UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Form 10–Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

OR

[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1–9397

Baker Hughes Incorporated

3900 Essex Lane, Suite 1200, Houston, Texas
(Address of principal executive offices)
77027
(Zip Code)

Registrant’s telephone number, including area code: (713) 439–8600

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 whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b–2).
YES [X] NO [   ]

As of July 30, 2004, the registrant has outstanding 333,749,722 shares of Common Stock, $1 par value per share.

INDEX

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

Baker Hughes Incorporated

See accompanying notes to consolidated condensed financial statements.

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Baker Hughes Incorporated

See accompanying notes to consolidated condensed financial statements.

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Baker Hughes Incorporated

See accompanying notes to consolidated condensed financial statements.

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Baker Hughes Incorporated

NOTE 1. GENERAL

Nature of Operations

     Baker Hughes Incorporated (“we,” “our” or “us”) is engaged in the oilfield services industry. We are a major supplier of wellbore related products and technology services and systems to the oil and natural gas industry on a worldwide basis and provide products and services for drilling, formation evaluation, completion and production of oil and natural gas wells.

Basis of Presentation

     Our unaudited consolidated condensed financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain information and disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited consolidated condensed financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. These unaudited consolidated condensed financial statements should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10–K for the year ended December 31, 2003. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year.

     In the notes to the unaudited consolidated condensed financial statements, all dollar and share amounts in tabulations are in millions of dollars and shares, respectively, unless otherwise indicated.

     Certain reclassifications, including reclassifications for deferred income taxes and other tax liabilities, have been made to the prior year’s consolidated condensed financial statements to conform with the current period presentation.

NOTE 2. DISCONTINUED OPERATIONS

     In July 2004, we signed an agreement for the sale of Baker Hughes Mining Tools (“BHMT”), a product line group within our Hughes Christensen division that manufactures rotary drill bits used in the mining industry. The sale is subject to various closing conditions and is expected to close in the third quarter of 2004.

     In January 2004, we completed the sale of BIRD Machine (“BIRD”), the remaining division of the former Process segment, and recorded an additional loss on sale of $0.5 million with no tax benefit. We received $5.6 million in proceeds in January 2004, which was subject to adjustment pending final completion of the purchase price, and retained certain accounts receivable, inventories and other assets. During the second quarter of 2004, we made a net payment of $6.8 million to the buyer in settlement of the final purchase price adjustment. The adjustment was the result of changes in the value of assets sold to and liabilities assumed by the buyer during the time frame in which the initial sales price was negotiated and the date of the closing of the sale.

     Effective January 1, 2003, we sold our interest in oil producing operations in West Africa and recorded a gain on sale of $4.1 million, net of a tax benefit of $0.2 million, in the first quarter of 2003. In the first quarter of 2003, we also recorded an additional loss on the sale of EIMCO Process Equipment (“EIMCO”), which was sold in November 2002, due to purchase price adjustments of $2.5 million, net of tax of $1.3 million.

     We have reclassified our consolidated condensed financial statements for all prior periods presented to reflect these operations as discontinued.

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Baker Hughes Incorporated
Notes to Consolidated Condensed Financial Statements (continued)

Summarized financial information from discontinued operations is as follows:

Assets and liabilities of discontinued operations are as follows:

NOTE 3. ACQUISITION

     In the second quarter of 2003, we made an acquisition with an aggregate purchase price of $12.6 million, of which $9.4 million was paid in cash. As a result of this acquisition, we recorded approximately $2.0 million of goodwill through June 30, 2003. The purchase price is allocated based on fair value of the acquisition. Pro forma results of operations have not been presented because the effect of this acquisition was not material to our consolidated condensed financial statements.

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Baker Hughes Incorporated
Notes to Consolidated Condensed Financial Statements (continued)

NOTE 4. COMPREHENSIVE INCOME (LOSS)

     Comprehensive income (loss) includes all changes in equity during a period except those resulting from investments by and distributions to owners. The components of our comprehensive income (loss), net of related tax, are as follows:

     Total accumulated other comprehensive loss consisted of the following:

NOTE 5. STOCK–BASED COMPENSATION

     As allowed under Statement of Financial Accounting Standards (“SFAS”) No. 123, Accounting for Stock–Based Compensation, we have elected to account for our stock–based compensation using the intrinsic value method of accounting in accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. Under this method, no compensation expense is recognized when the number of shares granted is known and the exercise price of the stock option at the time of grant is equal to or greater than the market price of our common stock. Reported net income does not include any compensation expense associated with stock options but does include compensation expense associated with restricted stock awards.

     If we had recognized compensation expense as if the fair value based method had been applied to all awards as provided for under SFAS No. 123, our pro forma net income, earnings per share (“EPS”) and stock–based compensation cost would have been as follows:

     These pro forma calculations may not be indicative of future amounts since additional awards in future years are anticipated.

