UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 2006

OR

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

Baker Hughes Incorporated

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		76-0207995 (I.R.S. Employer Identification No.)
3900 Essex Lane, Suite 1200, Houston, Texas (Address of principal executive offices)		77027-5177 (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 þ NO o

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES o NO þ

As of April 28, 2006, the registrant has outstanding 340,762,226 shares of Common Stock, $1 par value per share.

 

 

INDEX

		Page No.
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)
Consolidated Condensed Statements of Operations — Three months ended March 31, 2006 and 2005			2
Consolidated Condensed Balance Sheets — March 31, 2006 and December 31, 2005			3
Consolidated Condensed Statements of Cash Flows — Three months ended March 31, 2006 and 2005			4
Notes to Consolidated Condensed Financial Statements			5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			16
Item 3. Quantitative and Qualitative Disclosures About Market Risk			26
Item 4. Controls and Procedures			27
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			27
Item 1A. Risk Factors			28
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			28
Item 3. Defaults Upon Senior Securities			29
Item 4. Submission of Matters to a Vote of Security Holders			29
Item 5. Other Information			30
Item 6. Exhibits			31
Signatures			32
Master Sales Agreement
Bylaws
Annual Incentive Compensation Plan
Certification of CEO pursuant to Rule 13a-14a
Certification of CFO pursuant to Rule 13a-14a
Statement of CEO and CFO pursuant to Rule 13a-14b
Press Release dated April 28, 2006
Press Release dated April 27, 2006

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Baker Hughes Incorporated

		Three Months Ended
		March 31,
		2006				2005
Revenues		$	2,062.0			$	1,642.9
Costs and expenses:
Cost of revenues			1,349.5				1,155.6
Selling, general and administrative			272.1				220.9
Total costs and expenses			1,621.6				1,376.5
Operating income			440.4				266.4
Equity in income of affiliates			48.2				20.5
Interest expense			(16.5	)			(18.6	)
Interest income			7.3				1.9
Income from continuing operations before income taxes			479.4				270.2
Income taxes			(160.6	)			(91.8	)
Income from continuing operations			318.8				178.4
Income from discontinued operations, net of tax			20.4				1.4
Net income		$	339.2			$	179.8
Basic earnings per share:
Income from continuing operations		$	0.93			$	0.53
Income from discontinued operations			0.06				—
Net income		$	0.99			$	0.53
Diluted earnings per share:
Income from continuing operations		$	0.93			$	0.53
Income from discontinued operations			0.06				—
Net income		$	0.99			$	0.53
Cash dividends per share		$	0.13			$	0.115

See accompanying notes to consolidated condensed financial statements.

Baker Hughes Incorporated

		March 31,				December 31,
		2006				2005
		(Unaudited)				(Audited)
ASSETS
Current Assets:
Cash and cash equivalents		$	558.2			$	697.0
Short—term investments			83.9				77.0
Accounts receivable, net			1,789.0				1,673.4
Inventories			1,214.6				1,126.3
Deferred income taxes			184.1				181.2
Other current assets			71.4				68.6
Assets of discontinued operations			—				16.6
Total current assets			3,901.2				3,840.1
Investments in affiliates			720.9				678.9
Property, net			1,412.2				1,355.5
Goodwill			1,335.1				1,315.8
Intangible assets, net			193.3				163.4
Other assets			463.4				453.7
Total assets		$	8,026.1			$	7,807.4
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable		$	580.9			$	558.1
Short—term borrowings and current portion of long—term debt			6.4				9.9
Accrued employee compensation			300.6				424.5
Income taxes			199.7				141.5
Other accrued liabilities			214.9				222.9
Liabilities of discontinued operations			—				3.8
Total current liabilities			1,302.5				1,360.7
Long—term debt			1,077.0				1,078.0
Deferred income taxes and other tax liabilities			258.5				228.1
Pensions and postretirement benefit obligations			344.5				336.1
Other liabilities			90.0				106.7
Stockholders’ Equity:
Common stock			341.2				341.5
Capital in excess of par value			3,242.8				3,293.5
Retained earnings			1,558.0				1,263.2
Accumulated other comprehensive loss			(188.4	)			(188.0	)
Unearned compensation			—				(12.4	)
Total stockholders’ equity			4,953.6				4,697.8
Total liabilities and stockholders’ equity		$	8,026.1			$	7,807.4

See accompanying notes to consolidated condensed financial statements.

Baker Hughes Incorporated

		Three Months Ended
		March 31,
		2006				2005
Cash flows from operating activities:
Income from continuing operations		$	318.8			$	178.4
Adjustments to reconcile income from continuing operations to net cash flows from operating activities:
Depreciation and amortization			100.0				92.4
Amortization of net deferred gains on derivatives			(1.3	)			(1.7	)
Stock—based compensation costs			11.8				2.0
Acquired in—process research and development			2.6				—
Provision for deferred income taxes			33.0				23.1
Gain on disposal of assets			(11.8	)			(8.4	)
Equity in income of affiliates			(48.2	)			(20.5	)
Changes in operating assets and liabilities:
Accounts receivable			(77.1	)			(65.7	)
Inventories			(79.9	)			(36.0	)
Accounts payable			15.9				(8.3	)
Accrued employee compensation and other current liabilities			(151.1	)			(102.1	)
Other			(3.4	)			6.4
Net cash flows from continuing operations			109.3				59.6
Net cash flows from discontinued operations			0.4				0.7
Net cash flows from operating activities			109.7				60.3
Cash flows from investing activities:
Expenditures for capital assets			(159.1	)			(85.6	)
Acquisition of businesses, net of cash acquired			(55.4	)			—
Purchase of short—term investments			(78.1	)			—
Proceeds from maturities of short—term investments			71.2				—
Proceeds from sale of business			46.3				—
Proceeds from disposal of assets			28.7				20.6
Net cash flows from investing activities			(146.4	)			(65.0	)
Cash flows from financing activities:
Net repayments of short—term debt			(3.0	)			(50.8	)
Proceeds from issuance of common stock			29.4				60.6
Repurchase of common stock			(90.7	)			—
Dividends			(44.4	)			(38.7	)
Excess tax benefits from stock—based compensation			6.2				—
Net cash flows from financing activities			(102.5	)			(28.9	)
Effect of foreign exchange rate changes on cash			0.4				0.7
Decrease in cash and cash equivalents			(138.8	)			(32.9	)
Cash and cash equivalents, beginning of period			697.0				319.0
Cash and cash equivalents, end of period		$	558.2			$	286.1
Income taxes paid		$	80.6			$	52.2
Interest paid		$	30.0			$	35.1

See accompanying notes to consolidated condensed financial statements.

Notes to Consolidated Condensed Financial Statements

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 worldwide oil and natural gas industry 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, 2005. 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.

NOTE 2. STOCK—BASED COMPENSATION

     On January 1, 2006, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 123 — Revised 2004, Share—Based Payment (“SFAS 123(R)”), which establishes accounting for equity instruments exchanged for employee services. SFAS 123(R) is a revision of SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS 123”), and supersedes APB No. 25, Accounting for Stock Issued to Employees (“APB 25”). Under the provisions of SFAS 123(R), stock-based compensation cost is measured at the date of grant, based on the calculated fair value of the award, and is recognized as expense over the employee’s service period, which is generally the vesting period of the equity grant.

     Prior to January 1, 2006, we accounted for stock-based compensation to employees under the intrinsic value method in accordance with APB 25, as permitted under SFAS 123. Under this method, compensation cost was recognized for the difference between the quoted market price on the date of grant, less the amount, if any, the employee was required to pay for the common stock. Accordingly, we did not recognize compensation cost for our stock option awards or our employee stock purchase plan because we issue options at exercise prices equal to the market value of our stock on the date of grant and because our employee stock purchase plan was noncompensatory. We did record compensation cost for our restricted stock awards and restricted stock units.

     SFAS 123(R) also clarified the accounting in SFAS 123 related to estimating the service period for employees that are or become retirement eligible during the vesting period, requiring that the recognition of compensation expense for these employees be accelerated. This impacts the timing of expense recognition, but not the total expense to be recognized over the vesting period. In the first quarter of 2005, we adopted this new methodology on a prospective basis. The cumulative effect of this clarification was $11.8 million, net of tax, and related only to stock option awards. We have included this amount in our pro forma disclosure for stock-based compensation costs for the three months ended March 31, 2005.

     We adopted SFAS 123(R) using the modified prospective application method and, accordingly, no prior periods have been restated. Under this method, compensation cost recognized during the three months ended March 31, 2006 include: (a) compensation cost for all stock-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of SFAS 123, and (b) compensation cost for all stock-based payments granted after January 1, 2006, based on the grant-date fair value estimated in accordance with SFAS 123(R). Additionally, compensation cost is recognized based on awards ultimately expected to vest, therefore, we have reduced the cost for estimated forfeitures based on historical forfeiture rates. SFAS 123(R) requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods to reflect actual forfeitures. As a result of the adoption of SFAS 123(R), the balance in unearned compensation recorded in stockholders’ equity as of January 1, 2006, of $12.4 million, net of tax, was reclassified to and reduced the balance of additional paid in capital.

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

     The following table summarizes stock—based compensation costs recognized under SFAS 123(R) for the three months ended March 31, 2006 and under APB 25 for three months ended March 31, 2005. There were no stock—based compensation costs capitalized as the amounts were not material.

