e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


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

For the quarterly period ended March 31, 2010


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. YESþ NOo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YESþ NOo

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


Large accelerated filerþ		Accelerated filero		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting companyo

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

As of April 30, 2010, the registrant has outstanding 429,045,990 shares of common stock, $1 par value per share.

Baker Hughes Incorporated

Consolidated Condensed Balance Sheets

(In millions)

(Unaudited)


	March 31,			December 31,
	2010			2009

ASSETS

Current Assets:
Cash and cash equivalents	$	1,614		$	1,595
Accounts receivable — less allowance for doubtful accounts (2010 - $143; 2009 - $157)		2,464			2,331
Inventories, net		1,952			1,836
Deferred income taxes		268			268
Other current assets		223			195

Total current assets		6,521			6,225

Property, plant and equipment, net		3,051			3,161
Goodwill		1,419			1,418
Intangible assets, net		185			195
Other assets		454			440

Total assets	$	11,630		$	11,439


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Accounts payable	$	858		$	821
Short-term borrowings		232			15
Accrued employee compensation		420			448
Income taxes payable		37			95
Other accrued liabilities		245			234

Total current liabilities		1,792			1,613

Long-term debt		1,788			1,785
Deferred income taxes and other tax liabilities		261			309
Liabilities for pensions and other postretirement benefits		369			379
Other liabilities		73			69
Commitments and contingencies

Stockholders’ Equity:
Common stock		312			312
Capital in excess of par value		890			874
Retained earnings		6,594			6,512
Accumulated other comprehensive loss		(449	)		(414	)

Total stockholders’ equity		7,347			7,284

Total liabilities and stockholders’ equity	$	11,630		$	11,439

See accompanying notes to unaudited consolidated condensed financial statements.

Baker Hughes Incorporated

Consolidated Condensed Statements of Cash Flows

(In millions)

(Unaudited)


	Three Months Ended
	March 31,
	2010			2009

Cash flows from operating activities:
Net income	$	129		$	195
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		189			173
Stock-based compensation costs		19			23
Provision (benefit) for deferred income taxes		(40	)		10
Gain on disposal of assets		(29	)		(21	)
Net provision for doubtful accounts		(2	)		29
Changes in operating assets and liabilities:
Accounts receivable		(154	)		229
Inventories		(47	)		(96	)
Accounts payable		56			(145	)
Accrued employee compensation and other accrued liabilities		(22	)		(171	)
Income taxes payable		(53	)		(161	)
Other		(41	)		(31	)

Net cash flows from operating activities		5			34


Cash flows from investing activities:
Expenditures for capital assets		(190	)		(281	)
Proceeds from disposal of assets		45			47

Net cash flows from investing activities		(145	)		(234	)


Cash flows from financing activities:
Net borrowings of commercial paper and other short-term debt		218			4
Repayment of long-term debt		—			(525	)
Proceeds from issuance of common stock		2			—
Dividends		(47	)		(46	)
Excess tax benefits from stock-based compensation costs		1			—

Net cash flows from financing activities		174			(567	)


Effect of foreign exchange rate changes on cash		(15	)		(9	)

Increase/(decrease) in cash and cash equivalents		19			(776	)
Cash and cash equivalents, beginning of period		1,595			1,955

Cash and cash equivalents, end of period	$	1,614		$	1,179


Supplemental cash flows disclosures:
Income taxes paid (net of refunds)	$	158		$	249
Interest paid	$	20		$	33
Supplemental disclosure of noncash investing activities:
Capital expenditures included in accounts payable	$	15		$	21

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 major supplier of wellbore-related products and technology services and systems and provide products and services for drilling, formation evaluation, completion and production, and reservoir technology and consulting to the worldwide oil and natural gas industry.

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 in the United States of America (“GAAP”) 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, 2009 (“2009 Annual Report”). 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 October 2009, the Financial Accounting Standards Board (“FASB”) issued an update to Accounting Standards Codification (“ASC”) 605, Revenue Recognition — Multiple Deliverable Revenue Arrangements. This Accounting Standards Update (“ASU”) addresses accounting for multiple-deliverable arrangements to enable vendors to account for deliverables separately. The provision establishes a selling price hierarchy for determining the selling price of a deliverable. This update requires expanded disclosures for multiple deliverable revenue arrangements. The ASU will be effective for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010. We have not determined the impact, if any, on our consolidated condensed financial statements.

In January 2010, the FASB issued an update to ASC 820, Fair Value Measurements and Disclosures- Improving Disclosures about Fair Value Measurements. This update provides a greater level of enhanced information and disclosures about valuation techniques and inputs to fair value measurements. The new disclosures are effective for interim and annual reporting periods beginning after December 15, 2009. We adopted the new disclosure requirements in the first quarter of 2010 as reflected in Note 8. Fair Value of Certain Financial Assets and Liabilities. Disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years.

NOTE 2. SUBSEQUENT EVENT – MERGER WITH BJ SERVICES COMPANY

On April 28, 2010 (the “Closing Date”), we completed a cash and stock merger with BJ Services Company (“BJ Services”) whereby we acquired 100% of the outstanding common stock of BJ Services, a leading provider of pressure pumping and oilfield services. The merger consideration totaled $6.9 billion based on the closing price of our stock on April 28, 2010. Under the terms of the merger agreement, each share of BJ Services common stock was converted into 0.40035 shares of our common stock and $2.69 in cash. In total, we paid out $0.8 billion in cash, issued 118.0 million shares, valued at $6.1 billion based upon the closing price of our common stock on the Closing Date, and assumed outstanding stock options held by BJ Services employees and directors. We also guaranteed $500 million of long-term debt of BJ Services. The merger will be accounted for using the acquisition method of accounting. Under the acquisition method of accounting, we are required to allocate the purchase price to tangible and identifiable intangible assets acquired and liabilities assumed based on their fair values at the Closing Date. The excess of the purchase price over those fair values is recorded as goodwill. We are in the process of valuing the assets acquired and liabilities assumed. Assuming the merger with BJ Services occurred on January 1, 2010 and January 1, 2009, pro forma revenues of the Company for the three months ended March 31, 2010 and 2009 would have been approximately $3.6 billion and $3.7 billion, respectively. Other disclosures required by ASC 805, Business Combinations, will be provided once the initial accounting for the merger is complete.

