing and financing activities: Liabilities assumed in acquisitions of businesses $ Liabilities disposed of in dispositions of businesses $ <FN> (1) Net cash flows from discontinued operations in 2001 include proceeds of $1.27 billion from the sale of the remaining businesses in Dresser Equipment Group and in 2000 proceeds of $913 million from the sales of Dresser-Rand in 2000 and Ingersoll-Dresser Pump in 1999. See Note 3. See notes to annual financial statements. </FN> </TABLE> 132 382 92 500 <PAGE> 34 HALLIBURTON COMPANY Notes to Annual Financial Statements Note 1. Significant Accounting Policies We employ accounting policies that are in accordance with accounting principles generally accepted in the United States of America. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect: the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements; and the reported amounts of revenues and expenses during the reporting period. Ultimate results could differ from those estimates. Principles of consolidation. The consolidated financial statements include the accounts of our company and all of our subsidiaries in which we own greater than 50% interest or control. All material intercompany accounts and transactions are eliminated. Investments in companies in which we own 50% interest or less and have a significant influence are accounted for using the equity method and if we do not have significant influence we use the cost method. Prior year amounts have been reclassified to conform to the current year presentation. 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 measurements of progress towards completion appropriate for the work performed. Progress is generally based upon physical progress, man-hours or costs incurred based upon the appropriate method for the type of job. 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. Training and consulting service revenues are recognized as the services are performed. Sales of perpetual software licenses, net of deferred maintenance fees, are recorded as revenue upon shipment. Sales of use licenses are recognized as revenue over the license period. Post-contract customer support agreements are recorded as deferred revenues and recognized as revenue ratably over the contract period of generally one year's duration. 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 htftv//www <!Pf* anv/Arphivec/pdaar/datfl//l^ni 9/000004*501 909000011 /pd 1 0V9001 tvt 8/?i /?nn? Page 37 of 89 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 $19 million in 2001, $7 million in 2000 and $12 million in 1999. Amortization expense of software development costs was $16 million for 2001, $12 million for 2000 and $15 million for 1999. Once the software is ready for release, amortization of the software development costs begins. Capitalized software development costs are amortized over periods which do not exceed five years. Income per share. Basic income per share is based on the weighted average number of common shares outstanding during the year. Diluted income per share includes additional common shares that would have been outstanding if potential common shares with a dilutive effect had been issued. See Note 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 several months. The claims and change orders, included in unbilled receivables, amounted to $234 million at December 31, 2001 and $113 million at December 31, 2000. Included in notes and accounts receivable are notes with varying interest rates totaling $19 million at December 31, 2001 and $38 million at December 31, 2000. <PAGE> 35 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. See Note 5. 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. See Note 6. Maintenance and repairs. Expenditures for maintenance and repairs are expensed; expenditures for renewals and improvements are generally capitalized. We use the accrue-in-advance method of accounting for major maintenance and repair costs of marine vessel dry docking expense and major aircraft overhauls and repairs. Under this method we anticipate the need for major maintenance and repairs and charge the estimated expense to operations before the actual work is performed. At the time the work is performed, the actual cost incurred is charged against the amounts that were previously accrued with any deficiency or excess charged or credited to operating expense. Goodwill. For acquisitions occurring prior to July 1, 2001, goodwill is amortized on a straight-line basis over periods not exceeding 40 years. Effective July 1, 2001, we adopted SFAS No. 141, "Business Combinations" which precludes amortization of goodwill on acquisitions completed subsequent to June W+frv/Ajnxmr fTAi?/9/00000/1^101 OOOHflOOl 1 /orll 010001 +-v+ o/oi /onno Page 38 of 89 30, 2001. See Note 12 for discussion of this accounting change. Goodwill 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, goodwill, and, if appropriate, the associated assets are reduced to reflect the estimated discounted cash flows to be generated by the underlying business. This practice is consistent with methodologies in SFAS No. 121 "Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to be Disposed of." Income taxes. Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the financial statements or tax returns. A valuation allowance is provided for deferred tax assets if it is more likely than not that these items will either expire before we are able to realize their benefit, or that future deductibility is uncertain. Derivative instruments. We enter into derivative financial transactions to hedge existing or projected exposures to changing foreign currency exchange rates, interest rates and commodity prices. We do not enter into derivative transactions for speculative or trading purposes. Effective January 1, 2001, we adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities." See Note 12. SFAS No. 133 requires that we recognize all derivatives on the balance sheet at fair value. Derivatives that are not hedges must be adjusted to fair value and reflected immediately through the results of operations. If the derivative is designated as a hedge under SFAS No. 133, depending on the nature of the hedge, changes in the fair value of derivatives are either offset against: the change in fair value of the hedged assets, liabilities, or firm commitments through earnings; or recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value is immediately recognized in earnings. Recognized gains or losses on derivatives entered into to manage foreign exchange risk are included in foreign currency gains and losses on the consolidated statements of income. Gains or losses on interest rate derivatives are included in interest expense and gains or losses on commodity derivatives are included in operating income. During the three years ended December 31, 2001, we did not enter into any significant transactions to hedge commodity prices. See Note 8 for discussion of interest rate swaps and Note 16 for further discussion of foreign currency exchange derivatives. <PAGE> 36 Foreign currency translation. Foreign entities whose functional currency is the United States dollar translate monetary assets and liabilities at year-end exchange rates and non-monetary items are translated at historical rates. Income and expense accounts are translated at the average rates in effect during the year, except for depreciation, cost of product sales and revenues, and expenses associated with non-monetary balance sheet accounts which are translated at historical rates. Gains or losses from changes in exchange rates are recognized in consolidated income in the year of occurrence. Foreign entities whose functional currency is the local currency translate net assets at year-end rates and income and expense accounts at average exchange rates. Adjustments resulting from these translations are reflected in the consolidated statements of shareholders' equity titled "Cumulative Translation Adjustment." Loss contingencies. We accrue for loss contingencies based upon our best estimates in accordance with SFAS No. 5, "Accounting for Contingencies." See Note 9 for discussion of our significant loss contingencies. Note 2. Acquisitions and Dispositions Magic Earth acquisition. In November 2001, we acquired Magic Earth, Inc., a leading 3-D visualization and interpretation technology company with broad applications in the area of data mining. Under the agreement, Halliburton issued 4.2 million shares of common stock from treasury stock valued at $100 million. Tittrv//www Qpr onir/ Arrhiirpc/prloar/Aata/ASOI 9/00000460190900001 11pA1 01-9001 tvt R/91 /9009 Page 39 of 89 Magic Earth became a wholly owned subsidiary and is reported within our Energy Services Group. We preliminarily recorded intangible assets of $19 million and goodwill of $71 million, all of which is nondeductible for tax purposes, subject to the final valuation of intangible assets and other costs. The intangible assets will be amortized based on a five year life. PGS Data Management acquisition. In March 2001 we acquired the PGS Data Management division of Petroleum Geo-Services ASA (PGS) for $164 million. The agreement also calls for Landmark to provide, for a fee, strategic data management and distribution services to PGS for three years. We preliminarily recorded intangible assets of $16 million and goodwill of $148 million, $9 million of which is nondeductible for tax purposes, subject to the final valuation of intangible assets and other costs. The goodwill amortization for 2001 was based on a 15 year life and the intangible assets are being amortized based on a three year life. PES acquisition. In February 2000, we acquired the remaining 74% of the shares of PES (International) Limited that we did not already own. 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 up to 2.1 million additional shares of Halliburton common stock between February 2001 and February 2002. We issued 1 million shares in February 2001; 400,000 in June 2001; and the remaining 700,000 shares in February 2002 under these rights. We recorded $115 million of goodwill in connection with acquiring the remaining 74%. During the second quarter of 2001, we contributed the majority of PES' assets and technologies, including $130 million of goodwill associated with the purchase of PES, to a newly formed joint venture, WellDynamics. We received $39 million in cash as an equity equalization adjustment. The remaining assets and goodwill of PES relating to completions and well intervention products have been combined with our existing completions product service line. We own 50% of WellDynamics and account for this investment using the equity method. Other acquisitions. We acquired other businesses in 2001 for $56 million, as compared to businesses acquired in 2000 for $10 million and $13 million in 1999. 2001 acquisitions. None of our 2001 acquisitions had a significant effect on revenues or earnings. Subsea joint venture. In October 2001, we signed a letter of intent to form a new company by combining our Halliburton Subsea operations with DSND Subsea ASA, a Norwegian-based company. The closing of the transaction is subject to the execution of a definitive agreement, regulatory approvals and approvals by the Board of Directors of each party. We will own 50% of the new company which will be accounted for on the equity method. The new company plans to begin operations by the end of the first quarter of 2002. European Marine Contractors Ltd. disposition. In October 2001, we signed an agreement to sell our 50% interest in European Marine Contractors Ltd., an unconsolidated joint venture in the Energy Services Group, to our joint venture partner, Saipem. The sale was finalized in January 2002 and we received $115 million in cash plus a contingent payment based on a formula linked to the Oil Service Index performance that was exercised in February 2002 for $19 million in cash. We expect to record a pretax gain of $108 million or $0.15 per diluted share after-tax in the first quarter of 2002. <PAGE> 37 Dresser Equipment Group divestiture. Between October 1999 and April 2001, we disposed of all the businesses in the Dresser Equipment Group. See Note 3. LWD divestiture. In March 1999, in connection with the Dresser Industries, Inc. 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. 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 IrttTv/AxraTw opr> ttn\r/ ArAhixiwj/i^dorar/datciAl^rH 9/000004^01 70700001 1 /<d1 OV-OAOI t-vf Q/9i /mm Page 40 of 89 line, which was acquired as part of the merger with Dresser Industries, Inc. 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 Industries, Inc. Note 3. Discontinued Operations In 1999, the Dresser Equipment Group was comprised of six operating divisions and two joint ventures that manufactured and marketed equipment used primarily in the energy, petrochemical, power and transportation industries. 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. The sales were triggered by Ingersoil-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. 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 $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. These joint ventures represented nearly half of the group's revenues and operating profit in 1999. The sale of our interests in the segment's joint ventures prompted a strategic review of the remaining businesses within the Dresser Equipment Group. As a result of this review, we determined that the remaining businesses did not closely fit with our core businesses, long-term goals and strategic objectives. In April 2000, our Board of Directors approved plans to sell all the remaining businesses within the Dresser Equipment Group. We sold these businesses on April 10, 2001. As part of the terms of the transaction, we retained a 5.1% equity interest in the Dresser Equipment .Group, which has been renamed Dresser, Inc. In the second quarter of 2001, we recognized a pretax gain on the sale of discontinued operations of $498 million, or $299 million after-tax. Total value under the agreement was $1.55 billion, less assumed liabilities, and resulted in cash proceeds of $1.27 billion from the sale. In connection with the sale, we accrued disposition related costs, realized $68 million of noncurrent deferred income tax assets, and reduced employee compensation and benefit liabilities by $152 million for liabilities assumed by the purchaser. The employee compensation and benefit liabilities were previously included in "Employee compensation and benefits" in the consolidated balance sheets. The financial results of the Dresser Equipment Group through March 31, 2001 are presented as discontinued operations in our financial statements. During 2001, we recorded as expense to discontinued operations $99 million, net of anticipated insurance recoveries for asbestos claims. This expense primarily consisted of $91 million relating to Harbison-Walker asbestos claims arising after our divestiture of Harbison-Walker in 1992. See Note 9. <PAGE> <TABLE> <CAPTION> Income (loss) from Operations of Discontinued Businesses 38 Years ended December 31 Millions of dollars 2001 2000 1999 <S> Revenues <C> $ 359 <C> $ 1,400 <C> $ 2,585 Vttr //vKnmi/ Qpr* crntr/ Arr*Wit^o/(adfTar/dQtQ/i6ni 7/000004601 70700001 1 01^7001 tvf 8/71 /7HH7 Page 41 of 89 Operating income Other income and expense Asbestos litigation claims, net of insurance recoveries Tax benefit (expense) Minority interest $ 37 - (99) 20 - $ 158 - - (60) - $ 249 (1) - (98) (26) Net income (loss) $ (42) $ 98 $ 124 </TABLE> Gain on disposal of