ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the consolidated financial statements of the Company for the years ended December 31, 2003, 2002 and 2001 and the related Notes to Consolidated Financial Statements contained in Item 8 herein.

EXECUTIVE SUMMARY

     We are engaged in the oilfield services industry and operate through six divisions – Baker Atlas, Baker Oil Tools, Baker Petrolite, Centrilift, Hughes Christensen and INTEQ – that we aggregate and refer to as the Oilfield segment. We manufacture and sell products and provide services used in the oil and natural gas industry, including drilling, formation evaluation, completion and production of oil and natural gas wells. We have operations in over 80 countries around the world, with headquarters in Houston, Texas. Previously we operated a Process segment, which manufactured and sold process equipment for separating solids from liquids and liquids from liquids. During 2003, we signed a definitive agreement for the sale of BIRD Machine (“BIRD”), the remaining division in this segment. We have reclassified the operating results for BIRD as discontinued operations and no longer operate in this segment.

     Our products and services are sold in highly competitive markets, and our revenues and earnings can be affected by changes in competitive prices, fluctuations in the level of activity in major markets, general economic conditions, foreign exchange fluctuations and governmental regulation. We compete with the oil and natural gas industry’s largest diversified oilfield services providers, as well as many small companies. We believe that the principal competitive factors in our industry are product and service quality; availability and reliability; health, safety and environmental standards; technical proficiency and price. We consider our key business drivers to include the rig count, oil and natural gas production levels and current and expected future energy prices.

     In 2003, we reported revenues of $5,292.8 million, an 8.0% increase compared with 2002. Income from continuing operations for 2003 was $180.1 million, compared with $229.6 million in 2002. Included in income from continuing operations for 2003 are charges, net of tax, of $105.9 million related to our share of the WesternGeco restructuring charge and $45.3 million related to the impairment of our investment in WesternGeco. Included in income from continuing operations for 2002 is a charge, net of tax, of $86.8 million related to our share of the WesternGeco restructuring charge.

     The increase in revenue was achieved despite cautious investment by our customers, shifting markets and strong competition. Even though oil and natural gas prices were relatively high in 2003, oil and natural gas companies invested cautiously because of the conflict in the Middle East and ongoing concerns about the economy. On a worldwide basis, the average rig count for 2003 increased 16.9% compared with the average rig count for 2002. Most of this increase came from land rigs drilling for natural gas in North America. Drilling activity in the Gulf of Mexico and the North Sea, historically among our strongest markets, declined during 2003 as deepwater operators re–evaluated projects and the large diversified oil and natural gas companies in the North Sea and Gulf of Mexico focused on new opportunities in other resource areas.

     We believe that our critical success factors include having sufficient financial liquidity and resources to fund the various requirements of the business; managing our overall global manufacturing capacity to ensure proper production levels; ensuring workforce and asset levels are in place and in line with business needs; maximizing efficiencies in our manufacturing and service delivery processes; identifying, evaluating and implementing profit improvement strategies; introducing new technology; flawless execution at the well site; delivering unmatched value to our customers and overall cost management.

     As 2004 begins, we remain focused on cost management and the introduction of new products. We have created a long–term strategy that is aimed at creating value for our stockholders throughout the business cycle and growing our business faster while achieving superior margins compared with our major competitors. We share a common high performance culture, and we are aligning to execute our long–term strategy. Our six divisions will continue to provide Best–in–Class technology, serving our traditional markets and new ones, while delivering unmatched value for our customers and maximizing returns for our stockholders.

BUSINESS ENVIRONMENT

     Our business environment and its corresponding operating results are significantly affected by the level of energy industry spending for the exploration and production of oil and natural gas reserves. An indicator for this spending is the rig count. When drilling and workover rigs are active, many of the products and services provided by the oilfield services industry are required. Our products and services are used during the drilling and workover phases, as well as when the oil and natural gas wells are completed and during actual production of the hydrocarbons. This spending by oil and natural gas companies is, in turn, influenced strongly by

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expectations about the supply and demand for oil and natural gas products and by current and expected prices for both oil and natural gas. Rig counts therefore generally reflect the relative strength and stability of energy prices.

Rig Counts

     We have been providing rig counts to the public since 1944. We gather all relevant data through our field service personnel, who obtain the necessary data from routine visits to the various rigs, customers, contractors or other outside sources. This data is then compiled and distributed to various wire services and trade associations and is published on our website. Rig counts are compiled weekly for the U.S. and Canada and monthly for all international and U.S. workover rigs. Published international rig counts do not include rigs drilling in certain countries, such as Russia and onshore China, because this information is extremely difficult to obtain.

     North American rigs are counted as active if, on the day the count is taken, the well being drilled has been started, drilling has not been completed and the well is anticipated to be of sufficient depth to be a potential customer of our drill bits. In most international areas, rigs are counted as active if drilling operations have taken place for at least 15 days during the month and if the well has not reached the target depth. Rigs that are in transit from one location to another, are rigging up, have been drilling less than 15 days of the month, are being used in non–drilling activities including production testing, completion and workover, or are not significant consumers of oilfield products and services are not included in the rig count. In some active international areas where better data is available, a weekly or daily average of active rigs is taken.

     Our rig counts are summarized in the table below as averages for each of the periods indicated.

     U.S. – land and Canadian rig counts increased 28.9% and 26.2%, respectively, in 2003 compared with 2002 due to the increase in drilling for natural gas. The U.S. – offshore rig count decreased 4.4% in 2003 compared with 2002 primarily related to a reduced level of spending by major diversified oil and natural gas companies who redirected a portion of their spending towards larger international projects.

     Outside North America, rig counts increased 5.2% in 2003 compared with 2002. The rig count in Latin America increased 14.0% as spending by the Mexican national oil company, PEMEX, drove rig count increases in Mexico, offsetting strike–related decreases attributed to the Venezuelan national oil company, PDVSA. The North Sea rig count in 2003 decreased 11.5% compared with 2002 following a 7.1% decrease in 2002 compared with 2001 primarily driven by a decline in drilling activity in the U.K. sector. Major diversified oil and natural gas companies redirected spending towards other larger international projects, especially in Russia and the Caspian. Activity in the Middle East continued to rise steadily with a 5.0% increase in the 2003 rig count, following a 12.3% increase in 2002 compared with 2001. Rig counts in Africa declined 6.9% in 2003 compared with 2002 primarily as a result of political disruptions in Nigeria and project delays in other parts of West Africa. Rig activity in the Asia Pacific region was up 3.5% in 2003 compared with 2002 primarily due to activity increases in India.

Oil and Natural Gas Prices

     Generally, changes in the current price and expected future prices of oil or natural gas drive both customers’ expectations about their prospects from oil and natural gas sales and their expenditures to explore for or produce oil and natural gas. Accordingly, changes in these expenditures will normally result in increased or decreased demand for our products and services. Oil (Bloomberg

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West Texas Intermediate (WTI) Cushing Crude Oil Spot Price) and natural gas (Bloomberg Henry Hub Natural Gas Spot Price) prices are summarized in the table below as averages of the daily closing prices during each of the periods indicated.