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

Pursuant to a final agreement with the Antitrust Division of the Department Of Justice (“DOJ”) in connection with the governmental approval of the merger between us and BJ Services, we are required to divest two chartered stimulation vessels (the HR Hughes and Blue Ray) and certain other assets used to perform sand control services in the U.S. Gulf of Mexico. Pursuant to a Hold Separate Stipulation and Order, the operation of our U.S. business and the U.S. business of BJ Services will be required to be operated separately until these assets are divested. We do not expect the divestiture to be material to the business or financial performance of the combined company following the merger.

Unless otherwise noted, all disclosures in the notes to unaudited consolidated condensed financial statements exclude any information related to and any potential impact that may result from the merger.

NOTE 3. 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. The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes option pricing model. The fair value of restricted stock awards and units is based on the market price of our common stock on the date of grant.

We also have an Employee Stock Purchase Plan (“ESPP”) available for eligible employees to purchase shares of our common stock. Effective January 1, 2010, the ESPP provides for shares to be purchased: (i) on June 30^th of each year at a 15% discount of the fair market value of our common stock on January 1^st or June 30^th, whichever is lower, and (ii) on December 31^st of each year at a 15% discount of fair market value of our common stock on July 1^st or December 31^st, whichever is lower. Also effective January 1, 2010, an employee may not contribute more than $5,000 in either of the six-month measurement periods described above or $10,000 annually.

The following summarizes stock-based compensation expense recognized in our consolidated condensed statements of operations:


	Three Months Ended
	March 31,
	2010		2009

Stock Options	$	7	$	7
Restricted Stock Awards and Units		10		10
ESPP		2		6

Total	$	19	$	23

NOTE 4. EARNINGS PER SHARE

A reconciliation of the number of shares used for the basic and diluted earnings per share (“EPS”) calculation is as follows:


	Three Months Ended
	March 31,
	2010		2009

Weighted average common shares outstanding for basic EPS		313		310
Effect of dilutive securities — stock plans		—		—

Adjusted weighted average common shares outstanding for diluted EPS		313		310


Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than average market price for the period		2		3

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

NOTE 5. INVENTORIES

Inventories, net of reserves, are comprised of the following:


	March 31,		December 31,
	2010		2009

Finished goods	$	1,670	$	1,570
Work in process		139		126
Raw materials		143		140

Total	$	1,952	$	1,836

NOTE 6. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are comprised of the following:


	March 31,			December 31,
	2010			2009

Land	$	81		$	81
Buildings and improvements		1,170			1,136
Machinery and equipment		3,402			3,384
Rental tools and equipment		2,174			2,228

Subtotal		6,827			6,829
Accumulated depreciation		(3,776	)		(3,668	)

Total	$	3,051		$	3,161

NOTE 7. 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, 2009	$	979	$	439	$	1,418
Purchase price and other adjustments		1		—		1

Balance as of March 31, 2010	$	980	$	439	$	1,419

Intangible assets are comprised of the following:


	March 31, 2010							December 31, 2009
	Gross							Gross
	Carrying		Accumulated					Carrying		Accumulated
	Amount		Amortization			Net		Amount		Amortization			Net

Technology-based	$	277	$	(147	)	$	130	$	277	$	(140	)	$	137
Contract-based		13		(10	)		3		13		(9	)		4
Marketing-related		36		(14	)		22		36		(13	)		23
Customer-based		41		(11	)		30		41		(10	)		31
Other		—		—			—		1		(1	)		—

Total	$	367	$	(182	)	$	185	$	368	$	(173	)	$	195

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 expected to be realized, which range from 15 to 30 years.

Amortization expense for intangible assets included in net income for the three months ended March 31, 2010 was $9 million and is estimated to be $25 million for the year 2010. Estimated amortization expense for each of the subsequent five fiscal years is

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

expected to be as follows: 2011 — $19 million; 2012 — $18 million; 2013 — $18 million; 2014 — $16 million; and 2015 — $16 million.

NOTE 8. FAIR VALUE OF CERTAIN FINANCIAL ASSETS AND LIABILITIES

Financial assets and liabilities measured at fair value are based on a hierarchy that prioritizes the inputs to valuation techniques into three broad levels, which are described below:

•		Level 1 inputs are quoted market prices in active markets for identical assets or liabilities (these are observable market inputs).

•		Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability (includes quoted market prices for similar assets or identical or similar assets in markets in which there are few transactions, prices that are not current or vary substantially).

•		Level 3 inputs are unobservable inputs that reflect the entity’s own assumptions in pricing the asset or liability (used when little or no market data is available).

In the first quarter of 2010, we adopted an update to ASC 820, which requires a greater level of enhanced information and disclosures. The new disclosures require us to provide fair values for each class of certain financial assets and liabilities. A class is defined as a subset of certain financial assets and liabilities within the line item in the balance sheet.

Non-qualified Defined Contribution Plan Assets and Liabilities

We have a non-qualified defined contribution plan that provides basically the same benefits as our Thrift Plan for certain non-U.S. employees who are not eligible to participate in the Thrift Plan. In addition, we provide a non-qualified supplemental retirement plan for certain officers and employees whose benefits under the Thrift Plan and/or U.S. defined benefit pension plan are limited by federal tax law. We hold the assets of these plans under a grantor trust and have recorded the assets along with the related deferred compensation liability at fair value. The assets and liabilities were valued using Level 1 inputs at the reporting date and were based on quoted market prices from various major stock exchanges. The fair value of the qualified defined contribution plan assets and liabilities as of March 31, 2010 and December 31, 2009 are classified based on the valuation hierarchy in the tables below:


	Fair Value Measurement at March 31, 2010
Description	Total		Level 1		Level 2		Level 3

Assets:
Non-qualified defined contribution plan assets:
Equity Mutual Funds	$	86	$	86	$	—	$	—
Cash Funds		33		33		—		—
Bond Mutual Funds		22		22		—		—
Balanced Funds		4		4		—		—
Equity securities		3		3		—		—

Total	$	148	$	148	$	—	$	—


Liabilities:

Non-qualified defined contribution plan liabilities	$	148	$	148	$	—	$	—


	Fair Value Measurement at December 31, 2009
Description	Total		Level 1		Level 2		Level 3

Assets:
Non-qualified defined contribution plan assets:
Equity Mutual Funds	$	82	$	82	$	—	$	—
Cash Funds		35		35		—		—
Bond Mutual Funds		22		22		—		—
Balanced Funds		5		5		—		—
Equity securities		2		2		—		—

Total	$	146	$	146	$	—	$	—


Liabilities:

Non-qualified defined contribution plan liabilities	$	146	$	146	$	—	$	—

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

NOTE 9. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable, debt, foreign currency forward contracts and interest rate swaps. Except as described below, the estimated fair value of such financial instruments at March 31, 2010 as reflected in our consolidated condensed balance sheet approximates their carrying value due to the short maturities of these instruments.

