BAKER HUGHES a GE 10Q 2007 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, 2007


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		76-0207995
(State or other jurisdiction		(I.R.S. Employer Identification No.)
of incorporation or organization)


2929 Allen Parkway, Suite 2100, Houston, Texas		77019-2118
(Address of principal executive offices)		(Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements for the past 90 days. YES þ NO o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.
See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (Check one):

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

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

As of July 25, 2007, the registrant has outstanding 319,556,942 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 (Unaudited) — Three months and six months ended June 30, 2007 and 2006	2

	Consolidated Condensed Balance Sheets (Unaudited) — June 30, 2007 and December 31, 2006	3

	Consolidated Condensed Statements of Cash Flows (Unaudited) — Six months ended June 30, 2007 and 2006	4

	Notes to Unaudited Consolidated Condensed Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	26

Item 4.	Controls and Procedures	26

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	27

Item 1A.	Risk Factors	28

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	28

Item 3.	Defaults Upon Senior Securities	29

Item 4.	Submission of Matters to a Vote of Security Holders	29

Item 5.	Other Information	29

Item 6.	Exhibits	29

Signatures		30
Restated Certificate of Incorporation
Certification of Chad C. Deaton
Certification of Peter A. Ragauss
Statement Pursuant to Rule 13a-14(b)
Final Judgement by the Securities and Exchange Commission

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,
	2007			2006			2007			2006

Revenues:
Sales	$	1,259.0		$	1,120.6		$	2,459.9		$	2,157.1
Services and rentals		1,278.5			1,082.7			2,550.4			2,108.2

Total revenues		2,537.5			2,203.3			5,010.3			4,265.3


Costs and expenses:
Cost of sales		782.7			661.5			1,516.2			1,283.4
Cost of services and rentals		772.1			679.1			1,522.4			1,328.3
Research and engineering		92.6			82.0			184.2			160.4
Selling, general and administrative		353.0			292.2			690.2			564.3

Total costs and expenses		2,000.4			1,714.8			3,913.0			3,336.4


Operating income		537.1			488.5			1,097.3			928.9
Equity in income of affiliates		0.2			11.3			0.4			59.5
Gain on sale of interest in affiliate		—			1,743.5			—			1,743.5
Interest expense		(16.2	)		(17.0	)		(33.0	)		(33.5	)
Interest and dividend income		10.7			24.2			22.2			31.5


Income from continuing operations before income taxes		531.8			2,250.5			1,086.9			2,729.9
Income taxes		(182.2	)		(855.5	)		(362.6	)		(1,016.1	)


Income from continuing operations		349.6			1,395.0			724.3			1,713.8
Income from discontinued operations, net of tax		—			—			—			20.4

Net income	$	349.6		$	1,395.0		$	724.3		$	1,734.2


Basic earnings per share:
Income from continuing operations	$	1.10		$	4.15		$	2.27		$	5.06
Income from discontinued operations		—			—			—			0.06

Net income	$	1.10		$	4.15		$	2.27		$	5.12


Diluted earnings per share:
Income from continuing operations	$	1.09		$	4.14		$	2.26		$	5.04
Income from discontinued operations		—			—			—			0.06

Net income	$	1.09		$	4.14		$	2.26		$	5.10


Cash dividends per share	$	0.13		$	0.13		$	0.26		$	0.26

See accompanying notes to unaudited consolidated condensed financial statements.

Baker Hughes Incorporated
Consolidated Condensed Balance Sheets
(In millions)


	June 30,			December 31,
	2007			2006
	(Unaudited)

ASSETS

Current Assets:
Cash and cash equivalents	$	654.6		$	750.0
Short-term investments		185.2			353.7
Accounts receivable, net		2,158.5			2,055.1
Inventories		1,698.8			1,528.8
Deferred income taxes		174.9			167.8
Other current assets		118.3			112.4

Total current assets		4,990.3			4,967.8

Property, plant and equipment		2,063.1			1,800.5
Goodwill		1,350.1			1,347.0
Intangible assets, net		181.6			190.4
Other assets		414.2			400.0

Total assets	$	8,999.3		$	8,705.7


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Accounts payable	$	579.7		$	648.8
Short-term borrowings		2.2			1.3
Accrued employee compensation		362.9			484.2
Income taxes payable		63.2			150.0
Other accrued liabilities		219.7			337.6

Total current liabilities		1,227.7			1,621.9

Long-term debt		1,071.6			1,073.8
Deferred income taxes and other tax liabilities		389.0			300.2
Liabilities for pensions and other postretirement benefits		346.9			339.3
Other liabilities		110.9			127.6

Stockholders’ Equity:
Common stock		319.7			319.9
Capital in excess of par value		1,568.4			1,600.6
Retained earnings		4,111.8			3,509.6
Accumulated other comprehensive loss		(146.7	)		(187.2	)

Total stockholders’ equity		5,853.2			5,242.9

Total liabilities and stockholders’ equity	$	8,999.3		$	8,705.7

See accompanying notes to unaudited consolidated condensed financial statements.

Baker Hughes Incorporated
Consolidated Condensed Statements of Cash Flows
(In millions)
(Unaudited)


	Six Months Ended
	June 30,
	2007			2006

Cash flows from operating activities:
Income from continuing operations	$	724.3		$	1,713.8
Adjustments to reconcile income from continuing operations to net cash flows from operating activities:
Depreciation and amortization		245.9			204.7
Amortization of net deferred gains on derivatives		(2.5	)		(1.7	)
Stock-based compensation costs		24.1			24.5
Acquired in-process research and development		—			2.6
Provision for deferred income taxes		3.3			173.6
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		(41.5	)		(23.9	)
Equity in income of affiliates		(0.4	)		(59.5	)
Changes in operating assets and liabilities:
Accounts receivable		(87.8	)		(161.0	)
Inventories		(152.4	)		(177.1	)
Accounts payable		(74.4	)		0.1
Accrued employee compensation and other accrued liabilities		(253.5	)		(65.0	)
Income taxes payable		13.4			(48.1	)
Income taxes paid on sale of interest in affiliate		(98.2	)		(313.3	)
Other		16.0			(70.3	)

Net cash flows from continuing operations		316.3			164.2
Net cash flows from discontinued operations		—			0.4

Net cash flows from operating activities		316.3			164.6


Cash flows from investing activities:
Expenditures for capital assets		(538.4	)		(367.2	)
Acquisition of businesses, net of cash acquired		—			(59.8	)
Purchase of short-term investments		(1,733.5	)		(780.5	)
Proceeds from maturities of short-term investments		1,902.0			393.0
Proceeds from disposal of property, plant and equipment		90.7			59.0
Proceeds from sale of business		—			46.3
Proceeds from sale of interest in affiliate		—			2,400.0
Distribution from affiliate		—			59.6

Net cash flows from investing activities		(279.2	)		1,750.4


Cash flows from financing activities:
Net borrowings (repayments) of short-term debt		1.1			(10.3	)
Repurchases of common stock		(98.8	)		(1,083.3	)
Proceeds from issuance of common stock		31.0			55.0
Dividends		(83.1	)		(88.5	)
Excess tax benefits from stock-based compensation		5.3			13.2

Net cash flows from financing activities		(144.5	)		(1,113.9	)


Effect of foreign exchange rate changes on cash		12.0			10.9

(Decrease) increase in cash and cash equivalents		(95.4	)		812.0
Cash and cash equivalents, beginning of period		750.0			697.0

Cash and cash equivalents, end of period	$	654.6		$	1,509.0


Income taxes paid (net of refunds)	$	440.0		$	548.1
Interest paid	$	37.7		$	36.9

See accompanying notes to unaudited consolidated condensed financial statements.

Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 1. GENERAL

Nature of Operations

Baker Hughes Incorporated (“Company,” “we,” “our” or “us”) is engaged in the oilfield services industry. We are a provider of drilling, formation evaluation, completion and production products and services 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 (“SEC”). 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, 2006. 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.

New Accounting Standards

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109(“FIN 48”). We adopted FIN 48 on January 1, 2007 and recorded a reduction to beginning retained earnings of $64.2 million. See Note 6 for further information.