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Baker Hughes Incorporated
Notes to Consolidated Condensed Financial Statements (continued)

NOTE 6. EARNINGS PER SHARE

     A reconciliation of the number of shares used for the basic and diluted EPS calculation is as follows:

NOTE 7. INVENTORIES

     Inventories are comprised of the following:

NOTE 8. INVESTMENTS IN AFFILIATES

     We have investments in affiliates that are accounted for using the equity method of accounting. The most significant of these affiliates is WesternGeco, a seismic venture in which we own 30%. Summarized unaudited operating results for WesternGeco are as follows:

     The summarized unaudited financial position of WesternGeco is as follows:

     In February 2004, we completed the sale of our minority interest in Petreco International for $35.8 million. We received $28.4 million in cash, with the remaining $7.4 million held in escrow pending the outcome of potential indemnification obligations pursuant to the sales agreement. We recognized a gain of $1.3 million, net of tax of $1.5 million.

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Baker Hughes Incorporated
Notes to Consolidated Condensed Financial Statements (continued)

     During the six months ended June 30, 2003, we invested cash of $34.1 million in affiliates, of which $30.1 million related to our 50% interest in the QuantX Wellbore Instrumentation venture (“QuantX”) with Expro International (“Expro”). The venture is engaged in the permanent in–well monitoring market and was formed in the second quarter of 2003 by combining Expro’s existing permanent monitoring business with one of our product lines. We account for our ownership in QuantX using the equity method of accounting.

NOTE 9. GOODWILL AND INTANGIBLE ASSETS

     The changes in the carrying amount of goodwill (net of accumulated amortization) for the six months ended June 30, 2004 are as follows:

     Intangible assets which are being amortized are comprised of the following:

     Amortization expense for intangible assets for the three months and six months ended June 30, 2004 was $3.5 million and $6.8 million, respectively, and is estimated to be $13.7 million for 2004. Estimated amortization expense for each of the subsequent five fiscal years is expected to be within the range of $11.9 million to $15.7 million.

NOTE 10. FINANCIAL INSTRUMENTS

     In April 2004, we entered into an interest rate swap agreement for a notional amount of $325.0 million associated with our 6.25% Notes due January 2009. Under this agreement we receive interest at a fixed rate of 6.25% and pay interest at a floating rate of six–month LIBOR plus a spread of 2.741%. The interest rate swap agreement has been designated and qualifies as a fair value hedging instrument. The interest rate swap agreement is fully effective, resulting in no gain or loss recorded in the consolidated condensed statement of operations. We recorded the fair value of the interest rate swap agreement, which was a $5.1 million liability at June 30, 2004 based on quoted market prices for contracts with similar terms and maturity dates.

     At June 30, 2004, we had entered into several foreign currency forward contracts with notional amounts aggregating $78.0 million to hedge exposure to currency fluctuations in various foreign currencies, including the British Pound Sterling, the Euro, the Norwegian Krone, the Canadian Dollar, the Brazilian Real, and the Indonesian Rupiah. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of June 30, 2004 for contracts with similar terms and maturity dates, we recorded a gain of $0.7 million to adjust these foreign currency forward contracts to their fair market value. This gain offsets designated foreign exchange losses resulting from the underlying exposures and is included in selling, general and administrative expense in the consolidated condensed statement of operations.

     At June 30, 2004, we had entered into several foreign currency forward contracts with notional amounts aggregating $28.5 million to hedge exposure to currency fluctuations in the British Pound Sterling and the Euro. These exposures arise when local currency operating expenses exceed local currency revenue collections. The funding of such expenses is supported by short–term intercompany borrowing commitments that have a definitive funding date and amount. These foreign currency forward contracts were designated as

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Baker Hughes Incorporated
Notes to Consolidated Condensed Financial Statements (continued)

cash flow hedging instruments. Based on quoted market prices as of June 30, 2004 for contracts with similar terms and maturity dates, we recorded a gain of $0.2 million to adjust these foreign currency forward contracts to their fair market value. This gain is recorded in other comprehensive income in the consolidated condensed balance sheet.

NOTE 11. SEGMENT AND RELATED INFORMATION

     Through June 2004, we operated through six divisions – Baker Atlas, Baker Oil Tools, Baker Petrolite, Centrilift, Hughes Christensen and INTEQ – that have been aggregated into the Oilfield segment because they have similar economic characteristics and because the long–term financial performance of these divisions is affected by similar economic conditions. The consolidated results are evaluated regularly by our chief operating decision maker in deciding how to allocate resources and in assessing performance.

     In July 2004, we created a new division within the Oilfield segment, Baker Hughes Drilling Fluids, that will be responsible for the oilfield drilling fluids, completion fluids and fluids environmental services businesses. These businesses were formerly part of the INTEQ division. INTEQ will continue to offer drilling and evaluation products and services.

     These operating divisions manufacture and sell products and provide services used in the oil and natural gas exploration industry, including drilling, formation evaluation, completion and production of oil and natural gas wells. They also operate in the same markets and have substantially the same customers. The principal markets include all major oil and natural gas producing regions of the world, including North America, South America, Europe, Africa, the Middle East and the Far East. Customers include major multi–national, independent and state–owned oil companies. The Oilfield segment also includes our 30% interest in WesternGeco and other similar businesses.

     We evaluate the performance of the Oilfield segment based on its segment profit (loss), which is defined as income from continuing operations before income taxes, accounting changes, restructuring charges and reversals, impairment of assets and interest income and expense.

