BAKER HUGHES a GE (BHI) 10-Q 2006 Q2 Quarterly report

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 June 30, 2006

OR

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

Commission File Number 1-9397

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. YESþ NOo

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

Large accelerated filerþ Accelerated filero Non-accelerated filero

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YESo NOþ

As of July 24, 2006, the registrant has outstanding 328,953,500 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 and six months ended June 30, 2006 and 2005		2
	Consolidated Condensed Balance Sheets – June 30, 2006 and December 31, 2005		3
	Consolidated Condensed Statements of Cash Flows – Six months ended June 30, 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		29
Item 3.	Defaults Upon Senior Securities		29
Item 4.	Submission of Matters to a Vote of Security Holders		29
Item 5.	Other Information		29
Item 6.	Exhibits		29
Signatures			30
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certification of CEO & CFO Pursuant to Rule 13a-14(b)

1

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Baker Hughes Incorporated

Consolidated Condensed Statements of Operations

(In millions, except per share amounts)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Revenues	$	2,203.3		$	1,768.4		$	4,265.3		$	3,411.3
Costs and expenses:
Cost of revenues		1,422.6			1,215.8			2,772.1			2,371.4
Selling, general and administrative		292.2			252.0			564.3			472.9
Total costs and expenses		1,714.8			1,467.8			3,336.4			2,844.3
Operating income		488.5			300.6			928.9			567.0
Equity in income of affiliates		11.3			18.2			59.5			38.7
Gain on sale of interest in affiliate		1,743.5			—			1,743.5			—
Interest expense		(17.0	)		(16.7	)		(33.5	)		(35.3	)
Interest and dividend income		24.2			3.3			31.5			5.2
Income from continuing operations before income taxes		2,250.5			305.4			2,729.9			575.6
Income taxes		(855.5	)		(87.4	)		(1,016.1	)		(179.2	)
Income from continuing operations		1,395.0			218.0			1,713.8			396.4
Income from discontinued operations, net of tax		—			0.8			20.4			2.2
Net income	$	1,395.0		$	218.8		$	1,734.2		$	398.6
Basic earnings per share:
Income from continuing operations	$	4.15		$	0.65		$	5.06		$	1.18
Income from discontinued operations		—			—			0.06			—
Net income	$	4.15		$	0.65		$	5.12		$	1.18
Diluted earnings per share:
Income from continuing operations	$	4.14		$	0.64		$	5.04		$	1.17
Income from discontinued operations		—			—			0.06			—
Net income	$	4.14		$	0.64		$	5.10		$	1.17
Cash dividends per share	$	0.13		$	0.115		$	0.26		$	0.23

See accompanying notes to consolidated condensed financial statements.

2

Baker Hughes Incorporated

Consolidated Condensed Balance Sheets

(In millions)

	June 30,			December 31,
	2006			2005
	(Unaudited)			(Audited)
ASSETS
Current Assets:
Cash and cash equivalents	$	1,509.0		$	697.0
Short-term investments		464.5			77.0
Accounts receivable, net		1,890.9			1,673.4
Inventories		1,317.3			1,126.3
Deferred income taxes		174.8			181.2
Other current assets		69.0			68.6
Assets of discontinued operations		—			16.6
Total current assets		5,425.5			3,840.1
Investments in affiliates		19.5			678.9
Property, net		1,509.6			1,355.5
Goodwill		1,339.5			1,315.8
Intangible assets, net		191.9			163.4
Other assets		449.6			453.7
Total assets	$	8,935.6		$	7,807.4
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	573.8		$	558.1
Short-term borrowings		0.3			9.9
Accrued employee compensation		373.9			424.5
Income taxes		469.7			141.5
Other accrued liabilities		269.8			222.9
Liabilities of discontinued operations		—			3.8
Total current liabilities		1,687.5			1,360.7
Long-term debt		1,075.9			1,078.0
Deferred income taxes and other tax liabilities		346.5			228.1
Pensions and postretirement benefit obligations		350.8			336.1
Other liabilities		94.1			106.7
Stockholders’ Equity:
Common stock		329.9			341.5
Capital in excess of par value		2,301.5			3,293.5
Retained earnings		2,908.8			1,263.2
Accumulated other comprehensive loss		(159.4	)		(188.0	)
Unearned compensation		—			(12.4	)
Total stockholders’ equity		5,380.8			4,697.8
Total liabilities and stockholders’ equity	$	8,935.6		$	7,807.4

See accompanying notes to consolidated condensed financial statements.

3

Baker Hughes Incorporated

Consolidated Condensed Statements of Cash Flows

(In millions)

(Unaudited)

	Six Months Ended
	June 30,
	2006			2005
Cash flows from operating activities:
Income from continuing operations	$	1,713.8		$	396.4
Adjustments to reconcile income from continuing operations to net cash flows from operating activities:
Depreciation and amortization		204.7			186.0
Amortization of net deferred gains on derivatives		(1.7	)		(3.2	)
Stock-based compensation costs		24.5			4.2
Acquired in-process research and development		2.6			—
Provision for deferred income taxes		173.6			22.1
Gain on sale of interest in affiliate		(1,743.5	)		—
Provision for income taxes on gain on sale of interest in affiliate		708.3			—
Gain on disposal of assets		(23.9	)		(20.7	)
Equity in income of affiliates		(59.5	)		(38.7	)
Changes in operating assets and liabilities:
Accounts receivable		(161.0	)		(140.9	)
Inventories		(177.1	)		(85.6	)
Accounts payable		0.1			32.3
Income taxes payable		(36.9	)		38.2
Income taxes payable on gain on sale of interest in affiliate		(313.3	)		—
Accrued employee compensation and other accrued liabilities		(76.2	)		(35.0	)
Other		(70.3	)		4.8
Net cash flows from continuing operations		164.2			359.9
Net cash flows from discontinued operations		0.4			2.6
Net cash flows from operating activities		164.6			362.5
Cash flows from investing activities:
Expenditures for capital assets		(367.2	)		(199.4	)
Acquisition of businesses, net of cash acquired		(59.8	)		—
Purchase of short-term investments		(780.5	)		—
Proceeds from maturities of short-term investments		393.0			—
Proceeds from sale of business		46.3			—
Proceeds from sale of interest in affiliate		2,400.0			3.7
Distribution from affiliate		59.6			—
Proceeds from disposal of assets		59.0			43.4
Net cash flows from investing activities		1,750.4			(152.3	)
Cash flows from financing activities:
Net repayments of short-term debt		(10.3	)		(62.8	)
Payment to terminate interest rate swap agreement		—			(5.5	)
Repurchases of common stock		(1,083.3	)		—
Proceeds from issuance of common stock		55.0			103.0
Dividends		(88.5	)		(77.7	)
Excess tax benefits from stock-based compensation		13.2			—
Net cash flows from financing activities		(1,113.9	)		(43.0	)
Effect of foreign exchange rate changes on cash		10.9			(8.9	)
Increase in cash and cash equivalents		812.0			158.3
Cash and cash equivalents, beginning of period		697.0			319.0
Cash and cash equivalents, end of period	$	1,509.0		$	477.3
Income taxes paid	$	548.1		$	122.5
Interest paid	$	36.9		$	42.1

See accompanying notes to consolidated condensed financial statements.