discontinued operations reflects the gain on the sale of the remaining businesses within the Dresser Equipment Group in the second quarter of 2001, the gain on the sale of Dresser-Rand in February 2000 and the gain on the sale of Ingersoll-Dresser Pump in December 1999. <TABLE> <CAPTION> Gain on Disposal of Discontinued Operations Millions of dollars 2001 2000 <S> Proceeds from sale, less intercompany settlement Net assets disposed <C> $ 1 ,267 (769) <C> $ 536 (180) < $ Gain before taxes Income taxes 498 (199) 356 (141) Gain on disposal of discontinued operations $ 299 $ 215 $ </TABLE> Net assets of discontinued operations at December 31, December 31, 2000 are composed of the following items: <TABLE> <CAPTION> Millions of dollars 2000 2001 are zero and at <S> Receivables Inventories Other current assets Accounts payable Other current liabilities <C> $ 286 255 22 (104) (161) Net current assets of discontinued operations $ 298 Net property, plant and equipment Net goodwill Other assets Employee compensation and benefits Other liabilities $ 219 257 30 (113) (2) Net noncurrent assets of discontinued operations $ 391 </TABLE> Note 4. Business Segment Information We have two business segments - Energy Services Group and Engineering and Construction Group. Dresser Equipment Group is presented as part of discontinued operations through March 31, 2001 as a result of the sale in April 2001 of the remaining businesses within Dresser Equipment Group. See Note 3. Our segments are organized around the products and services provided to our customers. During the fourth quarter of 2000, we announced restructuring plans to combine all engineering, construction, fabrication and project management operations into one company, Halliburton KBR, reporting as our Engineering and Construction liffn'/Ainim; cpp crrwrl A r/'Anwo/pHnorMotoMAOl 0 fC\C\C\(\C\A AOI 70000001 1 /p^ 1 OVOOOI fvt o/oi nnno Page 42 of 89 Group. This restructuring resulted in some activities moving from the Energy Services Group to the Engineering and Construction Group, effective January 1, 2001. Prior periods have been restated for this change. Energy Services Group. The Energy Services Group provides a wide range of discrete services and products and integrated solutions to customers for the exploration, development, and production of oil and gas. The customers for this segment are major, national and independent oil and gas companies. This segment consists of: Halliburton Energy Services provides oilfield services and products including discrete products and services and integrated solutions for oil and gas exploration, development and production throughout the world. Products and services include 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; Landmark Graphics provides integrated exploration and production software information systems, data management services and professional services to the petroleum industry; and Other product service lines provide construction, installation and servicing of subsea facilities; flexible pipe for offshore applications; pipeline services for offshore customers; pipecoating services; feasibility, conceptual and front-end engineering and design, detailed engineering, procurement, construction site management, commissioning, start-up and debottlenecking of both onshore and offshore facilities; and large integrated engineering, procurement, and construction projects containing both surface and sub-surface components. Engineering and Construction Group. The Engineering and Construction Group provides engineering, procurement, construction, project management, and facilities operation and maintenance for oil and gas and other industrial and governmental customers. The Engineering and Construction Group, operating as Halliburton KBR, includes the following five product lines: Onshore operations comprises engineering and construction activities, including liquefied natural gas, ammonia, crude oil refineries, and natural gas plants; Offshore operations includes specialty offshore deepwater engineering and marine technology and worldwide fabrication capabilities; Government operations provides operations, maintenance and logistics activities for government facilities and installations; Operations and maintenance provides services for private sector customers, primarily industrial, hydrocarbon and commercial applications; and Asia Pacific operations, based in Australia, provides civil engineering and consulting services. General corporate. General corporate represents assets not included in a business segment and is primarily composed of receivables, deferred tax assets and other shared assets, including the investment in an enterprise-wide information system. Intersegment revenues included in the revenues of the business segments and revenues between geographic areas are immaterial. Our equity in pretax earnings and losses of unconsolidated affiliates that are accounted for on the equity method is included in revenues and operating income of the applicable segment. The tables below present information on our continuing operations business segments. <PAGE> 40 littn"/hunxnxT cpr (mv/ A tv*Vii"*;,=>c/rror/rlofq /zl 01 9/000004^01 90000001 1 A=r11 OVOO01 tvt 8/01 /OOOO <TABLE> <CAPTION> Operations by Business Segment Millions of dollars <S> Revenues: Energy Services Group Engineering and Construction Group Total Operating income: Energy Services Group Engineering and Construction Group Special credits General corporate Total Capital expenditures: Energy Services Group Engineering and Construction Group General corporate and shared assets Total Depreciation, depletion and amortization Energy Services Group Engineering and Construction Group General corporate and shared assets Total Total assets: Energy Services Group Engineering and Construction Group Net assets of discontinued operations General corporate and shared assets Total Research and development: Energy Services Group Engineering and Construction Group Total Special credits: Energy Services Group Engineering and Construction Group General corporate Total </TABLE> <PAGE> 41 Page 43 of 89 Years ended December 31 2001 2000 IS <C> <C> <C> $ 8,722 4,324 $ 6,776 5,168 $ $ 13,046 $ 11,944 $3 $ 1,015 143 (74) $ 1,084 $ 582 (42) (78) $ 462 $ $ $ 705 47 45 $ 797 $ 494 33 51 $ 578 $ $ $ 430 44 57 $ 531 $ 403 53 47 $ 503 $ $ $ 7,075 2,674 1,217 $ 10,966 $ 226 7 $ 233 $ $ 6, 086 2,408 690 1, 008 $ 10,192 $ 224 7 $ 231 $- $ $ $ $ $ $ - $ -$ httjv/Axtww cpn crrw/Arr`liivpc/pdoaT7/1atn/45fl1 9/0000(1450190900001 1 /pd 1 0V9001 tvt R/91/9009 Page 44 of 89 <TABLE> <CAPTION> Operations by Geographic Area Years ended December 31 Millions of dollars <s> Revenues: United States United Kingdom Other areas (numerous countries) 2001 <C> $ 4,911 1, 800 6,335 2000 <C> $ 4,073 1,512 6,359 1 <C> $ Total $ 13,046 $ 11,944 $ Long-lived assets: United States United Kingdom Other areas (numerous countries) $ 3,030 617 744 $ 2,068 525 776 $ Total $ 4,391 $ 3,369 $ </TABLE> Note 5. Inventories Inventories to support continuing are composed of the following: operations at December 31, 2001 and 2000 <TABLE> <CAPTI0N> Millions of dollars 2001 2000 <S> Finished products and parts Raw materials and supplies Work in process <C> $ 520 192 75 <C> $ 486 178 59 Total $ 787 $ 723 </TABLE> Inventories on the last-in, first-out method were $54 million at December 31, 2001 and $66 million at December 31, 2000. If the average cost method had been used, total inventories would have been about $20 million higher than reported at December 31, 2001, and $28 million higher than reported at December 31, 2000. Note 6. Property, Plant and Equipment Property, plant and equipment to support continuing operations at December 31, 2001 and 2000 are composed of the following: <TABLE> <CAPTI0N> Millions of dollars 2001 2000 <S> Land Buildings and property improvements Machinery, equipment and other <C> $ 82 942 4,926 <C> $ 83 968 4,509 Total Less accumulated depreciation 5,950 3,281 5,560 3,150 Net property, plant and equipment $ 2,669 $ 2,410 </TABLE> Tittrv//www cpr* crnv/ A minvpc/<=/) 9/000004 SOI 00900001 1 !pi\ 1 01-9001 tvt R/71 n 009 Page 45 of 89 At December 31, 2001 machinery, equipment and other property includes oil and gas investments of approximately $423 million and software developed for an information system of $233 million. At December 31, 2000 machinery, equipment and other property includes oil and gas investments of approximately $363 million and software developed for an information system of $223 million. 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. <PAGE> 42 . The larger unconsolidated entities include European Marine Contractors, Ltd., and Bredero-Shaw which are both part of the Energy Services Group. We sold our 50% interest in European Marine Contractors, Ltd., in January 2002. See Note 2. Bredero-Shaw, which is 50%-owned, specializes in pipecoating. Combined summarized financial information for all jointly owned operations which are not consolidated is as follows: <TABLE> <CAPTION> Combined Operating Results Years ended December 31 Millions of dollars 2001 2000 1999 <S> Revenues <C> $ 1,987 <C> $ 3,098 <C> $ 3,215 Operating income $ 231 $ 192 $ 193 Net income $ 169 $ 169 $ 127 </TABLE> <TABLE> <CAPTI0N> Combined Financial Position December 31 Millions of dollars 2001 2000 <S> Current assets Noncurrent assets <C> $ 1,818 1, 672 <C> $ 1,604 1,307 Total Current liabilities Noncurrent liabilities Minority interests Shareholders' equity $ 3,490 $ 1,522 1,272 2 694 $ 2,911 $ 1,238 947 2 724 Total . $ 3,490 $ 2,911 </TABLE> Note 8. Lines of Credit, Notes Payable and Long-Term Debt At December 31, 2001, we had committed lines of credit totaling $700 million, of which $350 million expires in 2002 and $350 million expires in 2006. There were no borrowings outstanding under these lines of credit. These lines are not available if our senior unsecured long-term debt is rated lower than BBB- by Standard & Poor's Ratings Service Group or lower than Baa3 by Moody's Investors' Services. httiW/www cpr> or>v/AiY'Viiv(aG//daar/d!it5iM^01 9/000004^01 90900001 1/<=>d1 OVOOni t-vt s/oi /onno Page 46 of 89 Fees for committed lines of credit were immaterial. Short-term debt consists primarily of $25 million in commercial paper with an effective interest rate of 2.9% and $19 million of other facilities with varying rates of interest. Long-term debt at the end of 2001 and 2000 consists of the following: <TABLE> <CAPTION> Millions of dollars <c> 7.6% debentures due August 2096 8.75% debentures due February 2021 8% senior notes due April 2003 Medium-term notes due 2002 through 2027 Effect of interest rate swaps Term loans at LIBOR (GBP) plus 0.75% payable in semiannual installments through March 2002 Other notes with varying interest rates 2001 <C> $ 300 200 139 825 3 4 13 2000 <C> $ 300 200 139 400 - 11 7 Total long-term debt Less current portion 1,484 81 1,057 8 Noncurrent portion of long-term debt $ 1,403 $ 1, 049 </TABLE> The 7.6% debentures notes due 2003 may not be fund requirements. due 2096, 8.75% debentures due 2021, and 8% senior redeemed prior to maturity and do not have sinking <PAGE> 43 On July 12, 2001, we issued $425 million of two and five year notes under our medium-term note program. The notes consist of $275 million 6% fixed rate notes due August 2006 and $150 million LIBOR + 0.15% floating rate notes due July 2003. At December 31, 2001, we have outstanding notes under our medium-term note program as follows: <TABLE> <CAPTION> Amount Due Rate Issue Price <S> $ $ $ $ $ $ 75 150 275 150 50 125 million million million million million million <C> 08/2002 07/2003 08/2006 12/2008 05/2017 02/2027 <C> 6.30% Floating% 6.00% 5.63% 7.53% 6.75% <C> Par Par 99.57% 99.97% Par 99.78% </TABLE> Each holder of the 6.75% medium-term notes has the right to require us to repay the holder's notes in whole or in part, on February 1, 2007. We may redeem the 5.63% and 6.00% medium-term notes in whole or in part at any time. Other notes issued under the medium-term note program may not be redeemed prior to maturity. The medium-term notes do not have sinking fund requirements. We manage our ratio of fixed variable rate debt and accordingly have entered into two interest rate swaps during the second half of 2001 on a portion of our newly issued 6% fixed rate medium-term notes and on our 8% senior notes. The interest rate swap agreements have notional amounts of $150 million and $139 million. The interest rate swaps have been designated as fair value hedges under SFAS No. 133. See Note 16. At December 31, 2001 the fair value of the interest rate swap on our 6% fixed rate medium-term notes was $3.4 million which has been Lt+rv*//vimn*r opn CirwrlArr1*u'Vpao/p/1fTCjr/dotaM4ni 7/000/1/1^401 70700001 1 /pJ1 01*7001 tvt S/71 /7fl07 Page 47 of 89 classified in "Other assets." The fair value of the interest rate swap on our 8% senior notes at December 31, 2001 was a $0.2 million liability and has been classified in "Other liabilities." The hedged portion of the long-term debt is recorded at fair value. We account for these interest rate swaps using the short-cut method, as described in SFAS No. 133, and determined there was no ineffectiveness for the period ending December 31, 2001. Amounts to be received or paid as a result of the swap agreements are recognized as adjustments to interest expense. The interest rate swaps resulted in a decrease to interest expense of $2.6 million for the year ended December 31, 2001. Our debt matures as follows: $81 million in 2002; $291 million in 2003; $2 million in 2004 and 2005; $277 million in 2006; and $828 million thereafter. Note 9. Commitments and Contingencies Leases. At year end 2001, 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, net of sublease rentals, for noncancelable leases in 2001, 2000, and 1999 were as follows: <TABLE> <CAPTION> Millions of dollars 2001 2000 1999 <S> Rental expense <C> $ 172 <C> $ 149 <C> $ 139 </TABLE> Future total rentals on noncancelable operating leases are as follows: $97 million in 2002; $83 million in 2003; $59 million in 2004; $43 million in 2005; $30 million in 2006; and $97 million thereafter. Asbestos litigation. Several of our subsidiaries, particularly Dresser Industries, Inc. and Kellogg Brown & Root, Inc., are defendants in a large number of asbestos related lawsuits. The plaintiffs allege injury as a result of exposure to asbestos in products manufactured or sold by former divisions of Dresser Industries, Inc. or in materials used in construction or maintenance projects of Kellogg Brown & Root, Inc. These claims are in three general categories: refractory claims; other Dresser Industries, Inc. claims; and construction claims. <PAGE> 44 Refractory claims Asbestos was used in a small number of products manufactured or sold by the refractories business of Harbison-Walker Refractories Company, which Dresser Industries, Inc. acquired in 1967. Harbison-Walker was spun-off by Dresser Industries, Inc. in 1992. At that time, Harbison-Walker assumed liability for asbestos claims filed after the spin-off and it agreed to defend and indemnify Dresser Industries, Inc. from liability for those claims. Dresser Industries, Inc. retained responsibility for asbestos claims filed before the spin-off. After the spin-off. Dresser Industries, Inc. and Harbison-Walker entered into coverage-in-place agreements with a number of insurance companies. Those agreements provide both Dresser Industries, Inc. and Harbison-Walker access to the same insurance coverage to reimburse them for defense costs, settlements and court