     Oil prices averaged $31.06/Bbl in 2003, the highest annual average in more than a decade. Oil prices rose to a high of $37.83/Bbl in early March due to low inventories, seasonally colder than normal weather, the disruption of Venezuelan production by a general strike and concerns about the potential for significant supply disruptions as a result of military operations in the Middle East. Oil prices fell to a low of $25.24/Bbl in late April as significant supply disruptions did not occur and the market reacted to the possibility of a more rapid than expected recovery in Iraqi oil production. Oil prices then increased to and remained between $30/Bbl and $32/Bbl through the balance of the year, excluding September. In September, concern rose again about a quicker than anticipated recovery in Iraqi production in the fourth quarter of 2003 and early 2004 and oil prices dropped below $27/Bbl. The Organization of Petroleum Exporting Countries (“OPEC”) reacted with a surprise 0.9 million barrels per day quota cut in late September which sustained oil prices of $30/Bbl to $32/Bbl through the end of 2003. In early 2004, oil prices are averaging between $32/Bbl and $38/Bbl due to colder than normal weather, low inventories and improving Chinese and U.S. economic growth expectations. In February 2004, OPEC again surprised the market with a 1.0 million barrels per day quota cut and pledged to further reduce the current level of production in excess of agreed quotas by another 1.5 million barrels per day.

     During 2003, natural gas prices averaged $5.49/mmBtu, the highest level in two decades. In early 2003, natural gas traded between $5.00/mmBtu and $6.50/mmBtu, except for a two week period in late February 2003 when prices spiked to $19.38/mmBtu. Natural gas storage levels at the beginning of the injection season, which runs from April to November, were at record low levels but high summer natural gas prices resulted in reduced industrial demand and allowed storage levels to increase. Natural gas prices remained above $5/mmBtu until early July 2003, when it became apparent that storage injections during the summer of 2003 could approach record levels and that storage would likely be full by the beginning of the winter withdrawal season. Prices weakened through the remainder of the injection season to a low of $3.99/mmBtu in late October. Natural gas prices increased over the remainder of 2003 and are trading between $5/mmBtu and $7/mmBtu in early 2004.

Key Risk Factors

     Our business is focused on providing products and services to the worldwide oil and natural gas industry; therefore, our risk factors are centered on those factors that impact the markets for oil and natural gas. Key risk factors currently influencing the worldwide oil and natural gas markets that could impact our outlook are discussed below.

•		Production control – the degree to which individual OPEC nations and other large oil and natural gas producing countries, including, but not limited to, Mexico, Norway and Russia, are willing and able to control production and exports of oil, to decrease or increase supply and to support their targeted oil price while meeting their market share objectives. Key measures of production control include actual production levels compared with target or quota production levels, oil price compared with targeted oil price and changes in each country’s market share.
•		Global economic growth – particularly the impact of the U.S. and Western European economies and the economic activity in Japan, China, South Korea and the developing areas of Asia where the correlation between economic growth and energy demand is strong. The strength of the U.S. economy and economic growth in developing Asia, particularly China, will be important in 2004. Key measures include U.S. and international economic output, global energy demand and forecasts of future demand by governments and private organizations.
•		Oil and natural gas storage inventory levels – a measure of the balance between supply and demand. A key measure of U.S. natural gas inventories is the storage level reported weekly by the U.S. Department of Energy compared with historic levels. Key measures for oil inventories include U.S. inventory levels reported by the U.S. Department of Energy and American Petroleum Institute and worldwide estimates reported by the International Energy Agency.
•		Ability to produce natural gas – the amount of natural gas that can be produced is a function of the number of new wells drilled, completed and connected to pipelines as well as the rate of production and resulting depletion of existing wells. Advanced technologies, such as horizontal drilling, improve total recovery but also result in a more rapid production decline. Key measures include government and private surveys of natural gas production, company reported production, estimates of reservoir depletion rates and drilling and completion activity.

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•		Technological progress – the design and application of new products that allow oil and natural gas companies to drill fewer wells and to drill, complete and produce wells faster, recover more hydrocarbons and/or lower costs. Key measures also include the overall level of research and engineering spending by oilfield services companies and the pace at which new technology is both introduced commercially and accepted by customers.
•		Maturity of the resource base – the growing necessity for increased levels of investment and activity to support production from an area the longer it is developed. Key measures include changes in undeveloped hydrocarbon reserves in mature areas like the North Sea, the U.S., Canada and Latin America.
•		Pace of new investment – the amount oil and natural gas companies choose to invest in emerging markets and any impact it has on their spending in areas where they already have an established presence.
•		Access to capital – the ability of oil and natural gas companies to access the funds necessary to carry out their exploration and production (“E&P”) plans. Access to capital is particularly important for smaller independent oil and natural gas companies. Key measures of access to capital include cash flow, interest rates, analysis of oil and natural gas company leverage and equity offering activity.
•		Energy prices and price volatility – the impact of widely fluctuating commodity prices on the stability of the market and subsequent impact on customer spending. While current energy prices are important contributors to positive cash flow at E&P companies, expectations for future prices and price volatility are generally more important for determining future E&P spending. While higher commodity prices generally lead to higher levels of E&P spending, sustained high energy prices can be an impediment to economic growth.
•		Impact of energy prices and price volatility on demand for hydrocarbons – short–term price changes can result in companies switching to the most economic sources of fuel, prompting a temporary curtailment of demand, while long–term price changes can lead to permanent changes in demand. This results in the oilfield services industry being cyclical in nature. Key indicators include hydrocarbon prices on a Btu equivalent basis and indicators of hydrocarbon demand, such as electricity generation or industrial production.
•		Access to prospects – the ability of oil and natural gas companies to develop economically attractive projects based on their expectations of future energy prices, required investments and resulting returns. Access to prospects may be limited because host governments do not allow access to the reserves or because another oil and natural gas company owns the rights to develop the prospect.
•		Supply disruptions – the loss of production and/or delay of activity from key oil exporting countries, including but not limited to, Iraq, Saudi Arabia and other Middle Eastern countries, Nigeria and Venezuela, due to political instability, civil unrest, labor issues or military activity. In addition, adverse weather such as hurricanes could impact production facilities, causing supply disruptions.
•		Weather – the impact of variations in temperatures as compared with normal weather patterns and the related effect on demand for oil and natural gas. A key measure of the impact of weather on energy demand is population–weighted heating and cooling degree days as reported by the U.S. Department of Energy and forecasts of warmer than normal or cooler than normal temperatures.
•		Government regulations – the costs incurred by oil and natural gas companies to conform to and comply with government regulations, including environmental regulations, may limit the quantity of oil and natural gas that may be economically produced.

Industry Outlook

     Caution is advised that the factors described in “Forward Looking Statements” and “Business Environment” could negatively impact our expectation for oil and natural gas demand, oil and natural gas prices and drilling activity.

      Oil – Inventories of crude oil and products were at record low levels as 2004 began, supporting oil prices of $32/Bbl to $38/Bbl. Oil prices are expected to decline throughout 2004 and average between $26/Bbl and $34/Bbl. Factors which could support prices at the upper end of this range include stronger than expected worldwide economic growth, especially in China and the U.S., the potential for supply disruptions in the Middle East, Africa or Venezuela, the slower growth of Russian exports due to export capacity bottlenecks and OPEC’s desire and ability to maintain a higher price target to stabilize their purchasing power. Factors which could

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result in oil prices at the lower end of the range include slower than expected economic growth in the U.S. and China, sooner than expected increases in Iraqi production growth and increased production from OPEC members Algeria, Libya and Nigeria, challenging the Persian Gulf members of OPEC to act as the swing producers.

      Natural Gas – In 2004, prices are expected to trade between $4/mmBtu and $7/mmBtu. Natural gas could trade at the top of this range if weather is colder than normal, the U.S. economy, particularly the industrial sector, exhibits greater than expected growth and continued levels of customer spending are not sufficient to support the growth of natural gas production. Prices could move to the bottom of this range if the U.S. economic recovery is weaker than expected or weather is milder than expected. During the summer, natural gas prices are expected to trade at a level necessary to curtail price sensitive demand and allow storage to refill.