		Three Months Ended
		March 31,
		2006				2005
Cost of sales		$	3.2			$	0.3
Selling, general and administrative			8.6				1.7
Stock—based compensation costs			11.8				2.0
Tax benefit			(2.8	)			(0.7	)
Stock—based compensation costs, net of tax		$	9.0			$	1.3

     The application of SFAS 123(R) had the following effect on the as reported amounts for the three months ended March 31, 2006 compared to amounts that would have been reported using the intrinsic value method pursuant to our previous accounting:

										Intrinsic
										Value
						SFAS 123(R)				Method
		As Reported				Effect				(APB 25)
Income from continuing operations before income taxes		$	479.4			$	7.1			$	486.5
Income from continuing operations			318.8				5.7				324.5
Net income			339.2				5.7				344.9
Basic earnings per share:
Income from continuing operations		$	0.93			$	0.02			$	0.95
Net income		$	0.99			$	0.02			$	1.01
Diluted earnings per share:
Income from continuing operations		$	0.93			$	0.02			$	0.95
Net income		$	0.99			$	0.02			$	1.01
Cash flows from operating activities		$	109.7			$	6.2			$	115.9
Cash flows from financing activities			(102.5	)			(6.2	)			(108.7	)

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

     If we had recognized compensation expense during the three months ended March 31, 2005 by applying the fair value based method to all awards as provided for under SFAS 123, our pro forma net income, earnings per share (“EPS”) and stock—based compensation costs would have been as follows:

		Three Months
		Ended
		March 31, 2005
Net income, as reported		$	179.8
Add: Stock—based compensation for restricted stock awards and units included in reported net income, net of tax			1.3
Deduct: Stock—based compensation determined under SFAS 123, net of tax			(17.7	)
Pro forma net income		$	163.4
Basic EPS:
As reported		$	0.53
Pro forma		$	0.48
Diluted EPS:
As reported		$	0.53
Pro forma		$	0.48

     For our stock options and restricted stock awards and units, we currently have 39.0 million shares authorized for issuance and as of March 31, 2006, approximately 10.9 million shares were available for future grants. Our policy is to issue new shares for exercises of stock options; vesting of restricted stock awards and units; and issuances under the employee stock purchase plan.

Stock Options

     Our stock option plans provide for the issuance of incentive and non—qualified stock options to directors, officers and other key employees at an exercise price equal to the fair market value of the stock at the date of grant. Substantially all of the stock options become exercisable in three equal annual installments, beginning a year from the date of grant, and generally expire ten years from the date of grant. The stock option plans provide for the acceleration of vesting upon the employee’s retirement. Therefore, we reduced the service period for employees that are or will become retirement eligible during the vesting period and, accordingly, the recognition of compensation expense for these employees will be accelerated. Compensation cost related to stock options is recognized on a straight-line basis over the vesting or service period and is net of forfeitures.

     The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes option pricing model. The following table presents the weighted-average assumptions used in the option pricing model for the three months ended March 31, 2006 and 2005. The expected life of the options represents the period of time the options are expected to be outstanding. For the three months ended March 31, 2005, the expected life was based on historical trends. For the three months ended March 31, 2006, the expected life is based on our historical exercise trends and post-vest termination data incorporated into a forward looking stock price model. For the three months ended March 31, 2005, our expected volatility is based on the historical volatility of our stock for a period approximating the expected life. For the three months ended March 31, 2006, as allowed under Staff Accounting Bulletin 107 (“SAB 107”), the expected volatility is based on our implied volatility, which is the volatility forecast that is implied by the prices of our actively traded options to purchase our stock observed in the market. The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the options were granted. The dividend yield is based on our history of dividend payouts.

		2006				2005
		Actual				Pro forma
Expected life (years)			5	.0			3	.5
Risk—free interest rate			4	.5%			3	.5%
Volatility			29	.4%			35	.3%
Dividend yield			0	.7%			1	.1%
Weighted—average fair value per share at grant date		$	23	.78		$	11	.95

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

     A summary of our stock option activity and related information is presented below (in thousands, except per option prices):

						Weighted—
						Average
						Exercise Price
		Number of Options				Per Option
Outstanding at December 31, 2005			5,575			$	38.84
Granted			303				75.06
Exercised			(888	)			33.50
Forfeited			(147	)			41.96
Outstanding at March 31, 2006			4,843			$	42.02

     For the three months ended March 31, 2006, the total intrinsic value of stock options (defined as the amount by which the market price of the underlying stock on the date of exercise exceeds the exercise price of the option) exercised was $33.1 million and the income tax benefit realized from stock options exercised was $7.5 million. As of March 31, 2006, there was $14.1 million of total unrecognized compensation cost related to nonvested stock options. That cost is expected to be recognized over a weighted—average period of 1.4 years.

     The following table summarizes information about stock options outstanding as of March 31, 2006 (in thousands, except per option prices and remaining life):

		Outstanding												Exercisable
						Weighted—
						Average
						Remaining				Weighted—								Weighted—
						Contractual				Average								Average
		Number of				Life				Exercise Price				Number of				Exercise Price
Range of Exercise Prices		Options				(In years)				Per Option				Options				Per Option
$  8.80 — $19.13			10				4.6			$	15.73				10			$	15.73
20.41 —   29.25			644				4.4				26.17				644				26.17
30.25 —   35.88			1,217				7.2				34.22				825				33.91
36.00 —   47.81			2,023				6.5				42.35				993				44.16
56.21 —   75.06			949				9.5				62.23				1				56.21
Total			4,843				7.0			$	42.02				2,473			$	35.95

     The aggregate intrinsic value of stock options outstanding at March 31, 2006 was $127.8 million, of which $80.3 million relates to awards vested and exercisable and $47.5 million relates to awards expected to vest. The intrinsic value for stock options outstanding is calculated as the amount by which the quoted price of our common stock as of March 31, 2006 exceeds the exercise price of the option.

Restricted Stock Awards and Units

     In addition to stock options, officers, directors and key employees may be granted restricted stock awards (“RSA”), which is an award of common stock with no exercise price or restricted stock units (“RSU”), where each unit represents the right to receive at the end of a stipulated period one unrestricted share of stock with no exercise price. RSAs and RSUs are subject to cliff or graded vesting, generally ranging over a three to five year period. We determine the fair value of restricted stock awards and restricted stock units based on the market price of our common stock on the date of grant. Compensation cost for RSAs and RSUs is recognized on a straight-line basis over the vesting or service period and is net of forfeitures.

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

     A summary of our RSA and RSU activity and related information is presented below (in thousands, except per share/unit prices):

						Weighted—								Weighted—
		RSA				Average				RSU				Average
		Number of				Fair Value				Number of				Fair Value
		Shares				Per Share				Units				Per Unit
Nonvested balance at December 31, 2005			669			$	42.22				77			$	42.60
Granted			258				74.70				73				75.06
Vested			(188	)			39.70				(26	)			42.60
Forfeited			(3	)			42.60				(1	)			42.60
Nonvested balance at March 31, 2006			736			$	54.25				123			$	61.90

     The total grant—date fair value of RSA’s and RSU’s vested during the three months ended March 31, 2006 was $8.6 million. As of March 31, 2006, there was $33.4 million and $6.8 million of total unrecognized compensation cost related to nonvested RSAs and RSUs, respectively. That cost is expected to be recognized over a weighted—average period of 2.6 years.

Employee Stock Purchase Plan

     Our Employee Stock Purchase Plan (“ESPP”) allows eligible employees to purchase shares of our stock at 85% of market value on the first or last business day, whichever is lower, of the 2006 calendar year. Purchases are limited to 10% of an employee’s regular salary. We currently have 14.5 million shares authorized for issuance under the ESPP and at March 31, 2006, there were 3.4 million shares reserved for future issuance under the ESPP. Compensation expense determined under SFAS 123(R) for the three months ended March 31, 2006 was calculated using the Black-Scholes option pricing model with the following assumptions:

		2006				2005
		Actual				Pro forma
Expected life (years)			1	.0			1	.0
Interest rate			4	.4%			2	.7%
Volatility			28	.0%			26	.6%
Dividend yield			0	.9%			1	.1%
Weighted—average fair value per share at grant date		$	7	.68		$	4	.76

     We calculated estimated volatility using historical daily prices based on the expected life of the stock purchase plan. The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the ESPP shares were granted. The dividend yield is based on our history of dividend payouts.

NOTE 3. DISCONTINUED OPERATIONS

     In the fourth quarter of 2005, our management initiated and our Board of Directors approved a plan to sell the Baker Supply Products Division (“Baker SPD”), a product line group within the Completion and Production segment, which distributes basic supplies, products and small tools to the drilling industry. In March 2006, we completed the sale of Baker SPD and received cash proceeds of $42.5 million. We recorded a gain on the sale of $19.2 million, net of tax of $11.0 million, which consisted of an after-tax gain on the disposal of $16.9 million and $2.3 million related to the recognition of the cumulative foreign currency translation adjustments. We have reclassified our consolidated condensed financial statements for all prior periods presented to reflect Baker SPD as a discontinued operation.

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

     Summarized financial information for Baker SPD is as follows:

		Three Months Ended
		March 31,
		2006				2005
Revenues		$	6.7			$	7.7
Income before income taxes		$	1.8			$	2.2
Income taxes			(0.6	)			(0.8	)
Income before gain on sale			1.2				1.4
Gain on sale, net of tax			19.2				—
Income from discontinued operations		$	20.4			$	1.4

NOTE 4. ACQUISITION

     In January 2006, we acquired Nova Technology Corporation (“Nova”) for $58.4 million in cash plus assumed debt. Nova is a leading supplier of permanent monitoring, chemical injection systems, and multi—line services for deepwater and subsea oil and gas well applications and is included in the Production Optimization business unit of the Completion and Production segment. As a result of the acquisition, we recorded $29.7 million of goodwill and $24.3 million of intangibles. We also assigned $2.6 million to in—process research and development that was written off at the date of acquisition. This write—off is included in research and development expenses, which are included in cost of revenues in the consolidated condensed statement of operations. The purchase price was allocated based on the fair value of the assets acquired and liabilities assumed of Nova. The fair values were determined using a discounted cash flow approach. Pro forma results of operations have not been presented because the effect of this acquisition was not material to our consolidated condensed financial statements. Under the terms of the purchase agreement, the former owners of Nova are entitled to additional purchase price consideration of up to $3.0 million based on certain post closing events.