4

Baker Hughes Incorporated

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 six months ended June 30, 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 and six months ended June 30, 2006 include: (a) compensation cost for all stock-based awards 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 awards 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 capital in excess of par value.

5

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 and six months ended June 30, 2006 and under APB 25 for the three and six months ended June 30, 2005. There were no stock-based compensation costs capitalized as the amounts were not material.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Cost of sales	$	2.7		$	0.4		$	5.9		$	0.7
Selling, general and administrative		10.0			1.8			18.6			3.5
Stock-based compensation costs		12.7			2.2			24.5			4.2
Tax benefit		(2.7	)		(0.8	)		(5.5	)		(1.5	)
Stock-based compensation costs, net of tax	$	10.0		$	1.4		$	19.0		$	2.7

     The application of SFAS 123(R) had the following effect on the as reported amounts for the three and six months ended June 30, 2006 compared to amounts that would have been reported using the intrinsic value method pursuant to our previous accounting method:

	Three Months Ended									Six Months Ended
	June 30, 2006									June 30, 2006
							Intrinsic									Intrinsic
							Value									Value
				SFAS 123(R)			Method						SFAS 123(R)			Method
	As Reported			Effect			(APB 25)			As Reported			Effect			(APB 25)
Income from continuing operations before income taxes	$	2,250.5		$	5.1		$	2,255.6		$	2,729.9		$	12.2		$	2,742.1
Income from continuing operations		1,395.0			4.3			1,399.3			1,713.8			10.0			1,723.8
Net income		1,395.0			4.3			1,399.3			1,734.2			10.0			1,744.2
Basic earnings per share:
Income from continuing operations	$	4.15		$	0.02		$	4.17		$	5.06		$	0.03		$	5.09
Net income		4.15			0.02			4.17			5.12			0.03			5.15
Diluted earnings per share:
Income from continuing operations	$	4.14		$	0.01		$	4.15		$	5.04		$	0.03		$	5.07
Net income		4.14			0.01			4.15			5.10			0.03			5.13
Cash flows from operating activities	$	54.9		$	7.0		$	61.9		$	164.6		$	13.2		$	177.8
Cash flows from financing activities		(1,011.4	)		(7.0	)		(1,018.4	)		(1,113.9	)		(13.2	)		(1,127.1	)

6

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

     If we had recognized compensation expense during the three and six months ended June 30, 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 (“EP”) and stock-based compensation costs would have been as follows:

	Three Months Ended			Six Months Ended
	June 30, 2005			June 30, 2005
Net income, as reported	$	218.8		$	398.6
Add: Stock-based compensation for restricted stock awards and units included in reported net income, net of tax		1.6			2.9
Deduct: Stock-based compensation determined under SFAS 123, net of tax		(5.0	)		(22.7	)
Pro forma net income	$	215.4		$	378.8
Basic EPS:
As reported	$	0.65		$	1.18
Pro forma		0.64			1.12
Diluted EPS:
As reported	$	0.64		$	1.17
Pro forma		0.63			1.11

     For our stock options and restricted stock awards and units, we currently have 32.5 million shares authorized for issuance and as of June 30, 2006, approximately 10.6 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 is 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 options granted during the six months ended June 30, 2006 and 2005. The expected life of the options represents the period of time the options are expected to be outstanding. For the six months ended June 30, 2005, the expected life was based on historical trends. For the six months ended June 30, 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 six months ended June 30, 2005, our expected volatility is based on the historical volatility of our stock for a period approximating the expected life. For the six months ended June 30, 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		4.6	%		3.5	%
Volatility		29.4	%		35.3	%
Dividend yield		0.7	%		1.1	%
Weighted-average fair value per share at grant date	$	23.95		$	11.95

7

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		352			75.19
Exercised		(1,577	)		34.89
Forfeited		(71	)		43.41
Outstanding at June 30, 2006		4,279		$	43.21

     For the six months ended June 30, 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 $64.0 million and the income tax benefit realized from stock options exercised was $14.1 million. As of June 30, 2006, there was $12.8 million of total unrecognized compensation cost related to nonvested stock options which is expected to be recognized over a weighted-average period of 1.2 years.

     The following table summarizes information about stock options outstanding as of June 30, 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
$  14.49 — $21.07		101		2.4	$	20.55		101	$	20.55
22.88 —  33.50		895		6.1		30.27		635		29.32
35.81 —  47.82		2,291		6.6		40.80		988		42.36
56.21 —  79.94		992		9.2		62.84		6		59.25
Total		4,279		7.0	$	43.21		1,730	$	36.34

     The aggregate intrinsic value of stock options outstanding at June 30, 2006 was $165.3 million, of which $78.7 million relates to awards vested and exercisable and $86.6 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 June 30, 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 primarily recognized on a straight-line basis over the vesting or service period and is net of forfeitures.

8

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		294			74.89		73			75.06
Vested		(188	)		39.70		(26	)		43.13
Forfeited		(8	)		63.25		(4	)		62.09
Nonvested balance at June 30, 2006		767		$	55.14		120		$	61.66

     The total grant-date fair value of RSA’s and RSU’s vested during the six months ended June 30, 2006 was $8.6 million. As of June 30, 2006, there was $32.2 million and $6.3 million of total unrecognized compensation cost related to nonvested RSAs and RSUs, respectively, which is expected to be recognized over a weighted-average period of 2.4 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 calendar year. Purchases are limited to 10% of an employee’s base salary. We currently have 14.5 million shares authorized for issuance under the ESPP and at June 30, 2006, there were 3.4 million shares reserved for future issuance under the ESPP. Compensation expense determined under SFAS 123(R) for the six months ended June 30, 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. SALE OF INTEREST AND INVESTMENTS IN AFFILIATES

     We have investments in affiliates that are accounted for using the equity method of accounting. The most significant of these affiliates was our 30% interest in WesternGeco, a seismic venture jointly owned with Schlumberger. On April 28, 2006, we sold our 30% interest in WesternGeco to Schlumberger for $2.4 billion in cash. We recorded a pre-tax gain of $1,743.5 million ($1,035.2 million, net of tax). A cash distribution of $59.6 million was also made by WesternGeco to us prior to closing. Cash proceeds after anticipated income tax payments are expected to be $1.8 billion and are being used to repurchase our stock.