Debt

The estimated fair value of total debt at March 31, 2010 and December 31, 2009, was $2.37 billion and $2.13 billion, which differs from the carrying amount of $2.02 billion and $1.80 billion, respectively, included in our consolidated condensed balance sheet. The fair value of our debt has been estimated based on quoted market prices for the respective period.

Foreign Currency Forward Contracts

We conduct our business in over 90 countries around the world, and we are exposed to market risks resulting from fluctuations in foreign currency exchange rates. A number of our significant foreign subsidiaries have designated the local currency as their functional currency. We transact in various foreign currencies and seek to balance our foreign currency exposures by matching our revenue and costs in non-functional currencies where possible. Where imbalances in the non-functional currencies remain we have established a program that primarily utilizes foreign currency forward contracts to reduce the risks associated with the effects of certain foreign currency exposures. Under this program, our strategy is to have gains or losses on the foreign currency forward contracts mitigate the foreign currency transaction gains or losses to the extent practical. These foreign currency exposures typically arise from changes in the value of assets and liabilities which are denominated in currencies other than the functional currency. Our foreign currency forward contracts generally settle within 90 to 120 days. We do not use these forward contracts for trading or speculative purposes. We designate these forward contracts as fair value hedging instruments pursuant to ASC 815. Accordingly, we record the fair value of these contracts as of the end of our reporting period to our consolidated condensed balance sheet with changes in fair value recorded in our consolidated condensed statement of operations along with the change in fair value of the hedged item.

At March 31, 2010, we had outstanding foreign currency forward contracts with notional amounts aggregating $175 million to hedge exposure to currency fluctuations in various foreign currencies. These contracts expire on various dates prior to the end of the third quarter of 2010. These contracts are designated and qualify as fair value hedging instruments. The fair value was determined using a model with Level 2 inputs including quoted market prices for contracts with similar terms and maturity dates.

Interest Rate Swaps

We are subject to interest rate risk on our debt and investment of cash and cash equivalents arising in the normal course of our business, as we do not engage in speculative trading strategies. We maintain an interest rate management strategy, which primarily uses a mix of fixed and variable rate debt that is intended to mitigate the exposure to changes in interest rates in the aggregate for our investment portfolio. In addition, we are currently using interest rate swaps to manage the economic effect of fixed rate obligations associated with our senior notes so that the interest payable on the senior notes effectively becomes linked to variable rates.

In June 2009, we entered into two interest rate swap agreements (“the Swap Agreements”) for a notional amount of $250 million each in order to hedge changes in the fair market value of our $500 million 6.5% senior notes maturing on November 15, 2013. Under the Swap Agreements, we receive interest at a fixed rate of 6.5% and pay interest at a floating rate of one-month Libor plus a spread of 3.67% on one swap and three-month Libor plus a spread of 3.54% on the second swap both through November 15, 2013. The counterparties are primarily the lenders in our credit facilities. The Swap Agreements are designated and each qualifies as a fair value hedging instrument. The swap to three-month Libor is deemed to be 100 percent effective resulting in no gain or loss recorded in the consolidated condensed statement of operations. The effectiveness of the swap to one-month Libor, which is highly effective, is calculated as of each period end and any ineffective portion is recognized in the consolidated condensed statement of operations. The fair value of the Swap Agreements was determined using a model with Level 2 inputs including quoted market prices for contracts with similar terms and maturity dates.

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

Fair Value of Derivative Instruments

The fair value of derivative instruments included in our consolidated condensed balance sheet was as follows as of March 31, 2010:


Derivative	Balance Sheet Location	Fair Value

Foreign Currency Forward Contracts	Other accrued liabilities	$ 1
Interest Rate Swaps	Other assets	$13

The effects of derivative instruments in our consolidated condensed statement of operations were as follows (amounts exclude any income tax effects):


		Amount of
		Gain/(Loss)
		Recognized in Income
		Three Months Ended
Derivative	Statement of Operations Location	March 31, 2010

Foreign Currency Forward Contracts	Marketing, general and administrative	$(5)
Interest Rate Swap	Interest Expense	$ 7

NOTE 10. INDEBTEDNESS

On March 19, 2010, we entered into a credit agreement (the “2010 Credit Agreement”). The 2010 Credit Agreement is a three-year committed $1.2 billion revolving credit facility that expires on March 19, 2013; $800 million of the revolving credit facility was available immediately and the remaining $400 million of such facility became available after consummation of the merger with BJ Services, which occurred on April 28, 2010. Also on March 19, 2010, we terminated our 364-day credit agreement in the amount of $500 million, dated as of March 30, 2009 and expiring March 29, 2010. At March 31, 2010, we had $1.3 billion of committed revolving credit facilities with commercial banks, consisting of the 2010 Credit Agreement ($800 million) and a $500 million facility expiring on July 7, 2012. Both facilities contain certain covenants which, among other things, require the maintenance of a funded indebtedness to total capitalization ratio (a defined formula per each agreement), restrict certain merger transactions or the sale of all or substantially all of our assets or a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the occurrence of certain events of default, our obligations under the facilities may be accelerated. Such events of default include payment defaults to lenders under the facilities, covenant defaults and other customary defaults.

At March 31, 2010, we were in compliance with all of the covenants of both committed credit facilities. There were no direct borrowings under the committed credit facilities during the quarter ended March 31, 2010. We also have a commercial paper program under which we may issue up to $1.0 billion in commercial paper with maturity of no more than 270 days. To the extent we have commercial paper outstanding, our ability to borrow under the facilities is reduced. At quarter end, we had $215 million of commercial paper outstanding.

NOTE 11. SEGMENT AND RELATED INFORMATION

We are a major supplier of wellbore-related products and technology services and systems and provide products and services for drilling, formation evaluation, completion and production, and reservoir technology and consulting to the worldwide oil and natural gas industry. In 2009, we reorganized the Company by geography and product lines; however, at this time we continue to review product line financial information as well as geographic information in deciding how to allocate resources and in assessing performance. Accordingly, we report results for our product lines under two segments: the Drilling and Evaluation segment and the Completion and Production segment. We have aggregated the product lines within each segment because they have similar economic characteristics and because the long-term financial performance of these product lines 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 Drilling and Evaluation segment consists of the following product lines: drilling fluids, drill bits, directional drilling, drilling evaluation services, wireline formation evaluation, wireline completion and production services and reservoir technology and consulting. The Drilling and Evaluation segment provides products and services used to drill and evaluate oil and natural gas wells as well as consulting services used in the analysis of oil and gas reservoirs.