     Summarized financial information is shown in the following table. The “Corporate and Other” column includes corporate–related items, results of insignificant operations and, as it relates to segment profit (loss), income and expense not allocated to the Oilfield segment. The “Corporate and Other” column also includes assets of discontinued operations.

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Baker Hughes Incorporated
Notes to Consolidated Condensed Financial Statements (continued)

     The following table presents the details of “Corporate and Other” segment loss:

NOTE 12. EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

     We have noncontributory defined benefit pension plans (“Pension Benefits”) covering various domestic and foreign employees. The components of net periodic benefit cost are as follows:

     In our consolidated financial statements for the year ended December 31, 2003, we disclosed that we expected to contribute approximately $35.0 million to $40.0 million to our pension plans during 2004. During the second quarter of 2004, we revised our estimate and now anticipate contributing approximately $45.0 million to $50.0 million to fund our pension plans in 2004.

Postretirement Welfare Benefits

     We provide certain postretirement health care and life insurance benefits to substantially all U.S. employees who retire and have met certain age and service requirements. The components of net periodic benefit cost are as follows:

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Baker Hughes Incorporated
Notes to Consolidated Condensed Financial Statements (continued)

NOTE 13. GUARANTEES

     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 $290.4 million at June 30, 2004. We have also guaranteed debt and other obligations of third parties totaling up to $15.5 million at June 30, 2004.

     We sell certain of our products to customers with a product warranty that provides that customers can return a defective product during a specified warranty period following the purchase in exchange for a replacement product, repair at no cost to the customer or the issuance of a credit to the customer. We accrue amounts for estimated warranty claims based upon both current and historical product sales data, warranty costs incurred and any other related information known to us.

     The changes in the aggregate product warranty liabilities for the six months ended June 30, 2004 are as follows:

NOTE 14. NEW ACCOUNTING STANDARDS

     In January 2003, the Financial Accounting Standards Board (“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. The adoption of FIN 46 and FIN 46R in 2004 had no impact on the consolidated condensed financial statements.

     In May 2004, the FASB issued FASB Staff Position No. FAS 106–2 (“FSP 106–2”), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which provides guidance on the accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”) for employers that sponsor postretirement health care plans that provide prescription drug benefits. FSP 106–2 supersedes FSP 106–1, which was issued in January 2004. FSP 106–2 is effective at the beginning of the first interim period beginning after June 15, 2004. We have not yet determined whether benefits provided by our plan are actuarially equivalent and, accordingly, our accumulated projected benefit obligation and net periodic postretirement benefit cost do not reflect any amount associated with the federal subsidy provided for in the Act.

NOTE 15. CONTINGENCY

     On May 10, 2004, the District Court of Andrews County, Texas entered a judgment in favor of LOTUS, LLC and against INTEQ in the amount of $14.8 million for lost profits resulting from a breach of contract in drilling a well to create a salt cavern for disposing of naturally occurring radioactive waste. We have asked the trial court to grant a new trial. If this request is not granted, we will pursue an appeal. While we believe we have a valid basis for appeal and intend to vigorously pursue it, our appeal could be denied and the judgment affirmed against INTEQ.

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ITEM 2. 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 our consolidated condensed financial statements and the related notes thereto, as well as our Annual Report on Form 10–K for the year ended December 31, 2003.

EXECUTIVE SUMMARY

     We are engaged in the oilfield services industry and, prior to July 2004, operated 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.

     In July 2004, we created a new division within the Oilfield segment, Baker Hughes Drilling Fluids, that will be responsible for the oilfield drilling fluids, completion fluids and fluids environmental services businesses. These businesses were formerly part of the INTEQ division. INTEQ will continue to offer drilling and evaluation products and services.

     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 service 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 the second quarter of 2004, we reported revenues of $1,499.0 million, a 14.8% increase compared with the second quarter of 2003. Income from continuing operations for the second quarter of 2004 was $116.3 million compared with $82.4 million for the second quarter of 2003. The increase in revenues and income from continuing operations was primarily a result of increased activity from land rigs drilling for natural gas in the U.S., driven by continued investment in drilling for natural gas prospects, and increased activity in certain international markets including Latin America, Russia and the Caspian and Asia. These increases were partially offset by continuing declines in activity in the Gulf of Mexico.

BUSINESS ENVIRONMENT

     Our business environment and its corresponding operating results are significantly affected by the level of energy industry spending for the exploration for and production of (“E&P”) oil and natural gas reserves. An indicator for this spending is the rig count because 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, during the completion of the oil and natural gas wells and during actual production of the hydrocarbons. This spending by oil and natural gas companies is in turn influenced strongly by 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 rigs 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 consumer 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. The rig count does not include 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

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workover, or are not significant consumers of oilfield products and services. 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.

     The U.S. – land rig count increased 16.3% in the second quarter of 2004 compared with the second quarter of 2003 due to the increase in drilling for natural gas. The Canadian rig count was flat in the second quarter of 2004 compared with the second quarter of 2003. The U.S. – offshore rig count decreased 13.8% in the second quarter of 2004 compared with the second quarter of 2003.

