LOOKING BEYOND 2004 2 0 0 4 A n n u a l R e p o r t COMPARATIVE HIGHLIGHTS Millions of dollars and shares, except per share data Revenue Operating income (loss) Income (loss) from continuing operations before change in accounting principle Net loss Diluted income (loss) per share from continuing operations before change in accounting principle Diluted net loss per share Cash dividends per share Diluted weighted average common shares outstanding Working capital1 Long-term debt (including current maturities) Debt to total capitalization2 Capital expenditures Depreciation, depletion, and amortization 2004 2003 2002 $20,466 $16,271 $12,572 837 720 (112) 385 (979) 0.87 (2.22) 0.50 441 2,898 3,940 339 (820) 0.78 (1.88) 0.50 437 1,355 3,437 (346) (998) (0.80) (2.31) 0.50 432 2,288 1,476 50.1% 57.6% 30.0% 575 509 515 518 764 505 1Calculated as current assets minus current liabilities. Current assets included the current portion of our insurance for asbestos- and silica-related liabilities of $1,066 million and $96 million in 2004 and 2003, respectively. Current liabilities included the current portion of the asbestos- and silica-related liabilities of $2,408 and $2,507 in 2004 and 2003, respectively. 2Calculated as total debt divided by total debt plus shareholders’ equity. HALLIBURTON Founded in 1919, Halliburton is one of the world’s largest providers of global energy solutions, engineering and construction services, infrastructure and other government services. With approximately 100,000 people working in over 100 countries, Halliburton delivers unparalleled resources, capabilities and experience through two major operating units: The Energy Services Group (ESG) offers the broadest support to the upstream petroleum industry worldwide. Its services span the entire life cycle of the reservoir. These services include digital and consulting solutions for locating hydrocarbons and managing digital data; drilling and formation evaluation; fluid systems for drilling and completing wells; and production optimization. KBR designs, builds, operates and maintains energy and chemical facilities such as liquefied natural gas plants, refining and processing plants, production facilities and pipelines – both onshore and offshore. In addition, KBR provides engineering, construction and logistics services to meet the needs of governments and civil infrastructure customers worldwide. DEAR FELLOW SHAREHOLDERS For 85 years, Halliburton has weathered every sort of challenge to our Company. But I think we will remember 2004 as the year we overcame extreme adversity. Unprecedented asbestos claims, dangerous work with the armed forces in Iraq, public cynicism about large corporations, a U.S. vice president with past ties to our company – all of these issues converged in an election year as some tried to turn the proud old name Halliburton into a political symbol. Today, as we stand on the brink of a bright and exciting future, I am proud to report that not only has Halliburton survived some of the greatest challenges ever faced by any company, but we have emerged stronger than ever. Look at our financial position: our revenue and operating income increased in 2004 and our stock climbed steadily through the year. Although the charges we took to resolve our asbestos liabilities, the Barracuda-Caratinga project and other outstanding issues in KBR depressed our bottom-line financial results, our liquidity remains strong, and I believe that both the Energy Services Group (ESG) and KBR are positioned for profitability in 2005. For any who doubted the strength and integrity of our Company, I think the continuing support of our shareholders and customers speaks for itself. I want to thank you for standing behind us. One of our most daunting tasks this year was concluding the largest and most complex prepackaged bankruptcy that has ever been accomplished, resolving our asbestos and silica liability. I deeply appreciate the members of our team who worked to achieve a fair solution for those who were impaired by asbestos exposure – a resolution that many said would never be possible. The value of the settlement included a cash contribution of $2.775 billion to fund a trust for current claimants; we also issued 59.5 million shares of Halliburton common stock for the benefit of future asbestos claimants. This has been somewhat offset by insurance collections from more than 150 insurance companies, which I view as a monumental achievement. So far, we have collected more than $1 billion from these companies, and we expect to collect about $500 million more. Halliburton achieved another significant milestone in 2004 when the Barracuda floating production, storage and offloading (FPSO) vessel produced first oil in December. Barracuda’s sister ship, Caratinga, also achieved first oil in February, 2005. Our $2.5 billion contract – which included converting two oil tankers into FPSO vessels and developing the 54-well Barracuda and Caratinga oil fields in offshore Brazil – was the largest engineering, procurement, installation and construction (EPIC) contract ever undertaken by a single contractor. Since then, we have moved away from lump sum off- shore contracts and have had good success with our new cost-reimbursable approach to this type of work. The political rhetoric we faced in the United States has subsided since Election Day – but not without a price. In the months leading up to the election, the false, misleading and unfair allegations about Halliburton seemed to multiply exponentially, simply because the nation’s vice president once held my job. We worked tirelessly to address these relentless accusations, to cooperate with every investigation, and to challenge and correct misinformation. Now that we have overcome these difficulties, it is time to look beyond – beyond asbestos, beyond Barracuda- Caratinga, beyond the politics – to the immense potential of Halliburton. In 2005, I look forward to spending my time on more constructive endeavors: growing the busi- ness and pursuing my vision for the Company’s future. We have a world-class leadership team in place to help us move forward. Upon the retirement of the former KBR chairman and the departure from the Company of the ESG president and CEO, I eliminated those positions to create a flatter, more streamlined reporting structure. Now the senior vice presidents of all KBR and ESG operating segments will report directly to Andrew Lane, whom I appointed chief operating officer. I am profoundly grateful for our talented, thoughtful and dedicated leadership team members who have supported me this year – Andy; Cris Gaut, our chief financial officer; and Bert Cornelison, our general counsel. In the coming year, we will continue to review our full portfolio, including the future of KBR. The positive value potential that KBR brings has not been reflected in Halliburton’s stock price. Therefore, we intend to separate KBR from the Company. This separation could take a number of forms, including a spin-off or split-off, an initial public offering, or the sale of KBR. However, I believe that, in order to maximize KBR’s value for our shareholders, it may be necessary to establish a track record of positive earnings for several quarters and to resolve government investigations and outstanding disputes. During that time, we will investigate our options and determine the best value, terms and structure for a transaction. We have reorgan- ized KBR into two segments, Energy & Chemicals and Government & Infrastructure, to support this effort. Halliburton’s most remarkable asset, now and always, is its people. In 2004, they had to defend their honorable work while their every action was examined as if they were under a magnifying glass. Yet, even in the darkest moments, their support never wavered. I am proud of our employees. Their passionate commitment, gritty determination and unswerving faith in our Company have been my greatest source of pride and inspiration. As I write this letter, more than 47,000 KBR employees and contractors – the largest civilian force ever assembled – are working alongside U.S. troops in Iraq, far from their homes and their families. This is demanding, dangerous work. Sixty of our employees and subcontractors have been killed, 250 have been wounded and one is still missing. As difficult as this is to accept, it has been made even harder by those who seek to politicize the work of these brave men and women. One of the brightest moments we shared this year happened when we welcomed Tommy Hamill home. Tommy was kidnapped when the truck convoy he commanded was ambushed by Iraqi militants. His courage in escaping his captors not once, but twice, exemplifies the “can do” attitude of the Halliburton employees who have volunteered for these positions. This ethic traces its origins back to our founders, Erle P. Halliburton and the Brown brothers, whose legendary determination to get the job done, no matter what, made them industry icons. Heartened by the amazing spirit of Halliburton people, we will honor our commitment to our customer, the U.S. government, and continue supporting our troops. It’s the right thing to do. This year, in our television commercials, we told the public, “It’s not who we know. It’s what we know.” The truth of this statement is evident in the many government and infrastructure contracts KBR won this year through competitive bidding – including two important construction contracts to support U.S. Navy facilities, as well as a logistics support contract with the U.K. Ministry of Defence. Nobody is better than KBR at what we do. Worldwide, KBR is well-positioned to benefit from increased demand for unconventional sources of gas. KBR has built a large portion of the world’s LNG capacity, and this year was David J. Lesar Chairman of the Board, President and Chief Executive Officer of Halliburton part of a joint venture team that received the engineering, procurement and construction contract to build another train for Nigeria LNG Limited – the fourth this company has awarded us. KBR is also part of a joint venture selected for design work on a grassroots LNG facility in Western Australia. In addition, KBR is pioneering innovative gas-to-liquids (GTL) technology that will help the world bring its remote gas reserves to market. KBR is part of a joint venture that was selected to provide front end engineering and design services for Shell’s GTL project in Qatar. In the ESG, business is thriving. We established annual records in revenue and operating income for three of the four ESG segments in 2004, and the total ESG group posted record revenue in the fourth quarter. I attribute this outstanding performance in revenue to our customers’ increased spending levels, and also to improved pricing as capacity tightened. Operating margins benefited from the improved pricing as well, but also from the ESG’s focus on capital discipline and improved cost structure. We expect activity in the oil and gas industry to remain robust through 2005. Like KBR, the ESG has also enjoyed the staunch support of its customers during this difficult year. One of our strengths is the ability to integrate our services across all product lines for an economically optimized, total reservoir solution. Petroleum Development Oman is one company that is taking advantage of this capability, with three contracts worth up to $500 million over five years to provide cementing, stimulation, directional drilling, logging-while-drilling and mud logging services. Throughout the ESG, we are building on our strengths for the future. For instance, our Drilling and Formation Evaluation segment is unlocking the burgeoning logging- while-drilling market with its Geo-Pilot® rotary steerable technologies. In 2004, this segment won contracts for drilling and related services in Brunei, Azerbaijan, Mexico and North America, as well as in both the U.K. and Norway sectors of the North Sea. The segment also introduced its new polycrystalline diamond compact (PDC) fixed cutter bit technology, representing a step-change for longer bit life and cost-effective drilling. In the roller cone bit market, our EnergyBalanced® technology, which allows us to design custom bits quickly for specific conditions encoun- tered in the field, continues to make inroads. The value of this innovation is underlined by our recent award in a patent infringement case against a competitor. With 95 percent of its revenue in No. 1 or No. 2 market share positions, the Production Optimization segment is ideally positioned as operators seek to boost declining production in the world’s maturing reservoirs. We recently won two major contracts in the prime stimulation market of the U.S. Rockies. We also celebrated a three-year contract for well completions in Qatar’s giant North Gas field, awarded by Dolphin Energy Limited – Qatar. The reliability and performance of Halliburton’s Peak® large monobore downhole completion equipment is critical to the success of the high-rate gas well completions that this project requires. Other technology advancements include the new DeepReachSM coiled tubing service and DeepQuestSM stimulation service. These technologies enable operators to recover harder-to-access deepwater reserves more economically. Halliburton Digital and Consulting Solutions, formerly the Landmark and Other Energy Services segment, is advancing its leadership position in software while growing its consulting practice to capture an untapped market opportunity. This year, the group signed five-year technology agreements to support both PEMEX and Statoil with a broad range of prospect generation and field development software. Another three-year agreement delivers information management services to China. On the technology frontier, Landmark Graphics Corporation announced the release of DecisionSpace® Well Seismic FusionTM, a unique suite of interpretation and analysis tools to improve reservoir understanding and dramatically reduce exploration risk. Working with Silicon Graphics and Marathon Oil Company, Landmark achieved another breakthrough in the search for new oil and gas reserves with advanced interactive visualization that allows scientists to evaluate acreage rapidly using four times more seismic information than previously possible. The Fluids Systems segment is leveraging its strong market leadership in cementing to further improve its pricing in this robust market. In our Baroid product line, our focus in 2004 has been on rightsizing our operations in areas that have been slow to pick up, particularly the Gulf of Mexico and the North Sea. Baroid is launching projects in Mexico and Bangladesh in alliance with National Oilwell to provide solids control and waste management services and equipment at the rig site. Similar operations are already under way in the United States, Venezuela and Brazil. We are very excited by this new market opportunity. Throughout both KBR and the ESG, innovative new technologies are helping customers reduce costs, improve productivity, use resources more efficiently and maximize the return on their investment. The industry recognized our innovation by honoring Halliburton with more prestigious technology awards than any other service company, including three for the DepthStar® subsurface safety valve. At Halliburton, we’re committed not just to our customers and shareholders, but also to all of the communities that we call home. Everywhere I travel, I see employees in red T-shirts cleaning beaches, building schools, feeding the hungry, raising money for medical research and caring for those who need our help the most. I hear about employees who have made tough decisions to handle situations ethically. I know how hard our Company works to develop eco-friendly technologies and minimize the environmental footprint we leave on our job sites. I support the priority we place on safety, which has earned us the reputation as the best in this arena. All across the Company, all around the world, I’m proud of the work we do. As the challenges of 2004 fade into the past and the opportunities of a new year come into focus, it is easy to see beyond the rhetoric, beyond the litigation – beyond all the other difficulties – to the promising future of this great Company. From my seat, I like what I see. David J. Lesar Chairman of the Board, President and Chief Executive Officer of Halliburton 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, 2004 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 or organization) 75-2677995 (I.R.S. Employer Identification No.) 5 Houston Center 1401 McKinney, Suite 2400 Houston, Texas 77010 (Address of principal executive offices) Telephone Number – Area code (713) 759-2600 Securities registered pursuant to Section 12(b) of the Act: Title of each class Common Stock par value $2.50 per share Name of each Exchange on which registered 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] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes X No ____ The aggregate market value of Common Stock held by nonaffiliates on June 30, 2004, determined using the per share closing price on the New York Stock Exchange Composite tape of $30.26 on that date was approximately $13,290,000,000. As of February 17, 2005, there were 504,455,647 shares of Halliburton Company Common Stock, $2.50 par value per share, outstanding. Portions of the Halliburton Company Proxy Statement for our 2005 Annual Meeting of Stockholders (File No. 1-3492) are incorporated by reference into Part III of this report. HALLIBURTON COMPANY INDEX TO ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2004 PA RT I Item 1. Item 2. Item 3. Item 4. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 E X E C U T I V E O F F I C E R S O F R E G I S T R A N T . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-9 PA RT I I Item 5. Item 6. Item 7. Market for the Registrant’s Common Equity and Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . 10 Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . 10 Item 7(a). Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Item 8. Item 9. Financial Statements and Supplementary Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . . . 10 Item 9(a). Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Item 9(b). Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 F I N A N C I A L S TAT E M E N T S a n d M D & A Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . 12-54 Management’s Report on Internal Control Over Financial Reporting. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 Reports of Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56-57 Consolidated Statements of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 Consolidated Statements of Shareholders’ Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 Consolidated Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62-106 Selected Financial Data (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107 Quarterly Data and Market Price Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108 PA RT I I I Item 10. Item 11. Directors and Executive Officers of Registrant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 Item 12(a). Security Ownership of Certain Beneficial Owners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 Item 12(b). Security Ownership of Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 Item 12(c). Changes in Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 Item 12(d). Securities Authorized for Issuance Under Equity Compensation Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 Item 13. Item 14. PA RT I V Item 15. Certain Relationships and Related Transactions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110-118 S I G N AT U R E S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119-120 PART I ITEM 1. BUSINESS. General description of business. Halliburton Company’s predecessor was established in 1919 and incorporated under the laws of the State of Delaware in 1924. Halliburton Company provides a variety of services, products, mainte- nance, engineering, and construction to energy, industrial, and governmental customers. Our six business segments are organized around how we manage the business: Production Optimization, Fluid Systems, Drilling and Formation Evaluation, Digital and Consulting Solutions (formerly Landmark and Other Energy Services), Government and Infrastructure, and Energy and Chemicals. We refer to the combination of the Production Optimization, Fluid Systems, Drilling and Formation Evaluation, and Digital and Consulting Solutions segments as our Energy Services Group and to the Government and Infrastructure and Energy and Chemicals segments as KBR. See Note 5 to the consoli- dated financial statements for financial information about our business segments. Asbestos and silica settlement and prepackaged Chapter 11 resolution. In December 2003, eight of our subsidiaries sought Chapter 11 protection to avail themselves of the provisions of Sections 524(g) and 105 of the Bankruptcy Code to discharge current and future asbestos and silica personal injury claims against us and our subsidiaries. The order confirming the plan of reorganization became final and nonappealable on December 31, 2004, and the plan of reorganization became effective in January 2005. Under the plan of reorganization, all current and future asbestos and silica personal injury claims against us and our affiliates were channeled into trusts established for the benefit of asbestos and silica claimants, thus releasing us from those claims. During 2004, we settled insurance disputes with substantially all insurance companies for asbestos- and silica-related claims and all other claims under the applica- ble insurance policies and terminated all the applicable insurance policies. Under the terms of our insurance settlements, we will receive cash proceeds with a nominal amount of approximately $1.5 billion and with a present value of approximately $1.4 billion for our asbestos- and silica-related insurance receivables. Cash payments of approximately $1.0 billion related to these receivables were received in January 2005. Under the terms of the settlement agreements, we will receive cash payments of the remaining amounts in several installments beginning in July 2005 through 2009. See Note 11 to the consolidated financial statements for further information regarding the resolution of our asbestos and silica settlement and prepackaged Chapter 11 proceedings. Description of services and products. We offer a broad suite of products and services through our six business seg- ments. The following summarizes our services and products for each business segment. ENERGY SERVICES GROUP Our Energy Services Group provides a wide range of discrete services and products, as well as bundled services and integrated services and solutions to customers for the exploration, development, and production of oil and gas. The Energy Services Group serves major, national, and independent oil and gas companies throughout the world. Production Optimization Our Production Optimization segment primarily tests, measures, and provides means to manage and/or improve well production once a well is drilled and, in some cases, after it has been producing. This segment consists of production enhancement services and completion tools In accordance with the plan of reorganization, in and services. January 2005 we contributed the following to trusts for the benefit of current and future asbestos and silica personal injury claimants: – approximately $2.3 billion in cash; – 59.5 million shares of Halliburton common stock; and – notes currently valued at approximately $55 million. Production enhancement services include stimulation services, pipeline process services, sand control services, coiled tubing tools and services, and hydraulic workover services. Stimulation services optimize oil and gas reser- voir production through a variety of pressure pumping services, and chemical processes, commonly known as fracturing and acidizing. Pipeline process services include 1 pipeline and facility testing, commissioning, and cleaning Cementing is the process used to bond the well and well via pressure pumping, chemical systems, specialty equip- casing while isolating fluid zones and maximizing wellbore ment, and nitrogen, and are provided to the midstream and stability. Cement and chemical additives are pumped to fill downstream sectors of the energy business. Sand control the space between the casing and the side of the wellbore. services include fluid and chemical systems and pumping Our cementing service line also provides casing equipment services for the prevention of formation sand production. and services. Completion tools and services include subsurface safety Our Baroid Fluid Services product line provides drilling valves and flow control equipment, surface safety systems, fluid systems, performance additives, solids control, and packers and specialty completion equipment, intelligent waste management services for oil and gas drilling, completion systems, production automation, expandable completion, and workover operations. In addition, Baroid liner hanger systems, sand control systems, slickline Fluid Services sells products to a wide variety of industrial equipment and services, self-elevated workover platforms, customers. Drilling fluids usually contain bentonite or tubing-conveyed perforating products and services, well barite in a water or oil base. Drilling fluids primarily servicing tools, and reservoir performance services. improve wellbore stability and facilitate the transportation Reservoir performance services include drill stem and of cuttings from the bottom of a wellbore to the surface. other well testing tools and services, underbalanced Drilling fluids also help cool the drill bit, seal porous well applications and real-time reservoir analysis, data acquisi- formations, and assist in pressure control within a wellbore. tion services, and production applications. Drilling fluids are often customized by onsite engineers for Also included in this segment is WellDynamics, an optimum stability and enhanced oil production. intelligent well completions joint venture. In January 2004, Also included in this segment is our investment in Halliburton and Shell Technology Ventures (Shell) agreed Enventure, which is an expandable casing joint venture. As to restructure two joint venture companies, WellDynamics discussed above, in January 2004, Halliburton and Shell B.V. (WellDynamics) and Enventure Global Technology agreed to restructure this joint venture. Enventure was LLC (Enventure), in an effort to more closely align the owned equally by Halliburton and Shell. Shell acquired an ventures with near-term priorities in the core businesses of additional 33.5% of Enventure, leaving us with 16.5% the venture owners. We acquired an additional 1% of ownership in return for enhanced and extended agree- WellDynamics from Shell, giving us 51% ownership. With ments and licenses with Shell for its Poro lex expandable F ® our resulting control of day-to-day operations, we believe sand screens and a distribution agreement for its we are now able to achieve more opportunities to leverage Versa lex™ expandable liner hangers, in addition to a 1% F existing complementary businesses, reduce costs, and increase in our ownership of WellDynamics. ensure global availability. Drilling and Formation Evaluation Additionally, subsea operations conducted by Subsea 7, Our Drilling and Formation Evaluation segment is Inc., of which we formerly owned 50%, are included in this primarily involved in drilling and evaluating the formations segment. In January 2005, we completed the sale of this during the bore-hole construction process. Major products joint venture to our partner, Siem Offshore (formerly and services offered include: DSND Subsea ASA). See Note 4 to the consolidated – drilling systems and services; financial statements for additional information related to – drill bits; and this disposition. Fluid Systems – logging services. Our Sperry Drilling Services product line provides Our Fluid Systems segment focuses on providing drilling systems and services. These services include services and technologies to assist in the drilling and directional and horizontal drilling, measurement-while- construction of oil and gas wells. This segment offers drilling, logging-while-drilling, multilateral completion cementing and drilling fluids systems. systems, and rig site information systems. Our drilling 2 systems offer directional control while providing important integrated, and national oil companies. These offerings measurements about the characteristics of the drill string make use of all of Halliburton’s oilfield services, products, and geological formations while drilling directional wells. technologies, and project management capabilities to Real-time operating capabilities enable the monitoring of assist our customers in optimizing the value of their oil well progress and aid decision-making processes. and gas assets. Our Security DBS Drill Bits product line provides roller KBR cone rock bits, fixed cutter bits, and related downhole tools KBR provides a wide range of services to energy and used in drilling oil and gas wells. In addition, coring industrial customers and government entities worldwide equipment and services are provided to acquire cores of and consists of two segments, Government and the formations drilled for evaluation. Infrastructure and Energy and Chemicals. Logging services include open-hole wireline services Government and Infrastructure which provide information on formation evaluation, Our Government and Infrastructure segment focuses on: including resistivity, porosity, and density; rock mechanics; – construction, maintenance, and logistics services for and fluid sampling. Cased-hole services are also offered government operations, facilities, and installations; which provide cement bond evaluation, reservoir monitor- – civil engineering, construction, consulting, and project ing, pipe evaluation, pipe recovery, and perforating. Our management services for state and local government Magnetic Resonance Imaging Logging (MRIL®) tools agencies and private industries; apply magnetic resonance imaging technology to the – integrated security solutions, including threat defini- evaluation of subsurface rock formations in newly drilled tion assessments, mitigation, and consequence oil and gas wells. management; design, engineering, and program Digital and Consulting Solutions management; construction and delivery; and physical Our Digital and Consulting Solutions segment provides security, operations, and maintenance; integrated exploration and production software information – dockyard operation and management through the systems, consulting services, real-time operations, Devonport Royal Dockyard Limited (DML) sub- subsea operations, and other integrated solutions. sidiary, with services that include design, Landmark Graphics is a supplier of integrated explo- construction, surface/subsurface fleet maintenance, ration and production software information systems as nuclear engineering and refueling, and weapons well as professional and data management services for the engineering; and upstream oil and gas industry. Landmark Graphics software – privately financed initiatives, in which KBR funds the transforms vast quantities of seismic, well log, and other development or provision of an asset, such as a facility, data into detailed computer models of petroleum reser- service, or infrastructure, for a government client, voirs. The models are used by our customers to achieve which we then own, operate, and maintain, enabling optimal business and technical decisions in exploration, our clients to utilize new assets at a reasonable cost. development, and production activities. Data management Energy and Chemicals services provide efficient storage, browsing, and retrieval Our Energy and Chemicals segment is a global engineer- of large volumes of exploration and petroleum data. The ing, procurement, construction, technology, and services products and services offered by Landmark Graphics provider for the energy and chemicals industries. Working integrate data workflows and operational processes across both upstream and downstream in support of our cus- disciplines, including geophysics, geology, drilling, tomers, Energy and Chemicals offers the following: engineering, production, economics, finance and corporate – downstream engineering and construction capabilities, planning, and key partners and suppliers. including global engineering execution centers, as This segment also provides value-added oilfield project well as engineering, construction, and program management and integrated solutions to independent, management of liquefied natural gas, ammonia, 3 petrochemicals, crude oil refineries, and natural gas – creating and continuing innovative business relation- plants; ships; and – upstream deepwater engineering, marine technology, – preserving a dynamic workforce. and project management; Now that we have resolved our asbestos and silica – Production Services provides plant operations, liability and our affected subsidiaries have exited Chapter maintenance, and start-up services for upstream oil 11 reorganization proceedings, we intend to separate KBR and gas facilities worldwide; from Halliburton, which could include a transaction – in the United States, Industrial Services provides involving a spin-off, split-off, public offering, or sale of KBR maintenance services to the petrochemical, forest or its operations. In order to maximize KBR’s value for our product, power, and commercial markets; shareholders and to determine the most appropriate form – industry-leading licensed technologies in the areas of of the transaction and its components, it may be necessary fertilizers and synthesis gas, olefins, refining, and for KBR to establish a track record of positive earnings for chemicals and polymers; and a number of quarters and to seek resolution of governmen- – consulting services in the form of expert technical and tal issues, investigations, and other disputes. management advice that include studies, conceptual Markets and competition. We are one of the world’s largest and detailed engineering, project management, diversified energy services and engineering and construc- construction supervision and design, and construction tion services companies. We believe that our future success verification or certification in both upstream and will depend in large part upon our ability to offer a wide downstream markets. array of services and products on a global scale. Our Also included in this segment are two joint ventures: services and products are sold in highly competitive TSKJ, in which we have a 25% interest, and M.W. Kellogg, markets throughout the world. Competitive factors Ltd., in which we have a 55% interest. TSKJ was formed to impacting sales of our services and products include: construct and subsequently expand a large natural gas – price; liquefaction complex in Nigeria. – service delivery (including the ability to deliver Dispositions in 2004. In August 2004, we sold our surface services and products on an “as needed, where well testing and subsea test tree operations within our needed” basis); Production Optimization segment to Power Well Service – health, safety, and environmental standards and Holdings, LLC, an affiliate of First Reserve Corporation. practices; This disposition will have an immaterial impact on our – service quality; future operations. See Note 4 to the consolidated financial – product quality; statements for additional information related to this – warranty; and disposition. – technical proficiency. Business strategy. Our business strategy is to maintain While we provide a wide range of discrete services and global leadership in providing energy services and products products, a number of customers have indicated a prefer- and engineering and construction services. We provide ence for bundled services and integrated services and these services and products to our customers as discrete solutions. In the case of the Energy Services Group, services and products and, when combined with project integrated services and solutions relate to all phases of management services, as integrated solutions. Our ability to exploration, development, and production of oil, natural be a global leader depends on meeting four key goals: gas, and natural gas liquids. In the case of KBR, integrated – establishing and maintaining technological leadership; services and solutions relate to all phases of design, – achieving and continuing operational excellence; procurement, construction, project management, and maintenance of facilities primarily for energy and govern- ment customers. 4 We conduct business worldwide in over 100 countries. the United States government during 2002 represented less In 2004, based on the location of services provided and than 10% of consolidated revenue. No other customer products sold, 26% of our consolidated revenue was from represented more than 10% of consolidated revenue in any Iraq, primarily related to our work for the United States period presented. Government, and 22% of our consolidated revenue was The following schedule summarizes our project from the United States. In 2003, 27% of our consolidated backlog: revenue was from the United States and 15% of our consolidated revenue was from Iraq. No other country Millions of dollars Firm orders: December 31 2004 2003 accounted for more than 10% of our consolidated revenue during these periods. See Note 5 to the consolidated Government and Infrastructure Energy and Chemicals Energy Services Group segments financial statements for additional financial information Total $3,968 3,643 64 7,675 about geographic operations in the last three years. Since the markets for our services and products are vast and Government orders firm but not yet funded, letters of intent, and contracts awarded but not signed: cross numerous geographic lines, a meaningful estimate Government and Infrastructure of the total number of competitors cannot be made. The industries we serve are highly competitive and we have Energy and Chemicals Energy Services Group segments Total many substantial competitors. Largely all of our services Total backlog 816 - - 816 $8,491 $5,025 3,625 278 8,928 1,076 19 43 1,138 $10,066 and products are marketed through our servicing and sales organizations. Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil unrest, expropriation or other governmental actions, and exchange control and currency problems. Except for our government services work in Iraq discussed above, 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 in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financial Instrument Market Risk” and in Note 18 to the consolidated financial statements. Customers and backlog. Our revenue during the past three years was mainly derived from the sale of services and products to the energy industry, including 54% in 2004, 66% in 2003, and 86% in 2002. Revenue from the United States government, resulting primarily from the work performed in the Middle East by our Government and Infrastructure segment, represented 39% of our 2004 consolidated revenue and 26% of our 2003 consolidated revenue. Revenue from Backlog related to Subsea 7, Inc. is not included in the table above at December 31, 2004 since it was sold subse- quent to year-end. We estimate that 74% of backlog existing within the Government and Infrastructure segment and 51% of backlog existing within the Energy and Chemicals segment at December 31, 2004 will be completed during 2005. Approximately 75% of total backlog relates to cost- reimbursable contracts, with the remaining 25% relating to fixed-price contracts. For contracts that are not for a specific amount, backlog is estimated as follows: – operations and maintenance contracts that cover multiple years are included in backlog based upon an estimate of the work to be provided over the next twelve months; and – government contracts that cover a broad scope of work up to a maximum value are included in backlog at the estimated amount of work to be completed under the contract based upon periodic consultation with the customer. For projects where we act as project manager, we only include our scope of each project in backlog. For projects related to unconsolidated joint ventures, we only include our percentage ownership of each joint venture’s backlog, which totaled $1.1 billion at December 31, 2004. Our backlog excludes contracts for recurring hardware and 5 software maintenance and support services offered by – typhoons and hurricanes can disrupt offshore Landmark Graphics. Backlog is not indicative of future operations; and operating results because backlog figures are subject to – severe weather during the winter months normally substantial fluctuations. Arrangements included in backlog results in reduced activity levels in the North Sea. are in many instances extremely complex, are nonrepetitive Due to higher spending near the end of the year on in nature, and may fluctuate in contract value and timing. capital expenditures by customers for software, Landmark Many contracts do not provide for a fixed amount of work Graphics results of operations are generally stronger in the to be performed and are subject to modification or termina- fourth quarter of the year than at the beginning of the year. tion by the customer. The termination or modification of Employees. At December 31, 2004, we employed approxi- any one or more sizeable contracts or the addition of other mately 97,000 people worldwide compared to 101,000 at contracts may have a substantial and immediate effect on December 31, 2003. At December 31, 2004, approximately backlog. 6% of our employees were subject to collective bargaining Raw materials. Raw materials essential to our business agreements. Based upon the geographic diversification of are normally readily available. Where we rely on a single these employees, we believe any risk of loss from employee supplier for materials essential to our business, we are strikes or other collective actions would not be material to confident that we could make satisfactory alternative the conduct of our operations taken as a whole. arrangements in the event of an interruption in supply. Environmental regulation. We are subject to numerous Research and development costs. We maintain an active environmental, legal, and regulatory requirements related research and development program. The program to our operations worldwide. In the United States, these improves existing products and processes, develops new laws and regulations include, among others: products and processes, and improves engineering – the Comprehensive Environmental Response, standards and practices that serve the changing needs of Compensation and Liability Act; our customers. Our expenditures for research and develop- – the Resources Conservation and Recovery Act; ment activities were $234 million in 2004, $221 million in – the Clean Air Act; 2003, and $233 million in 2002, of which over 96% was – the Federal Water Pollution Control Act; and company-sponsored in each year. – the Toxic Substances Control Act. Patents. We own a large number of patents and have In addition to the federal laws and regulations, states pending a substantial number of patent applications and other countries where we do business may have covering various products and processes. We are also numerous environmental, legal, and regulatory require- licensed to utilize patents owned by others. We do not ments by which we must abide. We evaluate and address consider any particular patent or group of patents to be the environmental impact of our operations by assessing material to our business operations. and remediating contaminated properties in order to avoid Seasonality. On an overall basis, our operations are not future liabilities and comply with environmental, legal, and generally affected by seasonality. Weather and natural regulatory requirements. On occasion, we are involved in phenomena can temporarily affect the performance of our specific environmental litigation and claims, including the services, but the widespread geographical locations of our remediation of properties we own or have operated, as operations serve to mitigate those effects. Examples of how well as efforts to meet or correct compliance-related weather can impact our business include: matters. Our Health, Safety and Environment group has – the severity and duration of the winter in North several programs in place to maintain environmental America can have a significant impact on gas storage leadership and to prevent the occurrence of environmental levels and drilling activity for natural gas; contamination. – the timing and duration of the spring thaw in Canada directly affects activity levels due to road restrictions; 6 We do not expect costs related to these remediation All of our owned properties are unencumbered. requirements to have a material adverse effect on our In addition, we have 155 international and 106 United consolidated financial position or our results of operations. States field camps from which the Energy Services Group Website access. Our annual reports on Form 10-K, delivers its products and services. We also have numerous quarterly reports on Form 10-Q, current reports on Form small facilities that include sales offices, project offices, and 8-K, and amendments to those reports filed or furnished bulk storage facilities throughout the world. We own or pursuant to Section 13(a) or 15(d) of the Exchange Act of lease marine fabrication facilities covering approximately 1934 are made available free of charge on our internet 519 acres in Texas, England (primarily related to DML), website at www.halliburton.com as soon as reasonably and Scotland, which are used by KBR. Our marine facilities practicable after we have electronically filed the material located in Texas and Scotland are currently for sale. with, or furnished it to, the Securities and Exchange We have mineral rights to proven and probable reserves Commission. We have posted on our website our Code of of barite and bentonite. These rights include leaseholds, Business Conduct, which applies to all of our employees mining claims, and owned property. We process barite and and directors and serves as a code of ethics for our bentonite for use in our Fluid Systems segment in addition principal executive officer, principal financial officer, to supplying many industrial markets worldwide. Based on principal accounting officer or controller, and other persons the number of tons of bentonite consumed in fiscal year performing similar functions. Any amendments to our 2004, we estimate that our 20 million tons of proven Code of Business Conduct or any waivers from provisions reserves in areas of active mining are sufficient to fulfill our of our Code of Business Conduct granted to the specified internal and external needs for the next 15 years. We officers above are disclosed on our website within four estimate that our 2.8 million tons of proven reserves of business days after the date of any amendment or waiver barite in areas of active mining equate to a 16-year supply pertaining to these officers. based on current rates of production. These estimates are ITEM 2. PROPERTIES. We own or lease numerous properties in domestic and foreign locations. The following locations represent our major facilities: Location Owned/Leased Description Energy Services Group North America Production Optimization Segment: Carrollton, Texas Alvarado, Texas Owned Manufacturing facility Owned/Leased Manufacturing facility Drilling and Formation Evaluation Segment: The Woodlands, Texas Shared Facilities: Duncan, Oklahoma Houston, Texas Houston, Texas Houston, Texas KBR North America Energy and Chemicals Segment: Houston, Texas Shared Facilities: Houston, Texas Europe/Africa Shared Facilities: Leased Manufacturing facility Owned Owned Manufacturing, technology, and campus facilities Manufacturing and campus facilities Owned/Leased Leased Campus facility Campus facility Leased Campus facility Owned Campus facility Leatherhead, United Kingdom Owned Campus facility Corporate Houston, Texas Leased Corporate executive offices subject to change based on periodic updates to reserve estimates and to the extent future consumption differs from current levels of consumption. We believe all properties that we currently occupy are suitable for their intended use. ITEM 3. LEGAL PROCEEDINGS. Information relating to various commitments and contingencies is described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Forward-Looking Information and Risk Factors” and in Notes 3, 11, 12, and 13 to the consolidated financial statements. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. There were no matters submitted to a vote of security holders during the fourth quarter of 2004. 7 EXECUTIVE OFFICERS OF THE REGISTRANT. The following table indicates the names and ages of the executive officers of the registrant as of February 15, 2005, along with a listing of all offices held by each during the past five years: Name and Age Offices Held and Term of Office * Albert O. Cornelison, Jr. Executive Vice President and General Counsel of Halliburton Company, (Age 55) since December 2002 Vice President and General Counsel of Halliburton Company, May 2002 to December 2002 Vice President and Associate General Counsel of Halliburton Company, October 1998 to May 2002 * C. Christopher Gaut Executive Vice President and Chief Financial Officer of Halliburton (Age 48) Company, since March 2003 Senior Vice President, Chief Financial Officer and Member – Office of the President and Chief Operating Officer of ENSCO International Incorporated, January 2002 to February 2003 Senior Vice President and Chief Financial Officer of ENSCO International Incorporated, December 1987 to December 2001 W. Preston Holsinger Vice President and Treasurer of Halliburton Company, since (Age 63) October 2004 Director, Special Projects, May 2002 to October 2004 Shared Services Director HED/IS, November 1998 to May 2002 * Andrew R. Lane (Age 45) Executive Vice President and Chief Operating Officer, since December 2004 President and Chief Executive Officer of KBR, July 2004 to November 2004 Senior Vice President, Global Operations of Halliburton Energy Services, April 2004 to July 2004 President, Landmark Division of Halliburton Energy Services Group, May 2003 to March 2004 President and Chief Executive Officer of Landmark Graphics, April 2002 to April 2003 Chief Operating Officer of Landmark Graphics, January 2002 to March 2002 Vice President, Production Enhancement PSL, Completion Products PSL and Tools/Testing/TCP of Halliburton Energy Services Group, January 2000 to December 2001 8 Name and Age * David J. Lesar (Age 51) Offices Held and Term of Office Chairman of the Board, President and Chief Executive Officer of Halliburton Company, since August 2000 Director of Halliburton Company, since August 2000 President and Chief Operating Officer of Halliburton Company, May 1997 to August 2000 Chairman of the Board of Kellogg Brown & Root, Inc., January 1999 to August 2000 Executive Vice President and Chief Financial Officer of Halliburton Company, August 1995 to May 1997 Mark A. McCollum Senior Vice President and Chief Accounting Officer, since August 2003 (Age 45) Senior Vice President and Chief Financial Officer, Tenneco Automotive, Inc., November 1999 to August 2003 * Weldon J. Mire (Age 57) Vice President, Human Resources of Halliburton Company, since May 2002 Division Vice President of Halliburton Energy Services, January 2001 to May 2002 (Country Vice President Indonesia) Asia Pacific Sales Manager of Halliburton Energy Services, November 1999 to January 2001 Director of Business Development, September 1999 to November 1999 Global Director of Strategic Business Development, January 1999 to November 1999 Senior Shared Services Manager Houston, November 1998 to January 1999 David R. Smith (Age 58) Vice President, Tax of Halliburton Company, since May 2002 Vice President, Tax of Halliburton Energy Services, Inc., September 1998 to May 2002 * Members of the Policy Committee of the registrant. There are no family relationships between the executive officers of the registrant or between any director and any executive officer of the registrant. 9 PART II ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. Halliburton Company’s common stock is traded on the New York Stock Exchange. Information relating to the high and low market prices of common stock and quarterly dividend payments is included under the caption “Quarterly Data and Market Price Information” on page 108 of this annual report. Cash dividends on common stock for 2004 and 2003 in the amount of $0.125 per share 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 February 15, 2005, there were approximately 22,573 shareholders of record. In calculating the number of shareholders, we consider clearing agencies and security position listings as one shareholder for each agency or listing. Following is a summary of our repurchases of our common stock during the three-month period ended December 31, 2004. Period October 1-31 November 1-30 December 1-31 Total Total Number of Shares Purchased (a) 4,145 20,414 8,219 32,778 Average Price Paid per Share $31.57 $33.81 $36.32 $34.16 Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs - - - - (a) All of the shares repurchased during the three-month period ended December 31, 2004 were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These share purchases were not part of a publicly announced program to purchase common shares. On April 25, 2000, our Board of Directors approved plans to implement a share repurchase program for up to 44 million shares of our common stock, of which 22,385,700 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 12 through 54 of this annual report. ITEM 7(A). QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Information relating to market risk is included in Management’s Discussion and Analysis of Financial Condition and Results of Operations under the caption “Financial Instrument Market Risk” on page 42 of this annual report. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Management’s Report on Internal Control Over Financial Reporting Reports of Independent Registered Public Accounting Firm Consolidated Statements of Operations for the years ended December 31, 2004, 2003, and 2002 Consolidated Balance Sheets at December 31, 2004 and 2003 Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2004, 2003, and 2002 Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003, and 2002 Notes to Consolidated Financial Statements Selected Financial Data (Unaudited) Quarterly Data and Market Price Information (Unaudited) Page No. 55 56 58 59 60 61 62 107 108 The related financial statement schedules are included under Part IV, Item 15 of this annual report. shares may yet be purchased. ITEM 6. SELECTED FINANCIAL DATA. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. Information relating to selected financial data is None. included on page 107 of this annual report. 