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:

		Three Months Ended
		March 31,
		2006				2005
Net income		$	339.2			$	179.8
Other comprehensive income (loss):
Foreign currency translation adjustments:
Translation adjustments during the period			1.9				(16.9	)
Reclassifications included in net income due to sale of Baker SPD			(2.3	)			—
Other			—				(1.9	)
Total comprehensive income		$	338.8			$	161.0

     Total accumulated other comprehensive loss consisted of the following:

		March 31,				December 31,
		2006				2005
Foreign currency translation adjustments		$	(117.8	)		$	(117.4	)
Pension adjustment			(69.5	)			(69.5	)
Other			(1.1	)			(1.1	)
Total accumulated other comprehensive loss		$	(188.4	)		$	(188.0	)

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:

		Three Months Ended
		March 31,
		2006				2005
Weighted average common shares outstanding for basic EPS			341.2				337.7
Effect of dilutive securities — stock plans			1.5				1.8
Adjusted weighted average common shares outstanding for diluted EPS			342.7				339.5
Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than average market price for the period			0.3				1.8

NOTE 7. INVENTORIES

     Inventories are comprised of the following:

		March 31,				December 31,
		2006				2005
Finished goods		$	969.5			$	914.5
Work in process			163.6				134.2
Raw materials			81.5				77.6
Total		$	1,214.6			$	1,126.3

NOTE 8. PROPERTY

     Property is comprised of the following:

		March 31,				December 31,
		2006				2005
Land		$	39.4			$	39.7
Buildings and improvements			623.0				611.7
Machinery and equipment			2,084.2				2,022.3
Rental tools and equipment			1,209.6				1,157.5
Total property			3,956.2				3,831.2
Accumulated depreciation			(2,544.0	)			(2,475.7	)
Property — net		$	1,412.2			$	1,355.5

NOTE 9. GOODWILL AND INTANGIBLE ASSETS

     The changes in the carrying amount of goodwill are detailed below by segment:

		Drilling				Completion
		and				and
		Evaluation				Production				Total
Balance as of December 31, 2005		$	904.1			$	411.7			$	1,315.8
Goodwill from acquisitions during the period			—				29.7				29.7
Adjustments to final purchase price of previous acquisition			—				(10.7	)			(10.7	)
Translation adjustments and other			0.1				0.2				0.3
Balance as of March 31, 2006		$	904.2			$	430.9			$	1,335.1

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

     Intangible assets are comprised of the following:

		March 31, 2006												December 31, 2005
		Gross												Gross
		Carrying				Accumulated								Carrying				Accumulated
		Amount				Amortization				Net				Amount				Amortization				Net
Technology based		$	227.0			$	(75.3	)		$	151.7			$	204.8			$	(71.3	)		$	133.5
Contract based			11.9				(5.8	)			6.1				11.1				(6.5	)			4.6
Marketing related			8.2				(5.6	)			2.6				6.1				(5.6	)			0.5
Customer based			13.3				(0.7	)			12.6				6.4				(0.4	)			6.0
Other			1.5				(0.8	)			0.7				1.2				(0.7	)			0.5
Total amortizable intangible assets			261.9				(88.2	)			173.7				229.6				(84.5	)			145.1
Marketing related intangible assets with an indefinite useful life			19.6				—				19.6				18.3				—				18.3
Total		$	281.5			$	(88.2	)		$	193.3			$	247.9			$	(84.5	)		$	163.4

     Intangible assets are amortized either on a straight—line basis with estimated useful lives ranging from 1 to 20 years, or on a basis that reflects the pattern in which the economic benefits of the intangible assets are consumed, which range from 15 to 30 years.

     Amortization expense for intangible assets included in net income for the three months ended March 31, 2006 was $5.4 million and is estimated to be $20.3 million for 2006. Estimated amortization expense for each of the subsequent five fiscal years is expected to be within the range of $12.0 million to $18.4 million.

NOTE 10. FINANCIAL INSTRUMENTS

Foreign Currency Forward Contracts

     At March 31, 2006, we had entered into several foreign currency forward contracts with notional amounts aggregating $55.0 million to hedge exposure to currency fluctuations in various foreign currencies, including the British Pound Sterling, the Norwegian Krone and the Euro. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of March 31, 2006 for contracts with similar terms and maturity dates, we recorded a gain of $0.3 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 our consolidated condensed statement of operations.

Commodity Swaps

     At March 31, 2006, we had entered into swap agreements for 4.5 million pounds of copper to reduce our exposure to fluctuations in the price of copper. These contracts mature over the remainder of 2006. The swap agreements were not designated as hedging instruments for accounting purposes. Based on quoted market prices as of March 31, 2006 for contracts with similar terms and maturity dates, we recorded a gain of $1.0 million to adjust these contracts to their fair market value. This gain is included in cost of revenues in our consolidated condensed statement of operations.

NOTE 11. SEGMENT AND RELATED INFORMATION

     We have organized our seven product-line focused divisions into two segments: the Drilling and Evaluation segment, which consists of the Baker Atlas, Baker Hughes Drilling Fluids, Hughes Christensen and INTEQ divisions, and the Completion and Production segment, which consists of the Baker Oil Tools, Baker Petrolite and Centrilift divisions. The Completion and Production segment also includes our Production Optimization business unit. Our segments are aligned based on the types of products and services provided to our customers, to provide additional focus on our product lines and technology and to be able to more effectively serve our customers.

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

     Accordingly, we are reporting our results under three segments; Drilling and Evaluation, Completion and Production and WesternGeco, a seismic venture in which, as of March 31, 2006, we owned 30% and Schlumberger Limited (“Schlumberger”) owned 70%, which is accounted for using the equity method of accounting. Divisions in the Drilling and Evaluation segment generally provide services and products used directly in the drilling and formation evaluation of oil and natural gas wells. Divisions in the Completion and Production segment provide services and products used to complete wells, rework existing wells and enhance or initiate production from new wells. We have aggregated the divisions within each segment because they have similar economic characteristics and because the long-term financial performance of these divisions is affected by similar economic conditions. They also operate in the same markets, which includes all of the major oil and natural gas producing regions of the world. The results of each segment are evaluated regularly by our chief operating decision maker in deciding how to allocate resources and in assessing performance. We sold our 30% minority interest in WesternGeco on April 28, 2006.

     The performance of our segments is evaluated based on segment profit (loss), which is defined as income from continuing operations before income taxes 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 segments. The “Corporate and Other” column also includes assets of discontinued operations as of December 31, 2005.

		Drilling				Completion
		and				and								Total				Corporate
		Evaluation				Production				WesternGeco				Oilfield				and Other				Total
Revenues
Three months ended March 31, 2006		$	1,084.5			$	977.5			$	—			$	2,062.0			$	—			$	2,062.0
Three months ended March 31, 2005			839.3				803.2				—				1,642.5				0.4				1,642.9
Segment profit (loss)
Three months ended March 31, 2006		$	280.3			$	207.7			$	47.9			$	535.9			$	(56.5	)		$	479.4
Three months ended March 31, 2005			158.5				151.5				19.3				329.3				(59.1	)			270.2
Total assets
As of March 31, 2006		$	3,403.9			$	3,120.5			$	729.5			$	7,253.9			$	772.2			$	8,026.1
As of December 31, 2005			3,221.9				2,882.6				688.0				6,792.5				1,014.9				7,807.4

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

		Three Months Ended
		March 31,
		2006				2005
Corporate and other expenses		$	(47.3	)		$	(42.4	)
Interest, net			(9.2	)			(16.7	)
Total		$	(56.5	)		$	(59.1	)

NOTE 12. EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

     We have noncontributory defined benefit pension plans (“Pension Benefits”) covering employees primarily in the U.S., the United Kingdom and Germany. The components of net periodic benefit cost are as follows:

		U.S. Pension Benefits								Non-U.S. Pension Benefits
		Three Months Ended								Three Months Ended
		March 31,								March 31,
		2006				2005				2006				2005
Service cost		$	6.6			$	5.7			$	0.8			$	0.6
Interest cost			3.2				3.0				3.5				3.6
Expected return on plan assets			(7.9	)			(6.4	)			(3.7	)			(3.4	)
Recognized actuarial loss			0.2				0.6				0.6				0.7
Net periodic benefit cost		$	2.1			$	2.9			$	1.2			$	1.5

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

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:

		Three Months Ended
		March 31,
		2006				2005
Service cost		$	1.9			$	1.6
Interest cost			2.4				2.4
Amortization of prior service cost			0.2				0.1
Recognized actuarial loss			0.5				0.5
Net periodic benefit cost		$	5.0			$	4.6

NOTE 13. GUARANTEES

     In the normal course of business with customers, vendors and others, we have entered into off—balance sheet arrangements, such as letters of credit and other bank issued guarantees, which totaled approximately $334.9 million at March 31, 2006. None of the off—balance sheet arrangements either has, or is likely to have, a material effect on our consolidated condensed financial statements.