In September 2006, the FASB issued FASB Staff Position No. AUG AIR-1 (“FSP AUG AIR-1”), which addresses the accounting for planned major maintenance activities. FSP AUG AIR-1 prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. We adopted FSP AUG AIR-1 on January 1, 2007 to change our method of accounting for repairs and maintenance activities on certain rental tools from the accrue-in-advance method to the direct expense method. The adoption resulted in the reversal of a $34.2 million accrued liability for future repairs and maintenance (“R&M”) costs and the recording of an income tax liability of $9.0 million. The net impact of $25.2 million has been recorded as an increase to beginning retained earnings as of January 1, 2007. We did not restate any prior periods as the impact was not material to our financial statements.

The table below reflects the impact of the adoption of FIN 48 and FSP AUG AIR-1 on beginning retained earnings, the current year-to-date activity and the ending balance of retained earnings as reflected on the condensed consolidated balance sheet as of June 30, 2007.


	Retained Earnings

As reported ending balance as of December 31, 2006	$	3,509.6
Adjustments for the adoption of new accounting standards:
FIN 48 – Accounting for Uncertainty in Income Taxes		(64.2	)
FSP AUG AIR-1 – Accounting for R&M activities		25.2

Adjusted beginning balance as of January 1, 2007		3,470.6
Activity for the six months ended June 30, 2007:
Net income		724.3
Cash dividends		(83.1	)

Ending balance as of June 30, 2007	$	4,111.8

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

In September 2006, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurements (“SFAS 157”), which is intended to increase consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value and expanding disclosures about fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We will adopt SFAS 157 on January 1, 2008, and have not yet determined the impact, if any, on our consolidated condensed financial statements.

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132(R) (“SFAS 158”). We adopted all requirements of SFAS 158 on December 31, 2006, except for the funded status measurement date requirement, which will be adopted on December 31, 2008, as allowed under SFAS 158. We have not yet determined the impact of adopting the funded status measurement date requirement on our consolidated condensed financial statements.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115(“SFAS 159”). SFAS 159 permits entities to measure eligible assets and liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We will adopt SFAS 159 on January 1, 2008, and have not yet determined the impact, if any, on our consolidated condensed financial statements.

NOTE 2. STOCK-BASED COMPENSATION

We grant various forms of equity based awards to directors, officers and other key employees. These equity based awards consist primarily of stock options, restricted stock awards and restricted stock units. We also have an Employee Stock Purchase Plan available for eligible employees to purchase shares of our common stock at a 15% discount. We recorded total stock-based compensation expense of $11.5 million and $12.7 million for the three months ended June 30, 2007 and 2006, respectively, and $24.1 million and $24.5 million for the six months ended June 30, 2007 and 2006, respectively.

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 market price of our common stock on the date of grant.

The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes option pricing model. The following table presents the weighted-average assumptions used in the option pricing model for the six months ended June 30, 2007 and 2006.


	2007			2006

Expected life (years)		5.1			5.0
Risk-free interest rate		4.8	%		4.6	%
Volatility		29.6	%		29.4	%
Dividend yield		0.8	%		0.7	%
Weighted-average fair value per share at grant date	$	22.33		$	23.95

We granted 354,372 options during the six months ended June 30, 2007 at a weighted-average exercise price per option of $68.33.

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. 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.

We granted 350,872 RSAs and 93,295 RSUs during the six months ended June 30, 2007 at a weighted-average price per award or unit of $68.55 and $68.54, respectively.

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

Employee Stock Purchase Plan

Our Employee Stock Purchase Plan (“ESPP”) allows eligible employees to elect to contribute on an after-tax basis between 1% and 10% of their annual pay to purchase our common stock; provided, however, an employee may not contribute more than $25,000 annually to the plan pursuant to Internal Revenue Service restrictions. Shares are purchased at a 15% discount of the fair market value of our common stock on January 1st or December 31st, whichever is lower. We determined the fair value of our ESPP shares using the Black-Scholes option pricing model with the following assumptions.


	2007			2006

Expected life (years)		1.0			1.0
Risk-free interest rate		4.9	%		4.4	%
Volatility		30.5	%		28.0	%
Dividend Yield		0.7	%		0.9	%
Weighted-average fair value per share	$	10.39		$	7.68

Based on contributions as currently elected by eligible employees and our stock price on January 1, 2007, we estimate we will issue approximately 536,000 shares under the ESPP on or around January 1, 2008.

NOTE 3. SALE OF INTEREST IN AFFILIATE

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 Limited (“Schlumberger”), that we sold on April 28, 2006, to Schlumberger for $2.4 billion in cash. We recorded a pre-tax gain of $1,743.5 million ($1,035.2 million after-tax).

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 adjustments into earnings. 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,
	2007		2006		2007		2006

Revenues	$	—	$	—	$	—	$	6.7


Income before income taxes	$	—	$	—	$	—	$	1.8
Income taxes		—		—		—		(0.6	)

Income before gain on sale		—		—		—		1.2
Gain on sale, net of tax		—		—		—		19.2

Income from discontinued operations, net of tax	$	—	$	—	$	—	$	20.4

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. As a result of the acquisition, we recorded $29.7 million of goodwill and $24.3 million of intangible assets and assigned $2.6 million to in-process research and development. 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, of which $0.9 million was paid through June 30, 2007.

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

NOTE 6. INCOME TAXES

In June 2006, the FASB issued FIN 48,Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109. FIN 48 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, the tax benefit from an uncertain tax position is to be recognized when it is more likely than not, based on the technical merits of the position, that the position will be sustained on examination by the taxing authorities. Additionally, the amount of the tax benefit to be recognized is the largest amount of benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and financial statement disclosures.

We adopted FIN 48 on January 1, 2007, pursuant to which we recognized a $78.5 million increase in the gross liability for unrecognized tax benefits, which included $17.3 million of interest and penalties. As a result of the implementation of FIN 48, we recognized the following adjustments to our accounts as of January 1, 2007.


	Increase (Decrease)

Beginning retained earnings	$	(64.2	)
Deferred tax assets		(0.6	)
Non-current tax receivables		14.9
Tax liabilities		78.5

As of January 1, 2007, we had $422.8 million of total gross unrecognized tax benefits, which includes liabilities for interest and penalties of $50.4 million and $18.1 million, respectively, related to unrecognized tax benefits. Of this total, $339.2 million (net of associated and recognized tax benefits) represents the amount of unrecognized tax benefits that, if recognized, would favorably affect the effective tax rate.

As of June 30, 2007, we had $445.7 million of total gross unrecognized tax benefits, which includes liabilities for interest and penalties of $57.6 million and $20.3 million, respectively, related to unrecognized tax benefits. Of this total, $361.5 million (net of associated and recognized tax benefits) represents the amount of unrecognized tax benefits that, if recognized, would favorably affect the effective tax rate.

During the second quarter of 2007, the increase in our gross unrecognized tax benefits includes $9.3 million of additional taxes and related interest and penalties associated with disallowed tax deductions taken in previous years, arising from the previously announced resolution of investigations with the SEC and the Department of Justice (“DOJ”).

We have elected under FIN 48 to continue with our prior policy to classify interest and penalties related to unrecognized tax benefits as income taxes in our financial statements. For the six months ended June 30, 2007, we recognized $7.2 million of interest expense related to unrecognized tax benefits.

It is expected that the amount of unrecognized tax benefits will change in the next twelve months due to expiring statutes and audit activity, including expected tax payments; however, we do not anticipate the change to have a significant impact on our statement of operations or our balance sheet.

We operate in over 90 countries and are subject to income taxes in most taxing jurisdictions in which we operate. The following table summarizes the earliest tax years that remain subject to examination by the major taxing jurisdictions in which we operate. These jurisdictions are those we project to have the highest tax liability for the current year.