judgments they pay to resolve refractory claims. As of December 31, 2001 there were approximately 7,000 open and unresolved pre-spin-off refractory claims against Dresser Industries, Inc. In addition, there were approximately 125,000 post spin-off claims that name Dresser Industries, Inc. as a defendant. Dresser Industries, Inc. has taken up the defense of unsettled post spin-off refractory claims that name it as a defendant in order to prevent Harbison-Walker from unnecessarily eroding the insurance coverage both companies can access for these claims. o/oi /onno Page 48 of 89 Other Dresser Industries, Inc. claims As of December 31, 2001, there were approximately 110,000 open and unresolved claims alleging injuries from asbestos used in several other types of products formerly manufactured by Dresser Industries, Inc. Most of these claims involve gaskets and packing materials used in pumps and other industrial products. Construction claims Our Engineering and Construction Group includes engineering and construction businesses formerly operated by The M.W. Kellogg Company and Brown & Root, Inc., now combined as Kellogg Brown & Root, Inc. As of December 31, 2001, there were approximately 32,000 open and unresolved claims alleging injuries from asbestos in materials used in construction and maintenance projects, most of which were conducted by Brown & Root, Inc. Less than 1,000 of these claims are asserted against The M.W. Kellogg Company. A prior owner of The M.W. Kellogg Company provides Kellogg Brown & Root, Inc. a contractual indemnification for those claims. Harbison-Walker Chapter 11 bankruptcy Harbison-Walker was spun-off by Dresser Industries, Inc. in 1992. At that time Harbison-Walker agreed to assume liability for asbestos claims filed after the spin-off and it agreed to defend and indemnify Dresser Industries, Inc. from liability for those claims. On February 14, 2002 Harbison-Walker filed a voluntary petition for reorganization under Chapter 11 of the United States Bankruptcy Code in the bankruptcy court in Pittsburgh, Pennsylvania. In its bankruptcy-related filings, Harbison-Walker said that it would seek to utilize Sections 524(g) and 105 of the bankruptcy code to propose and have confirmed a plan of reorganization that provides for distributions for all legitimate asbestos pending and future claims against it or for which it has agreed to indemnify and defend Dresser Industries, Inc. If a plan of reorganization is ultimately confirmed, all pending and future Harbison-Walker related asbestos claims against Harbison-Walker or Dresser Industries, Inc. could be channeled to a Section 524(g)/105 trust for resolution and payment. In order for a trust to be confirmed, at least a majority of the equity ownership of Harbison-Walker would have to be contributed to the trust. Creation of a trust would also require the approval of 75% of the asbestos claimant creditors of Harbison-Walker. In connection with the Chapter 11 filing by Harbison-Walker, the bankruptcy court issued a temporary restraining order staying all further litigation of more than 200,000 asbestos claims currently pending against Dresser Industries, Inc. in numerous courts throughout the United States. On February 21, 2002, the bankruptcy court extended the time period of the stay until April 4, 2002, when the bankruptcy court will hold a hearing to decide if the stay will continue or be modified. The stayed asbestos claims are those covered by insurance that both Dresser Industries, Inc. and Harbison-Walker can access to pay defense costs, settlements and judgments attributable to asbestos claims. The stayed claims include approximately 132,000 post-1992 spin-off refractory claims, 7,000 pre-spin-off refractory claims and approximately 96,000 other types of asbestos claims pending against Dresser Industries, Inc. that are covered by the same shared insurance. Approximately 46,000 of the claims in the third category are claims made against Dresser Industries, Inc. based on more than one ground for recovery and the stay affects only the portion of the claim covered by the shared insurance. The stay prevents litigation from proceeding while the stay is in effect and also prohibits the filing of new claims. One of the purposes of the stay is to allow Harbison-Walker and Dresser Industries, Inc. time to develop and propose a plan of reorganization. <PAGE> 45 The stay issued on February 14, 2002, and extended on February 21, 2002, is temporary until the bankruptcy court completes a hearing currently scheduled for April 4, 2002. At the conclusion of that hearing, the bankruptcy court may issue a preliminary injunction continuing the stay or it may modify or dissolve the stay as it applies to Dresser Industries, Inc. It is also possible that the bankruptcy court will schedule future hearings while continuing or modifying TvHtX'/Axnxnx/ c^r* crr\ir!A-rr4vi'tr#aeAa/"1rrar/data Al^OI 7/OOOOOd^COI 70700001 1 /od 1 01-7001 fvt 0/71/7007 Page 49 of 89 the stay. At present, there is no assurance that a stay will remain in effect, that a plan of reorganization will ultimately be proposed or confirmed, or that any plan that is confirmed will provide relief to Dresser Industries, Inc. If a plan is not ultimately confirmed that provides relief to Dresser Industries, Inc., it will be required to defend all open claims in the courts in which they have been filed, possibly with reduced access to the insurance shared with Harbison-Walker. Dresser Industries, Inc. has agreed to provide $35 million of debtor-in-possession financing to Harbison-Walker during the pendency of the Chapter 11 proceeding. On February 14, 2002, Dresser Industries, Inc. paid $40 million to Harbison-Walker's U.S. parent holding company, RHI Refractories Holding Company which we will charge to discontinued operations in the first quarter of 2002. The first payment was made on the filing of the bankruptcy petition. Dresser Industries, Inc. had to act to protect its insurance asset from dissipation by Harbison-Walker if there was going to be any potential to resolve the asbestos claims through the creation of a Section 524(g)/105 trust. The payment to RHI Refractories led RHI Refractories to forgive certain inter-company debt owed to it by Harbison-Walker, thus increasing the assets of Harbison-Walker. Dresser Industries, Inc. will pay another $35 million to RHI if a plan of reorganization acceptable to Dresser Industries, Inc. is proposed in the bankruptcy proceedings. A further $85 million will be paid to RHI if a plan acceptable to Dresser Industries, Inc. is approved by 75% of the Harbison-Walker asbestos claimant creditors and is confirmed by the bankruptcy court. Dresser Industries, Inc., Harbison-Walker and RHI and its affiliates have settled all litigation among them. Asbestos insurance coverage We have insurance coverage that reimburses us for a substantial portion of the costs we incur defending against asbestos claims. This coverage also reimburses us for a substantial portion of amounts we pay to settle claims and amounts awarded in court judgments. The coverage is provided by a large number of insurance policies written by dozens of insurance companies. The insurance companies wrote the coverage over a period of more than 30 years for our subsidiaries and their predecessors. Large amounts of this coverage are now subject to coverage-in-place agreements that resolve issues concerning amounts and terms of coverage. The amount of insurance coverage available to us depends on the nature and time of the alleged exposure to asbestos, the specific subsidiary against which an asbestos claim is asserted and other factors. Refractory claims insurance Dresser Industries, Inc. has approximately $2.1 billion in aggregate limits of insurance coverage for refractory asbestos claims of which over half is with Equitas. Many of the issues relating to the majority of this coverage have been resolved by coverage-in-place agreements with dozens of companies, including Equitas and other London-based insurance companies. Recently, however, Equitas and other London-based companies have imposed new restrictive documentation requirements on Dresser Industries, Inc. and other insureds. Equitas and the other London-based companies have stated that the new requirements are part of an effort to limit payment of settlements to claimants who are truly impaired by exposure to asbestos and can identify the product or premises that caused their exposure. On August 7, 2001 Dresser Industries, Inc. filed a lawsuit in Dallas County, Texas, against a number of these insurance companies asserting Dresser Industries, Inc.'s rights under existing coverage-in-place agreements. These agreements allow Dresser Industries, Inc. to enter into settlements for small amounts without requiring claimants to produce detailed documentation to support their claims, when we believe settlements are an effective claims management strategy. We believe that the new documentation requirements are inconsistent with the current coverage-in-place agreements and are unenforceable. The insurance companies Dresser Industries, Inc. has sued have not refused to pay larger claim settlements where documentation is obtained or where court judgments are entered. Also, they continue to pay previously agreed to amounts of defense costs Dresser Industries, Inc. incurs defending refractory asbestos claims. If a Section 524(g)/105 trust is confirmed as part of the Harbison-Walker bankruptcy proceedings, this insurance will be used to fund that trust. VittrW/www apt* ww/Arr*hitri=>o/(rl<T'jr/d3t5/4^ni 7/000004^01 70700001 1 /pH 1 0V7001 tvf R/71 /7fin7 Page 50 of 89 <PAGE> 46 Other Dresser Industries, Inc. claims insurance Dresser Industries, Inc. has insurance that covers other open asbestos claims against it. Some of this insurance covers Dresser Industries, Inc. entities acquired prior to the 1986 asbestos exclusions. Many of the traditional Dresser Industries, Inc. product manufacturing companies or divisions are covered under these policies. Other coverage is provided by a number of different policies which Dresser Industries, Inc. acquired rights to access for coverage of asbestos claims when it acquired businesses from other companies. A significant portion of this insurance coverage is shared with Federal-Mogul Corporation, which is now in reorganization under Chapter 11 of the bankruptcy code. The effect of that bankruptcy on Dresser Industries, Inc.'s ability to continue to access this shared insurance is uncertain. On August 28, 2001, Dresser Industries, Inc. filed a separate lawsuit against Equitas and other London-based companies that provide some of this insurance. This lawsuit is similar to the lawsuit described under Refractory Claims Insurance above that seeks to prevent insurance companies from unilaterally modifying the terms of existing coverage-in-place agreements. Construction claims insurance Nearly all of our construction asbestos claims relate to Brown & Root, Inc. operations before the 1980s. Our primary insurance coverage for these claims was written by Highlands Insurance Company during the time it was one of our subsidiaries. Highlands was spun-off to our shareholders in 1996. At present. Highlands is not paying any portion of the settlement or defense costs we incur for construction asbestos claims. On April 5, 2000, Highlands filed a lawsuit against us in the Delaware Chancery Court. Highlands asserted that the insurance it wrote for Brown & Root, Inc. that covered construction asbestos claims was terminated by agreements between Halliburton and Highlands at the time of the 1996 spin-off. Although we do not believe that a termination of this insurance occurred, in March 2001, the Chancery Court ruled that a termination did occur and that Highlands is not obligated to provide coverage for Brown & Root, Inc.'s asbestos claims. A three Justice panel of the Delaware Supreme Court heard oral arguments of our appeal of this decision on September 17, 2001. The appeal will be reargued before the entire Delaware Supreme Court on March 12, 2002. We believe the Chancery Court's decision is wrong and that the Delaware Supreme Court will reverse and return the case to the Chancery Court for a trial on the merits. We expect, based on an opinion from our outside legal counsel, to ultimately prevail in this litigation. We anticipate the Delaware Supreme Court's decision later this year. In addition, on April 24, 2000, we filed a lawsuit in Harris County, Texas, asserting that Highlands has breached its contractual obligations to provide coverage for asbestos claims under the policies it wrote for Brown & Root, Inc. This lawsuit is stayed pending resolution of the Delaware litigation. We are aware that Highland's financial condition has deteriorated since this litigation began. A.M. Best has reduced its rating for Highlands to "C-" (weak) and Highlands has ceased all of its underwriting operations. However, we believe that once the Delaware litigation is successfully concluded in our favor as we expect. Highlands has the ability to reimburse us for a substantial portion of the defense, settlement and other costs we incur defending Brown & Root, Inc. open asbestos claims. If Highlands becomes unable to pay amounts owed to us for coverage of Brown & Root, Inc. open asbestos claims, we have the right to seek reimbursement from the Texas Property and Casualty Guaranty Association. This association consists of and is funded by all insurance companies permitted to write insurance in Texas. It provides protection to insured parties and claimants when an insurance company licensed in Texas becomes insolvent. This protection is limited and there are a number of issues that would need to be resolved if we seek to collect from the association if Highlands becomes insolvent. Significant asbestos judgments on appeal During 2001, there were several adverse judgments in trial court proceedings that are in various stages of the appeal process. All of these judgments concern asbestos claims involving Harbison-Walker refractory products. httrv//www Qpr criw/Arrfiivpc/pdcrnr/rljitnMSOI 9/000004^01909000011 IpcM 0V9001 tvt 8/91/9009 Page 51 of 89 Each of these appeals, however, has been stayed by the bankruptcy court, as described in the Harbison-Walker Chapter 11 bankruptcy section above, until at least April 4, 2002. On November 29, 2001, the Texas District Court in Orange, Texas, entered judgments against Dresser Industries, Inc. on a $65 million jury verdict rendered in September 2001 in favor of five plaintiffs. The $65 million amount includes $15 million of a $30 million judgment against Dresser Industries, Inc. and another defendant. Dresser Industries, Inc. is jointly and severally liable for $15 million in addition to $65 million if the other defendant does not pay its share of this judgment. We believe that during the trial the court committed numerous errors, including prohibiting Dresser Industries, Inc. from presenting evidence that the alleged illness of the plaintiffs was caused by products of <PAGE> 47 other companies that had previously settled with the plaintiffs. We intend to appeal this judgment and believe that the Texas appellate courts will ultimately reverse this judgment. On November 29, 2001, the same District Court in Orange, Texas, entered three additional judgments against Dresser Industries, Inc. in the aggregate amount of $35.7 million in favor of 100 other asbestos plaintiffs. These judgments relate to an alleged breach of purported settlement agreements signed early in 2001 by a New Orleans lawyer hired by Harbison-Walker, which had been defending Dresser Industries, Inc. pursuant to the agreement by which Harbison-Walker was spun-off by Dresser Industries, Inc.