     We sell certain products 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 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 are as follows:

Balance as of December 31, 2005		$	13.4
Claims paid			(0.9	)
Additional warranties issued			1.3
Other			(0.2	)
Balance as of March 31, 2006		$	13.6

NOTE 14. NEW ACCOUNTING STANDARDS

     In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and No. 140 (“SFAS 155”). SFAS 155 amends SFAS 133, which required that a derivative embedded in a host contract that does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS 155 amends SFAS 133 to narrow the scope exception to strips that represent rights to receive only a portion of the contractual interest cash flows or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS 155 amends SFAS 140, which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS 155 amends SFAS 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to beneficial interests that itself is a derivative financial instrument. SFAS 155 is effective for all financial instruments acquired or issued (or subject to a remeasurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. We will adopt SFAS 155 on January 1, 2007, and we do not expect this standard to have a material impact, if any, on our consolidated condensed financial statements.

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

NOTE 15. INVESTMENTS IN AFFILIATES AND SUBSEQUENT EVENT

     We have investments in affiliates that are accounted for using the equity method of accounting. The most significant of these affiliates is WesternGeco. Summarized unaudited operating results for WesternGeco are as follows:

		Three Months Ended
		March 31,
		2006				2005
Revenues		$	529.5			$	378.1
Operating income			157.9				62.5
Net income			138.3				56.3

     The summarized unaudited financial position of WesternGeco is as follows:

		March 31,				December 31,
		2006				2005
Current assets		$	1,195.5			$	1,083.6
Noncurrent assets			1,092.0				1,047.5
Total assets		$	2,287.5			$	2,131.1
Current liabilities		$	528.3			$	514.5
Noncurrent liabilities			88.4				84.7
Stockholders’ equity			1,670.8				1,531.9
Total liabilities and stockholders’ equity		$	2,287.5			$	2,131.1

     In February 2004, we completed the sale of our minority interest in Petreco International, a venture we entered into in 2001, for $35.8 million, of which $7.4 million was placed in escrow pending the outcome of potential indemnification obligations pursuant to the sales agreement. We received $3.7 million in May 2005 and $3.8 million in March 2006 from the release of the amount held in escrow plus interest.

     In April 2006, we signed an agreement to sell to Schlumberger for $2.4 billion in cash our 30% minority interest in WesternGeco, a seismic venture jointly owned with Schlumberger. The sale was completed on April 28, 2006. We expect to record a pre—tax gain of approximately $1.74 billion (approximately $1.05 billion, net of tax). Cash proceeds are estimated to be approximately $1.8 billion, net of tax, and include a cash distribution of $59.6 million made immediately prior to closing. We plan to use the net after—tax cash proceeds to repurchase stock; accordingly, in April 2006, our Board of Directors increased our stock repurchase authorization by an additional $1.8 billion.

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, 2005.

EXECUTIVE SUMMARY

     We are a leading provider of drilling, formation evaluation, completion and production products and services to the worldwide oil and natural gas industry. We compete as one of the three largest diversified oilfield services companies. We report our product-line focused divisions in two separate segments: the Drilling and Evaluation segment and the Completion and Production segment. The segments are aligned by product line based on the types of products and services provided to our customers and on the business characteristics of the divisions during business cycles. Activity of the businesses under the Drilling and Evaluation segment is closely correlated to rig counts and, therefore, is prone to cyclicality as drilling activity increases or decreases. Activity of businesses in the Completion and Production segment is more dependent on production volumes and, therefore, is less cyclical than the Drilling and Evaluation segment. Prior to April 28, 2006, we owned a 30% interest in WesternGeco, a seismic venture with Schlumberger Limited (“Schlumberger”). Accordingly, we report our results under three segments - Drilling and Evaluation, Completion and Production and WesternGeco. On April 28, 2006, we completed the sale of our 30% minority interest in WesternGeco to Schlumberger.

•

The Drilling and Evaluation segment consists of Baker Hughes Drilling Fluids (drilling fluids), Hughes Christensen (oilfield drill bits), INTEQ (conventional and rotary directional drilling, measurement-while-drilling and logging-while-drilling) and Baker Atlas (wireline formation evaluation and wireline completion services). The Drilling and Evaluation segment provides products and services used to drill and evaluate oil and natural gas wells.

	•		The Completion and Production segment consists of Baker Oil Tools (workover, fishing and completion equipment), Baker Petrolite (oilfield specialty chemicals) and Centrilift (electric submersible pumps and progressing cavity pumps). The Completion and Production segment also includes our Production Optimization business unit (permanent downhole monitoring). The Completion and Production segment provides equipment and services used from the completion phase through the productive life of oil and natural gas wells.
	•		The WesternGeco segment consisted of our equity interest in WesternGeco.

     The business operations of our divisions are organized around four primary geographic regions: North America; Latin America; Middle East and Asia Pacific; and Europe, Africa, Russia and the Caspian. Each region has a council comprised of regional vice presidents from each division as well as representatives from various functions such as human resources, legal, marketing and health, safety and environmental. The regional vice presidents report directly to each division president. Through this structure, we have placed our management closer to the customer, improving our customer relationships and allowing us to react more quickly to local market conditions and needs.

     Our headquarters are in Houston, Texas, and we have significant manufacturing operations in various countries, including, but not limited to, the United States (Texas, Oklahoma and Louisiana), Scotland (Aberdeen and East Kilbride), Germany (Celle), Northern Ireland (Belfast) and Venezuela (Maracaibo). We operate in over 90 countries around the world and employ approximately 30,300 employees — about one—half of which work outside the U.S.

     In the first quarter of 2006, we reported revenues of $2,062.0 million, a 25.5 % increase compared with the first quarter of 2005 outpacing the 17.7% increase in the worldwide average rig count. Income from continuing operations for the first quarter of 2006 was $318.8 million, a 78.7% increase compared with $178.4 million in the first quarter of 2005. The Baker Hughes worldwide rig count continued to increase, as oil and natural gas companies around the world recognized the need to build productive capacity to meet the growing demand for hydrocarbons and to offset depletion of existing developed reserves. In addition to the growth in our revenues from increased activity, our revenues and net income were impacted by pricing improvements and changes in market share in certain product lines.

•

North American revenues increased 31.1% in the first quarter of 2006 compared with the first quarter of 2005, while the rig count increased 21.3% for the first quarter of 2006 compared with the first quarter of 2005, driven primarily by land-based drilling for natural gas.

	•		Latin American revenues increased 18.6% in the first quarter of 2006 compared with the first quarter of 2005, while the Latin American rig count was flat.
	•		Europe, Africa, Russia and the Caspian revenues increased 21.4% in the first quarter of 2006 compared with the first quarter of 2005, while the rig count increased 18.8%.
	•		Middle East and Asia Pacific revenues were up 22.1% in the first quarter of 2006 compared with the first quarter of 2005. Revenue from the Middle East was up 17.5% compared to a rig count, as restated below, which increased 18.9% and Asia Pacific revenue was up 27.0% compared to a rig count which increased 11.9%.

     The execution of our 2006 business plan and the ability to meet our 2006 financial objectives are dependent on a number of factors. These factors include, but are not limited to, our ability to: recruit, train and retain the skilled and diverse workforce necessary to meet our business needs; realize price increases commensurate with the value we provide to our customers and in excess of the increase in raw material and labor costs; expand our business in areas that are growing rapidly with customers whose spending is expected to increase substantially, such as state—owned national oil companies (“NOCs”), and in areas where we have market share opportunities (such as the Middle East, Russia and the Caspian region); manage increasing raw material and component costs (especially steel alloys, copper, carbide, chemicals and electronic components); continue to make ongoing improvements in the productivity of our manufacturing organization.

     For a full discussion of risk factors and forward-looking statements, please see “Part II, Item 1A. Risk Factors” and “Forward-Looking Statements” sections, both contained herein.

BUSINESS ENVIRONMENT

     Our business environment and its corresponding operating results are significantly affected by the level of energy industry spending for the exploration and production (“E&P”) of 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 oil and natural gas wells and during actual production of the hydrocarbons. This E&P 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 and U.S. workover rigs. Published international rig counts do not include rigs drilling in certain locations, such as Russia, onshore China and other countries, because this information is extremely difficult to obtain or we do not have local resources to make an accurate count.

     Rigs in the U.S. 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, which may change from time to time and may vary from region to region, and is expected to be a potential consumer of our drill bits. In general, rigs are counted as active if the well has been started but has not reached its target depth, even if there are extensive delays due to weather or other reasons. If the well has been started but not completed and the rig is expected to resume work in two weeks or less, the rig is counted as active during a weather delay. Rigs are not typically counted as active if the rig is lost or damaged or if drilling operations are expected to be suspended for more than two weeks.

     Rigs in Canada are counted as active if data obtained by the Canadian Association of Oilwell Drillers and Contractors indicates that drilling operations have occurred during the week and we are able to verify this information. In most other international areas, rigs are counted as active if drilling operations have taken place for at least 15 days during the month. In some active international areas where better data is available, a weekly or daily average of active rigs is taken. In those international areas where there is poor availability of data, the rig counts are estimated or quoted from third party data.

     The rig count does not include rigs that are in transit from one location to another, are rigging up, are being used in non-drilling activities, including production testing, completion and workover, or are not, in our opinion, deemed to be a potential user of our drill bits.

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

		Three Months Ended
		March 31,
		2006				2005 1
U.S. — land and inland waters			1,441				1,178
U.S. — offshore			81				101
Canada			661				521
North America			2,183				1,800
Latin America			313				313
North Sea			53				34
Other Europe			29				27
Africa			51				51
Middle East			214				180
Asia Pacific			236				211
Outside North America			896				816
Worldwide			3,079				2,616
U.S. Workover Rigs			1,527				1,261

     The U.S. land and inland waters rig count increased 22.3% in the first quarter of 2006 compared with the first quarter of 2005, due primarily to the increase in drilling for natural gas. The U.S. offshore rig count decreased 19.8% in the first quarter of 2006 compared with the first quarter of 2005, reflecting the activity disruptions caused by hurricanes in the Gulf of Mexico in the third quarter of 2005 and the migration of mobile rigs out of the Gulf of Mexico to other regions offering more attractive day rates. The Canadian rig count increased 26.9% due to the increase in drilling for natural gas.