	Earliest Open
Jurisdiction	Tax Period
Angola		2002
Argentina		1999
Brazil		2002
Canada		1998
Equatorial Guinea		2003
Germany		2003
Norway		1999
Russia		2004
Saudi Arabia		1995
United Kingdom		1999
United States		2002
Venezuela		1998

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

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,
	2007		2006		2007		2006

Weighted average common shares outstanding for basic EPS		319.1		335.8		319.1		338.5
Effect of dilutive securities — stock plans		2.2		1.6		2.1		1.5

Adjusted weighted average common shares outstanding for diluted EPS		321.3		337.4		321.2		340.0


Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than the average market price for the period		0.3		—		0.6		0.4

NOTE 8. INVENTORIES

Inventories are comprised of the following:


	June 30,		December 31,
	2007		2006

Finished goods	$	1,383.8	$	1,239.5
Work in process		197.7		188.0
Raw materials		117.3		101.3

Total	$	1,698.8	$	1,528.8

NOTE 9. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of the following:


	June 30,			December 31,
	2007			2006

Land	$	47.7		$	46.1
Buildings and improvements		705.0			661.0
Machinery and equipment		2,561.1			2,387.6
Rental tools and equipment		1,597.2			1,419.2

Subtotal		4,911.0			4,513.9
Accumulated depreciation		(2,847.9	)		(2,713.4	)

Total	$	2,063.1		$	1,800.5

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, 2006	$	909.2	$	437.8	$	1,347.0
Translation adjustments and other		2.8		0.3		3.1

Balance as of June 30, 2007	$	912.0	$	438.1	$	1,350.1

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

Intangible assets are comprised of the following:


	June 30, 2007							December 31, 2006
	Gross							Gross
	Carrying		Accumulated					Carrying		Accumulated
	Amount		Amortization			Net		Amount		Amortization			Net

Technology based	$	237.6	$	(96.2	)	$	141.4	$	236.7	$	(87.2	)	$	149.5
Contract based		14.6		(8.0	)		6.6		13.8		(6.6	)		7.2
Marketing related		5.7		(5.7	)		—		5.7		(5.7	)		—
Customer based		13.7		(3.2	)		10.5		13.7		(2.4	)		11.3
Other		1.3		(0.3	)		1.0		0.7		(0.4	)		0.3

Total amortizable intangible assets		272.9		(113.4	)		159.5		270.6		(102.3	)		168.3
Marketing related intangible assets with indefinite useful lives		22.1		—			22.1		22.1		—			22.1

Total	$	295.0	$	(113.4	)	$	181.6	$	292.7	$	(102.3	)	$	190.4

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

Amortization expense for intangible assets included in net income for the three months and six months ended June 30, 2007 was $5.2 million and $10.6 million, respectively, and is estimated to be $20.5 million for 2007. Estimated amortization expense for each of the subsequent five fiscal years is expected to be within the range of $13.6 million to $19.0 million.

NOTE 11. FINANCIAL INSTRUMENTS

Foreign Currency Forward Contracts

At June 30, 2007, we had entered into several foreign currency forward contracts with notional amounts aggregating $130.0 million to hedge exposure to currency fluctuations in various foreign currencies, including British Pound Sterling, Euro, Norwegian Krone, Brazilian Real and Indonesian Rupiah. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of June 30, 2007 for contracts with similar terms and maturity dates, during the second quarter of 2007 we recorded a gain of $0.5 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.

At June 30, 2007, we had entered into several foreign currency forward contracts with notional amounts aggregating $82.7 million to hedge exposure to fluctuations in the Canadian dollar exchange rate. The contracts were not designated as hedging instruments. Based on quoted market prices as of June 30, 2007 for contracts with similar terms and maturity dates, during the second quarter of 2007 we recorded a loss of $2.0 million to adjust these forward foreign currency contracts to their fair market value. This loss is included in selling, general and administrative expense in our consolidated condensed statement of operations.

At June 30, 2007, we had entered into option contracts as a hedge of fluctuations in the Russian Ruble exchange rate. The contracts were not designated as hedging instruments. Based on quoted market prices as of June 30, 2007 for contracts with similar terms and maturity dates, during the second quarter of 2007 we recorded a loss of $0.1 million to adjust the carrying value of these contracts to their fair market value. This loss is included in selling, general and administrative expense in our consolidated condensed statement of operations.

Baker Hughes Incorporated
Notes to Unaudited 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 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 WesternGeco segment consisted of our 30% interest in WesternGeco, which we sold in April 2006.

	•		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) divisions. 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) divisions and the ProductionQuest 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 performance of our segments is evaluated based on segment profit (loss), which is defined as income from continuing operations before income taxes, interest expense and interest and dividend income. 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.


	Drilling		Completion and				Total		Corporate
	and Evaluation		Production		WesternGeco		Oilfield		and Other			Total

*Revenues*
Three months ended June 30, 2007	$	1,278.7	$	1,258.7	$	—	$	2,537.4	$	0.1		$	2,537.5
Three months ended June 30, 2006		1,118.4		1,084.9		—		2,203.3		—			2,203.3

Six months ended June 30, 2007	$	2,567.2	$	2,442.9	$	—	$	5,010.1	$	0.2		$	5,010.3
Six months ended June 30, 2006		2,203.0		2,062.3		—		4,265.3		—			4,265.3

*Segment profit (loss)*
Three months ended June 30, 2007	$	328.5	$	266.9	$	—	$	595.4	$	(63.6	)	$	531.8
Three months ended June 30, 2006		290.1		248.2		10.8		549.1		1,701.4			2,250.5

Six months ended June 30, 2007	$	695.1	$	513.3	$	—	$	1,208.4	$	(121.5	)	$	1,086.9
Six months ended June 30, 2006		570.4		455.8		58.7		1,084.9		1,645.0			2,729.9

*Total assets*
As of June 30, 2007	$	4,296.3	$	3,815.3	$	—	$	8,111.6	$	887.7		$	8,999.3
As of December 31, 2006		3,988.8		3,595.7		—		7,584.5		1,121.2			8,705.7

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

The following table presents the details of the segment profit (loss) for “Corporate and Other”:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006

Corporate and other expenses	$	(58.1	)	$	(49.3	)	$	(110.7	)	$	(96.5	)
Interest expense		(16.2	)		(17.0	)		(33.0	)		(33.5	)
Interest and dividend income		10.7			24.2			22.2			31.5
Gain on sale of interest in affiliate		—			1,743.5			—			1,743.5

Total	$	(63.6	)	$	1,701.4		$	(121.5	)	$	1,645.0

NOTE 13. EMPLOYEE BENEFIT PLANS

We have noncontributory defined benefit pension plans (“Pension Benefits”) covering employees primarily in the U.S., the U.K. and Germany. In the U.S., we merged two defined benefit pension plans effective January 1, 2007, resulting in one tax-qualified U.S. pension plan, the Baker Hughes Incorporated Pension Plan (“BHIPP”). We also provide certain postretirement health care and life insurance benefits (“other postretirement benefits”), through an unfunded plan, 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 for the three months ended June 30:


	U.S. Pension Benefits						Non-U.S. Pension Benefits						Other Postretirement Benefits
	2007			2006			2007			2006			2007		2006

Service cost	$	7.9		$	6.6		$	0.7		$	0.8		$	1.9	$	1.9
Interest cost		3.9			3.2			4.4			3.5			2.2		2.4
Expected return on plan assets		(8.6	)		(7.9	)		(4.8	)		(3.7	)		—		—
Amortization of prior service cost		0.2			—			—			—			0.3		0.2
Amortization of net loss		0.1			0.2			0.7			0.6			—		0.5

Net periodic benefit cost	$	3.5		$	2.1		$	1.0		$	1.2		$	4.4	$	5.0

The components of net periodic benefit cost are as follows for the six months ended June 30:


	U.S. Pension Benefits						Non-U.S. Pension Benefits						Other Postretirement Benefits
	2007			2006			2007			2006			2007		2006

Service cost	$	15.8		$	13.2		$	1.4		$	1.6		$	3.8	$	3.8
Interest cost		7.8			6.4			8.8			7.0			4.4		4.8
Expected return on plan assets		(17.2	)		(15.8	)		(9.6	)		(7.4	)		—		—
Amortization of prior service cost		0.4			—			—			—			0.6		0.4
Amortization of net loss		0.2			0.4			1.4			1.2			—		1.0

Net periodic benefit cost	$	7.0		$	4.2		$	2.0		$	2.4		$	8.8	$	10.0

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 $412.5 million at June 30, 2007. None of the off-balance sheet arrangements either has, or is likely to have, a material effect on our consolidated condensed financial statements.