- in 1992. These settlement agreements expressly bind Harbison-Walker Refractories Company as the obligated party, not Dresser Industries, Inc. Dresser Industries, Inc. intends to appeal these three judgments on the grounds that it was not a party to the settlement agreements and it did not authorize anyone to settle on its behalf. We believe that these judgments are contrary to applicable law and will be reversed. On December 5, 2001, a jury in the Circuit Court for Baltimore City, Maryland, returned verdicts against Dresser Industries, Inc. and other defendants following a trial involving refractory asbestos claims. Each of the five plaintiffs alleges exposure to Harbison-Walker products. Dresser Industries, Inc.'s portion of the verdicts was approximately $30 million. Dresser Industries, Inc. believes that the trial court committed numerous errors and that the trial evidence did not support the verdicts. The trial court has entered judgment on these verdicts. Dresser Industries, Inc. intends to appeal the judgment to the Maryland Supreme Court where we expect the judgment will be significantly reduced, if not totally reversed. On October 25, 2001, in the Circuit Court of Holmes County, Mississippi, a jury verdict of $150 million was rendered in favor of six plaintiffs against Dresser Industries, Inc. and two other companies. Dresser Industries, Inc.'s share of the verdict was $21.5 million. The award was for compensatory damages. The jury did not award any punitive damages. The trial court has entered judgment on the verdict. We believe there were serious errors during the trial and we intend to appeal this judgment to the Mississippi Supreme Court. We believe the judgment will ultimately be reversed because there was a total lack of evidence that the plaintiffs were exposed to a Harbison-Walker product or that they suffered compensatory damages. Also, there were procedural errors in the selection of the jury. Asbestos claims history. Since 1976, approximately 474,500 asbestos claims have been filed against us. Almost all of these claims have been made in separate lawsuits in which we are named as a defendant along with a number of other defendants, often exceeding 100 unaffiliated defendant companies in total. During the fourth quarter of 2001 we received approximately 14,000 new claims, compared to 16,000 new claims in the third quarter, 27,000 new claims in the second quarter and 18,000 new claims in the first quarter of 2001. Included in these numbers are new Harbison-Walker claims of approximately 4,000 in the fourth quarter and 3,000 in the third quarter. During the fourth quarter of 2001, we closed approximately 7,000 claims, resulting in approximately 36,000 closed claims during 2001. The number of open claims pending against us at the crmr! Arr*Viii7-7so/^drrcr/dataM4ni 0/000004401 70000001 1 le^A'X rVt-7AA1 t-vt <an i nnm Page 52 of 89 end of each quarter of 2001 and at the end of the two preceding years is as follows: <TABLE> <CAPTION> Period Ending Total Open Claims <S> December 31, 2001 September 30, 2001 June 30, 2001 March 31, 2001 December 31, 2000 December 31, 1999 <C> 274,000 146,000 145,000 129,000 117,000 107,700 </TABLE> The claims reported above at December 31, 2001 include approximately 125,000 Harbison-Walker refractory related claims that name Dresser Industries, Inc. as a defendant. These claims were added to the open claim total during the fourth quarter. <PAGE> 48 We manage asbestos claims to achieve settlements of valid claims for reasonable amounts. When that is not possible, we contest claims in court. Since 1976 we have closed approximately 200,500 claims through settlements and court proceedings at a total cost of approximately $150 million. We have received or expect to receive from our insurers all but approximately $40 million of this cost, resulting in an average net cost per closed claim of less than $200. Reserves for asbestos claims. We have accrued reserves for our estimate of our liability for known open asbestos claims. We have not accrued reserves for unknown claims that may be filed against us in the future. Our estimate of the cost of resolving open claims is based on our historical litigation experience on closed claims, completed settlements and our estimate of amounts we will recover from insurance companies. Our estimate of recoveries from insurance companies with which we have coverage-in-place agreements is based on those agreements. In those instances in which agreements are still in negotiation or in litigation, our estimate is based on our expectation of our ultimate recovery from insurance companies. We believe that the insurance companies with which we have signed agreements will be able to meet their obligations under these agreements for the amounts due to us. A summary of our reserves for open claims and corresponding insurance recoveries is as follows: <TABLE> <CAPTION> December 31 Millions of dollars 2001 2000 <S> Asbestos litigation claims <C> $ 737 <C> $ 80 Estimated insurance recoveries: Highlands Insurance Company Other insurance carriers (45) (567) (39) (12) Insurance for asbestos litigation claims (612) (51) Net liability for known open asbestos claims $ 125 $ 29 ear* crrwrt A rrTiiK,ff.c/^r1rrQf/r)oto//1 401 0/00000/1 401 900OOOOI 1 /o^l HVOflAI fvf q/oi /oono Page 53 of 89 </TABLE> These insurance receivables and reserves are included in noncurrent assets and liabilities due to the extended time periods involved to settle claims. In addition to these asbestos reserves, our accounts receivable include $35 million we expect to collect from Highlands Insurance Company for settlements and defense costs we have already incurred for construction asbestos claims. If we are ultimately unsuccessful in the Highlands litigation, we will be unable to collect this $35 million as well as the $45 million estimated recovery from Highlands included in our asbestos reserves summarized above. If this occurs, it may have a material adverse impact on the results of our operations and our financial position at that time. Accounts receivable for billings to other insurance companies for payments made on asbestos claims were $18 million at December 31, 2001 and $13 million at December 31, 2000. We have not accrued reserves for unknown claims that may be asserted against us in the future. We have not had sufficient information to make a reasonable estimate of future claims. However, we recently retained a leading claim evaluation firm to assist us in making an estimate of our potential liability for asbestos claims that may be asserted against us in the future. When the evaluation firm's analysis is completed it is likely that we will accrue a material liability for future claims that may be asserted against us. We expect the analysis will be completed during the second quarter of 2002 and that we will accrue the liability at the end of the quarter. At the same time we will accrue a receivable for related insurance proceeds we expect to collect when future claims are actually paid. The uncertainties of asbestos claim litigation and resolution of the litigation with insurance companies described above make it difficult to accurately predict the results of the ultimate resolution of asbestos claims. That uncertainty is increased by the possibility of adverse court rulings or new legislation affecting asbestos claim litigation or the settlement process. Subject to these uncertainties and based on our experience defending asbestos claims and our estimate of amounts we will recover from insurance, we believe that the open asbestos claims pending against us will be resolved without a material adverse effect on our financial position or the results of our operations. Fort Ord litigation. Brown & Root Services, how operating as Kellogg Brown Sc Root, has been 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. On February 8, 2002, this lawsuit and a related grand jury investigation <PAGE> 49 were settled. Kellogg Brown & Root made a $2 million payment to the United States government and paid the former employee's legal expenses. Kellogg Brown & Root denied wrongdoing and did not admit liability. The United States agreed to suspend further investigation and forgo any further sanctions with regard to the Ft. Ord contract. Kellogg Brown & Root's ability to perform further work for the United States government has not been impaired. BJ Services patent litigation. On March 17, 2000, BJ Services Company filed a lawsuit against us in the United States District Court in Houston, Texas. The lawsuit alleges that a well fracturing fluid system used by Halliburton Energy Services infringes a patent issued to BJ in January 2000 for a method of well fracturing using a specific fracturing fluid. A jury trial is scheduled for March 2002. We expect BJ will seek several hundred million dollars of damages and an injunction to prevent us from using one of our competing fracturing fluids. We also expect BJ to allege that we intentionally infringed its patent and to seek treble damages. We do not believe we have infringed BJ's patent and we have filed a counterclaim that the patent is invalid and unenforceable. We TnHn'/Aimmr cap (Tmr/Ai*AliiijAe/A^rtor//1af'3/y1^ri1 7/00000/1 OAOOfinOI 1 /a/11 AlrOAAl tvt o/oi /onno Page 54 of 89 also believe that BJ's large damage claims are unsupportable. We believe that we have no liability for infringement of the BJ patent. However, if the patent is found to be enforceable and we are found to have infringed it, we could be held liable for damages in an amount that has a material adverse effect on our financial position and the results of our operations. 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 requirements. 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. We also incur costs related to compliance with ever-changing environmental, legal and regulatory requirements in the jurisdictions 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. During the second quarter of 2001, we accrued $15 million for environmental matters related to liabilities retained on properties included in the sale of Dresser Equipment Group. Our accrued liabilities for environmental matters were $49 million as of December 31, 2001 and $31 million as of December 31, 2000. Other. We are a party to various other legal proceedings. We expense the cost 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 results of operations. Letters of credit. In the normal course of business, we have agreements with banks under which approximately $1.4 billion of letters of credit or bank guarantees were issued, including $241 million which relate to our joint ventures' operations. In addition, $320 million of these financial instruments include provisions that allow the banks to require cash collateralization if debt ratings of either rating agency fall below the rating of BBB by Standard & Poor's or Baa2 by Moody's Investors' Sevices and $149 million where banks may require cash collateralization if either debt rating falls below investment grade. These letters of credit and bank guarantees relate to our guaranteed performance or retention payments under our long-term contracts and self-insurance. In the past, no significant claims have been made against these financial instruments. We do not anticipate material losses to occur as a result of these financial instruments. <PAGE> 50 Note 10. Income Per Share <TABLE> <CAPTION> Millions of dollars and shares except per share data 2001 20 <S> Income from continuing operations before change in accounting method, net <C> $ 551 <C> $ Basic weighted average shares Effect of common stock equivalents Diluted weighted average shares 428 2 430 Income per common share from continuing operations before change in accounting method, net: Basic $ 1.29 $ littn'/Alninr cfir* crrwrl A rrVtnw/A/1 rror/Joto IA 5f11 D /flfinflfl/l OnOfinflfM 1 /p/11 flVOOfil tvt nnnn Page 55 of 89 Diluted $ 1.28 $ </TABLE> 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 10 million shares of common stock in 2001, 1 million shares in 2000 and 2 million shares in 1999. These options were outstanding during these years, but were excluded because the option exercise price was greater than the average market price of the common shares. Note 11. Engineering and Construction Reorganization The table below summarizes non-recurring charges of $36 million pretax recorded in the Engineering and Construction Group segment in December 2000 related to the reorganization of our engineering and construction businesses. <TABLE> <CAPTION> Millions of dollars <c> 2000 charges Utilized in 2000 Asset Related Charges <C> $ 20 (20) Personnel Charges <C> $ 16 Total <C> $ 36 (20) Balance December 31, 2000 Utilized in 2001 Adjustments of estimate to actual - 16 16 - (11) (11) - (4) (4) Balance December 31, 2001 </TABLE> $ $1 $1 These charges were reflected in the following captions of the consolidated statements of income: <TABLE> <CAPTION> Year ended December 31 Millions of dollars 2000 <S> Cost of services General and administrative <C> $ 30 6 Total $ 36 </TABLE> <PAGE> 51 Asset Related Charges As a result of the reorganization of the engineering and construction businesses, we took actions in the fourth quarter of 2000 to rationalize our Vi+fn'/Aurwm: ce*r> nmi/A-rr4-ni7^e//=>drrarMa+aM^01 0/00000^*101 OfVOnnnni 1 OVOOPlI tvt c/oi nnno Page 56 of 89 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. As of December 31, 2001, payments of $11 million had been made and the elimination of personnel was substantially complete. In January 2002, the last of the planned personnel actions was completed. Note 12. Change in Accounting Method In July 2001, the Financial Accounting Standards Board issued SFAS No. 142 "Goodwill and Other Intangible Assets." Effective January 1, 2002, goodwill will no longer be amortized but will be tested for impairment as set forth in the statement. We have reviewed this new statement and have determined that our reporting units as defined under SFAS No. 142 will be the same as our reportable operating segments; Energy Services Group and Engineering and Construction Group. We have completed our step one goodwill impairment analysis as of January 1, 2002 to estimate the fair value of each of our reporting units and that analysis indicates that we do not have a goodwill impairment as a result of adopting SFAS No. 142. Amortization of goodwill for 2001 totaled $42 million pretax and $38 million after-tax. In July 2001, the Financial Accounting Standards Board issued SFAS No. 141 "Business Combinations" which requires the purchase method of accounting for business combination transactions initiated after June 30, 2001. The statement requires that goodwill recorded on acquisitions completed prior to July 1, 2001 be amortized through December 31, 2001. Goodwill amortization is precluded on acquisitions completed after June 30, 2001. In June 1998, the Financial Accounting Standards Board issued SFAS No. 133 "Accounting for Derivative Instruments and for Hedging Activities", subsequently amended by SFAS No. 137 and SFAS No. 138. This standard requires entities to recognize all derivatives on the 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 is specified in the standard depending on the intended use of the derivative and other criteria. We adopted SFAS No. 133 effective January 2001 and recorded a gain of $1 million after-tax for the cumulative effect of adopting the change in accounting method. We do not expect future measurements at fair value under the new accounting method to have a material effect on our financial condition or results of operations. 