     Outside North America, rig counts increased 9.7% in the second quarter of 2004 compared with the second quarter of 2003. The rig count in Latin America increased 20.8% compared with the second quarter of 2003 driven primarily by spending increases by the Mexican national oil company, PEMEX, and spending increases in Venezuela and Argentina. The North Sea rig count in the second quarter of 2004 decreased 8.3% compared with the second quarter of 2003 primarily driven by continued declines in drilling activity in the U.K. sector. Major diversified oil and natural gas companies continue to redirect spending towards other larger international projects, especially in Russia and the Caspian region. Activity in the Middle East continued to rise steadily with an 8.7% increase in the rig count for the second quarter of 2004 compared with the second quarter of 2003. Rig counts in Africa declined 14.0% in the second quarter of 2004 compared with the second quarter of 2003 primarily as a result of project delays in West Africa. Rig activity in the Asia Pacific region was up 11.9% in the second quarter of 2004 compared with the second quarter of 2003 primarily due to activity increases in India and China.

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 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 $38.31/Bbl in the second quarter of 2004, continuing the increasing trend that began in September/October 2003. Oil prices remained volatile during the second quarter, rising from a low of $34.27/Bbl at the beginning of the quarter to $42.33/Bbl in early June and then falling to $35.66/Bbl in late June before rallying once more to $40.23/Bbl at the end of June. Subsequent to the end of the quarter, oil prices rose again into the low $40/Bbl. The primary factors influencing oil prices during the second quarter of 2004 included persistent low inventories, strong economic growth in both the U.S. and China, the lack of excess

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capacity within the Organization of Petroleum Exporting Countries (“OPEC”) and concerns over the possibility of additional disruptions of Iraqi exports.

     During the second quarter of 2004, natural gas prices averaged $6.10/mmBtu. Prices trended higher during the quarter, ranging from a low in mid June of $5.49/mmBtu to a high in mid May of $6.71/mmBtu. Natural gas storage levels at the beginning of the injection season, which runs from April to November, were in excess of one trillion cubic feet. Prices have remained high, discouraging industrial demand and allowing storage operators to build inventories.

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 other 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.
•		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 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.

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•		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. These changes in demand result 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, the ability to export and/or delay of activity from key oil exporting countries, including, but not limited to, Iraq, Saudi Arabia and other Middle Eastern countries, Nigeria, Norway, Russia 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 and remained low during the first six months of 2004, supporting oil prices of $36/Bbl to $42/Bbl. Oil prices are expected to decline throughout the balance of 2004 and average between $30/Bbl and $40/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 result in oil prices at the lower end of the range include slower than expected economic growth in the U.S. and China, higher than expected increases in Iraqi production growth and increased production from OPEC members Algeria, Libya and Nigeria, without offsetting reductions from the Persian Gulf members of OPEC.

     Natural Gas – In 2004, prices are expected to trade between $4/mmBtu and $7/mmBtu. Natural gas could trade at the upper end of this range if winter weather is colder than normal, if summer weather is warmer than normal, if the U.S. economy, particularly the industrial sector, exhibits greater than expected growth and continued levels of energy sector spending are not sufficient to meet the demand for natural gas. Prices could move to the lower end of this range if the U.S. economic recovery is weaker than expected or summer or winter weather is milder than expected. During the injection season, which runs from April through November, 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 9% to 11% in 2004 compared with 2003.
•		Outside North America – Customer spending, primarily directed at developing oil supplies, is expected to increase 10% to 12% in 2004 compared with 2003.
•		Total spending is expected to increase 10% to 12% in 2004 compared with 2003.

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     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 9% to 11% in 2004 compared with 2003.
•		Drilling activity outside of North America is expected to increase approximately 7% to 9% in 2004 compared with 2003.

COMPANY OUTLOOK

     In our outlook for 2004, we took into account the factors described herein. We expect that 2004 will be a stronger year than 2003, with revenues increasing 10% to 12%. 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 $30/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 9% to 11% in 2004 compared with 2003 primarily due to increased spending on land based projects offset by decreased offshore spending in the Gulf of Mexico.

     Outside North America, we expect revenues to increase 10% to 12% in 2004 compared with 2003, continuing the multi–year trend of modest growth in customer spending. The Middle East, Latin America, the Caspian region and Russia are expected to demonstrate above average spending increases, resulting in increased revenues, while growth in revenues from the North Sea is expected to be below average. Our expectations for spending and revenue growth could decrease if prices fall below $30/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 the six months ended June 30, 2004, WesternGeco contributed $12.8 million of equity income compared with a loss of $9.8 million for all of 2003. We expect the trend of improving operating results for WesternGeco to continue throughout the remainder of 2004; however, based on the historical trend of operating losses and weakness in the seismic industry in prior years, there is uncertainty regarding the future operating performance of WesternGeco.

     Based on the above forecasts, we believe that earnings per share in 2004 from continuing operations will be in the range of $1.39 to $1.45. 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 lower end 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. In addition, U.S. government agencies are conducting investigations into allegations of potential violations of laws in certain countries, including Nigeria, Angola and Kazakhstan. We anticipate that the devotion of significant resources to compliance related issues, including the necessity for 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. Compliance related issues could limit our ability to do business in these countries. 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.

