UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Form 10-Q

OR

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).

As of October 29, 2004, the registrant has outstanding 335,469,673 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. 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 (loss), 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 3. DISCONTINUED OPERATIONS

     In September 2004, we completed the sale of Baker Hughes Mining Tools (“BHMT”), a product line group within our Hughes Christensen division that manufactured rotary drill bits used in the mining industry. We received proceeds of $32.0 million, which are subject to post-closing adjustments to the purchase price. In the three months ended September 30, 2004, we recorded a gain on sale of $0.5 million, net of tax of $3.8 million, which consisted of a gain on disposal of $7.1 million offset by a loss of $6.6 million related to the recognition of the cumulative foreign currency translation adjustments into earnings.

     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 were subject to post-closing adjustments to 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 adjustments. The adjustments were 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.

     In January 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, 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.

     Summarized financial information from discontinued operations is as follows:

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

     Assets and liabilities of discontinued operations at December 31, 2003 are as follows:

NOTE 4. ACQUISITION

     In the second quarter of 2003, we made an acquisition with an aggregate purchase price of $12.7 million, of which $9.6 million was paid in cash. As a result of this acquisition, we recorded approximately $9.8 million of intangible assets through September 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.

NOTE 5. 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:

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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% and Schlumberger Limited (“Schlumberger”) owns 70%. 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)

     Included in the caption “Equity in income (loss) of affiliates” for the three months and nine months ended September 30, 2003 is $135.7 million for our share of the $452.0 million of certain impairment and restructuring charges taken by WesternGeco. The charges related to the impairment of WesternGeco’s multiclient seismic library and rationalization of WesternGeco’s marine seismic fleet. In addition, as a result of the continuing weakness in the seismic industry, we evaluated the value of our investment in WesternGeco and recorded an impairment loss of $45.3 million in the third quarter of 2003 to write-down the investment to its fair value. The fair value was determined using a combination of a market capitalization and discounted cash flows approach. We were assisted in the determination of the fair value by an independent third party.

     In connection 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 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 through November 30, 2004 in the same relative percentages incurred through June 30, 2004, we currently estimate that Schlumberger will make a payment to us in the range of $8.0 million to $10.0 million. We expect that the payment will be made in the first quarter of 2005. Any payment received by us will be recorded as an adjustment to the carrying value of our investment in WesternGeco.

     During the nine months ended September 30, 2003, we invested cash of $35.4 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 nine months ended September 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 nine months ended September 30, 2004 was $3.5 million and $10.3 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 $12.1 million to $15.9 million.

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

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 $1.8 million liability at September 30, 2004 based on quoted market prices for contracts with similar terms and maturity dates.

     At September 30, 2004, we had entered into several foreign currency forward contracts with notional amounts aggregating $86.0 million to hedge exposure to currency fluctuations in various foreign currencies, including the British Pound Sterling, the Euro, the Norwegian Krone, 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 September 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 September 30, 2004, we had entered into several foreign currency forward contracts with notional amounts aggregating $55.5 million to hedge exposure to currency fluctuations in the British Pound Sterling and the Canadian Dollar. These exposures arise when local currency operating expenses are not in balance with local currency revenue collections. The funding of such imbalances is supported by short-term intercompany borrowing commitments that have definitive amounts and funding dates. All fundings are scheduled to take place on or before December 31, 2004. These foreign currency forward contracts were designated as cash flow hedging instruments and are fully effective. Based on quoted market prices as of September 30, 2004 for contracts with similar terms and maturity dates, we recorded a loss of $1.0 million, net of tax of $0.6 million, to adjust these foreign currency forward contracts to their fair market value. This loss is recorded in other comprehensive income in the consolidated condensed balance sheet.

NOTE 11. SEGMENT AND RELATED INFORMATION

     We operate through seven divisions — Baker Atlas, Baker Hughes Drilling Fluids, 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.