     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 a final payment of $3.8 million in March 2006 from the release of the amount held in escrow, plus interest.

NOTE 4. 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

9

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

adjustments. We have reclassified our consolidated condensed financial statements for all prior periods presented to reflect Baker SPD as a discontinued operation.

     Summarized financial information for Baker SPD is as follows:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2006		2005			2006			2005
Revenues	$	—	$	7.2		$	6.7		$	14.8
Income before income taxes	$	—	$	1.3		$	1.8		$	3.4
Income taxes		—		(0.5	)		(0.6	)		(1.2	)
Income before gain on sale		—		0.8			1.2			2.2
Gain on sale, net of tax		—		—			19.2			—
Income from discontinued operations	$	—	$	0.8		$	20.4		$	2.2

NOTE 5. ACQUISITION

     In January 2006, we acquired Nova Technology Corporation (“Nova”) for $55.4 million, 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 ProductionQuest (formerly 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 intangible assets. 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 to the extent that those events occur no later than January 31, 2016.

NOTE 6. 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					Six Months Ended
	June 30,					June 30,
	2006		2005			2006			2005
Net income	$	1,395.0	$	218.8		$	1,734.2		$	398.6
Other comprehensive income (loss):
Foreign currency translation adjustments:
Translation adjustment during the period		27.9		(32.4	)		29.8			(49.3	)
Reclassifications included in net income due to sale of Baker SPD		—		—			(2.3	)		—
Other		1.1		(3.5	)		1.1			(5.4	)
Total comprehensive income	$	1,424.0	$	182.9		$	1,762.8		$	343.9

10

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

     Total accumulated other comprehensive loss consisted of the following:

	June 30,			December 31,
	2006			2005
Foreign currency translation adjustments	$	(89.9	)	$	(117.4	)
Pension adjustment		(69.5	)		(69.5	)
Other		—			(1.1	)
Total accumulated other comprehensive loss	$	(159.4	)	$	(188.0	)

NOTE 7. EARNINGS PER SHARE

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Weighted average common shares outstanding for basic EPS		335.8		338.6		338.5		338.0
Effect of dilutive securities — stock plans		1.6		1.8		1.5		1.8
Adjusted weighted average common shares outstanding for diluted EPS		337.4		340.4		340.0		339.8
Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than average market price for the period		—		1.7		0.4		1.7

NOTE 8. INVENTORIES

     Inventories are comprised of the following:

	June 30,		December 31,
	2006		2005
Finished goods	$	1,037.0	$	914.5
Work in process		182.1		134.2
Raw materials		98.2		77.6
Total	$	1,317.3	$	1,126.3

NOTE 9. PROPERTY

     Property is comprised of the following:

	June 30,			December 31,
	2006			2005
Land	$	40.2		$	39.7
Buildings and improvements		637.6			611.7
Machinery and equipment		2,163.4			2,022.3
Rental tools and equipment		1,286.4			1,157.5
Total property		4,127.6			3,831.2
Accumulated depreciation		(2,618.0	)		(2,475.7	)
Property, net	$	1,509.6		$	1,355.5

11

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

NOTE 10. 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		1.5		30.6			32.1
Adjustments for final purchase price allocations of previous acquisitions		—		(10.7	)		(10.7	)
Translation adjustments and other		1.7		0.6			2.3
Balance as of June 30, 2006	$	907.3	$	432.2		$	1,339.5

     Intangible assets are comprised of the following:

	June 30, 2006							December 31, 2005
	Gross							Gross
	Carrying		Accumulated					Carrying		Accumulated
	Amount		Amortization			Net		Amount		Amortization			Net
Technology based	$	228.9	$	(79.3	)	$	149.6	$	204.8	$	(71.3	)	$	133.5
Contract based		13.6		(6.3	)		7.3		11.1		(6.5	)		4.6
Marketing related		8.2		(5.7	)		2.5		6.1		(5.6	)		0.5
Customer based		13.7		(1.4	)		12.3		6.4		(0.4	)		6.0
Other		1.1		(0.5	)		0.6		1.2		(0.7	)		0.5
Total amortizable intangible assets		265.5		(93.2	)		172.3		229.6		(84.5	)		145.1
Marketing related intangible assets with indefinite useful lives		19.6		—			19.6		18.3		—			18.3
Total	$	285.1	$	(93.2	)	$	191.9	$	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 and six months ended June 30, 2006 was $5.1 million and $10.4 million, respectively, and is estimated to be $20.5 million for 2006. Estimated amortization expense for each of the subsequent five fiscal years is expected to be within the range of $12.4 million to $19.1 million.

NOTE 11. FINANCIAL INSTRUMENTS

Foreign Currency Forward Contracts

     At June 30, 2006, we had entered into several foreign currency forward contracts with notional amounts aggregating $87.5 million to hedge exposure to currency fluctuations in various currencies, including the British Pound Sterling, the Norwegian Krone, the Euro, the Brazilian Real and the Indonesian Rupiah. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of June 30, 2006 for contracts with similar terms and maturity dates, we recorded a gain of $0.4 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

     During the quarter ended June 30, 2006, our existing swap agreements either matured or were terminated. We received cash settlements of $2.5 million related to these contracts. The agreements were entered into to reduce our exposure to fluctuations in the price of copper. The swap agreements were not designated as hedging instruments for accounting purposes. During the quarter ended June 30, 2006, we recognized a gain of $1.5 million, which represents the increase in value of the contracts prior to closure. This gain is included in cost of revenues in our consolidated condensed statement of operations.

12

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

NOTE 12. SEGMENT AND RELATED INFORMATION

     We are a provider of drilling, formation evaluation, completion and production products and services to the worldwide oil and natural gas industry. We report our results under three segments - - Drilling and Evaluation, Completion and Production and WesternGeco.

     We report results for our product-line focused divisions under two segments: the Drilling and Evaluation segment and the Completion and Production segment. 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.

• The Drilling and Evaluation segment consists of Baker Hughes Drilling Fluids (drilling fluids), Hughes Christensen (oilfield drill bits), INTEQ (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 ProductionQuest (formerly Production Optimization) business unit. 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. On April 28, 2006, we completed the sale of our 30% interest in WesternGeco, a seismic venture with Schlumberger Limited (“Schlumberger”), to Schlumberger.