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. <PAGE> 52 Note 13. Income Taxes The components of the (provision) benefit for income taxes are: htfn'/Anmm/ o**r* crr\\7l Ar^Hitr^c/^dnror/doto/J.^GI 7/OOnOOJ^AI 70900001 1 Oils') 001 tvt s/oi nooo Page 57 of 89 <TABLE> <CAPTION> Years ended December 31 Millions of dollars 2001 2000 199S <S> Current Federal Foreign State income taxes: Total <C> $ (146) (157) (20) (323) <C> $ (16) (114) (5) (135) <C> $ 13 (6 ( 7 Deferred income taxes: Federal Foreign and state Total Total continuing operations Discontinued operations: Current income taxes Deferred income taxes Disposal of discontinued operations Benefit for change in accounting method (58) (3) (61) $ (384) (15) 35 (199) (20) 26 6 $ (129) (60) - (141) - (17 (1 (18 $ (11 (S (S 1 Total </TABLE> $ (563) $ (330) $ (2S II Included in the current (provision) benefit for income taxes are foreign tax credits of $106 million in 2001, $113 million in 2000 and $52 million in 1999. The United States and foreign components of income before income taxes, minority interests, discontinued operations, and change in accounting method are as follows: <TABLE> <CAPTI0N> Years ended December 31 Millions of dollars <S> United States Foreign 2001 <C> $ 565 389 2000 <C> $ 128 207 1999 <C> $ 131 176 Total </TABLE> $ 954 $ 335 $ 307 The primary components of our deferred tax assets and liabilities and the related valuation allowances, including federal deferred tax assets of discontinued operations are as follows: <PAGE> 53 <TABLE> <CAPTI0N> December 31 lifti-v/Annim/ or*n rrr'(7/AT,/,*!iiT7^c?/^drro-r/dcifo/46ni OOOnnnni 1 nirOOm fvf o/oi /onno Page 58 of 89 Millions of dollars 2001 2000 <S> Gross deferred tax assets: Employee benefit plans Capitalized research and experimentation Accrued liabilities Insurance accruals Construction contract accounting methods Inventory Asbestos Intercompany profit Net operating loss carryforwards Intangibles Allowance for bad debt All other <C> $ 214 46 121 82 100 53 44 54 44 18 36 41 <C> $ 265 39 118 99 117 43 10 44 35 20 31 57 Total Gross deferred tax liabilities: Depreciation and amortization Nonrepatriated foreign earnings All other $ 853 $ 106 36 101 $ 878 $ 128 36 103 Total Valuation allowances: Net operating loss carryforwards All other $ 243 $ 38 8 $ 267 $ 28 8 Total 46 36 Net deferred income tax asset </TABLE> $ 564 $ 575 We have accrued for the potential repatriation of undistributed earnings of our foreign subsidiaries and consider earnings above the amounts on which tax has been provided to be permanently reinvested. While these additional earnings could become subject to additional tax if repatriated, repatriation is not anticipated. Any additional amount of tax is not practicable to estimate. We have net operating loss carryforwards of $95 million which expire in 2002 through 2009. We also have net operating loss carryforwards of $25 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: <TABLE> <CAPTI0N> Years ended Dec Millions of dollars <S> Provision computed at statutory rate Reductions (increases) in taxes resulting from: Tax differentials on foreign earnings State income taxes, net of federal income tax benefit Nondeductible goodwill Other items, net 2001 <C> $ (334) (32) (13) (11) 6 2000 <C> $ (117 (14 (3 (11 16 Total continuing operations Discontinued operations (384) 20 (129 (60 Tittn'/Aimmr oop 0/00^0^/1^01 000^0001 1 /o/11 HVOHOI fvf 0/01 /OAAO Page 59 of 89 Disposal of discontinued operations Benefit for change in accounting method (199) (141 Total $ (563) $ (330 </TABLE> <PAGE> 54 Note 14. Common Stock Our 1993 Stock and Long-Term Incentive Plan provides for the grant of any or all of the following types of awards: stock options, including incentive stock options and non-qualified stock options; stock appreciation rights, in tandem with stock options or freestanding; restricted stock; performance share awards; and stock value equivalent awards. Under the terms of the 1993 Stock and Long-Term Incentive Plan as amended, 49 million shares of common stock have been reserved for issuance to key employees. The plan specifies that no more than 16 million shares can be awarded as restricted stock. At December 31, 2001, 22 million shares were available for future grants under the 1993 Stock and Long-Term Incentive Plan of which 11 million shares remain available for restricted stock awards. In connection with the acquisition of Dresser Industries, Inc. in 1998, we assumed the outstanding stock options under the stock option plans maintained by Dresser Industries, Inc. Stock option transactions summarized below include amounts for the 1993 Stock and Long-Term Incentive Plan and stock plans of Dresser Industries, Inc. and other acquired companies. No further awards are being made under the stock plans of acquired companies. <TABLE> <CAPTION> Stock Options Number of Shares (in millions) Exercise Price per Share Weighted Exercise per Sb <S> Outstanding at December 31, 1998 Granted Exercised Forfeited <C> 13.8 5.6 (1.7) (0.6) <C> $ 3.10 - 61.50 28.50 - 48.31 3.10 - 54.50 8.28 - 54.50 <C> $ 29. 36. 24. 35. Outstanding at December 31, 1999 Granted Exercised Forfeited 17.1 1.7 (3.6) (0.5) $ 3.10 - 61.50 34.75 - 54.00 3.10 - 45.63 12.20 - 54.50 $ 32. 41. 25. 37. Outstanding at December 31, 2000 Granted Exercised Forfeited 14.7 3.6 (0.7) (0.5) $ 8.28 - 61.50 12.93 - 45.35 8.93 - 40.81 12.32 - 54.50 $ 34. 35. 25. 36. Outstanding at December 31, 2001 </TABLE> 17.1 $ 8.28 - 61.50 $ 35. Options outstanding at December 31, 2001 are composed of the following: httiv/Ajrww Qpn onv/Arr>Tiivpc/pHopr/di(t:>M^ni 9/000004^01 '70900001 1 /f>d1 01-9001 tvt snmnm Page 60 of 89 <TABLE> <CAPTION> Outstanding Range of Exercise Prices Number of Shares (in millions) Weighted Average Remaining Contractual Life Weighted Average Exercise Price Numbe Sha (in mi <S> $ 8.28 - 29.06 29.07 - 39.06 39.07 - 39.55 39.56 - 61.50 <C> 4.9 4.7 5.3 2.2 <C> 5.7 6.7 8.0 6.7 <C> $ 25.11 33.42 39.51 50.22 <C> $ 8.28 - 61.50 17.1 6.8 $ 35.10 1 </TABLE> There were 8.8 million options exercisable with a weighted average exercise price of $32.81 at December 31, 2000, and 9.5 million options exercisable with a weighted average exercise price of $28.96 at December 31, 1999. <PAGE> 55 All stock options under the 1993 Stock and Long-Term Incentive Plan, including options granted to employees of Dresser Industries, Inc. since its acquisition, are granted at the fair market value of the common stock at the grant date. 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: <TABLE> <CAPTION> Risk-Free Interest Rate Assumptions Expected Dividend Yield Expected Life (in years) Expected Volatility Vi <C> 2001 2000 1999 <C> 4.5% 5.2% 5.8% <C> 2.3% 1.3% 1.3% <C> 5 5 5 <C> 58% 54% 56% </TABLE> Stock options generally expire 10 years from the grant date. Stock options under the 1993 Stock and Long-Term Incentive Plan vest ratably over a three or four year period. Other plans have vesting periods ranging from three to 10 years. Options under the Non-Employee Directors' Plan vest after six months. 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 other than for restricted stock grants. Compensation cost for the stock option programs calculated consistent with SFAS No. 123, "Accounting for Stock-Based Compensation," is set forth on a pro forma basis below: <TABLE> <CAPTI0N> Millions of dollars except per share data 2001 2000 1999 httrv/Avww apn orfw/Arr,Tiiv<=`c//=>Ho'Cir/dcit'jM.^ni O/nnOOflAAOl 90900001 1 MLOnni fvt 8/91 nnm Page 61 of 89 <s> Net income: As reported Pro forma <C> $ 809 767 <C> $ 501 460 <C> $ 438 406 Diluted earnings per share As reported Pro forma $ 1.88 1.77 $ 1.12 1.03 $ 0.99 0.92 </TABLE> Restricted shares awarded under the 1993 Stock and Long-Term Incentive Plan were 1,484,034 in 2001, 695,692 in 2000 and 352,267 in 1999. The shares awarded are net of forfeitures of 170,050 in 2001, 69,402 in 2000 and 72,483 in 1999. The weighted average fair market value per share at the date of grant of shares granted was $30.90 in 2001, $42.25 in 2000 and $43.41 in 1999. Our Restricted Stock Plan for Non-Employee Directors allows for each non-employee director to receive an annual award of 400 restricted shares of common stock as a part of compensation. We reserved 100,000 shares of common stock for issuance to non-employee directors. Under this plan we issued 4,800 restricted shares in 2001, 3,600 restricted shares in 2000 and 4,800 restricted shares in 1999. At December 31, 2001, 33,600 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 $34.35 in 2001, $46.81 in 2000 and $46.13 in 1999. 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, 2001, 153,050 shares (net of 42,350 shares forfeited) have been issued. Forfeitures were 800 in 2001, 6,450 in 2000 and 8,400 in 1999. 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, 2001, 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. <PAGE> 56 Restricted shares issued under the 1993 Stock and Long-Term Incentive Plan, Restricted Stock Plan for Non-Employee Directors, Employees' Restricted Stock Plan and the Career Executive Incentive Stock Plan are limited as to sale or disposition. These restrictions lapse periodically over an extended period of time not exceeding 10 years. Restrictions may also lapse for early retirement and other conditions in accordance with our established policies. The fair market value of the stock, on the date of issuance, is being amortized and charged to income (with similar credits to paid-in capital in excess of par value) generally over the average period during which the restrictions lapse. At December 31, 2001, the unamortized amount is $87 million. We recognized compensation costs of $23 million in 2001, $18 million in 2000 and $11 million in 1999. On April 25, 2000, our Board of Directors approved plans to implement a share repurchase program for up to .44 million shares. We repurchased 1.2 million shares at a cost of $25 million in 2001 and 20.4 million shares at a cost of $759 million in 2000. Note 15. 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 opt1 rrmr/Ar/'1in7pe/A7lfTQrMofa//1^ni 0/00000/1^01 007000^1 1 ApJ 1 nVOfWlI +vf 9/oi nnm Page 62 of 89 Series A Junior Participating Preferred Stock, without par value, at an exercise price of $75. These preferred stock purchase rights are subject to anti-dilution adjustments, which are described in the Rights Agreement entered into with Mellon. The preferred stock purchase rights do not have any voting rights and are not entitled to dividends. The preferred stock purchase rights become exercisable in limited circumstances involving a potential business combination. After the preferred stock purchase rights become exercisable, each preferred stock purchase right will entitle its holder to an amount of our common stock, or in some circumstances, securities of the acquirer, having a total market value equal to two times the exercise price of the preferred stock purchase right. The preferred stock purchase rights are redeemable at our option at any time before they become exercisable. The preferred stock purchase rights expire on December 15, 2005. No event during 2001 made the preferred stock purchase rights exercisable. Note 16. Financial Instruments and Risk Management In June 1998, the Financial Accounting Standards Board issued SFAS No. 133 "Accounting for Derivative Instruments and for Hedging Activities", subsequently amended by SFAS No. 137 and SFAS No. 138. This standard requires entities to recognize all derivatives on the balance sheet as assets or liabilities and to measure the instruments at fair value. Accounting for gains 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 adopted SFAS No. 133 effective January 2001 and recorded a $1 million after-tax credit for the cumulative effect of adopting the change in accounting method. We do not expect future measurements at fair value under the new accounting method to have a material effect on our financial condition or results of operations. Foreign exchange risk. Techniques in managing foreign exchange risk include, but are not limited to, foreign currency borrowing and investing and the use of currency derivative instruments. We selectively manage significant exposures to potential foreign exchange losses considering current market conditions, future operating activities and the associated cost in relation to the perceived risk of loss. The purpose of our foreign currency risk management activities is to protect us from the risk that the eventual dollar cash flows resulting from the sale and purchase of products and services in foreign currencies will be adversely affected by changes in exchange rates. We do not hold or issue derivative financial instruments for trading or speculative purposes. We manage our currency exposure through the use of currency derivative instruments as it relates to the major currencies, which are generally the currencies of the countries for which we do the majority of our international business. These contracts generally have an expiration date of two years or less. Forward exchange contracts, which are commitments to buy or sell a specified amount of a foreign currency at a specified price and time, are generally used to manage identifiable foreign currency commitments. Forward exchange contracts and foreign exchange option contracts, which convey the right, but not the obligation, to sell or buy a specified amount of foreign currency at a specified price, are generally used to manage exposures related to assets and liabilities denominated in a foreign currency. None of the forward or <PAGE> 57 option contracts are exchange traded. While derivative instruments are subject to fluctuations in value, the fluctuations are generally offset by the value of the underlying exposures being managed. The use of some contracts may limit our ability to benefit from favorable fluctuations in foreign exchange rates. Foreign currency contracts are not utilized to manage exposures in some currencies due primarily to the lack of available markets or cost considerations (non-traded currencies). We attempt to manage our working capital position to minimize foreign currency commitments in non-traded currencies and recognize that pricing for the services and products offered in these countries should cover the cost of exchange rate devaluations. We have historically incurred TvH'rv//www <5pr onv/Arrbivpc/pdonr/dntn/A^m 0/000004501000000011 !pt\ 1 0V0001 t-vt S/01 /0000 Page 63 of 89 transaction losses in non-traded currencies. Assets, liabilities and forecasted cash flows denominated in foreign currencies. We utilize the derivative instruments described above to manage the foreign currency exposures related to certain assets and liabilities, which are denominated in foreign currencies; however, we have not elected to account for these instruments as hedges for accounting purposes. Additionally, we utilize the derivative instruments described above to manage forecasted cash flows denominated in foreign currencies generally related to long-term engineering and construction projects. While we enter into these instruments to manage the foreign currency risk on these projects, we have chosen not to seek hedge accounting treatment for these contracts. The fair value of these contracts was immaterial as of the end of 2001 and 2000. Notional amounts and fair market values. The notional amounts of open forward contracts and options for continuing operations were $505 million at December 31, 2001 and $281 million at December 31, 2000. Amounts related to discontinued operations were $61 million at December 31, 2000. The notional amounts of our foreign exchange contracts do not generally represent amounts exchanged by the parties, and thus, are not a measure of our exposure or of the cash requirements relating to these contracts. The amounts exchanged are calculated by reference to the notional amounts and by other terms of the derivatives, such as exchange rates. Credit risk. Financial instruments that potentially subject us to concentrations of credit risk are primarily cash equivalents, investments and trade receivables. It is our practice to place our cash equivalents and investments in high-quality securities with various investment institutions. We derive the majority of our revenues from sales and services, including engineering and construction, to the energy industry. Within the energy industry, trade receivables are generated from a broad and diverse group of customers. There are concentrations of receivables in the United States and the United Kingdom. We maintain an allowance for losses based upon the expected collectibility of all trade accounts receivable. There are no significant concentrations of credit risk with any individual counterparty related to our derivative contracts. We select counterparties based on their profitability, balance sheet and a capacity for timely payment of financial commitments which is unlikely to be adversely affected by foreseeable events. Interest rate risk. We have several debt instruments outstanding which have both fixed and variable interest rates. We manage our ratio of fixed to variable-rate debt through the use of different types of debt instruments and derivative instruments. Fair market value of financial instruments. The estimated fair market value of long-term debt at year-end 2001 was $1.3 billion and in 2000 was $1.1 billion as compared to the carrying amount of $1.5 billion at year-end 2001 and $1.1 billion at year-end 2000. 