     Outside North America, the rig count increased 9.8% in the first quarter of 2006 compared with the first quarter of 2005. The rig count in Latin America was flat in the first quarter of 2006 compared with the first quarter of 2005, with activity increases in Venezuela, Colombia and Brazil offsetting decreases in Mexico. The North Sea rig count increased 55.9% in the first quarter of 2006 compared with the first quarter of 2005 with increases in all sectors, especially the UK sector. The rig count in Africa was flat in the first quarter of 2006 compared with the first quarter of 2005. Activity in the Middle East continued to rise with an 18.9% increase in the rig count in the first quarter of 2006 compared with the first quarter of 2005, driven primarily by activity increases in Saudi Arabia. The rig count in the Asia Pacific region was up 11.9% in the first quarter of 2006 compared with the first quarter of 2005, primarily due to activity increases in India, offshore China, Malaysia, Thailand and New Zealand.

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.

		Three Months Ended
		March 31,
		2006				2005
Oil prices ($/Bbl)		$	63.34			$	49.83
Natural gas prices ($/mmBtu)			7.66				6.44

     Oil prices averaged $63.34/Bbl in the first quarter of 2006. Prices increased from $63/Bbl to a quarter high of $68/Bbl during January. Increasing inventories resulted in a $10/Bbl decrease in oil prices to just under $57/Bbl in mid-February, however, rising geo—political tensions, particular in regards to civil unrest in Nigeria and Iran’s nuclear program, resulted in prices rising to almost $67/Bbl by the end of the quarter. Worldwide excess productive capacity remained at historically low levels throughout the quarter. Worldwide demand for hydrocarbons was driven by strong worldwide economic growth, which was particularly strong in China and developing Asia.

     During the first quarter of 2006, natural gas prices averaged $7.66/mmBtu. Prices fell from just under $10/mmBtu at the beginning of the quarter to just over $6/mmBtu in early March before increasing to $7/mmBtu by the end of the quarter, primarily on the increase in oil prices. Winter weather in North America was more than 10% warmer than normal (measured in population-weighted heating-degree days) resulting in high inventories. Natural gas traded at a discount to oil throughout the quarter.

Worldwide Oil and Natural Gas Industry Outlook

     This section should be read in conjunction with the factors described in the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry”, “Risk Factors Related to Our Business” and “Forward-Looking Statements” sections contained in this Part I, Item 2 and in Part II, Item 1A. Risk Factors, both contained herein. These factors could impact, either positively or negatively, our expectation for oil and natural gas demand, oil and natural gas prices and drilling activity.

     Oil — Oil prices in 2006 are expected to average between $60/Bbl and $70/Bbl and trade between $50/Bbl and $75/Bbl. Strong worldwide economic growth and the lack of excess productive capacity and heightened geo-political tensions are expected to support prices within this range. Growth in oil demand is expected to increase in 2006 compared with 2005, as worldwide economic growth and, in particular, the economy in China is expected to continue to grow in 2006. At the beginning of March 2006, the International Energy Agency estimated that excess productive capacity was less than 4% of demand and that more than 60% of the excess capacity was in Saudi Arabia and Iraq. The ongoing lack of excess productive capacity will leave the energy markets susceptible to price volatility and the Organization of Petroleum Exporting Countries (“OPEC”) is unlikely to be able to rapidly increase production should there be any significant disruptions or threat of disruptions in oil supplies.

     Factors that could lead to prices at the lower end of this range include, but are not limited to: (1) a significant slowing of worldwide economic growth, particularly economic growth in China; (2) increases in Russian oil exports; (3) any significant disruption to demand; (4) reduced geo—political tensions or (5) other factors that result in excess productive capacity and higher oil inventory levels or decreased demand. Factors that could lead to prices at the higher end of this range include, but are not limited to: (1) more rapid than planned expansion of the worldwide economy, particularly the economy in China; (2) a significant slowing of exports from Russia and the inability of key exporting countries to produce additional crude; (3) heightened geo-political tensions, particularly concerning Iran’s nuclear program or (4) other factors that result in excess productive capacity remaining at low levels. Higher inventories are expected to have significantly less impact on oil prices than the lack of excess productive capacity.

     Factors that could lead to disruptions or the threat of disruptions in oil supply and volatility in oil prices include, but are not limited to: (1) terrorist attacks targeting oil production from Saudi Arabia or other key producers; (2) labor strikes in key oil producing areas such as Nigeria; (3) the potential for other military actions in the Middle East; or (4) adverse weather conditions, especially in the Gulf of Mexico. The potential for these and other events to cause volatility will be mitigated by the degree to which OPEC and, in particular, Saudi Arabia are able to increase excess productive capacity as well as the capability of the markets to refine and market products refined from crude oil.

     Natural Gas — Natural gas prices in 2006 are expected to remain volatile, averaging between $7/mmBtu and $10/mmBtu and trade between $6/mmBtu and $15/mmBtu. Natural gas inventories were at record high levels for the month of April 2006. Accordingly, less natural gas will be required to be injected to fill natural gas storage before the beginning of the 2006—2007 winter heating season. Significant factors that will impact natural gas markets during the summer injection season include the pace of recovery of Gulf of Mexico natural gas production following 2005’s hurricanes, the possibility of additional disruptions from 2006 hurricanes and variation in summer weather.

     Natural gas prices could trade at the top, or beyond the top, of this range if: (1) storage levels are relatively low at the beginning of the winter heating season; (2) winter weather is colder than normal or summer weather is warmer than normal; (3) we experience slower than expected restoration of hurricane damaged production facilities; or (4) the U.S. economy, particularly the industrial sector, exhibits greater than expected growth and continued levels of customer spending are not sufficient to support the production growth required to meet the growth of natural gas demand. Natural gas prices could move to the bottom, or below the bottom, of this range if: (1) storage levels are relatively high at the beginning of the injection season; (2) U.S. economic growth is weaker than expected; or (3) weather is milder than expected.

     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 — Customer spending in North America, primarily towards developing natural gas supplies, is expected to increase approximately 21% to 25% in 2006 compared with 2005.

	•		Outside North America — Customer spending, primarily directed at developing oil supplies, is expected to increase approximately 19% to 23% in 2006 compared with 2005.
	•		Total spending is expected to increase approximately 20% to 24% in 2006 compared with 2005.

     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:

	•		Drilling activity in North America is expected to increase approximately 15% to 17% in 2006 compared with 2005.
	•		Drilling activity outside of North America is expected to increase approximately 9% to 11% in 2006 compared with 2005, excluding Iran and Sudan.

Risk Factors Related to the Worldwide Oil and Natural Gas Industry

     For discussion of our risk factors, see “Part II, Item 1A. Risk Factors” section contained herein.

BUSINESS OUTLOOK

     This section should be read in conjunction with the factors described in the “Risk Factors Related to Our Business”, “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” and “Forward-Looking Statements” sections contained in this Part I, Item 2 and in Part II, Item 1A. Risk Factors, both contained herein. These factors could impact, either positively or negatively, our expectation for oil and natural gas demand, oil and natural gas prices and drilling activity.

     In our outlook for 2006, we took into account the factors described herein. Revenues in 2006 are expected to increase by approximately 23% to 25%, in line with the expected increase in customer spending. We expect the growth in our revenues will primarily be due to increased activity and pricing improvement. Our assumptions regarding overall growth in customer spending assume strong economic growth in the U.S. and China, resulting in an average oil price exceeding $50/Bbl. Our assumptions regarding customer spending in North America assume strong economic growth in the U.S. and natural gas prices exceeding an average of $7/mmBtu.

     In North America, we expect revenues to increase approximately 23% to 26% in 2006 compared with 2005. We expect spending on land—based projects to continue to increase in 2006 driven by demand for natural gas, following the trend evident in 2005. We also expect offshore spending in the Gulf of Mexico to increase modestly in 2006 compared with 2005. The normal weather-driven seasonal decline in U.S. and Canadian spending in the first half of the year should result in sequentially softer revenues in the second quarter of 2006.

     In 2005, 2004 and 2003, revenues outside North America were 57.6%, 58.5% and 57.9% of total revenues, respectively. In 2006, we expect revenues outside North America to continue to be between 55% and 60% of total revenues, and we expect these revenues to increase approximately 21% to 24% in 2006 compared with 2005, continuing the multi-year trend of growth in customer spending. Spending on large projects by NOCs is expected to reflect established seasonality trends, resulting in softer revenues in the first half of the year and stronger revenues in the second half. In addition, customer spending should be affected by weather-related reductions in the North Sea in the second quarter of 2006. The Middle East, Africa and Latin America regions are expected to grow modestly in 2006 compared with 2005. Our expectations for spending and revenue growth could decrease if there are disruptions in key oil and natural gas production markets, such as Venezuela or Nigeria.

     In the first quarter of 2006, WesternGeco contributed $47.9 million of equity in income of affiliates compared with $19.3 million of equity in income of affiliates in the first quarter of 2005. On April 28, 2006, we completed the sale of our 30% minority interest in WesternGeco to Schlumberger. We expect WesternGeco will contribute an additional $9.0 million to $13.0 million of equity income through the date of sale.