10 ITEM 9(A). CONTROLS AND PROCEDURES. In accordance with Exchange Act Rules 13a-15 and 15d- 15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2004 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting that occurred during the three months ended December 31, 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. See page 55 for Management’s Report on Internal Control Over Financial Reporting and page 57 for Report of Independent Registered Public Accounting Firm on our assessment of internal control over financial reporting and opinion on the effectiveness of the Company’s internal control over financial reporting. ITEM 9(B). OTHER INFORMATION. None. 11 HALLIBURTON COMPANY MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS EXECUTIVE OVERVIEW States Department of Defense and other governmental The past year was marked with several milestones, agencies, including worldwide United States Army logistics including: contracts, known as LogCAP, and contracts to rebuild Iraq’s – the finalization of our asbestos and silica settlements petroleum industry, known as RIO and PCO Oil South. and our subsidiaries’ related emergence from Chapter Total revenue from the United States Government for 2004 11 proceedings. We funded the trusts in January 2005 includes $8.0 billion, or 39% of consolidated revenue, and with $2.3 billion in cash and 59.5 million shares of our revenue related to Iraq (which includes Kuwait) totaled common stock. We received approximately $1.0 billion approximately $7.1 billion, or 35% in 2004. in cash during January 2005 under the terms of our Detailed discussions of asbestos and silica, our United insurance settlement agreements; States government contract work, the Nigerian joint – achieving record revenue of over $20 billion, driven by venture and investigations, the Barracuda-Caratinga our government services work in the Middle East and project, and our liquidity and capital resources follow. Our strong performance in our Energy Services Group, operating performance, including our recent restructuring where we increased our international presence. Our of KBR, is described in “Business Environment and Results Energy Services Group also had record levels of of Operations” below. revenue, operating income, and operating margins; Looking ahead, the outlook for our business is positive. – reaching an important agreement with our customer Current market conditions for our energy services for the Barracuda-Caratinga project, which settled all business are good with strong commodity prices, and our claims and change orders, as well as adjusted the customers are increasing their exploration and production project scope and various milestone dates. We also budgets. We are well-positioned in sectors that are experi- achieved 92% project completion as a result of the encing particularly strong activity, such as United States Barracuda vessel producing first oil and the Caratinga onshore gas, and in areas that could experience increased vessel moving offshore for sea trials and final inspec- activity in the near term, such as the deepwater Gulf of tions. Subsequently, the Caratinga vessel achieved Mexico. In addition to the benefits expected from our first oil in February 2005; recent restructuring initiative at KBR, we will continue to – restructuring KBR, which we expect will yield pursue our natural gas monetization strategy and push between $80 million and $100 million in annual forward on the definitization process of our United States savings; and government contracts in the Middle East. Finally, now that – addressing our liquidity needs in anticipation of we have resolved our asbestos and silica liability and our funding the asbestos and silica trusts while managing affected subsidiaries have exited Chapter 11 reorganization our working capital position related to our government proceedings, we intend to separate KBR from Halliburton, services work in the Middle East. This included which could include a transaction involving a spin-off, split- utilizing two accounts receivable facilities during 2004, off, public offering, or sale of KBR or its operations. In issuing $500 million of senior notes due 2007 in order to maximize KBR’s value for our shareholders and to January 2004, maintaining one revolving credit facility, determine the most appropriate form of the transaction and and arranging a new $500 million revolving credit its components, it may be necessary for KBR to establish a facility during 2004. As of December 31, 2004, the two track record of positive earnings for a number of quarters revolving credit facilities had available credit totaling and to seek resolution of governmental issues, contract $1.028 billion. investigations, and other disputes. During 2004, we continued to provide substantial work under our government contracts business to the United 12 Asbestos and Silica Obligations and Insurance Recoveries Prepackaged Chapter 11 proceedings. DII Industries, Kellogg Brown & Root, Inc. (Kellogg Brown & Root), and six other subsidiaries (Mid-Valley, Inc.; KBR Technical Services, Inc.; Kellogg Brown & Root Engineering Corporation; Kellogg Brown & Root International, Inc. (a Delaware corporation); Kellogg Brown & Root International, Inc. (a Panamanian corporation); and BPM Minerals, LLC) filed Chapter 11 proceedings on December 16, 2003 in bankruptcy court in Pittsburgh, Pennsylvania. Each of these entities was a wholly owned subsidiary of Halliburton before, during, and after the bankruptcy proceedings became final. Our subsidiaries sought Chapter 11 protection to avail themselves of the provisions of Sections 524(g) and 105 of the Bankruptcy Code to discharge current and future asbestos and silica personal injury claims against us and our subsidiaries. The order confirming the plan of reorgani- zation became final and nonappealable on December 31, 2004, and the plan of reorganization became effective in January 2005. Under the plan of reorganization, all current and future asbestos and silica personal injury claims against us and our affiliates were channeled into trusts established for the benefit of asbestos and silica claimants, thus releasing us from those claims. In accordance with the plan of reorganization, in January 2005 we contributed the following to trusts for the benefit of current and future asbestos and silica personal injury claimants: – approximately $2.345 billion in cash, which represents the remaining portion of the $2.775 billion total cash settlement after payments of $311 million in December 2003 and $119 million in June 2004; – 59.5 million shares of Halliburton common stock; – a one-year non-interest-bearing note of $31 million for the benefit of asbestos claimants. We prepaid the initial installment on the note of approximately $8 million in January 2005. The remaining note will be paid in three equal quarterly installments starting in the second quarter of 2005; and – a silica note with an initial payment into a silica trust of $15 million. Subsequently, the note provides that we will contribute an amount to the silica trust at the end of each year for the next 30 years of up to $15 million. The note also provides for an extension of the note for 20 additional years under certain circumstances. We have estimated the value of this note to be approxi- mately $24 million. We will periodically reassess our valuation of this note based upon our projections of the amounts we believe we will be required to fund into the silica trust. As a result of the filing of the Chapter 11 proceedings, we adjusted the asbestos and silica liability to reflect the amount of the proposed settlement and certain related costs, which resulted in a pre-tax charge of approximately $1.016 billion to discontinued operations in the fourth quarter of 2003. The tax effect on this charge was minimal, as a valuation allowance was established against the liability to reflect the expected net tax benefit from the future deductions the liability will create. In accordance with the definitive settlement agreements entered in early 2003, we reviewed plaintiff files to establish a medical basis for payment of settlement amounts and to establish that the claimed injuries were based on exposure to our products. In 2003, we concluded that substantially all the asbestos and silica liability related to claims filed against our former operations that have been divested and included in discontinued operations. Consequently, all 2003 and 2004 changes in our estimates related to the asbestos and silica liability were recorded through discontinued operations. Our plan of reorganization called for a portion of our total asbestos liability to be settled by contributing 59.5 million shares of Halliburton common stock to the trust. As of December 31, 2004, we revalued our shares to approxi- mately $2.335 billion ($39.24 per share), an increase of $778 million from December 31, 2003, and this amount was charged to discontinued operations on our consolidated statement of operations during 2004. Effective December 31, 2004, concurrent with receiving final and nonappealable confirmation of our plan of reorganization, we reclassified from a long-term liability to shareholders’ equity the final value of the 59.5 million shares of Halliburton common stock. If the shares had been included in the calculation of earnings per share as of the beginning of 2004, our diluted 13 earnings per share from continuing operations would have Our operations under United States government been reduced by $0.11 for 2004. contracts are regularly reviewed and audited by the Insurance settlements. During 2004, we settled insurance Defense Contract Audit Agency (DCAA) and other disputes with substantially all the insurance companies for governmental agencies. The DCAA serves in an advisory asbestos- and silica-related claims and all other claims role to our customer. When issues are found during the under the applicable insurance policies and terminated all governmental agency audit process, these issues are the applicable insurance policies. Under the terms of our typically discussed and reviewed with us. The DCAA then insurance settlements, we will receive cash proceeds with a issues an audit report with their recommendations to our nominal amount of approximately $1.5 billion and with a customer’s contracting officer. In the case of management present value of approximately $1.4 billion for our asbestos- systems and other contract administrative issues, the and silica-related insurance receivables. The present value contracting officer is generally with the Defense Contract was determined by discounting the expected future cash Management Agency (DCMA). We then work with our payments with a discount rate implicit in the settlements, customer to resolve the issues noted in the audit report. which ranged from 4.0% to 5.5%. Beginning in the third Given the demands of working in Iraq and elsewhere for quarter of 2004, this discount is being accreted as interest the United States government, we expect that from time to income (classified as discontinued operations) over the life time we will have disagreements or experience perform- of the expected future cash payments. Cash payments of ance issues with the various government customers for approximately $1.0 billion related to these receivables were which we work. If our performance is unacceptable to our received in January 2005. Under the terms of the settle- customer under any of our government contracts, the ment agreements, we will receive cash payments of the government retains the right to pursue remedies under any remaining amounts in several installments beginning in affected contract, which remedies could include threatened July 2005 through 2009. termination or termination. If any contract were so Our December 31, 2003 estimate of our asbestos- and terminated, we may not receive award fees under the silica-related insurance receivables already included a affected contract, and our ability to secure future contracts charge for the settlement amount under an agreement could be adversely affected, although we would receive reached in January 2004, as well as certain other probable payment for amounts owed for our allowable costs under settlements with companies for which we could reasonably cost-reimbursable contracts. estimate the amount of the settlement. During 2004, we Fuel. In December 2003, the DCAA issued a preliminary reduced the amount recorded as insurance receivables for audit report that alleged that we may have overcharged the asbestos- and silica-related liabilities insured by other Department of Defense by $61 million in importing fuel companies based upon the final agreements, resulting in into Iraq. The DCAA questioned costs associated with fuel pretax charges to discontinued operations of approximately purchases made in Kuwait that were more expensive than $698 million. United States Government Contract Work We provide substantial work under our government contracts business to the United States Department of Defense and other governmental agencies, including worldwide United States Army logistics contracts, known as LogCAP, and contracts to rebuild Iraq’s petroleum industry, known as RIO and PCO Oil South. Our govern- ment services revenue related to Iraq totaled approximately $7.1 billion in 2004 and approximately $3.6 billion in 2003. buying and transporting fuel from Turkey. We responded that we had maintained close coordination of the fuel mission with the Army Corps of Engineers (COE), which was our customer and oversaw the project, throughout the life of the task order and that the COE had directed us to use the Kuwait sources. After a review, the COE concluded that we obtained a fair price for the fuel. However, Department of Defense officials thereafter referred the matter to the agency’s inspector general, which we understand has commenced an investigation. 14 The DCAA has issued various audit reports related to In October 2004, a civilian contracting official in the task orders under the RIO contract that reported $304 COE asked for a review of the process used by the COE for million in questioned and unsupported costs. The majority awarding some of the contracts to us. We understand that of these costs are associated with the humanitarian fuel the Department of Defense Inspector General’s office may mission. In these reports, the DCAA has compared fuel review the issues involved. costs we incurred during the duration of the RIO contract We understand that the United States Department of in 2003 and early 2004 to fuel prices obtained by the Justice, an Assistant United States Attorney based in Defense Energy Supply Center (DESC) in April 2004 when Illinois, and others are investigating these and other the fuel mission was transferred to that agency. We are individually immaterial matters we have reported relating working with our customer to resolve this issue. to our government contract work in Iraq. We also under- Investigations. On January 22, 2004, we announced the stand that current and former employees of KBR have identification by our internal audit function of a potential received subpoenas and have given or may give grand jury overbilling of approximately $6 million by La Nouvelle testimony relating to some of these matters. If criminal Trading & Contracting Company, W.L.L. (La Nouvelle), one wrongdoing were found, criminal penalties could range up of our subcontractors, under the LogCAP contract in Iraq, to the greater of $500,000 in fines per count for a corpora- for services performed during 2003. In accordance with our tion, or twice the gross pecuniary gain or loss. policy and government regulation, the potential overcharge Dining Facility and Administration Centers (DFACs). During was reported to the Department of Defense Inspector 2003, the DCAA raised issues relating to our invoicing to General’s office as well as to our customer, the AMC. On the Army Materiel Command (AMC) for food services for January 23, 2004, we issued a check in the amount of $6 soldiers and supporting civilian personnel in Iraq and million to the AMC to cover that potential overbilling while Kuwait. We believe the issues raised by the DCAA relate to we conducted our own investigation into the matter. Later the difference between the number of troops the AMC in the first quarter of 2004, we determined that the amount directed us to support and the number of soldiers counted of overbilling was $4 million, and the subcontractor billing at dining facilities for United States troops and supporting should have been $2 million for the services provided. As a civilian personnel. In the first quarter of 2004, we reviewed result, we paid La Nouvelle $2 million and billed our our DFAC subcontracts in our Iraq and Kuwait areas of customer that amount. We subsequently terminated La operation and have billed and continue to bill for all current Nouvelle’s services under the LogCAP contract. In October DFAC costs. During 2004, we received notice from the 2004, La Nouvelle filed suit against us alleging $224 million DCAA that it was recommending withholding a portion of in damages as a result of its termination. We are continuing our DFAC billings. For DFAC billings relating to subcon- to investigate whether La Nouvelle paid, or attempted to tracts entered into prior to February 2004, the DCAA has pay, one or two of our former employees in connection with recommended withholding 19.35% of the billings until it the billing. See Note 13 to our consolidated financial completes its audits. Subsequent to February 2004, we statements for further discussion. renegotiated our DFAC subcontracts to address the In October 2004, we reported to the Department of specific issues raised by the DCAA and advised the AMC Defense Inspector General’s office that two former and the DCAA of the new terms of the arrangements. We employees in Kuwait may have had inappropriate contacts have had no objection by the government to the terms and with individuals employed by or affiliated with two third- conditions associated with these new DFAC subcontract party subcontractors prior to the award of the subcontracts. agreements. During the third quarter of 2004, we received The Inspector General’s office may investigate whether notification that, for three Kuwait DFACs, the DCAA these two employees may have solicited and/or accepted recommended to our customer that costs be disallowed payments from these third-party subcontractors while they because the DCAA is not satisfied with the level of docu- were employed by us. mentation provided by us. The amount withheld related to 15 suspended and recommended disallowed DFAC costs for As of December 31, 2004, the COE had withheld $85 work performed prior to February 2004 and totaled million of our invoices related to a portion of our RIO approximately $224 million as of December 31, 2004. The contract pending completion of the definitization process. amount withheld could change as the DCAA continues All 10 definitization proposals required under this contract their audits of the remaining DFAC facilities. We are have been submitted by us, and three have been finalized negotiating with our customer, the AMC, to resolve this through a task order modification. After review by the issue. We are currently withholding a proportionate DCAA, we have resubmitted five of the unfinalized seven amount of these billings from our subcontractors. proposals and are in the process of developing revised Laundry. During the third quarter of 2004, we received proposals for the remaining two. These withholdings notice from the DCAA that it recommended withholding represent the amount invoiced in excess of 85% of the $16 million of subcontract costs related to the laundry funding in the task order. The COE also could withhold service for one task order in southern Iraq for which it similar amounts from future invoices under our RIO believes we and our subcontractors have not provided contract until agreement is reached with the customer and adequate levels of documentation supporting the quantity task order modifications are issued. Approximately $2 of the services provided. The DCAA recommended that the million was withheld from our PCO Oil South project as of cost be withheld pending receipt of additional explanation December 31, 2004. The PCO Oil South project has or documentation to support subcontract cost. This $16 definitized 15 of the 28 task orders and withholdings are million was withheld from the subcontractor in the fourth not continuing on those task orders. We do not believe the quarter of 2004. We are working with the AMC to resolve withholding will have a significant or sustained impact on this issue. our liquidity because the withholding is temporary and Withholding of payments. During 2004, the AMC issued a ends once the definitization process is complete. determination that a particular contract clause could cause In addition, we had unapproved claims totaling $93 it to withhold 15% from our invoices until our task orders million at December 31, 2004 for the LogCAP, RIO, and under the LogCAP contract are definitized. The AMC PCO Oil South contracts. These unapproved claims related delayed implementation of this withholding pending further to contracts where our costs have exceeded the funded review. The Army Field Support Command (AFSC) has value of the task order or were related to lost, damaged, now been delegated authority by the AMC to determine and destroyed equipment. whether or not to implement the withholding. The AFSC We are working diligently with our customers to has informed us that it will assess the situation on a task proceed with significant new work only after we have a fully order by task order basis and, currently, withholding will definitized task order, which should limit withholdings on continue to be delayed. We do not believe any potential 15% future task orders. withholding will have a significant or sustained impact on Cost reporting. We have received notice that a contracting our liquidity because any withholding is temporary and officer for our PCO Oil South project considers our ends once the definitization process is complete. During monthly categorization and detail of costs and our ability to the third quarter of 2004, we and the AMC identified three schedule and forecast costs to be inadequate, and he has senior management teams to facilitate negotiation under requested corrections be made by March 10, 2005. We the LogCAP task orders, and these teams are working to expect to be able to make the requested corrections. If we negotiate outstanding issues and definitize task orders as were unable to satisfy our customer, our customer may quickly possible. We are continuing to work with our pursue remedies under the applicable federal acquisition customer to resolve outstanding issues. As of January 18, regulations, including terminating the affected contract. 2005, 25 task orders for LogCAP totaling over $636 million Although there can be no assurances, we do not expect that have been definitized. our work on the PCO Oil South project will be terminated for default. We are in the process of developing an accept- 16 able management cost reporting system and are supple- a formal investigation into payments made in connection menting the existing PCO cost reporting team with with the construction and subsequent expansion by TSKJ additional manpower. of a multibillion dollar natural gas liquefaction complex and Report on estimating system. On December 27, 2004, the related facilities at Bonny Island in Rivers State, Nigeria. DCMA granted continued approval of our estimating The United States Department of Justice is also conducting system, stating that our estimating system is “acceptable an investigation. TSKJ is a private limited liability company with corrective action.” We are in process of completing registered in Madeira, Portugal whose members are these corrective actions. Specifically, based on the unprece- Technip SA of France, Snamprogetti Netherlands B.V., dented level of support our employees are providing the which is an affiliate of ENI SpA of Italy, JGC Corporation of military in Iraq, Kuwait, and Afghanistan, we needed to Japan, and Kellogg Brown & Root, each of which owns 25% update our estimating policies and procedures to make of the venture. them better suited to such contingency situations. The SEC and the Department of Justice have been Additionally, we are in process of developing a detailed reviewing these matters in light of the requirements of the training program that will be made available to all estimat- United States Foreign Corrupt Practices Act (FCPA). We ing personnel to ensure that employees are adequately have produced documents to the SEC both voluntarily and prepared to deal with the challenges and unique circum- pursuant to subpoenas, and intend to make our employees stances associated with a contingency operation. available to the SEC for testimony. In addition, we under- Report on purchasing system. As a result of a Contractor stand that the SEC has issued a subpoena to A. Jack Purchasing System Review by the DCMA during the Stanley, who most recently served as a consultant and second quarter of 2004, the DCMA granted the continued chairman of Kellogg Brown & Root, and to other current approval of our government contract purchasing system. and former Kellogg Brown & Root employees. We further The DCMA’s approval letter, dated September 7, 2004, understand that the Department of Justice has invoked its stated that our purchasing system’s policies and practices authority under a sitting grand jury to obtain letters are “effective and efficient, and provide adequate protection rogatory for the purpose of obtaining information abroad. of the Government’s interest.” TSKJ and other similarly owned entities entered into The Balkans. We have had inquiries in the past by the various contracts to build and expand the liquefied natural DCAA and the civil fraud division of the United States gas project for Nigeria LNG Limited, which is owned by the Department of Justice into possible overcharges for work Nigerian National Petroleum Corporation, Shell Gas B.V., performed during 1996 through 2000 under a contract in Cleag Limited (an affiliate of Total), and Agip International the Balkans, which inquiry has not yet been completed by B.V., which is an affiliate of ENI SpA of Italy. Commencing the Department of Justice. Based on an internal investiga- in 1995, TSKJ entered into a series of agency agreements in tion, we credited our customer approximately $2 million connection with the Nigerian project. We understand that a during 2000 and 2001 related to our work in the Balkans as French magistrate has officially placed Jeffrey Tesler, a a result of billings for which support was not readily principal of Tri-Star Investments, an agent of TSKJ, under available. We believe that the preliminary Department of investigation for corruption of a foreign public official. In Justice inquiry relates to potential overcharges in connec- Nigeria, a legislative committee of the National Assembly tion with a part of the Balkans contract under which and the Economic and Financial Crimes Commission, approximately $100 million in work was done. We believe which is organized as part of the executive branch of the that any allegations of overcharges would be without merit. government, are also investigating these matters. Our Nigerian Joint Venture and Investigations Foreign Corrupt Practices Act investigation. The United States Securities and Exchange Commission (SEC) is conducting representatives have met with the French magistrate and Nigerian officials and expressed our willingness to cooperate with those investigations. In October 2004, 17 representatives of TSKJ voluntarily testified before the If violations of the FCPA were found, we could be Nigerian legislative committee. subject to civil penalties of $500,000 per violation, and As a result of our continuing investigation into these criminal penalties could range up to the greater of $2 matters, information has been uncovered suggesting that, million per violation or twice the gross pecuniary gain commencing at least 10 years ago, the members of TSKJ or loss. considered payments to Nigerian officials. We provided There can be no assurance that any governmental this information to the United States Department of Justice, investigation or our investigation of these matters will not the SEC, the French magistrate, and the Nigerian conclude that violations of applicable laws have occurred Economic and Financial Crimes Commission. We also or that the results of these investigations will not have a notified the other owners of TSKJ of the recently uncov- material adverse effect on our business and results of ered information and asked each of them to conduct their operations. own investigation. Bidding practices investigation. In connection with the We understand from the ongoing governmental and investigation into payments made in connection with the other investigations that payments may have been made to Nigerian project, information has been uncovered suggest- Nigerian officials. In addition, TSKJ has suspended the ing that Mr. Stanley and other former employees may have receipt of services from and payments to Tri-Star engaged in coordinated bidding with one or more competi- Investments and is considering instituting legal proceed- tors on certain foreign construction projects and that such ings to declare all agency agreements with Tri-Star coordination possibly began as early as the mid-1980s, Investments terminated and to recover all amounts which was significantly before our 1998 acquisition of previously paid under those agreements. Dresser Industries. We also understand that the matters under investigation On the basis of this information, we and the Department by the Department of Justice involve parties other than of Justice have broadened our investigations to determine Kellogg Brown & Root and M.W. Kellogg, Ltd. (a joint the nature and extent of any improper bidding practices, venture in which Kellogg Brown & Root has a 55% inter- whether such conduct violated United States antitrust laws, est), cover an extended period of time (in some cases and whether former employees may have received significantly before our 1998 acquisition of Dresser payments in connection with bidding practices on some Industries (which included M.W. Kellogg, Ltd.)), and foreign projects. possibly include the construction of a fertilizer plant in If violations of applicable United States antitrust laws Nigeria in the early 1990s and the activities of agents and occurred, the range of possible penalties includes criminal service providers. fines, which could range up to the greater of $10 million in In June 2004, we terminated all relationships with Mr. fines per count for a corporation, or twice the gross Stanley and another consultant and former employee of pecuniary gain or loss, and treble civil damages in favor of M.W. Kellogg, Ltd. The terminations occurred because of any persons financially injured by such violations. If such violations of our Code of Business Conduct that allegedly violations occurred, the United States government also involve the receipt of improper personal benefits in would have the discretion to deny future government connection with TSKJ’s construction of the natural gas contracts business to KBR or affiliates or subsidiaries of liquefaction facility in Nigeria. KBR. Criminal prosecutions under applicable laws of In February 2005, TSKJ notified the Attorney General of relevant foreign jurisdictions and civil claims by or relation- Nigeria that TSKJ would not oppose the Attorney General’s ship issues with customers are also possible. efforts to have sums of money held on deposit in banks in There can be no assurance that the results of these Switzerland transferred to Nigeria and to have the legal investigations will not have a material adverse effect on our ownership of such sums determined in the Nigerian courts. business and results of operations. 18 Barracuda-Caratinga Project – the performance by Petrobras of certain work under In June 2000, Kellogg Brown & Root, Inc. entered into a the original contract; contract with Barracuda & Caratinga Leasing Company – the repayment by Kellogg Brown & Root of $300 B.V., the project owner, to develop the Barracuda and million of advance payments by the end of February Caratinga crude oilfields, which are located off the coast of 2005, with interest on $74 million. Of this amount, $79 Brazil. The construction manager and project owner’s million was paid in 2004; and representative is Petrobras, the Brazilian national oil – revised milestones and other dates, including settle- company. When completed, the project will consist of two ment of liquidated damages and an extension of time converted supertankers, Barracuda and Caratinga, which to the FPSO final acceptance dates. will be used as floating production, storage, and offloading As of December 31, 2004: units, commonly referred to as FPSOs. In addition, there – the project was approximately 92% complete; will be 32 hydrocarbon production wells, 22 water injection – we have recorded an inception-to-date loss of $762 wells, and all subsea flow lines, umbilicals, and risers million related to the project, of which $407 million necessary to connect the underwater wells to the FPSOs. was recorded in 2004, $238 million was recorded in The original completion date for the Barracuda vessel was 2003, and $117 million was recorded in 2002; December 2003, and the original completion date for the – the losses recorded include an estimated $24 million Caratinga vessel was April 2004. The project has been in liquidated damages based on the final agreement significantly behind the original schedule, due in part to with Petrobras; and change orders from the project owner, and is in a financial – the probable unapproved claims were reduced from loss position. $114 million at December 31, 2003 to zero based upon In December 2004, the Barracuda vessel achieved first the final agreement with Petrobras. oil after being moved offshore for sea trials and final Cash flow considerations. We have now begun to fund inspections in October 2004 and the Caratinga vessel was operating cash shortfalls on the project and are obligated to moved offshore for sea trials and final inspections. The fund total shortages over the remaining project life. Caratinga vessel achieved first oil in February 2005. Estimated cash flows relating to the losses are as follows: Pursuant to the settlement agreement with Petrobras described below, the Barracuda vessel must be completed by March 31, 2006, and the Caratinga vessel must be completed by June 30, 2006. While we anticipate meeting these completion targets, there can be no assurance that further delays will not occur. Millions of dollars Amount funded through December 31, 2004 Amounts to be paid/(received) in 2005: Remaining repayment of $300 million advance Payment to us relating to change orders Remaining project costs, net of revenue to be received Total cash shortfalls $586 221 (138) 93 $762 Also in December 2004, Kellogg Brown & Root and LIQUIDITY AND CAPITAL RESOURCES Petrobras, on behalf of the project owner, reached an We ended 2004 with cash and cash equivalents of $2.8 agreement to settle various claims between the parties. The billion compared to $1.8 billion at the end of 2003. Our cash agreement provides for: and cash equivalents balance at the end of January 2005, – the release of all claims of all parties that arise prior to after funding of the asbestos and silica liability trusts and the effective date of a final definitive agreement; receipt of insurance proceeds discussed below, was – a payment to us in 2005 of $79 million as a result of approximately $1.7 billion. change orders for remaining claims; Significant sources of cash. Our liquidity position was – payment by Petrobras of applicable value added taxes strong at the end of 2004 due to our positive cash flow from on the project, except for $8 million which has been operations, new debt financing, sales of accounts receiv- paid by us; able, and our controlled capital spending in 2004. Our operations provided approximately $928 million in cash 19 flow in 2004, including the sale of accounts receivable which replaced a letter of credit expiring on our Barracuda- discussed below. In addition, our cash flow was supple- Caratinga project, thus reducing the availability under that mented by cash totaling $126 million from the sale of our revolving credit facility to $528 million. There were no cash surface well testing operations in August 2004 and $20 drawings under the $700 million revolving credit facility or million from the sale of our remaining shares of National the $500 million 364-day revolving credit facility as of Oilwell, Inc. in February 2004. December 31, 2004. In January 2004, we issued senior notes due 2007 Asbestos and silica settlements with insurance companies. totaling $500 million, which were issued in anticipation of During 2004, we settled insurance disputes with substan- funding the asbestos and silica liability trusts. Our com- tially all the insurance companies for asbestos- and bined short-term notes payable and long-term debt was 50% silica-related claims and all other claims under the applica- of total capitalization at December 31, 2004, compared to ble insurance policies and terminated all the applicable 58% at the end of 2003 and 30% at the end of 2002. While insurance policies. Under the terms of our insurance our debt balance increased, the decrease in our ratio of settlements, we expect to receive cash proceeds with debt-to-total-capitalization was due to the reclassification to a nominal value of $1.5 billion and a present value of shareholders’ equity of the value of the 59.5 million shares approximately $1.4 billion for our asbestos- and silica- to be contributed to the asbestos trust in our consolidated related insurance receivables as follows: balance sheet as of December 31, 2004. In May 2004, we entered into an agreement to sell, assign, and transfer the entire title and interest in specified United States government accounts receivable of KBR to a third party. The total amount outstanding under this agreement as of December 31, 2004 was approximately $263 million. Subsequent to year-end 2004, these receiv- Millions of dollars 2005 2006 2007 2008 2009 Thereafter Total $1,066 162 40 45 131 16 $1,460 ables were collected and the balance retired, and we are We received approximately $1.0 billion in insurance not currently selling further receivables, although the proceeds in January 2005. We intend to use a substantial facility continues to be available. portion of these proceeds to reduce debt. In June 2004, we sold undivided interests totaling Other. In January 2005, we received approximately $200 $268 million under our Energy Services Group securitiza- million in cash proceeds from the sale of our 50% interest tion facility. As of December 31, 2004, we have $256 in Subsea 7, Inc. million outstanding under this facility. See “Off Balance In June 2004, a Texas district court jury returned a Sheet Risk” below for further discussion regarding verdict in our favor in connection with a patent infringe- these facilities. ment lawsuit we filed against Smith International (Smith) in Future sources of cash. We have available to us significant September 2002. We were awarded $41 million in damages sources of cash in the near term should we need them. and legal fees by the court. Because the verdict is currently Revolving credit facilities. In the fourth quarter of 2003, we under appeal by Smith, the timing of ultimate collection of entered into a secured $700 million three-year revolving this award is uncertain. credit facility for general working capital purposes. In July Significant uses of cash. Our liquidity and cash balance 2004, we entered into an additional secured $500 million during 2004 were significantly affected by our government 364-day revolving credit facility for general working capital services work in Iraq. Our working capital requirements for purposes with terms substantially similar to our $700 our Iraq-related work, excluding cash and equivalents, million revolving credit facility. As of December 31, 2004, were down from $885 million at the end of 2003 to approxi- we had issued a letter of credit for approximately $172 mately $700 million at December 31, 2004. We do not million under the $700 million revolving credit facility, 20 expect a further increase in our working capital invest- Payments due ments above that amount. In connection with reaching an agreement with repre- sentatives of asbestos and silica claimants to limit the cash required to settle pending claims to $2.775 billion, DII Millions of dollars Long-term debt (1) $ 347 $293 $518 $156 $ – Asbestos and silica 2005 2006 2007 2008 2009 Thereafter settlement payment Operating leases Purchase 2,345 158 – 125 – 104 – 92 – 82 Industries paid $311 million to the claimants in December obligations (3) 363 18 18 18 12 $2,625 – 453 11 – – Total $3,939 2,345 1,014 440 176 77 176 77 – – – – – – – – Barracuda- Caratinga Pension funding obligations Asbestos insurance partitioning agreement Asbestos note Silica note (2) RHI Refractories Total 16 31 15 11 – – 1 – $3,539 $452 $656 $267 $95 15 – 1 – 15 – 1 – – – 1 – – – 5 – $3,094 46 31 24 11 $8,103 (1) Long-term debt excludes the effect of a terminated interest rate swap of approximately $5 million. See Note 10 to the consolidated financial statements for further discussion. (2) Subsequent to the initial payment of $15 million, the silica note provides that we will contribute an amount to the silica trust at the end of each year for the next 30 years of up to $15 million. The note also provides for an extension of the note for 20 additional years under certain circumstances. We have recorded the note at our estimated amount of approximately $24 million. We will periodically reassess our valuation of this note based upon our projections of the amounts we believe we will be required to fund into the silica trust. (3) The purchase obligations disclosed above do not include purchase obligations that KBR enters into with its vendors in the normal course of business that support existing contracting arrangements with its customers. The purchase obligations with their vendors can span several years depending on the duration of the projects. In general, the costs associated with the purchase obligations are expensed as the revenue is earned on the related projects. Capital spending for 2005 is expected to be approxi- mately $650 million. The capital expenditures budget for 2005 includes increased activities at our DML shipyard, software spending as KBR moves forward with the implementation of SAP, and higher spending in the Energy Services Group to accommodate increased business. As of December 31, 2004, we had commitments to fund approximately $58 million to certain of our related compa- nies. These commitments arose primarily during the start-up of these entities or due to losses incurred by them. We expect approximately $42 million of the commitments $2,345 to be paid during the next year. Other factors affecting liquidity 16 15 11 Letters of credit. In the normal course of business, we have agreements with banks under which approximately $1.1 billion of letters of credit or bank guarantees were outstand- ing as of December 31, 2004 including $264 million which relate to our joint ventures’ operations. Also included in 2003, plus an additional $22 million in lieu of interest. We also agreed to guarantee the payment of certain claims, and, in accordance with settlement agreements, we made additional payments of $119 million, plus an additional $4 million in lieu of interest, in June 2004. Capital expenditures of $575 million in 2004 were 12% higher than in 2003. Capital spending in 2004 continued to be primarily directed to the Energy Services Group for Production Optimization, Drilling and Formation Evaluation, and manufacturing capacity. We paid $221 million in dividends to our shareholders in 2004 compared to $219 million in 2003 and 2002. In April 2004, we paid the $107 million judgment amount in the BJ Services Company patent litigation, including pre- and post-judgment interest, with the funds that had been used to post bond in the case. In April 2004, we also reached a settlement with the plaintiffs in the Anglo-Dutch (Tenge) litigation and made all payments pursuant to the settlement agreement. During the second quarter of 2004, we recovered the $25 million cash-in-lieu-of-bond deposit for the Anglo-Dutch (Tenge) litigation formerly included in restricted cash. Future use of cash. In January 2005, we made the following payments for our asbestos and silica liability settlement: Millions of dollars Cash payments made in Januar y 2005: Payment to the asbestos and silica trust in accordance with the plan of reorganization Cash payment related to insurance partitioning agreement reached with Federal-Mogul in October 2004 – first of three installments First installment payment for the silica note Payments related to RHI Refractories agreement First of four installment payments for the one-year non-interest-bearing note of $31 million for the benefit of asbestos claimants Total cash payments made in January 2005 8 $2,395 The following table summarizes our significant contrac- letters of credit outstanding as of December 31, 2004 and tual obligations and other long-term liabilities as of related to the Barracuda-Caratinga project were $277 December 31, 2004: million of performance letters of credit and $176 million of retainage letters of credit. Certain of the outstanding letters 21 of credit have triggering events which would entitle a bank to require cash collateralization. BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS In the fourth quarter of 2003, we entered into a senior secured master letter of credit facility (Master LC Facility) with a syndicate of banks which covered at least 90% of the face amount of our existing letters of credit. The facility expired on December 31, 2004 due to our plan of reorgani- zation becoming final and nonappealable. We did not have any outstanding advances under the Master LC Facility when it expired. Upon the expiration of the Master LC Facility, all letters of credit under the facility reverted back to the original agreements with the individual banks. Debt covenants. Certain of our letters of credit, our $700 million revolving credit facility, and our $500 million 364- day revolving credit facility contain restrictive covenants including covenants that require us to maintain certain financial ratios as defined by the agreements. For certain of our letters of credit and the two revolving credit facilities we are required to maintain an interest coverage ratio of 3.5 or greater and a leverage ratio less than or equal to 0.55. At December 31, 2004, our interest coverage ratio was 7.18 and our leverage ratio was 0.42. Borrowings under the revolving credit facilities will be secured by certain of our assets until our long-term senior unsecured debt is rated BBB or higher (stable outlook) by Standard & Poor’s and Baa2 or higher (stable outlook) by Moody’s Investors Service. To the extent that the aggregate principal amount of all secured indebtedness exceeds 5% of the consolidated net tangible assets of Halliburton and its subsidiaries, all collateral will be shared pro rata with holders of Halliburton’s 8.75% debentures due 2021, 3.125% convert- ible senior notes due 2023, senior notes due 2005, 5.5% senior notes due 2010, medium-term notes, 7.6% deben- tures due 2096, senior notes issued in January 2004 due 2007, and any other new issuance, to the extent that the issuance contains a requirement that the holders thereof be equally and ratably secured with Halliburton’s other secured creditors. At December 31, 2004, 5% of our consolidated net tangible assets as calculated based on the agreement was $392 million, and the total aggregate amount of our secured debt outstanding was approximately $50 million. 22 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 revenue is derived from the sale of services and products, including engineering and construction activities. We sell services and products primarily to major, national, and independent oil and gas companies and the United States government. The products and services provided to the major, national, and independent oil and gas companies are used throughout the energy industry from the earliest phases of exploration, development, and production of oil and gas resources through refining, processing, and marketing. Our six business segments are organized around how we manage the business: Production Optimization, Fluid Systems, Drilling and Formation Evaluation, Digital and Consulting Solutions, Government and Infrastructure, and Energy and Chemicals. We refer to the combination of Production Optimization, Fluid Systems, Drilling and Formation Evaluation, and Digital and Consulting Solutions segments as the Energy Services Group, and the combination of Government and Infrastructure and Energy and Chemicals as KBR. The industries we serve are highly competitive, with many substantial competitors for each segment. In 2004, based upon the location of the services provided and products sold, 26% of our consolidated revenue was from Iraq, primarily related to our work for the United States government, and 22% of our consolidated revenue was from the United States. In 2003, 27% of our consolidated revenue was from the United States and 15% of our consolidated revenue was from Iraq. No other country accounted for more than 10% of our revenue during these periods. Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil unrest, force majeure, war or other armed conflict, expropriation or other governmental actions, inflation, exchange controls, or currency devaluation. Except for our government services work in Iraq discussed above, we believe the geographic diversification of our business activities reduces the risk that loss of operations in any one The yearly average rig counts based on the Baker country would be material to our consolidated results of Hughes Incorporated rig count information are as follows: operations. Halliburton Company Activity levels within our business segments are significantly impacted by the following: – spending on upstream exploration, development, and production programs by major, national, and independ- Average Rig Counts Land vs. Offshore United States: Land Offshore Total Canada: Land Offshore Total ent oil and gas companies; International (excluding Canada): – capital expenditures for downstream refining, process- ing, petrochemical, and marketing facilities by major, national, and independent oil and gas companies; and – government spending levels. Land Offshore Total Worldwide total Land total Offshore total Also impacting our activity is the status of the global economy, which indirectly impacts oil and gas consump- Average Rig Counts Oil vs. Gas United States: tion, demand for petrochemical products, and investment in infrastructure projects. Energy Services Group Oil Gas Total Canada:* International (excluding Canada): Some of the more significant barometers of current and future spending levels of oil and gas companies are oil and Oil Gas Total gas prices, exploration and production activities by Worldwide total 2004 2003 2002 1,093 97 1,190 365 4 369 594 242 836 2,395 2,052 343 924 108 1,032 368 4 372 544 226 770 2,174 1,836 338 718 113 831 260 6 266 507 225 732 1,829 1,485 344 2004 2003 2002 165 1,025 1,190 369 648 188 836 2,395 157 875 1,032 372 576 194 770 2,174 137 694 831 266 561 171 732 1,829 international and national oil companies, the world econ- omy, and global stability, which together drive worldwide drilling activity. Our Energy Services Group financial performance is significantly affected by oil and gas prices and worldwide rig activity which are summarized in the following tables. This table shows the average oil and gas prices for West Texas Intermediate crude oil and Henry Hub natural gas prices: *Canadian rig counts by oil and gas were not available. Our customers’ cash flows, in many instances, depend upon the revenue they generate from sale of oil and gas. With higher prices, they may have more cash flow, which usually translates into higher exploration and production budgets. Higher prices may also mean that oil and gas exploration in marginal areas can become attractive, so our customers may consider investing in such properties when prices are high. When this occurs, it means more potential work for us. The opposite is true for lower oil Average Oil and Gas Prices West Texas Intermediate 2004 2003 2002 and gas prices. oil prices (dollars per barrel) $41.31 $31.14 $25.92 Over 2004, oil prices trended upward to over $50 per Henry Hub gas prices (dollars per million cubic feet) $ 5.85 $ 5.63 $ 3.33 barrel in October due to low petroleum inventory levels in the United States and Organization for Economic Cooperation and Development countries, uncertainties caused by potential disruption of crude supplies in Iraq, Russia, Saudi Arabia, Nigeria, Norway, and Venezuela, and increased demand in the United States and Asia markets reflecting improved year-over-year economies. Since October, prices have retreated somewhat as the Organization of the Petroleum Exporting Countries 23 increased production in order to restock low inventories, reduced activity, discounts normally increase, reducing the and more than half of the production capacity that was net revenue for our services and conversely, during periods closed because of Hurricane Ivan in September has been of higher activity, discounts normally decline resulting in reopened. On average, natural gas prices in 2004 gained net revenue increasing for our services. some ground compared to the already-elevated prices of In May 2004, we implemented United States price book 2003. As high oil costs have promoted switching to natural increases ranging between 5% and 8%, followed in October gas as a fuel substitute, demand for natural gas has by an 11% United States price book increase in our pump- strengthened. Thus, higher petroleum prices have lifted ing services. We worked diligently to minimize the impact natural gas prices, despite the fact that natural gas in of inflationary pressures in our cost base in 2004 and are storage is at the upper end of the five-year average. maintaining a steady focus on capital discipline. Additionally, there are still large volumes of Gulf Coast gas Consequently, we expect to realize continued benefits of supply which remain offline due to Hurricane Ivan damage. these price book increases in 2005. Most of our work in the Energy Services Group closely We have made a decision to be very selective about tracks the number of active rigs. As rig count increases or pursuing turn-key drilling projects in the future. As has decreases, so does the total available market for our been experienced within the energy services industry, services and products. Further, our margins associated these types of projects are inherently risky and may not with services and products for offshore rigs are generally provide sufficient upside to offset this risk. higher than those associated with land rigs. Overall outlook. Strong growth in the demand for oil Heightened demand coupled with high petroleum and worldwide, particularly in China, India, and other develop- natural gas prices in 2004 contributed to a 10% increase in ing countries, is generally cited as the driving force behind average worldwide rig count compared to 2003. This the sharp oil price increases seen over the past three years. increase was primarily driven by the United States rig The single most important factor behind high prices in count, which grew 15% year-over-year. Land gas drilling in 2004 was the largest annual gain in world oil demand since the United States rose sharply, as gas prices remained high 1978. The Energy Information Administration forecasts due to economic demand growth, severe weather disrup- world petroleum demand growth for 2005-2006 to remain tions in the Gulf of Mexico, and higher fuel oil prices that strong but down from the demand growth seen in 2004. discouraged switching to a lower-priced fuel source to Based on its exploration and production expenditure minimize cost. Average Canadian rig counts remained survey for 2005, Lehman Brothers expects worldwide relatively flat year-over-year. Outside of North America, exploration and production spending in 2005 to increase average rig counts increased in Latin America, Asia Pacific, over 2004 spending, predominantly in the United States and and the Middle East, with the entire increase related to oil Canada. Spears and Associates predicted that operators as production. In Europe, where average rig counts declined a group will increase their activity in terms of rigs, wells, compared to 2003, oil company dissatisfaction with high and footage in the range of 4% to 6% in most regions in operating costs and inconsistent government policies 2005. Spears and Associates forecasted a 4% increase in impeded exploration and production recovery. United States rigs, with a 5% rise offshore. Thus, the three- It is common practice in the United States oilfield year downturn in the United States offshore rig count is services industry to sell services and products based on a expected to end in 2005. International drilling activity is price book and then apply discounts to the price book predicted to turn in another solid year of growth in 2005, based upon a variety of factors. The discounts applied with Spears and Associates projecting a 5% increase in typically increase to partially or substantially offset price international rig count. book increases in the weeks immediately following a price We are well-positioned in the strong growth sectors increase. The discount applied normally decreases over noted above. In pressure pumping, we have a leading share time if the activity levels remain strong. During periods of of the United States onshore gas market. We are also well- 24 positioned in the offshore segments that could experience Within our Energy and Chemicals segment, the major a rebound over the next several quarters, particularly the focus is on our gas monetization work. Forecasted LNG deepwater Gulf of Mexico. Furthermore, given the market growth remains strong in a range of 7% to 10% tightness of service company capacity, customers are annual growth through 2010, with demand indicated to increasingly seeking to secure oilfield services with longer- double in the period through 2015. Significant numbers of term contracts. In the fourth quarter of 2004, we won a new LNG liquefaction plant and LNG receiving terminal series of major contracts onshore in the United States gas projects are proposed worldwide and are in various sector, and internationally in Russia, Algeria, and the stages of development. Committed LNG liquefaction Middle East. engineering, procurement, and construction projects are Finally, technology is an important aspect of our now yielding substantial growth in worldwide LNG business, and we have focused on improving the develop- liquefaction capacity. This trend is expected to continue ment and introduction of new technologies. In 2004, we through 2007 and beyond. realized growth in our new product and service sales. In Outsourcing of operations and maintenance work by 2005, we expect to continue to invest in technology at the industrial and energy companies has been increasing same level as 2004. KBR worldwide. Even greater opportunities in this area are anticipated as the aging infrastructure in United States KBR provides a wide range of services to energy and refineries and chemical plants require more maintenance industrial customers and government entities worldwide. and repairs to minimize production downtime. More KBR projects are generally longer term in nature than our stringent industry safety standards and environmental Energy Services Group work and are impacted by more regulations also tend to lead to higher maintenance diverse drivers than short-term fluctuations in oil and gas standards and costs. prices and drilling activities. Contract structure. Engineering and construction contracts Effective October 1, 2004, we restructured KBR into two can be broadly categorized as either cost-reimbursable or segments, Government and Infrastructure and Energy and fixed-price, sometimes referred to as lump sum. Some Chemicals. As a result of the reorganization and in a contracts can involve both fixed-price and cost-reim- continued effort to better position KBR for the future, we bursable elements. Fixed-price contracts are for a fixed made several strategic organizational changes. We elimi- sum to cover all costs and any profit element for a defined nated certain internal expenditures; we refocused our scope of work. Fixed-price contracts entail more risk to research and development expenditures with emphasis on us as we must predetermine both the quantities of work the more profitable liquefied natural gas (LNG) market; to be performed and the costs associated with executing and we took appropriate steps to streamline the entire the work. organization. We expect to yield between $80 million and Cost-reimbursable contracts include contracts where $100 million in annual savings due to our reorganization. the price is variable based upon actual costs incurred for In our Government and Infrastructure segment, our time and materials, or for variable quantities of work priced government services work is forecasted to grow in all at defined unit rates. Profit elements on cost-reimbursable regions, with United States government spending in Iraq contracts may be based upon a percentage of costs outpacing other markets. Our work in Iraq continues to be incurred and/or a fixed amount. Cost-reimbursable our largest revenue contributor within this segment. We contracts are generally less risky, since the owner retains continue to make progress with our LogCAP, RIO, and PCO many of the risks. While fixed-price contracts involve Oil South customers on definitizing our cost proposals. greater risk, they also are potentially more profitable for Going forward, we expect activity in Iraq to decline, but not the contractor, since the owners pay a premium to transfer as much as we had previously anticipated. many risks to the contractor. 