     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, the pre-tax gain on the sale of our interest in WesternGeco of $1,743.5 million, 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				Total		Corporate
	and Evaluation		Production		WesternGeco		Oilfield		and Other			Total
Revenues
Three months ended June 30, 2006	$	1,118.4	$	1,084.9		—	$	2,203.3	$	—		$	2,203.3
Three months ended June 30, 2005		893.7		873.8		—		1,767.5		0.9			1,768.4
Six months ended June 30, 2006	$	2,203.0	$	2,062.3		—	$	4,265.3	$	—		$	4,265.3
Six months ended June 30, 2005		1,733.0		1,677.0		—		3,410.0		1.3			3,411.3
Segment profit (loss)
Three months ended June 30, 2006	$	290.1	$	248.2	$	10.8	$	549.1	$	1,701.4		$	2,250.5
Three months ended June 30, 2005		177.3		174.4		18.5		370.2		(64.8	)		305.4
Six months ended June 30, 2006	$	570.4	$	455.8	$	58.7	$	1,084.9	$	1,645.0		$	2,729.9
Six months ended June 30, 2005		335.8		325.9		37.8		699.5		(123.9	)		575.6
Total assets
As of June 30, 2006	$	3,600.4	$	3,290.2	$	—	$	6,890.6	$	2,045.0		$	8,935.6
As of December 31, 2005		3,221.9		2,882.6		688.0		6,792.5		1,014.9			7,807.4

13

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Corporate and other expenses	$	(49.3	)	$	(51.4	)	$	(96.5	)	$	(93.8	)
Interest expense		(17.0	)		(16.7	)		(33.5	)		(35.3	)
Interest and dividend income		24.2			3.3			31.5			5.2
Gain on sale of interest in affiliate		1,743.5			—			1,743.5			—
Total	$	1,701.4		$	(64.8	)	$	1,645.0		$	(123.9	)

NOTE 13. EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

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

	U.S. Pension Benefits
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Service cost	$	6.6		$	5.7		$	13.2		$	11.4
Interest cost		3.2			2.9			6.4			5.9
Expected return on plan assets		(7.9	)		(6.5	)		(15.8	)		(12.9	)
Recognized actuarial loss		0.2			0.7			0.4			1.3
Net periodic benefit cost	$	2.1		$	2.8		$	4.2		$	5.7

	Non-U.S. Pension Benefits
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Service cost	$	0.8		$	0.6		$	1.6		$	1.2
Interest cost		3.5			3.5			7.0			7.1
Expected return on plan assets		(3.7	)		(3.4	)		(7.4	)		(6.8	)
Recognized actuarial loss		0.6			0.7			1.2			1.4
Net periodic benefit cost	$	1.2		$	1.4		$	2.4		$	2.9

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				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Service cost	$	1.9	$	1.5	$	3.8	$	3.1
Interest cost		2.4		2.4		4.8		4.8
Amortization of prior service cost		0.2		0.2		0.4		0.3
Recognized actuarial loss		0.5		0.5		1.0		1.0
Net periodic benefit cost	$	5.0	$	4.6	$	10.0	$	9.2

NOTE 14. 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 $356.5 million at June 30, 2006. None of the off-balance sheet arrangements either has, or is likely to have, a material effect on our consolidated condensed financial statements.

14

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

     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 for the six months ended June 30, 2006 are as follows:

Balance as of December 31, 2005	$	13.4
Claims paid		(1.7	)
Additional warranties issued		7.9
Other		(0.6	)
Balance as of June 30, 2006	$	19.0

NOTE 15. NEW ACCOUNTING STANDARDS

     In July 2006, the FASB issued FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109(“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109,Accounting for Income Taxes. It prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return. This interpretation is effective for fiscal years beginning after December 15, 2006. Consistent with its requirements, we will adopt FIN 48 on January 1, 2007. We are currently evaluating the provisions of FIN 48 and have not yet determined the impact, if any, on our consolidated condensed financial statements.

     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 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.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

     Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with our consolidated condensed financial statements and the related notes thereto, as well as our Annual Report on Form 10-K for the year ended December 31, 2005.

EXECUTIVE SUMMARY

Organization

     We are a leading provider of drilling, formation evaluation, completion and production products and services to the worldwide oil and natural gas industry. We have historically reported our results under three segments — Drilling and Evaluation, Completion and Production and WesternGeco.

     We report results for our product-line focused divisions under two segments: the Drilling and Evaluation segment and the Completion and Production segment. These segments are aligned by product line based upon the types of products and services provided to our customers and upon the business characteristics of the divisions during business cycles.

• The Drilling and Evaluation segment consists of Baker Hughes Drilling Fluids (drilling fluids), Hughes Christensen (oilfield drill bits), INTEQ (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 ProductionQuest (formerly Production Optimization) business unit. 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 30% interest in WesternGeco, a seismic venture with Schlumberger Limited (“Schlumberger”). On April 28, 2006, we completed the sale of our 30% interest in WesternGeco to Schlumberger.

     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 close to the customer, improving our customer relationships and allowing us to react more quickly to local market conditions and needs.

     Our corporate 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 31,600 employees — about one-half of which work outside the U.S.

Results of Operations

     In the second quarter of 2006, we reported revenues of $2,203.3 million, a 25% increase compared with the second quarter of 2005 outpacing the 17% increase in the worldwide average rig count. Income from continuing operations for the second quarter of 2006 was $1,395.0 million, which includes a gain of $1,035.2 million after tax from the sale of our interest in WesternGeco, compared with $218.0 million in the second 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 also impacted by pricing improvements and changes in market share in certain product lines.

• We sold our 30% interest in WesternGeco to Schlumberger on April 28, 2006 for $2.4 billion in cash. The pre-tax gain on the sale was $1,743.5 million ($1,035.2 million after tax).

16

• North American revenues increased 32% in the second quarter of 2006 compared with the second quarter of 2005, while the rig count increased 23% for the second quarter of 2006 compared with the second quarter of 2005, driven primarily by land-based drilling for oil and natural gas.

• Latin American revenues increased 10% in the second quarter of 2006 compared with the second quarter of 2005, while the Latin American rig count was up 0.9%.

• Europe, Africa, Russia and the Caspian revenues increased 21% in the second quarter of 2006 compared with the second quarter of 2005, while the rig count increased 14% in Europe and 2% in Africa. We do not count rigs in Russia or the Caspian.

• Middle East and Asia Pacific revenues were up 23% in the second quarter of 2006 compared with the second quarter of 2005. Revenue from the Middle East was up 33% while the rig count, as restated below, increased 22% and Asia Pacific revenue was up 15% while the rig count decreased 0.9%. We do not count rigs for onshore China.