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

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

The changes in the aggregate product warranty liabilities for the six months ended June 30, 2007 are as follows:



Balance as of December 31, 2006	$	22.6
Claims paid		(8.4	)
Additional warranties issued		2.4
Revisions in estimates of previously issued warranties		(1.2	)
Other		0.2

Balance as of June 30, 2007	$	15.6

NOTE 15. 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,
	2007			2006		2007			2006

Net income	$	349.6		$	1,395.0	$	724.3		$	1,734.2
Other comprehensive income (loss):
Foreign currency translation adjustments:
Translation adjustment during the period		34.8			27.9		41.1			29.8
Reclassifications included in net income due to sale of Baker SPD		—			—		—			(2.3	)
Pension and other postretirement benefits		(0.3	)		—		(0.6	)		—
Other		—			1.1		—			1.1

Total comprehensive income	$	384.1		$	1,424.0	$	764.8		$	1,762.8

Total accumulated other comprehensive loss consisted of the following:


	June 30,			December 31,
	2007			2006

Foreign currency translation adjustments	$	(19.2	)	$	(60.3	)
Pension and other postretirement benefits		(127.5	)		(126.9	)

Total accumulated other comprehensive loss	$	(146.7	)	$	(187.2	)

NOTE 16. LITIGATION

On April 26, 2007, the United States District Court, Southern District of Texas, Houston Division (the “Court”) unsealed a three-count criminal information that had been filed against the Company as part of the execution of a Deferred Prosecution Agreement (the “DPA”) between us and the DOJ. The three counts arise out of payments made to an agent in connection with a project in Kazakhstan and include conspiracy to violate the Foreign Corrupt Practices Act (“FCPA”), a substantive violation of the antibribery provisions of the FCPA, and a violation of the FCPA’s books-and-records provisions. All three counts relate to the Company’s operations in Kazakhstan during the period from 2000 to 2003. Although the Company did not plead guilty to that information, it faces prosecution under that information, and possibly under other charges as well, if it fails to comply with the terms of the DPA. Those terms include, for the two-year term of the DPA, full cooperation with the government; compliance with all federal criminal law, including but not limited to the FCPA; and adoption of a Compliance Code containing specific provisions intended to prevent violations of the FCPA. The DPA also requires the Company to retain an independent monitor for a term of three years to assess and make recommendations about our compliance policies and procedures and our implementation of those procedures. Provided that the Company complies with the DPA, the DOJ has agreed not to prosecute the Company for violations of the FCPA based on information that the Company has disclosed to the DOJ regarding its operations in Nigeria, Angola, Kazakhstan, Indonesia, Russia, Uzbekistan, Turkmenistan, and Azerbaijan, among other countries.

On the same date, the Court also accepted a plea of guilty by our subsidiary Baker Hughes Services International, Inc. (“BHSII”) pursuant to a plea agreement between BHSII and the DOJ (the “Plea Agreement”) based on similar charges relating to the same conduct. Pursuant to the Plea Agreement, we agreed to a three-year term of organizational probation. The Plea Agreement contains provisions requiring BHSII to cooperate with the government, to comply with all federal criminal law, and to adopt a Compliance

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

Code similar to the one that the DPA requires of the Company. Also on April 26, 2007, the SEC filed a Complaint (the “SEC Complaint”) and a proposed order (the “SEC Order”) against the Company in the Court. The SEC Complaint and the SEC Order were filed as part of a settled civil enforcement action by the SEC, to resolve the civil portion of the government’s investigation of the Company. As part of its agreement with the SEC, the Company consented to the filing of the SEC Complaint without admitting or denying the allegations in the Complaint, and also consented to the entry of the SEC Order. The SEC Complaint alleges civil violations of the FCPA’s antibribery provisions related to the Company’s operations in Kazakhstan, the FCPA’s books-and-records and internal-controls provisions related to the Company’s operations in Nigeria, Angola, Kazakhstan, Indonesia, Russia, and Uzbekistan, and the SEC’s cease and desist order of September 12, 2001, which has been previously disclosed in our Annual Reports on Form 10-K. The SEC Order became effective on May 1, 2007, which is the date it was confirmed by the Court. The SEC order enjoins the Company from violating the FCPA’s antibribery, books-and-records, and internal-controls provisions. As in the DPA, it requires that the Company retain the independent monitor to assess its FCPA compliance policies and procedures for the three-year period.

The selection of the independent monitor to assess our FCPA compliance policies and procedures for the specified three-year period has been approved by the SEC and DOJ, but is subject to the negotiation of an engagement letter that must also be reviewed and approved by the SEC and DOJ.

On May 4, 2007 and May 15, 2007, The Sheetmetal Workers’ National Pension Fund and Chris Larson, respectively, instituted shareholder derivative lawsuits for and on the Company’s behalf against certain current and former members of the Board of Directors and certain officers, and the Company as a nominal defendant, following the Company’s April 27, 2007 settlement with the DOJ and SEC. Both complaints allege, among other things, that the individual Defendants failed to implement adequate controls and compliance procedures to prevent the events addressed by the settlement with the SEC and DOJ. The relief sought in the lawsuits includes a declaration that the Defendants breached their fiduciary duties, an award of damages sustained by the Company as a result of the alleged breach and monetary and injunctive relief, as well as attorneys’ and experts’ fees. The lawsuit brought by the Sheetmetal Workers’ National Pension Fund is pending in the Houston Division of the United States District Court for the Southern District of Texas. The lawsuit brought by Chris Larson is pending in the 215th District Court of Harris County, Texas. We do not expect these lawsuits to have a material adverse effect on our consolidated condensed financial statements.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION ANDRESULTS 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, 2006.

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 report our results under two segments – Drilling and Evaluation and Completion and Production – which 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 the 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) divisions. 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 the Baker Oil Tools (workover, fishing and completion equipment), Baker Petrolite (oilfield specialty chemicals) and Centrilift (electric submersible pumps and progressing cavity pumps) divisions. The Completion and Production segment also includes our ProductionQuest 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 jointly owned with Schlumberger Limited (“Schlumberger”). On April 28, 2006, we sold our 30% interest in WesternGeco to Schlumberger for $2.4 billion. We recorded a pre-tax gain of $1,743.5 million ($1,035.2 million after-tax).

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 including compliance, marketing, finance and treasury, 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 our customers, improving our customer relationships and allowing us to react more quickly to local market conditions and needs.

We operate in over 90 countries around the world and our corporate headquarters are in Houston, Texas. We have significant manufacturing operations in various countries, including, but not limited to, the United States (Texas, Oklahoma and Louisiana), the U.K. (Aberdeen, East Kilbride and Belfast), Germany (Celle), and Venezuela (Maracaibo). As of June 30, 2007, we had approximately 35,800 employees, up approximately 200 employees from March 31, 2007. Approximately 56% of our employees work outside the U.S.

Results of Operations

In the second quarter of 2007, we reported revenues of $2,537.5 million, a 15.2% increase compared with the second quarter of 2006, outpacing the 2.3% increase in the worldwide average rig count for the same period. Income from continuing operations for the second quarter of 2007 was $349.6 million compared with $1,395.0 million in the second quarter of 2006 which included a gain of $1,035.2 million after-tax from the sale of our interest in WesternGeco. During the second quarter of 2007, the Canadian rig count decreased 50.7% compared to the second quarter of 2006, resulting in a decline in our profitability in Canada, particularly in the Drilling and Evaluation segment.

•

North America revenues increased 7.6% in the second quarter of 2007 compared with the second quarter of 2006, while the rig count decreased 1.3% for the second quarter of 2007 compared with the second quarter of 2006. The decline in Canada and offshore U.S. rig counts more than offset the increase in the U.S. land and inland waters rig count.

	•		Latin America revenues increased 19.7% in the second quarter of 2007 compared with the second quarter of 2006, while the Latin America rig count was up 7.9%.

	•		Europe, Africa, Russia and the Caspian revenues increased 26.7% in the second quarter of 2007 compared with the second quarter of 2006, while the rig count decreased 2.4% in Europe and increased 21.6% in Africa. We do not count rigs in Russia or the Caspian.

	•		Middle East and Asia Pacific revenues were up 13.9% in the second quarter of 2007 compared with the second quarter of 2006. Revenue from the Middle East was up 11.9% while the rig count increased 13.9% and Asia Pacific revenue was up 15.9% while the rig count increased 10.5%. 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 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,
	2007		2006		2007		2006

Oil prices ($/Bbl)	$	64.95	$	70.51	$	61.58	$	66.95
Natural gas prices ($/mmBtu)		7.53		6.51		7.36		7.08

Oil prices averaged $64.95/Bbl in the second quarter of 2007. Prices increased from a low of $61.47/Bbl in early May to a quarter high of $70.68/Bbl in late June. Oil prices continue to reflect strong worldwide demand, led by China, developing Asia and the U.S., as well as ongoing concerns about potential supply disruption which could result from geo-political events such as continued civil unrest in Nigeria and tensions in the Middle East or from disruption in major producing countries such as Venezuela. The International Energy Agency (“IEA”) estimated in its July 2007 Oil Market Report that worldwide excess productive capacity was 3.99 million barrels per day (“mbd”). However, the IEA stated that “effective” spare capacity (which excludes Indonesia, Iraq, Nigeria and Venezuela), was 2.85 mbd and suggested that this figure likely overstates what the Organization of Petroleum Exporting Countries’ (“OPEC”) could actually deliver to the market given current prices and shortages in refinery upgrading capacity.