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 consolidated balance sheets approximates fair market value due to the short maturities of these instruments. The currency derivative instruments are carried on the balance sheet at fair value and are based upon third-party quotes. The fair market values of derivative instruments used for fair value hedging and cash flow hedging were immaterial. Note 17. Retirement Plans Our company and subsidiaries have various plans which cover a significant number of their employees. These plans include defined contribution plans, which provide retirement contributions in return for services rendered, provide an individual account for each participant and have terms that specify how contributions to the participant's account are to be determined rather than the amount of pension benefits the participant is to receive. Contributions to these 58 htttW/www ce*r omr/Arr'I'iivpc/pdcrnr/dtitii/ASni 9/000004*101 90900001 1 /edl 01-9001 fvt 8/91/9009 Page 64 of 89 <PAGE> 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 $129 million in 2001 compared to $140 million in 2000 and $111 million in 1999. 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. <TABLE> <CAPTION> 2001 Millions of dollars United States International <S> Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Plan participants' contributions Effect of business combinations Amendments Divestitures Settlements/curtailments Currency fluctuations Actuarial gain/(loss) Benefits paid <C> $ 288 2 13 - (Ill) (46) - 8 (14) <C> $ 1,670 60 89 14 - - (90) - 15 270 (60) Benefit obligation at end of year $ 140 $ 1,968 </TABLE> <TABLE> <CAPTION> 2001 Millions of dollars United States International <S> Change in plan assets Fair value of plan assets at beginning of year Actual return on plan assets Employer contribution Settlements Plan participants' contributions Divestitures Currency fluctuations Benefits paid <C> $ 313 (22) 7 (46) 1 (109) - (14) <C> $ 2,165 (294) 30 - 14 (45) 15 (58) Fair value of plan assets at end of year $ 130 $ 1,827 Funded status Unrecognized transition obligation/(asset) Unrecognized actuarial (gain)/loss Unrecognized prior service cost/(benefit) Net amount recognized $ (10) (1) 34 (2) $ 21 $ (141) (3) 308 (96) $ 68 /Aimm? ffni7/Arp1inwo/Ar1fTor/^oto//l^ni/)/nOrtOn/I^ni 000000^1 1 HVOOOI fvt Q/OI /ODOO Page 65 of 89 </TABLE> <PAGE> 59 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. <TABLE> <CAPTION> 2001 Millions of dollars United States International <S> Amounts recognized in the consolidated balance sheets Prepaid benefit cost Accrued benefit liability Intangible asset Deferred tax asset Accumulated other comprehensive income, net of tax <C> $7 (10) 1 8 15 <C> $ 85 (36) 1 6 12 Net amount recognized $ 21 $ 68 </TABLE> 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: <TABLE> <CAPTI0N> Weighted-average assumptions 2001 2000 1999 <S> Expected return on plan assets United States plans International plans Discount rate: United States plans International plans Rate of compensation increase: United States plans International plans </TABLE> <C> 9.0% 5.5% to 9.0% 7.25% 5.0% to 8.0% 4.5% 3.0% to 7.0% <C> 9.0% 3.5% to 9.0% 7.5% 4.0% to 8.0% 4.5% 3.0% to 7.6% <C> 9.0% 7.25% to 8.0% 7.5% 2.5% to 7.5% 4.5% to 5.0% 1.0% to 10.5% <TABLE> <CAPTI0N> 2001 2000 Millions of dollars United States International United States In <S> Components of net periodic benefit cost <C> <C> <C> <C hf+tW/www cf>r or>v/Arr*hiv(=c:/pdcTar/Hflt5)//lS019/nnnnn4S01 OnOOnrini 1 /pdl nV?Pini t-vt c/91 /onm Page 66 of 89 Service cost Interest cost Expected return on plan assets Transition amount Amortization of prior service cost Settlements/curtailments Recognized actuarial gain $2 13 (18) - (2) 16 (1) $ 60 89 (95) (2) (6) - (9) $4 20 (26) - (1) 10 - Net periodic benefit cost $ 10 $ 37 $7 </TABLE> The projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets as of December 31, 2001 and 2000 are as follows: <PAGE> 60 <TABLE> <CAPTION> Millions of dollars 2001 2000 <S> Projected benefit obligation Accumulated benefit obligation Fair value of plan assets <C> $ $ $ 235 215 175 <C> $ $ $ 172 154 82 </TABLE> Postretirement medical plan. We offer postretirement medical plans to specific eligible employees. For some plans, our liability is limited to a fixed contribution amount for each participant or dependent. The plan participants share the total cost for all benefits provided above our fixed contribution and participants' contributions are adjusted as required to cover benefit payments. We have made no commitment to adjust the amount of our contributions; therefore, the computed accumulated postretirement benefit obligation amount is not affected by the expected future health care cost inflation rate. Other postretirement medical plans are contributory but we generally absorb the majority of the costs. We may elect to adjust the amount of our contributions for these plans. As a result, the expected future health care cost inflation rate affects the accumulated postretirement benefit obligation amount. These plans have assumed health care trend rates (weighted based on the current year benefit obligation) for 2001 of 11% which are expected to decline to 5% by 2005. Obligations and expenses for postretirement medical plans in the following tables include both continuing and discontinued operations. <TABLE> <CAPTION> Millions of dollars 2001 2000 <S> Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Plan participants' contributions Acquisitions/divestitures, net Settlements/curtailments Actuarial gain Benefits paid <C> $ 296 2 15 12 - (144) 5 (29) <C> $ 392 3 20 11 (110) - 11 (31) Benefit obligation at end of year $ 157 $ 296 TrH'tv/Avww cpr amr/A mBh/pc/prl oror/dato/zl^ni 9/000004^01 90900001 1 /pr11 0V9001 tvt 8/91 /9009 Page 67 of 89 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 $17 12 (29) $- $20 11 (31) $ Funded status Employer contribution Unrecognized actuarial gain Unrecognized prior service cost $ (157) 2 (14) 3 $ (296) 3 (20) (78) Net amount recognized $ (166) $(391) </TABLE> <PAGE> 61 <TABLE> <CAPTION> Millions of dollars <s> Amounts recognized in the consolidated balance sheets Accrued benefit liability 2001 <C> ' $ (166) 2000 <C> $ (391) Net amount recognized </TABLE> $ (166) $ (391) <TABLE> <CAPTI0N> Weighted-average assumptions <S> Discount rate </TABLE> 2001 <C> 7.25% 2000 <C> 7.50% 1999 <C> 7.50% <TABLE> <CAPTI0N> Millions of dollars 2001 2000 1999 <S> Components of net periodic benefit cost Service cost Interest cost Amortization of prior service cost Settlement's/curtailments Recognized actuarial gain <C> $2 15 (3) (221) (1) <C> $3 20 (7) - (1) <C> $5 28 (9) (2) (5) Net periodic benefit cost </TABLE> $ (208) $ 15 $ 17 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: 1ittiv//nmnv ci=r orr>Tr/Arr,iii'\7(=>o/(dor!>r/r)oto/zl^ni 7/(3(30(3(34^(31 70700001 1 /e41 OV-7001 fvt 5/71/7007 Page 68 of 89 <TABLE> <CAPTION> One-Percentage-Point Millions of dollars Increase (Decrease) <S> Effect on total of service and interest cost components Effect on the postretirement benefit obligation <C> $ 1 $8 <C> $ (1) $ (7) </TABLE> Note 18. Dresser Industries, Inc. Financial Information Since becoming a wholly owned subsidiary. Dresser Industries, Inc. has ceased filing periodic reports with the United States Securities and Exchange Commission. Dresser Industries, Inc. 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 Industries, Inc. The majority of our operating assets and activities are included in Dresser Industries, Inc. and its subsidiaries. In August 2000, the United States 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. <PAGE> 62 <TABLE> <CAPTI0N> Condensed Consolidating Statements of Income Year ended December 31, 2001 Millions of dollars Non-issuer/ Non-guarantor Subsidiaries Dresser Industries, (Issuer) Inc. Hall Cc (Gua <S> Total revenues Cost of revenues General and administrative Interest expense Interest income Other, net <C> $ 13,046 11,575 387 (41) 25 (3) <C> $ 596 - - (43) 1 189 <C> $1 Income from continuing operations before taxes, minority interest and change in accounting method, net Benefit (provision) for income taxes Minority interest in net income of subsidiaries 1,065 (387) (19) 743 (17) 1 Income from continuing operations before change in accounting method, net Income (loss) from discontinued operations Cumulative effect of change in accounting method, net of tax benefit 659 (64) 1 726 321 1 Net income </TABLE> $ 596 $1,047 $1 lithv//www cec aov/Archivpc/edoar/dfltflM^OI 9/000004^01909000011 Ipi\ 1 0V9001 tvt S/91/9009 Page 69 of 89 <TABLE> <CAPTION> Condensed Consolidating Statements of Income Year ended December 31, 2000 Millions of dollars <s> 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 Benefit (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 </TABLE> <PAGE> 63 <TABLE> <CAPTION> Condensed Consolidating Statements of Income Year ended December 31, 1999 Millions of dollars <S> Total revenues Cost of revenues General and administrative Special credits Interest expense Interest income Other, net Income from continuing operations before taxes, minority interest, andchange in accounting method, net Benefit (provision) for income taxes Minority interest in net income of subsidiaries Income from continuing operations before change in accounting method, net Income from discontinued operations Gain on disposal of discontinued Non-issuer/ Non-guarantor Subsidiaries <C> $ 11,944 11,218 352 (88) (47) 21 2 438 (162) (18) 258 98 $ 356 Non-issuer/ Non-guarantor Subsidiaries <C> $ 12,313 11,608 351 (47) (50) 77 (29) 399 (91) (17) 291 124 Dresser Industries, (Issuer) Inc. Hall Cc (Gua <C> $ 356 _ - (45) 18 129 <C> $ 68 (6 5 458 7 66 2 465 215 $ 680 6S $ 69 Dresser Industries, (Issuer) Inc. Hall Cc (Gua <C> $ 555 _ - (50) 26 105 <C> $ 63 (7 18 636 1 - 75 (2 637 - 72 cpr rrm;/ Ar/'lii1i/Po/pHnrQr//lQtQMAni 9/0000/1/1401 OOOOOOOI 1 //=*/11 01/-0001 fvf 9/01 /OOOO Page 70 of 89 operations, net of tax Cumulative effect of change in accounting method, net of tax benefit Net income </TABLE> <PAGE> 64 <TABLE> <CAPTION> Condensed Consolidating Balance Sheets Year ended December 31, 2001 Millions of dollars <S> 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 Goodwill, net Insurance for asbestos litigation claims Other assets Total assets 159 (19) $ 555 Non-issuer/ Non-guarantor Subsidiaries <C> $ 213 3,002 1, 080 4,082 787 323 5,405 2,669 551 (1,089) - 636 612 793 $ 9,577 $ 637 $ 72 Dresser Industries, (Issuer) Inc. Hall Cc (Gua <C> <C> $ 13 $ 13 - 71 84 - - - 5,296 84 27 $ 5,491 2,8 3,1 Liabilities and Shareholders1 Current liabilities: Accounts and notes payable Other current liabilities Equity Total current liabilities Long-term debt Intercompany payable from consolidated affiliates Asbestos litigation claims Other liabilities Minority interest in consolidated subsidiaries Total liabilities Shareholders' equity: Common shares Other shareholders' equity $ 808 1,791 2,599 211 737 1, 016 41 4,604 175 4,798 $ 129 20 149 439 1,765 - 16 2,369 3,122 $i i 7 1,0 1,1 3,9 II II II II II II </> II II <T> II O Vittrx*//xxnxrxxr opp fTA'tr/Arp1in^Po/pHoQr//1ai-QM^ni 7/000004^01 00700001 1 /pHI nVOOOl fvt e/oi nnm Page 71 of 89 II II II I! II II II II II II II II II II II II II II II II II II II II II 11 II II II II II II II II II II II 11 II II II II II II li II II II II II II II II Total shareholders' equity Total liabilities and shareholders' equity $ 4,973 9,577 </TABLE> <PAGE> 65 <TABLE> <CAPTI0N> Condensed Consolidating Balance Sheets Year ended December 31, 2000 Millions of dollars <S> 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 Goodwill, net Insurance for asbestos litigation claims Other assets Total assets Non-issuer/ Non-guarantor Subsidiaries <C> $ 227 2,889 982 3,871 723 753 5,574 2,410 258 66 510 51 1,058 $ 9,927 II II II II II II II II II II II II II II 11 II II II II II II II II II II II II II u II 3,122 $ 5,491 5,0 $ 6,0 Dresser Industries, (Issuer) Inc. Hall Cc (Gua <C> <C> $ 63 $ 63 1 64 -- 142 6,558 87 5 $ 6,856 2,1 4,2 $ 6,3 Liabilities and Shareholders1 Current liabilities: Accounts and notes payable Other current liabilities Equity Total current liabilities Long-term debt Intercompany payable from consolidated affiliates Asbestos litigation claims Other liabilities Minority interest in consolidated subsidiaries Total liabilities Shareholders' equity: Common shares Other shareholders1 equity Total shareholders' equity $ 767 1,463 2,230 205 80 1,038 38 3,591 391 5,945 6,336 $ 53 36 89 444 2,206 - 26 2,765 4,091 4,091 $ 1,5 1,5 4 1 2,1 1,1 3,1 4,2 liffn'/Anmm; cpr* (tAv/Ar^i'trPo/p^fror/HQtQM^niO/nnnnn^^ni 90900001 1 /pHI 01^00/11 tvt 9/oi /onno Page 72 of 89 Total liabilities and shareholders' equity $ 9,927 </TABLE> <PAGE> 66 <TABLE> <CAPTI0N> Condensed Consolidating Statements of Cash Flows Year ended December 31, 2001 Millions of dollars Non-issuer/ Non-guarantor Subsidiaries <S> 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 <C> $ 1,021 (797) 120 (281) (8) (15) - (87) (20) Increase (decrease) in cash and equivalents $ (67) </TABLE> $ 6,856 $ 6,3 Dresser Industries, (Issuer) Inc. Hall Cc (Gua <C> $ (28) - (5) <C> $ 3 1,29 42 (1,177) ~ (1,51 (21 2 (3 5 1,263 $ 53 $7 <TABLE> <CAPTION> Condensed Consolidating Statements of Cash Flows Year ended December 31, 2000 Millions of dollars <S> 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 