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

•

The Completion and Production segment consists of the following product lines: wellbore construction and completion, specialty chemicals, artificial lift systems, permanent monitoring systems, chemical injection systems, integrated operations and project management. 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 before income taxes, interest expense, interest income, and certain gains and losses not allocated to the segments.

Summarized financial information is shown in the following table.


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

*Revenues*
Three months ended March 31, 2010	$	1,235	$	1,304	$	2,539	$	—		$	2,539
Three months ended March 31, 2009		1,304		1,364		2,668		—			2,668

*Segment profit (loss)*
Three months ended March 31, 2010	$	99	$	178	$	277	$	(83	)	$	194
Three months ended March 31, 2009		150		230		380		(96	)		284

*Total assets*
As of March 31, 2010	$	5,498	$	4,551	$	10,049	$	1,581		$	11,630
As of December 31, 2009		5,419		4,451		9,870		1,569			11,439

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


	Three Months Ended
	March 31,
	2010			2009

Corporate and other expenses	$	(49	)	$	(62	)
Acquisition-related costs		(10	)		—
Interest expense		(25	)		(35	)
Interest income		1			1

Total	$	(83	)	$	(96	)

NOTE 12. EMPLOYEE BENEFIT PLANS

We have both funded and unfunded noncontributory defined benefit pension plans (“Pension Benefits”) covering employees primarily in the U.S., the U.K., Germany and several countries in the Middle East region. We also provide certain postretirement health care 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 March 31:


													Other Postretirement
	U.S. Pension Benefits						Non-U.S. Pension Benefits						Benefits
	2010			2009			2010			2009			2010		2009

Service cost	$	8		$	7		$	1		$	1		$	2	$	2
Interest cost		6			5			5			4			3		3
Expected return on plan assets		(7	)		(6	)		(4	)		(4	)		—		—
Amortization of prior service cost		—			—			—			—			1		—
Amortization of net loss		3			3			1			—			—		—

Net periodic benefit cost	$	10		$	9		$	3		$	1		$	6	$	5

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

NOTE 13. COMMITMENTS AND CONTINGENCIES

Litigation

We are involved in litigation or proceedings that have arisen in our ordinary business activities as well as in relation to the merger with BJ Services. We insure against these risks to the extent deemed prudent by our management and to the extent insurance is available, but no assurance can be given that the nature and amount of that insurance will be sufficient to fully indemnify us against liabilities arising out of pending and future legal proceedings. Many of these insurance policies contain deductibles or self-insured retentions in amounts we deem prudent and for which we are responsible for payment. In determining the amount of self-insurance, it is our policy to self-insure those losses that are predictable, measurable and recurring in nature, such as claims for automobile liability, general liability and workers compensation. The accruals for losses are calculated by estimating losses for claims using historical claim data, specific loss development factors and other information as necessary.

BJ Services Merger Related Stockholder Lawsuits

Delaware Cases

On September 1, 2009, three purported stockholder class action lawsuits styled Laborers Local 235 Benefit Fund v. Stewart, et al., The Booth Family Trust v. Huff, et al., and Dugdale v. Huff, et al., were filed in the Court of Chancery of the State of Delaware (the “Delaware Chancery Court”) on behalf of the public stockholders of BJ Services, with respect to the Merger Agreement, dated as of August 30, 2009, among Baker Hughes, its wholly owned subsidiary, BSA Acquisition LLC (now named BJ Services Company LLC), a Delaware limited liability company (“Merger Sub”), and BJ Services, providing for BJ Services to merge with and into Merger Sub (the “Merger”), with Merger Sub continuing as the surviving entity after the Merger. Each action names BJ Services, the then members of the BJ Services Board of Directors (the “BJ Services Board”) and the Company as defendants (collectively the “Defendants”).

In these Delaware actions, and the follow-on actions discussed below, the plaintiffs allege, among other things, that the members of the BJ Services Board breached their fiduciary duties by failing to properly value BJ Services, failing to take steps to maximize the value of BJ Services to its public stockholders, and avoiding a competitive bidding process. The actions each allege that the Company aided and abetted the purported breaches by the BJ Services Board. The plaintiffs in each lawsuit seek, among other things, injunctive relief with respect to the Merger.

Six additional purported class action lawsuits were filed in the Delaware Chancery Court on behalf of the public stockholders of BJ Services against the Company, BJ Services and the BJ Services Board, including: Myers, v. BJ Services, et al., which was filed on September 4, 2009, Garden City Employees’ Retirement System v. BJ Services, et al., which was filed on September 8, 2009, Saratoga Advantage Trust-Energy & Basic Materials Portfolio v. Huff, et al., which was filed on September 8, 2009, Stationary Engineers Local 39 Pension Trust Fund v. Stewart, et al., which was filed on September 11, 2009, Jacobs v. Stewart, et al., which was filed on September 23, 2009, and Lyle v. BJ Services Company, et al., which was filed on October 1, 2009.

On September 25, 2009, the Delaware Chancery Court entered an order consolidating the lawsuits filed in the Delaware Chancery Court. On October 6, 2009, the Delaware Chancery Court entered an order implementing a bench ruling of October 5, 2009, resolving competing motions for appointment of lead counsel in the Delaware Chancery Court and designating the law firm of Faruqi & Faruqi, LLP of New York, New York as lead counsel and Rosenthal, Monhait & Goddess, P.A. of Wilmington, Delaware as liaison counsel. On October 14, 2009, the Delaware Chancery Court entered a supplemental consolidation order adding the October 1, 2009 Lyle complaint to the consolidated action.

On October 16, 2009, lead counsel for plaintiffs in the consolidated class action, In re: BJ Services Company Shareholders Litigation, C.A. No. 4851-VCN, served a Verified Consolidated Amended Class Action Complaint (the “Amended Complaint”) in the Delaware Court of Chancery. The Amended Complaint, among other things, added an officer of BJ Services (Jeffrey E. Smith, the then Executive Vice President-Finance and CFO of BJ Services) as a defendant, contained new factual allegations about the negotiations between BJ Services and the Company, and alleged the Form S-4 Registration Statement and preliminary joint proxy statement/prospectus, filed with the SEC on October 14, 2009, omitted and misrepresents material information.