25 The approximate percentages of revenue attributable to fixed-price and cost-reimbursable contracts within KBR are as follows: 2004 2003 2002 Fixed-Price 17% 24% 47% Cost-Reimbursable 83% 76% 53% The increase in percentage of revenue attributable to cost-reimbursable contracts over the past two years reflects increased revenue from our government services work in Iraq as well as our continuing strategy to move away from fixed-price contracts within our Energy and Chemical segment. We have two remaining major fixed-price engineering, procurement, installation, and commissioning, or EPIC, offshore projects. As of December 31, 2004, they are substantially complete. The reshaping of our offshore business away from lump-sum EPIC contracts to cost reimbursement services has been marked by some significant new work. During the first quarter of 2004 we signed a major reimbursable engineering, procurement, and construction management, or EPCM, contract for a West African oilfield development. This is a major award under our new EPCM strategy. We are also pursuing program management opportunities in deepwater locations around the world. These efforts, implemented under our new strategy, are allowing us to utilize our global resources to continue to be a leader in the offshore business. 26 Increase/ (Decrease) Percentage Change Results of Operations in 2004 Compared to 2003 Revenue: Millions of dollars Production Optimization Fluid Systems Drilling and Formation Evaluation Digital and Consulting Solutions Total Energy Services Group Government and Infrastructure Energy and Chemicals Total KBR Total revenue Geographic – Energy Services Group segments only: Production Optimization: North America Latin America Europe/Africa Middle East/Asia Subtotal Fluid Systems: North America Latin America Europe/Africa Middle East/Asia Subtotal Drilling and Formation Evaluation: North America Latin America Europe/Africa Middle East/Asia Subtotal Digital and Consulting Solutions: North America Latin America Europe/Africa Middle East/Asia Subtotal Total Energy Services Group revenue by region: North America Latin America Europe/Africa Middle East/Asia Total Energy Services Group revenue 2004 $ 3,303 2,324 1,782 589 7,998 9,393 3,075 12,468 $20,466 $ 1,694 335 695 579 3,303 1,104 338 502 380 2,324 610 281 344 547 1,782 201 128 124 136 589 2003 $ 2,758 2,039 1,643 555 6,995 5,417 3,859 9,276 $16,271 $ 1,337 317 562 542 2,758 990 258 452 339 2,039 558 261 312 512 1,643 200 71 116 168 555 $ 545 285 139 34 1,003 3,976 (784) 3,192 $4,195 $ 357 18 133 37 545 114 80 50 41 285 52 20 32 35 139 1 57 8 (32) 34 3,609 1,082 1,665 1,642 $ 7,998 3,085 907 1,442 1,561 $ 6,995 524 175 223 81 $1,003 20% 14 8 6 14 73 (20) 34 26% 27% 6 24 7 20 12 31 11 12 14 9 8 10 7 8 1 80 7 (19) 6 17 19 15 5 14% 27 Increase/ (Decrease) Percentage Change 2004 $ 633 348 225 60 1,266 84 (426) – (342) (87) $ 837 $ 376 56 99 102 633 186 55 61 46 348 102 24 31 68 225 58 (5) (5) 12 60 722 130 186 228 2003 $413 251 177 (15) 826 194 (225) (5) (36) (70) $720 $194 75 52 92 413 104 52 48 47 251 60 30 30 57 177 (52) 8 17 12 (15) 306 165 147 208 $220 97 48 75 440 (110) (201) 5 (306) (17) $117 $182 (19) 47 10 220 82 3 13 (1) 97 42 (6) 1 11 48 110 (13) (22) – 75 416 (35) 39 20 $1,266 $826 $440 53% 39 27 NM 53 (57) (89) 100 NM (24) 16% 94% (25) 90 11 53 79 6 27 (2) 39 70 (20) 3 19 27 212 (163) (129) – NM 136 (21) 27 10 53% Results of Operations in 2004 Compared to 2003 Operating Income (Loss): Millions of dollars Production Optimization Fluid Systems Drilling and Formation Evaluation Digital and Consulting Solutions Total Energy Services Group Government and Infrastructure Energy and Chemicals Shared KBR Total KBR General corporate Operating income Geographic – Energy Services Group segments only: Production Optimization: North America Latin America Europe/Africa Middle East/Asia Subtotal Fluid Systems: North America Latin America Europe/Africa Middle East/Asia Subtotal Drilling and Formation Evaluation: North America Latin America Europe/Africa Middle East/Asia Subtotal Digital and Consulting Solutions: North America Latin America Europe/Africa Middle East/Asia Subtotal Total Energy Services Group operating income by region: North America Latin America Europe/Africa Middle East/Asia Total Energy Services Group operating income NM – Not Meaningful 28 The increase in consolidated revenue in 2004 compared services and hydraulic workover activity in the United to 2003 was largely attributable to activity in our govern- Kingdom. Completion tools and services activities con- ment services projects, primarily in the Middle East, and to tributed $59 million to the segment revenue increase increased sales of our Energy Services Group products and on improved activity in the Middle East/Asia and services as a result of the overall increase in worldwide rig Europe/Africa regions. WellDynamics contributed $49 counts. International revenue was 78% of consolidated million to segment revenue, driven by the consolidation revenue in 2004 and 73% of consolidated revenue in 2003, of the joint venture during the first quarter of 2004 and with the increase attributable to our government services increased demand for intelligent well completions services projects abroad. Revenue from the United States in the Middle East and North America. Prior to 2004, government for all geographic areas was approximately WellDynamics was accounted for under the equity method $8.0 billion or 39% of consolidated revenue in 2004 com- in the Digital and Consulting Solutions segment. The pared to $4.2 billion or 26% of consolidated revenue in 2003. segment’s improved revenue was partially offset by a The increase in consolidated operating income was significant reduction in sand control and completions primarily due to stronger performance in our Energy activity in Nigeria and a $32 million decline compared to Services Group resulting from favorable changes in oil and 2003 in revenue from our surface well testing operations gas prices, which increased worldwide rig counts, and sold in the third quarter of 2004. International revenue pricing improvements in the United States in the current was 54% of total segment revenue in 2004 compared to 56% year. The table below provides significant items included in in 2003. segment operating income. Millions of dollars Production Optimization: Surface well testing gain on sale HMS gain on sale Drilling and Formation Evaluation: Mono Pumps gain on sale Digital and Consulting Solutions: Integrated solutions project losses in Mexico Anglo-Dutch lawsuit Intellectual property settlement Wellstream loss on sale Government and Infrastructure: Restructuring charge Energy and Chemicals: Barracuda-Caratinga project loss Restructuring charge Years ended December 31 2004 $ 54 – – (33) 13 (11) – (12) (407) (28) 2003 $ – 24 36 – (77) – (15) – (238) – The increase in Production Optimization operating income for 2004 compared to 2003 was primarily driven by the higher production enhancement revenues described above, which contributed $155 million. Completion tools and services activities increase of $17 million primarily reflects higher sales of completions and sand control services in the United Kingdom and Norway and a more favorable product mix in Eurasia and Saudi Arabia, offset by a significant reduction in sand control tool sales in Nigeria in the current year. Included in the results were gains of $24 million from the sale of Halliburton Measurement Systems in the second quarter of 2003 and $54 million from the sale of our surface well testing In 2004, Iraq-related work contributed approximately operations in the third and fourth quarters of 2004. $7.1 billion to consolidated revenue and $78 million to Segment results for 2003 also included a $9 million consolidated operating income, a 1.1% margin before equity loss from our Subsea 7, Inc. joint venture, largely corporate costs and taxes. attributable to changes in estimated project costs and Following is a discussion of our results of operations by claims recoveries. reportable segment. Fluid Systems revenue increase in 2004 compared to Production Optimization increase in revenue compared 2003 was driven by a $177 million improvement in revenue to 2003 was largely attributable to production enhancement from cementing activities, due primarily to increased land services, which yielded $430 million in higher revenue. rig count and pricing improvements in the United States This was driven by a higher average land gas rig count and and start-up activity on recent contract awards in Mexico price increases in the United States, increased activity in and Norway. Drilling fluids contributed $95 million to the Canada and Russia, and increases in pipeline process segment revenue increase, resulting largely from new land 29 work in Mexico and land rig growth in the United States sales in China. Drill bits contributed $12 million to and Canada. These increases in segment revenue were improved segment results on higher revenue in the United partially offset by significantly decreased activity in the States and the Caspian Sea region. Operating income for Gulf of Mexico. International revenue was 58% of total 2003 included a $36 million gain on the disposition of Mono segment revenue in 2004 compared to 56% in 2003. Pumps in the first quarter of 2003. The Fluid Systems segment operating income increase Digital and Consulting Solutions revenue increased in compared to 2003 resulted from a cementing services 2004 compared to 2003 primarily due to a $27 million increase of $68 million and drilling fluids increase of $22 increase in Landmark Graphics. During 2004, Landmark million. These improved results occurred primarily in the Graphics achieved its highest revenue since we acquired it. United States due to increased land rig activity, improved Software-related sales in Landmark Graphics increased in pricing, and better utilization and cost management. the current year due to strong acceptance of the new real- Partially offsetting improved segment operating income in time (drilling) and GeoProbe offerings. The increase in 2004 was a $17 million impact of reduced higher margin segment revenue was partially offset by a decline in subsea activity in the Gulf of Mexico. Included in 2003 results were operations in the first half of 2004 and the absence of $11 equity losses of $7 million from the Enventure expandable million of revenue from Wellstream prior to the sale of this casing joint venture, which did not reoccur in 2004. This business in the first quarter of 2003. International revenue joint venture is currently accounted for on a cost basis was 69% of total segment revenue in 2004 compared to 67% since reducing our ownership in the first quarter of 2004. in 2003. Drilling and Formation Evaluation revenue improvement Segment operating income increased $75 million from a in 2004 compared to 2003 was driven by a $66 million loss position in 2003. This segment recorded a $77 million increase in logging and perforating services due to higher charge related to the Anglo-Dutch lawsuit in the third land rig activity and pricing improvements in the United quarter of 2003 and a $15 million loss on the disposition of States and direct sales to China. Drilling services con- Wellstream in the first quarter of 2003. For 2004, results tributed $40 million to the segment revenue increase, were positively impacted by a $13 million release of legal resulting principally from new contracts in Norway and liability accruals in the first quarter of 2004 pertaining to Brazil and higher activity in Canada, Venezuela, and the April 2004 Anglo-Dutch settlement and increased Argentina. The increase in drilling services revenue was integrated solutions operating income stemming from partially offset by a substantial decline in logging-while- higher commodity prices. The increase in the segment drilling activity in the Gulf of Mexico. Drill bits sales was partially offset by a $33 million loss recorded in the increased $29 million, benefiting from increases in land rig fourth quarter of 2004 on two integrated solutions projects activity, improved pricing, and better market penetration in Mexico. The loss resulted from operational start-up with fixed cutter and roller cone bits primarily in the United and subsurface problems on the initial wells, third-party States, as well as sales growth in the Caspian Sea region and other cost increases, increased drilling times, and a and China. International revenue was 72% of total segment work stoppage due to community blockage. The charge revenue in 2004 and in 2003. reflects the estimated total project loss through completion The increase in Drilling and Formation Evaluation of the drilling program in mid-2006. Segment results for segment operating income was due to improved results in 2004 also included an $11 million charge for an intellectual drilling services, which benefited from a lower depreciation property settlement. expense of $35 million in 2004 compared to 2003 primarily Government and Infrastructure revenue increased $4.0 due to extending depreciable asset lives in the second billion compared to 2003. The increase was primarily due to quarter of 2004. Logging and perforating services con- $3.7 billion higher revenue from government services tributed $33 million to the increase, due to improved contracts in the Middle East. Activities in the DML pricing and land rig activity in the United States and direct 30 shipyard projects also contributed $108 million to increased projects in the United States and United Kingdom, and new revenue in 2004 compared to 2003. offshore program management projects. The operating loss The Government and Infrastructure operating income for 2003 included losses recognized on the Barracuda- decrease resulted from $94 million in write-downs on Caratinga project of $238 million and losses on a infrastructure projects in Europe and Africa, a government hydrocarbon project in Belgium. project in Afghanistan, completion of the construction General corporate expenses for 2004 increased prima- phase of a rail project in Australia, and reduction in rily due to a $7.5 million charge related to a settlement with activities in the government project in the Balkans. Current the SEC, financing fees on outstanding credit facilities, year results were also impacted by a restructuring charge Sarbanes-Oxley compliance expenses, and increased of $12 million due to the reorganization of KBR. The legal fees. charge related to personnel termination benefits. Partially offsetting the decreases was an increase in income of $14 million from Iraq-related activities primarily due to the LogCAP contract. Energy and Chemicals decrease in revenue compared to 2003 was primarily due to lower revenue of $1.1 billion on the Barracuda-Caratinga project in Brazil, the Belanak project in Indonesia, completion of refining facilities in the United States, gas projects in Africa, offshore projects in Mexico, and a hydrocarbon project in Europe. The decrease was partially offset by higher revenue of $391 million on refining projects in Canada, an olefins project in the United States, operations and maintenance projects in the United States and the United Kingdom, and new offshore program management projects. The operating loss for the segment in 2004 primarily resulted from $407 million of losses on the Barracuda- Caratinga project in Brazil, $47 million of losses on a gas project in Africa, and $29 million of losses on the Belanak project in Indonesia. The losses recognized on the Barracuda-Caratinga project were primarily due to the agreement with Petrobras, higher cost estimates, schedule delays, and increased contingencies for the balance of the project until completion. Specifically, in the second quarter, with the integration phase of the Barracuda vessel we experienced a significant reduction in productivity and rework required from the vessel conversion. Also included in the 2004 results was a restructuring charge of $28 million due to the reorganization of KBR. The charge related to personnel termination benefits and asset impairments. Operating losses in 2004 were partially offset by a $59 million increase on an LNG project in Egypt, a refining project in Canada, operations and maintenance Nonoperating Items Interest expense increased $90 million in 2004 compared to 2003, due primarily to interest on $1.2 billion convertible notes issued in June 2003, $1.05 billion senior floating and fixed notes issued in October 2003, $500 million senior floating-rate notes issued in January 2004, and interest on tax deficiencies in Indonesia and Mexico. Interest income increased $14 million in 2004 compared to the same period in 2003, attributable to higher average daily cash balances during the year and interest on tax refunds in various jurisdictions. Loss from discontinued operations, net of tax in 2004 included, on a pretax basis, a $778 million charge for the revaluation of 59.5 million shares of Halliburton common stock to be contributed to the asbestos claimant trust as part of the proposed settlement, a $698 million charge related to the write-down of the asbestos and silica insur- ance receivable, a $44 million charge related to our October 2004 partitioning agreement, and an $11 million charge related to the delayed-draw term facility, which expired in June 2004. The remaining amount primarily consisted of professional and administrative fees related to various aspects of the proposed asbestos and silica settlement, accretion on the asbestos insurance receivables, and our October 2004 partitioning agreement. The loss from discontinued operations was $1.145 billion in 2003. The benefit for income taxes on discontinued operations was $180 million in 2004, compared to a provision of $6 million for 2003. We have established a valuation allowance against the deferred tax asset arising from the asbestos and silica charges to reflect the expected net tax benefit from the future deductions the charges will create. In 2004, we 31 increased the valuation allowance by $449 million to a balance of $1.073 billion. The balance at the end of 2003 was $624 million. Cumulative effect of change in accounting principle, net for the year ended 2003 was an $8 million after-tax charge, or $0.02 per diluted share, related to our January 1, 2003 adoption of Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 addresses the financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated assets’ retirement costs. The asset retire- ment obligations primarily relate to the removal of leasehold improvements upon exiting certain lease arrangements and restoration of land associated with the mining of bentonite. 32 Increase/ (Decrease) Percentage Change Results of Operations in 2003 Compared to 2002 Revenue: Millions of dollars Production Optimization Fluid Systems Drilling and Formation Evaluation Digital and Consulting Solutions Total Energy Services Group Government and Infrastructure Energy and Chemicals Total KBR Total revenue Geographic – Energy Services Group segments only: Production Optimization: North America Latin America Europe/Africa Middle East/Asia Subtotal Fluid Systems: North America Latin America Europe/Africa Middle East/Asia Subtotal Drilling and Formation Evaluation: North America Latin America Europe/Africa Middle East/Asia Subtotal Digital and Consulting Solutions: North America Latin America Europe/Africa Middle East/Asia Subtotal Total Energy Services Group revenue by region: North America Latin America Europe/Africa Middle East/Asia Total Energy Services Group revenue 2003 $ 2,758 2,039 1,643 555 6,995 5,417 3,859 9,276 $16,271 $ 1,337 317 562 542 2,758 990 258 452 339 2,039 558 261 312 512 1,643 200 71 116 168 555 3,085 907 1,442 1,561 2002 $ 2,544 1,815 1,633 844 6,836 1,539 4,197 5,736 $12,572 $ 1,254 277 556 457 2,544 934 216 381 284 1,815 549 251 344 489 1,633 294 102 297 151 844 3,031 846 1,578 1,381 $ 214 224 10 (289) 159 3,878 (338) 3,540 $3,699 $ 83 40 6 85 214 56 42 71 55 224 9 10 (32) 23 10 (94) (31) (181) 17 (289) 54 61 (136) 180 $ 6,995 $ 6,836 $ 159 8% 12 1 (34) 2 252 (8) 62 29% 7% 14 1 19 8 6 19 19 19 12 2 4 (9) 5 1 (32) (30) (61) 11 (34) 2 7 (9) 13 2% 33 Increase/ (Decrease) Percentage Change 2003 $413 251 177 (15) 826 194 (225) (5) (36) (70) $720 $194 75 52 92 413 104 52 48 47 251 60 30 30 57 177 (52) 8 17 12 (15) 306 165 147 208 2002 $ 374 202 160 (98) 638 75 (131) (629) (685) (65) $(112) $218 41 46 69 374 119 33 20 30 202 70 29 (6) 67 160 (208) 5 118 (13) (98) 199 108 178 153 $ 39 49 17 83 188 119 (94) 624 649 (5) $832 $ (24) 34 6 23 39 (15) 19 28 17 49 (10) 1 36 (10) 17 156 3 (101) 25 83 107 57 (31) 55 $826 $638 $188 10% 24 11 85 29 159 (72) 99 95 (8) NM (11)% 83 13 33 10 (13) 58 140 57 24 (14) 3 NM (15) 11 75 60 (86) 192 85 54 53 (17) 36 29% Results of Operations in 2003 Compared to 2002 Operating Income (Loss): Millions of dollars Production Optimization Fluid Systems Drilling and Formation Evaluation Digital and Consulting Solutions Total Energy Services Group Government and Infrastructure Energy and Chemicals Shared KBR Total KBR General corporate Operating income (loss) Geographic – Energy Services Group segments only: Production Optimization: North America Latin America Europe/Africa Middle East/Asia Subtotal Fluid Systems: North America Latin America Europe/Africa Middle East/Asia Subtotal Drilling and Formation Evaluation: North America Latin America Europe/Africa Middle East/Asia Subtotal Digital and Consulting Solutions: North America Latin America Europe/Africa Middle East/Asia Subtotal Total Energy Services Group operating income by region: North America Latin America Europe/Africa Middle East/Asia Total Energy Services Group operating income NM – Not Meaningful 34 The increase in consolidated revenue for 2003 com- Following is a discussion of our results of operations by pared to 2002 was largely attributable to activity in our reportable segment. government services projects, primarily work in the Middle Production Optimization increase in revenue was mainly East. International revenue was 73% of total revenue in 2003 attributable to production enhancement services, which and 67% of total revenue in 2002, with the increase attributa- increased $187 million compared to 2002, driven by higher ble to our government services projects. During 2003, the activity in the Middle East following the end of the war in United States government became a major customer of Iraq and increased rig count in Mexico and North America. ours with total revenue of approximately $4.2 billion or 26% In addition, completion tools and services activities of consolidated revenue for 2003. Revenue from the United increased $35 million compared to 2002 due primarily to States government during 2002 represented less than 10% increased land rig counts in North America, increased of consolidated revenue. The consolidated operating activity in Brazil due to higher activity with national and income increase in 2003 compared to 2002 was largely international oil companies in deepwater, and increased rig attributable to our government services projects and the activity in Mexico. These increases were partially offset by absence of the $644 million in asbestos and silica charges lower activity in the Gulf of Mexico and the United and restructuring charges that occurred in 2002. In Kingdom. The May 2003 sale of Halliburton Measurement addition, we recorded a loss on the Barracuda-Caratinga Systems had a $24 million negative impact on segment project of $238 million in 2003 as compared to a $117 revenue in 2003 compared to 2002. The improvement in million loss in 2002. Our Energy Services Group segments revenue more than offset the $9 million in equity losses accounted for approximately $188 million of the increase from the Subsea 7, Inc. joint venture. International revenue in income. was 56% of segment revenue in 2003 compared to 53% in The table below provides significant items included in 2002 as activity picked up in the Middle East following the segment operating income. end of the war in Iraq. Millions of dollars Production Optimization: HMS gain on sale Drilling and Formation Evaluation: Mono Pumps gain on sale Digital and Consulting Solutions: Anglo-Dutch lawsuit Wellstream loss on sale EMC gain on sale Patent infringement lawsuit accrual Restructuring charge Bredero-Shaw impairment Bredero-Shaw loss on sale Government and Infrastructure: Restructuring charge Energy and Chemicals: Barracuda-Caratinga project loss Restructuring charge Shared KBR: Asbestos and silica liability accruals Highlands receivable write-off General corporate: Insurance company demutualization Restructuring charge Years ended December 31 2003 2002 $24 36 (77) (15) – – – – – – (238) – (5) – – – $– – – – 108 (98) (64) (61) (18) (5) (117) (13) (564) (80) 29 (25) In 2003, Iraq-related work contributed approximately $3.6 billion to consolidated revenue and $85 million to consolidated operating income, a 2.4% margin before corporate costs and taxes. The Production Optimization operating income increase included a $24 million gain on the sale of Halliburton Measurement Systems in North America, offset by inventory write-downs. Fluid Systems increase in revenue was driven by drilling fluids sales increase of $101 million and cementing activities increase of $121 million compared to 2002. Cementing benefited from higher land rig counts in the United States. Both drilling fluids and cementing revenue benefited from increased activity in Mexico, primarily with PEMEX, which offset lower activity in Venezuela. Drilling fluids also benefited from price improvements on certain contracts in Europe/Africa. International revenue was 56% of total revenue in 2003 compared to 52% in 2002. The Fluid Systems segment operating income increase was a result of drilling fluids increasing $29 million and cementing services increasing $24 million compared to 2002, partially offset by lower results of $4 million from Enventure. Drilling fluids benefited from higher sales of biodegradable drilling fluids and improved contract terms. Those benefits were partially offset by contract losses in 35 the Gulf of Mexico and United States pricing pressures in Digital and Consulting Solutions decrease in revenue 2003. Cementing operating income primarily increased in compared to 2002 was primarily due to the contribution of Middle East/Asia due to collections on previously reserved most of the assets of Halliburton Subsea to Subsea 7, Inc., receivables, certain start-up costs in 2002, and higher which beginning in May 2002 was reported on the equity margin work. All regions showed improved segment basis. This accounted for approximately $200 million of the operating income in 2003 compared to 2002, except North decrease. The sale of Wellstream in March 2003 also America, which was impacted by the decrease in activity contributed $49 million to the decrease. Revenue for from the higher margin offshore business in the Gulf of Landmark Graphics was down $13 million compared to Mexico. 2002 due to the general weakness in information technol- Drilling and Formation Evaluation revenue was essen- ogy spending. International revenue was 67% of segment tially flat. Logging and perforating services revenue revenue in 2003 compared to 74% in 2002. The decrease is increased $25 million, primarily due to higher average year- the result of the contribution of the Halliburton Subsea over-year rig counts in the United States and Mexico, assets to Subsea 7, Inc., which mainly conducts operations partially offset by lower sales in China and reduced activity in the North Sea. in Venezuela. Drill bits revenue increased $21 million, Segment operating loss was $15 million in 2003 com- benefiting from the increased rig counts in the United pared to a loss of $98 million in 2002. Included in 2003 were States and Canada. Drilling services revenue for 2003 was a $15 million loss on the sale of Wellstream ($11 million in negatively impacted by $79 million compared to 2002 due North America and $4 million in Europe/Africa) and a $77 to the sale of Mono Pumps in January 2003. The remainder million charge related to the October 2003 verdict in the of drilling services revenue increased $34 million compared Anglo-Dutch lawsuit, which impacted North America to 2002 as contracts that were expiring were more than results. The significant items affecting operating income in offset by new contracts, primarily in West Africa, the 2002 included: Middle East, and Ecuador. Also impacting drilling services – $108 million gain on the sale of European Marine were significant price discounts in the fourth quarter of Contractors Ltd. in Europe/Africa; 2003 on basic drilling services and rotary steerables in the – $98 million charge for BJ Services patent infringement United Kingdom. International revenue was 72% of total lawsuit accrual in North America; segment revenue in both 2003 and 2002. – $79 million loss on the impairment of our 50% equity The increase in operating income for the segment was investment in the Bredero-Shaw joint venture in North primarily driven by logging and perforating services, which America; and increased operating income by $32 million, a result of – $64 million in expense related to restructuring increased rig counts internationally, lower discounts in the charges ($51 million in North America, $3 million in United States, and the absence of start-up costs incurred in Latin America, $7 million in Europe/Africa, and $3 2002. Operating income for 2003 also included a $36 million million in Middle East/Asia). gain ($24 million in North America and $12 million in Government and Infrastructure increase in revenue Europe/Africa) on the sale of Mono Pumps. Operating compared to 2002 was due to increased activity in Iraq for income for drilling services decreased by $49 million and the United States government, and, to a lesser extent, a $9 million for drill bits compared to 2002 due to lower $264 million increase on other government projects. activity in Venezuela, pricing pressures in the United Government and Infrastructure operating income States, severance expense, and facility consolidation improvement in 2003 was due to government-related expenses. Drilling services operating income for 2003 was activities, partially stemming from operations in the Middle negatively impacted by $5 million compared to 2002 due to East for Iraq-related work and a $14 million increase in the sale of Mono Pumps. income from other government projects. 36 Energy and Chemicals decrease in revenue compared to The provision was $80 million in 2002 on a net loss from 2002 was due to lower revenue earned on the Barracuda- continuing operations. The inclusion of asbestos accruals in Caratinga project in Brazil and a $111 million decrease on continuing operations for 2002 was the primary cause of industrial services projects in the United States and the unusual 2002 effective tax rate on continuing opera- production services projects globally. Partially offsetting tions. There are no asbestos charges or related tax accruals the revenue decrease was a $161 million increase on LNG included in continuing operations for 2003. Our impairment and oil and gas projects in Africa. loss on Bredero-Shaw during 2002 could not be benefited The operating loss for the segment was $225 million in for tax purposes due to book and tax basis differences in 2003 compared to an operating loss of $131 million in 2002. that investment and the limited benefit generated by a The operating loss in 2003 included losses recognized on capital loss carryback. However, due to changes in the Barracuda-Caratinga project of $238 million and losses circumstances regarding prior years, we are now able to on a hydrocarbon project in Belgium. Partially offsetting carry back a portion of the capital loss, which resulted in these losses were income from liquefied natural gas an $11 million benefit in 2003. projects in Africa. Included in the 2002 results were a loss Loss from discontinued operations, net of tax of $1.2 on the Barracuda-Caratinga project of $117 million and $13 billion in 2003 was due to the following: million of restructuring charges. – asbestos and silica liability was increased to reflect the Shared KBR in 2002 included a charge of $564 million full amount of the proposed settlement as a result of related to the asbestos- and silica-related liabilities and a the Chapter 11 proceeding; charge of $80 million to write-off our receivable from – charges related to our July 2003 funding of $30 million Highlands Insurance Company to cover asbestos claims for the debtor-in-possession financing to Harbison- (see Note 11 to our consolidated financial statements). Walker in connection with its Chapter 11 proceedings General corporate in 2002 included a $29 million pretax that was expected to be forgiven by Halliburton on the gain for the value of stock received from the demutualiza- earlier of the effective date of a plan of reorganization tion of an insurance provider, partially offset by 2002 for DII Industries or the effective date of a plan of restructuring charges of $25 million. The higher 2003 reorganization for Harbison-Walker acceptable to DII expenses also relate to preparations for the certifications Industries; required under Section 404 of the Sarbanes-Oxley Act. – $10 million allowance for an estimated portion of Nonoperating Items Interest expense increased $26 million in 2003 compared to 2002. The increase was due primarily to $30 million in interest on the $1.2 billion convertible notes issued in June 2003 and the $1.05 billion senior floating and fixed notes issued in October 2003. The increase was partially offset by $5 million in pre-judgment interest recorded in 2002 related to the BJ Services patent infringement judgment and $296 million of scheduled debt repayments in 2003. Foreign currency losses, net for 2003 included gains in Canada offset by losses in the United Kingdom and Brazil. Losses in 2002 were due to negative developments in Brazil, Argentina, and Venezuela. Provision for income taxes of $234 million resulted in an effective tax rate on continuing operations of 38.2% in 2003. uncollectible amounts related to the insurance receivables purchased from Harbison-Walker; – professional fees associated with the due diligence, printing, and distribution cost of the disclosure statement and other aspects of the proposed settle- ment for asbestos and silica liabilities; and – a release of environmental and legal reserves related to indemnities that were part of our disposition of the Dresser Equipment Group and were no longer needed. The loss of $652 million in 2002 was due primarily to charges recorded for asbestos and silica liabilities and a $40 million payment associated with the Harbison-Walker Chapter 11 filing. The provision for income taxes on discontinued operations was $6 million in 2003 compared to a tax benefit 37 of $154 million in 2002. We have established a valuation assets and liabilities that are not readily apparent from allowance against the deferred tax asset arising from the other sources. We believe the following are the critical asbestos and silica charges to reflect the expected net tax accounting policies used in the preparation of our consoli- benefit from the future deductions the charges will create. dated financial statements, as well as the significant In 2003, we increased the valuation allowance by $391 estimates and judgments affecting the application of these million to a balance of $624 million. The balance at the end policies. This discussion and analysis should be read in of 2002 was $233 million. conjunction with our consolidated financial statements and Cumulative effect of change in accounting principle, net related notes included in this report. was an $8 million after-tax charge, or $0.02 per diluted We have discussed the development and selection of share, related to our January 1, 2003 adoption of SFAS No. these critical accounting policies and estimates with the 143, “Accounting for Asset Retirement Obligations.” SFAS Audit Committee of our Board of Directors, and the Audit No. 143 addresses the financial accounting and reporting Committee has reviewed the disclosure presented below. for obligations associated with the retirement of tangible Percentage of completion long-lived assets and the associated assets’ retirement Revenue from contracts to provide construction, costs. The asset retirement obligations primarily relate to engineering, design, or similar services, almost all of which the removal of leasehold improvements upon exiting relates to KBR, is reported on the percentage-of-completion certain lease arrangements and restoration of land associ- method of accounting. This method of accounting requires ated with the mining of bentonite. us to calculate job profit to be recognized in each reporting CRITICAL ACCOUNTING ESTIMATES The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our judgments about future events and related estimations and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective, or complex esti- mates and assessments and is fundamental to our results of operations. We identified our most critical accounting estimates to be: – percentage-of-completion accounting for contracts to provide construction, engineering, design, or similar services; – accounting for government contracts; – allowance for bad debts; – forecasting our effective tax rate, including our future ability to utilize foreign tax credits and the realizability of deferred tax assets; and – legal and investigation matters. We base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of period for each job based upon our predictions of future outcomes, which include: – estimates of the total cost to complete the project; – estimates of project schedule and completion date; – estimates of the percentage the project is complete; and – amounts of any probable unapproved claims and change orders included in revenue. At the outset of each contract, we prepare a detailed analysis of our estimated cost to complete the project. Risks relating to service delivery, usage, productivity, and other factors are considered in the estimation process. Our project personnel periodically evaluate the estimated costs, claims, change orders, and percentage of completion at the project level. The recording of profits and losses on long- term contracts requires an estimate of the total profit or loss over the life of each contract. This estimate requires consideration of contract revenue, change orders, and claims, less costs incurred and estimated costs to complete. Anticipated losses on contracts are recorded in full in the period in which they become evident. Profits are recorded based upon the total estimated contract profit times the current percentage complete for the contract. When calculating the amount of total profit or loss on a long-term contract, we include unapproved claims as 38 revenue when the collection is deemed probable based costs to complete the work) and an award fee (a variable upon the four criteria for recognizing unapproved claims profit percentage applied to definitized costs, which is under the American Institute of Certified Public subject to our customer’s discretion and tied to the specific Accountants Statement of Position 81-1 (SOP 81-1), performance measures defined in the contract, such as “Accounting for Performance of Construction-Type and adherence to schedule, health and safety, quality of work, Certain Production-Type Contracts.” Including probable responsiveness, cost performance, and business manage- unapproved claims in this calculation increases the ment). operating income (or reduces the operating loss) that Base fee revenue is recorded at the time services are would otherwise be recorded without consideration of the performed, based upon actual project costs incurred, and probable unapproved claims. Probable unapproved claims include a reimbursement fee for general, administrative, are recorded to the extent of costs incurred and include no and overhead costs. The general, administrative, and profit element. In all cases, the probable unapproved claims overhead cost reimbursement fees are estimated periodi- included in determining contract profit or loss are less than cally in accordance with government contract accounting the actual claim that will be or has been presented to the regulations and may change based on actual costs incurred customer. We are actively engaged in claims negotiations or based upon the volume of work performed. Revenue with our customers, and the success of claims negotiations may be reduced for our estimate of costs that may be have a direct impact on the profit or loss recorded for any categorized as disputed or unallowable as a result of cost related long-term contract. Unsuccessful claims negotia- overruns or the audit process. tions could result in decreases in estimated contract profits Award fees are generally evaluated and granted or additional contract losses, and successful claims periodically by our customer. For contracts entered into negotiations could result in increases in estimated contract prior to June 30, 2003, award fees are recognized during profits or recovery of previously recorded contract losses. the term of the contract based on our estimate of amounts At least quarterly, significant projects are reviewed in to be awarded. Once award fees are granted and task detail by senior management. We have a long history of orders underlying the work are definitized, we adjust our dealing with multiple types of projects and in preparing cost estimate of award fees to actual amounts earned. Our estimates. However, there are many factors that impact estimates are often based on our past award experience for future costs, including but not limited to weather, inflation, similar types of work. We have been receiving award fees labor and community disruptions, timely availability of on the Balkans project since 1995, and our estimates for materials, productivity, and other factors as outlined in our award fees for this project have generally been accurate in “Forward-Looking Information and Risk Factors.” These the periods presented. We are in the initial stages of the factors can affect the accuracy of our estimates and award fees process for the RIO and LogCAP projects and, materially impact our future reported earnings. In the past, therefore, these estimates are made with less history, and we have incurred substantial losses on projects that were the controversial nature of these contracts may cause not initially projected, including our Barracuda-Caratinga actual awards to vary significantly from past experience. project (see “Barracuda-Caratinga Project” for further As a result of our adoption of Emerging Issues Task discussion). Force Issue No. 00-21 (EITF 00-21), “Revenue Accounting for government contracts Arrangements with Multiple Deliverables,” for contracts Most of the services provided to the United States entered into subsequent to June 30, 2003 (such as PCO Oil government are governed by cost-reimbursable contracts. South), we do not recognize award fees for contracts Services under our LogCAP, RIO, PCO Oil South, and containing multiple deliverables based on estimates. Balkans support contracts are examples of these types of Instead, they are recognized only when definitized and arrangements. Generally, these contracts contain both a awarded by the customer. Also, for service-only contracts, base fee (a fixed profit percentage applied to our actual award fees are recognized only when awarded by the 39 customer. Award fees on government construction accounts receivable balance as of December 31, 2004 would contracts are recognized during the term of the contract have resulted in a $30 million adjustment to 2004 total based on our estimate of the amount of fees to be awarded. operating costs and expenses. Similar to many cost-reimbursable contracts, these Income tax accounting government contracts are typically subject to audit and We account for our income taxes in accordance with adjustment by our customer. Each contract is unique; Statement of Financial Accounting Standards No. 109, therefore, the level of confidence in our estimates for audit “Accounting for Income Taxes,” which requires the adjustments varies depending on how much historical data recognition of the amount of taxes payable or refundable we have with a particular contract. Further, the significant for the current year and an asset and liability approach in size and controversial nature of the RIO and LogCAP recognizing the amount of deferred tax liabilities and assets contracts may cause actual awards to vary significantly for the future tax consequences of events that have been from past experience. recognized in our financial statements or tax returns. We The estimates employed in our accounting for govern- apply the following basic principles in accounting for our ment contracts affect our Government and Infrastructure income taxes: segment. Allowance for bad debts – a current tax liability or asset is recognized for the estimated taxes payable or refundable on tax returns We evaluate our accounts receivable through a continu- for the current year; ous process of assessing our portfolio on an individual – a deferred tax liability or asset is recognized for the customer and overall basis. This process consists of a estimated future tax effects attributable to temporary thorough review of historical collection experience, current differences and carryforwards; aging status of the customer accounts, financial condition of – the measurement of current and deferred tax liabili- our customers, and other factors such as whether the ties and assets is based on provisions of the enacted receivables involve retentions or billing disputes. We also tax law, and the effects of potential future changes in consider the economic environment of our customers, both tax laws or rates are not considered; and from a marketplace and geographic perspective, in – the value of deferred tax assets is reduced, if neces- evaluating the need for an allowance. Based on our review sary, by the amount of any tax benefits that, based on of these factors, we establish or adjust allowances for available evidence, are not expected to be realized. specific customers and the accounts receivable portfolio as We determine deferred taxes separately for each tax- a whole. This process involves a high degree of judgment paying component (an entity or a group of entities that is and estimation, and frequently involves significant dollar consolidated for tax purposes) in each tax jurisdiction. That amounts. Accordingly, our results of operations can be determination includes the following procedures: affected by adjustments to the allowance due to actual – identifying the types and amounts of existing tempo- write-offs that differ from estimated amounts. Our esti- rary differences; mates of allowances for bad debts have historically been – measuring the total deferred tax liability for taxable accurate. Over the last five years, our estimates of temporary differences using the applicable tax rate; allowances for bad debts, as a percentage of notes and – measuring the total deferred tax asset for deductible accounts receivable before the allowance, have ranged temporary differences and operating loss carryfor- from 4.0% to 6.0%. At December 31, 2004, allowance for bad wards using the applicable tax rate; debts totaled $127 million or 4.3% of notes and accounts – measuring the deferred tax assets for each type of tax receivable before the allowance, and at December 31, 2003, credit carryforward; and allowance for bad debts totaled $175 million or 5.7% of – reducing the deferred tax assets by a valuation notes and accounts receivable before the allowance. A 1% allowance if, based on available evidence, it is more change in our estimate of the collectibility of our notes and 40 likely than not that some portion or all of the deferred future foreign tax credits in the United States. This tax assets will not be realized. valuation allowance is determined quarterly based on a Our methodology for recording income taxes requires a number of estimates including future creditable foreign significant amount of judgment in the use of assumptions taxes, tax loss carryforwards that the deductions will and estimates. Additionally, we use forecasts of certain tax generate, and future taxable income. Factors such as actual elements such as taxable income and foreign tax credit operating results, material acquisitions or dispositions, and utilization, as well as evaluate the feasibility of implement- changes to our operating environment could alter the ing tax planning strategies. Given the inherent uncertainty estimates, and such changes could have a material impact involved with the use of such variables, there can be on the valuation allowance. significant variation between anticipated and actual results. Legal and investigation matters Unforeseen events may significantly impact these variables, We are currently involved in other legal proceedings and changes to these variables could have a material and investigations not involving asbestos and silica. As impact on our income tax accounts related to both continu- discussed in Note 13 of our consolidated financial state- ing and discontinued operations. ments, as of December 31, 2004, we have accrued an We have operations in more than 100 countries other estimate of the probable and estimable costs for the than the United States. Consequently, we are subject to the resolution of some of these matters. For other matters for jurisdiction of a significant number of taxing authorities. which the liability is not probable and reasonably The income earned in these various jurisdictions is taxed estimable, we have