      Customer Spending – Based upon our discussions with major customers, review of published industry reports and our outlook for oil and natural gas prices described above, anticipated customer spending trends are as follows:

	•		North America – Spending in North America, primarily towards developing natural gas supplies, is expected to increase approximately 7% to 9% in 2004 compared with 2003.
	•		Outside North America – Customer spending, primarily directed at developing oil supplies, is expected to increase 4% to 6% in 2004 compared with 2003.
	•		Total spending is expected to increase 5% to 7% in 2004 compared with 2003.

      Drilling Activity – Based upon our outlook for oil and natural gas prices and customer spending described above, our outlook for drilling activity, as measured by the Baker Hughes rig count, is as follows:

	•		The North American rig count is expected to increase approximately 6% to 9% in 2004 compared with 2003.
	•		Drilling activity outside of North America is expected to increase approximately 4% to 6% compared with 2003.

COMPANY OUTLOOK

     We expect that 2004 will be a stronger year than 2003, with revenues increasing 5% to 7%. In our outlook for 2004, we took into account the factors described herein. In 2003, 2002 and 2001, revenues outside North America were 57.6%, 59.9% and 55.1% of total revenues, respectively. In 2004, we expect revenues outside North America to continue this trend and to be between 55% and 60% of total revenues.

     Growth in our revenues should mirror the growth in customer spending. Our assumptions regarding overall growth in customer spending assume strong economic growth in the U.S. and China and OPEC discipline, resulting in an oil price exceeding $26/Bbl. Our assumptions regarding customer spending in North America assume strong economic growth in the U.S. and natural gas prices exceeding $4/mmBtu.

     In North America, we expect revenues to increase 7% to 9% in 2004 compared with 2003, with the majority of the increase occurring in the second half of 2004. We expect spending on land based projects to continue to increase in 2004 following the trend evident in 2003. We also expect offshore spending in the Gulf of Mexico to be flat in 2004 compared with 2003. The normal weather–driven seasonal decline in U.S. and Canadian spending in the first half of the year should result in sequentially softer revenues in the first and second quarters of 2004.

     Outside North America, we expect revenues to increase 5% to 7% in 2004 compared with 2003, continuing the multi–year trend of modest growth in customer spending. Spending on large projects from national oil companies will reflect established seasonality trends, resulting in softer revenues in the first half of the year and stronger revenues in the second half. In addition, customer spending should be affected by weather–related reductions in the North Sea in the first and second quarters of 2004. The Middle East, Latin America, Caspian regions and Russia are expected to demonstrate above average spending increases, resulting in increased revenue, while growth in revenues from the North Sea may be below average. Our expectations for spending and revenue growth could decrease if prices fall below $26/Bbl for oil or $4/mmBtu for natural gas or if there are disruptions in key oil and natural gas production markets, such as Venezuela or Nigeria.

     In prior years, our profitability has been negatively affected by our share of WesternGeco’s operating results, which have been adversely affected by the continued weakness in the seismic industry. We expect the operating results of WesternGeco to improve in 2004 as compared with prior years; however, based on the trend of operating losses and weakness in the seismic industry in prior

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years, there is uncertainty regarding the future operating results of WesternGeco. Information regarding WesternGeco’s profitability in 2004 is based on information that WesternGeco has provided to us. Should this information not be accurate, our forecasts for profitability could be impacted, either positively or negatively.

     Based on the above forecasts, we believe that earnings per share in 2004 from continuing operations will be in the range of $1.20 to $1.35. This does not anticipate material changes in the prices that we charge for our products. Significant price increases or significantly better than expected results from WesternGeco could cause earnings per share to reach the upper end of this range. Conversely, significant price decreases or significantly worse than expected results at WesternGeco could result in earnings per share being at or below the bottom of this range. Our ability to improve pricing is dependent on demand for our products and services and our competitors strategies of managing capacity. While the commercial introduction of new technology is an important factor in realizing price improvement, without pricing discipline throughout the industry as a whole, meaningful improvements in our prices are not likely to be realized. Additionally, significant changes in drilling activity outside our expectations could impact operating results positively or negatively.

     We do business in approximately 80 countries including about one–half of the 34 countries having the worst scores in Transparency International’s Corruption Perception Index (“CPI”) survey for 2003. We devote significant resources to the development, maintenance and enforcement of our Business Code of Conduct policy, our Foreign Corrupt Practices Act (the “FCPA”) policy, our internal control processes and procedures and other compliance related policies. Notwithstanding the devotion of such resources, and in part as a consequence thereof, from time to time we discover or receive information alleging potential violations of the FCPA and our policies, processes and procedures. We conduct internal investigations of these potential violations and take appropriate action depending upon the outcome of the investigation. We anticipate that the devotion of significant resources to compliance related issues, including the necessity for such internal investigations, will continue to be an aspect of doing business in a number of the countries in which oil and natural gas exploration, development and production take place and in which we are requested to conduct operations. In order to provide products and services in some of these countries, we may in the future utilize joint ventures, sell products to distributors or otherwise modify our business approach in order to improve our ability to conduct our business in accordance with our Business Code of Conduct.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

     The discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. Our significant accounting policies are described in the Notes to Consolidated Financial Statements. In certain respects, the application of our significant accounting policies in the preparation of the consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. We base these estimates and judgments on historical experience and other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the business environment in which we operate changes.

     We have defined a critical accounting policy or estimate as one that is both important to the portrayal of our financial condition and results of operations and requires us to make difficult, subjective or complex judgments or estimates about matters that are uncertain. We believe the following are the critical accounting policies used in the preparation of our consolidated financial statements as well as the significant estimates and judgments and uncertainties affecting the application of these policies. We have discussed the development and selection of these critical accounting policies and estimates with the Audit/Ethics Committee of our Board of Directors and the Audit/Ethics Committee has reviewed the disclosure presented below.

Allowance for Doubtful Accounts

     The determination of the collectibility of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customers’ payment history and current credit worthiness to determine that collectibility is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Inherently, these uncertainties require us to make frequent judgments and estimates regarding our customers’ ability to pay amounts due us in order to determine the appropriate amount of valuation allowances required for doubtful accounts. Provisions for doubtful accounts are recorded when it becomes evident that the customer will not be able to make the required payments at either contractual due dates or in the future. Over the last five years, reserves for doubtful accounts, as a percentage of total accounts receivable before reserves, have ranged from 5.2% to 7.1%. At December 31, 2003 and 2002, reserves for doubtful accounts totaled $62.8 million, or 5.2%, and $67.2 million, or 5.7%, of total accounts receivable before reserves, respectively. We believe that our reserve for doubtful accounts is adequate to cover anticipated losses under current conditions; however, uncertainties regarding changes in the financial

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condition of our customers, either adverse or positive, could impact the amount and timing of any additional provisions for doubtful accounts that may be required. A one percentage point change in this reserve would have had a pre–tax impact of approximately $12.1 million in 2003.