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DISCONTINUED OPERATIONS

     In July 2004, we signed an agreement for the sale of Baker Hughes Mining Tools, a product line group within our Hughes Christensen division that manufactures rotary drill bits for the mining industry. The sale is subject to various closing conditions and is expected to close in the third quarter of 2004. The sale is expected to result in a gain, which is estimated not to be significant. In January 2004, we completed the sale of BIRD Machine (“BIRD”), the remaining division of the former Process segment, and recorded an additional loss on sale of $0.5 million with no tax benefit. We received $5.6 million in proceeds in January 2004, which was subject to adjustment pending final completion of the purchase price, and retained certain accounts receivable, inventories and other assets. During the second quarter of 2004, we made a net payment of $6.8 million to the buyer in settlement of the final purchase price adjustment. The adjustment was the result of changes in the value of assets sold to and liabilities assumed by the buyer during the time frame in which the initial sales price was negotiated and the date of the closing of the sale. Effective January 1, 2003, we sold our interest in oil producing operations in West Africa and recorded a gain on sale of $4.1 million, net of a tax benefit of $0.2 million, in the first quarter of 2003. In the first quarter of 2003, we also recorded an additional loss on the sale of EIMCO Process Equipment, which was sold in November 2002, due to purchase price adjustments of $2.5 million, net of tax of $1.3 million. We have reclassified our consolidated condensed financial statements for all prior periods presented to reflect these operations as discontinued. See Note 2 of the Notes to Consolidated Condensed Financial Statements 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 condensed statement of operations data and their percentage of revenues for the three months and six months ended June 30, 2004 and 2003, respectively.

Revenues

     Revenues for the three months ended June 30, 2004 increased 14.8% compared with the three months ended June 30, 2003, reflecting a 10.4% increase in worldwide rig counts. Revenues in North America, which accounted for 39.9% of total revenues, increased 9.7% for the three months ended June 30, 2004 compared with the three months ended June 30, 2003. This increase reflects increased activity in U.S. land operations, as evidenced by a 16.3% increase in the U.S. – land rig count. Revenues outside North America, which accounted for 60.1% of total revenues, increased 18.4% for the three months ended June 30, 2004 compared with the three months ended June 30, 2003. This increase reflects a 9.7% increase in rig counts outside North America, particularly in Latin America, the Middle East and Asia Pacific, coupled with limited pricing improvement in certain markets and product lines and significant revenue improvements in China and Russia.

     Revenues for the six months ended June 30, 2004 increased 15.7% compared with the six months ended June 30, 2003. Revenues were positively impacted by the increased activity from land rigs drilling for natural gas in the U.S. and Canada, driven by continued investment in drilling for natural gas prospects, and increased activity in certain international markets including the Caspian region, Russia and China. These increases were partially offset by continuing declines in the Gulf of Mexico.

Cost of Revenues

     Cost of revenues for the three months and the six months ended June 30, 2004 increased 14.0% compared with the three months and the six months ended June 30, 2003. Cost of revenues as a percentage of consolidated revenues was 71.5% and 72.0% for the

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three months ended June 30, 2004 and 2003, respectively. Cost of revenues as a percentage of consolidated revenues was 72.3% and 73.4% for the six months ended June 30, 2004 and 2003, respectively. The decreases are primarily the result of limited pricing improvement in certain markets and product lines, a change in the geographic and product mix from the sale of our products and services and improved cost control measures and lower repairs and maintenance costs at INTEQ, partially offset by increased material costs.

Selling, General and Administrative

     Selling, general and administrative expenses for the three months ended June 30, 2004 increased 12.5% compared with the three months ended June 30, 2003. SG&A expenses for the six months ended June 30, 2004 increased 11.1% compared with the six months ended June 30, 2003. These increases are primarily due to higher marketing and administrative expenses as a result of increased activity, including higher annual employee bonus expense; increased costs related to our continued focus on compliance, including our Sarbanes–Oxley implementation, legal investigations and increased staffing in our legal, compliance and audit groups; and net foreign currency exchange losses.

Equity in Income (Loss) of Affiliates

     Equity in income (loss) of affiliates increased $7.1 million in the three months ended June 30, 2004 compared with the three months ended June 30, 2003 primarily due to the increase in equity in income of WesternGeco, our most significant equity method investment, as a result of improving conditions in the seismic market.

Interest Expense

     Interest expense for the three months ended June 30, 2004 decreased $2.8 million compared with the three months ended June 30, 2003 primarily due to lower total debt levels and the effect of the interest rate swap agreement entered into in April 2004. The lower total debt levels are the result of the repayment of $350.0 million of long–term debt in the second quarter of 2004.

     Interest expense for the six months ended June 30, 2004 decreased $5.9 million compared with the six months ended June 30, 2003 primarily due to lower total debt levels and the effect of the interest rate swap agreement entered into in April 2004. The lower total debt levels are the result of the repayment of $350.0 million of long–term debt in the second quarter of 2004 and the repayment of $100.0 million of long–term debt in the first quarter of 2003.

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 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 in certain foreign jurisdictions where there was no current tax benefit and where a deferred tax asset was not recorded due to the uncertainty of its realization.

Cumulative Effect of Accounting Change

     On January 1, 2003, we adopted Statement of Financial Accounting Standards (“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 estimated useful life of the asset.