not accrued any amounts. Attorneys in on differing bases, including income actually earned, our legal department monitor and manage all claims filed income deemed earned, and revenue-based tax withhold- against us and review all pending investigations. Generally, ing. The final determination of our tax liabilities involves the estimate of probable costs related to these matters is the interpretation of local tax laws, tax treaties, and related developed in consultation with outside legal counsel authorities in each jurisdiction. Changes in the operating representing us. Our estimates are based upon an analysis environment, including changes in tax law and of potential results, assuming a combination of litigation currency/repatriation controls, could impact the determina- and settlement strategies. The precision of these estimates tion of our tax liabilities for a tax year. is impacted by the amount of due diligence we have been Tax filings of our subsidiaries, unconsolidated affiliates, able to perform. We attempt to resolve these matters and related entities are routinely examined in the normal through settlements, mediation, and arbitration proceed- course of business by tax authorities. These examinations ings when possible. If the actual settlement costs, final may result in assessments of additional taxes, which we judgments, or fines, after appeals, differ from our estimates, work to resolve with the tax authorities or through the our future financial results may be adversely affected. We judicial process. Predicting the outcome of disputed have in the past recorded significant adjustments to our assessments involves some uncertainty. Factors such as the initial estimates of these types of contingencies. availability of settlement procedures, willingness of tax authorities to negotiate, and the operation and impartiality of judicial systems vary across the different tax jurisdic- tions and may significantly influence the ultimate outcome. We review the facts for each assessment, then utilize assumptions and estimates to determine the most likely outcome and provide taxes based on this outcome. We have recorded a valuation allowance on the asbestos and silica liabilities based on the anticipated impact of the future asbestos and silica deductions on our ability to utilize OFF BALANCE SHEET RISK On April 15, 2002, we entered into an agreement to sell eligible United States Energy Services Group accounts receivable to a bankruptcy-remote limited-purpose funding subsidiary. Under the terms of the agreement, new receivables are added on a continuous basis to the pool of receivables. Collections reduce previously sold accounts receivable. This funding subsidiary sells an undivided ownership interest in this pool of receivables to entities 41 managed by unaffiliated financial institutions under another FINANCIAL INSTRUMENT MARKET RISK agreement. Sales to the funding subsidiary have been We are exposed to financial instrument market risk structured as “true sales” under applicable bankruptcy from changes in foreign currency exchange rates, interest laws. While the funding subsidiary is wholly owned by us, rates, and, to a limited extent, commodity prices. We its assets are not available to pay any creditors of ours or of selectively manage these exposures through the use of our subsidiaries or affiliates. The undivided ownership derivative instruments to mitigate our market risk from interest in the pool of receivables sold to the unaffiliated these exposures. The objective of our risk management companies, therefore, is reflected as a reduction of program is to protect our cash flows related to sales or accounts receivable in our consolidated balance sheets. purchases of goods or services from market fluctuations in The funding subsidiary retains the interest in the pool of currency rates. We do not use derivative instruments for receivables that are not sold to the unaffiliated companies trading purposes. Our use of derivative instruments and is fully consolidated and reported in our financial includes the following types of market risk: statements. – volatility of the currency rates; The amount of undivided interests that can be sold – time horizon of the derivative instruments; under the program varies based on the amount of eligible – market cycles; and Energy Services Group receivables in the pool at any given – the type of derivative instruments used. time and other factors. In April 2004, the expiration date for We do not consider any of these risk management our Energy Services Group accounts receivable securitiza- activities to be material. See Note 1 to the consolidated tion facility was extended to April 2005. The maximum financial statements for additional information on our amount that may be sold and outstanding under this accounting policies on derivative instruments. See Note 18 agreement at any given time is $300 million. As of to the consolidated financial statements for additional December 31, 2004, we had sold $256 million undivided disclosures related to derivative instruments. ownership interest to unaffiliated companies. Interest rate risk. We have exposure to interest rate risk In May 2004, we entered into an agreement to sell, from our long-term debt. assign, and transfer the entire title and interest in specified The following table represents principal amounts of our United States government accounts receivable of KBR to a long-term debt at December 31, 2004 and related weighted third party. The face value of the receivables sold to the average interest rates by year of maturity for our long-term third party is reflected as a reduction of accounts receiv- debt. able in our consolidated balance sheets. The amount of receivables that can be sold under the agreement varies based on the amount of eligible receivables at any given time and other factors, and the maximum amount that may be sold and outstanding under this agreement at any given time is $650 million. The total amount of receivables outstanding under this agreement as of December 31, 2004 Millions of dollars Fixed-rate debt: Amount Weighted average interest rate Variable-rate debt: Amount Weighted average interest rate 2005 2006 2007 2008 2009 Thereafter Total $1 $280 $ – $150 $ – $2,625 $3,056 6.9% 6.0% – 5.6% – 5.0% 5.1% $346 $18 $ 518 $6 $ – $ – $888 3.8% 5.4% 3.0% 5.5% – – 3.4% was approximately $263 million. Subsequent to December The fair market value of long-term debt was $3.7 billion 31, 2004, these receivables were collected and the balance as of December 31, 2004. retired, and we are not currently selling receivables, although the facility continues to be available. We have exposure to losses in certain unconsolidated variable interest entities. See Note 20 to the consolidated financial statements for more information. ENVIRONMENTAL MATTERS We are subject to numerous environmental, legal, and regulatory requirements related to our operations world- wide. In the United States, these laws and regulations include, among others: 42 – the Comprehensive Environmental Response, Accordingly, we will recognize compensation expense for Compensation, and Liability Act; all newly granted awards and awards modified, repur- – the Resources Conservation and Recovery Act; chased, or cancelled after July 1, 2005. Compensation cost – the Clean Air Act; for the unvested portion of awards that are outstanding as – the Federal Water Pollution Control Act; and of July 1, 2005 will be recognized ratably over the remain- – the Toxic Substances Control Act. ing vesting period. The compensation cost for the unvested In addition to the federal laws and regulations, states portion of awards will be based on the fair value at date of and other countries where we do business may have grant as calculated for our pro forma disclosure under numerous environmental, legal, and regulatory require- SFAS No. 123. We will recognize compensation expense for ments by which we must abide. We evaluate and address our Employee Stock Purchase Program beginning with the the environmental impact of our operations by assessing July 1, 2005 purchase period. and remediating contaminated properties in order to We estimate that the effect on net income and earnings avoid future liabilities and comply with environmental, per share in the periods following adoption of SFAS No. legal, and regulatory requirements. On occasion, we are 123R will be consistent with our pro forma disclosure involved in specific environmental litigation and claims, under SFAS No. 123, except that estimated forfeitures including the remediation of properties we own or have will be considered in the calculation of compensation operated, as well as efforts to meet or correct compliance- expense under SFAS No. 123R. However, the actual effect related matters. Our Health, Safety and Environment on net income and earnings per share will vary depending group has several programs in place to maintain environ- upon the number of options granted in 2005 compared to mental leadership and to prevent the occurrence of prior years and the number of shares purchased under environmental contamination. the Employee Stock Purchase Plan. Further, we have not We do not expect costs related to these remediation yet determined the actual model we will use to calculate requirements to have a material adverse effect on our fair value. consolidated financial position or our results of operations. Our accrued liabilities for environmental matters were $41 million as of December 31, 2004 and $31 million as of FORWARD-LOOKING INFORMATION AND RISK FACTORS The Private Securities Litigation Reform Act of 1995 December 31, 2003. The liability covers numerous proper- provides safe harbor provisions for forward-looking ties and no individual property accounts for more than $5 information. Forward-looking information is based on million of the liability balance. We have subsidiaries that have been named as potentially responsible parties along projections and estimates, not historical information. Some statements in this Form 10-K are forward-looking and use with other third parties for 15 federal and state superfund words like “may,” “may not,” “believes,” “do not believe,” sites for which we have established a liability. As of “expects,” “do not expect,” “anticipates,” “do not anticipate,” December 31, 2004, those 15 sites accounted for approxi- and other expressions. We may also provide oral or written mately $11 million of our total $41 million liability. In some forward-looking information in other materials we release instances, we have been named a potentially responsible to the public. Forward-looking information involves risks party by a regulatory agency, but in each of those cases, we and uncertainties and reflects our best judgment based on do not believe we have any material liability. NEW ACCOUNTING PRONOUNCEMENTS In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, “Share-Based Payment.” We will adopt the provisions of SFAS No. 123R on July 1, 2005 using the modified prospective application. current information. Our results of operations can be affected by inaccurate assumptions we make or by known or unknown risks and uncertainties. In addition, other factors may affect the accuracy of our forward-looking information. As a result, no forward-looking information can be guaranteed. Actual events and the results of operations may vary materially. 43 We do not assume any responsibility to publicly update issues an audit report with their recommendations to our any of our forward-looking statements regardless of customer’s contracting officer. In the case of management whether factors change as a result of new information, systems and other contract administrative issues, the future events, or for any other reason. You should review contracting officer is generally with the Defense Contract any additional disclosures we make in our press releases Management Agency (DCMA). We then work with our and Forms 10-Q and 8-K filed with the SEC. We also customer to resolve the issues noted in the audit report. suggest that you listen to our quarterly earnings release Given the demands of working in Iraq and elsewhere for conference calls with financial analysts. the United States government, we expect that from time to While it is not possible to identify all factors, we time we will have disagreements or experience perform- continue to face many risks and uncertainties that could ance issues with the various government customers for cause actual results to differ from our forward-looking which we work. If our performance is unacceptable to our statements and potentially materially and adversely affect customer under any of our government contracts, the our financial condition and results of operations, including government retains the right to pursue remedies under any risks relating to: Legal Matters United States Government contract work We provide substantial work under our government contracts business to the United States Department of Defense and other governmental agencies, including worldwide United States Army logistics contracts, known as LogCAP, and contracts to rebuild Iraq’s petroleum industry, known as RIO and PCO Oil South. Our govern- ment services revenue related to Iraq totaled approximately $7.1 billion in 2004. Most of the services provided to the United States government are subject to cost-reimbursable contracts where we have the opportunity to earn an award fee based on our customer’s evaluation of the quality of our performance. These award fees are evaluated and granted by our customer periodically. For the LogCAP and RIO contracts, we recognize award fees based on our estimate of amounts to be awarded. In determining our estimates, we consider, among other things, past award experience for similar types of work. These estimates are adjusted to actual when the task orders are definitized and the award fees have been finalized by our customer. Our operations under United States government contracts are regularly reviewed and audited by the Defense Contract Audit Agency (DCAA) and other governmental agencies. The DCAA serves in an advisory role to our customer. When issues are found during the governmental agency audit process, these issues are typically discussed and reviewed with us. The DCAA then affected contract, which remedies could include threatened termination or termination. If any contract were so terminated, we may not receive award fees under the affected contract, and our ability to secure future contracts could be adversely affected, although we would receive payment for amounts owed for our allowable costs under cost-reimbursable contracts. Fuel. In December 2003, the DCAA issued a preliminary audit report that alleged that we may have overcharged the Department of Defense by $61 million in importing fuel into Iraq. The DCAA questioned costs associated with fuel purchases made in Kuwait that were more expensive than buying and transporting fuel from Turkey. We responded that we had maintained close coordination of the fuel mission with the Army Corps of Engineers (COE), which was our customer and oversaw the project, throughout the life of the task order and that the COE had directed us to use the Kuwait sources. After a review, the COE concluded that we obtained a fair price for the fuel. However, Department of Defense officials thereafter referred the matter to the agency’s inspector general, which we understand has commenced an investigation. The DCAA has issued various audit reports related to task orders under the RIO contract that reported $304 million in questioned and unsupported costs. The majority of these costs are associated with the humanitarian fuel mission. In these reports, the DCAA has compared fuel costs we incurred during the duration of the RIO contract in 2003 and early 2004 to fuel prices obtained by the 44 Defense Energy Supply Center (DESC) in April 2004 when individually immaterial matters we have reported relating the fuel mission was transferred to that agency. to our government contract work in Iraq. We also under- Investigations. On January 22, 2004, we announced the stand that current and former employees of KBR have identification by our internal audit function of a potential received subpoenas and have given or may give grand jury overbilling of approximately $6 million by La Nouvelle testimony relating to some of these matters. If criminal Trading & Contracting Company, W.L.L. (La Nouvelle), one wrongdoing were found, criminal penalties could range up of our subcontractors, under the LogCAP contract in Iraq, to the greater of $500,000 in fines per count for a corpora- for services performed during 2003. In accordance with our tion, or twice the gross pecuniary gain or loss. policy and government regulation, the potential overcharge Dining Facility and Administration Centers (DFACs). During was reported to the Department of Defense Inspector 2003, the DCAA raised issues relating to our invoicing to General’s office as well as to our customer, the AMC. On the Army Materiel Command (AMC) for food services for January 23, 2004, we issued a check in the amount of $6 soldiers and supporting civilian personnel in Iraq and million to the AMC to cover that potential overbilling while Kuwait. We believe the issues raised by the DCAA relate to we conducted our own investigation into the matter. Later the difference between the number of troops the AMC in the first quarter of 2004, we determined that the amount directed us to support and the number of soldiers counted of overbilling was $4 million, and the subcontractor billing at dining facilities for United States troops and supporting should have been $2 million for the services provided. As a civilian personnel. In the first quarter of 2004, we reviewed result, we paid La Nouvelle $2 million and billed our our DFAC subcontracts in our Iraq and Kuwait areas of customer that amount. We subsequently terminated La operation and have billed and continue to bill for all current Nouvelle’s services under the LogCAP contract. In October DFAC costs. During 2004, we received notice from the 2004, La Nouvelle filed suit against us alleging $224 million DCAA that it was recommending withholding a portion of in damages as a result of its termination. We are continuing our DFAC billings. For DFAC billings relating to subcon- to investigate whether La Nouvelle paid, or attempted to tracts entered into prior to February 2004, the DCAA has pay, one or two of our former employees in connection with recommended withholding 19.35% of the billings until it the billing. See Note 13 to our consolidated financial completes its audits. Subsequent to February 2004, we statements for further discussion. renegotiated our DFAC subcontracts to address the In October 2004, we reported to the Department of specific issues raised by the DCAA and advised the AMC Defense Inspector General’s office that two former and the DCAA of the new terms of the arrangements. We employees in Kuwait may have had inappropriate contacts have had no objection by the government to the terms and with individuals employed by or affiliated with two third- conditions associated with these new DFAC subcontract party subcontractors prior to the award of the subcontracts. agreements. During the third quarter of 2004, we received The Inspector General’s office may investigate whether notification that, for three Kuwait DFACs, the DCAA these two employees may have solicited and/or accepted recommended to our customer that costs be disallowed payments from these third-party subcontractors while they because the DCAA is not satisfied with the level of docu- were employed by us. mentation provided by us. The amount withheld related to In October 2004, a civilian contracting official in the suspended and recommended disallowed DFAC costs for COE asked for a review of the process used by the COE for work performed prior to February 2004 and totaled awarding some of the contracts to us. We understand that approximately $224 million as of December 31, 2004. The the Department of Defense Inspector General’s office may amount withheld could change as the DCAA continues review the issues involved. their audits of the remaining DFAC facilities. We are We understand that the United States Department of negotiating with our customer, the AMC, to resolve this Justice, an Assistant United States Attorney based in issue. We are currently withholding a proportionate Illinois, and others are investigating these and other amount of these billings from our subcontractors. 45 Laundry. During the third quarter of 2004, we received represent the amount invoiced in excess of 85% of the notice from the DCAA that it recommended withholding funding in the task order. The COE also could withhold $16 million of subcontract costs related to the laundry similar amounts from future invoices under our RIO service for one task order in southern Iraq for which it contract until agreement is reached with the customer and believes we and our subcontractors have not provided task order modifications are issued. Approximately $2 adequate levels of documentation supporting the quantity million was withheld from our PCO Oil South project as of of the services provided. The DCAA recommended that the December 31, 2004. The PCO Oil South project has cost be withheld pending receipt of additional explanation definitized 15 of the 28 task orders and withholdings are or documentation to support subcontract cost. This $16 not continuing on those task orders. We do not believe the million was withheld from the subcontractor in the fourth withholding will have a significant or sustained impact on quarter of 2004. We are working with the AMC to resolve our liquidity because the withholding is temporary and this issue. ends once the definitization process is complete. Withholding of payments. During 2004, the AMC issued a In addition, we had unapproved claims totaling $93 determination that a particular contract clause could cause million at December 31, 2004 for the LogCAP, RIO, and it to withhold 15% from our invoices until our task orders PCO Oil South contracts. These unapproved claims related under the LogCAP contract are definitized. The AMC to contracts where our costs have exceeded the funded delayed implementation of this withholding pending further value of the task order or were related to lost, damaged, review. The Army Field Support Command (AFSC) has and destroyed equipment. now been delegated authority by the AMC to determine We are working diligently with our customers to whether or not to implement the withholding. The AFSC proceed with significant new work only after we have a fully has informed us that it will assess the situation on a task definitized task order, which should limit withholdings on order by task order basis and, currently, withholding will future task orders. continue to be delayed. We do not believe any potential 15% Cost reporting. We have received notice that a contracting withholding will have a significant or sustained impact on officer for our PCO Oil South project considers our our liquidity because any withholding is temporary and monthly categorization and detail of costs and our ability to ends once the definitization process is complete. During schedule and forecast costs to be inadequate, and he has the third quarter of 2004, we and the AMC identified three requested corrections be made by March 10, 2005. We senior management teams to facilitate negotiation under expect to be able to make the requested corrections. If we the LogCAP task orders, and these teams are working to were unable to satisfy our customer, our customer may negotiate outstanding issues and definitize task orders as pursue remedies under the applicable federal acquisition quickly as possible. We are continuing to work with our regulations, including terminating the affected contract. customer to resolve outstanding issues. As of January 18, Although there can be no assurances, we do not expect that 2005, 25 task orders for LogCAP totaling over $636 million our work on the PCO Oil South project will be terminated had been definitized. for default. We are in the process of developing an accept- As of December 31, 2004, the COE had withheld $85 able management cost reporting system and are million of our invoices related to a portion of our RIO supplementing the existing PCO cost reporting team with contract pending completion of the definitization process. additional manpower. All 10 definitization proposals required under this contract The Balkans. We have had inquiries in the past by the have been submitted by us, and three have been finalized DCAA and the civil fraud division of the United States through a task order modification. After review by the Department of Justice into possible overcharges for work DCAA, we have resubmitted five of the unfinalized seven performed during 1996 through 2000 under a contract in proposals and are in the process of developing revised the Balkans, which inquiry has not yet been completed by proposals for the remaining two. These withholdings the Department of Justice. Based on an internal investiga- 46 tion, we credited our customer approximately $2 million principal of Tri-Star Investments, an agent of TSKJ, under during 2000 and 2001 related to our work in the Balkans as investigation for corruption of a foreign public official. In a result of billings for which support was not readily Nigeria, a legislative committee of the National Assembly available. We believe that the preliminary Department of and the Economic and Financial Crimes Commission, Justice inquiry relates to potential overcharges in connec- which is organized as part of the executive branch of the tion with a part of the Balkans contract under which government, are also investigating these matters. Our approximately $100 million in work was done. We believe representatives have met with the French magistrate and that any allegations of overcharges would be without merit. Nigerian officials and expressed our willingness to Nigerian joint venture and investigations cooperate with those investigations. In October 2004, Foreign Corrupt Practices Act investigation. The SEC is representatives of TSKJ voluntarily testified before the conducting a formal investigation into payments made in Nigerian legislative committee. connection with the construction and subsequent expan- As a result of our continuing investigation into these sion by TSKJ of a multibillion dollar natural gas liquefaction matters, information has been uncovered suggesting that, complex and related facilities at Bonny Island in Rivers commencing at least 10 years ago, the members of TSKJ State, Nigeria. The United States Department of Justice is considered payments to Nigerian officials. We provided this also conducting an investigation. TSKJ is a private limited information to the United States Department of Justice, the liability company registered in Madeira, Portugal whose SEC, the French magistrate, and the Nigerian Economic members are Technip SA of France, Snamprogetti and Financial Crimes Commission. We also notified the Netherlands B.V., which is an affiliate of ENI SpA of Italy, other owners of TSKJ of the recently uncovered informa- JGC Corporation of Japan, and Kellogg Brown & Root, each tion and asked each of them to conduct their own of which owns 25% of the venture. investigation. The SEC and the Department of Justice have been We understand from the ongoing governmental and reviewing these matters in light of the requirements of the other investigations that payments may have been made to United States Foreign Corrupt Practices Act. We have Nigerian officials. In addition, TSKJ has suspended the produced documents to the SEC both voluntarily and receipt of services from and payments to Tri-Star pursuant to subpoenas, and intend to make our employees Investments and is considering instituting legal proceed- available to the SEC for testimony. In addition, we under- ings to declare all agency agreements with Tri-Star stand that the SEC has issued a subpoena to A. Jack Investments terminated and to recover all amounts Stanley, who most recently served as a consultant and previously paid under those agreements. chairman of Kellogg Brown & Root, and to other current We also understand that the matters under investigation and former Kellogg Brown & Root employees. We further by the Department of Justice involve parties other than understand that the Department of Justice has invoked its Kellogg Brown & Root and M.W. Kellogg, Ltd. (a joint authority under a sitting grand jury to obtain letters venture in which Kellogg Brown & Root has a 55% inter- rogatory for the purpose of obtaining information abroad. est), cover an extended period of time (in some cases TSKJ and other similarly owned entities entered into significantly before our 1998 acquisition of Dresser various contracts to build and expand the liquefied natural Industries (which included M.W. Kellogg, Ltd.)), and gas project for Nigeria LNG Limited, which is owned by the possibly include the construction of a fertilizer plant in Nigerian National Petroleum Corporation, Shell Gas B.V., Nigeria in the early 1990s and the activities of agents and Cleag Limited (an affiliate of Total), and Agip International service providers. B.V., which is an affiliate of ENI SpA of Italy. Commencing In June 2004, we terminated all relationships with Mr. in 1995, TSKJ entered into a series of agency agreements in Stanley and another consultant and former employee of connection with the Nigerian project. We understand that a M.W. Kellogg, Ltd. The terminations occurred because of French magistrate has officially placed Jeffrey Tesler, a violations of our Code of Business Conduct that allegedly 47 involve the receipt of improper personal benefits in contracts business to KBR or affiliates or subsidiaries of connection with TSKJ’s construction of the natural gas KBR. Criminal prosecutions under applicable laws of liquefaction facility in Nigeria. relevant foreign jurisdictions and civil claims by or relation- In February 2005, TSKJ notified the Attorney General of ship issues with customers are also possible. Nigeria that TSKJ would not oppose the Attorney General’s There can be no assurance that the results of these efforts to have sums of money held on deposit in banks in investigations will not have a material adverse effect on our Switzerland transferred to Nigeria and to have the legal business and results of operations. ownership of such sums determined in the Nigerian courts. Operations in Iran If violations of the FCPA were found, we could be We received and responded to an inquiry in mid-2001 subject to civil penalties of $500,000 per violation and from the Office of Foreign Assets Control (OFAC) of the criminal penalties could range up to the greater of $2 United States Treasury Department with respect to million per violation or twice the gross pecuniary gain operations in Iran by a Halliburton subsidiary that is or loss. incorporated in the Cayman Islands. The OFAC inquiry There can be no assurance that any governmental requested information with respect to compliance with the investigation or our investigation of these matters will not Iranian Transaction Regulations. These regulations prohibit conclude that violations of applicable laws have occurred or United States citizens, including United States corporations that the results of these investigations will not have a and other United States business organizations, from material adverse effect on our business and results of engaging in commercial, financial, or trade transactions operations. with Iran, unless authorized by OFAC or exempted by Bidding practices investigation. In connection with the statute. Our 2001 written response to OFAC stated that we investigation into payments made in connection with the believed that we were in compliance with applicable Nigerian project, information has been uncovered suggest- sanction regulations. In January 2004, we received a follow- ing that Mr. Stanley and other former employees may have up letter from OFAC requesting additional information. We engaged in coordinated bidding with one or more competi- responded to this request on March 19, 2004. We under- tors on certain foreign construction projects and that such stand this matter has now been referred by OFAC to the coordination possibly began as early as the mid-1980s, Department of Justice. In July 2004, we received a grand which was significantly before our 1998 acquisition of jury subpoena from an Assistant United States District Dresser Industries. Attorney requesting the production of documents. We are On the basis of this information, we and the Department cooperating with the government’s investigation and have of Justice have broadened our investigations to determine responded to the subpoena by producing documents on the nature and extent of any improper bidding practices, September 16, 2004. whether such conduct violated United States antitrust laws, Separate from the OFAC inquiry, we completed a study and whether former employees may have received in 2003 of our activities in Iran during 2002 and 2003 and payments in connection with bidding practices on some concluded that these activities were in compliance with foreign projects. applicable sanction regulations. These sanction regulations If violations of applicable United States antitrust laws require isolation of entities that conduct activities in Iran occurred, the range of possible penalties includes criminal from contact with United States citizens or managers of fines, which could range up to the greater of $10 million in United States companies. Notwithstanding our conclusions fines per count for a corporation, or twice the gross that our activities in Iran were not in violation of United pecuniary gain or loss, and treble civil damages in favor of States laws and regulations, we have recently announced any persons financially injured by such violations. If such that, after fulfilling our current contractual obligations violations occurred, the United States government also within Iran, we intend to cease operations within that would have the discretion to deny future government country and to withdraw from further activities there. 48 Liquidity – expropriation and nationalization of our assets in that Working capital requirements related to Iraq work country; As described in “Legal Matters – United States – political and economic instability; Government contract work” above, it is possible that we – civil unrest, acts of terrorism, force majeure, war, or may, or may be required to, withhold additional invoicing other armed conflict; or make refunds to our customer related to the DCAA’s – natural disasters, including those related to earth- review of additional aspects of our services, some of which quakes and flooding; could be substantial, until these matters are resolved. – inflation; Although we do not expect this to occur, such an outcome – currency fluctuations, devaluations, and conversion could materially and adversely affect our liquidity. restrictions; Credit facilities We currently have: – confiscatory taxation or other adverse tax policies; – governmental activities that limit or disrupt markets, – a $700 million revolving credit facility, which expires restrict payments, or limit the movement of funds; in October 2006; and – governmental activities that may result in the depriva- – a $500 million 364-day revolving credit facility, which tion of contract rights; and expires in July 2005. – trade restrictions and economic embargoes imposed We experience increased working capital requirements by the United States and other countries, including from time to time associated with our business. An current limitations on our ability to provide products increased demand for working capital could affect our and services to Iran and Syria, which are significant liquidity needs. producers of oil and gas. Due to the unsettled political conditions in many oil- Geopolitical and International Environment producing countries and countries in which we provide International and Political Events governmental logistical support, our revenue and profits A significant portion of our revenue is derived from our are subject to the adverse consequences of war, the non-United States operations, which exposes us to risks effects of terrorism, civil unrest, strikes, currency controls, inherent in doing business in each of the more than 100 and governmental actions. Countries where we operate other countries in which we transact business. The that have significant amounts of political risk include: occurrence of any of the risks described below could have Afghanistan, Algeria, Indonesia, Iran, Iraq, Nigeria, Russia, a material adverse effect on our consolidated results of and Venezuela. In addition, military action or continued operations and consolidated financial condition. unrest in the Middle East could impact the supply and Our operations in more than 100 countries other than pricing for oil and gas, disrupt our operations in the the United States accounted for approximately 78% of our region and elsewhere, and increase our costs for security consolidated revenue during 2004, 73% of our consolidated worldwide. revenue during 2003, and 67% of our consolidated revenue In addition, investigations by governmental authorities during 2002. Based on the location of services provided and (see “Legal Matters – Nigerian joint venture and investiga- products sold, 26% of our consolidated revenue in 2004 and tions” above), as well as the social, economic, and political 15% in 2003 was from Iraq, primarily related to our work for climate in Nigeria, could materially and adversely affect our the United States government. Revenue from Iraq repre- Nigerian business and operations. In September 2004, the sented less than 10% in 2002. Operations in countries other Federal Republic of Nigeria issued a directive banning than the United States are subject to various risks peculiar Halliburton Energy Services Nigeria Limited, one of our to each country. With respect to any particular country, subsidiaries, from receiving contracts from the Nigerian these risks may include: government or from companies controlled by the Nigerian government. We believe this directive to have been issued 49 as a result of an adverse reaction in Nigeria to the theft of significant use of estimates and assumptions regarding the radioactive material that we used in wireline logging scope of future operations and results achieved and the operations, which was subsequently recovered and timing and nature of income earned and expenditures returned to Nigeria. We are currently working with the incurred. Changes in the operating environment including Nigerian government to obtain a lifting of the ban. If the changes in tax law and currency/repatriation controls ban is not lifted, it could have an adverse effect on our could impact the determination of our tax liabilities for a ability to conduct business in Nigeria. Our facilities and our tax year. employees are under threat of attack in some countries Foreign Exchange and Currency Risks where we operate, including Iraq and Saudi Arabia. In A sizable portion of our consolidated revenue and addition, the risk of loss of life of our personnel and of our consolidated operating expenses are in foreign currencies. subcontractors in these areas continues. As a result, we are subject to significant risks, including: Military Action, Other Armed Conflicts, or Terrorist Attacks – foreign exchange risks resulting from changes in Military action in Iraq and increasing military tension foreign exchange rates and the implementation of involving North Korea, as well as the terrorist attacks of exchange controls; and September 11, 2001 and subsequent terrorist attacks, – limitations on our ability to reinvest earnings from threats of attacks, and unrest, have caused instability in the operations in one country to fund the capital needs of world’s financial and commercial markets and have our operations in other countries. significantly increased political and economic instability in We conduct business in countries that have nontraded some of the geographic areas in which we operate. Acts of or “soft” currencies which, because of their restricted or terrorism and threats of armed conflicts in or around limited trading markets, may be more difficult to exchange various areas in which we operate, such as the Middle East for “hard” currency. We may accumulate cash in soft and Indonesia, could limit or disrupt markets and our currencies and we may be limited in our ability to convert operations, including disruptions resulting from the our profits into United States dollars or to repatriate the evacuation of personnel, cancellation of contracts, or the profits from those countries. loss of personnel or assets. We selectively use hedging transactions to limit our Such events may cause further disruption to financial exposure to risks from doing business in foreign curren- and commercial markets and may generate greater political cies. For those currencies that are not readily convertible, and economic instability in some of the geographic areas in our ability to hedge our exposure is limited because which we operate. In addition, any possible reprisals as a financial hedge instruments for those currencies are consequence of the war and ongoing military action in Iraq, nonexistent or limited. Our ability to hedge is also limited such as acts of terrorism in the United States or elsewhere, because pricing of hedging instruments, where they exist, could materially and adversely affect us in ways we cannot is often volatile and not necessarily efficient. predict at this time. Income Taxes In addition, the value of the derivative instruments could be impacted by: We have operations in more than 100 countries other – adverse movements in foreign exchange rates; than the United States. Consequently, we are subject to the – interest rates; jurisdiction of a significant number of taxing authorities. – commodity prices; or The income earned in these various jurisdictions is taxed – the value and time period of the derivative being on differing bases, including net income actually earned, different than the exposures or cash flows being net income deemed earned, and revenue-based tax hedged. withholding. The final determination of our tax liabilities involves the interpretation of local tax laws, tax treaties, and related authorities in each jurisdiction as well as the 50 Customers and Business Historically, the markets for oil and gas have been Exploration and Production Activity volatile and are likely to continue to be volatile in the Demand for our services and products depends on oil future. Spending on exploration and production activities and natural gas industry activity and expenditure levels that and capital expenditures for refining and distribution are directly affected by trends in oil and natural gas prices. facilities by large oil and gas companies have a significant Demand for our products and services is particularly impact on the activity levels of our businesses. sensitive to the level of exploration, development, and Barracuda-Caratinga Project production activity of, and the corresponding capital See Note 3 to the consolidated financial statements for a spending by, oil and natural gas companies, including discussion of this project and “Fixed-Price Engineering and national oil companies. Prices for oil and natural gas are Construction Projects” below. subject to large fluctuations in response to relatively minor Governmental and Capital Spending changes in the supply of and demand for oil and natural Our business is directly affected by changes in govern- gas, market uncertainty, and a variety of other factors that mental spending and capital expenditures by our are beyond our control. Any prolonged reduction in oil and customers. Some of the changes that may materially and natural gas prices will depress the immediate levels of adversely affect us include: exploration, development, and production activity, often – a decrease in the magnitude of governmental spend- reflected as changes in rig counts. Perceptions of longer- ing and outsourcing for military and logistical support term lower oil and natural gas prices by oil and gas of the type that we provide. For example, the current companies can similarly reduce or defer major expendi- level of government services being provided in the tures given the long-term nature of many large-scale Middle East may not continue for an extended period development projects. Lower levels of activity result in a of time; corresponding decline in the demand for our oil and – an increase in the magnitude of governmental natural gas well services and products that could have a spending and outsourcing for military and logistical material adverse effect on our revenue and profitability. support, which can materially and adversely affect our Factors affecting the prices of oil and natural gas include: liquidity needs as a result of additional or continued – governmental regulations, including the policies of working capital requirements to support this work; governments regarding the exploration for and – a decrease in capital spending by governments for production and development of their oil and natural infrastructure projects of the type that we undertake; gas reserves; – the consolidation of our customers, which has: – global weather conditions and natural disasters; – caused customers to reduce their capital spending, – worldwide political, military, and economic conditions; which has in turn reduced the demand for our – the level of oil production by non-OPEC countries and services and products; and the available excess production capacity within OPEC; – resulted in customer personnel changes, which – economic growth in China and India; in turn affects the timing of contract negotiations – oil refining capacity and shifts in end-customer and settlements of claims and claim negotiations preferences toward fuel efficiency and the use of with engineering and construction customers on natural gas; cost variances and change orders on major projects; – the cost of producing and delivering oil and gas; – adverse developments in the business and operations – potential acceleration of development of alternative of our customers in the oil and gas industry, including fuels; and write-downs of reserves and reductions in capital – the level of demand for oil and natural gas, especially spending for exploration, development, production, demand for natural gas in the United States. processing, refining, and pipeline delivery networks; and 51 – ability of our customers to timely pay the amounts a number of quarters and to seek resolution of governmen- due us. Customers tal issues, investigations, and other disputes. We conduct some operations through joint ventures, Both our Energy Services Group and KBR depend on a where control may be shared with unaffiliated third parties. limited number of significant customers. While, except for As with any joint venture arrangement, differences in views the United States government, none of these customers among the joint venture participants may result in delayed represented more than 10% of consolidated revenue in any decisions or in failures to agree on major issues. We also period presented, the loss of one or more significant cannot control the actions of our joint venture partners, customers could have a material adverse effect on our including any nonperformance, default, or bankruptcy business and our consolidated results of operations. of our joint venture partners. These factors could poten- Acquisitions, Dispositions, Investments, and Joint Ventures tially materially and adversely affect the business and We may actively seek opportunities to maximize operations of the joint venture and, in turn, our business efficiency and value through various transactions, including and operations. purchases or sales of assets, businesses, investments, or Fixed-Price Contracts contractual arrangements or joint ventures. These transac- We contract to provide services either on a cost- tions would be intended to result in the realization of reimbursable basis or on a fixed-price basis, with savings, the creation of efficiencies, the generation of cash fixed-price (or lump-sum) contracts accounting for approxi- or income, or the reduction of risk. Acquisition transactions mately 11% of consolidated revenue for the year ended may be financed by additional borrowings or by the December 31, 2004 and 14% for the year ended December issuance of our common stock. These transactions may 31, 2003. We bear the risk of cost overruns, operating cost also affect our consolidated results of operations. inflation, labor availability and productivity, and supplier These transactions also involve risks and we cannot and subcontractor pricing and performance in connection ensure that: with projects covered by fixed-price contracts. Our failure – any acquisitions would result in an increase in income; to estimate accurately the resources and time required for – any acquisitions would be successfully integrated into a fixed-price project, or our failure to complete our contrac- our operations; tual obligations within the time frame and costs committed, – any disposition would not result in decreased earn- could have a material adverse effect on our business, ings, revenue, or cash flow; results of operations, and financial condition. – any dispositions, investments, acquisitions, or Environmental Requirements integrations would not divert management resources; Our businesses are subject to a variety of environmental or laws, rules, and regulations in the United States and other – any dispositions, investments, acquisitions, or countries, including those covering hazardous materials integrations would not have a material adverse effect and requiring emission performance standards for on our results of operations or financial condition. facilities. For example, our well service operations routinely Now that we have resolved our asbestos and silica involve the handling of significant amounts of waste liability and our affected subsidiaries have exited Chapter materials, some of which are classified as hazardous 11 reorganization proceedings, we intend to separate KBR substances. We also store, transport, and use radioactive from Halliburton, which could include a transaction and explosive materials in certain of our operations. involving a spin-off, split-off, public offering, or sale of KBR Environmental requirements include, for example, or its operations. In order to maximize KBR’s value for our those concerning: shareholders, and to determine the most appropriate form – the containment and disposal of hazardous sub- of the transaction and its components, it may be necessary stances, oilfield waste, and other waste materials; for KBR to establish a track record of positive earnings for – the importation and use of radioactive materials; 52 – the use of underground storage tanks; and the future and these rights could be invalidated, circum- – the use of underground injection wells. vented, or challenged. In addition, the laws of some foreign Environmental and other similar requirements generally countries in which our products and services may be sold are becoming increasingly strict. Sanctions for failure to do not protect intellectual property rights to the same comply with these requirements, many of which may be extent as the laws of the United States. Our failure to applied retroactively, may include: protect our proprietary information and any successful – administrative, civil, and criminal penalties; intellectual property challenges or infringement proceed- – revocation of permits to conduct business; and ings against us could materially and adversely affect our – corrective action orders, including orders to investi- competitive position. gate and/or clean up contamination. Technology Failure on our part to comply with applicable environ- The market for our products and services is character- mental requirements could have a material adverse effect ized by continual technological developments to provide on our consolidated financial condition. We are also better and more reliable performance and services. If we exposed to costs arising from environmental compliance, are not able to design, develop, and produce commercially including compliance with changes in or expansion of competitive products and to implement commercially environmental requirements, such as the potential regula- competitive services in a timely manner in response to tion in the United States of our Energy Services Group’s changes in technology, our business and revenue could be hydraulic fracturing services and products as underground materially and adversely affected and the value of our injection, which could have a material adverse effect on intellectual property may be reduced. Likewise, if our our business, financial condition, operating results, or proprietary technologies, equipment and facilities, or work cash flows. processes become obsolete, we may no longer be competi- We are exposed to claims under environmental require- tive and our business and revenue could be materially and ments and, from time to time, such claims have been made adversely affected. against us. In the United States, environmental require- Systems ments and regulations typically impose strict liability. Strict Our business could be materially and adversely affected liability means that in some situations we could be exposed by problems encountered in the installation of a new SAP to liability for cleanup costs, natural resource damages, and financial system to replace the current systems for KBR. other damages as a result of our conduct that was lawful at Technical Personnel the time it occurred or the conduct of prior operators or Many of the services that we provide and the products other third parties. Liability for damages arising as a that we sell are complex and highly engineered and often result of environmental laws could be substantial and could must perform or be performed in harsh conditions. We have a material adverse effect on our consolidated results believe that our success depends upon our ability to employ of operations. and retain technical personnel with the ability to design, Changes in environmental requirements may negatively utilize, and enhance these products and services. In impact demand for our services. For example, oil and addition, our ability to expand our operations depends in natural gas exploration and production may decline as a part on our ability to increase our skilled labor force. The result of environmental requirements (including land use demand for skilled workers is high and the supply is policies responsive to environmental concerns). Such a limited. A significant increase in the wages paid by decline, in turn, could have a material adverse effect on us. competing employers could result in a reduction of our Intellectual Property Rights skilled labor force, increases in the wage rates that we must We rely on a variety of intellectual property rights that pay, or both. If either of these events were to occur, our we use in our products and services. We may not be able to cost structure could increase, our margins could decrease, successfully preserve these intellectual property rights in and our growth potential could be impaired. 