     Based on the above forecasts, we believe income from continuing operations per diluted share in 2006 will be in the range of $7.00 to $7.39, which includes the impact of the $1.05 billion estimated gain, net of tax, on the sale of our interest in WesternGeco, expected stock repurchases and expensing stock option awards and stock issued under the employee stock purchase plan of between $18.0 million and $20.0 million, net of tax. Significant price increases, lower than expected raw material and labor costs, and/or higher than planned activity could cause earnings per share to reach the upper end of this range. Conversely, less than expected price increases, higher than expected raw material and labor costs, and/or lower than expected activity could result in earnings per share being at or below the bottom of this range. Our ability to improve pricing is dependent on demand for our products and services and our

competitors strategies of managing capacity. While the commercial introduction of new technology is an important factor in realizing pricing 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 90 countries including over one-half of the 35 countries having the lowest scores, which indicates high levels of corruption, in Transparency International’s Corruption Perception Index (“CPI”) survey for 2005. 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 ventures with third parties, 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. In the third quarter of 2005, our independent foreign subsidiaries initiated a process to prohibit any business activity that directly or indirectly involves or facilitates transactions in Iran, Sudan or with their governments, including government-controlled companies operating outside of these countries. Implementation of this process should be substantially complete by the end of 2006 and is not expected to have a material impact on our consolidated financial statements.

Risk Factors Related to Our Business

     For discussion of our risk factors, see “Part II, Item 1A. Risk Factors” section contained herein.

DISCONTINUED OPERATIONS

     In the fourth quarter of 2005, our management initiated and our Board of Directors approved a plan to sell the Baker Supply Products Division (“Baker SPD”), a product line group within the Completion and Production segment, which distributes basic supplies, products and small tools to the drilling industry. In March 2006, we completed the sale of Baker SPD and received cash proceeds of $42.5 million. We recorded a gain on the sale of $19.2 million, net of tax of $11.0 million, which consisted of an after-tax gain on the disposal of $16.9 million and $2.3 million related to the recognition of the cumulative foreign currency translation adjustments. We have reclassified the consolidated condensed financial statements for all prior periods presented to reflect Baker SPD as a discontinued operation.

RESULTS OF OPERATIONS

     The discussions below relating to significant line items from our consolidated condensed statements of operations 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 discussions are based on our consolidated condensed financial results, as individual segments do not contribute disproportionately to our revenues, profitability or cash requirements.

     The table below details certain consolidated condensed statement of operations data and their percentage of revenues for the three months ended March 31, 2006 and 2005, respectively.

		Three Months Ended March 31,
		2006								2005
Revenues		$	2,062.0				100.0	%		$	1,642.9				100.0	%
Cost of revenues			1,349.5				65.4	%			1,155.6				70.3	%
Selling, general and administrative			272.1				13.2	%			220.9				13.4	%

Revenues

     Revenues for the three months ended March 31, 2006 increased 25.5% compared with the three months ended March 31, 2005, primarily due to increases in activity, as evidenced by a 17.7% increase in the worldwide rig count, significant pricing improvements of between seven and eight percent and increases in market share in selected product lines and geographic areas. Revenues in North America, which accounted for 45.6% of total revenues, increased 31.1% for the three months ended March 31, 2006 compared with the three months ended March 31, 2005. This increase reflects a continued broad based increase in drilling activity in the U.S., as evidenced by the 21.3% increase in the North American rig count and price increases. Revenues outside North America, which accounted for 54.4% of total revenues, increased 21.2% for the three months ended March 31, 2006 compared with the three months ended March 31, 2005. This increase reflects the improvement in international drilling activity, as evidenced by the 9.8% increase in the rig count outside North America, particularly in Latin America, the Middle East and Asia Pacific, coupled with price increases in certain markets and product lines.

Cost of Revenues

     Cost of revenues for the three months ended March 31, 2006 increased 16.8% compared with the three months ended March 31, 2005. Cost of revenues as a percentage of revenues was 65.4% and 70.3% for the three months ended March 31, 2006 and 2005, respectively. The decrease in cost of revenues as a percentage of revenue is primarily the result of overall price increases of between seven and eight percent and continued high utilization of our rental tool fleet and personnel. These increases were partially offset by higher raw material costs and employee compensation expenses.

Selling, General and Administrative

     Selling, general and administrative (“SG&A”) expenses increased 23.2% for the three months ended March 31, 2006 compared with the three months ended March 31, 2005. The increase corresponds with increased activity and resulted primarily from higher marketing and employee compensation costs.

Equity in Income of Affiliates

     Equity in income of affiliates increased $27.7 million for the three months ended March 31, 2006 compared with the three months ended March 31, 2005. The increase is almost entirely due to the increase in equity in income of WesternGeco, our most significant equity method investment, which we sold on April 28, 2006. WesternGeco’s revenue and profitability continued to improve as a result of ongoing favorable market conditions in the seismic industry.

Interest Income

     Interest income increased $5.4 million for the three months ended March 31, 2006 compared with the three months ended March 31, 2005, due to significantly higher cash balances and short—term investments during the three months ended March 31, 2006 resulting primarily from higher cash flows from operations.

Income Taxes

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

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

LIQUIDITY AND CAPITAL RESOURCES

     Our objective in financing our business is to maintain adequate financial resources and access to additional liquidity. During the three months ended March 31, 2006, cash flows from operations and proceeds from the issuance of common stock resulting from the exercise of stock options were the principal sources of funding. We anticipate that cash flows from operations will be sufficient to

fund our liquidity needs in 2006. We also have a $500.0 million committed revolving credit facility that provides back—up liquidity in the event an unanticipated and significant demand on cash flows could not be funded by operations.

     Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of our company. During the three months ending March 31, 2006, we used cash for a variety of activities including working capital needs, payment of dividends, repurchase of common stock, repayments of borrowings and capital expenditures.

Cash Flows

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

		2006				2005
Operating activities		$	109.3			$	59.6
Investing activities			(146.4	)			(65.0	)
Financing activities			(102.5	)			(28.9	)

     Statements of cash flows for entities with international operations that are local currency functional exclude the effects of the changes in foreign currency exchange rates that occur during any given year, as these are noncash changes. 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 have been steadily increasing over the last three years and we expect this trend to continue in 2006. We attribute the increases in our cash flows to the increasing levels of income from continuing operations adjusted for noncash items.

     Cash flows from operating activities of continuing operations provided $109.3 million in the three months ended March 31, 2006 compared with $59.6 million in the three months ended March 31, 2005. This increase in cash flows of $49.7 million was primarily due to an increase in income from continuing operations of $140.4 million partially offset by a change in net operating assets and liabilities that used $80.1 million more in cash flows.

     The underlying drivers of the changes in net operating assets and liabilities are as follows:

	•		An increase in accounts receivable in the first quarter of 2006 used $77.1 million in cash compared with using $65.7 million in cash in the first quarter of 2005. This was due to the increase in revenues and an increase in days sales outstanding (defined as the average number of days our accounts receivable are outstanding) of approximately one day.
	•		A build up of inventory in anticipation of and related to increased activity used $79.9 million in cash in the first quarter of 2006 compared with using $36.0 million in cash in the first quarter of 2005.
	•		An increase in accounts payable provided $15.9 million in cash in the first quarter of 2006 compared with using $8.3 million in cash in the first quarter of 2005 primarily due to increased activity.
	•		A decrease in accrued employee compensation and other current liabilities used $151.1 million in cash in the first quarter of 2006 compared with using $102.1 million in cash in the first quarter of 2005. This was primarily due to employee bonus and benefit payments made in the first quarter of 2006 that were greater than employee bonus and benefit payments made in the first quarter of 2005.

Investing Activities

     Our principal recurring investing activity is the funding of capital expenditures to ensure that we have the appropriate levels and types of rental tools in place to generate revenues from operations. Expenditures for capital assets totaled $159.1 million and $85.6 million for the three months ended March 31, 2006 and 2005, respectively. The majority of these expenditures were for rental tools and machinery and equipment, including wireline equipment.

     In January 2006, we acquired Nova Technology Corporation (“Nova”) for $55.4 million in cash, net of cash acquired of $3.0 million, plus assumed debt. Nova is a leading supplier of permanent monitoring, chemical injection systems, and multi—line services

for deepwater and subsea oil and gas well applications and is included in the Production Optimization business unit of the Completion and Production segment. As a result of the acquisition, we recorded $29.7 million of goodwill and $24.3 million of intangibles. We also assigned $2.6 million to in—process research and development that was written off at the date of acquisition. Under the terms of the purchase agreement, the former owners of Nova are entitled to additional purchase price consideration of up to $3.0 million based on certain post closing events.

     During the three months ended March 31, 2006, we purchased $78.1 million of and received proceeds of $71.2 million from maturing auction rate securities, which are highly liquid, variable—rate debt securities. While the underlying security has a long—term maturity, the interest rate is reset through Dutch auctions that are typically held every 7, 28 or 35 days, creating short—term liquidity. These short—term investments are classified as available—for—sale and are recorded at cost, which approximates market value.

     In March 2006, we completed the sale of Baker SPD and received $42.5 million in proceeds, and we received $3.8 million from the release of the remaining amount held in escrow related to our sale of Petreco International.

     Proceeds from the disposal of assets were $28.7 million and $20.6 million for the three months ended March 31, 2006 and 2005, respectively. These disposals relate 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.

Financing Activities

     We had net repayments of short—term debt of $3.0 million and $50.8 million in the three months ended March 31, 2006 and 2005, respectively. Total debt outstanding at March 31, 2006 was $1,083.4 million, a decrease of $4.5 million compared with December 31, 2005. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratios were 0.18 at March 31, 2006 and 0.19 at December 31, 2005.

     We received proceeds of $29.4 million and $60.6 million in the three months ended March 31, 2006 and 2005, respectively, from the issuance of common stock from the exercise of stock options and the employee stock purchase plan.