During the second quarter of 2007, natural gas prices averaged $7.53/mmBtu. Prices traded in the mid-to-high $7/mmBtu range throughout the majority of the quarter before decreasing to a low of $6.36/mmBtu at the end of June on concerns of building natural gas inventories. The amount of storage at the end of the withdrawal season on March 23, 2007 was 1,511 Bcf, 21% ahead of the 5-year historic average but 11% below last year’s record high storage level. At the end of June, storage was 2,521 Bcf, only 4% below last year, and 18% above the 5-year historic average, primarily as a result of significant increases in Liquefied Natural Gas (“LNG”) imports.

Rig Counts

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

Rigs in the U.S. are counted as active if, on the day the count is taken, the well being drilled has been started but 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, rigging up, being used in non-drilling activities, including production testing, completion and workover, or 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,
	2007		2006		2007		2006

U.S. – land and inland waters		1,680		1,539		1,666		1,489
U.S. – offshore		77		96		80		89
Canada		144		292		333		477

North America		1,901		1,927		2,079		2,055

Latin America		355		329		354		321
North Sea		54		55		51		54
Other Europe		26		27		27		28
Africa		62		51		64		51
Middle East		262		230		260		222
Asia Pacific		243		220		237		228

Outside North America		1,002		912		993		904

Worldwide		2,903		2,839		3,072		2,959


U.S. Workover Rigs		1,526		1,624		1,506		1,576

The U.S. – land and inland waters rig count increased 9.2% in the second quarter of 2007 compared with the second quarter of 2006 due to the increase in drilling for oil and natural gas. The U.S. – offshore rig count decreased 19.8% in the second quarter of 2007 compared with the second quarter of 2006 primarily due to the ongoing migration of rigs out of the Gulf of Mexico to more attractive international markets. The Canadian rig count was down 50.7% in the second quarter of 2007 compared with the second quarter of 2006 as drilling activity in Canada was impacted by lower economic returns for Canadian exploration and production projects.

Outside North America, the rig count increased 9.9% in the second quarter of 2007 compared with the second quarter of 2006. The rig count in Latin America increased 7.9% in the second quarter of 2007 compared with the second quarter of 2006, with activity increases in Colombia, Brazil, Argentina and Mexico offsetting declines in Venezuela and Ecuador. The North Sea rig count decreased 1.8% in the second quarter of 2007 compared with the second quarter of 2006. The rig count in Africa increased 21.6% in the second quarter of 2007 compared with the second quarter of 2006 driven by activity increases in Northern Africa (Algeria and Libya). Activity in the Middle East continued to rise steadily, with a 13.9% increase in the rig count in the second quarter of 2007 compared with the second quarter of 2006 driven primarily by activity increases in Saudi Arabia, Oman and Egypt. The rig count in the Asia Pacific region was up 10.5% in the second quarter of 2007 compared with the second quarter of 2006.

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 forecasts are based on information provided by our customers as well as market research and analyst reports including theShort Term Energy Outlook(“STEO”) published by the Energy Information Administration of the U.S. Department of Energy (“DOE”), theOil Market Reportpublished by the IEA and theMonthly Oil Market Reportpublished by OPEC.

Oil– In its July 2007 STEO, the DOE forecasted oil prices to average $65.56/Bbl in 2007. The DOE has forecasted a high case of approximately $80/Bbl and a low case of approximately $55/Bbl at the end of 2007. The DOE expects oil prices to be between these

cases 95% of the time. This forecast is supported by: industry and government forecasts for rising global oil demand; relatively modest forecasted increases in production from non-OPEC countries; and ongoing cuts in OPEC production. Commercial inventories are expected to fall to historically low levels, in terms of days of supply, by the end of 2007 and spare productive capacity, which buffers the market from supply disruptions, remains relatively low. While both inventories and spare productive capacity have increased recently, spare productive capacity remains relatively low and is an indicator that supply and demand remain relatively tightly balanced. The increase in spare productive capacity has been and will likely be driven by planned cuts in OPEC production which are aimed at supporting near-term oil prices while allowing for non-OPEC production increases.

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 averaging between $55/Bbl and $75/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 expected to trade below $55/Bbl for an extended period of time. The risks to oil prices falling significantly below $55/Bbl include (i) a significant economic recession in either the U.S. and/or China; (ii) increases in Russian oil exports or non-OPEC production; (iii) any significant disruption to worldwide demand; (iv) reduced geo-political tensions; (v) poor OPEC Quota discipline; or (vi) other factors that result in spare productive capacity and higher oil inventory levels or decreased demand. If expectations for sustained oil prices were to rise significantly above $75/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 $75/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 2007 STEO, the DOE forecasted that natural gas prices are expected to average $7.91/mmBtu in 2007 with monthly averages for the balance of 2007 varying between $7.00/mmBtu and $10.00/mmBtu depending on seasonality. The DOE also publishes a high and low case and expects gas to trade between these two cases 95% of the time. The low case varies between $5.00/mmBtu and $7.00/mmBtu, depending on seasonality, and the high case varies between $9.00/mmBtu and $15.00/mmBtu, depending on seasonality. Prices are expected to remain volatile through 2007 with weather-driven demand and storage levels playing significant roles in determining prices.

If natural gas storage is in-line with historical norms, we expect natural gas to trade in the upper half of the DOE’s forecast range. If natural gas storage is above historic norms, we believe that natural gas prices could approach the bottom of the DOE’s forecast range. Natural gas storage levels are dependent on: North American summer cooling demand, which is demand driven primarily by summer weather being hotter or cooler than normal; changes in U.S. natural gas production, which is driven by production increases offset by production declines; changes in pipeline imports from Canada; and changes in LNG imports, which are driven by the relative attractiveness of the U.S. market in competition with other global markets, particularly Europe; and the impact of hurricanes to both supply and demand. Based on current industry data regarding decline rates, we believe that a significant reduction in drilling activity in the U.S. or Canada would result in decreased production within one or two quarters helping to rebalance supply and demand quickly and prices would move from the bottom of the DOE’s range to the middle or top of the range. We believe that our customers’ forecasts are similar to the DOE’s and that they recognize that the long-term positive fundamentals for natural gas remain intact.

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, we expect revenue growth in the U.S. to more than offset an expected decline in Canadian revenue in 2007 compared with 2006. We expect that customer spending outside North America, primarily directed at developing oil supplies, will increase approximately 19% to 21% in 2007 compared with 2006.

Drilling Activity– Based upon our outlook for oil and natural gas prices and customer spending described above, we expect drilling activity outside of North America to increase approximately 11% to 13% in 2007 compared with 2006.

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.

BUSINESS OUTLOOK

In our outlook for 2007, we took into account the factors described herein.

In 2006, 2005 and 2004, revenues outside North America were 55.7%, 57.6% and 58.5% of total revenues, respectively. In 2007, we expect revenues outside North America to increase approximately 19% to 21% compared with 2006, continuing the multi-year trend of growth in customer spending. Spending on large projects by National Oil Companies (“NOCs”) is expected to reflect established seasonality trends, resulting in softer revenues in the first half of the year and stronger revenues in the second half. In addition, customer spending could be affected by weather-related reductions. The Russia and Caspian, Middle East and Latin America areas are expected to grow significantly in 2007 compared with 2006. Our expectations for spending and revenue growth could decrease if there are disruptions in key oil and natural gas production markets. Our assumptions regarding overall growth in customer spending outside of North America assume strong economic growth in the United States, China and the balance of the world outside of North America, resulting in an average oil price exceeding $55/Bbl.

In 2006, 2005 and 2004, revenues in North America were 44.3%, 42.4%, and 41.5% of total revenues, respectively. We expect revenue growth in the U.S. to more than offset an expected decline in Canadian revenue in 2007 compared with 2006. Customer spending growth and therefore revenue growth in 2007 is highly uncertain given its dependence on the impact of weather-driven events and their impact on supply, demand and natural gas storage levels.

In 2006, WesternGeco contributed $58.7 million of equity in income of affiliates compared with $96.7 million of equity in income of affiliates in 2005. We sold our 30% interest in WesternGeco in April of 2006.