53 Weather Our businesses could be materially and adversely affected by severe weather, particularly in the Gulf of Mexico where we have significant operations. Repercussions of severe weather conditions may include: – evacuation of personnel and curtailment of services; – weather-related damage to offshore drilling rigs resulting in suspension of operations; – weather-related damage to our facilities; – inability to deliver materials to jobsites in accordance with contract schedules; and – loss of productivity. Because demand for natural gas in the United States drives a disproportionate amount of our Energy Services Group’s United States business, warmer than normal winters in the United States are detrimental to the demand for our services to gas producers. 54 MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING The management of Halliburton Company is responsi- ble for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time. Under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, we conducted an evaluation to assess the effectiveness of our internal control over financial reporting as of December 31, 2004 based upon criteria set forth in the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that, as of December 31, 2004, our internal control over financial reporting is effective. Our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by our independent registered public accounting firm, KPMG LLP. Their audit opinion on our assessment of internal control over financial reporting is on page 57. HALLIBURTON COMPANY by David J. Lesar C. Christopher Gaut Chairman of the Board, Executive Vice President and President, and Chief Financial Officer Chief Executive Officer 55 We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Halliburton Company’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 25, 2005 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting. Houston, Texas February 25, 2005 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM THE BOARD OF DIRECTORS AND SHAREHOLDERS HALLIBURTON COMPANY We have audited the accompanying consolidated balance sheets of Halliburton Company and subsidiaries as of December 31, 2004 and December 31, 2003, and the related consolidated statements of operations, sharehold- ers’ equity, and cash flows for each of the years in the three-year period ended December 31, 2004. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial state- ments based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Halliburton Company and subsidiaries as of December 31, 2004 and December 31, 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted account- ing principles. As described in Note 5 to the consolidated financial statements, the Company changed the composition of its reportable segments in 2004 and 2003. The amounts in the 2003 and 2002 consolidated financial statements related to reportable segments have been restated to conform to the 2004 composition of reportable segments. 56 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM THE BOARD OF DIRECTORS AND SHAREHOLDERS HALLIBURTON COMPANY We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting appearing on page 55, that Halliburton Company maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Halliburton Company’s management is responsi- ble for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the stan- dards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effective- ness of internal control, and performing such other procedures as we considered necessary in the circum- stances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and disposi- tions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the com- pany’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstate- ments. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or proce- dures may deteriorate. In our opinion, management’s assessment that Halliburton Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control – Integrated Framework issued by COSO. Also, in our opinion, Halliburton Company main- tained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by COSO. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Halliburton Company and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2004, and our report dated February 25, 2005 expressed an unqualified opinion on those consolidated financial statements. Houston, Texas February 25, 2005 57 HALLIBURTON COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (Millions of dollars and shares except per share data) Revenue: Services Product sales Equity in earnings of unconsolidated affiliates, net Total revenue Operating costs and expenses: Cost of services Cost of sales General and administrative Gain on sale of business assets, net Total operating costs and expenses Operating income (loss) Interest expense Interest income Foreign currency gains (losses), net Other, net Income (loss) from continuing operations before income taxes, minority interest, and change in accounting principle Provision for income taxes Minority interest in net income of subsidiaries Income (loss) from continuing operations before change in accounting principle Loss from discontinued operations, net of tax (provision) benefit of $180, $(6), and $154 Cumulative effect of change in accounting principle, net of tax benefit of $5 Net loss Basic income (loss) per share: Income (loss) from continuing operations before change in accounting principle Loss from discontinued operations, net Cumulative effect of change in accounting principle, net Net loss Diluted income (loss) per share: Income (loss) from continuing operations before change in accounting principle Loss from discontinued operations, net Cumulative effect of change in accounting principle, net Net loss Basic weighted average common shares outstanding Diluted weighted average common shares outstanding See notes to consolidated financial statements. 58 Years ended December 31 2004 2003 2002 $18,327 2,137 2 20,466 17,441 1,882 361 (55) 19,629 837 (229) 44 (3) 2 651 (241) (25) 385 $14,383 1,863 25 16,271 13,589 1,679 330 (47) 15,551 720 (139) 30 – 1 612 (234) (39) 339 (1,364) (1,151) $10,658 1,840 74 12,572 10,737 1,642 335 (30) 12,684 (112) (113) 32 (25) (10) (228) (80) (38) (346) (652) – $ (979) (8) $ (820) – $ (998) $ 0.88 (3.13) – $ (2.25) $ 0.87 (3.09) – $ (2.22) 437 441 $ 0.78 (2.65) (0.02) $ (1.89) $ (0.80) (1.51) – $ (2.31) $ 0.78 (2.64) (0.02) $ (1.88) 434 437 $ (0.80) (1.51) – $ (2.31) 432 432 HALLIBURTON COMPANY CONSOLIDATED BALANCE SHEETS (Millions of dollars and shares except per share data) Current assets: Cash and equivalents Receivables: Assets Notes and accounts receivable (less allowance for bad debts of $127 and $175) Unbilled work on uncompleted contracts Insurance for asbestos- and silica-related liabilities Total receivables Inventories Other current assets Total current assets Net property, plant, and equipment Goodwill Noncurrent deferred income taxes Equity in and advances to related companies Insurance for asbestos- and silica-related liabilities Other assets Total assets Liabilities and Shareholders’ Equity Current liabilities: Asbestos- and silica-related liabilities Accounts payable Advance billings on uncompleted contracts Accrued employee compensation and benefits Current maturities of long-term debt Other current liabilities Total current liabilities Long-term debt Employee compensation and benefits Asbestos- and silica-related liabilities Other liabilities Total liabilities Minority interest in consolidated subsidiaries Shareholders’ equity: Common shares, par value $2.50 per share – authorized 1,000 and 600 shares, issued 458 and 457 shares Paid-in capital in excess of par value Common shares to be contributed to asbestos trust – 59.5 shares Deferred compensation Accumulated other comprehensive income Retained earnings Less 16 and 18 shares of treasury stock, at cost Total shareholders’ equity Total liabilities and shareholders’ equity See notes to consolidated financial statements. December 31 2004 2003 $ 2,808 $ 1,815 2,873 1,812 1,066 5,751 723 680 9,962 2,553 795 780 541 350 815 $15,796 $ 2,408 2,271 553 473 347 1,012 7,064 3,593 635 37 427 11,756 108 1,146 277 2,335 (74) (146) 871 4,409 477 3,932 $15,796 2,909 1,760 96 4,765 695 644 7,919 2,526 670 774 579 2,038 993 $15,499 $ 2,507 1,776 741 400 22 1,118 6,564 3,415 801 1,579 493 12,852 100 1,142 273 – (64) (298) 2,071 3,124 577 2,547 $15,499 59 HALLIBURTON COMPANY CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Millions of dollars and shares) Balance at January 1 Dividends and other transactions with shareholders Common shares to be contributed to asbestos trust – 59.5 shares Comprehensive loss: Net loss Cumulative translation adjustment Realization of (gains) losses included in net loss Net cumulative translation adjustment Pension liability adjustments Unrealized gains on investments and derivatives Total comprehensive loss Balance at December 31 See notes to consolidated financial statements. 2004 $2,547 (123) 2,335 (979) 33 (1) 32 115 5 (827) $3,932 2003 $3,558 (174) 2002 $4,752 (151) – – (820) (998) 43 15 58 (88) 13 (837) $2,547 69 15 84 (130) 1 (1,043) $3,558 60 HALLIBURTON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of dollars) Cash flows from operating activities: Net loss Adjustments to reconcile net income (loss) to net cash from operations: Loss from discontinued operations Asbestos and silica charges not included in discontinued operations, net Depreciation, depletion, and amortization Provision (benefit) for deferred income taxes, including $(167), $27, and $(133) related to discontinued operations Distributions from (advances to) related companies, net of equity in (earnings) losses Change in accounting principle, net Gain on sale of assets Asbestos and silica liability payment related to Chapter 11 filing Other changes: Accounts receivable Accounts receivable facilities transactions Inventories Accounts payable Other Total cash flows from operating activities Cash flows from investing activities: Capital expenditures Sales of property, plant, and equipment Dispositions (acquisitions) of businesses assets, net of cash disposed Proceeds from sale of securities Investments – restricted cash Other investing activities Total cash flows from investing activities Cash flows from financing activities: Proceeds from long-term borrowings, net of offering costs Proceeds from exercises of stock options Payments to reacquire common stock Borrowings (repayments) of short-term debt, net Payments on long-term borrowings Payments of dividends to shareholders Other financing activities Total cash flows from financing activities Effect of exchange rate changes on cash Increase in cash and equivalents Cash and equivalents at beginning of year Cash and equivalents at end of year Supplemental disclosure of cash flow information: Cash payments during the year for: Interest Income taxes See notes to consolidated financial statements. Years ended December 31 2004 2003 2002 $ (979) $ (820) $ (998) 1,364 – 509 (176) (39) – (62) (119) (506) 519 (22) 428 11 928 (575) 166 102 22 89 (30) (226) 496 63 (7) (7) (20) (221) (21) 283 8 993 1,815 $2,808 $ 189 $ 265 1,151 – 518 (86) 13 8 (52) (311) (1,442) (180) 7 676 (257) (775) (515) 107 224 57 (18) (51) (196) 2,192 21 (6) (32) (296) (219) (24) 1,636 43 708 1,107 $1,815 652 530 505 (151) 3 – (25) – 675 180 62 71 58 1,562 (764) 266 170 62 (187) (20) (473) 66 – (4) (2) (81) (219) (8) (248) (24) 817 290 $1,107 $ 114 $ 173 $ 104 $ 94 61 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. DESCRIPTION OF COMPANY AND SIGNIFICANT ACCOUNTING POLICIES Description of Company. Halliburton Company’s predeces- sor was established in 1919 and incorporated under the laws of the State of Delaware in 1924. We are one of the world’s largest oilfield services companies and a leading provider of engineering and construction services. We have six business segments that are organized around how we manage our business: Production Optimization, Fluid Systems, Drilling and Formation Evaluation, and Digital and Consulting Solutions (formerly Landmark and Other Energy Services), collectively, the Energy Services Group; and Government and Infrastructure and Energy and Chemicals, collectively known as KBR. Through our Energy Services Group, we provide a comprehensive range of discrete and integrated products and services for the exploration, development, and production of oil and gas. We serve major, national, and independent oil and gas companies throughout the world. KBR provides a wide range of services to energy and industrial customers and governmental entities worldwide. Use of estimates. Our financial statements are prepared in conformity with accounting principles generally accepted in the United States, requiring us to make estimates and assumptions that affect: – the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements; and – the reported amounts of revenue and expenses during the reporting period. Ultimate results could differ from those estimates. Basis of presentation. The consolidated financial state- ments include the accounts of our company and all of our subsidiaries which we control or variable interest entities for which we have determined that we are the primary beneficiary (see Note 20). All material intercompany accounts and transactions are eliminated. Investments in companies in which we have a significant influence are accounted for using the equity method, and if we do not have significant influence we use the cost method. Certain prior year amounts have been reclassified to conform to the current year presentation. Revenue recognition. We generally recognize revenue as services are rendered or products are shipped. Usually the date of shipment corresponds to the date upon which the customer takes title to the product and assumes all risks and rewards of ownership. The distinction between services and product sales is based upon the overall activity of the particular business operation. Training and consult- ing service revenue is recognized as the services are performed. In accordance with Emerging Issues Task Force Issue No. 00-21 (EITF No. 00-21), “Revenue Arrangements with Multiple Deliverables,” for contracts containing multiple deliverables entered into after June 30, 2003 that contain performance awards, award fees related to service components of the contract are recognized when they are awarded by our customer. For such contracts entered into prior to June 30, 2003, these award fees are recognized as services are performed based on our estimate of the amount to be awarded. For service-only contracts, award fees are recognized only when awarded by the customer. Revenue recognition for specialized products and services follows. Revenue from contracts to provide construction, engineering, design, or similar services, almost all of which relates to KBR, is reported on the percentage-of-completion method of accounting. Progress is generally based upon physical progress, man-hours, or costs incurred, depending on the type of job. All known or anticipated losses on contracts are provided for when they become evident. Claims and change orders that are in the process of being negotiated with customers for extra work or changes in the scope of work are included in revenue when collection is deemed probable. Accounting for government contracts. Most of the services provided to the United States government are governed by cost-reimbursable contracts. Generally, these contracts contain both a base fee (a fixed profit percentage applied to our actual costs to complete the work) and an award fee (a variable profit percentage, subject to our customer’s discretion and tied to the specific performance measures 62 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS defined in the contract). Similar to many cost-reimbursable revenue and recognized as revenue ratably over the contracts, these government contracts are typically subject contract period, generally a one-year duration. to audit and adjustment by our customer. Services under Research and development. Research and development our LogCAP, RIO, PCO Oil South, and Balkans support expenses are charged to income as incurred. Research and contracts are examples of these types of arrangements. development expenses were $234 million in 2004, $221 For these contracts, base fee revenue is recorded at the million in 2003, and $233 million in 2002, of which over 96% time services are performed based upon actual project was company-sponsored in each year. costs incurred and include a reimbursement fee for Software development costs. Costs of developing software general, administrative, and overhead costs and the base for sale are charged to expense when incurred, as research fee. The general, administrative, and overhead fees are and development, until technological feasibility has been estimated periodically in accordance with government established for the product. Once technological feasibility contract accounting regulations and may change based on is established, software development costs are capitalized actual costs incurred or based upon the volume of work until the software is ready for general release to customers. performed. Revenue may be adjusted for our estimate of We capitalized costs related to software developed for costs that may be categorized as disputed or unallowable as resale of $16 million in 2004, $17 million in 2003, and $11 a result of cost overruns or the audit process. million in 2002. Amortization expense of software develop- Award fees are generally evaluated and granted ment costs was $22 million for 2004, $17 million for 2003, periodically by our customer. For contracts entered into and $19 million for 2002. Once the software is ready for prior to June 30, 2003, all award fees are recognized during release, amortization of the software development costs the term of the contract based on our estimate of amounts begins. Capitalized software development costs are to be awarded. Once award fees are granted and task amortized over periods which do not exceed five years. orders underlying the work are definitized, we adjust our Cash equivalents. We consider all highly liquid invest- estimate of award fees to actual amounts earned. Our ments with an original maturity of three months or less to estimates are often based on our past award experience for be cash equivalents. similar types of work. In accordance with EITF No. 00-21, Inventories. Inventories are stated at the lower of cost or for contracts containing multiple deliverables entered into market. Cost represents invoice or production cost for new subsequent to June 30, 2003 (such as PCO Oil South), we items and original cost less allowance for condition for used do not recognize award fees for the services portion of the material returned to stock. Production cost includes contract based on estimates. Instead, they are recognized material, labor, and manufacturing overhead. Some only when definitized and awarded by the customer. Also, domestic manufacturing and field service finished products for service-only contracts, award fees are recognized only and parts inventories for drill bits, completion products, when awarded by the customer. Award fees on government and bulk materials are recorded using the last-in, first-out construction contracts are recognized during the term of method. The cost of over 95% of the remaining inventory is the contract based on our estimate of the amount of fees to recorded on the average cost method, with the remainder be awarded. on the first-in, first-out method. Software sales. Software sales of perpetual software Allowance for bad debts. We establish an allowance for licenses, net of deferred maintenance fees, are recorded as bad debts through a review of several factors including: revenue upon shipment. Sales of use licenses are recog- historical collection experience; current aging status of the nized as revenue over the license period. Post-contract customer accounts; financial condition of our customers; customer support agreements are recorded as deferred and whether the receivables involve retentions or billing disputes. 63 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Property, plant, and equipment. Other than those assets Income taxes. We recognize the amount of taxes payable that have been written down to their fair values due to or refundable for the year. In addition, deferred tax assets impairment, property, plant, and equipment are reported and liabilities are recognized for the expected future tax at cost less accumulated depreciation, which is generally consequences of events that have been recognized in the provided on the straight-line method over the estimated financial statements or tax returns. A valuation allowance is useful lives of the assets. Some assets are depreciated on provided for deferred tax assets if it is more likely than not accelerated methods. Accelerated depreciation methods that these items will not be realized. are also used for tax purposes, wherever permitted. Upon In assessing the realizability of deferred tax assets, sale or retirement of an asset, the related costs and management considers whether it is more likely than not accumulated depreciation are removed from the accounts that some portion or all of the deferred tax assets will not and any gain or loss is recognized. We follow the successful be realized. The ultimate realization of deferred tax assets efforts method of accounting for oil and gas properties. is dependent upon the generation of future taxable income Goodwill. The reported amounts of goodwill for each during the periods in which those temporary differences reporting unit are reviewed for impairment on an annual become deductible. Management considers the scheduled basis and more frequently when negative conditions such reversal of deferred tax liabilities, projected future taxable as significant current or projected operating losses exist. income, and tax planning strategies in making this assess- The annual impairment test for goodwill is a two-step ment. Based upon the level of historical taxable income and process and involves comparing the estimated fair value of projections for future taxable income over the periods in each reporting unit to the reporting unit’s carrying value, which the deferred tax assets are deductible, management including goodwill. If the fair value of a reporting unit believes it is more likely than not that we will realize the exceeds its carrying amount, goodwill of the reporting benefits of these deductible differences, net of the existing unit is not considered impaired, and the second step of valuation allowances. the impairment test is unnecessary. If the carrying amount We generally do not provide income taxes on the of a reporting unit exceeds its fair value, the second step undistributed earnings of non-United States subsidiaries of the goodwill impairment test would be performed to because such earnings are intended to be reinvested measure the amount of impairment loss to be recorded, indefinitely to finance foreign activities. Taxes are provided if any. Our annual impairment tests resulted in no goodwill as necessary with respect to earnings which are not impairment. permanently reinvested. The American Job Creations Act Evaluating impairment of long-lived assets. When events or of 2004 introduced a special dividends-received deduction changes in circumstances indicate that long-lived assets with respect to the repatriation of certain foreign earnings other than goodwill may be impaired, an evaluation is to a United States taxpayer under certain circumstances. performed. For an asset classified as held for use, the Based on our analysis of the Act, we do not expect to utilize estimated future undiscounted cash flows associated with the special deduction. the asset are compared to the asset’s carrying amount to Derivative instruments. At times, we enter into derivative determine if a write-down to fair value is required. When financial transactions to hedge existing or projected an asset is classified as held for sale, the asset’s book exposures to changing foreign currency exchange rates, value is evaluated and adjusted to the lower of its carrying interest rates, and commodity prices. We do not enter into amount or fair value less cost to sell. In addition, derivative transactions for speculative or trading purposes. depreciation (amortization) is ceased while it is classified We recognize all derivatives on the balance sheet at fair as held for sale. 64 value. Derivatives that are not hedges are adjusted to fair value and reflected through the results of operations. If the HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS derivative is designated as a hedge, depending on the addition, no cost for the Employee Stock Purchase Plan is nature of the hedge, changes in the fair value of derivatives reflected in net income because it is not considered a are either offset against : compensatory plan. the change in fair value of the hedged assets, – The fair value of options at the date of grant was liabilities, or firm commitments through earnings; or estimated using the Black-Scholes option pricing model. – recognized in other comprehensive income until the The weighted average assumptions and resulting fair hedged item is recognized in earnings. values of options granted are as follows: The ineffective portion of a derivative’s change in fair value is recognized in earnings. Recognized gains or losses on derivatives entered into to manage foreign exchange risk are included in foreign currency gains and losses in 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. 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 revenue, 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 not the United States dollar translate net assets at year-end rates and income and expense accounts at average exchange rates. Adjustments resulting from these translations are reflected in the consolidated statements of shareholders’ equity as cumulative translation adjustments. Stock-based compensation. At December 31, 2004, we have six stock-based employee compensation plans. We account for these plans under the recognition and measurement principles of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. No cost for stock options granted is reflected in net income, as all options granted under our plans have an exercise price equal to the market value of the underlying common stock on the date of grant. In Assumptions Risk-Free Interest Rate 3.7% 3.2% 2.9% Expected Dividend Yield 1.3% 1.9% 2.7% Expected Life (in years) 5 5 5 Expected Volatility 54% 59% 63% Weighted Average Fair Value of Options Granted $13.37 $12.37 $6.89 2004 2003 2002 Included in the pro forma compensation table below is the fair value of the employee stock purchase plan shares. The fair value of these shares was estimated using the Black-Scholes model with the following assumptions for 2004: risk-free interest rate of 2.6%; expected dividend yield of 1.3%; expected life of six months; and expected volatility of 27%. The following table illustrates the effect on net loss and loss per share if we had applied the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation. Millions of dollars except per share Net loss, as reported Total stock-based employee compensation expense determined under fair value based method for all awards (except restricted stock), net of related tax effects Net loss, pro forma Basic loss per share: As reported Pro forma Diluted loss per share: As reported Pro forma Years ended December 31 2004 $ (979) 2003 2002 $ (820) $ (998) (28) $(1,007) (30) $ (850) (26) $(1,024) $ (2.25) $ (2.31) $(1.89) $ (2.31) $(1.96) $ (2.37) $ (2.22) $ (2.28) $(1.88) $ (2.31) $(1.95) $ (2.37) We also maintain a restricted stock program wherein the fair market value of the stock on the date of issuance is amortized and ratably charged to income over the average period during which the restrictions lapse. The related expense, net of tax, reflected in net income as reported was $14 million in 2004, $13 million in 2003, and $24 million in 2002. 65 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS See Note 15 for further detail on stock incentive plans. accounting. Billings in excess of recognized revenue are In December 2004, the Financial Accounting Standards recorded in “Advance billings on uncompleted contracts.” Board (FASB) issued SFAS No. 123R, “Share-Based When billings are less than recognized revenue, the Payment.” We will adopt the provisions of SFAS No. 123R difference is recorded in “Unbilled work on uncompleted on July 1, 2005 using the modified prospective application. contracts.” With the exception of claims and change Accordingly, we will recognize compensation expense for orders that are in the process of being negotiated with all newly granted awards and awards modified, repur- customers, unbilled work is usually billed during chased, or cancelled after July 1, 2005. Compensation cost normal billing processes following achievement of the for the unvested portion of awards that are outstanding as contractual requirements. of July 1, 2005 will be recognized ratably over the remain- Recording of profits and losses on long-term contracts ing vesting period. The compensation cost for the unvested requires an estimate of the total profit or loss over the life portion of awards will be based on the fair value at date of of each contract. This estimate requires consideration of grant as calculated for our pro forma disclosure under contract revenue, change orders and claims reduced by SFAS No. 123. We will recognize compensation expense for costs incurred, and estimated costs to complete. our Employee Stock Purchase Program beginning with the Anticipated losses on contracts are recorded in full in the July 1, 2005 purchase period. period they become evident. Except in a limited number of We estimate that the effect on net income and earnings projects that have significant uncertainties in the estimation per share in the periods following adoption of SFAS No. of costs, we do not delay income recognition until projects 123R will be consistent with our pro forma disclosure under have reached a specified percentage of completion. SFAS No. 123, except that estimated forfeitures will be Generally, profits are recorded from the commencement considered in the calculation of compensation expense date of the contract based upon the total estimated contract under SFAS No. 123R. Additionally, the actual effect on net profit multiplied by the current percentage complete for income and earnings per share will vary depending upon the contract. the number of options granted in 2005 compared to prior When calculating the amount of total profit or loss on a years, and the number of shares purchased under the long-term contract, we include unapproved claims as Employee Stock Purchase Plan. Further, we have not revenue when the collection is deemed probable based yet determined the actual model we will use to calculate upon the four criteria for recognizing unapproved claims fair value. under the American Institute of Certified Public NOTE 2. PERCENTAGE-OF-COMPLETION CONTRACTS Revenue from contracts to provide construction, engineering, design, or similar services is reported on the percentage-of-completion method of accounting using measurements of progress toward completion appropriate for the work performed. Commonly used measurements are physical progress, man-hours, and costs incurred. Billing practices for these projects are governed by the contract terms of each project based upon costs incurred, achievement of milestones, or pre-agreed schedules. Billings do not necessarily correlate with revenue recog- nized under the percentage-of-completion method of Accountants Statement of Position 81-1, “Accounting for Performance of Construction-Type and Certain Production- Type Contracts.” Including unapproved claims in this calculation increases the operating income (or reduces the operating loss) that would otherwise be recorded without consideration of the probable unapproved claims. Probable unapproved claims are recorded to the extent of costs incurred and include no profit element. In all cases, the probable unapproved claims included in determining contract profit or loss are less than the actual claim that will be or has been presented to the customer. When recording the revenue and the associated unbilled receivable for unapproved claims, we only accrue 66 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS an amount equal to the costs incurred related to probable claims of $114 million at December 31, 2003 for a payment unapproved claims. Therefore, the difference between the in January 2005 of $79 million. probable unapproved claims included in determining We have contracts with probable unapproved claims that contract profit or loss and the probable unapproved claims will likely not be settled within one year totaling $153 recorded in unbilled work on uncompleted contracts million at December 31, 2004 and $204 million at December relates to forecasted costs which have not yet been 31, 2003 included in the table above, which are reflected as incurred. The amounts included in determining the profit “Other assets” on the consolidated balance sheets. Other or loss on contracts and the amounts booked to “Unbilled probable unapproved claims that we believe will be settled work on uncompleted contracts” for each period are as within one year included in the table above have been follows: Total Probable Unapproved Claims (included in determining contract profit or loss) 2003 $279 63 (94) 2002 $137 158 (11) Millions of dollars Beginning balance Additions Claims resolved Costs incurred during period Other Ending balance 2004 $233 113 (172) – 8 $182 Probable Unapproved Claims Accrued Revenue (unbilled work on uncompleted contracts) 2004 $225 110 (165) 2003 2002 $210 $102 105 (11) 61 (94) recorded to “Unbilled work on uncompleted contracts” included in the “Total receivables” amount on the consoli- dated balance sheets. Unapproved change orders. We have other contracts for which we are negotiating change orders to the contract scope and have agreed upon the scope of work but not the – (15) $233 – (5) $279 6 6 $182 63 (15) 19 (5) $225 $210 price. These change orders amount to $43 million at December 31, 2004. Unapproved change orders at The probable unapproved claims as of December 31, 2004 relate to four contracts, most of which are complete or substantially complete. The additions in 2004 to probable unapproved claims include $110 million for contracts with Petroleos Mexicanos (PEMEX), which was reclassified from unapproved change orders. A significant portion of the total probable unapproved claims ($153 million related to our consolidated entities and $45 million related to our unconsolidated related compa- nies) arose from three completed projects with PEMEX that are currently subject to arbitration proceedings. In addition, we have “Other assets” of $64 million for previ- ously approved services that are unpaid by PEMEX and December 31, 2003 were $97 million. Unconsolidated related companies. Our unconsolidated related companies include probable unapproved claims as revenue to determine the amount of profit or loss for their contracts. Probable unapproved claims from our related companies are included in “Equity in and advances to related companies,” and our share totaled $51 million at December 31, 2004 and $10 million at December 31, 2003. In addition, our unconsolidated related companies are negotiating change orders to the contract scope where we have agreed upon the scope of work but not the price. Our share of these change orders totaled $37 million at December 31, 2004 and $59 million at December 31, 2003. See Note 12 for discussion of government contract have been included in these arbitration proceedings. Actual amounts we are seeking from PEMEX in the claims. arbitration proceedings are in excess of these amounts. NOTE 3. BARRACUDA-CARATINGA PROJECT The arbitration proceedings are expected to extend through 2007. The $172 million decrease for claims resolution primarily resulted from efforts to settle older contract issues and reflects the terms of the Barracuda-Caratinga agreement with Petroleo Brasilero SA (Petrobras). See Note 13. The agreement settled our probable unapproved In June 2000, Kellogg Brown & Root, Inc. (Kellogg Brown & Root) entered into a contract with Barracuda & Caratinga Leasing Company B.V., the project owner, to develop the Barracuda and Caratinga crude oilfields, which are located off the coast of Brazil. The construction manager and project owner’s representative is Petrobras, the Brazilian national oil company. When completed, the 67 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS project will consist of two converted supertankers, – revised milestones and other dates, including settle- Barracuda and Caratinga, which will be used as floating ment of liquidated damages and an extension of time production, storage, and offloading units, commonly to the FPSO final acceptance dates. referred to as FPSOs. In addition, there will be 32 hydro- As of December 31, 2004: carbon production wells, 22 water injection wells, and all – the project was approximately 92% complete; subsea flow lines, umbilicals, and risers necessary to – we have recorded an inception-to-date loss of $762 connect the underwater wells to the FPSOs. The original million related to the project, of which $407 million completion date for the Barracuda vessel was December was recorded in 2004, $238 million was recorded in 2003, and the original completion date for the Caratinga 2003, and $117 million was recorded in 2002; vessel was April 2004. The project has been significantly – the losses recorded include an estimated $24 million behind the original schedule, due in part to change orders in liquidated damages based on the final agreement from the project owner, and is in a financial loss position. with Petrobras; and In December 2004, the Barracuda vessel achieved first – the probable unapproved claims were reduced from oil after being moved offshore for sea trials and final $114 million at December 31, 2003 to zero based upon inspections in October 2004, and the Caratinga vessel was the final agreement with Petrobras. moved offshore for sea trials and final inspections. The Cash flow considerations. We have now begun to fund Caratinga vessel achieved first oil in February 2005. operating cash shortfalls on the project and are obligated to Pursuant to the settlement agreement with Petrobras fund total shortages over the remaining project life. described below, the Barracuda vessel must be completed Estimated cash flows relating to the losses are as follows: by March 31, 2006, and the Caratinga vessel must be completed by June 30, 2006. While we anticipate meeting these completion targets, there can be no assurance that further delays will not occur. Also in December 2004, Kellogg Brown & Root and Petrobras, on behalf of the project owner, reached an agreement to settle various claims between the parties. The agreement provides for: – the release of all claims of all parties that arise prior to the effective date of a final definitive agreement; – a payment to us in 2005 of $79 million as a result of change orders for remaining claims; – payment by Petrobras of applicable value added taxes on the project, except for $8 million which has been paid by us; – the performance by Petrobras of certain work under the original contract; – the repayment by Kellogg Brown & Root of $300 million of advance payments by the end of February 2005, with interest on $74 million. Of this amount, $79 million was paid in 2004; and Millions of dollars Amount funded through December 31, 2004 Amounts to be paid/(received) in 2005: Remaining repayment of $300 million advance Payment to us relating to change orders Remaining project costs, net of revenue received Total cash shortfalls $586 221 (138) 93 $762 NOTE 4. ACQUISITIONS AND DISPOSITIONS Subsea 7, Inc. In January 2005, we completed the sale of our 50% interest in Subsea 7, Inc. to our joint venture partner, Siem Offshore (formerly DSND Subsea ASA), for approximately $200 million in cash. As a result of the transaction, we recorded a gain of approximately $110 million during the first quarter of 2005. We accounted for our 50% ownership of Subsea 7, Inc. using the equity method in our Production Optimization segment. Surface Well Testing. In August 2004, we sold our surface well testing and subsea test tree operations within our Production Optimization segment to Power Well Service Holdings, LLC, an affiliate of First Reserve Corporation, for approximately $129 million, of which we received $126 million in cash. During 2004, we recorded a $54 million 68 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS gain on the sale. For a limited period of time, we continue million and was included in our Production Optimization to have significant involvement with portions of these segment. operations in certain countries and, therefore, have not Wellstream. In March 2003, we sold the assets relating to recognized the gain from the sale of these operations as of our Wellstream business, a global provider of flexible pipe December 31, 2004. products, systems, and solutions, to Candover Partners Ltd. Enventure and WellDynamics. In the first quarter of 2004, for $136 million in cash. The assets sold included manufac- Halliburton and Shell Technology Ventures (Shell, an turing plants in Newcastle upon Tyne, United Kingdom, unrelated party) agreed to restructure two joint venture and Panama City, Florida, as well as assets and contracts in companies, Enventure Global Technology LLC (Enventure) Brazil. Wellstream had $34 million in goodwill recorded at and WellDynamics B.V. (WellDynamics), in an effort to the disposition date. The transaction resulted in a loss of more closely align the ventures with near-term priorities in $15 million, which was included in our Digital and the core businesses of the venture owners. Prior to this Consulting Solutions segment. Included in the loss is the transaction, Enventure (part of our Fluid Systems segment) write-off of the cumulative translation adjustment related to and WellDynamics (formerly part of our Digital and Wellstream of approximately $9 million. Consulting Solutions segment) were owned equally by Mono Pumps. In January 2003, we sold our Mono Pumps Shell and us. Shell acquired an additional 33.5% of business to National Oilwell, Inc. The sale price of approxi- Enventure, leaving us with 16.5% ownership in return for mately $88 million was paid with $23 million in cash and 3.2 enhanced and extended agreements and licenses with Shell million shares of National Oilwell, Inc. common stock, for its PoroFlex ® expandable sand screens and a distribu- which were valued at $65 million on January 15, 2003. We tion agreement for its VersaFlex™ expandable liner hangers. recorded a gain of $36 million on the sale in the first As a result of this transaction, we changed the way we quarter of 2003, which was included in our Drilling and account for our ownership in Enventure from the equity Formation Evaluation segment. Included in the gain was method to the cost method of accounting for investments. the write-off of the cumulative translation adjustment We acquired an additional 1% of WellDynamics from Shell, related to Mono Pumps of approximately $5 million. In giving us 51% ownership and control of day-to-day opera- February 2003, we sold 2.5 million of our 3.2 million shares tions. In addition, Shell received an option to obtain our of National Oilwell, Inc. common stock for $52 million, remaining interest in Enventure for an additional 14% which resulted in a gain of $2 million, and in February interest in WellDynamics. No gain or loss resulted from the 2004, we sold the remaining shares for $20 million, transaction. Beginning in the first quarter of 2004, resulting in a gain of $6 million. The gains related to the WellDynamics was consolidated and is now included in our sale of the National Oilwell, Inc. common stock were Production Optimization segment. The consolidation of recorded in “Other, net.” WellDynamics resulted in an increase to our goodwill of Bredero-Shaw. In the second quarter of 2002, we incurred $109 million, which was previously carried as equity an impairment charge of $61 million related to our then- method goodwill in “Equity in and advances to related pending sale of Bredero-Shaw. On September 30, 2002, we companies.” sold our 50% interest in the Bredero-Shaw joint venture to Halliburton Measurement Systems. In May 2003, we sold our partner ShawCor Ltd. The sale price of $149 million certain assets of Halliburton Measurement Systems, which was comprised of $53 million in cash, a short-term note of provides flow measurement and sampling systems, to $25 million, and 7.7 million of ShawCor Class A NuFlo Technologies, Inc. for approximately $33 million in Subordinate shares. Consequently, we recorded a 2002 cash, subject to post-closing adjustments. The gain on the third-quarter loss on the sale of $18 million, which is sale of Halliburton Measurement Systems’ assets was $24 reflected in our Digital and Consulting Solutions segment. 69 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Included in this loss was $15 million of cumulative transla- and integrated services and solutions to customers for the tion adjustment loss, which was realized upon the exploration, development, and production of oil and gas. disposition of our investment in Bredero-Shaw. During the The Energy Services Group serves major, national, and 2002 fourth quarter, we recorded in “Other, net” a $9 independent oil and gas companies throughout the world. million loss on the sale of ShawCor shares. Following is a summary of our Energy Services Group European Marine Contractors Ltd. In January 2002, we sold segments. our 50% interest in European Marine Contractors Ltd., an Production Optimization. The Production Optimization unconsolidated joint venture reported within our Digital segment primarily tests, measures, and provides means to and Consulting Solutions segment, to our joint venture manage and/or improve well production once a well is partner, Saipem. At the date of sale, we received $115 drilled and, in some cases, after it has been producing. This million in cash and a contingent payment option valued at segment consists of production enhancement services and $16 million, resulting in a gain of $108 million. The completion tools and services. contingent payment option was based on a formula linked Production enhancement services include stimulation to performance of the Oil Service Index. In February 2002, services, pipeline process services, sand control services, we exercised our option and received an additional $19 coiled tubing tools and services, and hydraulic workover million and recorded a gain of $3 million, in “Other, net” in services. Stimulation services optimize oil and gas reser- the statement of operations as a result of the increase in voir production through a variety of pressure pumping value of this option. NOTE 5. BUSINESS SEGMENT INFORMATION During the second quarter of 2003, we restructured our Energy Services Group into four segments, and, in the fourth quarter of 2004, we restructured KBR into two segments, which form the basis for the six segments we now report. The new segments mirror the way our chief operating decision maker now regularly reviews the operating results, assesses performance, and allocates resources. We refer to the combination of Production Optimization, Fluid Systems, Drilling and Formation Evaluation, and Digital and Consulting Solutions segments as the Energy Services Group and the combination of our Government and Infrastructure and Energy and Chemicals segments as KBR. The amounts in the 2003 and 2002 notes to the consoli- dated financial statements related to segments have been restated to conform to the 2004 composition of reportable segments. ENERGY SERVICES GROUP Our Energy Services Group provides a wide range of discrete services and products, as well as bundled services services and chemical processes, commonly know as fracturing and acidizing. Pipeline process services include pipeline and facility testing, commissioning, and cleaning via pressure pumping, chemical systems, specialty equipment, and nitrogen, which are provided to the midstream and downstream sectors of the energy business. Sand control services include fluid and chemical systems and pumping services for the prevention of formation sand production. Completion tools and services include subsurface safety valves and flow control equipment, surface safety systems, packers and specialty completion equipment, intelligent completion systems, production automation, expandable liner hanger systems, sand control systems, slickline equipment and services, self-elevated workover platforms, tubing-conveyed perforating products and services, well servicing tools, and reservoir performance services. Reservoir performance services include drill stem and other well testing tools and services, underbalanced applications and real-time reservoir analysis, data acquisi- tion services, and production applications. Also included in the Production Optimization segment are WellDynamics, an intelligent well completions joint venture, which was consolidated in the first quarter of 70 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2004, and subsea operations conducted by Subsea 7, Inc., of evaluation. Also offered are cased-hole services and which we formerly owned 50%. magnetic resonance imaging tools. Fluid Systems. The Fluid Systems segment focuses on Digital and Consulting Solutions. The Digital and providing services and technologies to assist in the drilling Consulting Solutions segment provides integrated explo- and construction of oil and gas wells. Drilling fluids are ration and production software information systems, used to provide for well control and drilling efficiency, and consulting services, real-time operations, subsea opera- as a means of removing wellbore cuttings. This segment tions, value-added oilfield project management, and other consists of: integrated solutions. Included in this business segment is – cementing services, which involve the process used to Landmark Graphics, a supplier of integrated exploration bond the well and well casing while isolating fluid and production software information systems, as well as zones and maximizing wellbore stability. Our cement- professional and data management services. Also included ing service line also provides casing equipment and were Wellstream, Bredero-Shaw, and European Marine services; Contractors Ltd., all of which have been sold. – Baroid Fluid Services product line, which provides KBR drilling fluid systems, performance additives, solids KBR provides engineering, procurement, construction, control, and waste management services for oil and project management, and facilities operation and mainte- gas drilling, completion, and workover operations; and nance for oil and gas and other industrial customers and – Enventure, which is an expandable casing joint government entities worldwide. Following is a summary of venture. The joint venture is currently a cost method KBR’s segments. investment that was accounted for using the equity Government and Infrastructure. The Government and method prior to the ownership restructuring agree- Infrastructure segment is one of the largest government ment with Shell in the first quarter of 2004. logistics and services contractors with worldwide civil Drilling and Formation Evaluation. The Drilling and infrastructure capabilities. This segment represents Formation Evaluation segment is primarily involved in construction, maintenance, and logistics services for drilling and evaluating the formations related to bore-hole government operations, facilities, and installations. Other construction and initial oil and gas formation evaluation. major operations include civil engineering, consulting, The products and services in this segment incorporate project management services for state and local govern- integrated technologies, which offer synergies related ments and private industries, integrated security solutions, to drilling activities and data gathering. This segment dockyard operation and maintenance through the consists of: Devonport Royal Dockyard Limited (DML) subsidiary, and – Sperry Drilling Services, which provides drilling privately financed initiatives. systems and services. These services include direc- Energy and Chemicals. The Energy and Chemicals tional and horizontal drilling, segment is a global engineering, procurement, construc- measurement-while-drilling, logging-while-drilling, tion, technology, and services provider for the energy and multilateral completion systems, and rig site informa- chemicals industries. Working both upstream and down- tion systems; stream in support of our customers, Energy and Chemicals – Security DBS Drill Bits, which provides roller cone offers the following: rock bits, fixed cutter bits, and other downhole tools – downstream engineering and construction capabilities, used in drilling oil and gas wells; and including global engineering execution centers, as – logging services, which include open-hole wireline well as engineering, construction, and program services that provide information on formation management of liquefied natural gas, ammonia, 71 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS petrochemicals, crude oil refineries, and natural more than 10% of consolidated revenue in any period gas plants; presented. – upstream deepwater engineering, marine technology, The tables below present information on our business and project management; segments. – plant operations, maintenance, and start-up services for both upstream and downstream oil, gas, and O p e r a t i o n s b y B u s i n e s s S e g m e n t petrochemical facilities, as well as operations, Millions of dollars maintenance, and logistics services for the power, commercial, and industrial markets; – industry-leading licensed technologies in the areas of fertilizers and synthesis gas, olefins, refining, and chemicals and polymers; and – consulting services in the form of expert technical and management advice covering studies, conceptual and detailed engineering, project management, construc- tion supervision and design, and construction verification or certification in both upstream and downstream markets. Also included in this segment are two joint ventures: TSKJ, in which we have a 25% interest, and M.W. Kellogg, Ltd., in which we have a 55% interest. TSKJ was formed to construct and subsequently expand a large natural gas liquefaction complex in Nigeria. GENERAL CORPORATE General corporate represents assets not included in a business segment and is primarily composed of cash and cash equivalents, deferred tax assets, and insurance for asbestos and silica litigation claims. Intersegment revenue and revenue between geographic Revenue: Production Optimization Fluid Systems Drilling and Formation Evaluation Digital and Consulting Solutions Total Energy Services Group Government and Infrastructure Energy and Chemicals Total KBR Total Operating income (loss): Production Optimization Fluid Systems Drilling and Formation Evaluation Digital and Consulting Solutions Total Energy Services Group Government and Infrastructure Energy and Chemicals Shared KBR Total KBR General corporate Total Capital expenditures: Production Optimization Fluid Systems Drilling and Formation Evaluation Digital and Consulting Solutions Shared Energy Services Total Energy Services Group Government and Infrastructure Energy and Chemicals Shared KBR Total KBR Total Years ended December 31 2004 2003 2002 $ 3,303 2,324 1,782 589 7,998 9,393 3,075 12,468 $20,466 $ 633 348 225 60 1,266 84 (426) – (342) (87) $ 837 $ 181 66 135 32 84 498 41 9 27 77 $ 575 $ 2,758 2,039 1,643 555 6,995 5,417 3,859 9,276 $16,271 $ 413 251 177 (15) 826 194 (225) (5) (36) (70) $ 720 $ 124 54 145 27 103 453 45 5 12 62 $ 515 $ 2,544 1,815 1,633 844 6,836 1,539 4,197 5,736 $12,572 $ 374 202 160 (98) 638 75 (131) (629) (685) (65) $ (112) $ 118 55 190 149 91 603 138 12 11 161 $ 764 areas are immaterial. Our equity in pretax earnings and Within the Energy Services Group and KBR, not all losses of unconsolidated affiliates that are accounted for on assets are associated with specific segments. Those assets the equity method is included in revenue and operating specific to segments include receivables, inventories, income of the applicable segment. certain identified property, plant, and equipment (including Total revenue for 2004 includes $8.0 billion, or 39% of field service equipment), equity in and advances to related consolidated revenue from the United States government, companies, and goodwill. The remaining assets, such as and total revenue for 2003 includes $4.2 billion, or 26% of cash and the remaining property, plant, and equipment consolidated revenue from the United States government, (including shared facilities), are considered to be shared which is derived almost entirely from our Government and among the segments within the two groups. For segment Infrastructure segment. Revenue from the United States operating income presentation, the depreciation expense government during 2002 represented less than 10% of associated with these shared Energy Services Group assets consolidated revenue. No other customer represented 72 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS and KBR assets are allocated to the two groups and general 31, 2004, 39% of our consolidated receivables related to our corporate. United States government contracts, primarily for projects Revenue by country is determined based on the location in the Middle East. Receivables from the United States of services provided and products sold. government at December 31, 2003 represented 41% of O p e r a t i o n s b y B u s i n e s s S e g m e n t ( c o n t i n u e d ) Millions of dollars Depreciation, depletion, and amortization: Production Optimization Fluid Systems Drilling and Formation Evaluation Digital and Consulting Solutions Shared Energy Services Total Energy Services Group Government and Infrastructure Energy and Chemicals Shared KBR Total KBR General corporate Total Total assets: Production Optimization Fluid Systems Drilling and Formation Evaluation Digital and Consulting Solutions Shared Energy Services Total Energy Services Group Government and Infrastructure Energy and Chemicals Shared KBR Total KBR General corporate Total Years ended December 31 2004 2003 2002 $ 115 60 115 75 91 456 27 11 15 53 – 509 $ $ 1,754 1,045 960 768 1,021 5,548 3,309 1,656 198 5,163 5,085 $15,796 $ 104 50 144 77 92 467 22 16 12 50 1 $ 518 $ 1,659 1,030 1,074 794 1,240 5,797 2,758 2,078 246 5,082 4,620 $15,499 $ 99 48 137 112 79 475 11 17 1 29 1 $ 505 $ 1,444 830 1,163 1,320 1,187 5,944 784 2,055 265 3,104 3,796 $12,844 O p e r a t i o n s b y G e o g r a p h i c A r e a Years ended December 31 consolidated receivables. Under an agreement to sell United States Energy Services Group accounts receivable to a bankruptcy- remote limited-purpose funding subsidiary, new receivables are added on a continuous basis to the pool of receivables. Collections reduce previously sold accounts receivable. This funding subsidiary sells an undivided ownership interest in this pool of receivables to entities managed by unaffiliated financial institutions under another agreement. Sales to the funding subsidiary have been structured as “true sales” under applicable bankruptcy laws. While the funding subsidiary is wholly owned by us, its assets are not available to pay any creditors of ours or of our subsidiaries or affiliates. The undivided ownership interest in the pool of receivables sold to the unaffiliated companies, therefore, is reflected as a reduction of accounts receivable in our consolidated balance sheets. The funding subsidiary retains the interest in the pool of receivables that are not sold to the unaffiliated companies and is fully consolidated and reported in our financial statements. The amount of undivided interests which can be sold under the program varies based on the amount of eligible 2004 2003 2002 Energy Services Group receivables in the pool at any given Millions of dollars Revenue: Iraq United States Kuwait United Kingdom Other areas (numerous countries) Total Long-lived assets: United States United Kingdom Other areas (numerous countries) Total $ 5,362 4,461 1,841 1,646 7,156 $20,466 $ 2,485 697 1,126 $ 4,308 $ 2,399 4,415 856 1,473 7,128 $16,271 $ 4,461 630 917 $ 6,008 $ 1 4,139 50 1,521 6,861 $12,572 $ 4,617 691 711 $ 6,019 NOTE 6. RECEIVABLES (OTHER THAN “INSURANCE FOR ASBESTOS- AND SILICA-RELATED LIABILITIES”) Our receivables are generally not collateralized. Included in notes and accounts receivable are notes with varying interest rates totaling $12 million at December 31, 2004 and $11 million at December 31, 2003. At December time and other factors. The maximum amount that may be sold and outstanding under this agreement at any given time is $300 million. As of December 31, 2004, we had sold $256 million undivided ownership interest to unaffiliated companies. The securitization facility matures in April 2005. In May 2004, we entered into an agreement to sell, assign, and transfer the entire title and interest in specified United States government accounts receivable of KBR to a third party. The face value of the receivables sold to the third party is reflected as a reduction of accounts receiv- able in our consolidated balance sheets. The amount of receivables which can be sold under the agreement varies based on the amount of eligible receivables at any given time and other factors, and the maximum amount that may 73 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS be sold and outstanding under this agreement at any given – $4 million for payroll related to bankruptcy, which was time is $650 million. The total amount of receivables released in January 2005. outstanding under this agreement as of December 31, 2004 At December 31, 2003, we had restricted cash of $159 was approximately $263 million. Subsequent to December million in “Other current assets” and $100 million in “Other 31, 2004, these receivables were collected and the balance assets,” which consisted of similar items as above. Included retired, and we are not currently selling receivables, in these amounts were $107 million that collateralized a although the facility continues to be available. bond for a patent infringement judgment on appeal and $37 NOTE 7. INVENTORIES million related to the Chapter 11 proceedings. Inventories are stated at the lower of cost or market. We NOTE 9. PROPERTY, PLANT, AND EQUIPMENT manufacture in the United States certain finished products Property, plant, and equipment at December 31, 2004 and parts inventories for drill bits, completion products, and 2003 are composed of the following: bulk materials, and other tools that are recorded using the last-in, first-out method totaling $37 million at December 31, 2004 and $38 million at December 31, 2003. If the average cost method had been used, total inventories would have been $17 million higher than reported at both December 31, 2004 and at December 31, 2003. The cost of over 95% of the remaining inventory is recorded on the average cost method, with the remainder on the first-in, first-out method. Inventories at December 31, 2004 and December 31, 2003 were composed of the following: Millions of dollars Land Buildings and property improvements Machinery, equipment, and other Total Less accumulated depreciation Net property, plant, and equipment 2004 $68 1,088 5,071 6,227 3,674 $2,553 2003 $80 1,065 4,921 6,066 3,540 $2,526 Machinery, equipment, and other includes oil and gas properties of $308 million at December 31, 2004 and $359 million at December 31, 2003. The percentage of total building and property improve- ments and total machinery, equipment, and other, December 31 excluding oil and gas investments, are depreciated over the Millions of dollars Finished products and parts Raw materials and supplies Work in process Total 2004 $534 156 33 $723 2003 $503 159 33 $695 Finished products and parts are reported net of obsolescence reserves of $119 million at December 31, 2004 and $117 million at December 31, 2003. NOTE 8. RESTRICTED CASH At December 31, 2004, we had restricted cash of $138 million, which consists of: – $98 million as collateral for potential future insurance claim reimbursements, included in “Other assets”; – $36 million ($23 million in “Other assets” and $13 million in “Other current assets”) primarily related to cash collateral agreements for outstanding letters of credit for various construction projects; and following useful lives: 1 – 10 years 11 – 20 years 21 – 30 years 31 – 40 years 1 – 5 years 6 – 10 years 11 – 25 years Building and Property Improvements 2004 19% 45% 16% 20% 2003 19% 48% 12% 21% Machinery, Equipment, and Other 2004 28% 63% 9% 2003 30% 62% 8% In the second quarter of 2004, we implemented a change in accounting estimate to more accurately reflect the useful life of some of the tools of our Drilling and Formation Evaluation segment. This resulted in a com- bined $35 million reduction in depreciation expense in the last three quarters of 2004, thereby reducing our consoli- dated net loss by $22 million, or $0.05 per share, for 2004. 74 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS We extended the useful lives of these tools based on our Standard & Poor’s are lower than Ba1 and BB+, review of their service lives, technological improvements in respectively, or the notes are no longer rated by at the tools, and recent changes to our repair and mainte- least one of these rating services or their successors. nance practices which helped to extend the lives. The initial conversion price is $37.65 per share and NOTE 10. DEBT Short-term notes payable of $15 million at December 31, 2004 and $18 million at December 31, 2003 are included in “Other current liabilities” in the consolidated balance sheets. Long-term debt at December 31, 2004 and 2003 consisted of the following: Millions of dollars 3.125% convertible senior notes due July 2023 0.75% plus three-month LIBOR senior notes due January 2007 5.5% senior notes due October 2010 1.5% plus three-month LIBOR senior notes due October 2005 Medium-term notes due 2006 through 2027 7.6% debentures of Halliburton due August 2096 8.75% debentures due February 2021 Other Total long-term debt Less current portion Noncurrent portion of long-term debt 2004 $1,200 2003 $1,200 500 748 – 748 300 600 294 200 98 3,940 347 $3,593 300 600 294 200 95 3,437 22 $3,415 Convertible notes. In June 2003, we issued $1.2 billion of 3.125% convertible senior notes due July 15, 2023, with interest payable semiannually. The notes are our senior unsecured obligations ranking equally with all of our existing and future senior unsecured indebtedness. The notes are convertible under any of the following circumstances: – during any calendar quarter if the last reported sale price of our common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous quarter is greater than or equal to 120% of the conversion price per share of our common stock on such last trading day; – if the notes have been called for redemption; – upon the occurrence of specified corporate transac- tions that are described in the indenture relating to the offering; or – during any period in which the credit ratings assigned to the notes by both Moody’s Investors Service and is subject to adjustment upon the occurrence of a stock dividend in common stock, the issuance of rights or warrants, stock splits and combinations, the distribution of indebtedness, securities, or assets, or excess cash distributions. Upon conversion, we must settle the principal amount of the notes in cash, and for any amounts in excess of the aggregate principal we have the right to deliver shares of our common stock, cash, or a combination of cash and common stock. See Note 17 for discussion of supplemental indenture on these notes. The notes are redeemable for cash at our option on or after July 15, 2008. Holders may require us to repurchase the notes for cash on July 15 of 2008, 2013, or 2018 or, prior to July 15, 2008, in the event of a fundamental change as defined in the underlying indenture. Senior notes due 2007. In January 2004, we issued $500 million aggregate principal amount of senior notes due 2007 bearing interest at a floating rate equal to three-month LIBOR (London interbank offered rates) plus 0.75%, payable quarterly. We have the option to redeem all or a portion of the outstanding notes on any quarterly interest payment date. Floating- and fixed-rate senior notes. In October 2003, we completed an offering of $1.05 billion of floating and fixed- rate unsecured senior notes. The fixed-rate notes, with an aggregate principal amount of $750 million, will mature on October 15, 2010 and bear interest at a rate equal to 5.5%, payable semiannually. The fixed-rate notes were initially offered on a discounted basis at 99.679% of their face value. The discount is being amortized to interest expense over the life of the bond. The floating-rate notes, with an aggregate principal amount of $300 million, will mature on October 17, 2005 and bear interest at a rate equal to three- month LIBOR plus 1.5%, payable quarterly. 75 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Medium-term notes. We have outstanding notes under our 2007, and any other new issuance to the extent that the medium-term note program as follows: issuance contains a requirement that the holders thereof be Due 08/2006 12/2008 05/2017 02/2027 Rate 6.00% 5.63% 7.53% 6.75% Amount (in millions) $275 $150 $ 50 $125 We may redeem the 6.00% and 5.63% medium-term notes in whole or in part at any time. The 7.53% notes may not be redeemed prior to maturity. Each holder of the 6.75% medium-term notes has the right to require us to repay their notes in whole or in part on February 1, 2007. The medium-term notes do not have sinking fund requirements and rank equally with our existing and future senior unsecured indebtedness. Revolving credit facilities. As of December 31, 2004 we had outstanding, for general working capital purposes: – a $700 million revolving credit facility, which expires in October 2006; and – a $500 million 364-day revolving credit facility, which expires in July 2005. In September 2004, we issued a letter of credit for approximately $172 million under our $700 million revolv- ing credit facility to replace an expiring letter of credit for our Barracuda-Caratinga project, which reduced our availability under the revolving credit facility to $528 million. As of December 31, 2004, no cash had been drawn under either revolving credit facility. Borrowings under the revolving credit facilities will be secured by certain of our assets until our long-term senior equally and ratably secured with Halliburton’s other secured creditors. Security to be provided includes: – 100% of the stock of Halliburton Energy Services, Inc. (a wholly owned subsidiary of Halliburton); – 100% of the stock or other equity interests held by Halliburton and Halliburton Energy Services, Inc. in certain of their first-tier domestic subsidiaries; – 66% of the stock or other equity interests of Halliburton Affiliates LLC (a wholly owned subsidiary of Halliburton); and – 66% of the stock or other equity interests of certain foreign subsidiaries of Halliburton or Halliburton Energy Services, Inc. As of December 31, 2004, we had approximately $50 million of secured debt outstanding. Maturities. Our debt, excluding the effects of our terminated interest rate swaps, matures as follows: $347 million in 2005; $293 million in 2006; $518 million in 2007; $156 million in 2008; zero in 2009; and $2,625 million thereafter. NOTE 11. ASBESTOS AND SILICA OBLIGATIONS AND INSURANCE RECOVERIES Summary Several of our subsidiaries, particularly DII Industries and Kellogg Brown & Root, had been named as defendants in a large number of asbestos- and silica-related lawsuits. The plaintiffs alleged injury primarily as a result of unsecured debt is rated BBB or higher (stable outlook) by exposure to: Standard & Poor’s and Baa2 or higher (stable outlook) by Moody’s Investors Service. To the extent that the aggregate principal amount of all secured indebtedness exceeds 5% of the consolidated net tangible assets of Halliburton and its subsidiaries, all collateral will be shared pro rata with holders of Halliburton’s 8.75% debentures due 2021, 3.125% convert- ible senior notes due 2023, senior notes due 2005, 5.5% senior notes due 2010, medium-term notes, 7.6% deben- tures due 2096, senior notes issued in January 2004 due – asbestos used in products manufactured or sold by former divisions of DII Industries (primarily refractory materials, gaskets, and packing materials used in pumps and other industrial products); – asbestos in materials used in the construction and maintenance projects of Kellogg Brown & Root or its subsidiaries; and – silica related to sandblasting and drilling fluids operations. 76 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Effective December 31, 2004, we resolved all open and future claims in the prepackaged Chapter 11 proceedings of DII Industries, Kellogg Brown & Root, and our other affected subsidiaries (which were filed on December 16, 2003) upon the District Court’s affirmation order and the bankruptcy court’s order confirming the plan of reorganiza- tion becoming final and nonappealable. In January 2005, we paid approximately $2.3 billion in cash and transferred 59.5 million shares of our common stock to the trusts estab- lished for the benefit of asbestos and silica claimants. The first table that follows summarizes the various charges we have incurred during 2002, 2003, and 2004. The second table presents a rollforward of our asbestos- and silica- related liabilities and insurance receivables. 2004 2003 2002 Cont’g. Discont’d. Cont’g. Discont’d. Cont’g. Discont’d. Oper. Oper. Oper. Oper. Oper. Oper. Millions of dollars Asbestos and silica charges: Prepackaged Chapter 11 proceedings 2002 Rabinovitz Study 59.5 million share revaluation Federal-Mogul partitioning agreement Revaluation of silica note Subtotal Asbestos and silica insurance write-off (receivables): Insurance receivable write-down Navigant Study Write-off of Highlands accounts receivable Subtotal Other costs: Harbison-Walker matters Professional fees Cash in lieu of interest Accretion Other costs Subtotal Pretax asbestos and silica charges Tax provision (benefit) Total asbestos and silica $ – – $ – $ – – – $1,016 $ – 564 – $ – 2,256 – – – – – – – – – – – – – – – – 778 44 3 825 698 – – 698 – 28 7 (22) 4 17 – – – – – – – – – – – – 5 5 – – – – – – – 1,016 – 564 – 2,256 – 6 – 6 51 58 24 – – 133 – – 80 80 – – – – – – – (1,530) – (1,530) 45 35 – – – 80 1,540 (179) 5 (2) 1,155 5 644 (114) 806 (154) charges, net of tax $– $1,361 $3 $1,160 $530 $ 652 Millions of dollars Asbestos- and silica-related liabilities: Beginning balance Accrued liability 59.5 million shares revaluation Federal-Mogul partitioning agreement Revaluation of silica note Payments on claims Reclassification of 59.5 million shares to shareholders’ equity Other Asbestos- and silica-related December 31 2004 2003 $ 4,086 – 778 44 3 (119) (2,335) (12) $ 3,425 1,016 – – – (355) – – liabilities – ending balance (of which $2,408 and $2,507 is current) $ 2,445 $ 4,086 Insurance for asbestos- and silica-related liabilities: Beginning balance Write-off of insurance recoveries/ net present value true-up Accretion Purchase of Harbison-Walker receivable, net of allowance Payments received Other Insurance for asbestos- and silica-related liabilities – ending balance (of which $1,066 and $96 is current) $(2,134) $(2,103) 698 (22) – 37 5 6 – (40) 3 – $(1,416) $(2,134) Prepackaged Chapter 11 proceedings and insurance settlements Prepackaged Chapter 11 proceedings. DII Industries, Kellogg Brown & Root, and six other subsidiaries (Mid- Valley, Inc.; KBR Technical Services, Inc.; Kellogg Brown & Root Engineering Corporation; Kellogg Brown & Root International, Inc. (a Delaware corporation); Kellogg Brown & Root International, Inc. (a Panamanian corpora- tion); and BPM Minerals, LLC) filed Chapter 11 proceedings on December 16, 2003 in bankruptcy court in Pittsburgh, Pennsylvania. Each of these entities was a wholly owned subsidiary of Halliburton before, during, and after the bankruptcy proceedings became final. Our subsidiaries sought Chapter 11 protection to avail themselves of the provisions of Sections 524(g) and 105 of the Bankruptcy Code to discharge current and future asbestos and silica personal injury claims against us and our subsidiaries. The order confirming the plan of reorgani- zation became final and nonappealable on December 31, 2004 and the plan of reorganization became effective in January 2005. Under the plan of reorganization all current 77 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS and future asbestos and silica personal injury claims a medical basis for payment of settlement amounts and to against us and our affiliates were channeled into trusts establish that the claimed injuries were based on exposure to established for the benefit of asbestos and silica claimants, our products. In 2003, we concluded that substantially all of thus releasing us from those claims. the asbestos and silica liability related to claims filed against In accordance with the plan of reorganization, in our former operations that have been divested and included January 2005 we contributed the following to trusts for the in discontinued operations. Consequently, all 2003 and 2004 benefit of current and future asbestos and silica personal changes in our estimates related to the asbestos and silica injury claimants: liability were recorded through discontinued operations. – approximately $2.345 billion in cash, which represents Our plan of reorganization called for a portion of our the remaining portion of the $2.775 billion total cash total asbestos liability to be settled by contributing 59.5 settlement after payments of $311 million in December million shares of Halliburton common stock to the trust. As 2003 and $119 million in June 2004; of December 31, 2004, we revalued our shares to approxi- – 59.5 million shares of Halliburton common stock; mately $2.335 billion ($39.24 per share), an increase of $778 – a one-year non-interest-bearing note of $31 million for million from December 31, 2003, and this amount was the benefit of asbestos claimants. We prepaid the charged to discontinued operations on our consolidated initial installment on the note of approximately $8 statement of operations during 2004. Effective December million in January 2005. The remaining note will be 31, 2004, concurrent with receiving final and nonappealable paid in three equal quarterly installments starting in confirmation of our plan of reorganization, we reclassified the second quarter of 2005; and from a long-term liability to shareholders’ equity the final – a silica note with an initial payment into a silica trust of value of the 59.5 million shares of Halliburton common $15 million. Subsequently, the note provides that we stock. If the shares had been included in the calculation of will contribute an amount to the silica trust at the end earnings per share as of the beginning of 2004, our diluted of each year for the next 30 years of up to $15 million. earnings per share from continuing operations would have The note also provides for an extension of the note for been reduced by $0.11 for 2004. 20 additional years under certain circumstances. We Insurance settlements. During 2004, we settled insurance have estimated the value of this note to be approxi- disputes with substantially all the insurance companies for mately $24 million. We will periodically reassess our asbestos- and silica-related claims and all other claims valuation of this note based upon our projections of under the applicable insurance policies and terminated all the amounts we believe we will be required to fund the applicable insurance policies. Under the terms of our into the silica trust. insurance settlements, we will receive cash proceeds with a As a result of the filing of the Chapter 11 proceedings, nominal amount of approximately $1.5 billion and with a we adjusted the asbestos and silica liability to reflect the present value of approximately $1.4 billion for our asbestos- full amount of the proposed settlement and certain related and silica-related insurance receivables. The present value costs, which resulted in a pretax charge of approximately was determined by discounting the expected future cash $1.016 billion to discontinued operations in the fourth payments with a discount rate implicit in the settlements, quarter of 2003. The tax effect on this charge was minimal, which ranged from 4.0% to 5.5%. Beginning in the third as a valuation allowance was established against the liability quarter of 2004, this discount is being accreted as interest to reflect the expected net tax benefit from the future income (classified as discontinued operations) over the life deductions the liability will create. of the expected future cash payments. Cash payments of In accordance with the definitive settlement agreements approximately $1 billion related to these receivables were entered in early 2003, we reviewed plaintiff files to establish received in January 2005. Under the terms of the settle- 78 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ment agreements, we will receive cash payments of the companies received on or before January 1, 2006 do not remaining amounts in several installments beginning in equal at least $4.5 million, DII Industries agreed to also pay July 2005 through 2009. to Federal-Mogul the difference between their recoveries Our December 31, 2003 estimate of our asbestos- and from the insolvent London-based insurance companies and silica-related insurance receivables already included a $4.5 million. Any recoveries received by Federal-Mogul charge for the settlement amount under an agreement from the insolvent London-based insurance companies after reached in January 2004, as well as certain other probable January 1, 2006 will be reimbursed to DII Industries until settlements with companies for which we could reasonably such time as DII Industries is fully reimbursed for the estimate the amount of the settlement. During 2004, we amount of the payment. reduced the amount recorded as insurance receivables for Under the insurance settlements entered into as part of asbestos- and silica-related liabilities insured by other the resolution of our Chapter 11 proceedings, we have companies based upon the final agreements, resulting in agreed to indemnify our insurers under certain historic pretax charges to discontinued operations of approximately general liability insurance policies in certain situations. $698 million. The following factors were considered when entering into A significant portion of the insurance coverage applica- these indemnifications: ble to Worthington Pump, a former division of DII – we conducted an extensive due diligence process to Industries, was alleged by Federal-Mogul (and others who determine if other third parties have rights to assert formerly were associated with Worthington Pump prior to claims under the relevant insurance policies. Any its acquisition by DII Industries) to be shared with them. third parties known to us which we determined During 2004, we reached an agreement with Federal- might have rights allowing them to assert claims Mogul, our insurance companies, and another party under these insurance policies have either waived sharing in the insurance coverage to obtain their consent their rights to assert claims under the insurance and support of a partitioning of the insurance policies. policies or have been excluded from the scope of Under the terms of the agreement, DII Industries was the indemnities. Therefore, we are not aware of any allocated 50% of the limits of any applicable insurance third parties that could assert valid claims under policy, and the remaining 50% of limits of the insurance the relevant insurance policies that could trigger policies were allocated to the remaining policyholders. As our indemnification obligations; part of the settlement, DII Industries agreed to pay $46 – the settlements that we have entered into with our million in three installment payments. The first payment of insurers have exhausted the relevant products limits $16 million was paid in January 2005. The second and third of liability applicable to asbestos, silica, and other payments of $15 million each will occur on the first and product claims. These settlements have been second anniversaries from the date of the first payment. In approved by the bankruptcy court as reasonable, 2004, we accrued $44 million, which represents the present good faith settlements; value of the $46 million to be paid. The discount is accreted – the insurance policies that are subject to the indemnity as interest expense (classified as discontinued operations) were issued for 1992 and prior periods. If there is an over the life of the expected future cash payments begin- undiscovered third party that can assert a valid, ning in the fourth quarter of 2004. covered claim under the relevant policies that has not DII Industries and Federal-Mogul agreed to share already had such claims excluded from the scope of equally in recoveries from insolvent London-based insur- the indemnity, any claims asserted would be at least ance companies. To the extent that Federal-Mogul’s 12 years old. Moreover, given the exclusions that recoveries from certain insolvent London-based insurance appear in the insurance policies beginning in 1985 79 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS and, in some cases, 1971 the probable age of any claim defendant in order to prevent Harbison-Walker from that could potentially trigger our indemnity obligations unnecessarily eroding the insurance coverage both is almost 20 years old. Given this passage of time, companies access for these claims. which passage of time also gives rise to defenses to In February 2002, Harbison-Walker filed a voluntary coverage under the relevant insurance policies, such petition for reorganization under Chapter 11 of the as late notice defenses, and the lack of any known Bankruptcy Code. In its initial Chapter 11 filings, Harbison- third party that could assert a claim that could trigger Walker stated it would seek to utilize Sections 524(g) and our indemnity obligations, we believe that the 105 of the Bankruptcy Code to propose and seek confirma- likelihood of any third party being able to assert tion of a plan of reorganization that would provide for claims that could trigger our indemnity is remote. distributions for all legitimate pending and future asbestos Accordingly, we have concluded that the likelihood of and silica claims asserted directly against Harbison-Walker any claims triggering the indemnity obligations is remote, or asserted against DII Industries. In order to protect the and we believe any potential liability for these indemnifica- shared insurance from dissipation, DII Industries began tions will be immaterial. to assist Harbison-Walker in its Chapter 11 proceedings At December 31, 2004, we had not recorded any liability as follows: associated with these indemnifications. – in February 2002, DII Industries paid $40 million to Other matters relating to 2003 and 2002 Harbison-Walker’s United States parent holding Harbison-Walker Chapter 11 proceedings. A large portion of company, RHI Refractories Holding Company (RHI our asbestos claims related to alleged injuries from Refractories); asbestos used in a small number of products manufactured – DII Industries agreed to provide up to $35 million in or sold by Harbison-Walker Refractories Company, whose debtor-in-possession financing to Harbison-Walker ($5 operations DII Industries acquired in 1967 and spun off in million was paid in 2002 and the remaining $30 million 1992. At the time of the spin-off, Harbison-Walker assumed was paid in 2003); and liability for asbestos claims filed after the spin-off, and it – during 2003, DII Industries purchased $50 million of agreed to defend and indemnify DII Industries from liability Harbison-Walker’s outstanding insurance receivables, for those claims, although DII Industries continued to have of which $10 million were estimated to be uncol- direct liability to tort claimants for all post-spin-off refrac- lectible. These receivables were included as part of tory asbestos claims. DII Industries retained responsibility the insurance settlements. for all asbestos claims pending as of the date of the spin-off. All the cash payments noted above ($40 million paid in The agreement governing the spin-off provided that February 2002, $5 million paid in 2002, and $30 million Harbison-Walker would have the right to access DII paid in 2003) and $10 million write-off of Harbison-Walker Industries’ historic insurance coverage for the asbestos- insurance receivable are included in the asbestos and silica related liabilities that Harbison-Walker assumed in the charges table in the appropriate years under the line item spin-off. “Harbison-Walker matters.” In July 2001, DII Industries determined that the In 2003, DII Industries entered into a definitive agree- demands that Harbison-Walker was making on the shared ment with Harbison-Walker. Under the terms of this insurance policies were not acceptable to DII Industries agreement, once our plan of reorganization became final, and that Harbison-Walker probably would not be able to all asbestos and silica personal injury claims against fulfill its indemnification obligations to DII Industries. Harbison-Walker and certain of its affiliates were channeled Accordingly, DII Industries took up the defense of unset- into trusts created in our bankruptcy proceedings. Our tled post-spin-off refractory claims that name it as a asbestos and silica obligations and related insurance 80 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS recoveries recorded as of December 31, 2003 and 2004 available studies, including annual surveys by the National reflected the terms of this definitive agreement. Institutes of Health concerning the incidence of mesothe- In the first quarter of 2004, we entered into an agree- lioma deaths. In addition, Dr. Rabinovitz used the following ment with RHI Refractories to settle remaining funding assumptions in her estimates: issues relating to Harbison-Walker. The agreement calls for – there will be no legislative or other systemic changes a $10 million payment to RHI Refractories and a $1 million to the tort system; payment to our asbestos and silica trusts on behalf of RHI – we will continue to aggressively defend against Refractories. These amounts were expensed during 2003 asbestos claims made against us; and are include in the asbestos and silica charges table – an inflation rate of 3% annually for settlement pay- under line item “Harbison-Walker matters”. These pay- ments and an inflation rate of 4% annually for defense ments were made during January 2005. costs; and Highlands litigation. Highlands Insurance Company – we would receive no relief from our asbestos obliga- (Highlands) was our wholly-owned insurance company tion due to actions taken in the Harbison-Walker until it was spun off to our shareholders in 1996. Highlands Chapter 11 proceedings. wrote the primary insurance coverage for the construction In her estimates, Dr. Rabinovitz relied on the source data claims related to Brown & Root, Inc. prior to 1980. In provided by our management; she did not independently March 2002, Highlands won a lawsuit against Halliburton verify the accuracy of the source data. The report took asserting that the construction claims insurance it wrote approximately seven months to complete. for Brown & Root, Inc. was terminated by agreements Dr. Rabinovitz estimated the current and future total between Halliburton and Highlands at the time of the undiscounted liability for personal injury asbestos and silica 1996 spin-off. As a result of this ruling, in the first quarter claims through 2052, including defense costs, would be a 2002 we wrote off approximately $35 million in accounts range between $2.2 billion and $3.5 billion. The lower end receivable for amounts paid for claims and defense of the range was calculated by using an average of the last costs and $45 million of accrued receivables in relation five years of asbestos claims experience and the upper end to estimated insurance recoveries claims settlements of the range was calculated using the more recent two-year from Highlands. elevated rate of asbestos claim filings in projecting the rate Other. We continue to pursue our insurance rights of future claims. As a result of reaching an agreement in against certain insolvent London-based and domestic principle in December of 2002 (which was the basis of the insurance companies, such as Highlands Insurance definitive settlement agreements entered in early 2003) for Company (under insurance policies that were issued to the settlement of all of our asbestos and silica claims, we Dresser Industries, Inc. and certain of its predecessors) believed it was appropriate to adjust our accrual to use the and The Home Insurance Company. upper end of the range contained in Dr. Rabinovitz’s study. Asbestos and silica obligations and receivables based upon Therefore, in 2002, we recorded a pretax charge of $2.820 outside studies billion to increase our asbestos and silica liability to the Rabinovitz study. In late 2001, DII Industries retained Dr. upper end of the range. Francine F. Rabinovitz of Hamilton, Rabinovitz & Alschuler, Navigant studies. In 2002, we retained Navigant Inc. to estimate the probable number and value, including Consulting (formerly Peterson Consulting), a nationally defense costs, of unresolved current and future asbestos- recognized consultant in asbestos and silica liability and and silica-related bodily injury claims asserted against DII insurance, to work with us to project the amount of Industries and its subsidiaries. Dr. Rabinovitz’s estimates insurance recoveries probable at that time. In conducting are based on historical data supplied by us and publicly this analysis, Navigant Consulting used the Rabinovitz 81 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Study to project liabilities through 2052 using the two-year insured retentions, policy exclusions, liability caps and the elevated rate of asbestos claim filings. The methodology financial status of applicable insurers, and various judicial used by Navigant Consulting for that study was consistent determinations relevant to the applicable insurance with the methodology employed in December 2003. Based programs. The analysis of Navigant Consulting was based on our analysis of the probable insurance recoveries, we on information provided by us. recorded a receivable of $1.530 billion. As of December 31, 2003, we developed our best In December 2003, we again retained Navigant estimate of the asbestos and silica insurance receivables Consulting to assist us. In conducting their analysis, as follows: Navigant Consulting performed the following with respect – included $575 million of insurance recoveries from to our policies: Equitas based on a January 2004 comprehensive – reviewed DII Industries’ historical course of dealings agreement; with its insurance companies concerning the payment – included insurance recoveries from other specific of asbestos-related claims, including DII Industries’ insurers with whom we had settled; 15-year litigation and settlement history; – estimated insurance recoveries from specific insurers – reviewed our insurance coverage policy database that we are probable of settling with and for which we containing information on key policy terms as could reasonably estimate the amount of the settle- provided by outside counsel; ment. When appropriate, these estimates considered – reviewed the terms of DII Industries’ prior and prior settlements with insurers with similar facts and current coverage-in-place settlement agreements; circumstances; and – reviewed the status of DII Industries’ and Kellogg – estimated insurance recoveries for all other policies Brown & Root’s current insurance-related lawsuits and with the assistance of the Navigant Consulting study. the various legal positions of the parties in those The estimate we developed as a result of this process lawsuits in relation to the developed and developing was consistent with the amount of asbestos and silica case law and the historic positions taken by insurers in receivables recorded as of December 31, 2003, causing us the earlier filed and settled lawsuits; not to significantly adjust our recorded insurance asset at – engaged in discussions with our counsel; and that time. – analyzed publicly available information concerning the ability of the DII Industries insurers to meet their obligations. Navigant Consulting’s analysis assumed that there would be no recoveries from insolvent carriers and that NOTE 12. UNITED STATES GOVERNMENT CONTRACT WORK We provide substantial work under our government contracts business to the United States Department of Defense and other governmental agencies, including those carriers which are currently solvent would continue worldwide United States Army logistics contracts, known to be solvent throughout the period of the applicable as LogCAP, and contracts to rebuild Iraq’s petroleum recoveries in the projections. Based on its review, analysis, industry, known as RIO and PCO Oil South. Our govern- and discussions, Navigant Consulting’s analysis assisted us ment services revenue related to Iraq totaled approximately in making our judgments concerning insurance coverage that we believed were reasonable and consistent with our historical course of dealings with our insurers and the relevant case law to determine the probable insurance $7.1 billion in 2004 and approximately $3.6 billion in 2003. Our operations under United States government contracts are regularly reviewed and audited by the Defense Contract Audit Agency (DCAA) and other recoveries for asbestos liabilities. This analysis included the governmental agencies. The DCAA serves in an advisory probable effects of self-insurance features, such as self- 82 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS role to our customer. When issues are found during the of these costs are associated with the humanitarian fuel governmental agency audit process, these issues are mission. In these reports, the DCAA has compared fuel typically discussed and reviewed with us. The DCAA then costs we incurred during the duration of the RIO contract issues an audit report with their recommendations to our in 2003 and early 2004 to fuel prices obtained by the customer’s contracting officer. In the case of management Defense Energy Supply Center (DESC) in April 2004 when systems and other contract administrative issues, the the fuel mission was transferred to that agency. contracting officer is generally with the Defense Contract Investigations. On January 22, 2004, we announced the Management Agency (DCMA). We then work with our identification by our internal audit function of a potential customer to resolve the issues noted in the audit report. overbilling of approximately $6 million by La Nouvelle Given the demands of working in Iraq and elsewhere for Trading & Contracting Company, W.L.L. (La Nouvelle), one the United States government, we expect that from time to of our subcontractors, under the LogCAP contract in Iraq, time we will have disagreements or experience perform- for services performed during 2003. In accordance with our ance issues with the various government customers for policy and government regulation, the potential overcharge which we work. If our performance is unacceptable to our was reported to the Department of Defense Inspector customer under any of our government contracts, the General’s office as well as to our customer, the AMC. On government retains the right to pursue remedies under any January 23, 2004, we issued a check in the amount of $6 affected contract, which remedies could include threatened million to the AMC to cover that potential overbilling while termination or termination. If any contract were so we conducted our own investigation into the matter. Later terminated, we may not receive award fees under the in the first quarter of 2004, we determined that the amount affected contract, and our ability to secure future contracts of overbilling was $4 million, and the subcontractor billing could be adversely affected, although we would receive should have been $2 million for the services provided. As a payment for amounts owed for our allowable costs under result, we paid La Nouvelle $2 million and billed our cost-reimbursable contracts. customer that amount. We subsequently terminated La Fuel. In December 2003, the DCAA issued a preliminary Nouvelle’s services under the LogCAP contract. In October audit report that alleged that we may have overcharged the 2004, La Nouvelle filed suit against us alleging $224 million Department of Defense by $61 million in importing fuel in damages as a result of its termination. We are continuing into Iraq. The DCAA questioned costs associated with fuel to investigate whether La Nouvelle paid, or attempted to purchases made in Kuwait that were more expensive than pay, one or two of our former employees in connection with buying and transporting fuel from Turkey. We responded the billing. that we had maintained close coordination of the fuel In October 2004, we reported to the Department of mission with the Army Corps of Engineers (COE), which Defense Inspector General’s office that two former was our customer and oversaw the project, throughout the employees in Kuwait may have had inappropriate contacts life of the task order and that the COE had directed us to with individuals employed by or affiliated with two third- use the Kuwait sources. After a review, the COE concluded party subcontractors prior to the award of the subcontracts. that we obtained a fair price for the fuel. However, The Inspector General’s office may investigate whether Department of Defense officials thereafter referred the these two employees may have solicited and/or accepted matter to the agency’s inspector general, which we payments from these third-party subcontractors while they understand commenced an investigation. were employed by us. The DCAA has issued various audit reports related to In October 2004, a civilian contracting official in the task orders under the RIO contract that reported $304 COE asked for a review of the process used by the COE for million in questioned and unsupported costs. The majority awarding some of the contracts to us. We understand that 83 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS the Department of Defense Inspector General’s office may work performed prior to February 2004 and totaled review the issues involved. approximately $224 million as of December 31, 2004. The We understand that the United States Department of amount withheld could change as the DCAA continues Justice, an Assistant United States Attorney based in their audits of the remaining DFAC facilities. We are Illinois, and others are investigating these and other negotiating with our customer, the AMC, to resolve this individually immaterial matters we have reported relating issue. We are currently withholding a proportionate to our government contract work in Iraq. We also under- amount of these billings from our subcontractors. stand that current and former employees of KBR have Laundry. During the third quarter of 2004, we received received subpoenas and have given or may give grand jury notice from the DCAA that it recommended withholding testimony relating to some of these matters. If criminal $16 million of subcontract costs related to the laundry wrongdoing were found, criminal penalties could range up service for one task order in southern Iraq for which it to the greater of $500,000 in fines per count for a corpora- believes we and our subcontractors have not provided tion, or twice the gross pecuniary gain or loss. adequate levels of documentation supporting the quantity Dining Facility and Administration Centers (DFACs). During of the services provided. The DCAA recommended that the 2003, the DCAA raised issues relating to our invoicing to cost be withheld pending receipt of additional explanation the Army Materiel Command (AMC) for food services for or documentation to support subcontract cost. This $16 soldiers and supporting civilian personnel in Iraq and million was withheld from the subcontractor in the fourth Kuwait. We believe the issues raised by the DCAA relate to quarter of 2004. We are working with the AMC to resolve the difference between the number of troops the AMC this issue. directed us to support and the number of soldiers counted Withholding of payments. During 2004, the AMC issued a at dining facilities for United States troops and supporting determination that a particular contract clause could cause civilian personnel. In the first quarter of 2004, we reviewed it to withhold 15% from our invoices until our task orders our DFAC subcontracts in our Iraq and Kuwait areas of under the LogCAP contract are definitized. The AMC operation and have billed and continue to bill for all current delayed implementation of this withholding pending further DFAC costs. During 2004, we received notice from the review. The Army Field Support Command (AFSC) has DCAA that it was recommending withholding a portion of now been delegated authority by the AMC to determine our DFAC billings. For DFAC billings relating to subcon- whether or not to implement the withholding. The AFSC tracts entered into prior to February 2004, the DCAA has has informed us that it will assess the situation on a task recommended withholding 19.35% of the billings until it order by task order basis and, currently, withholding will completes its audits. Subsequent to February 2004, we continue to be delayed. We do not believe any potential 15% renegotiated our DFAC subcontracts to address the withholding will have a significant or sustained impact on specific issues raised by the DCAA and advised the AMC our liquidity because any withholding is temporary and and the DCAA of the new terms of the arrangements. We ends once the definitization process is complete. During have had no objection by the government to the terms and the third quarter of 2004, we and the AMC identified three conditions associated with these new DFAC subcontract senior management teams to facilitate negotiation under agreements. During the third quarter of 2004, we received the LogCAP task orders, and these teams are working to notification that, for three Kuwait DFACs, the DCAA negotiate outstanding issues and definitize task orders as recommended to our customer that costs be disallowed quickly possible. We are continuing to work with our because the DCAA is not satisfied with the level of docu- customer to resolve outstanding issues. As of January 18, mentation provided by us. The amount withheld related to 2005, 25 task orders for LogCAP totaling over $636 million suspended and recommended disallowed DFAC costs for have been definitized. 84 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS As of December 31, 2004, the COE had withheld $85 our work on the PCO Oil South project will be so termi- million of our invoices related to a portion of our RIO nated for default. We are in the process of developing an contract pending completion of the definitization process. acceptable management cost reporting system, and are All 10 definitization proposals required under this contract supplementing the existing PCO cost reporting team with have been submitted by us, and three have been finalized additional manpower. through a task order modification. After review by the Report on estimating system. On December 27, 2004, the DCAA, we have resubmitted five of the unfinalized seven DCMA granted continued approval of our estimating proposals and are in the process of developing revised system, stating that our estimating system is “acceptable proposals for the remaining two. These withholdings with corrective action.” We are in process of completing represent the amount invoiced in excess of 85% of the these corrective actions. Specifically, based on the unprece- funding in the task order. The COE also could withhold dented level of support our employees are providing the similar amounts from future invoices under our RIO military in Iraq, Kuwait, and Afghanistan, we needed to contract until agreement is reached with the customer and update our estimating policies and procedures to make task order modifications are issued. Approximately $2 them better suited to such contingency situations. million was withheld from our PCO Oil South project as of Additionally, we are in process of developing a detailed December 31, 2004. The PCO Oil South project has training program that will be made available to all estimat- definitized 15 of the 28 task orders and withholdings are ing personnel to ensure that employees are adequately not continuing on those task orders. We do not believe the prepared to deal with the challenges and unique circum- withholding will have a significant or sustained impact on stances associated with a contingency operation. our liquidity because the withholding is temporary and Report on purchasing system. As a result of a Contractor ends once the definitization process is complete. Purchasing System Review by the DCMA during the In addition, we had unapproved claims totaling $93 second quarter of 2004, the DCMA granted the continued million at December 31, 2004, for the LogCAP, RIO, and approval of our government contract purchasing system. PCO Oil South contracts. These unapproved claims related The DCMA’s approval letter, dated September 7, 2004, to contracts where our costs have exceeded the funded stated that our purchasing system’s policies and practices value of the task orders or were related to lost, damaged are “effective and efficient, and provide adequate protection and destroyed equipment. of the Government’s interest.” We are working diligently with our customers to The Balkans. We have had inquiries in the past by the proceed with significant new work only after we have a fully DCAA and the civil fraud division of the United States definitized task order, which should limit withholdings on Department of Justice into possible overcharges for work future task orders. performed during 1996 through 2000 under a contract in Cost reporting. We have received notice that a contracting the Balkans, which inquiry has not yet been completed by officer for our PCO Oil South project considers our the Department of Justice. Based on an internal investiga- monthly categorization and detail of costs and our ability to tion, we credited our customer approximately $2 million schedule and forecast costs to be inadequate, and he has during 2000 and 2001 related to our work in the Balkans as requested corrections be made by March 10, 2005. We a result of billings for which support was not readily expect to be able to make the requested corrections. If we available. We believe that the preliminary Department of were unable to satisfy our customer, our customer may Justice inquiry relates to potential overcharges in connec- pursue remedies under the applicable federal acquisition tion with a part of the Balkans contract under which regulations, including terminating the affected contract. approximately $100 million in work was done. We believe Although there can be no assurances, we do not expect that that any allegations of overcharges would be without merit. 