BUSINESS ENVIRONMENT

     Our business environment and its corresponding operating results are significantly affected by the level of energy industry spending for the exploration, development, and production of oil and natural gas reserves. Spending by oil and natural gas exploration and production companies is dependent upon their forecasts regarding the expected future supply and future demand for oil and natural gas products and their estimates of risk-adjusted costs to find, develop, and produce reserves. Changes in oil and natural gas exploration and production company spending will normally result in increased or decreased demand for our products and services which will be reflected in the rig count and other measures.

Oil and Natural Gas Prices

     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				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Oil prices ($/Bbl)	$	70.51	$	53.11	$	66.95	$	51.51
Natural gas prices ($/mmBtu)		6.51		6.95		7.08		6.70

     Oil prices averaged $70.51/Bbl in the second quarter of 2006. Prices increased from $66/Bbl in early April to a quarter high of over $74/Bbl by early May and traded between $68/Bbl and $74/Bbl for the balance of the quarter. Geo-political concerns, including civil unrest in Nigeria, tensions in the Middle East, Iran’s nuclear program, and North Korea’s nuclear program and missile testing, resulted in continued high prices offsetting the impact of higher inventories. Worldwide excess productive capacity remained at historically low levels and was estimated by the International Energy Agency (“IEA”) in its July 2006 Oil Market Report at 3.04 million barrels per day (“mbd”) (2.61 mbd excluding Iraq) or 3.6% of 2006 demand (3.1% of 2006 demand excluding Iraq). Worldwide demand for hydrocarbons was driven by strong worldwide economic growth, which was particularly strong in China, developing Asia and the United States.

     During the second quarter of 2006, natural gas prices averaged $6.51/mmBtu. Prices fell in mid-April 2006 from almost $8/mmBtu at the beginning of the quarter to trade between $5.75/mmBtu and $6.50/mmBtu for the balance of the quarter. The winter of 2005/2006 was more than 10% warmer than normal in North America (measured in population-weighted heating-degree days) and we ended the winter withdrawal season with record high levels of natural gas in storage. Because we started the summer 2006 injection season with record inventories, there is expected to be less demand required to fill storage prior to the beginning of the 2006/2007 winter withdrawal season in November. The reduced demand to fill storage and the potential for natural gas storage to fill before the start of the winter withdrawal season were the primary reasons for weaker natural gas prices. Natural gas traded at a discount to oil throughout the quarter.

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

17

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, the Caspian and onshore China, because this information is extremely difficult to obtain.

     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, to be a potential consumer of our drill bits. 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 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 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 significant consumers of drill bits.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		20051		2006		20051
U.S. - land and inland waters		1,539		1,243		1,489		1,212
U.S. - offshore		96		93		89		97
Canada		292		237		477		373
North America		1,927		1,573		2,055		1,682
Latin America		329		326		321		319
North Sea		55		45		54		40
Other Europe		27		27		28		26
Africa		51		50		51		51
Middle East		230		189		222		184
Asia Pacific		220		222		228		216
Outside North America		912		859		904		836
Worldwide		2,839		2,432		2,959		2,518
U.S. Workover Rigs		1,624		1,314		1,576		1,288

¹ Restated to exclude rig counts for Iran and Sudan, which counts were discontinued as of December 31, 2005.

     The U.S. - land and inland waters rig count increased 23.8% in the second quarter of 2006 compared with the second quarter of 2005 due to the increase in drilling for oil and natural gas. The U.S. - offshore rig count increased 3.2% in the second quarter of 2006 compared with the second quarter of 2005. The Canadian rig count increased 23.2% in the second quarter of 2006 compared with the second quarter of 2005 due to the increase in drilling for natural gas.

     Outside North America, the rig count increased 6.2% in the second quarter of 2006 compared with the second quarter of 2005. The rig count in Latin America increased 0.9% in the second quarter of 2006 compared with the second quarter of 2005, with activity increases in Venezuela, Colombia, Argentina, and Brazil offsetting spending declines in Mexico. The North Sea rig count increased 22.2% in the second quarter of 2006 compared with the second quarter of 2005. The rig count in Africa increased 2.0% in the second quarter of 2006 compared with the second quarter of 2005. Activity in the Middle East continued to rise steadily, with a 21.7% increase in the rig count in the second quarter of 2006 compared with the second quarter of 2005 driven primarily by activity increases in Saudi Arabia. The rig count in the Asia Pacific region was down 0.9% in the second quarter of 2006 compared with the second quarter of 2005.

Worldwide Oil and Natural Gas Industry Outlook

     This section should be read in conjunction with the factors described in “Part II, Item 1A. Risk Factors” and in the “Forward-Looking Statements” section in this Part I, Item 2, 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.

     Our outlook is based upon our expectations for customer spending. Our expectations for customer spending are in turn driven by our perception of industry expectations for energy prices and their likely impact on customer capital and operating budgets. Our

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forecasts are based on information provided by our customers as well as market research and analyst reports including the Short Term Energy Outlook (“STEO”) published by the Energy Information Administration of the U.S. Department of Energy (“DOE”), The Oil Market Report published by the IEA and the Oil Market Report published by the Organization for Petroleum Exporting Countries (“OPEC”).

     Oil — In its July 2005 STEO, the DOE forecasted oil prices to average $68/Bbl in 2006 with a high case of $80/Bbl and a low case of $55/Bbl. The DOE expects oil prices to be within this band 95% of the time. While inventories have increased recently, the lack of excess productive capacity, which buffers the market from supply disruptions, remains the most significant driver of high oil prices. We believe that the DOE’s forecasts are similar to the forecasts our customers are using to plan their current spending levels and with prices of between $55/Bbl and $80/Bbl, our customers will continue to execute their capital budgets as planned.

     Our customers are more likely to reduce their capital budgets if the oil price were to fall below $55/Bbl. The risks to oil prices falling significantly below $55/Bbl include (1) a significant economic recession in either the US and/or China; (2) increases in Russian oil exports; (3) any significant disruption to worldwide demand; (4) reduced geo-political tensions or (5) other factors that result in excess productive capacity and higher oil inventory levels or decreased demand. If prices were to rise significantly above $80/Bbl there is a risk that the high energy price environment could destroy demand and significantly slow economic growth. If economic growth were to slow, our customers would likely decrease their capital spending from current levels. The primary risk of oil prices exceeding $80/Bbl is a supply disruption in a major oil exporting country including Iran, Saudi Arabia, Iraq, Venezuela, Nigeria or Norway.