     The adoption of SFAS No. 143 in the first quarter of 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 condensed 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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LIQUIDITY AND CAPITAL RESOURCES

     Our objective in appropriately financing our business is to maintain adequate financial resources and access to additional liquidity. During the six months ended June 30, 2004, cash flows from operations and short–term borrowings were the principal sources of funding. We anticipate that this trend will continue throughout the remainder of 2004. We also have a $500.0 million 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. This facility expires in July 2006.

     Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of our company. During the six months ended June 30, 2004, we used cash for a mix of activities including working capital needs, payment of dividends, repayments of indebtedness and capital expenditures. We expect this trend to continue throughout 2004. We do not anticipate any additional material demands, commitments or other events that would require significant outlays of cash.

Cash Flows

     Cash flows provided (used) by continuing operations by type of activity were as follows for the six months ended June 30:

     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 period, as these are noncash charges. As a result, changes reflected in certain accounts on the consolidated condensed statements of cash flows may not reflect the changes in corresponding accounts on the consolidated condensed balance sheets.

Operating Activities

     Cash flows from operating activities of continuing operations provided $266.4 million in the six months ended June 30, 2004 compared with $137.0 million in the six months ended June 30, 2003. This increase was primarily due to increased operating performance, which is directly related to our increased revenues, and a $17.8 million increase in cash flows related to changes in working capital, primarily consisting of changes in accounts receivable, inventories, accounts payable and accrued employee compensation and other accrued liabilities.

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

•		An increase in accounts receivable due to increased activity used $95.1 million in cash in the first six months of 2004 compared with using $47.6 million in cash in the first six months of 2003.
•		A build up of inventory in anticipation of increased activity used $35.5 million in cash in the first six months of 2004 compared with using $38.9 million in the first six months of 2003.
•		An increase in accounts payable and accrued employee compensation and other accrued liabilities provided $39.5 million in cash in the first six months of 2004 compared with using $22.4 million in cash in the first six months of 2003. This was due primarily to better management of our accounts payable and $35.2 million less in net income tax payments in the first six months of 2004 compared with the first six months of 2003.

Investing Activities

     Our principal recurring investing activity is the funding of capital expenditures to improve the productivity of our operations. Expenditures for capital assets totaled $164.4 million and $174.2 million for the six months ended June 30, 2004 and 2003, respectively. The majority of these expenditures were for machinery and equipment and rental tools.

     In January 2004, we completed the sale of BIRD and received $5.6 million in proceeds, which was subject to adjustment pending final completion of the purchase price. In June 2004, we made a net payment of $6.8 million to the buyer of BIRD in settlement of the final purchase price adjustment. The adjustment was the result of changes in the value of assets sold to and liabilities assumed by the

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buyer during the time frame in which the initial sales price was negotiated and the date of the closing of the sale. In February 2004, we also completed the sale of our minority interest in Petreco International for $35.8 million. We received $28.4 million in cash, with the remaining $7.4 million held in escrow pending the outcome of potential indemnification obligations pursuant to the sales agreement.

     Proceeds from the disposal of assets were $39.5 million and $36.4 million for the six months ended June 30, 2004 and 2003, respectively. These disposals related to machinery, rental tools and equipment no longer used in operations that were sold throughout the period.

Financing Activities

     We had net short–term borrowings of $188.0 million and $144.2 million in the six months ended June 30, 2004 and 2003, respectively. In the second quarter of 2004, we repaid the $100.0 million 8.0% Notes due May 2004 and the $250.0 million 7.875% Notes due June 2004. In the first quarter of 2003, we repaid the $100.0 million 5.8% Notes due February 2003. These repayments were funded with cash on hand, cash flows from operations and the issuance of commercial paper.

     Total debt outstanding at June 30, 2004 was $1,311.9 million, a decrease of $172.5 million compared with December 31, 2003. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was 0.27 at June 30, 2004 and 0.31 at December 31, 2003.

     We received proceeds of $26.9 million and $34.8 million in the six months ended June 30, 2004 and 2003, respectively, from the issuance of common stock from the exercise of stock options and 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 the six months ended June 30, 2003, we repurchased 2.5 million shares at an average cost of $28.69 per share, for a total of $72.9 million. Upon repurchase, the shares were retired. We did not repurchase any shares during the six months ended June 30, 2004.

     We paid dividends of $76.5 million and $77.3 million in the six months ended June 30, 2004 and 2003, respectively.

Available Credit Facilities

     At June 30, 2004, we had $889.7 million of credit facilities with commercial banks, of which $500.0 million is a 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 June 30, 2004, we were in compliance with all of the facility covenants. There were no direct borrowings under the facility during the six months ended June 30, 2004; however, to the extent we have outstanding commercial paper, our ability to borrow under the facility is reduced. At June 30, 2004, we had $180.0 million of commercial paper and $16.0 million of money market borrowings outstanding. We have classified $27.8 million of short–term borrowings as long–term debt as we have both the ability under the facility and the intent to maintain these obligations for longer than one year.

     If market conditions were to change and revenues were to be significantly reduced or operating costs were to increase, 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 borrowing 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, pay dividends and support the development of our short–term and long–term operating strategies.