Texas Cases

On September 4, 2009, a purported stockholder class action lawsuit styled Garden City Employees’ Retirement System v. BJ Services Company, et al., was filed in the 80th Judicial District Court of Harris County, Texas, on behalf of the public stockholders of

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

BJ Services with respect to the Merger Agreement naming BJ Services, the then members of the BJ Services Board, the Company and Merger Sub as defendants.

Three additional actions were filed against the Company, BJ Services and the BJ Services Board in District Courts in Harris County, Texas. They are: (1) Johnson v. Stewart, et al., filed on September 11, 2009, (2) Saratoga Advantage Trust — Energy & Basic Materials Portfolio v. Huff, et al., filed on September 11, 2009, and (3) Matt v. Huff, et al., filed on September 21, 2009. The lead plaintiff and plaintiff’s counsel in the Garden City and Saratoga Advantage Trust cases filed in Texas also filed the cases of the same name in Delaware that are listed above. The Texas actions make substantially the same allegations as were initially asserted in the Delaware actions, and seek the same relief.

On October 9, 2009, the Harris County Court consolidated the Texas actions and restyled the action as Garden City Employees’ Retirement System, et al. v. BJ services Company, et al., Cause No. 2009-57320, 80^th Judicial District of Harris County, Texas.

On October 20, 2009, the Court of Appeals for the First District of Texas at Houston granted the Defendants’ emergency motion to stay the Texas cases pending its decision on the Defendants’ mandamus petition seeking a stay of the Texas litigation pending adjudication of the first-filed cases in Delaware.

Proposed Settlement of Delaware and Texas Cases

The Company believes that the Delaware and Texas actions are without merit, and that it has valid defenses to all claims. Nevertheless, in an effort to minimize further cost, expense, burden and distraction of any litigation relating to such lawsuits, on February 9, 2010, the parties to the Delaware and Texas actions entered into a Memorandum of Understanding regarding the terms of settlement of such lawsuits. The Memorandum of Understanding resolves the allegations by the plaintiffs against the defendants in connection with the merger and provides a release and settlement by the purported class of the BJ Services stockholders of all claims against BJ Services, its directors and an officer and Baker Hughes, and their affiliates and agents, in connection with the merger. In exchange for such release and settlement, the parties agreed, after discussions on an arms’ length basis, that Baker Hughes and BJ Services provide additional supplemental disclosures in the joint proxy statement/prospectus included in a registration statement on Form S-4 filed by Baker Hughes on February 9, 2010 with the SEC. The proposed settlement includes an agreement that neither BJ Services nor Baker Hughes will oppose plaintiff’s counsel’s application for BJ Services to pay attorneys’ fees and costs in an amount to be determined by the court up to $700,000. In general, the terms of the Memorandum of Understanding will not become legally binding unless and until further definitive documentation is entered into and court approval is obtained. There can be no assurance as to when or whether any of the foregoing conditions will be satisfied. In the event that these conditions are not satisfied, the Company intends to continue to vigorously defend these actions.

OTHER

In the normal course of business with customers, vendors and others, we have entered into off-balance sheet arrangements, such as surety bonds for performance, letters of credit and other bank issued guarantees, which totaled approximately $686 million at March 31, 2010. None of the off-balance sheet arrangements either has, or is likely to have, a material effect on our consolidated condensed financial statements.

NOTE 14. COMPREHENSIVE INCOME (LOSS)

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


	Three Months Ended
	March 31,
	2010			2009

Net income	$	129		$	195
Other comprehensive income (loss):
Foreign currency translation adjustments during the period		(44	)		(16	)
Pension and other postretirement benefits		9			2

Total comprehensive income	$	94		$	181


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

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with our consolidated condensed financial statements and the related notes thereto, as well as our Annual Report on Form 10-K for the year ended December 31, 2009 (“2009 Annual Report”).

EXECUTIVE SUMMARY

Global operations are organized into a number of geomarket organizations, which report into nine region presidents, who in turn report into two hemisphere presidents. Separately, product-line marketing and technology organizations report to a president of products and technology. The presidents of the Eastern Hemisphere, Western Hemisphere, Products and Technology and the Vice President of Supply Chain report to our Chief Operating Officer. This organizational structure is intended to strengthen our client-focused operations by moving management into the countries where we conduct our business. The product-line organizations are responsible for product development and manufacturing, technology, marketing and delivery of solutions for our customers to advance their reservoir performance. The supply chain organization is responsible for development of cost-effective procurement and manufacturing of our products and services. As of March 31, 2010, we had approximately 34,800 employees, with approximately 60% of these employees working outside the United States.

The recovery of the global economy from the recession of 2008 and 2009 continued into the first quarter of 2010. Increasing economic activity and expectations for continued economic growth supported higher oil prices and increased oil-directed spending throughout the world. At current oil prices, many projects have attractive returns.

Natural gas-directed activity in North America continued to increase from the trough levels experienced in mid-2009. Although gas prices remained relatively low, many projects were economically attractive due to significantly lower drilling and completion costs as well as the ability of operators to hedge future production at attractive levels. The increase in gas-directed drilling in North America was almost exclusively dependent on drilling in the unconventional shale plays.

In the first quarter of 2010, the worldwide rig count continued to increase from year-end 2009 levels. International activity was supported by higher oil prices, driven by an improved worldwide economic outlook. The increase in North American rig count was led by natural gas drilling activity but also reflected an increase in the number of oil-directed rigs.

Prices for our products and services remain significantly below year ago pricing levels and price trends are mixed, improving for some products and in some geographies (such as North America) and deteriorating in others (primarily in the Eastern Hemisphere).

In the first quarter of 2010, we generated revenues of $2.54 billion, which is down $129 million or 5% compared to the first quarter of 2009 and compared to a 7% increase in the worldwide average rig count for the same time period. Our North American revenues for the first quarter of 2010 were $1.03 billion, a decrease of 5% compared to the first quarter of 2009 and compared to an 8% increase in the average rig counts for the U.S. and Canada. Revenues outside of North America were $1.51 billion, a decrease of 5% compared to the first quarter of 2009.

Net income for the first quarter of 2010 was $129 million compared to $195 million in the first quarter of 2009.

International activity is expected to continue to increase in 2010 supported by continued growth of the global economy — particularly in Asia and the Middle East and oil prices above $70 to $80/Bbl. In North America, oil-directed activity is expected to increase supported by high oil prices; however, lower natural gas prices are likely to result in less gas-directed activity in the balance of the year.