Non-issuer/ Non-guarantor Subsidiaries <C> $ (268) (578) 209 (42) (8) 17 - (235) (9) 826 $ (88) Dresser Industries, (Issuer) Inc. Hall Cc (Gua <C> $ 113 - <C> $ 5 (300) 7 - 143 " 61 (22 10 (76 - $ (44) $ (10 TiHn'//nmmr cap crrwrl A 7V'Li,iroe/*a*'1rraf//^o+o//1 7 700000/1 ^lOI 00000001 1 /o/11 /llOnAI -f-v+ Q/O 1 /OAAO Page 73 of 89 </TABLE> <PAGE> 67 <TABLE> <CAPTION> Condensed Consolidating Statements of Cash Flows Year ended December 31, 1999 Millions of dollars <S> 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 </TABLE> <PAGE> 68 Non-issuer/ Non-guarantor Subsidiaries <C> $ (219) (520) 118 295 (9) (27) - 297 5 234 $ 174 Dresser Industries, (Issuer) Inc. Hall Cc (Gua <C> $ 52 - <C> $ 10 (24 ' (5 (55) " 46 (22 4 (1 $ (3) $5 <TABLE> <CAPTION> Halliburton Company Selected Financial Data (Unaudited) Millions of dollars and shares except per share and employee data <s> 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 (l) Years en ------------------------------------------------------------------------------------------ 2001 2000 1 <C> <C> <C> $ 8,722 4,324 $ 13,046 $ 6,776 5,168 $ 11,944 $ $ $ 1,015 143 (74) 1,084 $ 582 (42) (78) 462 $ httrv/Axrorw opp cmv/Arp1*nvpc/pr1cT5*r/d9taAl^ni 7/000004*101 70700001 1 /pdlOlrOflfH fvt C/01 /0000 Page 74 of 89 Nonoperating income (expense), net (2) (130) (127) Income from continuing operations before income taxes and minority interest Provision for income taxes (3) Minority interest in net income of consolidated subsidiaries 954 (384) (19) 335 (129) (18) Income (loss) from continuing operations $ 551 $ 188 $ Income from discontinued operations $ 257 $ 313 $ Net income (loss) $ 809 $ 501 $ 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 $ 1.29 1.89 1.28 1.88 0.50 18.64% $ 0.42 1.13 0.42 1.12 0.50 12.20% $ 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) $ 2,665 10,966 2,669 1,484 4,752 6,280 10.95 428 430 $ 1,742 10,192 2,410 1, 057 3,928 6,555 9.20 442 446 $ Other financial data Capital expenditures Long-term borrowings (repayments), net Depreciation, depletion and amortization expense Goodwill amortization included in depreciation. depletion and amortization expense: Energy Services Group Engineering and Construction Group Payroll and employee benefits (4) Number of employees (4), (5) $ (797) 412 531 27 15 (4,818) 85,000 $ (578) (308) 503 $ 22 22 (5,260) 93,000 1 (continued on next page) </TABLE> <PAGE> 69 <TABLE> <CAPTION> Halliburton Company Selected Financial Data (Unaudited) (continued) Millions of dollara and shares except per share and employee data Years en --------------------------------------------------------------------------------------------- 1996 1995 <S> Operating results <C> <C> <C> httrv//www q<?r, anv/Archivpq/prlonr/rlatfl/d'ifn 9/000004^01 909000011 /pH 1 0V9001 tvt 8/91 /9fin9 Page 75 of 89 II II II II II 11 11 II II II II it II II II II 11 11 II II II II II II 11 II II II 11 II II II II II II II II II II II II II II 11 II II II II II Net revenues Energy Services Engineering and Group 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) $ 5,936 5,300 $ 4,902 4,143 $ $ 11,236 $ 9,045 $ = = = = = ========= = = = = = ======== ======= $ 654 $ 553 $ 178 88 (86) (8) (72) (71) 674 (70) 562 (34) Income from continuing operations before income taxes and minority interest Provision for income taxes (3) Minority interest in net income of consolidated subsidiaries Income (loss) from continuing operations 604 (158) 528 (167) (1) $ 446 $ 360 $ Income from discontinued operations $ 112 $ 36 $ Net income (loss) $ 558 $ 381 $ 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 $ 1.04 1.30 1.03 1.29 0.50 15.25% $ 0.83 0.88 0.83 0.88 0.50 10.44% $ 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) $ 1,501 8,689 2,047 957 3,741 4,828 8.78 429 432 $ 1,477 7,723 1,865 667 3,577 4,378 8.29 431 432 $ Other financial data Capital expenditures Long-term borrowings (repayments), net Depreciation, depletion and amortization expense Goodwill amortization included in depreciation. depletion and amortization expense: Energy Services Group Engineering and Construction Group Payroll and employee benefits (4) Number of employees (4), (5) $ (612) 286 405 19 7 (4,674) 93,000 $ (474) (481) 380 17 7 (4,188) 89,800 $ (continued on next page) <PAGE> 70 Halliburton Company Trfftv/AxmTW opo ornv/Arf''hiv#>a/pr1ornr/Hnta/4^m 9/000004501 70700001 1 IpA 1 OVOOni tvt c/oi /onno Page 76 of 89 Selected Financial Data (Unaudited) (continued) <FN> (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 assets and of assets million). million: merger costs ($9 million), write-downs on impaired early retirement incentives ($10 million), losses from the sale ($12 million), and gain on extension of joint venture ($42 1996 - $86 million: merger costs ($13 million), restructuring, severance costs ($62 million), and write-off of acquired research and development costs ($11 million). merger and in-process 1995 - $8 million: restructuring costs ($5 million) and write-off acquired in-process research and development costs ($3 million). of 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 severance ($21 million). ($273 million) and restructuring and (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 discontinued operations for the years 1992 through 2000. accounted for as (5) Does not include employees of 50% or less owned affiliated companies. </FN> </TABLE> <TABLE> <CAPTI0N> HALLIBURTON COMPANY Quarterly Data and Market Price Information (Unaudited) Millions of dollars except per share data <S> First <C> Quar Second <C> Btfrv/Axmnxr c&r' crmr/ AtV'T'iii/Ac/pdcrsir/dataAd^ni 9/000004*101 90900001 1 l(*c11 0V9001 f-vf 8/91/9009 Page 77 of 89 2001 Revenues Operating income Income from continuing operations before change in accounting method, net Income (loss) from discontinued operations Gain on disposal of discontinued operations Cumulative effect of accounting change Net income Earnings per share: Basic income (loss) per common share: Income from continuing operations Income (loss) from discontinued operations Gain on disposal of discontinued operations Net income Diluted income (loss) per common share: Income from continuing operations Income (loss) from discontinued operations Gain on disposal of discontinued operations Net income Cash dividends paid per share Common stock prices (2) High Low 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 (continued on next page) <PAGE> 72 $ 3,144 198 86 22 1 109 0.20 0.05 0.25 0.20 0.05 0.25 0.125 45.91 34.81 $ 2,859 81 27 22 215 264 0.06 0.05 0.49 0.60 0.06 0.05 0.48 0.59 0.125 45.50 33.44 $ 3,339 272 143 (60) 299 382 0.34 (0.14) 0.70 0.90 0.33 (0.14) 0.70 0.89 0.125 49.25 32.20 $ 2,868 126 52 23 75 0.12 0.05 0.17 0.12 0.05 0.17 0.125 52.25 37.50 HALLIBURTON COMPANY Quarterly Data and Market Price (Unaudited) (continued) Information <FN> (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. httrv//www cpf cww/Arr'liivpc/prloar/dntn/A^ni 9/000004^01709000011/pr)1DV9001 tvt 9/71/9009 Page 78 of 89 (2) New York price . </FN> </TABLE> Stock Exchange - composite transactions high and low intraday- <PAGE> 73 PART III Item 10. Directors and Executive Officers of Registrant. The information required for the directors of the Registrant is incorporated by reference to the Halliburton Company Proxy Statement dated March 19, 2002, under the caption "Election of Directors." The information required for the executive officers of the Registrant is included under Part I on pages 9 and 10 of this annual report. Item 11. Executive Compensation. This information is incorporated by reference to the Halliburton Company Proxy Statement dated March 19, 2002, under the captions "Compensation Committee Report on Executive Compensation," "Comparison of Cumulative Total Return," "Summary Compensation Table," "Option Grants For Fiscal 2001," "Aggregated Option Exercises in Fiscal 2001 and December 31, 2001 Option Values," "Employment Contracts and Change-in-Control Arrangements" and "Directors' Compensation." Item 12(a). Security Ownership of Certain Beneficial Owners and Management. This information is incorporated by reference to the Halliburton Company Proxy Statement dated March 19, 2002, under the caption "Stock Ownership of Certain Beneficial Owners and Management." Item 12(b). Security Ownership of Management. This information is incorporated by reference to the Halliburton Company Proxy Statement dated March 19, 2002, under the caption "Stock Ownership of Certain Beneficial Owners and Management." Item 12(c). Changes in Control. Not applicable. Item 13. Certain Relationships and Related Transactions. This information is incorporated by reference to the Halliburton Company Proxy Statement dated March 19, 2002, under the caption "Certain Relationships and Related Transactions." <PAGE> 74 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K. (a) 1. Financial Statements: The report of Arthur Andersen LLP, Independent Public Accountants, and the financial statements of the Company as required by Part II, Item 8, are included on pages 28 through 68 and pages 72 and 73 of this annual report. See index on page 12. 2. Financial Statement Schedules: Page No. Report on supplemental schedule of Arthur Andersen LLP 83 Schedule II - Valuation and qualifying accounts for the three years ended December 31,2001 84 httri'/Axmmr crrwr/ A m'hixrf^c/fxAcrQr/A^t^/A^O't 7/000004*101 70700001 1/*v11 OP'OOOI tvt s/oi /oooo Page 79 of 89 Note: All schedules not filed with this report required by Regulation S-X have been omitted as not applicable or not required or the information required has been included in the notes to financial statements. 3. Exhibits: Exhibit Number Exhibits 3.1 3.2 4.1 4.2 4.3 4.4 <PAGE> 4.5 Restated Certificate of Incorporation of Halliburton Company filed with the Secretary of State of Delaware on July 23, 1998 (incorporated by reference to Exhibit 3(a) to Halliburton's Form 10-Q for the quarter ended June 30, 1998). By-laws of Halliburton revised effective May 16, 2000 (incorporated by reference to Exhibit 3 to Halliburton's Form 10-Q for the quarter ended June 30, 2000). Form of debt security of 8.75% Debentures due February 12, 2021 (incorporated by reference to Exhibit 4(a) to the Predecessor's Form 8-K dated as of February 20, 1991). Senior Indenture dated as of January 2, 1991 between the Predecessor and Texas Commerce Bank National Association, as trustee (incorporated by reference to Exhibit 4(b) to the Predecessor's Registration Statement on Form S-3 (File No. 33-38394) originally filed with the Securities and Exchange Commission on December 21, 1990), as supplemented and amended by the First Supplemental Indenture dated as of December 12, 1996 among the Predecessor, Halliburton and the Trustee (incorporated by reference to Exhibit 4.1 of Halliburton's Registration Statement on Form 8-B dated December 12, 1996, File No. 1-03492). Resolutions of the Predecessor's Board of Directors adopted at a meeting held on February 11, 1991 and of the special pricing committee of the Board of Directors of the predecessor adopted at a meeting held on February 11, 1991 and the special pricing committee's consent in lieu of meeting dated February 12, 1991 (incorporated by reference to Exhibit 4(c) to the Predecessor's Form 8-K dated as of February 20, 1991). Form of debt security of 6.75% Notes due February 1, 2027 (incorporated by reference to Exhibit 4.1 to Halliburton's Form 8-K dated as of February 11, 1997). 75 Second Senior Indenture dated as of December 1, 1996 between the Predecessor and Texas Commerce Bank National Association, as Trustee, as supplemented and amended by the First Supplemental Indenture dated as of December 5, 1996 between the Predecessor and the Trustee and the Second Supplemental Indenture dated as of December 12, 1996 among the Predecessor, Halliburton and the Trustee (incorporated by reference to Exhibit 4.2 of Halliburton's Registration Statement on Form 8-B dated December 12, 1996, File NO. 1-03492) . liftn'/Ainimr 0/000004^01 90000^01 1 /p/^inVOfiOl tvt 8/iirtnm 4.6 4.7 4.8 4.9 4.10 4.11 4.12 4.13 4.14 <PAGE> 4.15 Page 80 of 89 Third Supplemental Indenture dated as of August 1, 1997 between Halliburton and Texas Commerce Bank National Association, as Trustee, to the Second Senior Indenture dated as of December 1, 1996 (incorporated by reference to Exhibit 4.7 to Halliburton's Form 10-K for the year ended December 31, 1998). Fourth Supplemental Indenture dated as of September 29, 1998 between Halliburton and Chase Bank of Texas, National Association (formerly Texas Commerce Bank National Association), as Trustee, to the Second Senior Indenture dated as of December 1, 1996 (incorporated by reference to Exhibit 4.8 to Halliburton's Form 10-K for the year ended December 31, 1998). Resolutions of Halliburton's Board of Directors adopted by unanimous consent dated December 5, 1996 (incorporated by reference to Exhibit 4(g) of Halliburton's Form 10-K for the year ended December 31, 1996). Resolutions of Halliburton's Board of Directors adopted at a special meeting held on September 28, 1998 (incorporated by reference to Exhibit 4.10 to Halliburton's Form 10-K for the year ended December 31, 1998). Restated Rights Agreement dated as of December 1, 1996 between Halliburton and Mellon Investor Services LLC (formerly ChaseMellon Shareholder Services, L.L.C.) (incorporated by reference to Exhibit 4.4 of the Company's Registration Statement on Form 8-B dated December 12, 1996, File No. 1-03492). Copies of instruments that define the rights of holders of miscellaneous long-term notes of Halliburton and its subsidiaries, totaling $17 million in the aggregate at December 31, 2001, have not been filed with the Commission. Halliburton agrees to furnish copies of these instruments upon request. Form of debt security of 7.53% Notes due May 12, 2017 (incorporated by reference to Exhibit 4.4 to Halliburton's Form 10-Q for the quarter ended March 31, 1997). Form of debt security of 6.30% Notes due August 5, 2002 (incorporated by reference to Exhibit 4.1 to Halliburton's Form 8-K dated as of August 5, 1997) . Form of debt security of 5.63% Notes due December 1, 2008 (incorporated by reference to Exhibit 4.1 to Halliburton's Form 8-K dated as of November 24, 1998). 76 Form of Indenture, between Baroid Corporation and Texas Commerce Bank National Association, as Trustee, for 8% Senior Notes due 2003 (incorporated by reference to Exhibit 4.01 to the Registration Statement on Form S-3 filed by Baroid Corporation, Registration No. 33-60174), as supplemented and amended by Form of Supplemental Indenture, between Dresser, Baroid Corporation and Texas Commerce Bank N.A. as Trustee, for 8% Guaranteed Senior Notes due 2003 (incorporated by reference to Exhibit 4.3 to Registration Statement on Form S-4 filed by Baroid fiftrs*JhTTVKrw ef=>r* rrmrf&Tr`\*wt*eJ(:>f:\ci`>vlA*z+cilA^C\'\ 9/00/1004^01 00900001 1 /orllOV-9001 +*vf ??