     We currently expect that 2004 capital expenditures will be between $330.0 million and $350.0 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.

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     In 2004, we 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.

     In our consolidated financial statements for the year ended December 31, 2003, we disclosed that we expected to contribute approximately $35.0 million to $40.0 million to our pension plans during 2004. During the second quarter of 2004, we revised our estimate and now anticipate contributing approximately $45.0 million to $50.0 million to fund our pension plans in 2004. We estimate that we will 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.

     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.

NEW ACCOUNTING STANDARDS

     In January 2003, the Financial Accounting Standards Board (“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. The adoption of FIN 46 and FIN 46R in 2004 had no impact on the consolidated condensed financial statements.

     In May 2004, the FASB issued FASB Staff Position No. FAS 106–2 (“FSP 106–2”), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which provides guidance on the accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”) for employers that sponsor postretirement health care plans that provide prescription drug benefits. FSP 106–2 supersedes FSP 106–1, which was issued in January 2004. FSP 106–2 is effective at the beginning of the first interim period beginning after June 15, 2004. We have not yet determined whether benefits provided by our plan are actuarially equivalent and, accordingly, our accumulated projected benefit obligation and net periodic postretirement benefit cost do not reflect any amount associated with the federal subsidy provided for in the Act.

FORWARD–LOOKING STATEMENTS

     MD&A and certain statements in the Notes to Consolidated Condensed Financial Statements, as well as this report, 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. The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward–looking statements. We undertake no obligation to publicly update or revise any forward–looking statement. Our expectations regarding our business outlook, changes in profitability, customer spending, oil and natural gas prices and our business environment and the oil and natural gas 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 rising costs and 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; the accuracy of our estimates regarding our capital spending requirements; changes in the levels of our capital expenditures due to the occurrence of any unanticipated transaction or research and development opportunities; changes in our strategic direction; the need to replace any unanticipated losses in capital 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, regulatory and business

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environment in the U.S. and other countries in which we operate; outcome of government and internal investigations and legal proceedings; changes in environmental regulations; unexpected, adverse outcomes or material increases in liability with respect to environmental remediation sites where we have been named as a potentially responsible party; the discovery of new environmental remediation sites; the discharge of hazardous materials or hydrocarbons into the environment; OPEC policy and the adherence by OPEC nations to their OPEC 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, regulations and policies that could have a significant impact on the future operations and conduct of all businesses; the effect of the level and sources of our profitability on our tax rate; changes in tax laws or tax rates in the jurisdictions in which we operate; resolution of audits by various tax authorities; ability to fully utilize our tax loss carryforwards and tax credits; 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; material adverse changes in the mining business; consummation of the sale of Baker Hughes Mining Tools 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 and in “Business Environment,” 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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     We conduct operations around the world in a number of different currencies. The majority of our significant foreign subsidiaries have designated the local currency as their functional currency. As such, future earnings are subject to change due to changes in foreign currency exchange rates when transactions are denominated in currencies other than our functional currencies. To minimize the need for foreign currency forward contracts to hedge this exposure, our objective is to manage foreign currency exposure by maintaining a minimal consolidated net asset or net liability position in a currency other than the functional currency.

     In April 2004, we entered into an interest rate swap agreement for a notional amount of $325.0 million associated with our 6.25% Notes due January 2009. Under this agreement we receive interest at a fixed rate of 6.25% and pay interest at a floating rate of six–month LIBOR plus a spread of 2.741%. The interest rate swap agreement has been designated and qualifies as a fair value hedging instrument. The interest rate swap agreement is fully effective, resulting in no gain or loss recorded in the consolidated condensed statement of operations. We recorded the fair value of the interest rate swap agreement, which was a $5.1 million liability at June 30, 2004 based on quoted market prices for contracts with similar terms and maturity dates.

     At June 30, 2004, we had entered into several foreign currency forward contracts with notional amounts aggregating $78.0 million to hedge exposure to currency fluctuations in various foreign currencies, including the British Pound Sterling, the Euro, the Norwegian Krone, the Canadian Dollar, the Brazilian Real, and the Indonesian Rupiah. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of June 30, 2004 for contracts with similar terms and maturity dates, we recorded a gain of $0.7 million to adjust these foreign currency forward contracts to their fair market value. This gain offsets designated foreign exchange losses resulting from the underlying exposures and is included in selling, general and administrative expense in the consolidated condensed statement of operations.

     At June 30, 2004, we had entered into several foreign currency forward contracts with notional amounts aggregating $28.5 million to hedge exposure to currency fluctuations in the British Pound Sterling and the Euro. These exposures arise when local currency operating expenses exceed local currency revenue collections. The funding of such expenses is supported by short–term intercompany borrowing commitments that have a definitive funding date and amount. These foreign currency forward contracts were designated as cash flow hedging instruments. Based on quoted market prices as of June 30, 2004 for contracts with similar terms and maturity dates, we recorded a gain of $0.2 million to adjust these foreign currency forward contracts to their fair market value. This gain is recorded in other comprehensive income in the consolidated condensed balance sheet.