     On October 27, 2005, the Board of Directors authorized us to repurchase up to $455.5 million of common stock, which was in addition to the balance of $44.5 million remaining from the Board of Directors’ September 2002 authorization, resulting in the authorization to repurchase up to a total of $500.0 million of common stock. On November 3, 2005, we entered into a Stock Purchase Plan with an agent for the purchase of shares of our common stock that complies with the requirements of Rule 10b5—1 promulgated by the Securities Exchange Act of 1934. The term of the November Plan ran from November 7, 2005 through April 30, 2006. On February 22, 2006, we entered into another Plan for a term that ran from February 23, 2006 through April 30, 2006. Shares were repurchased by the agent at the prevailing market prices, subject to limitations provided by us, in open market transactions which complied with Rule 10b—18 of the Exchange Act. During the first quarter of 2006, we repurchased 1.3 million shares of our common stock at an average price of $67.41 per share, for a total of $90.7 million. In April 2006, the Board of Directors authorized the repurchase of an additional $1.8 billion of common stock.

     We paid dividends of $44.4 million and $38.7 million in the three months ended March 31, 2006 and 2005, respectively.

Available Credit Facilities

     At March 31, 2006, we had $947.6 million of credit facilities with commercial banks, of which $500.0 million is a committed revolving credit facility (the “facility”) that expires in July 2010. The facility provides for up to three one—year extensions, subject to the approval and acceptance by the lenders, among other conditions. In addition, the facility contains a provision to allow for an increase in the facility amount of an additional $500.0 million, subject to the approval and acceptance by the lenders, among other conditions. 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 0.60, restrict certain merger transactions or the sale of all or substantially all of the assets of the company or a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the occurrence of certain events of default, our obligations under the facility may be accelerated. Such events of default include payment defaults to lenders under the facility, covenant defaults and other customary defaults. At March 31, 2006, we were in compliance with all of the facility covenants. There were no direct borrowings under the facility during the quarter ended March 31, 2006; however, to the extent we have outstanding commercial paper, our ability to borrow under the facility is reduced. At March 31, 2006, we had no outstanding commercial paper.

     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 borrowings under the facility and could also limit or preclude our ability to issue commercial paper. Should this occur, we would seek alternative sources of funding, including borrowing under the facility.

     We believe our credit ratings and relationships with major commercial and investment banks would allow us to obtain interim financing over and above our existing credit facilities for any currently unforeseen significant needs or growth opportunities. We also believe that such interim financings could be funded with subsequent issuances of long—term debt or equity, if necessary.

Cash Requirements

     In 2006, we believe operating cash flows and the proceeds from the sale of our interest in WesternGeco will provide us with sufficient capital resources and liquidity to manage our working capital needs, meet contractual obligations, fund capital expenditures, pay dividends, repurchase common stock and support the development of our short—term and long—term operating strategies.

     In 2006, we expect capital expenditures to be between $750.0 million and $780.0 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 2006, we expect to make interest payments of between $72.0 million and $77.0 million. This is based on our current expectations of debt levels during 2006.

     During the first quarter of 2006, we revised our estimate for income tax payments for 2006 and now anticipate making income tax payments of between $1,125.0 million and $1,215.0 million, which includes payments in the range of $575.0 million to $625.0 million related to the sale of our interest in WesternGeco.

     We anticipate paying dividends of between $170.0 million and $180.0 million in 2006; however, the Board of Directors can change the dividend policy at anytime. As of March 31, 2006, we had authorization remaining to repurchase up to $310.8 million in common stock. On April 28, 2006, we completed the sale of our 30% minority interest in WesternGeco to Schlumberger for $2.4 billion in cash. The net after—tax cash proceeds of approximately $1.8 billion, which include a cash distribution of $59.6 million made immediately prior to closing, are expected to be used to repurchase stock. Accordingly, in April 2006, our Board of Directors increased our stock repurchase authorization by an additional $1.8 billion. We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. We may discontinue stock repurchases at any time.

     In 2006, we estimate we will contribute between $18.0 million and $23.0 million to our defined benefit pension plans and make benefit payments related to postretirement welfare plans of between $15.0 million and $17.0 million. We also estimate we will contribute between $85.0 million and $95.0 million to our defined contribution plans.

     We do not believe 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 2005 are not indicative of what we can expect in the future.

RELATED PARTY TRANSACTIONS

     In April 2006, we signed an agreement to sell to Schlumberger for $2.4 billion in cash our 30% minority interest in WesternGeco, a seismic venture jointly owned with Schlumberger. The sale was completed on April 28, 2006. We expect to record a pre—tax gain of approximately $1.74 billion (approximately $1.05 billion, net of tax). Cash proceeds are estimated to be approximately $1.8 billion, net of tax, and include a cash distribution of $59.6 million made immediately prior to closing. We plan to use the net after—tax cash proceeds to repurchase stock; accordingly, in April 2006, our Board of Directors increased our stock repurchase authorization by an additional $1.8 billion.

NEW ACCOUNTING STANDARDS

     In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and No. 140 (“SFAS 155”). SFAS 155 amends SFAS 133, which required that a derivative embedded in a host contract that does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS 155 amends SFAS 133 to narrow the scope exception to strips that represent rights to receive only a portion of the contractual interest cash flows

or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS 155 amends SFAS 140, which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS 155 amends SFAS 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to beneficial interests that itself is a derivative financial instrument. SFAS 155 is effective for all financial instruments acquired or issued (or subject to a remeasurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. We will adopt SFAS 155 on January 1, 2007, and we do not expect this standard to have a material impact, if any, on our consolidated condensed financial statements.

FORWARD—LOOKING STATEMENTS

     MD&A and certain statements in the Notes to Consolidated Condensed Financial Statements include forward—looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, (each a “forward—looking statement”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward—looking statements. Our forward—looking statements are based on assumptions that we believe to be reasonable but that may not prove to be accurate. The statements do not include the potential impact of future transactions, such as an acquisition, disposition, merger, joint venture or other transaction that could occur. We undertake no obligation to publicly update or revise any forward—looking statement. Our expectations regarding our business outlook, including changes in revenue, pricing, capital spending, profitability, strategies for our operations, impact of our common stock repurchases, oil and natural gas market conditions, market share and contract terms, costs and availability of resources, economic and regulatory conditions, and environmental matters are only our forecasts regarding these matters.

     All of our forward—looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry”, “Risk Factors Related to Our Business” and Item 1A. Risk Factors sections contained herein, as well as the risk factors described in the Company’s Annual Report on Form 10K for the year ended December 31, 2005, this filing and those set forth from time to time in our filings with the Securities and Exchange Commission (“SEC”). These documents are available through our web site or through the SEC’s Electronic Data Gathering and Analysis Retrieval System (“EDGAR”) at http://www.sec.gov.

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.

Foreign Currency Forward Contracts

     At March 31, 2006, we had entered into several foreign currency forward contracts with notional amounts aggregating $55.0 million to hedge exposure to currency fluctuations in various foreign currencies, including the British Pound Sterling, the Norwegian Krone and the Euro. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of March 31, 2006 for contracts with similar terms and maturity dates, we recorded a gain of $0.3 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 our consolidated condensed statement of operations.

Commodity Swaps

     At March 31, 2006 we had entered into swap agreements for 4.5 million pounds of copper to reduce our exposure to fluctuations in the price of copper. These contracts mature over the remainder of 2006. The swap agreements were not designated as hedging instruments for accounting purposes. Based on quoted market prices as of March 31, 2006 for contracts with similar terms and maturity dates, we recorded a gain of $1.0 million to adjust these contracts to their fair market value. This gain is included in cost of revenues in our consolidated condensed statement of operations.

     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

Evaluation of Disclosure 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 March 31, 2006, our disclosure controls and procedures are effective at a reasonable assurance level in ensuring 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 March 31, 2006 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.

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. The SEC has issued subpoenas seeking information about our operations in Angola (subpoena dated August 6, 2003) and Kazakhstan (subpoenas dated August 6, 2003 and April 22, 2005) as part of its ongoing investigation. We are providing documents to and cooperating fully with the SEC and DOJ. The DOJ and the SEC have issued subpoenas to, or otherwise asked for interviews with, current and former employees in connection with the investigations regarding Nigeria, Angola and Kazakhstan. In addition, we have conducted internal investigations into these matters.

     Our 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 consolidated condensed financial statements. 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 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. WesternGeco continued to use the licenses until 2001. Under the WesternGeco formation agreement, we owe indemnity to WesternGeco for certain matters and , accordingly, we have agreed to indemnify WesternGeco with certain limitations in connection with the matter. We are cooperating fully with the U.S. agencies.

     We have received a subpoena from a grand jury in the Southern District of New York regarding goods and services we delivered to Iraq from 1995 through 2003 during the United Nations Oil-for-Food Program. We have also received a request from the SEC to provide a written statement and certain information regarding our participation in that program. We have responded to both the subpoena and the request and may provide additional information and documents in the future. Other companies in the energy industry are believed to have received similar subpoenas and requests.

     The U.S. agencies, the SEC and other authorities have a broad range of civil and criminal sanctions they may seek to impose against corporations and individuals in appropriate circumstances including, but not limited to, injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs. Such agencies and authorities have entered into agreements with, and obtained a range of sanctions against, several public corporations and individuals arising from allegations of improper payments and deficiencies in books and records and internal controls, whereby civil and criminal penalties were imposed, including in some cases multi—million dollar fines and other sanctions. It is not possible to accurately predict at this time when any of the investigations related to the Company 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 U.S. agencies, the SEC or other authorities or the effect it may have on our consolidated condensed financial statements.

     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 taken other actions. We believe that any liability that we may incur as a result of this litigation would not have a material adverse financial effect on our consolidated condensed financial statements.