Other factors that could have a significant positive impact on profitability include: increasing prices for our products and services; lower than expected raw material and labor costs; and/or higher than planned activity. Conversely, less than expected price increases or price deterioration, higher than expected raw material and labor costs and/or lower than expected activity would have a negative impact on profitability. Our ability to improve pricing is dependent on demand for our products and services and our competitors’ strategies of managing capacity. While the commercial introduction of new technology is an important factor in realizing pricing improvement, without capital discipline throughout the industry as a whole, meaningful improvements in our prices are not likely to be realized.

We do business in over 90 countries including over one-half of the 30 countries having the lowest scores, which indicates high levels of corruption, in Transparency International’s Corruption Perception Index (“CPI”) survey for 2006. We devote significant resources to the development, maintenance and enforcement of our Business Code of Conduct policy, our Foreign Corrupt Practices Act (“FCPA”) policy, our internal control processes and procedures and other compliance related policies. Notwithstanding the devotion of such resources, and in part as a consequence thereof, from time to time we discover or receive information alleging potential violations of laws and regulations, including the FCPA and our policies, processes and procedures. We conduct internal investigations of these potential violations and take appropriate action depending upon the outcome of the investigation. In addition, in April 2007, we entered into agreements with the Department of Justice (“DOJ”) and the Securities and Exchange Commission (“SEC”) that require an independent monitor for three years to assess whether our policies and procedures are reasonably designed to detect and prevent violations of the FCPA, all applicable U.S. commercial bribery laws, and all applicable foreign bribery laws, by reviewing the controls, policies and procedures of the Company and its affiliates and subsidiaries. See “Part II, Item 1. Legal Proceedings” contained herein for additional information.

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 and the activities of the independent monitor 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.

DISCONTINUED OPERATIONS

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. In addition, the discussions below for revenues and cost of revenues are on a combined basis as the business drivers for the individual components of product sales and services and rentals are similar.

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, 2007 and 2006, respectively.


	Three Months Ended June 30,
	2007				2006

Revenues	$	2,537.5	100.0	%	$	2,203.3	100.0	%
Cost of revenues		1,554.8	61.3	%		1,340.6	60.8	%
Research and engineering		92.6	3.6	%		82.0	3.7	%
Selling, general and administrative		353.0	13.9	%		292.2	13.3	%


	Six Months Ended June 30,
	2007				2006

Revenues	$	5,010.3	100.0	%	$	4,265.3	100.0	%
Cost of revenues		3,038.6	60.6	%		2,611.7	61.2	%
Research and engineering		184.2	3.7	%		160.4	3.8	%
Selling, general and administrative		690.2	13.8	%		564.3	13.2	%

Revenues

Revenues for the three months ended June 30, 2007 increased 15.2% compared with the three months ended June 30, 2006, primarily due to increases in activity in certain geographic areas, overall price increases averaging approximately four percent and changes in market share in selected product lines and geographic areas. These increases were partially offset by activity declines in Canada and the U.S. offshore market. Revenues in North America, which accounted for 41.4% of total revenues, increased 7.6% for the three months ended June 30, 2007 compared with the three months ended June 30, 2006. This increase reflects a continued increase in U.S. land and inland waters drilling activity, as evidenced by the 9.2% increase in the rig count and pricing improvements, which more than offset the deterioration in the Canadian and U.S. offshore activity. Revenues outside North America, which accounted for 58.6% of total revenues, increased 21.1% for the three months ended June 30, 2007 compared with the three months ended June 30, 2006. This increase reflects the improvement in international drilling activity, as evidenced by the 9.9% increase in the rig count outside North America, particularly in Latin America, Africa, the Middle East and Asia Pacific region, coupled with pricing improvements in certain markets and product lines.

Revenues for the six months ended June 30, 2007 increased 17.5% compared with the six months ended June 30, 2006. Revenues were positively impacted by the increased activity from land rigs drilling for natural gas in the U.S., driven by continued investment in drilling for natural gas prospects; increased activity in certain international markets, including Latin America, Africa, Middle East and the Asia Pacific region; and pricing improvements in certain markets and product lines. These increases were partially offset by weaker activity in Canada and the U.S. offshore market.

Cost of Revenues

Cost of revenues for the three months ended June 30, 2007 increased 16.0% compared with the three months ended June 30, 2006. Cost of revenues as a percentage of consolidated revenues was 61.3% and 60.8% for the three months ended June 30, 2007 and 2006, respectively. The increase in cost of revenues as a percentage of consolidated revenues during the second quarter of 2007 is due primarily to the decrease in activity and profitability in the U.S. offshore market and in Canada, particularly in the Drilling and Evaluation segment, and an increase in repair and maintenance costs at our INTEQ division. Cost of revenues for the six months

ended June 30, 2007 increased 16.3% compared with the six months ended June 30, 2006. Cost of revenues as a percentage of consolidated revenues was 60.6% and 61.2% for the six months ended June 30, 2007 and 2006, respectively. The decrease in cost of revenues as a percentage of consolidated revenues was primarily the result of overall average price increases 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, higher repair and maintenance costs and the decline in activity in the U.S. offshore market and Canada. Additionally, effective January 1, 2007, we increased the depreciable lives of certain assets of our Baker Atlas division resulting in a reduction to cost of services and rentals of approximately $6.0 million and $12.0 million for the three months and six months ended June 30, 2007, respectively.

Research and Engineering

Research and engineering expenses increased 12.9% in the three months ended June 30, 2007 compared with the three months ended June 30, 2006 and increased 14.8% in the six months ended June 30, 2007 compared with the six months ended June 30, 2006. The increase reflects our continued commitment to developing and commercializing new technologies as well as investing in our core product offerings.

Selling, General and Administrative

Selling, general and administrative expenses increased 20.8% in the three months ended June 30, 2007 compared with the three months ended June 30, 2006 and increased 22.3% in the six months ended June 30, 2007 compared with the six months ended June 30, 2006. The increase corresponds with increased activity and resulted primarily from higher employee related costs including compensation, training and benefits, as well as higher marketing expenses as a result of increased activity.

Equity in Income of Affiliates

Equity in income of affiliates decreased $11.1 million in the three months ended June 30, 2007 compared with the three months ended June 30, 2006 and decreased $59.1 million in the six months ended June 30, 2007 compared with the six months ended June 30, 2006. The decrease in equity in income of affiliates 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 after-tax).

Interest and Dividend Income

Interest and dividend income decreased $13.5 million in the three months ended June 30, 2007 compared with the three months ended June 30, 2006 and decreased $9.3 million in the six months ended June 30, 2007 compared with the six months ended June 30, 2006. The decrease was primarily due to lower average cash and short-term investment balances.

Income Taxes

Our effective tax rate is lower than the U.S. statutory income tax rate of 35% due to lower rates of tax on certain international operations offset by state income taxes.

Our tax filings for various periods are subject to audit by the tax authorities in most jurisdictions where we conduct business. These audits may result in assessment of additional taxes that are resolved with the authorities or through the courts. We believe 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 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. We provide for uncertain tax positions pursuant to FIN 48,Accounting for Uncertainty in Income Taxes: an Interpretation of FASB Statement No. 109.

During the second quarter of 2007, we provided $9.3 million of additional taxes, and related interest and penalties associated with disallowed tax deductions taken in previous years, arising from the previously announced resolution of investigations with the SEC and the DOJ.

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, 2007, cash flows from operations were the principal sources of funding. We anticipate that cash flows from operations will be sufficient to fund our liquidity needs in 2007. We also have a $500.0 million committed revolving credit facility that provides back-up liquidity in the event an unanticipated and significant demand on cash could not be funded by operations.

Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of our company. During the six months ended June 30, 2007, we used cash for a variety of activities including working capital needs, 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:


	2007			2006

Operating activities	$	316.3		$	164.2
Investing activities		(279.2	)		1,750.4
Financing activities		(144.5	)		(1,113.9	)

Statements of cash flows for entities with international operations that are local currency functional exclude the effects of the changes in foreign currency exchange rates that occur during any given period, as these are noncash charges. As a result, changes reflected in certain accounts on the consolidated condensed statements of cash flows may not reflect the changes in corresponding accounts on the consolidated condensed balance sheets.

Operating Activities

Cash flows from operating activities of continuing operations provided $316.3 million in the six months ended June 30, 2007 compared with $164.2 million in the six months ended June 30, 2006. Cash flows from operating activities for the six months ended June 30, 2007 and 2006, were reduced by $98.2 million and $313.3 million, respectively, for income tax payments made related to the sale of our interest in WesternGeco. Cash flows from other operating activities decreased $63.0 million primarily due to an increase in net operating assets and liabilities that used cash.