     The counterparties to the forward contracts are major financial institutions. The credit ratings and concentration of risk of these financial institutions are monitored on a continuing basis. In the unlikely event that the counterparties fail to meet the terms of a foreign currency contract, our exposure is limited to the foreign currency rate differential.

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Item 4. Controls and Procedures

     As of the end of the period covered by this quarterly report, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a–15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This evaluation was carried out under the supervision and with the participation of our management, including our principal executive officer and principal financial officer. Based on this evaluation, these officers have concluded that, as of June 30, 2004, our disclosure controls and procedures are functioning effectively to provide reasonable assurance that the information required to be disclosed by us in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission (“SEC”) rules and forms. There has been no change in our internal controls over financial reporting during the quarter ended June 30, 2004 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

     Disclosure controls and procedures are our controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act, such as this quarterly report, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

     On March 29, 2002, we announced that we had been advised that the Securities and Exchange Commission (“SEC”) and the Department of Justice (“DOJ”) are conducting investigations into allegations of violations of law relating to Nigeria and other related matters. The SEC has issued a formal order of investigation into possible violations of provisions under the Foreign Corrupt Practices Act (“FCPA”) regarding anti–bribery, books and records and internal controls, and the DOJ has asked to interview current and former employees. On August 6, 2003, the SEC issued a subpoena seeking information about our operations in Angola and Kazakhstan as part of its ongoing investigation. We are providing documents to and cooperating fully with the SEC and DOJ. In addition, we are conducting internal investigations into these matters.

     Our ongoing internal investigations have identified issues regarding the propriety of certain payments and apparent deficiencies in our books and records and internal controls with respect to certain operations in Nigeria, Angola and Kazakhstan, as well as potential liabilities to governmental authorities in Nigeria. The investigation in Nigeria was substantially completed during the first quarter of 2003 and, based upon current information, we do not expect that any such potential liabilities will have a material adverse effect on our results of operations or financial condition. We believe the internal investigations in Angola and Kazakhstan will be substantially completed in the third quarter of 2004.

     The Department of Commerce, Department of the Navy and the DOJ (the “U.S. agencies”) are investigating compliance with certain export licenses issued to Western Geophysical from 1994 through 2000 for export of seismic equipment leased by the People’s Republic of China. We acquired Western Geophysical in August 1998 and subsequently transferred related assets to WesternGeco in December 2000. Under the joint venture formation agreement with WesternGeco, we owe indemnity to WesternGeco for certain matters. We are cooperating fully with the U.S. agencies.

     The SEC, DOJ and other U.S. agencies have a broad range of sanctions they may seek to impose in appropriate circumstances including, but not limited to, injunctive relief, disgorgement, fines and penalties and modifications to business practices and compliance programs, as well as civil and criminal charges against individuals. It is not possible to accurately predict at this time when such investigations will be completed. Based on current information, we cannot predict the outcome of any of the investigations described above or what, if any, actions may be taken by the SEC, DOJ or other U.S. agencies or authorities or the effect it may have on us.

     On May 10, 2004, the District Court of Andrews County, Texas entered a judgment in favor of LOTUS, LLC and against INTEQ in the amount of $14.8 million for lost profits resulting from a breach of contract in drilling a well to create a salt cavern for disposing of naturally occurring radioactive waste. We have asked the trial court to grant a new trial. If this request is not granted, we will pursue an appeal. While we believe we have a valid basis for appeal and intend to vigorously pursue it, our appeal could be denied and the judgment affirmed against INTEQ.

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(b)		Reports on Form 8–K:
		A Current Report on Form 8–K was filed with the SEC on April 27, 2004, to furnish under “Item 12. Results of Operations and Financial Condition” our announcement of financial results for the first quarter of 2004.
		A Current Report on Form 8–K was filed with the SEC on April 29, 2004, to report under “Item 5. Other Events and Regulation FD Disclosure” our issuance of a press release whereby we announced the results of the votes at the Annual Meeting of Stockholders held on April 28, 2004, and the succession plans for Michael E. Wiley, Chairman of the Board and Chief Executive Officer.
		A Current Report on Form 8–K was filed with the SEC on July 16, 2004, to furnish under “Item 9. Regulation FD Disclosure” our issuance of a press release whereby we announced our creation of a new division that would be responsible for oilfield drilling fluids, completion fluids and fluids environmental services businesses.
		A Current Report on Form 8–K was filed with the SEC on July 29, 2004, (a) to furnish under “Item 9. Regulation FD Disclosure” our issuance of a press release whereby we announced the signing of an agreement to sell the Baker Hughes Mining Tools business and (b) to furnish under “Item 12. Results of Operations and Financial Condition” our announcement of financial results for the second quarter of 2004.

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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Index to Exhibits

10.1		Interest Rate Swap Confirmation, dated April 7, 2004.
10.2		Restated Employment Agreement by and between Baker Hughes Incorporated and Michael B. Wiley dated August 1, 2004.
31.1		Certification of Michael E. Wiley, Chief Executive Officer, dated August 4, 2004, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.
31.2		Certification of G. Stephen Finley, Chief Financial Officer, dated August 4, 2004, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.
32		Statement of Michael E. Wiley, Chief Executive Officer, and G. Stephen Finley, Chief Financial Officer, dated August 4, 2004, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.