Inventory Reserves

     Inventory is a significant component of current assets and is stated at the lower of cost or market. This requires us to record provisions and maintain reserves for excess or obsolete inventory. To determine these reserve amounts, we regularly review inventory quantities on hand and compare them to estimates of future product demand, market conditions, production requirements and technological developments. These estimates and forecasts inherently include uncertainties and require us to make judgments regarding potential outcomes. Over the last five years, inventory reserves, as a percentage of total inventories before reserves, have ranged from 18.2% to 19.6%. At December 31, 2003 and 2002, inventory reserves totaled $232.5 million, or 18.5%, and $235.9 million, or 19.1%, of gross inventory, respectively. We believe that our reserves are adequate to cover anticipated losses under current conditions; however, significant or unanticipated changes to our estimates and forecasts, either adverse or positive, could impact the amount and timing of any additional provisions for excess or obsolete inventory that may be required. A one percentage point change in this reserve would have had a pre– tax impact of approximately $12.6 million in 2003.

Impairment of Long–Lived Assets

     Long–lived assets, which include property, goodwill, intangible assets, investments in affiliates and certain other assets, comprise a significant amount of our total assets. We make judgments and estimates in conjunction with accounting for these assets, including depreciation and amortization methods and useful lives. Additionally, the carrying values of these assets are reviewed for impairment periodically, and at least annually for goodwill, or whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires us to make judgments regarding long–term forecasts of future revenues and costs related to the assets subject to review. In turn, these forecasts are uncertain in that they require assumptions about demand for our products and services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. Given the nature of these evaluations and their application to specific assets and specific times, it is not possible to reasonably quantify the impact of changes in these assumptions; however, based upon our evaluation of the current business climate in which we operate, we do not currently anticipate that any significant asset impairment losses will be necessary.

Income Taxes

     The liability method is used for determining our income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In determining the need for valuation allowances, we have considered and made judgments and estimates regarding estimated future taxable income and ongoing prudent and feasible tax planning strategies. These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to adjust the valuation allowances for our deferred tax assets. Historically, changes to valuation allowances have been caused by major changes in the business cycle in certain countries and changes in local country law. The ultimate realization of the deferred tax assets depends on the generation of sufficient taxable income in the applicable taxing jurisdictions.

     We operate in more than 80 countries under many legal forms. As a result, we are subject to the jurisdiction of numerous domestic and foreign tax authorities, as well as to tax agreements and treaties among these governments. Our operations in these different jurisdictions are taxed on various bases: actual income before taxes, deemed profits (which are generally determined using a percentage of revenues rather than profits) and withholding taxes based on revenue. Determination of taxable income in any jurisdiction requires the interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of deductions, permissible revenue recognition methods under the tax law and the sources and character of income and tax credits. Changes in tax laws, regulations, agreements and treaties, foreign currency exchange restrictions or our level of operations or profitability in each taxing jurisdiction could have an impact on the amount of income taxes that we provide during any given year.

     Our tax filings are subjected to audit by the tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or potentially through the courts. We believe that these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. Resolution of these situations

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inevitably includes some degree of uncertainty; accordingly we provide taxes only for the amounts we believe will ultimately result from these proceedings. We do not believe it is possible to reasonably estimate the potential impact of changes to the assumptions and estimates identified because the resulting change to our tax liability, if any, is dependent on numerous factors which cannot be reasonably estimated. These include, among others, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a fair settlement through an administrative process; the impartiality of the local courts; the sheer number of countries in which we do business; and the potential for changes in the tax paid to one country to either produce, or fail to produce, an offsetting tax change in other countries. Our experience has been that the estimates and assumptions we have used to provide for future tax assessments have proven to be appropriate. However, past experience is only a guide, and the potential exists, however limited, that the tax resulting from the resolution of current and potential future tax controversies may differ materially from the amount accrued.

DISCONTINUED OPERATIONS

     In the third quarter of 2003, our Board of Directors approved and management initiated a plan to sell BIRD, the last remaining division of our former Process segment. In October 2003, we signed a definitive agreement for the sale of BIRD and recorded charges totaling $37.4 million, net of tax of $10.9 million, which consisted of a loss of $13.5 million on the write–down of BIRD to fair value, $6.2 million of severance and warranty accruals and a loss of $17.7 million related to the recognition of cumulative foreign currency translation adjustments into earnings. The sale closed in January 2004 and we received $5.6 million in proceeds, which is subject to adjustment pending final completion of the purchase price. We retained certain accounts receivable, inventories and other assets.

     In December 2002, we entered into exclusive negotiations for the sale of our interest in oil producing operations in West Africa for $32.0 million in proceeds. The transaction was effective as of January 1, 2003, and resulted in a gain on sale of $4.1 million, net of a tax benefit of $0.2 million, recorded in the first quarter of 2003. We received $10.0 million as a deposit in 2002 and the remaining $22.0 million in April 2003.

     In November 2002, we sold EIMCO Process Equipment (“EIMCO”), a division of our former Process segment, and recorded a loss on disposal of $22.3 million, net of tax of $1.2 million, which consisted of a loss of $2.3 million on the write–down to fair value and a loss of $20.0 million related to the recognition of cumulative foreign currency translation adjustments into earnings. We received total proceeds of $48.9 million, of which $4.9 million was held in escrow pending completion of final adjustments of the purchase price. In 2003, all purchase price adjustments were completed, resulting in the release of the escrow balance, of which $2.9 million was returned to the buyer and $2.0 million was received by us. In 2003, we also recorded an additional loss on sale due to purchase price adjustments of $2.5 million, net of tax of $1.3 million.

     We have reclassified the consolidated financial statements for all prior periods presented to reflect these operations as discontinued. See Note 2 of the Notes to Consolidated Financial Statements in Item 8 herein for additional information regarding discontinued operations.

RESULTS OF OPERATIONS

     The discussions below relating to significant line items are based on available information and represent our analysis of significant changes or events that impact the comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect comparability or trends and, where possible and practical, have quantified the impact of such items.

     The table below details certain consolidated statement of operations data and their percentage of revenues for 2003, 2002 and 2001, respectively.

Revenues

     Revenues for 2003 were $5,292.8 million, an increase of 8.0% compared with 2002 reflecting a 16.9% increase in rig counts. Rig counts act as a leading indicator for our revenues because when rigs are active, many of our products and services are required. Our products and services are used during drilling operations and then subsequently during completion of the wells and also during production of the hydrocarbons. Revenues in North America, which accounted for 42.4% of total revenues, increased 14.0% compared with 2002. This increase reflects increased drilling activity in the U.S. and Canada, as evidenced by a 24.8% increase in the

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North American rig count. Revenues outside North America, which accounted for 57.6% of total revenues, increased 3.9% compared with 2002. This increase reflects the improvement in international drilling activity, as evidenced by the 5.2% increase in rig counts outside North America, primarily in Latin America and the Middle East, partially offset by decreased drilling activity in the North Sea and Africa. During 2003, pricing was not a significant contributor to our revenue growth, as deterioration in prices for certain product lines at our INTEQ division were partially offset by pricing improvement realized from our other product lines.

     Revenues for 2002 were $4,901.7 million, a decrease of 2.7% compared with 2001. Revenues in North America, which accounted for 40.1% of total revenues, decreased 12.9% compared with 2001. This decrease reflects lower activity in the U.S. land and offshore operations and Canada, as evidenced by a 27.0% decrease in the North American rig count. Inclement weather in the Gulf of Mexico, including Tropical Storm Isidore and Hurricane Lili, also contributed to the decline. Revenues outside North America, which accounted for 59.9% of total revenues, increased 5.6% compared with 2001. This increase reflects the improvement in drilling activity, particularly in the Middle East and Asia Pacific, partially offset by weaker revenues in Latin America due to the political and economic environments in Argentina and Venezuela and the impact of a labor strike in Norway.