     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 (loss) from continuing operations before income taxes, accounting changes, restructuring charges and reversals, impairment of assets and interest income and expense.

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

     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, including restructuring charges and reversals and impairment of assets. The “Corporate and Other” column at December 31, 2003 also includes assets of discontinued operations.

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

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

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:

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:

     In May 2004, the Financial Accounting Standards Board (“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 for employers that sponsor postretirement health care plans that provide prescription drug benefits. We adopted the provisions of FSP 106-2 in the third quarter of 2004, resulting in a reduction in our accumulated postretirement benefit obligation of $18.8 million. We recognized a reduction in our net periodic postretirement benefit costs of $0.7 million and $1.3 million for the three months and nine months ended September 30, 2004, respectively, as a result of the adoption of FSP 106-2. Results for the three months ended June 30, 2004 have been restated to reflect the retroactive application of FSP 106-2. The impact for the three months ended June 30, 2004 was an increase in income from continuing operations of $0.4 million, net of tax of $0.2 million. There was no impact on any other prior period.

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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 $302.2 million at September 30, 2004. We have also guaranteed debt and other obligations of third parties totaling up to $7.9 million at September 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 nine months ended September 30, 2004 are as follows:

NOTE 14. NEW ACCOUNTING STANDARDS

     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. The adoption of FIN 46 and FIN 46R in 2004 had no impact on our consolidated condensed financial statements.

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 filed an appeal and, 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 operate through seven divisions — Baker Atlas, Baker Hughes Drilling Fluids, 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.

     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 third quarter of 2004, we reported revenues of $1,538.1 million, a 15.8% increase compared with the third quarter of 2003. The increase in revenues 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, the Caspian region, Africa and Asia. These increases were partially offset by lower activity in the Gulf of Mexico due to hurricanes and in Norway due to the offshore oil workers strike. Income from continuing operations for the third quarter of 2004 was $137.3 million compared with a loss from continuing operations of $59.9 million for the third quarter of 2003. Included in the loss from continuing operations for the third quarter of 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.

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 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.

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

     The U.S. — land rig count increased 15.7% in the third quarter of 2004 compared with the third quarter of 2003 due to the increase in drilling for natural gas, which accounted for 86.1% of total U.S. drilling activity. The Canadian rig count was down 15.1% in the third quarter of 2004 compared with the third quarter of 2003. Unusually wet weather in Canada in the third quarter of 2004 resulted in fewer active rigs compared with the third quarter of 2003. The U.S. — offshore rig count decreased 12.8% in the third quarter of 2004 compared with the third quarter of 2003.

     Outside North America, rig counts increased 8.2% in the third quarter of 2004 compared with the third quarter of 2003. The rig count in Latin America increased 15.0% compared with the third quarter of 2003 driven primarily by spending increases in Mexico, Venezuela and Argentina. The North Sea rig count in the third quarter of 2004 decreased 30.6% compared with the third quarter of 2003 primarily driven by continued declines in drilling activity in the U.K. sector and the impact of an offshore oil workers strike in Norway. 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 11.3% increase in the rig count for the third quarter of 2004 compared with the third quarter of 2003. Rig counts in Africa declined 2.0% in the third quarter of 2004 compared with the third quarter of 2003. Rig activity in the Asia Pacific region was up 16.2% in the third quarter of 2004 compared with the third quarter of 2003 primarily due to activity increases in Indonesia, India and Australia.

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 $43.91/Bbl in the third quarter of 2004, continuing the increasing trend that began in September/October 2003. Oil prices remained volatile during the third quarter, rising from a low of just under $39/Bbl at the beginning of the quarter to a high of near $50/Bbl at the end of the quarter. Subsequent to the end of the quarter, oil prices have been trading above $50/Bbl. The primary factors influencing oil prices during the third quarter of 2004 included persistent low inventories, strong economic growth in both the U.S. and China, the lack of excess capacity within the Organization of Petroleum Exporting Countries (“OPEC”), hurricanes in the Gulf of Mexico and concerns over the possibility of additional disruptions of Iraqi exports.