85 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 13. OTHER COMMITMENTS AND CONTINGENCIES which is organized as part of the executive branch of the Nigerian joint venture and investigations government, are also investigating these matters. Our Foreign Corrupt Practices Act investigation. The Securities representatives have met with the French magistrate and and Exchange Commission (SEC) is conducting a formal Nigerian officials and expressed our willingness to investigation into payments made in connection with the cooperate with those investigations. In October 2004, construction and subsequent expansion by TSKJ of a representatives of TSKJ voluntarily testified before the multibillion dollar natural gas liquefaction complex and Nigerian legislative committee. related facilities at Bonny Island in Rivers State, Nigeria. As a result of our continuing investigation into these The United States Department of Justice is also conducting matters, information has been uncovered suggesting that, an investigation. TSKJ is a private limited liability company commencing at least 10 years ago, the members of TSKJ registered in Madeira, Portugal whose members are considered payments to Nigerian officials. We provided this Technip SA of France, Snamprogetti Netherlands B.V., information to the United States Department of Justice, the which is an affiliate of ENI SpA of Italy, JGC Corporation of SEC, the French magistrate, and the Nigerian Economic Japan, and Kellogg Brown & Root, each of which owns 25% and Financial Crimes Commission. We also notified the of the venture. other owners of TSKJ of the recently uncovered informa- The SEC and the Department of Justice have been tion and asked each of them to conduct their own reviewing these matters in light of the requirements of the investigation. United States Foreign Corrupt Practices Act (FCPA). We We understand from the ongoing governmental and have produced documents to the SEC both voluntarily and other investigations that payments may have been made to pursuant to subpoenas, and intend to make our employees Nigerian officials. In addition, TSKJ has suspended the available to the SEC for testimony. In addition, we under- receipt of services from and payments to Tri-Star stand that the SEC has issued a subpoena to A. Jack Investments and is considering instituting legal proceed- Stanley, who most recently served as a consultant and ings to declare all agency agreements with Tri-Star chairman of Kellogg Brown & Root, and to other current Investments terminated and to recover all amounts and former Kellogg Brown & Root employees. We further previously paid under those agreements. understand that the Department of Justice has invoked its We also understand that the matters under investigation authority under a sitting grand jury to obtain letters by the Department of Justice involve parties other than rogatory for the purpose of obtaining information abroad. Kellogg Brown & Root and M.W. Kellogg, Ltd. (a joint TSKJ and other similarly owned entities entered into venture in which Kellogg Brown & Root has a 55% inter- various contracts to build and expand the liquefied natural est), cover an extended period of time (in some cases gas project for Nigeria LNG Limited, which is owned by the significantly before our 1998 acquisition of Dresser Nigerian National Petroleum Corporation, Shell Gas B.V., Industries (which included M.W. Kellogg, Ltd.)), and Cleag Limited (an affiliate of Total), and Agip International possibly include the construction of a fertilizer plant in B.V., which is an affiliate of ENI SpA of Italy. Commencing Nigeria in the early 1990s and the activities of agents and in 1995, TSKJ entered into a series of agency agreements in service providers. connection with the Nigerian project. We understand that a In June 2004, we terminated all relationships with Mr. French magistrate has officially placed Jeffrey Tesler, a Stanley and another consultant and former employee of principal of Tri-Star Investments, an agent of TSKJ, under M.W. Kellogg, Ltd. The terminations occurred because of investigation for corruption of a foreign public official. In violations of our Code of Business Conduct that allegedly Nigeria, a legislative committee of the National Assembly involve the receipt of improper personal benefits in and the Economic and Financial Crimes Commission, 86 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS connection with TSKJ’s construction of the natural gas any persons financially injured by such violations. If such liquefaction facility in Nigeria. violations occurred, the United States government also In February 2005, TSKJ notified the Attorney General of would have the discretion to deny future government Nigeria that TSKJ would not oppose the Attorney General’s contracts business to KBR or affiliates or subsidiaries of efforts to have sums of money held on deposit in banks in KBR. Criminal prosecutions under applicable laws of Switzerland transferred to Nigeria and to have the legal relevant foreign jurisdictions and civil claims by or relation- ownership of such sums determined in the Nigerian courts. ship issues with customers are also possible. If violations of the FCPA were found, we could be There can be no assurance that the results of these subject to civil penalties of $500,000 per violation and investigations will not have a material adverse effect on our criminal penalties could range up to the greater of $2 business and results of operations. million per violation or twice the gross pecuniary gain As of December 31, 2004, we had not accrued any or loss. amounts related to this investigation. There can be no assurance that any governmental SEC investigation of change in accounting for revenue on long- investigation or our investigation of these matters will not term construction projects and related disclosures. In August conclude that violations of applicable laws have occurred or 2004, we reached a settlement in the investigation by the that the results of these investigations will not have a SEC involving our 1998 and 1999 disclosure of and material adverse effect on our business and results of accounting for the recognition of revenue from unapproved operations. claims on long-term construction projects. Our settlement As of December 31, 2004, we have not accrued any with the SEC covers a failure to disclose a 1998 change in amounts related to this investigation. accounting practice. We disclosed the change in accounting Bidding practices investigation. In connection with the practice in our 1999 Form 10-K and continued to do so in investigation into payments made in connection with the subsequent periods. The SEC did not determine that we Nigerian project, information has been uncovered suggest- departed from generally accepted accounting principles, ing that Mr. Stanley and other former employees may have nor did it find errors in accounting or fraud. We neither engaged in coordinated bidding with one or more competi- admitted nor denied the SEC’s findings, but paid a $7.5 tors on certain foreign construction projects and that such million civil penalty, and recorded a charge of that amount coordination possibly began as early as the mid-1980s, in the second quarter of 2004. As part of the settlement, the which was significantly before our 1998 acquisition of company agreed to cease and desist from committing or Dresser Industries. causing future securities law violations. On the basis of this information, we and the Department Securities and related litigation. On June 3, 2002, a class of Justice have broadened our investigations to determine action lawsuit was filed against us in federal court on behalf the nature and extent of any improper bidding practices, of purchasers of our common stock during the period of whether such conduct violated United States antitrust laws, approximately May 1998 until approximately May 2002 and whether former employees may have received alleging violations of the federal securities laws in connec- payments in connection with bidding practices on some tion with the accounting change and disclosures involved in foreign projects. the SEC investigation discussed above. In addition, the If violations of applicable United State antitrust laws plaintiffs allege that we overstated our revenue from occurred, the range of possible penalties includes criminal unapproved claims by recognizing amounts not reasonably fines, which could range up to the greater of $10 million in estimable or probable of collection. After that date, fines per count for a corporation, or twice the gross approximately twenty similar class actions were filed pecuniary gain or loss and treble civil damages in favor of against us. Several of those lawsuits also named as defen- 87 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS dants Arthur Andersen, LLP, our independent accountants asserted that it believes that, for various reasons, the $6 for the period covered by the lawsuits, and several of our million settlement amount is inadequate. present or former officers and directors. The class action The attorneys representing the dissident plaintiff filed cases were later consolidated and the amended consoli- another class action complaint in August 2003, raising dated class action complaint, styled Richard Moore, et al. v. allegations similar to those raised in the second amended Halliburton Company, et al., was filed and served upon us consolidated complaint regarding the accounting/disclo- on or about April 11, 2003 (the “Moore class action”). sure claims and the Dresser claims. In addition, the Subsequently, in October 2002 and March 2003, two complaint enhances the Dresser claims to include allega- derivative actions arising out of essentially the same tions related to our accounting with respect to the facts and circumstances were filed, one of which was acquisition, integration, and reserves of Dresser. We moved subsequently dismissed, while the other was transferred to dismiss that complaint, styled Kimble v. Halliburton to the same judge before whom the Moore class action Company, et al.; however, the court never ruled on our was pending. motion and ordered the case consolidated with the Moore In early May 2003, we announced that we had entered class action. On August 3, 2004 the attorneys representing into a written memorandum of understanding setting forth the dissident plaintiff filed a motion for leave to file yet the terms upon which both the Moore class action and the another class action complaint styled Murphey v. remaining derivative action would be settled. In June 2003, Halliburton Company, et al. The court has not ruled on that the lead plaintiffs in the Moore class action filed a motion motion. The proposed complaint raises and augments for leave to file a second amended consolidated complaint, allegations similar to those in the Moore class action and which was granted by the court. In addition to restating the the Kimble action, including additional allegations regard- original accounting and disclosure claims, the second ing disclosure of asbestos liability exposure. amended consolidated complaint includes claims arising On June 7, 2004, the court entered an order preliminar- out of the 1998 acquisition of Dresser Industries, Inc. by ily approving the settlement. Following the transfer of the Halliburton, including that we failed to timely disclose the case(s) to another district judge and a final hearing on the resulting asbestos liability exposure (the “Dresser claims”). fairness of the settlement, on September 9, 2004, the court The Dresser claims were included in the settlement entered an order holding that evidence of the settlement’s discussions leading up to the signing of the memorandum fairness was inadequate and denying the motion for final of understanding and are among the claims the parties approval of the settlement in the Moore class action and intended to be resolved by the terms of the proposed ordering the parties, among other things, to mediate. After settlement of the consolidated Moore class action and the the court’s denial of the motion to approve the settlement, derivative action. we withdrew from the settlement as we believe we are The memorandum of understanding called for entitled to do by its terms, although the settling plaintiffs Halliburton to pay $6 million, which would be funded by assert otherwise. In the days preceding the mediation, two insurance proceeds. After the May 2003 announcement union-sponsored pension funds filed a motion seeking leave regarding the memorandum of understanding, one of the to intervene in the consolidated class action litigation. We lead plaintiffs in the consolidated class action announced have opposed that motion. The mediation was held on that it was dissatisfied with the lead plaintiffs’ counsel’s January 27, 2005 and, at the conclusion of that day, was handling of settlement negotiations and what the dissident declared by the mediator to be at an impasse with no plaintiff regarded as inadequate communications by the settlement having been reached. lead plaintiffs’ counsel. The dissident lead plaintiff further After the mediation, the lead plaintiff and lead counsel filed motions to withdraw as lead plaintiff and lead counsel. 88 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The court has set a hearing on these motions, which were infringed on three of our patents. Under applicable law, unopposed, for April 29, 2005. We anticipate that at that the judge has the discretion to enhance the damages to a time the court will appoint a new lead counsel and issue an total amount of up to three times the amount awarded by order directing which complaint we are required to the jury and to award attorneys’ fees and costs. Subsequent respond to and the date by which any answer or responsive to the verdict, upon our motion, the court enhanced the motion should be filed. We intend to file a motion to jury verdict by $12 million and added another $5 million dismiss and to vigorously defend the action. in attorneys’ fees and costs for a total judgment of $41 On September 9, 2004, the court ordered that if no million. Post-trial motions for a new trial and for judgment objections to the settlement of the derivative action as a matter of law were denied and Smith appealed the described above were made by October 20, 2004, the court judgment. would finally approve the derivative action settlement. On Related litigation dealing with claims of infringement of February 18, 2005, the court entered an order dismissing the same technology was tried in January and February the derivative action with prejudice. 2005 in England and a decision is expected shortly. Similar Newmont Gold. In July 1998, Newmont Gold, a gold litigation is pending in courts in Italy and is expected to go mining and extraction company, filed a lawsuit over the to trial during 2005. failure of a blower manufactured and supplied to Newmont It is not possible to predict the results of these matters by Roots, a former division of Dresser Equipment Group. and no amounts have been recorded as of December 31, The plaintiff alleges that during the manufacturing process, 2004. Roots had reversed the blades on a component of the Improper payments reported to the SEC. During the second blower known as the inlet guide vane assembly, resulting in quarter 2002, we reported to the SEC that one of our the blower’s failure and the shutdown of the gold extraction foreign subsidiaries operating in Nigeria made improper mill for a period of approximately one month during 1996. payments of approximately $2.4 million to entities owned In January 2002, a Nevada trial court granted summary by a Nigerian national who held himself out as a tax judgment to Roots on all counts and Newmont appealed. In consultant, when in fact he was an employee of a local tax February 2004, the Nevada Supreme Court reversed the authority. The payments were made to obtain favorable tax summary judgment and remanded the case to the trial treatment and clearly violated our Code of Business court, holding that fact issues existed which would require Conduct and our internal control procedures. The pay- trial. Based on pretrial reports, the damages claimed by the ments were discovered during our audit of the foreign plaintiff are in the range of $33 million to $39 million. We subsidiary. We conducted an investigation assisted by believe that we have valid defenses to Newmont’s claims outside legal counsel and, based on the findings of the and intend to vigorously defend the matter. As of investigation, we terminated several employees. None of December 31, 2004, we had not accrued any amounts our senior officers were involved. We are cooperating with related to this matter. the SEC in its review of the matter. We took further action Smith International award. In June 2004, a Texas district to ensure that our foreign subsidiary paid all taxes owed in court jury returned a verdict in our favor in connection Nigeria. A preliminary assessment of approximately $4 with a patent infringement lawsuit we filed against Smith million was issued by the Nigerian tax authorities in the International (Smith). We were awarded $24 million in second quarter of 2003. We are cooperating with the damages by the jury. We filed the lawsuit in September Nigerian tax authorities to determine the total amount due 2002 seeking damages for Smith’s infringement of our as quickly as possible. patented Energy Balanced roller cone drill bit technology. ® Operations in Iran. We received and responded to an The jury found that Smith’s competing bits willfully inquiry in mid-2001 from the Office of Foreign Assets 89 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Control (OFAC) of the United States Treasury Department $34 million for tortious interference, and an unspecified with respect to operations in Iran by a Halliburton sub- sum for consequential and punitive damages. The dispute sidiary that is incorporated in the Cayman Islands. The arises from our termination of a master agreement OFAC inquiry requested information with respect to pursuant to which La Nouvelle operated a number of compliance with the Iranian Transaction Regulations. DFACs in Kuwait and Iraq and the replacement of La These regulations prohibit United States citizens, including Nouvelle with ESS which, prior to La Nouvelle’s termina- United States corporations and other United States tion, had served as La Nouvelle’s subcontractor. In business organizations, from engaging in commercial, addition, La Nouvelle alleges that we wrongfully withheld financial, or trade transactions with Iran, unless authorized from La Nouvelle certain sums due La Nouvelle under its by OFAC or exempted by statute. Our 2001 written various subcontracts. response to OFAC stated that we believed that we were in While we admit that we have withheld certain sums compliance with applicable sanction regulations. In January from La Nouvelle, we believe that we were contractually 2004, we received a follow-up letter from OFAC requesting entitled to do so and that we had the right to terminate the additional information. We responded to this request on master agreement with La Nouvelle for cause. The case has March 19, 2004. We understand this matter has now been only recently been filed and our investigation is in its referred by OFAC to the Department of Justice. In July preliminary stages. Accordingly, it is premature to assess 2004, we received a grand jury subpoena from an Assistant the likelihood of an unfavorable result. La Nouvelle has United States District Attorney requesting the production requested and we have agreed to stay all proceedings for a of documents. We are cooperating with the government’s period of 60 days, during which the parties will participate investigation and have responded to the subpoena by in mediation. We cannot assess the likelihood that media- producing documents on September 16, 2004. As of tion will result in a settlement. Should it not, however, it is December 31, 2004, we had not accrued any amounts our intention to vigorously defend the action. As of related to this investigation. December 31, 2004, except for amounts previously invoiced Separate from the OFAC inquiry, we completed a study to us by La Nouvelle for work performed, we had not in 2003 of our activities in Iran during 2002 and 2003 and accrued any amounts related to this litigation. concluded that these activities were in compliance with David Hudak and International Hydrocut Technologies Corp. applicable sanction regulations. These sanction regulations On October 12, 2004, David Hudak and International require isolation of entities that conduct activities in Iran Hydrocut Technologies Corp. (collectively, Hudak) filed from contact with United States citizens or managers of suit against us in the United States District Court alleging United States companies. Notwithstanding our conclusions civil Racketeer Influenced and Corrupt Organizations Act that our activities in Iran were not in violation of United violations, fraud, breach of contract, unfair trade practices, States laws and regulations, we have recently announced and other torts. The action, which seeks unspecified that, after fulfilling our current contractual obligations damages, arises out of Hudak’s alleged purchase in early within Iran, we intend to cease operations within that 1994 of certain explosive charges that were later alleged by country and to withdraw from further activities there. the United States Department of Justice to be military Litigation brought by La Nouvelle. In October 2004, La ordnance, the possession of which by persons not possess- Nouvelle, a subcontractor to us in connection with our ing the requisite licenses and registrations is unlawful. As a government services work in Kuwait and Iraq, filed suit result of that allegation by the government, Hudak was alleging breach of contract and interference with contrac- charged with, but later acquitted of, certain criminal tual and business relations. The relief sought includes $224 offenses in connection with his possession of the explosive million in damages for breach of contract, which includes charges. As mentioned above, the alleged transaction(s) 90 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS took place more than ten years ago. The fact that most of million of the liability balance. We have subsidiaries that the individuals that may have been involved, as well as the have been named as potentially responsible parties along entities themselves, are no longer affiliated with us, will with other third parties for 15 federal and state superfund complicate our investigation. For those reasons and sites for which we have established a liability. As of because the litigation is in its most preliminary stages, it is December 31, 2004, those 15 sites accounted for approxi- premature to assess the likelihood of an adverse result. It mately $11 million of our total $41 million liability. In some is, however, our intention to vigorously defend this action. instances, we have been named a potentially responsible As of December 31, 2004, we had not accrued any amounts party by a regulatory agency, but in each of those cases, related to this matter. we do not believe we have any material liability. Environmental. We are subject to numerous environmen- Letters of credit. In the normal course of business, we tal, legal, and regulatory requirements related to our have agreements with banks under which approximately operations worldwide. In the United States, these laws and $1.1 billion of letters of credit or bank guarantees were regulations include, among others: outstanding as of December 31, 2004, including $264 – the Comprehensive Environmental Response, million which relate to our joint ventures’ operations. Also Compensation and Liability Act; included in letters of credit outstanding as of December 31, – the Resources Conservation and Recovery Act; 2004 and related to the Barracuda-Caratinga project were – the Clean Air Act; $277 million of performance letters of credit and $176 – the Federal Water Pollution Control Act; and million of retainage letters of credit. Certain of the out- – the Toxic Substances Control Act. standing letters of credit have triggering events which In addition to the federal laws and regulations, states would entitle a bank to require cash collateralization. and other countries where we do business may have In the fourth quarter of 2003, we entered into a senior numerous environmental, legal, and regulatory require- secured master letter of credit facility (Master LC Facility) ments by which we must abide. We evaluate and address with a syndicate of banks which covered at least 90% of the the environmental impact of our operations by assessing face amount of our existing letters of credit. The facility and remediating contaminated properties in order to expired on December 31, 2004, at which time there were avoid future liabilities and comply with environmental, no outstanding advances under the Master LC Facility. legal, and regulatory requirements. On occasion, we are Upon the expiration of the Master LC Facility, all letters of involved in specific environmental litigation and claims, credit under the facility ceased to be subject to the terms of including the remediation of properties we own or have the facility and reverted back to the original agreements operated as well as efforts to meet or correct compliance- with the individual banks. related matters. Our Health, Safety and Environment Other commitments. As of December 31, 2004, we had group has several programs in place to maintain environ- commitments to fund approximately $58 million to certain mental leadership and to prevent the occurrence of of our related companies. These commitments arose environmental contamination. primarily during the start-up of these entities or due to We do not expect costs related to these remediation losses incurred by them. We expect approximately $42 requirements to have a material adverse effect on our million of the commitments to be paid during the next year. consolidated financial position or our results of operations. Liquidated damages. Many of our engineering and Our accrued liabilities for environmental matters were $41 construction contracts have milestone due dates that must million as of December 31, 2004 and $31 million as of be met or we may be subject to penalties for liquidated December 31, 2003. The liability covers numerous proper- damages if claims are asserted and we were responsible for ties and no individual property accounts for more than $5 the delays. These generally relate to specified activities 91 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS within a project by a set contractual date or achievement of The United States and foreign components of income a specified level of output or throughput of a plant we (loss) from continuing operations before income taxes, construct. Each contract defines the conditions under minority interest, and change in accounting principle are which a customer may make a claim for liquidated dam- as follows: ages. However, in most instances, liquidated damages are not asserted by the customer but the potential to do so is used in negotiating claims and closing out the contract. We had not accrued liabilities for $44 million at December 31, Millions of dollars United States Foreign Total Years ended December 31 2004 $135 516 $651 2003 $254 358 $612 2002 $(537) 309 $(228) 2004 and $243 million at December 31, 2003 of liquidated The reconciliations between the actual provision for damages we could incur based upon completing the income taxes on continuing operations and that computed projects as forecasted. A significant portion of the by applying the United States statutory rate to income from December 31, 2003 amount was related to the Barracuda- continuing operations before income taxes, minority Caratinga project. See Note 3 for further discussion. interest, and change in accounting principle are as follows: Leases. We are obligated under operating leases, principally for the use of land, offices, equipment, field facilities, and warehouses. Total rentals, net of sublease rentals, were as follows: Millions of dollars Rental expense 2004 $693 2003 $451 2002 $356 Future total rentals on noncancelable operating leases are as follows: $158 million in 2005; $125 million in 2006; $104 million in 2007; $92 million in 2008; $82 million in 2009; and $453 million thereafter. NOTE 14. INCOME TAXES United States statutory rate State income taxes, net of federal income tax benefit Impact of foreign operations Adjustments of prior year taxes Dispositions Valuation allowance Other items, net Total effective tax rate on continuing operations Years ended December 31 2004 35.0% 2003 35.0% 2002 35.0% 0.6 – (2.1) – – 3.6 0.9 0.8 1.6 (1.6) – 1.5 0.9 (1.8) 14.5 (12.3) (71.5) – 37.1% 38.2% (35.2)% Our impairment loss on Bredero-Shaw during 2002 could not be benefited for tax purposes due to book and tax basis differences in that investment and the limited benefit generated by a capital loss carryback. However, due to The components of the benefit (provision) for income changes in circumstances regarding prior years, we are taxes on continuing operations are: now able to carry back a portion of the capital loss, which Millions of dollars Current income taxes: Federal Foreign State Total current Deferred income taxes: Federal Foreign State Total deferred Provision for income taxes Years ended December 31 resulted in an $11 million benefit in 2003. 2004 2003 2002 The asbestos accruals, the losses on the Bredero-Shaw $ (88) (156) (6) (250) 3 6 – 9 $(241) $ (167) (181) 1 (347) 80 25 8 113 $(234) $ 71 (173) 4 (98) (11) 11 18 18 $(80) disposition, and the associated tax benefits net of valuation allowances in continuing operations during 2002 are the primary causes of the unusual 2002 effective tax rate on continuing operations. There were no significant asbestos charges or related tax accruals included in continuing operations for 2004 or 2003. 92 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The primary components of our deferred tax assets and liabilities and the related valuation allowances, including deferred tax accounts associated with discontinued operations, are as follows: Millions of dollars Gross deferred tax assets: December 31 2004 2003 Asbestos- and silica-related liabilities Employee compensation and benefits Foreign tax credit carryforward Net operating loss carryforwards Capitalized research and experimentation Construction contract accounting Insurance accruals Accrued liabilities Alternative minimum tax credit carryforward Other Total Gross deferred tax liabilities: Insurance for asbestos- and silica-related liabilities Depreciation and amortization Other Total Valuation allowances: Future tax attributes related to asbestos and silica litigation Foreign tax credit limitation Net operating loss carryforwards Total Net deferred income tax asset $1,770 263 135 115 85 75 71 69 21 260 $2,864 $318 182 33 $533 $1,073 135 43 $1,251 $1,080 $1,463 275 113 83 100 94 77 100 30 191 $ 2,526 $ 631 129 11 $ 771 $ 624 113 56 $ 793 $ 962 We have $303 million of net operating loss carryfor- wards that expire from 2005 through 2014 and net operating loss carryforwards of $71 million with indefinite expiration dates. The federal alternative minimum tax credits are available to reduce future United States federal income taxes on an indefinite basis. We have established a valuation allowance against foreign tax credit carryovers and certain foreign operating loss carryforwards on the basis that we believe these assets will not be utilized in the statutory carryover period. We also have recorded a valuation allowance on the asbestos and silica liabilities based on the anticipated impact of the future asbestos and silica deductions on our ability to utilize future foreign tax credits. We anticipate that a portion of the asbestos and silica deductions will displace future foreign tax credits, and those credits will expire unutilized. 93 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 15. SHAREHOLDERS’ EQUITY AND STOCK INCENTIVE PLANS The following tables summarize our common stock and other shareholders’ equity activity: (Millions of dollars) Balance at December 31, 2001 Cash dividends paid Reissuance of treasury stock for: Stock purchase, compensation, and incentive plans, net Stock issued for acquisition Treasury stock purchased Current year awards, net of tax Tax benefit from exercise of options Total dividends and other transactions with shareholders Comprehensive income: Net loss Other comprehensive income: Cumulative translation adjustment Realization of losses included in net income Minimum pension liability adjustment, net of tax of $70 Unrealized gain on investments and derivatives Total comprehensive loss Balance at December 31, 2002 Cash dividends paid Reissuance of treasury stock for: Stock purchase, compensation, and incentive plans, net Treasury stock purchased Current year awards, net of tax Tax benefit from exercise of options Total dividends and other transactions with shareholders Comprehensive income: Net loss Other comprehensive income: Cumulative translation adjustment Realization of losses included in net income Minimum pension liability adjustment, net of tax of $25 Unrealized gain on investments and derivatives Total comprehensive loss Balance at December 31, 2003 94 Common Stock $1,138 – Capital in Excess of Par Value $298 – Treasury Stock $(688) – Deferred Compensation Retained Earnings Accumulated Other Comprehensive Income $(87) – $4,327 (219) $(236) – 1 2 – – – 3 – – – – – – $1,141 – 1 – – – 1 – – – – (24) 24 – – (5) (5) – – – – – – $293 – (19) – – (1) (20) – – – – 62 – (4) – – 58 – – – – – – – 12 – 12 – – – – – – $(630) – – $(75) – 60 (7) – – 53 – – – – – – – 11 – 11 – – – – – – – – – (219) (998) – – – – (998) $3,110 (219) – – – – (219) (820) – – – – – $1,142 – – $273 – – $(577) – – $(64) – (820) $2,071 – – – – – – – 69 15 (130) 1 (45) $(281) – – – – – – – 43 15 (88) 13 (17) $(298) HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Millions of dollars) Balance at December 31, 2003 Cash dividends paid Reissuance of treasury stock for: Stock purchase, compensation, and incentive plans, net Treasury stock purchased Current year awards, net of tax Tax benefit from exercise of options Total dividends and other transactions with shareholders Asbestos trust shares Comprehensive income: Net loss Other comprehensive income: Cumulative translation adjustment Realization of gains included in net income Minimum pension liability adjustment, net of tax of $49 Unrealized gain on investments and derivatives, net of tax of $8 Total comprehensive income (loss) Balance at December 31, 2004 Common Stock $1,142 – 4 – – – 4 – – – – – – Capital in Excess of Par Value $273 – (3) – – 7 4 – – – – – – Asbestos Trust Shares $- – – – – – – 2,335 – – – – – Treasury Stock $(577) – 107 (7) – – 100 – – – – – – Deferred Compensation $(64) – – – (10) – (10) – – – – – – Retained Earnings $2,071 (221) – – – – (221) – (979) – – – – Accumulated Other Comprehensive Income $(298) – – – – – – – – 33 (1) 115 5 – $1,146 – $277 – $2,335 – $(477) – $(74) (979) $871 152 $(146) 95 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Accumulated other comprehensive income D e c e m b e r 3 1 Millions of dollars Cumulative translation adjustment Pension liability adjustments Unrealized gains (losses) on investments and derivatives Total accumulated other comprehensive income 2004 $(31) (130) 2003 $(63) (245) 2002 $(121) (157) 15 10 (3) $(146) $(298) $(281) Shares of common stock D e c e m b e r 3 1 Millions of shares 2004 458 Issued In treasury (16) Total shares of common stock outstanding 442 2003 457 (18) 439 2002 456 (20) 436 Our 1993 Stock and Incentive Plan provides for the grant of any or all of the following types of awards: – stock options, including incentive stock options and nonqualified 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 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, 2004, 14 million shares were available for future grants under the 1993 Stock and Incentive Plan, of which eight million shares remain available for restricted stock awards. All stock options under the 1993 Stock and Incentive Plan are granted at the fair market value of the common stock at the grant date. No further stock option grants are being made under the stock plans of acquired companies. The following table represents our stock options granted, exercised, and forfeited during the past three years, and includes exercised and forfeited shares residual to our acquired companies’ stock plans. Stock Options Outstanding at December 31, 2001 Granted Exercised Forfeited Outstanding at December 31, 2002 Granted Exercised Forfeited Outstanding at December 31, 2003 Granted Exercised Forfeited Outstanding at Number of Shares (in millions) Exercise Price per Share Weighted Average Exercise Price per Share 17.1 2.6 –* (1.2) 18.5 2.4 (0.4) (1.0) 19.5 2.2 (1.5) (0.8) $8.28 – 61.50 9.10 – 19.75 8.93 – 17.21 8.28 – 54.50 $9.10 – 61.50 18.60 – 24.76 8.28 – 23.52 9.10 – 54.50 $9.10 – 61.50 26.03 – 40.18 9.10 – 39.55 9.10 – 54.50 $35.10 12.57 11.39 31.94 $32.10 23.45 14.75 32.07 $31.34 29.22 21.87 33.19 December 31, 2004 19.4 $9.10 – 61.50 $31.74 *Actual exercises for 2002 were approximately 30,000 shares. Options outstanding at December 31, 2004 are com- posed of the following: O u t s t a n d i n g E x e r c i s a b l e Weighted Average Weighted Number of Remaining Average Exercise Contractual Price Life $18.54 6.6 28.39 5.4 37.40 4.9 45.82 4.8 $31.74 5.5 Shares (in millions) 4.5 6.0 5.5 3.4 19.4 Number of Shares (in millions) 2.3 3.6 4.9 3.3 14.1 Weighted Average Exercise Price $17.86 28.61 37.90 46.02 $34.15 Range of Exercise Prices $9.10 – 23.79 $23.80 – 29.87 $29.88 – 39.54 $39.55 – 61.50 $9.10 – 61.50 There were 13.8 million options exercisable with a weighted average exercise price of $34.59 at December 31, 2003 and 12.5 million options exercisable with a weighted average exercise price of $34.98 at December 31, 2002. Stock options generally expire 10 years from the grant date. Stock options under the 1993 Stock and Incentive Plan vest ratably over a three- or four-year period. Options under the non-employee directors’ plan vest after six months. Other plans have vesting periods ranging from three to 10 years. Restricted shares awarded under the 1993 Stock and Incentive Plan were 1,177,312 in 2004, 431,865 in 2003, and 1,706,643 in 2002. The shares awarded are net of forfeitures of 143,908 in 2004, 248,620 in 2003, and 46,894 in 2002. The weighted average fair market value per share at the date of 96 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS grant of shares granted was $29.80 in 2004, $22.94 in 2003, charged to income generally over the average period and $14.95 in 2002. during which the restrictions lapse, with similar credits to Our Restricted Stock Plan for Non-Employee Directors paid-in capital in excess of par value. At December 31, 2004, allows for each non-employee director to receive an annual the unamortized amount is $74 million. We recognized award of 400 restricted shares of common stock as a part of compensation costs of $21 million in 2004, $20 million in compensation. We reserved 100,000 shares of common 2003, and $38 million in 2002. stock for issuance to non-employee directors. Under this During 2002, our Board of Directors approved the 2002 plan we issued 4,000 restricted shares in 2004 and 2003, Employee Stock Purchase Plan (ESPP) and reserved 12 and 4,400 restricted shares in 2002. At December 31, 2004, million shares for issuance. Under the ESPP, eligible 46,000 shares have been issued to non-employee directors employees may have up to 10% of their earnings withheld, under this plan. The weighted average fair market value subject to some limitations, to be used to purchase shares per share at the date of grant of shares granted was $31.30 of our common stock. Unless the Board of Directors shall in 2004, $22.24 in 2003, and $12.56 in 2002. determine otherwise, each 6-month offering period Our Employees’ Restricted Stock Plan was established commences on January 1 and July 1 of each year. The price for employees who are not officers, for which 200,000 at which common stock may be purchased under the ESPP shares of common stock have been reserved. At December is equal to 85% of the lower of the fair market value of the 31, 2004, 151,850 shares (net of 43,550 shares forfeited) common stock on the commencement date or last trading have been issued. There were no forfeitures in 2004. day of each offering period. Through the ESPP, there were Forfeitures were 800 in 2003 and 400 in 2002. No further approximately 1.7 million shares sold in 2004, approxi- grants are being made under this plan. mately 1.3 million shares sold in 2003, and approximately Under the terms of our Career Executive Incentive 541,000 shares sold in 2002. Stock Plan, 15 million shares of our common stock were On April 25, 2000, our Board of Directors approved reserved for issuance to officers and key employees at a plans to implement a share repurchase program for up to purchase price not to exceed par value of $2.50 per share. 44 million shares. No shares were repurchased under this At December 31, 2004, 11.7 million shares (net of 2.2 plan in 2004, 2003, or 2002. million shares forfeited) have been issued under the plan. The last grant made under this plan was in December 1992. NOTE 16. SERIES A JUNIOR PARTICIPATING PREFERRED STOCK No further grants will be made under the Career Executive Our preferred stock consists of five million total Incentive Stock Plan. Restricted shares issued under the 1993 Stock and Incentive Plan, Restricted Stock Plan for Non-Employee Directors, Employees’ Restricted Stock Plan, and the authorized shares at December 31, 2004. 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 Career Executive Incentive Stock Plan are limited as to sale was issued subsequent to adoption of the Rights or disposition. These restrictions lapse periodically over an Agreement entered into with Mellon Investor Services extended period of time not exceeding 10 years. LLC. Each preferred stock purchase right entitles its Restrictions may also lapse for early retirement and other holder to buy one two-hundredth of a share of our Series A conditions in accordance with our established policies. Junior Participating Preferred Stock, without par value, at Upon termination of employment, shares in which restric- an exercise price of $75. These preferred stock purchase tions have not lapsed must be returned to us, resulting in rights are subject to antidilution adjustments, which are restricted stock forfeitures. The fair market value of the described in the Rights Agreement entered into with stock on the date of issuance is being amortized and 97 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Mellon. The preferred stock purchase rights do not have threshold for a specified time period. Our 3.125% convert- any voting rights and are not entitled to dividends. ible senior notes due 2023 are an example of these types of The preferred stock purchase rights become exercis- instruments. Prior to the effective date of the new consen- able in limited circumstances involving a potential business sus, we excluded the potential dilutive effect of the combination. After the preferred stock purchase rights conversion feature from diluted earnings per share until become exercisable, each preferred stock purchase right the contingency threshold was met (it has never been met will entitle its holder to an amount of our common stock, or in the case of the 3.125% convertible senior notes). EITF in some circumstances, securities of the acquirer, having a Issue No. 04-08 provides that these debt instruments total market value equal to two times the exercise price of should be included in the earnings per share computation, the preferred stock purchase right. The preferred stock if dilutive, regardless of whether the contingent feature has purchase rights are redeemable at our option at any time been met. before they become exercisable. The preferred stock As a result of the new EITF, in December 2004 we purchase rights expire on December 15, 2005. entered into a supplemental indenture that requires us to NOTE 17. INCOME (LOSS) PER SHARE Basic income (loss) per share is based on the weighted average number of shares of common stock outstanding during the period. Diluted income (loss) per share includes additional shares of common stock that would have been outstanding if potential common shares (consisting primarily of stock options) with a dilutive effect had been issued. The effect of common stock equivalents on basic weighted average shares outstanding was an additional four million shares in 2004 and three million shares in 2003. Excluded from the computation of diluted income (loss) per share are options to purchase nine million shares of common stock in 2004 and 15 million shares in 2003. These options were outstanding during these years, but were excluded because the option exercise price was greater than the average market price of the shares of common stock. On September 30, 2004, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-08, “The Effect of Contingently Convertible Debt on Diluted Earnings per Share,” which changes the treatment of contingently convertible debt instruments in the calculation of diluted earnings per share. Contingently convertible debt instruments are financial instruments that include a contingent feature, such as the debt becoming convertible into shares of common stock of the issuer if the issuer’s common stock price has exceeded a predetermined satisfy our conversion obligation for our $1.2 billion 3.125% convertible senior notes in cash, rather than in common stock, for at least the aggregate principal amount of the notes, thus reducing the resulting potential earnings dilution to only include the conversion premium, which is the difference between the conversion price per share of common stock and the average share price. The conversion price of $37.65 per share of common stock was greater than our average share price in each of the quarters since issuance of the notes in June 2003 and, as a result, did not result in dilution. For 2002, we used the basic weighted average shares in the calculation of diluted loss per share as the effect of the common stock equivalents, which totaled two million shares for this period, would have been antidilutive based upon the loss from continuing operations. NOTE 18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT Foreign exchange risk. Techniques in managing foreign exchange risk include, but are not limited to, foreign currency borrowing and investing and the use of currency derivative instruments. We selectively manage significant exposures to potential foreign exchange losses considering current market conditions, future operating activities, and the associated cost in relation to the perceived risk of loss. The purpose of our foreign currency risk management activities is to protect us from the risk that the eventual 98 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS dollar cash flows resulting from the sale and purchase of nated in foreign currencies generally related to long-term products and services in foreign currencies will be engineering and construction projects. Beginning in 2003, adversely affected by changes in exchange rates. we designated these contracts related to engineering and We manage our currency exposure through the use of construction projects as cash flow hedges. The ineffective currency derivative instruments as it relates to the major portion of these hedges was included in operating income currencies, which are generally the currencies of the in the accompanying consolidated statement of operations countries in which we do the majority of our international and was not material in 2004 or 2003. The unrealized net business. These contracts generally have an expiration date gains on these cash flow hedges were approximately $23 of two years or less. Forward exchange contracts, which million as of December 31, 2004 and $10 million as of are commitments to buy or sell a specified amount of a December 31, 2003 and are included in other comprehen- foreign currency at a specified price and time, are generally sive income in the accompanying consolidated balance used to manage identifiable foreign currency commitments. sheet. We expect approximately $23 million of the unreal- Forward exchange contracts and foreign exchange option ized net gain on these cash flow hedges to be reclassified contracts, which convey the right, but not the obligation, to into earnings within a year, as most of these cash flow sell or buy a specified amount of foreign currency at a hedges settle in the next 12 months. Changes in the timing specified price, are generally used to manage exposures or amount of the future cash flows being hedged could related to assets and liabilities denominated in a foreign result in hedges becoming ineffective and, as a result, the currency. None of the forward or option contracts are amount of unrealized gain or loss associated with those exchange traded. While derivative instruments are subject hedges would be reclassified from other comprehensive to fluctuations in value, the fluctuations are generally offset income into earnings. At December 31, 2004, the maximum by the value of the underlying exposures being managed. length of time over which we are hedging our exposure to The use of some contracts may limit our ability to benefit the variability in future cash flows associated with foreign from favorable fluctuations in foreign exchange rates. currency forecasted transactions is 16 months. In 2002, we Foreign currency contracts are not utilized to manage did not designate these derivative contracts related to exposures in some currencies due primarily to the lack engineering and construction projects as cash flow hedges. of available markets or cost considerations (non-traded The fair value of these contracts was $27 million as of currencies). We attempt to manage our working capital December 31, 2004, and immaterial as of December 31, position to minimize foreign currency commitments in 2003 and 2002. non-traded currencies and recognize that pricing for Notional amounts and fair market values. The notional the services and products offered in these countries amounts of open forward contracts and option contracts should cover the cost of exchange rate devaluations. were $1.4 billion at December 31, 2004 and $1.0 billion at We have historically incurred transaction losses in non- December 31, 2003. The notional amounts of our foreign traded currencies. exchange contracts do not generally represent amounts Assets, liabilities, and forecasted cash flows denominated in exchanged by the parties, and thus, are not a measure of foreign currencies. We utilize the derivative instruments our exposure or of the cash requirements relating to these described above to manage the foreign currency exposures contracts. The amounts exchanged are calculated by related to specific assets and liabilities, which are denomi- reference to the notional amounts and by other terms of nated in foreign currencies; however, we have not elected the derivatives, such as exchange rates. to account for these instruments as hedges for accounting Credit risk. Financial instruments that potentially subject purposes. Additionally, we utilize the derivative instruments us to concentrations of credit risk are primarily cash described above to manage forecasted cash flows denomi- equivalents, investments, and trade receivables. It is our 99 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS practice to place our cash equivalents and investments in instruments are carried on the balance sheet at fair value high quality securities with various investment institutions. and are based upon third-party quotes. We derive the majority of our revenue from our United States government contracts, primarily for projects in the Middle East, and from sales and services, including engineering and construction, to the energy industry. Within the energy industry, trade receivables are gener- ated 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. In addition, see Note 6 for discussion of United States government receivables. There are no significant concentrations of credit risk with any individual counterparty related to our derivative contracts. We select counterparties based on their prof- itability, 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. As of December 31, 2004, we held no interest rate derivative instruments. Fair market value of financial instruments. The estimated fair market value of long-term debt was $3.7 billion at December 31, 2004 and $3.6 billion at December 31, 2003, as compared to the carrying amount of $3.9 billion at December 31, 2004 and $3.4 billion at December 31, 2003. 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. 