Cost of Revenues

     Cost of revenues for 2003 was $3,854.9 million, an increase of 9.4% compared with 2002. Cost of revenues as a percentage of revenues was 72.8% and 71.9% for 2003 and 2002, respectively. The increase in cost of revenues as a percentage of revenues is primarily related to our INTEQ division. In 2003, INTEQ experienced the highest revenue growth of our divisions; however, margins deteriorated as they were impacted by increased downward pricing trends, increased repairs and maintenance (“R&M”) costs for newly developed downhole rental tools and other nonrecurring costs. We anticipate margins at INTEQ will improve in 2004 as a result of a stabilized pricing environment and improved cost control measures. In addition, corrective action was taken related to the increased R&M costs, which we anticipate will result in lower R&M costs in 2004. A change in the geographic and product mix from the sale of our products and services also contributed to the increase in the cost of revenues as a percentage of revenues. During 2003, our revenue increases came predominantly from North America and our margins on revenues generated in North America are typically lower than margins generated outside of North America.

     Cost of revenues for 2002 was $3,525.2 million, a decrease of 1.1% compared with 2001. Cost of revenues as a percentage of revenues was 71.9% and 70.8% for 2002 and 2001, respectively. The increase in cost of revenues as a percentage of revenues was the result of our strategy not to significantly reduce our work force to match the reduced activity levels and a change in the geographic and product mix from the sale of our products and services.

Selling, General and Administrative

     Selling, general and administrative (“SG&A”) expenses for 2003 were $830.1 million, an increase of $18.6 million, or 2.3% compared with 2002. This increase was primarily due to an $8.9 million increase in net costs related to corporate activities and an increase of approximately $17.0 million in costs related to our self insurance programs that are not expected to recur in the future, offset by improvement in the impact of foreign exchange activity of $18.7 million. In 2004, we anticipate corporate costs will continue to trend upward primarily due to compliance related expenditures.

     SG&A expenses for 2002 were $811.5 million, an increase of $56.4 million, or 7.5%, compared with 2001. This increase was primarily due to the impact of the weakening U.S. dollar resulting in increased foreign exchange losses of $14.8 million, increased depreciation of the cost associated with the now substantially completed implementation of SAP R/3, an enterprise–wide accounting and business application software system, of $15.2 million, and our strategy not to significantly reduce our work force to match current market activity levels.

Reversals of Restructuring Charge

     In October 2000, our Board of Directors approved a plan to substantially exit the oil and natural gas exploration business and we recorded restructuring charges of $29.5 million, consisting of $5.5 million of severance, $7.8 million for costs to settle contractual obligations and a $16.2 million loss for the write–off of our undeveloped exploration properties in certain foreign jurisdictions. The severance charges were for approximately 50 employees, all of which have been terminated as of December 31, 2003. All of the accrued severance has been paid as of December 31, 2003.

     Included in the costs to settle contractual obligations was $1.1 million related to an oil and natural gas property in Angola. The property was sold in 2003 and we reversed the liability related to this contractual obligation. Also included in the costs to settle contractual obligations was $4.5 million for the minimum amount of our share of project costs relating to our interest in an oil and natural gas property in Colombia. After unsuccessful attempts to negotiate a settlement with our joint venture partner, we decided to

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abandon further involvement in this project. Subsequently, in 2001, a third party agreed to assume the remaining obligations in exchange for our interest in the project. Accordingly, we reversed $4.2 million related to this obligation. All contractual obligations associated with this plan have been paid as of December 31, 2003.

Impairment of Investment in Affiliate

     As a result of the continuing weakness in the seismic industry, we evaluated the carrying value of our investment in WesternGeco and recorded an impairment loss of $45.3 million in 2003 to write–down the investment to its fair value. The fair value was determined using a combination of a market value and discounted cash flows approach. We were assisted in the determination of the fair value by an independent third party. Although not anticipated, further declines in the fair value of the investment in WesternGeco would result in additional impairments. We cannot predict if additional impairments of our investment in WesternGeco will be necessary in the future because the environment in the seismic industry continues to be uncertain.

Equity in Income (Loss) of Affiliates

     Equity in income (loss) of affiliates relates to our share of the income (loss) of affiliates accounted for using the equity method of accounting. Our most significant equity method investment is our 30% interest in WesternGeco. During 2003, the operating results of WesternGeco continued to be adversely affected by the continuing weakness in the seismic industry. As a result of this weakness, WesternGeco recorded certain impairment and restructuring charges of $452.0 million for impairment of its multiclient seismic library and rationalization of its marine seismic fleet. Our portion of these charges was $135.7 million and is recorded in equity in income (loss) of affiliates.

     Equity in income (loss) of affiliates decreased $115.5 million for 2002 compared with 2001. The decrease is primarily related to a $300.7 million restructuring charge recorded by WesternGeco for impairment of its multiclient library, reductions in workforce, closing land–based seismic operations in the U.S. lower 48 states and Canada and reducing its marine seismic fleet. Our portion of this charge was $90.2 million and was recorded in equity in income (loss) of affiliates.

     Operating results for WesternGeco are expected to improve in 2004; however, based on the trend of operating losses and weakness in the seismic industry in prior years, there is uncertainty regarding the future operating performance of WesternGeco.

     Included in equity in income (loss) of affiliates for 2001 was $7.9 million related to the amortization of goodwill associated with equity method investments. In conjunction with the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets , we discontinued the amortization of goodwill associated with equity method investments effective January 1, 2002.

Interest Expense

     Interest expense for 2003 decreased $8.0 million compared with 2002 due to lower total debt levels, lower weighted average interest rates on our commercial paper and money market borrowings and increased amortization of deferred gains related to terminated interest rate swap agreements. Total debt levels decreased $63.4 million primarily due to the repayment of $100.0 million of long–term debt in February 2003. The approximate weighted average interest rate on our commercial paper and money market borrowings was 1.2% in 2003 compared with 1.8% for 2002. The amortization of deferred gains related to terminated interest rate swap agreements reduced interest expense by $9.9 million in 2003 compared with $6.0 million in 2002.

     Interest expense for 2002 decreased $15.2 million compared with 2001 due to lower total debt levels resulting from cash flows from operations coupled with lower weighted average interest rates on our short–term debt, commercial paper and interest rate swaps. The approximate weighted average interest rate on short–term debt and commercial paper was 1.8% for 2002 compared with 4.0% for 2001.

Income Taxes

     Our effective tax rates differ from the statutory income tax rate of 35% due to state income taxes, differing rates of tax on international operations and higher taxes within the WesternGeco venture.

     During 2003, we recognized an incremental effect of $36.3 million of additional taxes attributable to our portion of the operations of WesternGeco. Of this amount, $15.9 million related to the reduction in the carrying value of our equity investment in WesternGeco for which there was no tax benefit. The remaining $20.4 million arose from operations of the venture due to: (i) the venture being taxed in certain foreign jurisdictions based on a deemed profit basis, which is a percentage of revenues rather than profits and (ii) unbenefitted foreign losses of the venture, which are operating losses and impairment and restructuring charges in certain foreign

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jurisdictions where there was no current tax benefit and where a deferred tax asset was not recorded due to the uncertainty of realization. In 2002 and 2001, the amount of additional taxes resulting from operations of the venture was $40.2 million and $14.8 million, respectively.