     Natural Gas — In its July 2005 STEO, the DOE forecasted that natural gas prices are expected to trade between $4/mmBtu and $14/mmBtu in 2006, with a low case of $4/mmBtu to $6/mmBtu and a high case of $6/mmBtu to $14/mmBtu. The DOE expects natural gas prices to trade between the high case and the low case 95% of the time. Following a winter in the U.S. that was more than 10% warmer than normal, natural gas inventories were at record high levels at the beginning of the summer injection season in April 2006. The storage overhang has been maintained throughout the summer. Fuel switching from oil to natural gas remains limited, and there is concern that absent warmer than normal weather or hurricane related supply disruptions, gas prices could be significantly weaker during September to November. If storage is filled before the beginning of the heating season, we believe that gas would likely trade at prices that would encourage consumers to switch from coal to natural gas — likely $4/mmBtu to $6/mmBtu. We believe that our customer’s forecasts are similar to the DOE’s and that they recognize that the long-term fundamentals for natural gas remain intact.

     Some of our customers may reduce their 2006 capital expenditures if the DOE’s low case scenario ($4/mmBtu to $6/mmBtu) occurs before the end of the summer injection period. The risks that would cause gas prices to weaken significantly include (1) full storage prior to the beginning of the winter withdrawal period, (2) cooler than normal summer weather, and (3) weaker than expected U.S. economic activity.

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

• North America — Spending in North America, primarily towards developing natural gas supplies, is expected to increase approximately 25% to 28% in 2006 compared with 2005.

• Outside North America — Customer spending, primarily directed at developing oil supplies, is expected to increase 17% to 20% in 2006 compared with 2005.

• Total spending is expected to increase 20% to 23% 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:

• The average North American rig count is expected to increase approximately 16% to 18% in 2006 compared with 2005.

• The average rig count outside of North America is expected to increase approximately 10% to 12% in 2006 compared with 2005.

     For additional risk factors and cautions regarding forward-looking statements, see “Part II, Item 1A. Risk Factors” and the “Forward-Looking Statements” section in this Part I, Item 2, both contained herein. This list of risk factors is not intended to be all inclusive.

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BUSINESS OUTLOOK

     This section should be read in conjunction with the factors described in “Part II, Item 1A. Risk Factors” and in the “Forward-Looking Statements” section in this Part I, Item 2, 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.

     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 national oil companies (“NOCs”), and in areas where we have market share opportunities (such as the Middle East, Russia and the Caspian); 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.

     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 $55/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 $6/mmBtu.

     In North America, we expect revenues to increase approximately 27% to 30% 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. However, there is a possibility that natural gas price weakness could result in slowing activity growth or declines in the second half of 2006 compared to the first half of 2006. We also expect offshore spending in the Gulf of Mexico to increase modestly in 2006 compared with 2005 but remain flat at current levels through the end of the year. The normal weather-driven seasonal increase in U.S. and Canadian spending in the second half of the year should result in sequentially higher revenues in the second half 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 20% to 22% in 2006 compared with 2005, continuing the multi-year trend of growth in customer spending. The Middle East, Russia and the Caspian areas are expected to show above average growth while growth in the Latin American region and Asia Pacific area are expected to be below this range. Spending on large projects by NOCs is expected to reflect established seasonal trends, resulting in softer revenues in the first half of the year and stronger revenues in the second half. Our expectations for spending and revenue growth could decrease if there are disruptions in key oil and natural gas production markets, such as the Middle East, Venezuela, Nigeria or Norway.

     In the first half of 2006, WesternGeco contributed to us $58.7 million of equity in income of affiliates compared with $37.8 million of equity in income of affiliates in the first half of 2005. On April 28, 2006, we completed the sale of our 30% interest in WesternGeco to Schlumberger.

     Based on the above forecasts, we believe income from continuing operations per diluted share in 2006 will be in the range of $7.07 to $7.37, which includes the impact of the $1.04 billion gain (approximately $3.07 per diluted share based on our weighted-average shares outstanding for the three months ended June 30, 2006), 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. 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. The commercial introduction of new technology can be an important factor in realizing pricing improvement, although other market factors may impact any meaningful improvements in our prices. 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.

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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. See “Part II, Item 1. Legal Proceedings” for a discussion of pending investigations.

     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 condensed financial statements.

     For additional risk factors and cautions regarding forward-looking statements, see “Part II, Item 1A. Risk Factors” and the “Forward-Looking Statements” section in this Part I, Item2, both contained herein. This list of risk factors is not intended to be all inclusive.

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 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 and six months ended June 30, 2006 and 2005, respectively.

	Three Months Ended June 30,
	2006				2005
Revenues	$	2,203.3	100.0	%	$	1,768.4	100.0	%
Cost of revenues		1,422.6	64.6	%		1,215.8	68.8	%
Selling, general and administrative		292.2	13.3	%		252.0	14.3	%

	Six Months Ended June 30,
	2006				2005
Revenues	$	4,265.3	100.0	%	$	3,411.3	100.0	%
Cost of revenues		2,772.1	65.0	%		2,371.4	69.5	%
Selling, general and administrative		564.3	13.2	%		472.9	13.9	%

Revenues

     Revenues for the three months ended June 30, 2006 increased 24.6% compared with the three months ended June 30, 2005, primarily due to increases in activity, as evidenced by a 16.7% increase in the worldwide rig count, price increases averaging

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approximately nine percent and changes in market share in selected product lines and geographic areas. Revenues in North America, which accounted for 44.3% of total revenues, increased 31.7% for the three months ended June 30, 2006 compared with the three months ended June 30, 2005. This increase reflects a continued broad based increase in drilling activity in the U.S., as evidenced by the 22.5% increase in the North American rig count and pricing improvements. Revenues outside North America, which accounted for 55.7% of total revenues, increased 19.6% for the three months ended June 30, 2006 compared with the three months ended June 30, 2005. This increase reflects the improvement in international drilling activity, as evidenced by the 6.2% increase in the rig count outside North America, particularly in Latin America, the Middle East and the North Sea, coupled with pricing improvements in certain markets and product lines.

     Revenues for the six months ended June 30, 2006 increased 25.0% compared with the six months ended June 30, 2005. Revenues were positively impacted by the increased activity from land rigs drilling for natural gas in the U.S. and Canada, driven by continued investment in drilling for natural gas prospects; increased activity in certain international markets, including the U.K. sector of the North Sea, Nigeria, Saudi Arabia and China; and pricing improvements in certain markets and product lines.

Cost of Revenues

     Cost of revenues for the three months ended June 30, 2006 increased 17.0% compared with the three months ended June 30, 2005. Cost of revenues for the six months ended June 30, 2006 increased 16.9% compared with the six months ended June 30, 2005. Cost of revenues as a percentage of consolidated revenues was 64.6% and 68.8% for the three months ended June 30, 2006 and 2005, respectively. Cost of revenues as a percentage of consolidated revenues was 65.0% and 69.5% for the six months ended June 30, 2006 and 2005, respectively. The decreases in cost of revenues as a percentage of consolidated revenues were primarily the result of overall average price increases of approximately nine 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 costs.