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, 2007 used $87.8 million in cash compared with using $161.0 million in cash in the six months ended June 30, 2006. This increase was primarily due to the increase in revenues offset partially by an increase in collections as reflected in a decrease in days sales outstanding (defined as the average number of days net our trade receivables are outstanding based on quarterly revenues) of approximately one day.

	•		A build up of inventory in anticipation of and related to increased activity used $152.4 million in cash in the six months ended June 30, 2007 compared with using $177.1 million in cash in the six months ended June 30, 2006.

	•		Accrued employee compensation and other accrued liabilities used $253.5 million in cash in the six months ended June 30, 2007 compared with using $65.0 million in cash in the six months ended June 30, 2006. This increase was primarily due to an increase in payments made in the first six months of 2007 that were greater than payments made in the first six months of 2006 related to employee bonuses, non income tax liabilities and the payment of $44.1 million related to the settlement of the investigations by the SEC and DOJ.

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 $538.4 million and $367.2 million for the six months ended June 30, 2007 and 2006, respectively. The majority of these expenditures were for rental tools and machinery and equipment, including wireline equipment.

During the six months ended June 30, 2007, we purchased $1,733.5 million of and received proceeds of $1,902.0 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.

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. 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.

Proceeds from the disposal of property, plant and equipment were $90.7 million and $59.0 million for the six months ended June 30, 2007 and 2006, 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.

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.

Financing Activities

We had net borrowings (repayments) of short-term debt of $1.1 million and $(10.3) million in the six months ended June 30, 2007 and 2006, respectively. Total debt outstanding at June 30, 2007 was $1,073.8 million, a decrease of $1.3 million compared with December 31, 2006. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratios were 0.16 at June 30, 2007 and 0.17 at December 31, 2006.

We received proceeds of $31.0 million and $55.0 million in the six months ended June 30, 2007 and 2006, respectively, from the issuance of common stock from the exercise of stock options.

In April 2006, the Board of Directors authorized the repurchase of $1.8 billion of common stock which was in addition to the balance remaining from the Board of Directors’ previous authorizations. During the six months ended June 30, 2007, we repurchased 1.2 million shares of our common stock at an average price of $82.26 per share, for a total of $98.8 million. At June 30, 2007, we had authorization remaining to repurchase up to a total of $246.7 million of our common stock. Repurchases were made under both a Stock Purchase Plan (the “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 “Exchange Act”) and open market purchases that comply with Rule 10b-18 of the Exchange Act. On June 12, 2007, we entered the Plan that runs from June 13, 2007 until July 31, 2007 unless earlier terminated. Under the Plan, the agent will repurchase a number of shares, if any, of our common stock determined under the terms of the Plan each trading day based on the trading price of the stock on that day. Shares are repurchased by the agent at prevailing market prices, in open market transactions which 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.

We paid dividends of $83.1 million and $88.5 million in the six months ended June 30, 2007 and 2006, respectively.

Available Credit Facilities

At June 30, 2007, we had $1,018.4 million of credit facilities with commercial banks, of which $500.0 million is a committed revolving credit facility (the “facility”) which expires in July 2012. The facility provides for a one-year extension, 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, 2007, we were in compliance with all of the facility covenants. There were no direct borrowings under the facility during the quarter ended June 30, 2007; however, to

the extent we have outstanding commercial paper, our ability to borrow under the facility is reduced. At June 30, 2007, 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 2007, we believe operating cash flows 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 2007, we expect capital expenditures to be between $1.1 billion and $1.2 billion, 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 2007, we expect to make interest payments of between $73.0 million and $75.0 million. This is based on our current expectations of debt levels during 2007.

During the second quarter of 2007, we revised our estimate for income tax payments for 2007 and now we anticipate making income tax payments of between $790.0 million and $840.0 million in 2007.

We anticipate paying dividends of between $165.0 million and $170.0 million in 2007; however, the Board of Directors can change the dividend policy at anytime.

As of June 30, 2007, we had authorization remaining to repurchase up to $246.7 million of common stock. On July 26, 2007, our Board of Directors authorized a plan to repurchase up to $1.0 billion of our common stock, from time to time, in addition to the existing stock repurchase plan in open market or privately negotiated transactions. We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. The repurchased shares will be retired. As of July 26, 2007, we have authorization to repurchase up to $1.2 billion of common stock.

In the U.S., we merged two defined benefit pension plans effective January 1, 2007, resulting in one tax-qualified U.S. pension plan, the Baker Hughes Incorporated Pension Plan (“BHIPP”). As a result of the merger of these plans, BHIPP is overfunded; therefore, we are not required nor do we intend to make pension contributions to BHIPP in 2007, and we currently estimate that we will not be required to make contributions to BHIPP for five to eight years thereafter. In 2007, we estimate we will contribute between $28.0 million and $33.0 million to our other defined benefit pension plans and our postretirement welfare plans, and between $115.0 million and $125.0 million to our defined contribution plans.

Other than previously discussed, 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 2007 are not indicative of what we can expect in the near term.

NEW ACCOUNTING STANDARDS

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FIN 48,Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109. FIN 48 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, the tax benefit from an uncertain tax position is to be recognized when it is more likely than not, based on the technical merits of the position, that the position will be sustained on examination by the taxing authorities. Additionally, the amount of the tax benefit to be recognized is the largest amount of benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and financial statement disclosures. We adopted

FIN 48 on January 1, 2007 and recorded a reduction to beginning retained earnings of $64.2 million and recognized a $78.5 million increase in the gross liability for unrecognized tax benefits, which included $17.3 million of interest and penalties. As a result of the implementation of FIN 48, we recognized the following adjustments to our accounts as of January 1, 2007.


	Increase (Decrease)

Beginning retained earnings	$	(64.2	)
Deferred tax assets		(0.6	)
Non-current tax receivables		14.9
Tax liabilities		78.5

In September 2006, the FASB issued FASB Staff Position No. AUG AIR-1 (“FSP AUG AIR-1”), which addresses the accounting for planned major maintenance activities. FSP AUG AIR-1 prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. We adopted FSP AUG AIR-1 on January 1, 2007 to change our method of accounting for repairs and maintenance activities on certain rental tools from the accrue-in-advance method to the direct expense method. The adoption resulted in the reversal of a $34.2 million accrued liability for future repairs and maintenance costs and the recording of an income tax liability of $9.0 million. The net impact of $25.2 million has been recorded as an increase to beginning retained earnings as of January 1, 2007. We did not restate any prior periods as the impact was not material to our 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, expenses, capital spending, backlogs, profitability, tax rates, 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, 2006, the Company’s Form 10-Q for the quarter ended March 31, 2007, 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, 2007, we had entered into several foreign currency forward contracts with notional amounts aggregating $130.0 million to hedge exposure to currency fluctuations in various currencies, including British Pound Sterling, Euro, Norwegian Krone, Brazilian Real and Indonesian Rupiah. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of June 30, 2007 for contracts with similar terms and maturity dates, during the second quarter of 2007 we recorded a gain of $0.5 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.

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, 2007, 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 SEC rules and forms. There has been no change in our internal controls over financial reporting during the quarter ended June 30, 2007 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 SEC and the DOJ were conducting investigations into allegations of violations of law relating to Nigeria and other related matters. The SEC issued a formal order of investigation into possible violations of provisions under the Foreign Corrupt Practices Act (“FCPA”) regarding antibribery, books and records and internal controls. In connection with the investigations, the SEC 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 have provided documents to and cooperated fully with the SEC and DOJ. In addition, we have conducted internal investigations into these matters. Our internal investigations 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 Angola, Kazakhstan and Nigeria, as well as potential liabilities to government authorities in Nigeria. Evidence obtained during the course of the investigations has been provided to the SEC and DOJ.