ITEM 1A. RISK FACTORS

     As of the date of this filing, except as noted below, there have been no material changes from the risk factors previously disclosed in our “Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2005 (“2005 Annual Report”). An investment in our common stock involves various risks. When considering an investment in our company, you should consider carefully all of the risk factors described in our 2005 Annual Report. These risks and uncertainties are not the only ones facing us and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our company.

     The following are new or modified risk factors that should be read in conjunction with the risk factors disclosed in our 2005 Annual Report:

     Our expectations regarding stock repurchases are subject to market conditions, such as the trading prices for our stock. Changes in the trading prices of our stock could cause us to change the rate at which we repurchase stock. Management in its discretion may discontinue stock repurchases at any time.

     Our forecast regarding earnings includes interest on short-term investments acquired with the proceeds from the sale of our minority interest in WesternGeco. Changes in short-term interest rates may impact our forecasted earnings.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

     The following table contains information about our purchases of equity securities during the first quarter of 2006.

Issuer Purchases of Equity Securities

																		Maximum Number
										Total Number								(or Approximate
										of Shares								Dollar Value) of
		Total Number				Average				Purchased as				Average				Shares that May Yet
		of Shares				Price Paid				Part of a Publicly				Price Paid				Be Purchased Under
Period		Purchased 1				Per Share				Announced Plan 2				Per Share 3				the Plan 2
January 1—31, 2006			40,326			$	72.96				2,000			$	61.62				—
February 1—28, 2006			75				72.96				139,800				69.71				—
March 1—31, 2006			10,789				69.46				1,203,500				67.15				—
Total			51,190			$	72.22				1,345,300			$	67.41				—

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

     None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     Our Annual Meeting of Stockholders was held on April 27, 2006 (i) to elect eleven members of the Board of Directors to serve for one—year terms, (ii) to ratify Deloitte & Touche LLP as our Independent Auditor for 2006, (iii) to consider a proposal to approve the performance criteria for awards under our annual incentive compensation plan and (iv) to consider a stockholder proposal regarding voting under the company’s Delaware Charter. Following are the final results of the Annual Meeting.

     The directors who were so elected are Larry D. Brady, Clarence P. Cazalot, Jr., Chad C. Deaton, Edward P. Djerejian , Anthony G. Fernandes, Claire W. Gargalli, James A. Lash, James F. McCall, J. Larry Nichols, H. John Riley, Jr., and Charles L. Watson.

		Number of				Number of
		Affirmative				Votes
Names		Votes				Withheld
Larry D. Brady			306,463,362				2,352,312
Clarence P. Cazalot, Jr.			306,489,441				2,326,233
Chad C. Deaton			302,762,744				6,052,930
Edward P. Djerejian			306,438,050				2,377,624
Anthony G. Fernandes			306,474,077				2,341,597
Claire W. Gargalli			306,420,741				2,394,933
James A. Lash			306,534,116				2,281,558
James F. McCall			306,493,053				2,322,621
J. Larry Nichols			306,510,272				2,305,402
H. John Riley, Jr.			306,522,736				2,292,938
Charles L. Watson			306,514,800				2,300,874

     The number of affirmative votes, the number of negative votes and the number of abstentions with respect to the ratification of Deloitte & Touche LLP as Independent Auditor for 2006 was as follows:

Number of

Number of

Affirmative

Negative

Votes

Votes

Abstentions

302,266,013

4,601,783

1,947,877

     The number of affirmative votes, the number of negative votes and the number of abstentions with respect to the proposal to consider a proposal to approve the performance criteria for awards under our annual incentive compensation plan was as follows:

Number of

Number of

Affirmative

Negative

Votes

Votes

Abstentions

298,951,636

7,667,927

2,196,110

     The number of affirmative votes, the number of negative votes, the number of abstentions and the number of broker non—votes with respect to the approval of the stockholder proposal regarding simple majority voting under the Company’s Delaware charter was as follows:

Number of

Number of

Affirmative

Negative

Broker

Votes

Votes

Abstentions

Non-Votes

247,423,986

33,150,227

2,777,228

25,464,240

ITEM 5. OTHER INFORMATION

     The following events occurred subsequent to the quarterly period covered by this Form 10-Q and are reportable under Form 8-K:

Item 1.01 Entry into a Material Definitive Agreement.

     The consummation of the transaction described in Item 2.01, the Master Sales Agreement dated April 20, 2006 by and among Baker Hughes Incorporated (“Baker Hughes” or the “Company”), Schlumberger Limited (“Schlumberger”) and the other parties thereto (the “Master Sales Agreement”) modified or terminated certain of the obligations of the parties under the Master Formation Agreement dated September 6, 2000, as amended, by and among Baker Hughes, Schlumberger and the other parties thereto. A copy of the Master Sales Agreement is attached hereto as Exhibit 10.2 and incorporated herein by reference.

Item 2.01 Completion of Acquisition or Disposition of Assets.

     On April 28, 2006, Baker Hughes completed the sale of its 30% minority interest in WesternGeco, a seismic venture jointly owned with Schlumberger Limited, to Schlumberger. The purchase price for the venture interests was $2.4 billion in cash. The terms of the Master Sales Agreement include a covenant by the Company to not compete with the seismic business of WesternGeco for a period of 18 months from the closing of the sale. A copy of the Master Sales Agreement is attached hereto as Exhibit 2.1 and a copy of the news release is attached hereto as Exhibit 99.1 each of which is hereby incorporated by reference.

Item 5.02 Department of Directors or Principal Officers; Election of Directors; Appointment of Principal Officers.

     On April 27, 2006, the Board of Directors appointed Pierre H. Jungels to serve on its Board of Directors as an independent non-employee director. Dr. Jungels will serve as a member of the Compensation and Finance Committees of the Board of Directors. Dr. Jungels received 949 shares of restricted stock on April 27, 2006, which will vest one-third on each of April 27, 2007, 2008 and 2009. He will also receive an annual retainer and stock options as outlined in the Compensation Table for Named Executive Officers and Directors, filed as Exhibit 10.44 to the Company’s Form 10-K for the year ended December 31, 2005. The Company and Dr. Jungels entered into an Indemnification Agreement dated as of April 27, 2006, which form of agreement was filed as Exhibit 10.4 and incorporated herein by reference to the Company’s Form 10-K for the year ended December 31, 2003. A copy of the news release, which contains Mr. Jungel’s biographical information, is attached hereto as Exhibit 99.2 and incorporated herein by reference.

Item 5.03 Amendments to Articles of Incorporation or Bylaws; Change in Fiscal Year.

     On April 27, 2006, the Board of Directors of the Company amended and restated its Bylaws to increase the number of directors to twelve (12). The Bylaws previously provided for eleven (11) directors. A copy of the Restated Bylaws is attached hereto as Exhibit 3.2.

Item 8.01 Other Events.

a.

Following our Annual Meeting of Stockholders held on April 27, 2006, our Board of Directors held a meeting at which it appointed the members and chairmen for the Board’s five standing committees. The composition of each committee is as follows:

Executive Committee — Messrs. Deaton (Chairman), Cazalot, Riley and Watson.

Audit/Ethics Committee — Messrs. McCall (Chairman), Brady, Cazalot, Fernandes, Lash and Nichols.

Governance Committee — Messrs. Cazalot (Chairman), Djerejian, McCall, Riley and Watson.

Finance Committee — Messrs. Fernandes (Chairman), Jungels, Lash and Watson and Ms. Gargalli.

Compensation Committee — Messrs. Riley (Chairman), Djerejian, Jungels and Nichols and Ms. Gargalli.

b.

On May 1, 2006, as part of a previously announced stock repurchase program, the Company entered into a Stock Purchase Plan (the “Plan”) with an agent for the purchase of shares of the Company’s common stock that complies with the requirements of Rule 10b5-1 promulgated by the Securities Exchange Act of 1934. The term of the Plan will run from May 1, 2006 until May 31, 2006, unless earlier terminated. During that term, the agent will use its best efforts to repurchase a fixed dollar amount of the Company’s common stock each trading day, subject to applicable trading rules, until the

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.

Exhibit Index

	2.1		Master Sales Agreement, dated April 20, 2006, by and among Schlumberger Limited, Baker Hughes Incorporated and the other parties listed on the signature pages thereto.
	3.2		Bylaws of Baker Hughes Incorporated restated as of April 27, 2006.
	10.1		Baker Hughes Incorporated — Annual Incentive Compensation Plan as amended and restated effective January 1, 2005.
	10.2		Master Sales Agreement, dated April 20, 2006, by and among Schlumberger Limited, Baker Hughes Incorporated and the other parties listed on the signature pages thereto (filed as Exhibit 2.1 to this Form 10—Q) as an amendment to the Master Formation Agreement, dated as of September 6, 2000, by and among Schlumberger Limited, Baker Hughes Incorporated and certain wholly owned subsidiaries of Schlumberger Limited (filed as Exhibit 2.1 to Current Report of Baker Hughes Incorporated on Form 8—K dated September 7, 2000).
	31.1		Certification of Chad C. Deaton, Chief Executive Officer, dated May 2, 2006, pursuant to Rule 13a—14(a) of the Securities Exchange Act of 1934, as amended.
	31.2		Certification of Peter A. Ragauss, Chief Financial Officer, dated May 2, 2006, pursuant to Rule 13a—14(a) of the Securities Exchange Act of 1934, as amended.
	32		Statement of Chad C. Deaton, Chief Executive Officer, and Peter A. Ragauss, dated May 2, 2006, furnished pursuant to Rule 13a—14(b) of the Securities Exchange Act of 1934, as amended.
	99.1		News Release dated April 28, 2006.
	99.2		News Release dated April 27, 2006.