     During 2003, a current year benefit of $3.3 million was recognized as the result of various refund claims filed in the U.S. During 2002, a $14.4 million benefit was recognized as the result of the settlement of an IRS examination related to our September 30, 1996 through September 30, 1998 tax years. In 2001, a benefit of $23.5 million was recognized as a result of the settlement of the IRS examination of certain 1994 through 1997 pre–acquisition tax returns and related refund claims of Western Atlas Inc.

     Our tax filings for various periods are subjected to audit by tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or potentially through the courts. We believe that these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. We have received tax assessments from various taxing authorities and are currently at varying stages of appeals and /or litigation regarding these matters. We have provided for the amounts we believe will ultimately result from these proceedings. We believe we have substantial defenses to the questions being raised and will pursue all legal remedies should an unfavorable outcome result. However, resolution of these matters involves uncertainties and there are no assurances that the outcomes will be favorable.

Cumulative Effect of Accounting Change

     On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations . SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of long–lived assets. SFAS No. 143 requires that the fair value of a liability associated with an asset retirement obligation (“ARO”) be recognized in the period in which it is incurred if a reasonable estimate can be made. The liability for the ARO is revised each subsequent period due to the passage of time and changes in estimates. The associated retirement costs are capitalized as part of the carrying amount of the long–lived asset and subsequently depreciated over the estimated useful life of the asset.

     The adoption of SFAS No. 143 in 2003 resulted in a charge of $5.6 million, net of tax of $2.8 million, recorded as the cumulative effect of accounting change in the consolidated statement of operations. In conjunction with the adoption, we recorded ARO liabilities of $11.4 million primarily for anticipated costs of obligations associated with the future disposal of power source units at certain of our divisions and refurbishment costs associated with certain leased facilities in Europe and with a fleet of leased railcars and tanks.

     On January 1, 2002, we adopted SFAS No. 142, Goodwill and Other Intangible Assets . The adoption of SFAS No. 142 required us to cease amortizing goodwill and to perform a transitional test of goodwill in each of our reporting units as of January 1, 2002. The reporting units were based on our organizational and reporting structure. Corporate and other assets and liabilities were allocated to the reporting units to the extent that they related to the operations of these reporting units. Valuations of the reporting units were performed by an independent third party. The goodwill in both the EIMCO and BIRD operating divisions of the former Process segment was determined to be impaired using a combination of a market value and discounted cash flows approach to estimate fair value. Accordingly, we recognized transitional impairment losses of $42.5 million, net of tax of $20.4 million in 2002 as the cumulative effect of accounting change in the consolidated statement of operations.

LIQUIDITY AND CAPITAL RESOURCES

     Our objective in appropriately financing our business is to maintain adequate financial resources and access to additional liquidity. During the last three years, cash flows from operations have been our principal source of funding. We anticipate that this trend will continue in 2004. We also have a $500.0 million three–year committed revolving credit facility that would provide an ample source of back–up liquidity that would be available in the event of an unanticipated significant demand on cash flow that could not be funded by operations or short–term borrowings.

     Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of the Company. In 2003, we used cash for a mix of activities including working capital needs, payment of dividends, repayment of debt, repurchase of common stock and capital expenditures. In 2004, we expect that this trend will continue, as we do not anticipate any additional material demands, commitments or other events that would require significant outlays of cash.

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Cash Flows

     Cash flows provided (used) by continuing operations by type of activity were as follows for the years ended December 31:

     Cash flow statements for companies with international operations that are local currency functional exclude the effects of the changes in foreign currency exchange rates that occur during any given year, as these are considered to be noncash changes and, as such, changes reflected in certain accounts on the cash flow statements may not reflect the changes in corresponding accounts on the consolidated balance sheets. During 2003, 2002 and 2001, these changes in foreign currency exchange rates were significant and resulted in corresponding changes in the foreign currency translation adjustment account.

     During 2003, we revised our capital expenditure reporting procedures for certain rental tools and engineering prototype tools. Previously, amounts for these items were reported as transfers from inventory to property, plant and equipment; however, they will now be reported as capital expenditures. In addition, depreciation related to certain of these tools that had not previously been included in total depreciation and amortization expense is now included in this caption. The consolidated statements of cash flows for the years ended December 31, 2002 and 2001 have been reclassified to give effect to this change. There was no impact to the consolidated statements of operations or the consolidated balance sheets for any of the periods presented.

Operating Activities

     Cash flows from operating activities have been relatively consistent during the last three years and we expect this trend to continue in 2004. We attribute the stability in our cash flow to successful management of working capital and consistent levels of income from continuing operations adjusted for non–cash items.

     Cash flows from operating activities from continuing operations increased $32.2 million in 2003 compared with 2002. The primary reason for this increase was improved operating performance, attributable to our increased revenues. In addition, working capital decreased with the effect of increasing cash flows from operating activities.

     The underlying drivers of the changes in working capital are as follows:

	•		An increase in accounts receivable in 2003 used $15.4 million in cash. This was due to increases in revenue offset by a reduction in days sales outstanding (defined as the average number of days our accounts receivable are outstanding) of approximately two days.
	•		A decrease in inventory in 2003 provided $21.5 million in cash as we increased our focus on improving the utilization of inventory on hand.
	•		An increase in accounts payable and accrued compensation and other accrued liabilities provided $31.8 million in cash. This was due to increased activity, increased employee compensation accruals, better management of our accounts payable and increased accruals for our self insurance programs. These changes were partially offset by $59.8 million more in income tax payments in 2003 compared with 2002.

     Our pension contributions in 2003 were approximately $28.0 million, an increase of approximately $19.0 million compared with the prior year, due to the formation of a new U.S. pension plan in 2002. In 2004, we expect pension contributions to increase and to be between $35.0 million and $40.0 million.

     Cash flows from operating activities from continuing operations decreased $24.3 million in 2002 compared with 2001 primarily due to decreased operating performance attributable to our decreased revenues. In addition, working capital increased with the effect of decreasing cash flows from operating activities.

     The underlying drivers of the changes in working capital are as follows:

•

A decrease in accounts receivable in 2002 provided $87.2 million in cash primarily due to decreases in revenues as days sales outstanding remained unchanged in 2002 compared with 2001.

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	•		A decrease in inventory in 2002 provided $17.5 million in cash as we increased our focus on improving the utilization of inventory on hand.
	•		A decrease in accounts payable and accrued compensation and other accrued liabilities in 2002 used $219.5 million in cash. This was due to decreased activity, decreased employee compensation accruals and the payment of $31.0 million more in income taxes in 2002 compared with 2001.

Investing Activities

     Our principal recurring investing activity is the funding of capital expenditures to improve the productivity of operations. Expenditures for capital assets totaled $405.2 million, $356.4 million and $326.0 million for 2003, 2002 and 2001, respectively. The increase in capital expenditures in 2003 compared with 2002 is due to expenditures necessary to support our growth and operations. The majority of these expenditures were for machinery and equipment and rental tools.

     We made two acquisitions in 2003 having an aggregate purchase price of $16.9 million, of which $9.5 million was paid in cash. As a result of these acquisitions, we recorded approximately $3.9 million of goodwill and $9.6 million of intangible assets through December 31, 2003. The purchase prices are allocated based on fair values of the acquisitions and may be subject to change based on the final determination of the purchase price allocation. In addition, during 2003, we invested $38.1 million in affiliates, of which $30.1 million related to the Company’s 50% interest in the QuantX Wellbore Instrumentation venture, which is engaged in the permanent in–well monitoring market.