On April 26, 2007, the United States District Court, Southern District of Texas, Houston Division (the “Court”) unsealed a three-count criminal information that had been filed against the Company as part of the execution of a Deferred Prosecution Agreement (the “DPA”) between us and the DOJ. The three counts arise out of payments made to an agent in connection with a project in Kazakhstan and include conspiracy to violate the FCPA, a substantive violation of the antibribery provisions of the FCPA, and a violation of the FCPA’s books-and-records provisions. All three counts relate to the Company’s operations in Kazakhstan during the period from 2000 to 2003. Although the Company did not plead guilty to that information, it faces prosecution under that information, and possibly under other charges as well, if it fails to comply with the terms of the DPA. Those terms include, for the two-year term of the DPA, full cooperation with the government; compliance with all federal criminal law, including but not limited to the FCPA; and adoption of a Compliance Code containing specific provisions intended to prevent violations of the FCPA. The DPA also requires the Company to retain an independent monitor for a term of three years to assess and make recommendations about the Company’s compliance policies and procedures and our implementation of those procedures. Provided that the Company complies with the DPA, the DOJ has agreed not to prosecute the Company for violations of the FCPA based on information that the Company has disclosed to the DOJ regarding its operations in Nigeria, Angola, Kazakhstan, Indonesia, Russia, Uzbekistan, Turkmenistan, and Azerbaijan, among other countries.

Also on April 26, 2007, the SEC filed a Complaint (the “SEC Complaint”) and a proposed order (the “SEC Order”) against the Company in the Court. The SEC Complaint and the SEC Order were filed as part of a settled civil enforcement action by the SEC, to resolve the civil portion of the government’s investigation of the Company. As part of its agreement with the SEC, the Company consented to the filing of the SEC Complaint without admitting or denying the allegations in the Complaint, and also consented to the entry of the SEC Order. The SEC Complaint alleges civil violations of the FCPA’s antibribery provisions related to the Company’s operations in Kazakhstan, the FCPA’s books-and-records and internal-controls provisions related to the Company’s operations in Nigeria, Angola, Kazakhstan, Indonesia, Russia, and Uzbekistan, and the SEC’s cease and desist order of September 12, 2001, which has been previously disclosed in our Annual Reports on Form 10-K. The SEC Order became effective on May 1, 2007, which is the date it was confirmed by the Court. The SEC order enjoins the Company from violating the FCPA’s antibribery, books-and-records, and internal-controls provisions. As in the DPA, it requires that the Company retain the independent monitor to assess its FCPA compliance policies and procedures for the three-year period.

Under the terms of the settlements with the DOJ and the SEC, the Company and BHSII paid in the second quarter of 2007, $44.1 million ($11 million in criminal penalties, $10 million in civil penalties, $19.9 million in disgorgement of profits and $3.2 million in pre-judgment interest) to settle these investigations. In the fourth quarter of 2006, we recorded a financial charge for the potential settlement. We previously disclosed copies of these settlements in our Quarterly Report on Form 10-Q for the period ended March 31, 2007 and a copy of the SEC Order is attached hereto as Exhibit 99.1 and incorporated herein by reference.

For additional information see, “Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Business Outlook” and “Item 5 — Other Information” of our Form 10-Q for the period ended March 31, 2007.

On May 4, 2007 and May 15, 2007, The Sheetmetal Workers’ National Pension Fund and Chris Larson, respectively, instituted shareholder derivative lawsuits for and on the Company’s behalf against certain current and former members of the Board of Directors and certain officers, and the Company as a nominal defendant, following the Company’s April 27, 2007 settlement with the United States Department of Justice and Securities and Exchange Commission. Both complaints allege, among other things, that the individual Defendants failed to implement adequate controls and compliance procedures to prevent the events addressed by the settlement with the SEC and DOJ. The relief sought in the lawsuits includes a declaration that the Defendants breached their fiduciary duties, an award of damages sustained by the Company as a result of the alleged breach and monetary and injunctive relief, as well as attorneys’ and experts’ fees. The lawsuit brought by the Sheetmetal Workers’ National Pension Fund is pending in the Houston Division of the United States District Court for the Southern District of Texas. The lawsuit brought by Chris Larson is pending in the 215th District Court of Harris County, Texas. We do not expect these lawsuits to have a material adverse effect on our consolidated condensed financial statements.

For additional discussion of legal proceedings see “Item 3 — Legal Proceedings” of Part I of our Annual Report on Form 10-K for the year ended December 31, 2006 (“2006 Annual Report”).

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 2006 Annual Report and the Form 10-Q for the period ended March 31, 2007 (“2007 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 2006 Annual Report, 2007 Filings and subsequent filings with the SEC as well as the risk factors described in this Form 10-Q. 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.

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, 2007.

Issuer Purchases of Equity Securities


											Maximum Number (or
											Approximate Dollar
					Total Number of						Value) of Shares
					Shares Purchased as						that May Yet Be
	Total Number of		Average Price Paid		Part of a Publicly		Average Price Paid		Total Number of		Purchased Under the
	Shares Purchased		Per Share		Announced Program		Per Share		Shares Purchased in		Program
Period	⁽¹⁾		⁽¹⁾		⁽²⁾		⁽³⁾		the Aggregate		⁽⁴⁾

April 1-30, 2007		732	$	78.51		—	$	—		732		—
May 1-31, 2007		—		—		722,000		81.07		722,000		—
June 1-30, 2007		135		89.36		478,700		84.06		478,835		—

Total		867	$	80.20		1,200,700	$	82.26		1,201,567	$	246,700,000


⁽¹⁾		Represents shares purchased from employees to pay the option exercise price related to stock-for-stock exchanges in option exercises or to satisfy the tax withholding obligations in connection with the vesting of restricted stock awards and restricted stock units.

⁽²⁾		Repurchases were made under both a Stock Purchase Plan (the “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 “Exchange Act”) and open market purchases that comply with Rule 10b-18 of the Exchange Act. On June 12, 2007, we entered the Plan that runs from June 13, 2007 until July 31, 2007 unless earlier terminated. Under the Plan, the agent will repurchase a number of shares, if any, of our common stock determined under the terms of the Plan each trading day based on the trading price of the stock on that day. Shares are repurchased by the agent at prevailing market prices, in open market transactions which comply with Rule 10b-18 of the Exchange Act.

⁽³⁾		Average price paid includes commissions.


⁽⁴⁾		In April 2006, the Board of Directors authorized the repurchase of an additional $1.8 billion of common stock which was in addition to the balance remaining from the Board of Directors’ previous authorization. During the second quarter of 2007, we repurchased 1.2 million shares of our common stock at an average price of $82.26 per share, for a total of $98.8 million. At June 30, 2007, we had authorization remaining to repurchase up to a total of $246.7 million of our common stock. On July 26, 2007, our Board of Directors authorized a plan to repurchase up to $1.0 billion of our common stock, from time to time, in addition to the existing stock repurchase plan. As of July 26, 2007, we have authorization to repurchase up to $1.2 billion of common stock.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

On April 26, 2007, 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, 2007.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS


	3.1			Restated Certificate of Incorporation dated July 26, 2007.

	4.2			Restated Certificate of Incorporation (filed as Exhibit 3.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2007).

	10.1			Second Amendment to the Credit Agreement dated as of May 31, 2007, among Baker Hughes Incorporated and fifteen banks (filed as Exhibit 10-1 to Current Report of Baker Hughes Incorporated on Form 8-K filed June 4, 2007, and incorporated herein by reference).

	31.1			Certification of Chad C. Deaton, Chief Executive Officer, dated July 30, 2007, 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 30, 2007, 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 30, 2007, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.

	99.1			Final Judgment by the Securities and Exchange Commission as to Defendant Baker Hughes Incorporated dated and filed on May 1, 2007 with the United States District Court of Texas, Houston Division.

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 30, 2007	By:	/s/ PETER A. RAGAUSS
		Peter A. Ragauss
		Senior Vice President and Chief Financial Officer


Date: July 30, 2007	By:	/s/ ALAN J. KEIFER
		Alan J. Keifer
		Vice President and Controller

EXHIBIT INDEX



	3.1			Restated Certificate of Incorporation dated July 26, 2007.

	4.2			Restated Certificate of Incorporation (filed as Exhibit 3.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2007).

	10.1			Second Amendment to the Credit Agreement dated as of May 31, 2007, among Baker Hughes Incorporated and fifteen banks (filed as Exhibit 10-1 to Current Report of Baker Hughes Incorporated on Form 8-K filed June 4, 2007, and incorporated herein by reference).

	31.1			Certification of Chad C. Deaton, Chief Executive Officer, dated July 30, 2007, 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 30, 2007, 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 30, 2007, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.

	99.1			Final Judgment by the Securities and Exchange Commission as to Defendant Baker Hughes Incorporated dated and filed on May 1, 2007 with the United States District Court of Texas, Houston Division.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Good

BAKER HUGHES a GE (BHI) 10-Q2007 Q2 Quarterly report

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