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 NOTE 19. RETIREMENT PLANS Our company and subsidiaries have various plans which cover a significant number of our employees. These plans include defined contribution plans, defined benefit plans, and other postretirement plans: - our defined contribution plans provide retirement contributions in return for services rendered. These plans provide an individual account for each participant and have terms that specify how contributions to the participant’s account are to be determined rather than the amount of pension benefits the participant is to receive. Contributions to these plans are based on pretax income and/or discretionary amounts deter- mined on an annual basis. Our expense for the defined contribution plans for both continuing and discontin- ued operations totaled $147 million, $87 million, and $80 million in 2004, 2003, and 2002, respectively. For 2004, we amended certain defined contribution plans to allow for a non-elective contribution, which resulted in an increase of $53 million over the 2003 expense; – our defined benefit plans include both funded and unfunded pension plans, which define an amount of pension benefit to be provided, usually as a function of age, years of service, or compensation; and – our postretirement medical plans are offered to specific eligible employees. These plans are contribu- tory. For some plans, our liability is limited to a fixed contribution amount for each participant or depend- ent. The plan participants share the total cost for all benefits provided above our fixed contribution. Participants’ contributions are adjusted as required to cover benefit payments. We have made no commit- ment 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. Dresser Retiree Medical. Through 2003, we were responsi- ble for the majority of the costs for the Dresser Retiree 100 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Medical Plan. An amendment was made to this plan at the end of 2003 to limit our share of the costs and eventually eliminate certain plans in 2005. We presented the impact of this amendment in our 2003 notes to consolidated financial statements which reduced our projected benefit obligation by $86 million and increased our unrecognized prior service benefit by the same amount, with no impact to our balance sheet or statement of operations. In December 2004, the United States District Court ruled that we must continue to maintain the Dresser Retiree Medical Plan as we had in the past. We have revised our prior year presentation of the projected benefit obligation and unrecognized prior service benefit to reflect the plan at its pre-amendment amounts. We also adjusted our annual postretirement benefit expense by $13 million in the fourth quarter of 2004. Plan assets, expenses, and obligation for retirement plans in the following tables include both continuing and discontinued operations. We use a September 30 measure- ment date for our international plans and an October 31 measurement date for our domestic plans. Employer contributions Settlements and transfers Plan participants’ contributions Effect of business combinations and new plans Divestitures Currency fluctuations Benefits paid Fair value of plan assets at end of period Pension Benefits U.S. Int’l. U.S. Int’l. Other Postretirement Benefits 2004 2003 2004 2003 $113 $2,003 $113 $1,886 $ – $ – Plan assets Millions of dollars Change in plan assets Fair value of plan assets at beginning of period Actual return on plan assets 17 259 8 2 – 3 152 53 (33) – 9 – 17 12 – 13 – 13 8 – – 77 (8) 22 – – – (13) 9 – 304 (90) – – – (13) – (47) 43 (68) – – – (21) – – – (26) $125 $2,576 $113 $2,003 $ – $ – Our pension plan weighted-average asset allocations at December 31, 2004 and 2003 and the target allocations for 2005 by asset category are as follows: Target Allocation 2005 Percentage of Plan Assets at Year End Int’l. U.S. Int’l. U.S. 2004 2003 Benefit obligations Millions of dollars Change in benefit obligation Benefit obligation at beginning of period Service cost Interest cost Plan participants’ contributions Effect of business combinations and new plans Amendments Divestitures Settlements/ curtailments Currency fluctuations Actuarial gain/(loss) Benefits paid Benefit obligation at end of period Accumulated benefit obligation at end of period Pension Benefits U.S. Int’l. U.S. Int’l. Other Postretirement Benefits 2004 2003 2004 2003 $160 $2,501 92 155 1 10 $144 1 10 $2,239 72 120 $188 1 11 $186 1 12 – – – – – – 8 (13) 22 14 (1) – (9) 371 72 (90) – – – – – – 18 (13) 17 12 13 12 – (56) 4 54 107 (68) – – – – – (16) (21) – (7) – – – 9 (26) Asset category Equity securities Debt securities Real estate Other – STIF Total 55%-70% 30%-35% 0% 0%-5% 100% 63% 33% 0% 4% 100% 64% 34% 0% 2% 100% 45% 23% 0% 32% 100% 63% 34% 0% 3% 100% Our investment strategy varies by country depending on the circumstances of the underlying plan. Typically, less mature plan benefit obligations are funded by using more equity securities, as they are expected to achieve long-term growth while exceeding inflation. More mature plan benefit obligations are funded using more fixed income securities, as they are expected to produce current income with limited volatility. Risk management practices include the use of multiple asset classes and investment managers $166 $3,127 $160 $2,501 $175 $188 within each asset class for diversification purposes. Specific guidelines for each asset class and investment manager are $165 $2,451 $158 $2,230 $ – $ – implemented and monitored. 101 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Funded status recognized as either an intangible asset or a reduction of The funded status of the plans, reconciled to the amount shareholders’ equity. reported on the consolidated balance sheets, is as follows: The projected benefit obligation, accumulated benefit End of year in millions of dollars Fair value of plan assets at end of period Benefit obligation at end of period Funded status Employer contribution Unrecognized transition asset Unrecognized actuarial loss Unrecognized prior service cost (benefit) Purchase accounting adjustment Net amount recognized Pension Benefits U.S. Int’l. U.S. Int’l. Other Postretirement Benefits 2004 2003 2004 2003 $125 $2,576 $113 $2,003 $ – $ – 166 3,127 160 2,501 175 188 $(41) $ ( 551) $ (47) $ (498) $(175) $(188) – (1) 19 – – 5 (1) (1) 1 – 2 – obligation, and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets as of December 31, 2004 and 2003 are as follows: Millions of dollars Projected benefit obligation Accumulated benefit obligation Fair value of plan assets Expected cash flows Pension Benefits 2004 $1,942 $1,629 $1,503 2003 $2,630 $2,363 $2,087 Contributions. Funding requirements for each plan are 74 632 76 594 12 28 determined based on the local laws of the country where such plan resides. In certain countries the funding require- – – (3) (82) 1 – (1) (4) (4) ments are mandatory, while in other countries they are (77) – – discretionary. We currently expect to contribute $72 million to our international pension plans in 2005. For our domestic $ 32 $ 15 $ 29 $ 22 $(166) $(162) plans, we expect our contributions to be in the range of $1 million to $5 million in 2005. We do not have a required minimum contribution for our domestic plans; however, we may make additional discretionary contributions, which will be determined after the actuarial valuations are complete. Benefits Millions of dollars 2005 2006 2007 2008 2009 Years 2010-2014 Pension Benefits Other United States $12 13 12 10 11 $54 Int’l. $ 96 90 93 99 101 $573 Postretirement Benefits $17 16 16 16 16 $77 Amounts recognized in the consolidated balance sheets are as follows: Pension Benefits U.S. Int’l. U.S. Int’l. Other Postretirement Benefits End of year in millions of dollars 2004 2003 2004 2003 Amounts recognized in the consolidated $34 $103 $31 $ 95 $ – $ – balance sheets Prepaid benefit cost Accrued benefit liability including additional minimum liability (74) – Intangible asset Accumulated other comprehensive 47 income, net of tax Deferred tax asset 25 Net amount recognized $32 (214) 8 (76) – (361) 8 (166) – (162) – 83 35 $15 48 26 $29 197 83 $ 22 – – – – $(166) $(162) We reduced our additional minimum pension liability for the underfunded defined benefit plans of $164 million in 2004, of which $115 million was recorded as “Other comprehensive income.” We recognized an additional minimum pension liability of $107 million in 2003, of which $88 million was recorded as “Other comprehensive income.” The additional minimum liability is equal to the excess of the accumulated benefit obligation over plan assets and accrued liabilities. A corresponding amount is 102 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Net periodic cost End of year in Millions of dollars Components of net periodic benefit cost Service cost Interest cost Expected return on plan assets Transition amount Amortization of prior service cost Settlements/curtailments Recognized actuarial (gain) loss Net periodic benefit (income) cost Assumptions U.S. Int’l. U.S. Int’l. U.S. Int’l. Pension Benefits Other Postretirement Benefits 2004 2003 2002 2004 2003 2002 $1 10 (11) – – 1 3 $4 $92 155 (173) (1) – (2) 16 $87 $1 10 (12) – – 2 1 $2 $72 120 (136) (1) – – 18 $1 9 (13) – (2) – 1 $72 102 (106) (2) (6) (2) 3 $1 11 – – (1) – 1 $1 12 – – – – 1 $1 11 – – – – (1) $73 $(4) $61 $12 $14 $11 Assumed long-term rates of return on plan assets, discount rates for estimating benefit obligations, and rates of compen- sation increases vary for the different plans according to the local economic conditions. The rates used are as follows: Weighted-average assumptions used to determine benefit obligations at measurement date Discount rate Rate of compensation increase U.S. Int’l. U.S. Int’l. U.S. Int’l. Pension Benefits Other Postretirement Benefits 2004 2003 5.75% 2.5-8.0% 6.25% 2.5-9.0% 4.5% 2.0-5.0% 4.5% 2.0-6.5% 7.0% 4.5% 2002 5.25-7.5% 2004 5.75% 2003 6.25% 2002 7.0% 3.0-7.0% N/A N/A N/A Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31 Discount rate Expected return on plan assets Rate of compensation increase U.S. Int’l. U.S. Int’l. U.S. Int’l. Pension Benefits Other Postretirement Benefits 2004 2003 2002 6.25% 2.5-9.0% 7.0% 2.5-7.5% 7.25% 5.0-8.0% 2004 6.25% 2003 7.0% 2002 7.25% 8.5% 4.5% 5.25-7.5% 8.75% 5.5-8.0% 2.0-6.5% 4.5% 2.0-7.0% 9.0% 4.5% 5.5-9.0% N/A N/A N/A 3.0-7.0% N/A N/A N/A 103 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The weighted average assumptions for the Nigerian and segment. In January 2005, we completed the sale of Subsea Indonesian plans are not included in the above table as the 7, Inc. to our joint venture partner, Siem Offshore. plans are immaterial. Combined summarized financial information for all The overall expected long-term rate of return on assets jointly owned operations that are accounted for under the is determined based upon an evaluation of our plan assets, equity method is as follows: historical trends, and experience taking into account current and expected market conditions. Assumed health care cost trend rates at December 31 Health care cost trend rate assumed for next year Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) Year that the rate reached the 2004 2003 2002 11.5% 13.0% 13.0% 5.0% 5.0% 5.0% ultimate trend rate 2008 2008 2007 Assumed health care cost trend rates are not expected to have a significant impact on the amounts reported for the total of the health care plans. A one-percentage-point Combined Operating Results Millions of dollars Revenue Operating income Net income Combined Financial Position Millions of dollars Current assets Noncurrent assets Total Current liabilities Noncurrent liabilities Minority interests Shareholders’ equity Total Years ended December 31 2004 $3,388 $ (34) $ (58) 2003 $4,438 $ 263 $ 230 2002 $4,045 $ 450 $ 409 December 31 2004 $2,390 3,226 $5,616 $2,049 2,832 – 735 $5,616 2003 $2,542 3,054 $5,596 $2,361 2,277 3 955 $5,596 change in assumed health care cost trend rates would have The FASB issued FASB Interpretation No. 46, the following effects: Millions of dollars Effect on total of service and interest cost components Effect on the postretirement benefit obligation “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (FIN 46), in January 2003. In One Percentage Point Increase (Decrease) December 2003, the FASB issued FIN 46R, a revision which supersedes the original interpretation. We adopted $1 $9 $ – $(8) NOTE 20. RELATED COMPANIES We conduct some of our operations through joint ventures which are in partnership, corporate, and other business forms and are principally accounted for using the equity method. Financial information pertaining to related companies for our continuing operations is set out in the following tables. This information includes the total related- company balances and not our proportional interest in those balances. Our larger unconsolidated entities include Subsea 7, Inc., a 50%-owned subsidiary, formed in May 2002, whose results are reported in our Production Optimization segment, and the partnerships created to construct the Alice Springs to Darwin rail line in Australia, whose results are reported in our Government and Infrastructure 104 FIN 46R effective January 1, 2004. FIN 46R requires the consolidation of entities in which a company absorbs a majority of another entity’s expected losses, receives a majority of the other entity’s expected residual returns, or both, as a result of ownership, contrac- tual, or other financial interests in the other entity. Previously, entities were generally consolidated based upon a controlling financial interest through ownership of a majority voting interest in the entity. We have identified the following variable interest entities: – during the second quarter of 2001, we formed a joint venture, WellDynamics, with Shell in which we held a 50% equity interest and accounted for the investment using the equity method in our Digital and Consulting Solutions segment. The joint venture was established for the further development and deployment of new technologies related to completions and well interven- tion products and services. In the first quarter of 2004, HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Halliburton and Shell restructured WellDynamics operate, and maintain roadways for certain govern- whereby Halliburton acquired an additional 1% of ment agencies in the United Kingdom. We have a 25% WellDynamics from Shell, giving Halliburton 51% ownership interest in these joint ventures and account ownership and control of day-to-day operations. The for them under the equity method. These joint joint venture is considered a variable interest entity ventures are considered variable interest entities as under FIN 46, and we have determined that we are the they were initially formed with little equity contributed primary beneficiary of the entity. Beginning in the first by the partners. The joint ventures have obtained quarter of 2004, WellDynamics was consolidated and financing through third parties that is not guaranteed included in our Production Optimization segment. The by us. We are not the primary beneficiary of these consolidation of WellDynamics resulted in an increase joint ventures and will, therefore, continue to account to our goodwill of $109 million, which was previously for them using the equity method. As of December 31, carried as equity method goodwill in our investment 2004, these joint ventures had total assets of $1.5 balance, and an increase in long-term debt of $27 billion and total liabilities of $1.4 billion. Our maxi- million. There are no assets of WellDynamics that mum exposure to loss is limited to our equity collateralize its obligations; investments in and loans to the joint ventures, which – during 2001, we formed a joint venture which owns totaled $42 million at December 31, 2004, and our and operates heavy equipment transport vehicles in share of any future losses to the construction of these the United Kingdom in which we own a 50% equity roadways. interest with two unrelated partners, each owning a 25% equity interest. This variable interest entity was formed to construct, operate, and service certain assets for a third party, and was funded with third- party debt. The construction of the assets was completed in the second quarter of 2004, and the operating and service contract related to the assets extends through 2023. The proceeds from the debt NOTE 21. REORGANIZATION OF BUSINESS OPERATIONS Effective October 1, 2004, we restructured KBR into two segments, Government and Infrastructure and Energy and Chemicals. In 2004, we recorded restructuring and related costs of $40 million related to the reorganization. The total restructuring charges consist of $31 million in personnel termination benefits and $9 million in impairment charges financing were used to construct the assets and will be on technology-related assets. For the year ended December paid down with cash flows generated during the operation and service phase of the contract with the 31, 2004, $32 million of the restructuring charge was included in “Cost of services” and $8 million was included third party. As of December 31, 2004, the joint venture in “General and administrative” on the consolidated had total assets of $174 million and total liabilities of $175 million. Our aggregate exposure to loss as a statements of operations. As of December 31, 2004, $19 million had not been paid and is included in “Other current result of our involvement with this joint venture is liabilities.” limited to our equity investment and subordinated Now that we have resolved our asbestos and silica debt of $12 million and any future losses related to the liability and our affected subsidiaries have exited Chapter operation of the assets. We are not the primary beneficiary. The joint venture is accounted for under the equity method of accounting in our Government and Infrastructure segment; and – we are involved in three privately funded initiatives executed through joint ventures to design, build, 11 reorganization proceedings, we intend to separate KBR from Halliburton, which could include a transaction involving a spin-off, split-off, public offering, or sale of KBR or its operations. In order to maximize KBR’s value for our shareholders, and to determine the most appropriate form 105 HALLIBURTON COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS of the transaction and its components, it may be necessary for KBR to establish a track record of positive earnings for a number of quarters and to seek resolution of governmen- tal issues, investigations, and other disputes. On March 18, 2002, we announced plans to restructure our businesses into two operating subsidiary groups, the Energy Services Group and KBR. As part of this reorgani- zation, we separated and consolidated the entities in our Energy Services Group together as direct and indirect subsidiaries of Halliburton Energy Services, Inc. We also separated and consolidated the entities in KBR together as direct and indirect subsidiaries of the former Dresser Industries, Inc., which became a limited liability company during the second quarter of 2002 and was renamed DII Industries, LLC. The reorganization of subsidiaries facilitated the separation of our business groups, organiza- tionally and financially, which we believe will significantly improve operating efficiencies in both, while streamlining management and easing manpower requirements. In addition, many support functions, which were previously shared, were moved into the two business groups. As a result, we took actions during 2002 to reduce our cost structure by reducing personnel, moving previously shared support functions into the two business groups, and realigning ownership of international subsidiaries by group. In 2002, we incurred costs related to the restructuring of approximately $107 million which consisted of the following: – $64 million in personnel-related expense; – $17 million of asset-related write-downs; – $20 million in professional fees related to the restruc- turing; and – $6 million related to contract terminations. As of December 31, 2004, all amounts related to the 2002 restructuring have been paid and the balance in the restructuring reserve account has been reduced to zero. 106 HALLIBURTON COMPANY SELECTED FINANCIAL DATA (UNAUDITED) Millions of dollars and shares except per share and employee data Total revenue Total operating income (loss) Nonoperating expense, net Income (loss) from continuing operations before income taxes and minority interest Provision for income taxes Minority interest in net income of consolidated subsidiaries Income (loss) from continuing operations Income (loss) from discontinued operations Net income (loss) Basic income (loss) per share Continuing operations Net income (loss) Diluted income (loss) per share Continuing operations Net income (loss) Cash dividends per share Return on average shareholders’ equity Financial position Net working capital Total assets Property, plant, and equipment, net Long-term debt (including current maturities) Shareholders’ equity Total capitalization Shareholders’ equity per share Average common shares outstanding (basic) Average common shares outstanding (diluted) Other financial data Capital expenditures Long-term borrowings (repayments), net Depreciation, depletion, and amortization expense Goodwill amortization included in depreciation, depletion, and amortization expense Payroll and employee benefits Number of employees 2004 $20,466 837 (186) 651 (241) (25) $ 385 $ (1,364) $ (979) $ 0.88 (2.25) Ye a r s e n d e d D e c e m b e r 3 1 2002 $12,572 (112) (116) 2003 $ 16,271 720 (108) 2001 $13,046 1,084 (130) 2000 $11,944 462 (127) 612 (234) (39) $ 339 $ (1,151) $ (820) $ 0.78 (1.89) (228) (80) (38) $ (346) $ (652) $ (998) $ (0.80) (2.31) 954 (384) 335 (129) (19) (18) $ 551 $ 257 $ 809 $ 1.29 1.89 $ 188 $ 313 $ 501 $ 0.42 1.13 0.87 (2.22) 0.50 (30.22)% 0.78 (1.88) 0.50 (26.86)% (0.80) (2.31) 0.50 (24.02)% 1.28 1.88 0.50 18.64% 0.42 1.12 0.50 12.20% $ 2,898 15,796 2,553 3,940 3,932 7,887 8.90 437 441 $ (575) 476 509 – (5,608) 97,000 $ 1,355 15,499 2,526 3,437 2,547 6,002 5.80 434 437 $ (515) 1,896 518 – (5,154) 101,000 $ 2,288 12,844 2,629 1,476 3,558 5,083 8.16 432 432 $ (764) (15) 505 – (4,875) 83,000 $ 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 $ (797) 412 531 $ (578) (308) 503 42 (4,818) 85,000 44 (5,260) 93,000 107 HALLIBURTON COMPANY QUARTERLY DATA AND MARKET PRICE INFORMATION (UNAUDITED) Millions of dollars except per share data 2 0 0 4 Revenue Operating income (loss) Income (loss) from continuing operations Loss from discontinued operations Net loss Earnings per share: Basic income (loss) per share: Income (loss) from continuing operations Loss from discontinued operations Net loss Diluted income (loss) per share: Income (loss) from continuing operations Loss from discontinued operations Net loss Cash dividends paid per share Common stock prices (1) High Low 2003 Revenue Operating income Income from continuing operations Loss from discontinued operations Cumulative effect of change in accounting principle, net of tax benefit of $5 Net income (loss) Earnings per share: Basic income (loss) per share: Income from continuing operations Loss from discontinued operations Cumulative effect of change in accounting principle, net of tax benefit Net income (loss) Diluted income (loss) per share: Income from continuing operations Loss from discontinued operations Cumulative effect of change in accounting principle, net of tax benefit Net income (loss) Cash dividends paid per share Common stock prices (1) High Low (1) New York Stock Exchange – composite transactions high and low intraday price. First Second Third Fourth Year Q u a r t e r $5,519 175 76 (141) (65) 0.17 (0.32) (0.15) 0.17 (0.32) (0.15) 0.125 32.70 25.80 $3,060 142 59 (8) (8) 43 0.14 (0.02) (0.02) 0.10 0.14 (0.02) (0.02) 0.10 0.125 21.79 17.20 $4,956 (26) (58) (609) (667) (0.13) (1.39) (1.52) (0.13) (1.39) (1.52) 0.125 32.35 27.35 $3,599 71 42 (16) – 26 0.09 (0.03) – 0.06 0.09 (0.03) – 0.06 0.125 24.97 19.98 $4,790 342 186 (230) (44) 0.43 (0.54) (0.11) 0.42 (0.51) (0.09) 0.125 33.98 26.45 $4,148 204 92 (34) – 58 0.21 (0.08) – 0.13 0.21 (0.08) – 0.13 0.125 25.90 20.50 $5,201 346 181 (384) (203) 0.41 (0.88) (0.47) 0.40 (0.86) (0.46) 0.125 41.69 33.08 $5,464 303 146 (1,093) – (947) 0.34 (2.52) – (2.18) 0.34 (2.51) – (2.17) 0.125 27.20 22.80 $20,466 837 385 (1,364) (979) 0.88 (3.13) (2.25) 0.87 (3.09) (2.22) 0.50 41.69 25.80 $16,271 720 339 (1,151) (8) (820) 0.78 (2.65) (0.02) (1.89) 0.78 (2.64) (0.02) (1.88) 0.50 27.20 17.20 108 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT. ITEM 12(B). SECURITY OWNERSHIP OF MANAGEMENT. This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2005 Annual The information required for the directors of the Meeting of Stockholders (File No. 1-3492) under the Registrant is incorporated by reference to the Halliburton caption “Stock Ownership of Certain Beneficial Owners and Company Proxy Statement for our 2005 Annual Meeting of Management.” Stockholders (File No. 1-3492), under the caption “Election of Directors.” The information required for the executive officers of the Registrant is included under Part I on pages ITEM 12(C). CHANGES IN CONTROL. Not applicable. 8 and 9 of this annual report. Audit Committee Financial Expert In the business judgment of the Board of Directors, all five members of the Audit Committee, Robert L. Crandall, Kenneth T. Derr, W. R. Howell, J. Landis Martin, and C. J. Silas, are independent and have accounting or related financial management experience required under the listing standards and have been designated by the Board of ITEM 12(D). SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS. This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2005 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Equity Compensation Plan Information.” ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. Directors as “audit committee financial experts.” This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2005 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Certain Relationships and Related Transactions” to the extent any disclosure is required. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES. This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2005 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Fees Paid to KPMG LLP.” ITEM 11. EXECUTIVE COMPENSATION. This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2005 Annual Meeting of Stockholders (File No. 1-3492) under the captions “Compensation Committee Report on Executive Compensation,” “Comparison of Cumulative Total Return,” “Summary Compensation Table,” “Option Grants for Fiscal 2004,” “Aggregated Option Exercises in Fiscal 2004 and December 31, 2004 Option Values,” “Long-term Incentive Plans – Awards in Fiscal 2004,” “Employment Contracts and Change-in-Control Arrangements,” and “Directors’ Compensation.” ITEM 12(A). SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS. This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2005 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Stock Ownership of Certain Beneficial Owners and Management.” 109 PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES. (a) 1. Financial Statements: The reports of the Independent Registered Public Accounting Firm and the financial statements of the Company as required by Part II, Item 8, are included on pages 56 and 57 and pages 58 through 106 of this annual report. See index on page 10. for Mid-Valley, Inc., DII Industries, LLC, Kellogg Brown & Root, Inc., KBR Technical Services, Inc., Kellogg Brown & Root Engineering Corporation, Kellogg Brown & Root International, Inc. (a Delaware corporation), Kellogg Brown & Root International, Inc. (a Panamanian corporation), and BPM Minerals, LLC under Chapter 11 of the United States Bankruptcy Code dated November 14, 2003 (incorporated by reference to Exhibit 99 to Halliburton’s Form 8-K dated as of November 19, 2. Financial Statement Schedules: Page No. 2003, File No. 1-3492). Report on supplemental schedule 3.1 Restated Certificate of Incorporation of Halliburton of KPMG LLP Schedule II – Valuation and qualifying accounts for the three years ended December 31, 2004 117 118 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 2.1 Disclosure Statement for the Proposed Joint Pre- packaged Plan of Reorganization for Mid-Valley, Inc., DII Industries, LLC, Kellogg Brown & Root, Inc., KBR Technical Services, Inc., Kellogg Brown & Root Engineering Corporation, Kellogg Brown & Root International, Inc. (a Delaware corporation), Kellogg Brown & Root International, Inc. (a Panamanian corporation), and BPM Minerals, LLC under Chapter 11 of the United States Bankruptcy Code dated September 18, 2003 (incorporated by reference to Exhibit 99 to Halliburton’s Form 8-K dated as of September 22, 2003, File No. 1-3492). Company filed with the Secretary of State of Delaware on May 21, 2004 (incorporated by reference to Exhibit 3.1 to Halliburton’s Registration Statement on Form S-4 filed on July 19, 2004, Registration No. 333-112977). 3.2 By-laws of Halliburton revised effective February 12, 2003 (incorporated by reference to Exhibit 3.2 to Halliburton’s Form 10-K for the year ended December 31, 2002, File No. 1-3492). 4.1 Form of debt security of 8.75% Debentures due February 12, 2021 (incorporated by reference to Exhibit 4(a) to the Form 8-K of Halliburton Company, now known as Halliburton Energy Services, Inc. (the Predecessor) dated as of February 20, 1991, File No. 1-3492). 4.2 Senior Indenture dated as of January 2, 1991 between the Predecessor and Texas Commerce Bank National Association, as Trustee (incorpo- rated by reference to Exhibit 4(b) to the Predecessor’s Registration Statement on Form S-3 (Registration No. 33-38394) originally filed with the Securities and Exchange Commission on December 21, 1990), as supplemented and amended by the First Supplemental Indenture dated as of December 12, 1996 among the Predecessor, Halliburton and the Trustee (incorporated by reference to Exhibit 4.1 of Halliburton’s Registration Statement on Form 8-B dated December 12, 1996, File No. 1-3492). 2.2 Supplemental Disclosure Statement for First Amended Joint Pre-packaged Plan of Reorganization 4.3 Resolutions of the Predecessor’s Board of Directors adopted at a meeting held on February 11, 1991 and of the special pricing committee of the Board of 110 Directors of the Predecessor adopted at a meeting 4.9 Resolutions of Halliburton’s Board of Directors held on February 11, 1991 and the special pricing adopted at a special meeting held on September 28, committee’s consent in lieu of meeting dated 1998 (incorporated by reference to Exhibit 4.10 to February 12, 1991 (incorporated by reference to Halliburton’s Form 10-K for the year ended Exhibit 4(c) to the Predecessor’s Form 8-K dated as December 31, 1998, File No. 1-3492). of February 20, 1991, File No. 1-3492). 4.10 Restated Rights Agreement dated as of December 1, 4.4 Second Senior Indenture dated as of December 1, 1996 between Halliburton and Mellon Investor 1996 between the Predecessor and Texas Services LLC (formerly ChaseMellon Shareholder Commerce Bank National Association, as Trustee, Services, L.L.C.) (incorporated by reference to as supplemented and amended by the First Exhibit 4.4 of Halliburton’s Registration Statement Supplemental Indenture dated as of December 5, on Form 8-B dated December 12, 1996, File 1996 between the Predecessor and the Trustee and No. 1-3492). the Second Supplemental Indenture dated as of 4.11 Copies of instruments that define the rights of December 12, 1996 among the Predecessor, holders of miscellaneous long-term notes of Halliburton and the Trustee (incorporated by Halliburton and its subsidiaries, totaling $12 million reference to Exhibit 4.2 of Halliburton’s in the aggregate at December 31, 2004, have not Registration Statement on Form 8-B dated been filed with the Commission. Halliburton agrees December 12, 1996, File No. 1-3492). to furnish copies of these instruments upon request. 4.5 Third Supplemental Indenture dated as of August 1, 4.12 Form of debt security of 7.53% Notes due May 12, 1997 between Halliburton and Texas Commerce 2017 (incorporated by reference to Exhibit 4.4 to Bank National Association, as Trustee, to the Halliburton’s Form 10-Q for the quarter ended Second Senior Indenture dated as of December 1, March 31, 1997, File No. 1-3492). 1996 (incorporated by reference to Exhibit 4.7 to 4.13 Form of debt security of 5.63% Notes due December Halliburton’s Form 10-K for the year ended 1, 2008 (incorporated by reference to Exhibit 4.1 to December 31, 1998, File No. 1-3492). Halliburton’s Form 8-K dated as of November 24, 4.6 Fourth Supplemental Indenture dated as of 1998, File No. 1-3492). September 29, 1998 between Halliburton and Chase 4.14 Form of Indenture, between Dresser and Texas Bank of Texas, National Association (formerly Commerce Bank National Association, as Trustee, Texas Commerce Bank National Association), as for 7.60% Debentures due 2096 (incorporated by Trustee, to the Second Senior Indenture dated as of reference to Exhibit 4 to the Registration Statement December 1, 1996 (incorporated by reference to on Form S-3 filed by Dresser as amended, Exhibit 4.8 to Halliburton’s Form 10-K for the year Registration No. 333-01303), as supplemented and ended December 31, 1998, File No. 1-3492). amended by Form of Supplemental Indenture, 4.7 Resolutions of Halliburton’s Board of Directors between Dresser and Texas Commerce Bank adopted by unanimous consent dated December 5, National Association, Trustee, for 7.60% Debentures 1996 (incorporated by reference to Exhibit 4(g) of due 2096 (incorporated by reference to Exhibit 4.1 Halliburton’s Form 10-K for the year ended to Dresser’s Form 8-K filed on August 9, 1996, File December 31, 1996, File No. 1-3492). No. 1-4003). 4.8 Form of debt security of 6.75% Notes due February 4.15 Second Supplemental Indenture dated as of October 1, 2027 (incorporated by reference to Exhibit 4.1 to 27, 2003 between DII Industries, LLC and Halliburton’s Form 8-K dated as of February 11, JPMorgan Chase Bank, as Trustee, to the Indenture 1997, File No. 1-3492). dated as of April 18, 1996, as supplemented by the First Supplemental Indenture dated as of August 6, 111 1996 (incorporated by reference to Exhibit 4.15 to 4.22 First Supplemental Indenture dated as of December Halliburton’s Form 10-K for the year ended 17, 2004 between Halliburton and JPMorgan Chase December 31, 2003, File No. 1-3492). Bank, National Association (formerly JPMorgan 4.16 Third Supplemental Indenture dated as of Chase Bank), as trustee, to Indenture dated as of December 12, 2003 among DII Industries, LLC, June 30, 2003, between Halliburton and JPMorgan Halliburton and JPMorgan Chase Bank, as Trustee, Chase Bank, National Association (formerly to the Indenture dated as of April 18, 1996, as JPMorgan Chase Bank), as trustee (incorporated by supplemented by the First Supplemental Indenture reference to Exhibit 4.1 to Halliburton’s Form 8-K dated as of August 6, 1996 and the Second filed on December 21, 2004, File No. 1-3492). Supplemental Indenture dated as of October 27, 4.23 Senior Indenture dated as of October 17, 2003 2003 (incorporated by reference to Exhibit 4.16 to between Halliburton and JPMorgan Chase Bank, as Halliburton’s Form 10-K for the year ended Trustee (incorporated by reference to Exhibit 4.1 to December 31, 2003, File No. 1-3492). Halliburton’s Form 10-Q for the quarter ended 4.17 Form of debt security of 6% Notes due August 1, September 30, 2003, File No. 1-3492). 2006 (incorporated by reference to Exhibit 4.2 to 4.24 First Supplemental Indenture dated as of October Halliburton’s Form 8-K dated January 8, 2002, File 17, 2003 between Halliburton and JPMorgan Chase No. 1-3492). Bank, as Trustee, to the Senior Indenture dated as 4.18 Credit Facility in the amount of £80 million dated of October 17, 2003 (incorporated by reference to November 29, 2002 between Devonport Royal Exhibit 4.2 to Halliburton’s Form 10-Q for the Dockyard Limited and Devonport Management quarter ended September 30, 2003, File No. 1-3492). Limited and The Governor and Company of the 4.25 Form of note of floating-rate senior notes due Bank of Scotland, HSBC Bank Plc and The Royal October 17, 2005 (included as Exhibit A to Bank of Scotland Plc (incorporated by reference to Exhibit 4.24 above). Exhibit 4.22 to Halliburton’s Form 10-K for the year 4.26 Form of note of 5.5% senior notes due October 15, ended December 31, 2002, File No. 1-3492). 2010 (included as Exhibit B to Exhibit 4.24 above). 4.19 Senior Indenture dated as of June 30, 2003 between 4.27 Registration Rights Agreement dated as of October Halliburton and JPMorgan Chase Bank, as Trustee 17, 2003 among Halliburton and J.P. Morgan (incorporated by reference to Exhibit 4.1 to Securities Inc., Citigroup Global Markets, Inc. and Halliburton’s Form 10-Q for the quarter ended June Goldman, Sachs & Co., as representatives of the 30, 2003, File No. 1-3492). several Purchasers named in Schedule I of the 4.20 Form of note of 3.125% Convertible Senior Notes Purchase Agreement dated as of October 14, 2003 due July 15, 2023 (included as Exhibit A to Exhibit (incorporated by reference to Exhibit 4.5 to 4.19 above). Halliburton’s Registration Statement on Form S-4, 4.21 Registration Rights Agreement dated as of June 30, Registration No. 333-110420). 2003 among Halliburton and Citigroup Global 4.28 Second Supplemental Indenture dated as of Markets, Inc., Goldman, Sachs & Co. and J.P. December 15, 2003 between Halliburton and Morgan Securities Inc., as representatives of the JPMorgan Chase Bank, as Trustee, to the Senior several Purchasers named in Schedule I of the Indenture dated as of October 17, 2003, as supple- Purchase Agreement dated as of June 24, 2003 mented by the First Supplemental Indenture dated (incorporated by reference to Exhibit 4.3 to as of October 17, 2003 (incorporated by reference to Halliburton’s Registration Statement on Form S-3, Exhibit 4.27 to Halliburton’s Form 10-K for the year Registration No. 333-110035). ended December 31, 2003, File No. 1-3492). 112 4.29 Form of note of 7.6% debentures due 2096 (included Form 10-K for the year ended December 31, 2000, as Exhibit A to Exhibit 4.28 above). File No. 1-3492). 4.30 Third Supplemental Indenture dated as of January 10.4 Halliburton Company 1993 Stock and Incentive 26, 2004 between Halliburton and JPMorgan Chase Plan, as amended and restated effective May 18, Bank, as Trustee, to the Senior Indenture dated as 2004 (incorporated by reference to Exhibit 10.5 to of October 17, 2003, as supplemented by the First Halliburton’s Form 10-Q for the quarter ended June Supplemental Indenture dated as of October 17, 30, 2004, File No. 1-3492). 2003 and the Second Supplemental Indenture 10.5 Halliburton Company Restricted Stock Plan for dated as of December 15, 2003 (incorporated Non-Employee Directors (incorporated by refer- by reference to Exhibit 4.2 to Halliburton’s ence to Appendix B of the Predecessor’s proxy Registration Statement on Form S-4, Registration statement dated March 23, 1993, File No. 1-3492). No. 333-112977). 10.6 Dresser Industries, Inc. Deferred Compensation 4.31 Form of Senior Notes due 2007 (included as Exhibit Plan, as amended and restated effective January 1, A to Exhibit 4.30 above). 2000 (incorporated by reference to Exhibit 10.16 to 4.32 Registration Rights Agreement dated as of January Halliburton’s Form 10-K for the year ended 26, 2004 among Halliburton and J.P. Morgan December 31, 2000, File No. 1-3492). Securities Inc., Citigroup Global Markets, Inc. and 10.7 Dresser Industries, Inc. 1982 Stock Option Plan Goldman, Sachs & Co., as representatives of the (incorporated by reference to Exhibit A to several Purchasers named in Schedule I of the Dresser’s Proxy Statement dated February 12, Purchase Agreement dated as of January 21, 2004 1982, File No. 1-4003). (incorporated by reference to Exhibit 4.4 to 10.8 ERISA Excess Benefit Plan for Dresser Industries, Halliburton’s Registration Statement on Form S-4, Inc., as amended and restated effective June 1, 1995 Registration No. 333-112977). (incorporated by reference to Exhibit 10.7 to 4.33 Stockholder Agreement between Halliburton and Dresser’s Form 10-K for the year ended October 31, the DII Industries, LLC Asbestos PI Trust dated 1995, File No. 1-4003). January 20, 2005 (incorporated by reference to 10.9 ERISA Compensation Limit Benefit Plan for Dresser Exhibit 10.1 to Halliburton’s Form 8-K filed January Industries, Inc., as amended and restated effective 25, 2005, File No. 1-3492). June 1, 1995 (incorporated by reference to Exhibit 10.1 Halliburton Company Career Executive Incentive 10.8 to Dresser’s Form 10-K for the year ended Stock Plan as amended November 15, 1990 (incor- October 31, 1995, File No. 1-4003). porated by reference to Exhibit 10(a) to the 10.10 Supplemental Executive Retirement Plan of Dresser Predecessor’s Form 10-K for the year ended Industries, Inc., as amended and restated effective December 31, 1992, File No. 1-3492). January 1, 1998 (incorporated by reference to 10.2 Retirement Plan for the Directors of Halliburton Exhibit 10.9 to Dresser’s Form 10-K for the year Company, as amended and restated effective May ended October 31, 1997, File No. 1-4003). 16, 2000 (incorporated by reference to Exhibit 10.2 10.11 Amendment No. 1 to the Supplemental Executive to Halliburton’s Form 10-Q for the quarter ended Retirement Plan of Dresser Industries, Inc. (incor- September 30, 2000, File No. 1-3492). porated by reference to Exhibit 10.1 to Dresser’s 10.3 Halliburton Company Directors’ Deferred Form 10-Q for the quarter ended April 30, 1998, File Compensation Plan as amended and restated No. 1-4003). effective February 1, 2001 (incorporated by 10.12 Stock Based Compensation Arrangement of Non- reference to Exhibit 10.3 to Halliburton’s Employee Directors (incorporated by reference to 113 Exhibit 4.4 to Dresser’s Registration Statement on 10.21 Halliburton Company Benefit Restoration Plan, as Form S-8, Registration No. 333-40829). amended and restated effective January 1, 2004 10.13 Dresser Industries, Inc. Deferred Compensation (incorporated by reference to Exhibit 10.2 to Plan for Non-Employee Directors, as restated Halliburton’s Form 10-Q for the quarter ended and amended effective November 1, 1997 (incorpo- September 30, 2004, File No. 1-3492). rated by reference to Exhibit 4.5 to Dresser’s 10.22 Halliburton Annual Performance Pay Plan, as Registration Statement on Form S-8, Registration amended and restated effective January 1, 2001 No. 333-40829). (incorporated by reference to Exhibit 10.1 to 10.14 Long-Term Performance Plan for Selected Halliburton’s Form 10-Q for the quarter ended Employees of The M. W. Kellogg Company, as September 30, 2001, File No. 1-3492). amended and restated effective September 1, 1999 10.23 Halliburton Company Performance Unit Program (incorporated by reference to Exhibit 10.23 to (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 10-K for the year ended Halliburton’s Form 10-Q for the quarter ended December 31, 2000, File No. 1-3492). September 30, 2001, File No. 1-3492). 10.15 Dresser Industries, Inc. 1992 Stock Compensation 10.24 Form of Nonstatutory Stock Option Agreement for Plan (incorporated by reference to Exhibit A to Non-Employee Directors (incorporated by refer- Dresser’s Proxy Statement dated February 7, 1992, ence to Exhibit 10.3 to Halliburton’s Form 10-Q File No. 1-4003). for the quarter ended September 30, 2000, 10.16 Amendments No. 1 and 2 to Dresser Industries, Inc. File No. 1-3492). 1992 Stock Compensation Plan (incorporated by 10.25 Halliburton Elective Deferral Plan as amended and reference to Exhibit A to Dresser’s Proxy Statement restated effective May 1, 2002 (incorporated dated February 6, 1995, File No. 1-4003). by reference to Exhibit 10.1 to Halliburton’s 10.17 Amendment No. 3 to the Dresser Industries, Inc. Form 10-Q for the quarter ended June 30, 2002, 1992 Stock Compensation Plan (incorporated File No. 1-3492). by reference to Exhibit 10.25 to Dresser’s 10.26 Halliburton Company 2002 Employee Stock Form 10-K for the year ended October 31, 1997, Purchase Plan, as amended and restated September File No. 1-4003). 9, 2004 (incorporated by reference to Exhibit 10.1 to 10.18 Employment Agreement (David J. Lesar) (incorpo- Halliburton’s Form 10-Q for the quarter ended rated by reference to Exhibit 10(n) to the September 30, 2004, File No. 1-3492). Predecessor’s Form 10-K for the year ended 10.27 Halliburton Company Directors’ Deferred December 31, 1995, File No. 1-3492). Compensation Plan as amended and restated 10.19 Employment Agreement (Mark A. McCollum) effective as of October 22, 2002 (incorporated by (incorporated by reference to Exhibit 10.1 to reference to Exhibit 10.1 to Halliburton’s Halliburton’s Form 10-Q for the quarter ended Form 10-Q for the quarter ended September 30, September 30, 2003, File No. 1-3492). 2002, File No. 1-3492). 10.20 Halliburton Company Supplemental Executive 10.28 Employment Agreement (Albert O. Cornelison) Retirement Plan (formerly part of Halliburton (incorporated by reference to Exhibit 10.3 to Company Senior Executives’ Deferred Halliburton’s Form 10-Q for the quarter ended June Compensation Plan), as amended and restated 30, 2002, File No. 1-3492). effective January 1, 2001 (incorporated by reference 10.29 Employment Agreement (Weldon J. Mire) (incorpo- to Exhibit 10.1 to Halliburton’s Form 10-Q for the rated by reference to Exhibit 10.4 to Halliburton’s quarter ended June 30, 2001, File No. 1-3492). Form 10-Q for the quarter ended June 30, 2002, File No. 1-3492). 114 10.30 Employment Agreement (David R. Smith) (incorpo- North America, Inc., as Administrative Agent, rated by reference to Exhibit 10.39 to Halliburton’s JPMorgan Chase Bank, as Syndication Agent, and Form 10-K for the year ended December 31, 2002, ABN AMRO Bank N.V., as Documentation Agent File No. 1-3492). (incorporated by reference to Exhibit 10.3 to 10.31 Employment Agreement (John W. Gibson) (incorpo- Halliburton’s Form 10-Q for the quarter ended rated by reference to Exhibit 10.40 to Halliburton’s September 30, 2003, File No. 1-3492). Form 10-K for the year ended December 31, 2002, 10.37 Amendment No. 1 dated as of May 10, 2004 to File No. 1-3492). Master Letter of Credit Facility Agreement, dated as 10.32 Employment Agreement (C. Christopher Gaut) of October 31, 2003, among Halliburton, Kellogg (incorporated by reference to Exhibit 10.1 to Brown & Root, Inc., and DII Industries, LLC, as Halliburton’s Form 10-Q for the quarter ended Account Parties, the Banks party thereto, and March 31, 2003, File No. 1-3492). Citicorp North America, Inc., as Administrative 10.33 3-Year Revolving Credit Agreement, dated as of Agent, JPMorgan Chase Bank, as Syndication October 31, 2003, among Halliburton, the Banks Agent, and ABN AMRO Bank N.V., as party thereto, Citicorp North America, Inc., as Documentation Agent, as amended (incorporated Administrative Agent, JPMorgan Chase Bank, as by reference to Exhibit 10.4 of Halliburton’s Syndication Agent, and ABN AMRO Bank N.V., as Registration Statement on Form S-4 filed on June 3, Documentation Agent (incorporated by reference to 2004, Registration No. 333-112977). Exhibit 10.2 to Halliburton’s Form 10-Q for the 10.38 Amendment No. 2 dated as of July 14, 2004 to the quarter ended September 30, 2003, File No. 1-3492). Master Letter of Credit Facility Agreement, dated as 10.34 Amendment No. 1 dated as of July 14, 2004 to the 3- of October 31, 2003, among Halliburton, Kellogg Year Revolving Credit Agreement, dated as of Brown & Root, Inc., and DII Industries, LLC, as October 31, 2003, among Halliburton, the Banks Account Parties, the Banks party thereto, Citicorp party thereto, Citicorp North America, Inc., as North America, Inc., as Administrative Agent, Administrative Agent, JPMorgan Chase Bank, as JPMorgan Chase Bank, as Syndication Agent, and Syndication Agent, and ABN AMRO Bank N.V., as ABN AMRO Bank N.V., as Documentation Agent, Documentation Agent (incorporated by reference to as amended (incorporated by reference to Exhibit Exhibit 10.1(a) of Halliburton’s Registration 10.2(a) of Halliburton’s Registration Statement on Statement on Form S-4 filed on July 19, 2004, Form S-4 filed on July 19, 2004, Registration Registration No. 333-112977). No. 333-112977). 10.35 Amendment No. 2 to 3-Year Revolving Credit 10.39 Amendment No. 3 to the Master Letter of Credit Agreement dated as of October 31, 2003, as Facility Agreement dated as of October 31, 2003 amended, among Halliburton, the Banks party among Halliburton, certain subsidiaries of thereto, Citicorp North America, Inc., as Halliburton, the Banks party thereto, Citicorp Administrative Agent, JPMorgan Chase Bank, as North America, Inc., as Administrative Agent, Syndication Agent, and ABN AMRO Bank N.V., as JPMorgan Chase Bank, as Syndication Agent, and Documentation Agent (incorporated by reference to ABN AMRO Bank, N.V., as Documentation Agent Exhibit 10.2 to Halliburton’s Form 8-K filed (incorporated by reference to Exhibit 10.1 to December 30, 2004, File No. 1-3492). Halliburton’s Form 8-K filed December 15, 2004, 10.36 Master Letter of Credit Facility Agreement, dated as File No. 1-3492). of October 31, 2003, among Halliburton, Kellogg 10.40 Amendment No. 4 to the Master Letter of Credit Brown & Root, Inc., and DII Industries, LLC, as Facility Agreement dated as of October 31, 2003, as Account Parties, the Banks party thereto, Citicorp amended, among Halliburton, certain subsidiaries 115 of Halliburton, the Banks party thereto, Citicorp 12* Statement of Computation of Ratio of Earnings to North America, Inc., as Administrative Agent, Fixed Charges. JPMorgan Chase Bank, as Syndication Agent, and 21* Subsidiaries of the Registrant. ABN AMRO Bank, N.V., as Documentation Agent 23.1* Consent of KPMG LLP. (incorporated by reference to Exhibit 10.1 to 24.1 Powers of attorney for the following directors Halliburton’s Form 8-K filed December 30, 2004, signed in January 2004 (incorporated by reference File No. 1-3492). to Exhibit 24.1 to Halliburton’s Form 10-K for the 10.41 Senior Unsecured Credit Facility Agreement, dated year ended December 31, 2003, File No. 1-3492): as of November 4, 2003, among Halliburton, the Banks party thereto, Citicorp North America, Inc., as Administrative Agent, JPMorgan Chase Bank, as Syndication Agent, and ABN AMRO Bank N.V., as Documentation Agent (incorporated by reference to Exhibit 10.4 to Halliburton’s Form 10-Q for the quarter ended September 30, 2003, File No. 1-3492). 10.42 364-Day Revolving Credit Agreement, dated as of July 14, 2004, among Halliburton, the Issuing Banks and Banks party thereto, Citicorp North America, Robert L. Crandall Kenneth T. Derr Charles J. DiBona W. R. Howell Ray L. Hunt Aylwin B. Lewis J. Landis Martin Jay A. Precourt Debra L. Reed C. J. Silas Inc., as Paying Agent and as Co-Administrative 31.1* Certification of Chief Executive Officer pursuant to Agent, JPMorgan Chase Bank, as Co-Administrative Section 302 of the Sarbanes-Oxley Act of 2002. Agent, ABN AMRO Bank N.V., as Syndication 31.2* Certification of Chief Financial Officer pursuant to Agent, and HSBC Bank USA, National Association Section 302 of the Sarbanes-Oxley Act of 2002. and The Royal Bank of Scotland plc, as Co- 32.1** Certification of Chief Executive Officer pursuant to Documentation Agents (incorporated by reference Section 906 of the Sarbanes-Oxley Act of 2002. to Exhibit 10.3 of Halliburton’s Registration 32.2** Certification of Chief Financial Officer pursuant to Statement on Form S-4 filed on July 19, 2004, Section 906 of the Sarbanes-Oxley Act of 2002. * ** Filed with this Form 10-K. Furnished with this Form 10-K. Registration No. 333-112977). 10.43 Amendment No. 1 to 364-Day Revolving Credit Agreement dated as of July 14, 2004, among Halliburton, the Banks party thereto, Citicorp North America, Inc., as Paying Agent, JPMorgan Chase Bank, as Co-Administrative Agent, ABN AMRO Bank N.V., as Syndication Agent, and HSBC Bank USA, National Association and The Royal Bank of Scotland plc, as Co-Documentation Agents (incorporated by reference to Exhibit 10.3 to Halliburton’s Form 8-K filed December 30, 2004, File No. 1-3492). 10.44 Employment Agreement (Andrew R. Lane) (incor- porated by reference to Exhibit 10.3 to Halliburton’s Form 10-Q for the quarter ended September 30, 2004, File No. 1-3492). 116 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON SUPPLEMENTAL SCHEDULE THE BOARD OF DIRECTORS AND SHAREHOLDERS HALLIBURTON COMPANY Under date of February 25, 2005, we reported on the consolidated balance sheets of Halliburton Company and subsidiaries as of December 31, 2004 and December 31, 2003, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2004, which are included in the Annual Report on Form 10-K. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related consoli- dated financial statement schedule (Schedule II) included in the Annual Report on Form 10-K. The financial state- ment schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statement schedule based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Houston, Texas February 25, 2005 117 HALLIBURTON COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (MILLIONS OF DOLLARS) The table below presents valuation and qualifying accounts for continuing operations. D e s c r i p t i o n o f P e r i o d E x p e n s e s A c c o u n t s D e d u c t i o n s A d d i t i o n s B a l a n c e a t C h a r g e d t o C h a r g e d t o B e g i n n i n g C o s t s a n d O t h e r B a l a n c e a t E n d o f P e r i o d Year ended December 31, 2002: Deducted from accounts and notes receivable: Allowance for bad debts Accrued reorganization charges Year ended December 31, 2003: Deducted from accounts and notes receivable: Allowance for bad debts Accrued reorganization charges Year ended December 31, 2004: Deducted from accounts and notes receivable: Allowance for bad debts Accrued reorganization charges $131 $ 1 $157 $ 10 $175 $ 1 $82 $29 $44 $ – $22 $40 $– $– $4 $– $2 $– $(56) (a) $(20) (b) $(30) (a) $ (9) (b) $(72) (a) $(22) (b) $157 $ 10 $175 $ 1 $127 $ 19 (a) Receivable write-offs, reclassifications, and net of recoveries. (b) See Note 21 to the consolidated financial statements for more information. 118 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 1st day of March, 2005. 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 1st day of March, 2005. /s/ David J. Lesar David J. Lesar Chairman of the Board, President, Chief Executive Officer, and Director /s/ C. Christopher Gaut C. Christopher Gaut Executive Vice President and Chief Financial Officer /s/ Mark A. McCollum Mark A. McCollum Senior Vice President and Chief Accounting Officer 119 * Robert L. Crandall Robert L. Crandall Director * Kenneth T. Derr Kenneth T. Derr Director * Charles J. DiBona Charles J. DiBona Director * W. R. Howell W. R. Howell Director * Ray L. Hunt Ray L. Hunt Director * Aylwin B. Lewis Aylwin B. Lewis Director * J. Landis Martin J. Landis Martin Director * Jay A. Precourt Jay A. Precourt Director * Debra L. Reed Debra L. Reed Director * C. J. Silas C. J. Silas Director 120 * /s/ Margaret E. Carriere Margaret E. Carriere, Attorney-in-fact CORPORATE INFORMATION BOARD OF DIRECTORS Robert L. Crandall (1986)(a), (b), (c) Chairman Emeritus AMR Corporation/American Airlines, Inc. Irving, Texas Kenneth T. Derr (2001)(a), (b), (c), (e) Retired Chairman of the Board Chevron Corporation San Francisco, California Charles J. DiBona (1997)(a), (d), (e) Retired President and Chief Executive Officer American Petroleum Institute Great Falls, Virginia W.R. Howell (1991)(a), (b), (c) Chairman Emeritus J.C. Penney Company, Inc. Dallas, Texas Ray L. Hunt (1998)(a), (e) Chairman of the Board and Chief Executive Officer Hunt Oil Company Dallas, Texas David J. Lesar (2000) Chairman of the Board, President and Chief Executive Officer Halliburton Company Houston, Texas Aylwin B. Lewis (2001)(a), (b), (d) President and Chief Executive Officer Kmart Holding Corporation Troy, Michigan J. Landis Martin (1998)(a), (d), (c) Chairman of the Board, President and Chief Executive Officer Titanium Metals Corporation Denver, Colorado Jay A. Precourt (1998)(a), (b), (d) Chairman of the Board and Chief Executive Officer Scissor Tail Energy, LLC Vail, Colorado Debra L. Reed (2001)(a), (b), (e) President and Chief Operating Officer Southern California Gas Company and San Diego Gas and Electric Company San Diego, California C.J. Silas (1993)(a), (b), (c) Retired Chairman of the Board and Chief Executive Officer Phillips Petroleum Company Bartlesville, Oklahoma (a) Member of the Management Oversight Committee (b) Member of the Compensation Committee (c) Member of the Audit Committee (d) Member of the Health, Safety and Environment Committee (e) Member of the Nominating and Corporate Governance Committee CORPORATE OFFICERS David J. Lesar Chairman of the Board, President and Chief Executive Officer Andrew R. Lane Executive Vice President and Chief Operating Officer C. Christopher Gaut Executive Vice President and Chief Financial Officer Albert O. Cornelison Jr. Executive Vice President and General Counsel Mark A. McCollum Senior Vice President and Chief Accounting Officer W. Preston Holsinger Vice President and Treasurer Evelyn M. Angelle Vice President, Investor Relations Margaret E. Carriere Vice President, Secretary and Corporate Counsel Charles E. Dominy Vice President, Government Relations Weldon J. Mire Vice President, Human Resources David R. Smith Vice President, Tax SHAREHOLDER INFORMATION Corporate Office 5 Houston Center 1401 McKinney, Suite 2400 Houston, Texas 77010 Shares Listed New York Stock Exchange Symbol: HAL Transfer Agent and Registrar Mellon Investor Services LLC Overpeck Center 85 Challenger Road Ridgefield Park, New Jersey 07660-2108 1-800-279-1227 www.melloninvestor.com For up-to-date information on Halliburton Company, shareholders may use the Company’s toll-free telephone-based information service available 24 hours a day at 1-888-669-3920 or contact the Halliburton Company homepage on the Internet’s World-Wide Web at www.halliburton.com. The CEO and CFO certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 have been filed as exhibits to Halliburton’s Form 10-K. Halliburton has also submitted the Annual CEO Certification required by the New York Stock Exchange to the NYSE. Corporate Office 5 Houston Center 1401 McKinney, Suite 2400 Houston, Texas 77010 USA www.halliburton.com H04218