     During 2002, we made three acquisitions having an aggregate cash purchase price of $39.7 million, net of cash acquired. As a result of these acquisitions, we recorded approximately $28.4 million of goodwill. In addition, during 2002, we invested $16.5 million in Luna Energy, L.L.C. (“Luna Energy”), a venture formed to develop, manufacture, commercialize, sell, market and distribute downhole fiber optic and other sensors for oil and natural gas exploration, production, transportation and refining applications. We have a 40% ownership interest in Luna Energy and account for this investment using the equity method of accounting.

     In 2003, we completed the sale of our interest in an oil producing property in West Africa for $32.0 million in proceeds. We received a deposit of $10.0 million in 2002 and the remaining $22.0 million in 2003. During 2002, we also disposed of our EIMCO division for $48.9 million in proceeds. We received $44.0 million in proceeds in 2002, with the remainder of the sales price held in escrow pending completion of final adjustments of the purchase price. In 2003, all purchase price adjustments were completed, resulting in the release of the escrow balance. We received $2.0 million and $2.9 million was returned to the buyer.

     Proceeds from disposal of assets were $66.8 million, $77.7 million and $77.6 million for 2003, 2002 and 2001, respectively. These disposals relate to machinery, rental tools and equipment no longer used in operations that were sold throughout the year.

     In January 2004, we completed the sale of BIRD and received $5.6 million in proceeds, which is subject to adjustment pending final completion of the purchase price. In addition, in February 2004, we completed the sale of our minority interest in Petreco International and received proceeds of $35.8 million, of which $7.4 million is held in escrow pending the outcome of potential indemnification obligations pursuant to the sales agreement. We do not believe the transaction is material to our financial condition or results of operations.

Financing Activities

     We had net borrowings of commercial paper and other short–term debt of $4.5 million during 2003 compared with net repayments of $163.7 million and $67.9 million in 2002 and 2001, respectively. We also repaid the $100.0 million 5.8% Notes due February 2003. The repayment was funded with cash on hand, cash flow from operations and the issuance of commercial paper.

     Total debt outstanding at December 31, 2003 was $1,484.4 million, a decrease of $63.4 million compared with December 31, 2002. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was 0.31 at December 31, 2003 and 2002.

     At different times during 2003, we entered into three separate interest rate swap agreements, each for a notional amount of $325.0 million, associated with our 6.25% Notes due January 2009. These agreements had been designated and had qualified as fair value hedging instruments. Due to our outlook for interest rates, we terminated the three agreements and received payments totaling $26.9 million. Each of the three agreements was terminated prior to entering into a new agreement. The deferred gains are being amortized as a reduction of interest expense over the remaining life of the underlying debt security, which matures in January 2009.

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     During 2002, we terminated two interest rate swap agreements that had been entered into in prior years. These agreements had been designated and had qualified as fair value hedging instruments. Upon termination, we received proceeds totaling $15.8 million. The deferred gains of $4.8 million and $11.0 million are being amortized as a reduction of interest expense over the remaining lives of the underlying debt securities, which mature in June 2004 and January 2009, respectively.

     We received proceeds of $61.8 million, $38.3 million and $50.1 million from the issuance of common stock in 2003, 2002 and 2001, respectively, from the exercise of stock options and the issuance of stock through our employee stock purchase plan.

     During 2002, we were authorized by our Board of Directors to repurchase up to $275.0 million of our common stock. During 2003, we repurchased 6.3 million shares at an average price of $28.78 per share, for a total of $181.4 million. During 2002, we repurchased 1.8 million shares at an average price of $27.52 per share, for a total of $49.1 million. Upon repurchase, the shares were retired.

     We paid dividends of $154.3 million, $154.9 million and $154.4 million in 2003, 2002 and 2001, respectively.

Available Credit Facilities

     At December 31, 2003, we had $930.2 million of credit facilities with commercial banks, of which $500.0 million is a three–year committed revolving credit facility (the “facility”) that expires in July 2006. The facility contains certain covenants which, among other things, require the maintenance of a funded indebtedness to total capitalization ratio (a defined formula per the facility) of less than or equal to 0.50, limit the amount of subsidiary indebtedness and restrict the sale of significant assets, defined as 10% or more of total consolidated assets. At December 31, 2003, we were in compliance with all the facility covenants, including the funded indebtedness to total capitalization ratio, which was 0.30. There were no direct borrowings under the facility during the year ended December 31, 2003; however, to the extent we have outstanding commercial paper, our ability to borrow under the facility is reduced. At December 31, 2003, we had no outstanding commercial paper.

     If market conditions were to change and revenues were to be significantly reduced or operating costs could not be controlled, our cash flows and liquidity could be reduced. Additionally, it could cause the rating agencies to lower our credit rating. We do not have any ratings triggers in the facility that would accelerate the maturity of any borrowings under the facility. However, a downgrade in our credit ratings could increase the cost of borrowings under the facility. Also, a downgrade in our credit ratings could limit or preclude our ability to issue commercial paper. Should this occur, we would seek alternative sources of funding, including borrowing under the facility.

Cash Requirements

     We believe operating cash flows combined with short–term borrowings, as needed, will provide us with sufficient capital resources and liquidity to manage our operations, meet contractual obligations, fund capital expenditures, repurchase common stock and support the development of our short–term and long–term operating strategies.

     We currently expect that 2004 capital expenditures will be between $320.0 million and $340.0 million, excluding acquisitions. The expenditures are expected to be used primarily for normal, recurring items necessary to support the growth of our business and operations.

     In 2004, we will repay the $100.0 million 8% Notes due May 2004 and the $250.0 million 7.875% Notes due June 2004. These repayments are expected to be funded with one or more of the following: cash flows from operations, available cash on hand and commercial paper borrowings. In 2004, we also expect to make interest payments of approximately $85.0 million to $95.0 million. This is based on our current expectations of debt levels during 2004.

     We have authorization remaining to repurchase up to $44.5 million in common stock. We may continue to repurchase our common stock in 2004 depending on the price of our common stock, our liquidity and other considerations. We anticipate paying dividends of $0.46 per share of common stock in 2004. However, our Board of Directors is free to change the dividend policy at any time.

     During 2004, we estimate that we will contribute approximately $35.0 million to $40.0 million to our pension plans and make benefit payments related to postretirement welfare plans of approximately $14.0 million.

     We anticipate making income tax payments of approximately $150.0 million to $180.0 million in 2004.

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     We do not believe that there are any other material trends, demands, commitments, events or uncertainties that would have, or are reasonably likely to have, a material impact on our financial condition and liquidity. Other than previously discussed, we currently have no information that would create a reasonable likelihood that the reported levels of revenues and cash flows from operations in 2003 are not indicative of what we can expect in the future.

     The following table summarizes our aggregate contractual cash obligations as of December 31, 2003 (in millions):

(1)		Amounts represent the expected cash payments for our long–term debt and do not include any unamortized discounts, deferred issuance costs or deferred gains on terminated interest rate swap agreements.
(2)		Purchase obligations include agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Purchase obligations exclude agreements that are cancelable at anytime without penalty.
(3)		Amounts represent other long–term liabilities reflected in our consolidated balance sheet where both the timing and amount of payment streams are known. Amounts include: payments for certain environmental remediation liabilities, payments for deferred compensation, payouts under acquisition agreements and payments for certain asset retirement obligations. Amounts do not include: payments for pension contributions and payments for various postretirement welfare plans and postemployment benefit plans, as such amounts have not been determined beyond 2004.