BJ SERVICES MERGER

On April 28, 2010 (the “Closing Date”), we completed a cash and stock merger with BJ Services whereby we acquired 100% of the outstanding common stock of BJ Services, a leading provider of pressure pumping and oilfield services. We believe that our services and the services of BJ Services are complimentary and that combining our services will strengthen our position in the oilfield services industry.

The merger consideration totaled $6.9 billion based on the closing price of our stock on April 28, 2010. Under the terms of the merger agreement, each share of BJ Services common stock was converted into 0.40035 shares of our common stock and $2.69 in cash. In total, we paid out $0.8 billion in cash, issued 118.0 million shares, valued at $6.1 billion based upon the closing price of our common stock on the Closing Date, and assumed outstanding stock options held by BJ Services employees and directors. We also guaranteed $500 million of long-term debt of BJ Services. The merger will be accounted for using the acquisition method of accounting. Under the acquisition method of accounting, we are required to allocate the purchase price to tangible and identifiable intangible assets acquired and liabilities assumed based on their fair values at the Closing Date. The excess of the purchase price over those fair values is recorded as goodwill. We are in the process of valuing the assets acquired and liabilities assumed. Assuming the merger with BJ Services occurred on January 1, 2010 and January 1, 2009, pro forma revenues of the Company for the three months ended March 31, 2010 and 2009 would have been approximately $3.6 billion and $3.7 billion, respectively. Other disclosures required by ASC 805, Business Combinations, will be provided once the initial accounting for the merger is complete.

Unless otherwise noted, all disclosure in Management’s Discussion and Analysis of Financial Condition and Results of Operations exclude any information related to and any potential impact that may result from the merger.

BUSINESS ENVIRONMENT

Our business environment and its corresponding operating results are affected significantly 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.

The global economic recovery and increasing oil and natural gas prices are all improving our business environment. The economic recovery is also positively impacting the incremental demand for hydrocarbon products around the world. Our customers typically fund their activity through a combination of borrowed funds and internally-generated cash flow.

Oil and Natural Gas Prices

Oil (West Texas Intermediate (WTI)/Cushing Crude Oil Spot Price) and natural gas (Henry Hub Natural Gas Spot Price) prices are summarized in the table below as averages of the daily closing prices during each of the periods indicated.


	Three Months Ended
	March 31,
	2010		2009

Oil prices ($/Bbl)	$	78.84	$	43.18
Natural gas prices ($/mmBtu)		5.09		4.55

Oil prices averaged $78.84/Bbl in the first quarter of 2010. Prices ranged from a low of $71.19/Bbl in mid-February to a quarter high of $83.76/Bbl in late March. Oil prices strengthened throughout the first quarter on expectations of worldwide economic recovery and energy demand growth, particularly in Asia and the Middle East. The International Energy Agency (“IEA”) estimated in its April 2010 Oil Market Report that worldwide demand would increase 2% to 86.6 million barrels per day in 2010, up from an estimated 84.9 million barrels per day in 2009.

Natural gas prices averaged $5.09/mmBtu in the first quarter of 2010. Natural gas prices decreased from a high of $7.51/mmBtu in early January to a low of $3.78/mmBtu in late March. Colder than normal weather in January and February and the increase in heating demand drove increases in natural gas prices. Increased gas production and declining demand due to warmer weather in March led to strong storage injections late in the quarter, resulting in downward pressure on natural gas prices. At quarter-end, working natural gas in storage was 160 Bcf above the five-year average and only 16 Bcf below the corresponding week in 2009.

Rig Counts

Baker Hughes has 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 and/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 is not readily available.

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 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, we compute a weekly or daily average of active rigs. In 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, and is not expected to be 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				%
	March 31,				Increase
	2010		2009		(Decrease)

U.S. — land and inland waters		1,300		1,287		1	%
U.S. — offshore		46		57		(19	)%
Canada		469		332		41	%

North America		1,815		1,676		8	%

Latin America		378		371		2	%
North Sea		43		50		(14	)%
Other Europe		45		39		15	%
Africa		80		59		36	%
Middle East		260		267		(3	)%
Asia Pacific		257		239		8	%

Outside North America		1,063		1,025		4	%

Worldwide		2,878		2,701		7	%

The rig count in North America increased 8% due to increases in natural gas and oil drilling activity. Outside North America, the rig count increased 4%. The rig count in Latin America increased due to higher activity in Brazil, Peru and Argentina. The North Sea rig count decreased due to lower activity in both the U.K and Norwegian sectors. The rig count in Africa increased primarily due to increased activity in Angola and Nigeria. The rig count decreased in the Middle East due to lower activity in Oman and Saudi Arabia, and the rig count in the Asia Pacific region increased due to principally higher activity in India, which more than offset decreased rig activity in Indonesia.

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, we have quantified the impact of such items. 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 ended March 31, 2010 and 2009, respectively.


	Three Months Ended March 31,
	2010				2009

Revenues	$	2,539	100	%	$	2,668	100	%
Cost of revenues		1,912	75	%		1,960	73	%
Research and engineering		94	4	%		109	4	%
Marketing, general and administrative		305	12	%		281	11	%

Revenues


	Three Months Ended
	March 31,				Increase
	2010		2009		(Decrease)			% Change

Geographic Revenues:
North America	$	1,030	$	1,083	$	(53	)		(5	)%
Latin America		279		288		(9	)		(3	)%
Europe, Africa, Russia, Caspian		762		776		(14	)		(2	)%
Middle East, Asia Pacific		468		521		(53	)		(10	)%

Total revenues	$	2,539	$	2,668	$	(129	)		(5	)%

Revenues for the three months ended March 31, 2010 were down 5% compared with the three months ended March 31, 2009, primarily due to lower pricing for our products and services. The worldwide rig count increased 7% for the three months ended March 31, 2010 compared with the three months ended March 31, 2009.

North America

Revenues in North America, which accounted for 41% of total revenues, decreased 5% for the three months ended March 31, 2010 compared to the three months ended March 31, 2009, due primarily to reduced pricing for our products and services and lower activity in the offshore market. U.S. revenues were down compared to a rig count that was essentially flat and Canada revenues increased as a result of increased activity as evidenced by a 41% increase in the rig count.

Outside North America

Revenue outside North America, which accounted for 59% of total revenues, decreased 5% for the three months ended March 31, 2010 compared with the three months ended March 31, 2009. Activity increased in most international markets, as evidenced by a 4% increase in the rig count outside of North America for the three months ended March 31, 2010, compared with the three months ended March 31, 2009. The revenue decrease reflects lower pricing for products and services across multiple regions which is due, in part, to renegotiation of customer contracts in the first half of 2009.