Selling, General and Administrative

     Selling, general and administrative expenses increased 16.0% in the three months ended June 30, 2006 compared with the three months ended June 30, 2005 and increased 19.3% in the six months ended June 30, 2006 compared with the six months ended June 30, 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 decreased $6.9 million in the three months ended June 30, 2006 compared with the three months ended June 30, 2005 and increased $20.8 million in the six months ended June 30, 2006 compared with the six months ended June 30, 2005. The decrease in equity in income of affiliates for the second quarter of 2006 is primarily due to the sale of our 30% interest in WesternGeco, our most significant equity method investment, on April 28, 2006.

Gain on Sale of Interest in Affiliate

     On April 28, 2006, we sold our 30% interest in WesternGeco, a seismic venture jointly owned with Schlumberger, to Schlumberger for $2.4 billion in cash. We recorded a pre-tax gain of $1,743.5 million ($1,035.2 million, net of tax).

Interest and Dividend Income

     Interest and dividend income increased $20.9 million in the three months ended June 30, 2006 compared with the three months ended June 30, 2005 and increased $26.3 million in the six months ended June 30, 2006 compared with the six months ended June 30, 2005. These increases were due to the significant increase in cash and short-term investments as a result of the cash proceeds of $2.4 billion from the sale of our interest in WesternGeco.

Income Taxes

     Our effective tax rate is higher than the U.S. statutory income tax rate of 35% due to taxes related to the sale of our interest in the WesternGeco venture and state income taxes, offset by lower rates of tax on certain international operations. During the second quarter of 2006, we provided $708.3 million for taxes related to the sale of our interest in WesternGeco, which included an estimate of taxes related to the future repatriation of the non-U.S. proceeds. Additionally, a $13.6 million tax benefit was recognized in the second quarter attributable to certain nonrecurring items related to foreign operations.

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     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 six months ended June 30, 2006, cash flows from operations and the proceeds from the sale of our interest in WesternGeco were the principal sources of funding. We anticipate that cash flows from operations will cover our liquidity needs in 2006. We also have a $500.0 million committed revolving credit facility that provides back-up liquidity.

     Our capital planning process is focused on utilizing cash flows in ways that enhance the value of our company. During the six months ended June 30, 2006, we used cash for a variety of activities including working capital needs, repayment of short-term borrowings, payment of dividends, share repurchases and capital expenditures.

Cash Flows

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

	2006			2005
Operating activities	$	164.2		$	359.9
Investing activities		1,750.4			(152.3	)
Financing activities		(1,113.9	)		(43.0	)

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

Operating Activities

     Cash flows from operating activities 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 $164.2 million in the six months ended June 30, 2006 compared with $359.9 million in the six months ended June 30, 2005. Cash flows from operating activities for the six months ended June 30, 2006, were reduced by $313.3 million of income tax payments related to the gain on sale of our interest in WesternGeco. Cash flows from other operating activities increased $117.6 million primarily due to an increase in income from continuing operations partially offset by a change in net operating assets and liabilities that used cash flows.

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

• An increase in accounts receivable in the six months ended June 30, 2006 used $161.0 million in cash compared with using $140.9 million in cash in the six months ended June 30, 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 two days.

• A build up of inventory in anticipation of and related to increased activity used $177.1 million in cash in the six months ended June 30, 2006 compared with using $85.6 million in cash in the six months ended June 30, 2005.

• Accrued employee compensation and other accrued liabilities used $76.2 million in cash in the six months ended June 30, 2006 compared with using $35.0 million in cash in the six months ended June 30, 2005. This was primarily due to employee bonus and benefit payments made in the first six months of 2006 that were greater than employee bonus and benefit payments made in the six months of 2005.

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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 $367.2 million and $199.4 million for the six months ended June 30, 2006 and 2005, respectively. The majority of these expenditures were for rental tools and machinery and equipment, including wireline equipment.

     In the first quarter of 2006, we acquired Nova Technology Corporation (“Nova”) for $55.4 million, 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 ProductionQuest 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 intangible assets. We also assigned $2.6 million to in-process research and development that was written off at the date of acquisition. In the second quarter of 2006, we made two acquisitions for $4.4 million, net of cash acquired of $0.7 million. As a result of the acquisitions, we recorded approximately $3.4 million of goodwill.

     During the six months ended June 30, 2006, we purchased $780.5 million of and received proceeds of $393.0 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.

     On April 28, 2006, we sold our 30% interest in WesternGeco, a seismic venture jointly owned with Schlumberger, to Schlumberger for $2.4 billion in cash. WesternGeco also made a cash distribution of $59.6 million prior to closing.

     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 $59.0 million and $43.4 million for the six months ended June 30, 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 $10.3 million and $62.8 million in the six months ended June 30, 2006 and 2005, respectively. Total debt outstanding at June 30, 2006 was $1,076.2 million, a decrease of $11.7 million compared with December 31, 2005. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratios were 0.17 at June 30, 2006 and 0.19 at December 31, 2005.

     We received proceeds of $55.0 million and $103.0 million in the six months ended June 30, 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 (a “Plan”). The term of that 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. In April 2006, the Board of Directors authorized the repurchase of an additional $1.8 billion of common stock. On June 8, 2006, we entered into a Plan that will run from June 9, 2006 until August 1, 2006, unless earlier terminated. During that term, the agent will, subject to applicable trading rules, use its best efforts to repurchase a number of shares of our common stock, if any, that will be determined under the terms of the Plan each trading day based on the trading price of the stock on that day. Shares will be repurchased by the agent at the prevailing market prices, in open market transactions intended to comply with Rule 10b-18 of the Exchange Act. During the six months ended June 30, 2006, we repurchased 13.4 million shares of our common stock at an average price of $80.55 per share, for a total of $1,083.3 million. At June 30, 2006, we had authorization remaining to repurchase up to a total of $1,118.2 million of our common stock.

     We paid dividends of $88.5 million and $77.7 million in the six months ended June 30, 2006 and 2005, respectively.

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Available Credit Facilities

     At June 30, 2006, we had $968.1 million of credit facilities with commercial banks, of which $500.0 million is a committed revolving credit facility (the “facility”). In June 2006, we extended the term of the facility for one additional year to July 2011. The facility provides for up to two additional 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 June 30, 2006, we were in compliance with all of the facility covenants. There were no direct borrowings under the facility during the quarter ended June 30, 2006; however, to the extent we have outstanding commercial paper, our ability to borrow under the facility is reduced. At June 30, 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 $850.0 million and $880.0 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 second quarter of 2006, we revised our estimate for income tax payments for 2006 and now anticipate making income tax payments of between $1,150.0 million and $1,240.0 million, which includes payments in the range of $600.0 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 June 30, 2006, we had authorization remaining to repurchase up to $1,118.2 million in common stock. 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 the first half of 2006 are not indicative of what we can expect in the future.