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     During the third quarter of 2004, natural gas prices averaged $5.50/mmBtu. Prices were volatile during the quarter, ranging from $6/mmBtu in early June to a low of $4.40/mmBtu in early September, before rising to $6.45/mmBtu by the end of the quarter. High prices in the beginning of the third quarter discouraged industrial demand and allowed storage operators to build inventories. Prices fell as storage approached three trillion cubic feet and then rose again as hurricanes in the Gulf of Mexico impacted natural gas production.

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 countries in 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 and productivity 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. Weather can also impact production, for example, in the North Sea, the Gulf of Mexico and Canada.
•		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 - Oil prices rose from just below $40/Bbl in early July to over $50/Bbl in early October. Concerns over strong demand and potential supply disruptions prevailed over higher OPEC production rates during the third quarter. Prices approached $50/Bbl in mid-August driven by concerns of export disruptions in Iraq, the Venezuelan recall election and the Yukos bankruptcy in Russia, falling briefly after the peaceful election in Venezuela. Prices rose again in September and early October, exceeding $50/Bbl, as a result of hurricane-related disruptions in the Gulf of Mexico, unrest in Nigeria, and strikes in Norway, Nigeria and Brazil. Oil prices are expected to remain volatile for the balance of the year and into 2005 and to average between $35/Bbl and $55/Bbl. While the balance between supply and demand is expected to remain tight, some forecasters, including the International Energy Agency, have lowered expectations regarding oil demand growth in 2005, reflecting the impact higher prices are expected to have on oil demand and the economy.

     Natural Gas — Natural gas prices remained highly volatile during the quarter. Natural gas traded in excess of $6/mmBtu as storage requirements competed with summer demand. As storage filled and oil prices moderated, natural gas prices fell from over $6/mmBtu in early July to $4.40/mmBtu in mid-September. Prices rose again to over $6/mmBtu in early October, primarily as a result of higher oil prices and disruptions of supply caused by hurricanes in the Gulf of Mexico. Natural gas prices are expected to average between $4.50/mmBtu and $6.50/mmBtu for the balance of the year and into 2005. Natural gas drilling activity is expected to remain at current levels or improve modestly over the balance of the year. Oil and natural gas company spending to develop incremental natural gas production has not been sufficient to offset natural decline rates and natural gas markets are expected to remain tightly balanced. Prices are expected to remain volatile with trading at or beyond the extremes of the range possible in response to variations in weather-driven demand or changes in oil prices.

     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 12% to 14% in 2004 compared with 2003.
•		Outside North America — Customer spending, primarily directed at developing oil supplies, is expected to increase 14% to 16% in 2004 compared with 2003.

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Total spending is expected to increase 14% to 16% 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 10% to 12% in 2004 compared with 2003.
•		Drilling activity outside of North America is expected to increase approximately 8% to 10% in 2004 compared with 2003.

COMPANY OUTLOOK

     In our outlook for 2004, we took into account the factors described herein. Revenues are expected to increase 14% to 15% in 2004 compared with 2003. Included in this increase for 2004 is approximately $25.0 million of intellectual property license fees that will be recorded in the fourth quarter of 2004 and are not expected to recur in subsequent years. 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 $40/Bbl. Our assumptions regarding customer spending in North America assume strong economic growth in the U.S. and natural gas prices exceeding $5/mmBtu.

     In North America, we expect revenues to increase 12% to 14% 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 15% to 17% in 2004 compared with 2003, continuing the multi-year trend of modest growth in customer spending. Asia Pacific, Latin America, the Caspian region and Russia are expected to demonstrate above average spending increases, resulting in increased revenues, while growth in revenues from Europe, particularly the North Sea, is expected to be below average. Our expectations for spending and revenue growth could decrease if prices fall below $40/Bbl for oil or $5/mmBtu for natural gas or if there are disruptions in key oil and natural gas production markets, such as Venezuela or Nigeria.