Off–Balance Sheet Arrangements

     In the normal course of business with customers, vendors and others, we are contingently liable for performance under letters of credit and other bank issued guarantees which totaled approximately $284.9 million at December 31, 2003. In addition, at December 31, 2003, we have guaranteed debt and other obligations of third parties totaling up to $34.1 million, including $15.0 million relating to Petreco. This guarantee was terminated in conjunction with the sale of Petreco in February 2004.

     Other than normal operating leases, we do not have any off–balance sheet financing arrangements such as securitization agreements, liquidity trust vehicles, synthetic leases or special purpose entities. As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such financing arrangements.

NEW ACCOUNTING STANDARDS

     Effective January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations . SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of long–lived assets. SFAS No. 143 requires that the fair value of a liability associated with an asset retirement obligation (“ARO”) be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The liability for the ARO is revised each subsequent period due to the passage of time and changes in estimates. The associated retirement costs are capitalized as part of the carrying amount of the long–lived asset and subsequently depreciated over the life of the asset.

     The adoption of SFAS No. 143 in 2003 resulted in a charge of $5.6 million, net of tax of $2.8 million, recorded as the cumulative effect of accounting change in the consolidated statement of operations. In conjunction with the adoption, we recorded ARO liabilities of $11.4 million primarily for anticipated costs of obligations associated with the future disposal of power source units at certain of our divisions and refurbishment costs associated with certain leased facilities in Europe and with a fleet of leased railcars and tanks.

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     In November 2002, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 45 (“FIN 45”), Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others . FIN 45 requires disclosures by a guarantor in its financial statements about obligations under certain guarantees that it has issued and requires a guarantor to recognize, at the inception of certain guarantees, a liability for the fair value of the obligation undertaken in issuing the guarantee. The adoption of the provisions of FIN 45 relating to the initial recognition and measurement of guarantor liabilities, which were effective for qualifying guarantees entered into or modified after December 31, 2002, did not have an impact on our consolidated financial statements. We adopted the new disclosure requirements in 2002.

     In January 2003, the FASB issued FASB Interpretation No. 46 (“FIN 46”), Consolidation of Variable Interest Entities . An entity is subject to the consolidation rules of FIN 46 and is referred to as a variable interest entity (“VIE”) if the entity’s equity investors lack the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its operations without additional financial support. In December 2003, the FASB issued modifications to FIN 46 (“FIN 46R”), resulting in multiple effective dates based on the nature as well as the creation date of a VIE. We are completing our evaluation of the provisions of the original FIN 46 and FIN 46R and do not expect the adoption to have an impact on our consolidated financial statements.

     In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities , which amends and clarifies the accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, with some exceptions for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 on July 1, 2003 had no impact on our consolidated financial statements.

     In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity , which modifies the accounting for certain financial instruments. SFAS No. 150 requires that these financial instruments be classified as liabilities and applies immediately for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS No. 150 on July 1, 2003 had no impact on our consolidated financial statements.

     In December 2003, the FASB revised SFAS No. 132, Employers’ Disclosures about Pensions and Other Postretirement Benefits . The new SFAS No. 132 requires additional disclosures about the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans, of which certain disclosures are not required until 2004. We have adopted the disclosure requirements that were effective for 2003.

     In January 2004, the FASB issued FASB Staff Position No. FAS 106–1 (“FSP 106–1”), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 , which provides temporary guidance concerning the recently enacted Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”). SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions , requires presently enacted changes in laws that will take effect in future periods to be taken into account in measuring current period postretirement benefit cost and the accumulated projected benefit obligation (“APBO”). FSP 106–1 allows companies that sponsor affected postretirement benefit plans to elect to defer recognizing the effects of the Act on postretirement benefit expense and on the APBO pursuant to SFAS No. 106. We have elected to defer accounting for the effects of the Act until 2004.

RELATED PARTY TRANSACTIONS

     In conjunction with the formation of WesternGeco in November 2000, we entered into an agreement with Schlumberger whereby a cash true–up payment will be made by either of the parties to the venture based on a formula comparing the ratio of the net present value of sales revenue from each party’s contributed multiclient seismic libraries during the four–year period ending November 30, 2004 and the ratio of the net book value of those libraries as of November 30, 2000. The maximum payment that either party will be required to make as a result of this adjustment is $100.0 million. In the event that future sales from the contributed libraries continue in the same relative percentages incurred through December 31, 2003, we currently estimate that Schlumberger will make a payment to us in the range of $5.0 million to $10.0 million. Any payment to be received by us will be recorded as an adjustment to the carrying value of our investment in WesternGeco. In November 2000, we also entered into an agreement with WesternGeco whereby WesternGeco subleased a facility from us for a period of ten years at then current market rates. In 2003 and 2002, we received payments of $5.0 million and $5.5 million, respectively, from WesternGeco related to this lease. In conjunction with the formation of WesternGeco, we transferred a lease on a seismic vessel to the venture. We were the sole guarantor of this lease obligation. During 2003, the lease and guarantee were terminated as a result of the purchase of the seismic vessel by WesternGeco.

     At December 31, 2003 and 2002, net accounts receivable from affiliates totaled $0.7 million and $16.1 million, respectively. There were no other significant related party transactions.

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FORWARD–LOOKING STATEMENTS

     MD&A and certain statements in the Notes to Consolidated Financial Statements include forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, (each a “Forward–Looking Statement”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward–looking statements. Our expectations regarding our business outlook, customer spending, oil and natural gas prices and our business environment and the industry in general are only our forecasts regarding these matters. These forecasts may be substantially different from actual results, which are affected by the following risk factors: the level of petroleum industry exploration and production expenditures; drilling rig and oil and natural gas industry manpower and equipment availability; our ability to implement and effect price increases for our products and services; our ability to control our costs; the availability of sufficient raw materials, manufacturing capacity and subcontracting capacity at forecasted costs to meet our revenue goals; the effect of competition, particularly our ability to introduce new technology on a forecasted schedule and at forecasted costs; the ability of our competitors to capture market share; our ability to retain or increase our market share; potential impairment of long–lived assets; world economic conditions; the price of, and the demand for, crude oil and natural gas; drilling activity; seasonal and other weather conditions that affect the demand for energy and severe weather conditions, such as hurricanes, that affect exploration and production activities; the legislative and regulatory environment in the U.S. and other countries in which we operate; outcome of government and internal investigations and legal proceedings; OPEC policy and the adherence by OPEC nations to their production quotas; war, military action or extended period of international conflict, particularly involving the U.S., Middle East or other major petroleum–producing or consuming regions; any future acts of war, armed conflicts or terrorist activities; civil unrest or in–country security concerns where we operate; expropriation; the development of technology by us or our competitors that lowers overall finding and development costs; new laws and regulations that could have a significant impact on the future operations and conduct of all businesses; labor–related actions, including strikes, slowdowns and facility occupations; the condition of the capital and equity markets in general; adverse foreign exchange fluctuations and adverse changes in the capital markets in international locations where we operate; and the timing of any of the foregoing. See “Key Risk Factors” for a more detailed discussion of certain of these risk factors.

     Our expectations regarding our level of capital expenditures described in “Liquidity and Capital Resources” are only our forecasts regarding these matters. In addition to the factors described in the previous paragraph, in “Business Environment,” and in “Item 1. Business–Environmental Matters,” these forecasts may be substantially different from actual results, which are affected by the following factors: the accuracy of our estimates regarding our spending requirements; regulatory, legal and contractual impediments to spending reduction measures; the occurrence of any unanticipated acquisition or research and development opportunities; changes in our strategic direction; and the need to replace any unanticipated losses in capital assets.