/oi /oooo 4.16 4.17 4.18 4.19 4.20 10.1 10.2 10.3 10.4 10.5 10.6 Page 81 of 89 Corporation, Registration No. 33-53077). Second Supplemental Indenture dated October 30, 1997 between Dresser and Texas Commerce Bank National Association, as Trustee, for 8% Senior Notes due 2003 (incorporated by reference to Exhibit 4.19 to Halliburton's Form 10-K for the year ended December 31, 1998). Third Supplemental Indenture dated September 29, 1998 between Dresser, Halliburton, as Guarantor, and Chase Bank of Texas, National Association, as Trustee, for 8% Senior Notes due 2003 (incorporated by reference to Exhibit 4.20 to Halliburton's Form 10-K for the year ended December 31, 1998). Form of Indenture, between Dresser and Texas Commerce Bank National Association, as Trustee, for 7.60% Debentures due 2096 (incorporated by reference to Exhibit 4 to the Registration Statement on Form S-3 as amended, Registration No. 333-01303), as supplemented and amended by Form of Supplemental Indenture, between Dresser and Texas Commerce Bank National Association, Trustee, for 7.60% Debentures due 2096 (incorporated by reference to Exhibit 4.1 to Dresser's Form 8-K filed on August 9, 1996). Form of debt security of floating rate Notes due July 16, 2003 (incorporated by reference to Exhibit 4.1 to Halliburton's Form 8-K dated January 8, 2002). Form of debt security of 6% Notes due August 1, 2006 (incorporated by reference to Exhibit 4.2 to Halliburton's Form 8-K dated January 8, 2002). Halliburton Company Career Executive Incentive Stock Plan as amended November 15, 1990 (incorporated by reference to Exhibit 10(a) to the Predecessor's Form 10-K for the year ended December 31, 1992). Retirement Plan for the Directors of Halliburton Company, as amended and restated effective May 16, 2000 (incorporated by reference to Exhibit 10.2 to Halliburton's Form 10-Q for the quarter ended September 30, 2000). Halliburton Company Directors' Deferred Compensation Plan as amended and restated effective February 1, 2001 (incorporated by referenceto Exhibit 10.3 to Halliburton's Form 2000). 10-K for the year ended December 31, Halliburton Company 1993 Stock and Long-Term Incentive Plan, as amended and restated effective May 16, 2000 (incorporated by reference to Exhibit 10.3 to Halliburton's 2000) . Form 10-Q for the quarter ended June 30, Halliburton Company Restricted Stock Plan for Non-Employee Directors (incorporated by reference to Appendix B of the Predecessor's proxy statement dated March 23, 1993). Employment agreement (incorporated by reference to Exhibit 10(n) to the Predecessor's Form 10-K for the year ended hftn`//www cfr* CTnv/Atr'Titvpo/pdonr/dpta/J^ni '?/fifif)f)OA^f)l 90700001 1 /10V9D01 tvt 8/71 nnm <PAGE> 10.7 10.8 10.9 10.10 10.11 10.12 10.13 10.14 10.15 10.16 10.17 10.18 Page 82 of 89 December 31, 1995). 77 Employment agreement (incorporated by reference to Exhibit 10.16 to Halliburton's Form 10-K for the year ended December 31, 1998). Employment agreement (incorporated by reference to Exhibit 10.19 to Halliburton's Form 10-K for the year ended December 31, 1998). Dresser Industries, Inc. Deferred Compensation Plan, as amended and restated effective January 1, 2000 (incorporated by reference to Exhibit 10.16 to Halliburton's Form 10-K for the year ended December 31, 2000). Dresser Industries, Inc. 1982 Stock Option Plan (incorporated by reference to Exhibit A to Dresser's Proxy Statement dated February 12, 1982, filed pursuant to Regulation 14A, File No. 1-4003). ERISA Excess Benefit Plan for Dresser Industries, Inc., as amended and restated effective June 1, 1995 (incorporated by reference to Exhibit 10.7 to Dresser's Form 10-K for the year ended October 31, 1995). ERISA Compensation Limit Benefit Plan for Dresser Industries, Inc., as amended and restated effective June 1, 1995 (incorporated by reference to Exhibit 10.8 to Dresser's Form 10-K for the year ended October 31, 1995). Supplemental Executive Retirement Plan of Dresser Industries, Inc., as amended and restated effective January 1, 1998 (incorporated by reference to Exhibit 10.9 to Dresser's Form 10-K for the year ended October 31, 1997) . Stock Based Compensation Arrangement of Non-Employee Directors (incorporated by reference to Exhibit 4.4 to Dresser's Registration Statement on Form S-8, Registration No. 333-40829). Dresser Industries, Inc. Deferred Compensation Plan for Non-employee Directors, as restated and amended effective November 1, 1997 (incorporated by reference to Exhibit 4.5 to Dresser's Registration Statement on Form S-8, Registration No. 333-40829). Long-Term Performance Plan for Selected Employees of The M. W. Kellogg Company, as amended and restated effective September 1, 1999 (incorporated by reference to Exhibit 10.23 to Halliburton's Form 10-K for the year ended December 31, 2000) . Dresser Industries, Inc. 1992 Stock Compensation Plan (incorporated by reference to Exhibit A to Dresser's Proxy Statement dated February 7, 1992, filed pursuant to Regulation 14A, File No. 1-4003) . Amendments No. 1 and 2 to Dresser Industries, Inc. 1992 Stock Compensation Plan (incorporated by reference to opp At*plitTfpc/p^rtor//^ofo/^^ni 0/00000/1^0100000001 1 /pHI OVOOni fvf Q/oi /onno Page 83 of 89 10.19 <PAGE> 10.20 10.21 10.22 10.23 10.24 10.25 10.26 10.27 10.28 10.29 10.30 Exhibit A to Dresser's Proxy Statement dated February 6, 1995, filed pursuant to Regulation 14A, File No. 1-4003). Amendment No. 3 to the Dresser Industries, Inc. 1992 Stock Compensation Plan (incorporated by reference to Exhibit 10.25 to Dresser's Form 10-K for the year ended October 31, 1997) . 78 Amendment No. 1 to the Supplemental Executive Retirement Plan of Dresser Industries, Inc. (incorporated by reference to Exhibit 10.1 to Dresser's Form 10-Q for the quarter ended April 30, 1998). Employment agreement (incorporated by reference to Exhibit 10.2 to Halliburton's Form 10-Q for the quarter ended June 30, 2000) . Employment agreement (incorporated by reference to Exhibit 10.1 to Halliburton's Form 10-Q for the quarter ended September 30, 2000) . Form of Nonstatutory Stock Option Agreement for Non-Employee Directors (incorporated by reference to Exhibit 10.3 to Halliburton's Form 10-Q for the quarter ended September 30, 2000). Employment agreement (incorporated by reference to Exhibit 10.39 to Halliburton's Form 10-K for the year ended December 31, 2000). Agreement and Plan of Recapitalization, as amended and restated effective April 10, 2001 (incorporated by reference to Halliburton's Form 8-K/A dated as of May 10, 2001). Halliburton Company Supplemental Executive Retirement Plan (formerly part of Halliburton Company Senior Executives' Deferred Compensation Plan), as amended and restated effective January 1, 2001 (incorporated by reference to Exhibit 10.1 to Halliburton's Form 10-Q for the quarter ended June 30, 2001) . Halliburton Company Benefit Restoration Plan (formerly part of Halliburton Company Senior Executives' Deferred Compensation Plan), as amended and restated effective January 1, 2001 (incorporated by reference to Exhibit 10.2 to Halliburton's Form 10-Q for the quarter ended June 30, 2001). Employment agreement (incorporated by reference to Exhibit 10.3 to Halliburton's Form 10-Q for the quarter ended June 30, 2001). Halliburton Annual Performance Pay Plan, as amended and restated effective January 1, 2001 (incorporated by reference to Exhibit 10.1 to Halliburton's Form 10-Q for the quarter ended September 30, 2001). Halliburton Company Performance Unit Program (incorporated by reference to Exhibit 10.2 to Halliburton's Form 10-Q for the quarter ended September 30, 2001). Tiftrv//www qpp onv/Arrhivec/prlonr/rlntn/A^ni 9/000004^0190900001 1 !pc\ 1 0V9001 tvt R/91/9009 Page 84 of 89 10.31 Halliburton Elective Deferral Plan, as amended and restated effective January 1, 2002 (incorporated by reference to Exhibit 4.1 to Halliburton's Registration Statement on Form S-8, Registration No. 333-73046 filed November 9, 2001). * 10.32 * 10.33 * 21 * 23 <PAGE> 24.1 Employment agreement. Employment agreement. Subsidiaries of the Registrant. Consent of Arthur Andersen LLP. 79 Powers of attorney for the following directors signed in February, 1997 (incorporated by reference to Exhibit 24 to Halliburton's Form 10-K for the year ended December 31, 1996): 24.2 24.3 Lord Clitheroe Robert L. Crandall W. R. Howell C. J. Silas Power of attorney signed in December, 1997 for Charles J. DiBona (incorporated by reference to Exhibit 24(b) to Halliburton's Form 10-K for the year ended December 31, 1997). Powers of attorney for the following directors signed in October, 1998 (incorporated by reference to Exhibit 24.3 to Halliburton's Form 10-K for the year ended December 31, 1998): 24.4 Lawrence S. Eagleburger Ray L. Hunt J. Landis Martin Jay A. Precourt Powers of attorney for the following directors signed in May, 2001 (incorporated by reference to Exhibit 24.1 to Halliburton's Form 10-Q for the quarter ended June 30, 2001): Kenneth T. Derr Aylwin B. Lewis Debra L. Reed 24.5 * Powers of attorney for Douglas L. Foshee, Robert R. Harl and Edgar J. Ortiz (incorporated by reference to Exhibit 24.2 to Halliburton's Form 10-Q for the quarter ended June 30, 2001). Filed with this Form 10-K. (b) Reports on Form 8-K: <TABLE> <CAPTION> Date of httr>`//www ser crnv/Arrhivps/pdcrar/rlata/A^OI 9/000004^01909000011 /pH 10V9f)01 tvt 8/91 nc\co Page 85 of 89 Date Filed Earliest Event <S> <C> During the fourth quarter of 2001: October 19, 2001 October 18, 2001 October 26, 2001 <PAGE> Date Filed October 23, 2001 80 Date of Earliest Event Description of Event <C> Item 5. Other Events for a press re of a letter of intent to combine Ha Subsea ASA. Item 5. Other Events for a press re quarter earnings. Description of Event During the fourth quarter of 2001 (continued): October 30, 2001 October 26, 2001 Item 5. Other Events for a press re Directors declared a 2001 fourth qu share payable December 20, 2001 to close of business on November 29, 2 November 6, 2001 November 1, 2001 Item 5. Other Events for a press re Halliburton KBR, formerly Kellogg E Consultants AB from British Maritirr undisclosed amount. November 7, 2001 October 30, 2001 Item 5. Other Events for a press re dispute of asbestos claims relating trial. November 27, 2001 November 21, 2001 Item 5. Other Events for a press re acquisition of Magic Earth, Inc., a interpretation technology company. December 4, 2001 November 29, 2001 Item 5. Other Events for a press r against Halliburton's subsidiary, E involving asbestos claims and Halli December 7, 2001 December 5, 2001 Item 5. Other Events for a press re verdicts against Halliburton's subs Inc., involving asbestos claims. December 11, 2001 December 7, 2001 Item 5. Other Events for a press re conference by Halliburton's manageir litigation. December 12, 2001 December 20, 2001 December 11, 2001 December in, 2001 Item 5. Other Events for a press re maintains Standard & Poor' s Investtr Item 5. Other Events for a press re Halliburton KBR Government Operatic the U.S. Army Logistics Civil Augme contract. <PAGE> Date of 81 httrv/Axnvw cpp oYw/ArY'hivpc/pHcyjir/datpMAni 9/000004^01 909000011 /pHI 0V9001 tvt R/91 /9009 Date Filed Earliest Event During the first quarter of 2002: January 4, 2002 January 4, 2002 January 8, 2002 July 16, 2001 January 28, 2002 January 28, 2002 February 1, 2002 February 13, 2002 February 15, 2002 January 23, 2002 January 23, 2002 January 30, 2002 February 7, 2002 February 13, 2002 February 15, 2002 February 27, 2002 </TABLE> February 14, 2002 February 22, 2002 Page 86 of 89 Description of Event Item 5. Other Events for a press re Item 5. Other Events for a press re the $275 million fixed-rate note du million of floating notes due July Item 5. Other Events for a press re quarter earnings. Item 5. Other Events for a press re Investors' Services continued credi Item 5. Other Events for a press re ratings reaffirmed by Standard & Pc Item 5. Other Events for a press re Brown & Root, Inc. settled Qui Tam Item 5. Other Events for a press re Directors declared a 2002 first qua share payable March 21, 2002 to sha close of business on February 28, 2 shareholders was set for May 15, 20 Item 5. Other Events for a press re Bankruptcy Court has issued a tempc certain pending asbestos claims. Item 5. Other Events for a press re Bankruptcy Court restraining order asbestos claims has extended the ti April 4, 2002. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SUPPLEMENTAL SCHEDULE To the Shareholders and Board of Directors Halliburton Company: We have audited in accordance with auditing standards generally accepted in the United States of America, the consolidated financial statements included in this Form 10-K, and have issued our report thereon dated January 23, 2002. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The supplemental schedule (Schedule II) is the responsibility of Halliburton Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic financial statements taken as a whole. L+tn'/Aimrar oe*n crmr/ A-rAhi'w^eAadrrcir/dQtaM^ni 7/fW3nfW34A01 00000001 1 AadinirOOfll fvt 5/01 nr\r\o Page 87 of 89 /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Dallas, Texas, January 23, 2002 (Except with respect to certain matters discussed in Note 9, as to which the date is February 21, 2002.) <TABLE> <CAPTION> HALLIBURTON COMPANY Schedule II - Valuation and Qualifying Accounts (Millions of Dollars) The table below presents operations. valuation and qualifying accounts for continuing Additic Descriptions <s> Year ended December 31, 1999: Deducted from accounts and notes receivable: Allowance for bad debts Balance at Beginning of Period <C> $ 66 </> A O V Charged to Costs and Expenses 49 Reserve for repairs and maintenance $ 14 $4 Accrued special charges $ 357 $- Year ended December 31, 2000: Deducted from accounts and notes receivable: Allowance for bad debts Reserve for repairs and maintenance Accrued special charges Accrued reorganization charges $ 94 $ 15 $ 69 $ $ 39 $4 $- $ 36 ii i ij i ii ii ii i ii Year ended December 31, 2001: Deducted from accounts and notes receivable: Allowance for bad debts Reserve for repairs and maintenance Accrued special charges Accrued reorganization charges $ 125 $ 14 $6 $ 16 $ 70 $4 $$- <FN> (a) Receivable write-offs and reclassifications, net of recoveries. (b) Includes $47 million reversal of special charges taken in 1998 and $14 milli to employee compensation and benefits in 1999. (c) Includes $9 million for items of a long-term nature reclassified to other li (d) Includes $4 million estimate to actual adjustment. </FN> </TABLE> tifffi'/Ainjnx/ cpo crfwif ArrQt*/dofo!A401 7IC\C\C\C\f\A401 7070DDD1 1 /a/^1 AVOnOI +vf o/oi /onno Page 88 of 89 <PAGE> 84 SIGNATURES As required by Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has authorized this report to be signed on its behalf by the undersigned authorized individuals, on this day of March, 2002. HALLIBURTON COMPANY By /s/ David J. Lesar David J. Lesar Chairman of the Board, President and Chief Executive Officer As required by the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities indicated on this day of March, 2002. Signature Title /s/ David J. Lesar David J. Lesar Chairman of the Board, President and Chief Executive Officer /s/ Douglas L. Foshee Douglas L. Foshee Executive Vice President and Chief Financial Officer /s/ R. Charles Muchmore, Jr. R. Charles Muchmore, Jr. <PAGE> Signature * LORD CLITHEROE Lord Clitheroe ROBERT L. CRANDALL Robert L. Crandall * KENNETH T. DERR Vice President and Controller and Principal Accounting Officer Director Director Director //wnjnw t?pn crrwjt Arp^iiTrAo/p/lfTOr/HotoM^OI 0/000004 *01 90900001 1 l&A 1 0V9001 tvt 8 /91 /9O09 Kenneth T. Derr * CHARLES J. DIBONA Charles J. DiBona * LAWRENCE S. EAGLEBURGER Lawrence S. Eagleburger * W. R. HOWELL W. R. Howell * RAY L. HUNT Ray L. Hunt * AYLWIN B. LEWIS Aylwin B. Lewis * J. LANDIS MARTIN J. Landis Martin * JAY A. PRECOURT Jay A. Precourt * DEBRA L. REED Debra L. Reed * C. J. SILAS C. J. Silas * /s/ SUSAN S. KEITH Susan S. Keith, Attorney-in-fact 86 </TEXT> </DOCUMENT> Page 89 of 89 Director Director Director Director Director Director Director Director Director htfTv//www cpc crnWAonr/zialW/d.^OI 9/00000AS01900000011 !e>r110L9001 tvt C/91 /9009