     In the nine months ended September 30, 2004, WesternGeco contributed $21.9 million of equity income compared with a loss of $9.8 million for all of 2003, which excludes $135.7 million related to our portion of the restructuring and impairment charge taken by WesternGeco in the third quarter of 2003, which we recorded in “Equity in income (loss) of affiliates.” 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 $1.48 to $1.51. 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 laws and regulations, including 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 and authorities are conducting investigations into allegations of potential violations of laws. 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 laws and regulations and our Business Code of Conduct.

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DISCONTINUED OPERATIONS

     In September 2004, we completed the sale of Baker Hughes Mining Tools (“BHMT”), a product line group within our Hughes Christensen division that manufactured rotary drill bits used in the mining industry. We received proceeds of $32.0 million, which are subject to post-closing adjustments to the purchase price. In the three months ended September 30, 2004, we recorded a gain on sale of $0.5 million, net of tax of $3.8 million, which consisted of a gain on disposal of $7.1 million offset by a loss of $6.6 million related to the recognition of the cumulative foreign currency translation adjustments into earnings. 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 were subject to post-closing adjustments to 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 adjustments. The adjustments were 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. In January 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, 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 nine months ended September 30, 2004 and 2003, respectively.

Revenues

     Revenues for the three months ended September 30, 2004 increased 15.8% compared with the three months ended September 30, 2003, reflecting a 6.6% increase in worldwide rig counts. Revenues in North America, which accounted for 40.7% of total revenues, increased 12.3% for the three months ended September 30, 2004 compared with the three months ended September 30, 2003. This increase reflects increased activity in U.S. land operations, as evidenced by a 15.7% increase in the U.S. — land rig count, partially offset by weaker revenues in Canada due to unusually wet weather and the impact of hurricanes in the Gulf of Mexico. Revenues outside North America, which accounted for 59.3% of total revenues, increased 18.2% for the three months ended September 30, 2004 compared with the three months ended September 30, 2003. This increase reflects an 8.2% 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 nine months ended September 30, 2004 increased 15.7% compared with the nine months ended September 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 declines in the Gulf of Mexico due to hurricanes and in Norway due to the offshore oil workers strike.

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Cost of Revenues

     Cost of revenues for the three months ended September 30, 2004 increased 14.1% compared with the three months ended September 30, 2003. Cost of revenues for the nine months ended September 30, 2004 increased 14.0% compared with the nine months ended September 30, 2003. Cost of revenues as a percentage of consolidated revenues was 71.8% and 72.8% for the three months ended September 30, 2004 and 2003, respectively. Cost of revenues as a percentage of consolidated revenues was 72.1% and 73.2% for the nine months ended September 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, including 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 September 30, 2004 increased 18.5% compared with the three months ended September 30, 2003. SG&A expenses for the nine months ended September 30, 2004 increased 13.5% compared with the nine months ended September 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, and 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.

Impairment of Investment in Affiliate

     In 2003, 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 the third quarter of 2003 to write-down the investment to its fair value. The fair value was determined using a combination of a market capitalization and discounted cash flows approach. We were assisted in the determination of the fair value by an independent third party.

Equity in Income (Loss) of Affiliates

     Equity in income of affiliates was $10.0 million for the three months ended September 30, 2004 compared with equity in loss of affiliates of $14.2 million in the three months ended September 30, 2003, which excludes $135.7 million related to our portion of the restructuring and impairment charge taken by Western Geco in the third quarter of 2003. During 2003, the operating results of WesternGeco continued to be adversely affected by the continuing weakness in the seismic market and, 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.