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RELATED PARTY TRANSACTIONS

     On April 28, 2006, we sold our 30% interest in WesternGeco, a seismic venture jointly owned with Schlumberger, to Schlumberger for $2.4 billion in cash. We recorded a pre-tax gain of $1,743.5 million ($1,035.2 million, net of tax). A cash distribution of $59.6 million was also made by WesternGeco to us prior to closing.

NEW ACCOUNTING STANDARDS

     In July 2006, the FASB issued FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109(“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109,Accounting for Income Taxes. It prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return. This interpretation is effective for fiscal years beginning after December 15, 2006. Consistent with its requirements, we will adopt FIN 48 on January 1, 2007. We are currently evaluating the provisions of FIN 48 and have not yet determined the impact, if any, on our consolidated condensed financial statements.

     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 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 “Part II, Item 1A. Risk Factors” section 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, the Company’s Form 10-Q for the quarter ended March 31, 2006, 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”) athttp://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 June 30, 2006, we had entered into several foreign currency forward contracts with notional amounts aggregating $87.5 million to hedge exposure to currency fluctuations in various currencies, including the British Pound Sterling, the Norwegian Krone, the Euro, the Brazilian Real and the Indonesian Rupiah. These contracts are designated and qualify as fair value hedging instruments. Based on

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quoted market prices as of June 30, 2006 for contracts with similar terms and maturity dates, we recorded a gain of $0.4 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

     During the quarter ended June 30, 2006, our existing swap agreements either matured or were terminated. We received cash settlements of $2.5 million related to these contracts. The agreements were entered into to reduce our exposure to fluctuations in the price of copper. The swap agreements were not designated as hedging instruments for accounting purposes. For the quarter, we recognized a gain of $1.5 million, which represents the increase in value of the contracts prior to closure. This gain is included in cost of revenues in our consolidated condensed statement of operations.

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 June 30, 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 June 30, 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.

     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

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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 materials.

     The DOJ, the SEC and other agencies and 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 ultimate outcome of such investigations or the effect it may have on our consolidated condensed financial statements.

     The Company has engaged in settlement discussions with both the DOJ and SEC concerning the issues in Nigeria, Angola and Kazakhstan. There can be no assurance that such discussions will result in a final settlement of any or all of these issues; however, it is possible that a settlement may include both civil and criminal sanctions as well as significant fines and penalties. If a settlement is not concluded, the Company believes it is probable that the DOJ and SEC will seek civil and criminal sanctions against the Company as well as fines and penalties that, if ultimately imposed, could have a material adverse financial effect on our consolidated condensed financial statements.

     The Department of Commerce, Department of the Navy and DOJ 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. The Company has engaged in settlement discussions with the Department of Commerce concerning the seismic equipment licensed for use in China by Western Geophysical. Although there can be no assurance that such discussions will result in a final settlement of this matter, the Company believes that any such settlement or any fines and penalties that might otherwise be imposed will not have a material adverse financial effect 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. The parties entered into a confidential settlement agreement resolving this matter in June 2006. The settlement did not have a material adverse effect on our consolidated condensed financial statements.

ITEM 1A. RISK FACTORS

     As of the date of this filing, 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”) and the Form 10-Q for the period ended March 31, 2006 (“2006 Filings”). 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 and the 2006 Filings. 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.

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

     The following table contains information about our purchases of equity securities during the three months ended June 30, 2006.

Issuer Purchases of Equity Securities

									Maximum Number (or
					Total Number				Approximate Dollar
					of Shares				Value) of Shares that
	Total Number		Average		Purchased as		Average		May Yet Be Purchased
	of Shares		Price Paid		Part of a Publicly		Price Paid		Under the Plan2
Period	Purchased1		Per Share		Announced Plan2		Per Share3		(in millions)
April 1-30, 2006		57	$	79.11		838,700	$	73.41		—
May 1-31, 2006		—		—		6,965,897		83.02		—
June 1-30, 2006		—		—		4,298,714		82.04		—
Total		57	$	79.11		12,103,311	$	82.01	$	1,118.2

1	Represents shares purchased from employees to satisfy the tax withholding obligations in connection with the vesting of restricted stock awards and restricted stock units.
2	On September 10, 2002, we announced a plan to repurchase from time to time up to $275 million of our outstanding common stock. 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. In April 2006, the Board of Directors authorized the repurchase of an additional $1.8 billion of common stock. On June 8, 2006, we entered into a Plan that will run from June 9, 2006 until August 1, 2006, unless earlier terminated. During that term, the agent will, subject to applicable trading rules, use its best efforts to repurchase a number of shares of our common stock, if any, that will be determined under the terms of the Plan each trading day based on the trading price of the stock on that day. Shares will be repurchased by the agent at the prevailing market prices, in open market transactions intended to comply with Rule 10b-18 of the Exchange Act. During the second quarter of 2006, we repurchased 12.1 million shares of our common stock at an average price of $82.01 per share, for a total of $992.6 million. At June 30, 2006, we had authorization remaining to repurchase up to a total of $1,118.2 million of our common stock.
3	Average price paid includes commissions.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

     None.

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

     On April 27, 2006, we held our Annual Meeting of Stockholders. Information regarding our meeting is included under Item 4 of our Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2006.

ITEM 5. OTHER INFORMATION

     None.

ITEM 6. EXHIBITS

10.1	First Amendment to the Credit Agreement dated June 7, 2006, among Baker Hughes Incorporated and fifteen banks for $500.0 million, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report on Form 8-K dated June 12, 2006 and incorporated by reference).
31.1	Certification of Chad C. Deaton, Chief Executive Officer, dated July 28, 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 July 28, 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, Chief Financial Officer, dated July 28, 2006, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.

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SIGNATURES

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

	BAKER HUGHES INCORPORATED
	(Registrant)
Date: July 28, 2006	By: /s/ PETER A. RAGAUSS
	Peter A. Ragauss
	Senior Vice President and Chief Financial Officer
Date: July 28, 2006	By: /s/ ALAN J. KEIFER
	Alan J. Keifer
	Vice President and Controller

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EXHIBIT INDEX

10.1	First Amendment to the Credit Agreement dated June 7, 2006, among Baker Hughes Incorporated and fifteen banks for $500.0 million, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report on Form 8-K dated June 12, 2006 and incorporated by reference).
31.1	Certification of Chad C. Deaton, Chief Executive Officer, dated July 28, 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 July 28, 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, Chief Financial Officer, dated July 28, 2006, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.