Latin America revenues decreased 3% for the three months ended March 31, 2010 compared to the same period a year ago and compared to a 2% increase in the rig count. Revenues increased in the Andean geomarket on higher artificial lift and drilling fluids sales, and in the Mexico/Central America geomarket due to increased directional drilling and wireline activity. Revenues declined across the balance of the region more than offset increases in the Andean and Mexico/Central America geomarkets. The largest revenue decline occurred in the Venezuelan geomarket, due to both lower activity and the devaluation of the Bolivar.

Europe, Africa, Russia, Caspian (“EARC”) revenues decreased 2% for the three months ended March 31, 2010 compared to the same period a year ago. Revenues increased in the Sub-Saharan Africa geomarket with strength across multiple product lines. Revenues also increased in the Norwegian geomarket, led by the directional drilling and fluids product lines, and in the Nigeria geomarket on strength in the completions and directional drilling product lines. Revenue increases in these geomarkets were offset by revenue declines in other geomarkets throughout the EARC region.

Revenues for Middle East, Asia Pacific (“MEAP”) were down 10% for the three months ending March 31, 2010, compared to the three months ended March 31, 2009, on a rig count that was up 2%. Revenues declined in all Middle East geomarkets compared to the first quarter of 2009. Within Asia Pacific, revenues increased in the Australasia and Southeast Asia geomarkets and declined in the North Asia, Indonesia and India and Southwest Asia geomarkets.

Cost of Revenues

Cost of revenues as a percentage of revenues increased to 75% for the three months ended March 31, 2010 compared to 73% for the three months ended March 31, 2009. The increase in cost of revenues as a percentage of revenues is primarily due to lower pricing for our products and services, partially offset by cost reductions in 2009 and a change in the mix of activity favoring horizontal wells in the unconventional oil and gas shales on land in the U.S. and Canada.

Research and Engineering

Research and engineering expenses decreased $15 million or 14% for the three months ended March 31, 2010 compared to the three months ended March 31, 2009. The decrease in research and engineering expenses is in line with the decrease in activity; however, we continue to be committed to developing and commercializing new technologies as well as investing in our core product offerings.

Marketing, General and Administrative

Marketing, general and administrative expenses increased $24 million or 9% for the three months ended March 31, 2010 compared to the three months ended March 31, 2009. The increase resulted primarily from costs associated with finance redesign efforts and software implementation activities and approximately $8 million of foreign exchange losses related to the devaluation of the Venezuelan Bolivar.

Interest Expense

Interest expense decreased $10 million for the three months ended March 31, 2010 compared with the three months ended March 31, 2009 due primarily to gains of approximately $7 million related to our interest rate swaps and approximately $2 million due to debt that matured during the three months ended March 31, 2009.

Income Taxes

Our effective tax rate in the first quarter of 2010 was 33.5%, which 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 Accounting Standards Codification (“ASC”) 740, Income Taxes.

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; exploration and development spending and drilling activity; and production spending.

Our industry is cyclical, and past cycles have been driven primarily by alternating periods of ample supply or shortage of oil and natural gas relative to demand. As an oilfield services company, our revenue is dependent on spending by our customers for oil and natural gas exploration, field development and production. This spending is dependent on a number of factors, including our customers’ forecasts of future energy demand, their expectations for future energy prices, their access to resources to develop and produce oil and gas and their ability to fund their capital programs.

The recovery from the global economic recession is expected to be the primary driver impacting the 2010 business environment. As the worldwide economy recovers, demand for hydrocarbons will increase. The largest incremental demands for oil are expected to be generated by China, India and the Middle East. Increasing oil demand is expected to support oil prices between $60/Bbl and $85/Bbl. In North America, the near-month futures prices for natural gas, as quoted in early April 2010 were just above $4/mmBtu, and the 12-month futures price was trading slightly above $5/mmBtu. Higher natural gas futures prices in 2008 and early 2009

provided an opportunity for many of our customers to hedge natural gas production. Cash flow of these customers benefited from the attractive prices received on hedged production allowing them to maintain exploration and development activity. However, the decline in natural gas prices in 2010, and the roll-off of attractive hedge positions is placing increased emphasis on well economics, cash flow and capital budgets for our customers. Capital discipline on the part of our competitors, attrition of existing rental fleets and rising demand are expected to result in an environment that we believe will support increasing prices for our products and services in some markets by the second half of 2010.

Our outlook for exploration and development spending is based upon our expectations for customer spending in the markets in which we operate, and is driven primarily by our perception of industry expectations for oil and natural gas prices and their likely impact on customer capital and operating budgets as well as other factors that could impact the economic return oil and gas companies expect for developing oil and gas reserves. Our forecasts are based on our analysis of information provided by our customers as well as market research and analyst reports including the Short Term Energy Outlook (“STEO”) published by the Energy Information Administration of the U.S. Department of Energy (“DOE”), the Oil Market Report published by the IEA and the Monthly Oil Market Report published by OPEC. Our outlook for economic growth is based on our analysis of information published by a number of sources including the International Monetary Fund (“IMF”), the Organization for Economic Cooperation and Development (“OECD”) and the World Bank.

In North America, the outlook for spending in 2010 will be significantly influenced by the outlook for the natural gas industry. However, oil-directed rig activity has increased to levels not seen since early 1991, and is expected to continue to increase with oil prices greater than $70/Bbl, as many operators seek to diversify activity away from natural gas. The increase in gas-directed rig count from mid-2009 lows and continued advances in horizontal drilling and advanced fracturing and completion technologies has led to increasing rates of initial production in the unconventional gas fields, resulting in high levels of gas production relative to demand. In January and February of 2010 natural gas prices increased in response to colder weather throughout much of the U.S. As heating demand has declined with warmer weather, natural gas prices have declined to a level below the $5.09/mmBtu average for the first quarter of 2010.

Expectations for Oil Prices - Due to improved expectations for the global economy, the Energy Information Administration (“EIA”) expects global demand for oil to increase 1.5 million barrels per day in 2010 relative to 2009. Non-OPEC supply growth is expected to increase by 600 thousand barrels per day in 2010. In its March 17, 2010 meeting in Vienna, OPEC left its production policy unchanged. The EIA projects that OPEC production will increase by 300 thousand barrels per day in 2010. OPEC spare productive capacity is expected to increase slightly through 2011. In its April 2010 STEO report, the DOE forecasted oil prices (West Texas Intermediate) to average slightly less than $81/Bbl for 2010, and $85/Bbl by the fourth quarter of 2011.