Interest Expense

     Interest expense for the three months ended September 30, 2004 decreased $7.5 million compared with the three months ended September 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 nine months ended September 30, 2004 decreased $13.4 million compared with the nine months ended September 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. Results for the third quarter of 2004 include the favorable impact from a reduction in our tax rate on operating profit from 34.5% to 33.0% for the year ending December 31, 2004. This reduction was primarily a result of a change from our original estimate in the geographic mix of our pretax profits and the increased international activity. The impact of the reduction was a decrease in income taxes of $7.8 million.

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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.

LIQUIDITY AND CAPITAL RESOURCES

     Our objective in financing our business is to maintain adequate financial resources and access to additional liquidity. During the nine months ended September 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 provides back-up liquidity 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 nine months ended September 30, 2004, we used cash for a variety 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 nine months ended September 30:

     Cash flow statements for certain 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 $518.1 million in the nine months ended September 30, 2004 compared with $331.4 million in the nine months ended September 30, 2003. This increase was primarily due to increased operating performance, which is directly related to our increased revenues. In addition, changes in working capital, primarily consisting of changes in accounts receivable, inventories, accounts payable and accrued employee compensation and other accrued liabilities, used $69.7 million less in cash flows during the nine months ended September 30, 2004 when compared to the nine months ended September 30, 2003.

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

	•		An increase in accounts receivable due to increased activity used $111.2 million in cash in the first nine months of 2004 compared with using $52.1 million in cash in the first nine months of 2003.
	•		A build up of inventory in anticipation of increased activity used $42.1 million in cash in the first nine months of 2004 compared with using $57.8 million in the first nine months of 2003.

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An increase in accounts payable and accrued employee compensation and other accrued liabilities provided $76.4 million in cash in the first nine months of 2004 compared with using $36.7 million in cash in the first nine months of 2003. This was due primarily to better management of our accounts payable and $46.0 million less in net income tax payments in the first nine months of 2004 compared with the first nine 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 $242.3 million and $270.2 million for the nine months ended September 30, 2004 and 2003, respectively. The majority of these expenditures were for machinery and equipment and rental tools.

     In September 2004, we completed the sale of BHMT and received $32.0 million in proceeds, which are subject to post-closing adjustments to the purchase price. In January 2004, we completed the sale of BIRD and received $5.6 million in proceeds, which were subject to post-closing adjustments to 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 adjustments. The adjustments were 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. 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 $81.8 million and $44.7 million for the nine months ended September 30, 2004 and 2003, respectively. These disposals related to rental tools that were lost-in-hole, as well as machinery, rental tools and equipment no longer used in operations that were sold throughout the period. Included in the proceeds for the nine months ended September 30, 2004 was $12.2 million related to the sale of certain real estate properties held for sale.

Financing Activities

     We had net short-term debt payments of $6.5 million in the nine months ended September 30, 2004 compared with net short-term borrowings of $57.6 million in the nine months ended September 30, 2003. 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 September 30, 2004 was $1,121.4 million, a decrease of $363.0 million compared with December 31, 2003. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was 0.23 at September 30, 2004 and 0.31 at December 31, 2003.

     We received proceeds of $75.2 million and $38.1 million in the nine months ended September 30, 2004 and 2003, respectively, from the issuance of common stock through the exercise of stock options and 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 nine months ended September 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 nine months ended September 30, 2004.

     We paid dividends of $114.9 million and $115.8 million in the nine months ended September 30, 2004 and 2003, respectively.

Available Credit Facilities

     At September 30, 2004, we had $886.1 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 September 30, 2004, we were in compliance with all of the facility covenants. There were no direct borrowings under the facility during the nine months ended September 30, 2004; however, to the extent we have outstanding commercial paper, our ability to borrow under the facility is reduced. At September 30, 2004, we had no outstanding commercial paper or money market borrowings. We have classified $8.9 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.

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     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.

     In 2004, we expect to make interest payments of approximately $100.0 million to $110.0 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.

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 our 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 for employers that sponsor postretirement health care plans that provide prescription drug benefits. We adopted the provisions of FSP 106-2 in the third quarter of 2004, resulting in a reduction in our accumulated postretirement benefit obligation of $18.8 million. We recognized a reduction in our net periodic postretirement benefit costs of $0.7 million and $1.3 million for the three months and nine months ended September 30, 2004, respectively, as a result of the adoption of FSP 106-2. Results for the three months ended June 30, 2004 have been restated to reflect the retroactive application of FSP 106-2. The impact for the three months ended June 30, 2004 was an increase in income from continuing operations of $0.4 million, net of tax of $0.2 million. There was no impact on any other prior period.

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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; regulatory, legal and contractual impediments to spending reduction measures; 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 environment in the U.S. and other countries in which we operate; outcome of government and internal investigations and legal proceedings; receipt of license fees; 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; and the timing of any of the foregoing. See “Key Risk Factors” for a more detailed discussion of certain of these risk factors.

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 $1.8 million liability at September 30, 2004 based on quoted market prices for contracts with similar terms and maturity dates.

     At September 30, 2004, we had entered into several foreign currency forward contracts with notional amounts aggregating $86.0 million to hedge exposure to currency fluctuations in various foreign currencies, including the British Pound Sterling, the Euro, the Norwegian Krone, 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 September 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.

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     At September 30, 2004, we had entered into several foreign currency forward contracts with notional amounts aggregating $55.5 million to hedge exposure to currency fluctuations in the British Pound Sterling and the Canadian Dollar. These exposures arise when local currency operating expenses are not in balance with local currency revenue collections. The funding of such imbalances is supported by short-term intercompany borrowing commitments that have definitive amounts and funding dates. All fundings are scheduled to take place on or before December 31, 2004. These foreign currency forward contracts were designated as cash flow hedging instruments and are fully effective. Based on quoted market prices as of September 30, 2004 for contracts with similar terms and maturity dates, we recorded a loss of $1.0 million, net of tax of $0.6 million, to adjust these foreign currency forward contracts to their fair market value. This loss 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.

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 September 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 September 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. The internal investigations in Angola and Kazakhstan were substantially completed in the third quarter of 2004. Evidence obtained during the course of the investigations has been provided to the SEC and DOJ.

     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.

     We have received a subpoena from the grand jury in the Southern District of New York regarding goods and services delivered by us to Iraq from 1995 through 2003. We are in the process of responding to the subpoena. Other companies in the energy industry are believed to have received similar subpoenas.

     The SEC, DOJ and other U.S. agencies and authorities 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 any of the investigations described above will be completed. Based on current information, we cannot predict the outcome of such investigations 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 filed an appeal and, 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. Unregistered Sales of Equity Securities and Use of Proceeds

     The following table contains information about our purchases of equity securities during the third quarter of 2004.

Issuer Purchases of Equity Securities

1		Represents shares purchased from employees to pay the option exercise price related to stock-for-stock exchanges in option exercises under employee benefit plans.
2		On September 10, 2002, we announced a plan to repurchase from time to time up to $275 million of our outstanding common stock. No shares have been repurchased in 2004 under the plan. The plan has no expiration date, but may be terminated by the Board of Directors at any time. Under the plan, we have authorization remaining to repurchase up to $44.5 million in common stock.
3		On September 3, 2004, we announced the commencement of a voluntary sale program (also known as an odd-lot program) for stockholders owning fewer than 100 shares of our common stock. The shares are sold on the open market by the program’s administrator, Mellon Investor Services LLC. The program is not conditioned on receipt of a minimum number of tenders and is expected to expire on November 5, 2004, unless extended by us.

Item 3. Defaults Upon Senior Securities

     None.

Item 4. Submission of Matters to a Vote of Security Holders

     None.

Item 5. Other Information

     None.

Item 6. Exhibits

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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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EXHIBIT INDEX