Expectations for North America Natural Gas Prices — Increasing production and the decline in heating demand are placing downward pressure on natural gas prices. Prices for natural gas have declined to a level which is resulting in coal to gas switching in the power generation sector. In its April 2010 STEO report, the DOE forecasted that U.S. natural gas prices would average $4.44/mmBTU in 2010. The DOE forecasts gas prices to increase to an average of $5.33/mmBTU in 2011.

Our capital expenditures are expected to be approximately $1.2 billion to $1.3 billion for 2010, including approximately $350 million to $400 million that we expect to spend on infrastructure, primarily outside North America, but excluding the BJ Services merger and any other acquisitions. A significant portion of our planned capital expenditures can be adjusted to reflect changes in our expectations for future customer spending. We expect to manage our capital expenditures to match market demand.

Compliance

In connection with our previously reported settlements with the DOJ and SEC, we retained an independent monitor (the “Monitor”) to assess and make recommendations about our compliance policies and procedures. In response to the Monitor’s initial recommendations, we have continued our reduction of the use of commercial sales representatives (“CSRs”) and processing agents, including the reduction of customs agents. We have also continued to enhance our channels of communication regarding agents while streamlining our compliance due diligence process for agents, including more clearly delineating the responsibilities of participants in the compliance due diligence process. We have adopted a risk-based compliance due diligence procedure for professional agents, enhancing our process for classifying distributors and creating a formal policy to guide business personnel in determining when subcontractors should be subjected to compliance due diligence. We have also instituted a program to ensure that each of our internal sponsors regularly reviews their CSRs, including a review with senior management.

In addition, we have reviewed and expanded the use of our centralized finance organization, including further implementation of our enterprise-wide accounting system and company-wide policies regarding expense reporting, petty cash, the approval of invoice payments and general ledger account coding. We also have consolidated our divisional audit functions and redeployed some of these

resources for corporate audits. Further, we have restructured our corporate audit function, and are incorporating additional anti-corruption procedures into some of our audits, which are applied on a country-wide basis. We are also continuing to refine and enhance our procedures for Foreign Corrupt Practices Act (“FCPA”) compliance reviews, risk assessments, and legal audit procedures.

Further, we continue to work to ensure that we have adequate legal compliance coverage around the world, including the coordination of compliance advice and training across the product lines in each of our regions. We have also worked to create simplified summaries, flow charts, and FAQs (Frequently Asked Questions) to accompany each of our compliance-related policies, and we are supplementing our existing policies. At the same time, we are taking steps to achieve further centralization of our customs and logistics function including the development of uniform and simplified customs policies and procedures. We are also developing uniform procedures for the verification and documentation of services provided by customs agents and a training program in which customs and logistics personnel receive specialized training focused specifically on risks associated with the customs process. We are also adopting a written plan for reviewing and reducing the number of our customs agents and freight forwarders.

We are continuing to centralize our human resources function, including creating consistent standards for pre-hire screening of employees, the screening of existing employees prior to promoting them to positions where they may be exposed to corruption-related risks, and creating a uniform policy for on-boarding training. We are implementing a training program that identifies employees for compliance training and sets appropriate training schedules based on job function and risk profile in addition to employment grade. Further, the contents of our training programs are being tailored to address the different risks posed by different categories of employees. We are supplementing our FCPA electronic training module while taking steps to ensure that training is available in the principal local languages of our employees and that local anti-corruption laws are discussed as part of our compliance training. We have also worked to ensure that our helpline is easily accessible to employees in their own language as well as taken actions to counter any cultural norms that might discourage employees from using the helpline. We continue to provide a regular and consistent message from senior management that compliance with the FCPA is obligatory, and emphasize that compliance is a positive factor in the continued success of our business.

The Monitor is required to perform two follow up reviews and to “certify whether the anti-bribery compliance program of Baker Hughes, including its policies and procedures, is appropriately designed and implemented to ensure compliance with the FCPA, U.S. commercial bribery laws and foreign bribery laws.” On April 8, 2009, the Monitor issued his report for the first of such follow up reviews, and the Monitor issued his certification that our compliance program is appropriately designed and implemented to ensure such compliance.

For a further description of our compliance programs see, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Compliance” and Note 15 “Commitment and Contingencies” in the Notes to Consolidated Financial Statements in our 2009 Annual Report.

LIQUIDITY AND CAPITAL RESOURCES

Our objective in financing our business is to maintain adequate financial resources and access to sufficient liquidity. At March 31, 2010, we had cash and cash equivalents of $1.61 billion and $1.08 billion available for borrowing under committed revolving credit facilities with commercial banks. We have a shelf registration statement on file with the SEC, which positions us to raise additional funds in the capital market as deemed appropriate.

Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of our company. During the three months ended March 31, 2010, we used cash to pay for a variety of activities including working capital needs, dividends, and capital expenditures.

Cash Flows

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


	2010			2009

Operating activities	$	5		$	34
Investing activities		(145	)		(234	)
Financing activities		174			(567	)

Statements of cash flows for our 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 provided $5 million in the three months ended March 31, 2010 compared with $34 million in the three months ended March 31, 2009. This decrease in cash flows of $29 million results primarily from a decrease in net income.

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

	•		An increase in accounts receivable in the first quarter of 2010 used $154 million in cash compared with providing $229 million in cash in the first quarter of 2009. The change in accounts receivable was primarily due to the decrease in activity offset by an increase in the quarterly days sales outstanding of approximately one day reflecting a slowdown in customer payments.

	•		Inventory used $47 million in cash in the first quarter of 2010 compared with using $96 million in cash in the first quarter of 2009.

	•		Accrued employee compensation and other accrued liabilities used $22 million in cash in the first quarter of 2010 compared with using $171 million in cash in the first quarter of 2009. The decrease in cash used was primarily due to a decrease in the annual payment of employee bonuses and other benefits in the first quarter of 2010 compared with the first quarter of 2009.

	•		Income taxes payable used $53 million in cash in the first quarter of 2010 compared to using $161 million in cash in the first quarter of 2009. The decrease in cash used was primarily due to federal income tax payments of $155 million for two quarterly installment payments in the first quarter of 2009. The U.S. Internal Revenue Service allowed companies impacted by Hurricane Ike to defer the third and fourth quarter installment payments for 2008 until January 2009.

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 $190 million and $281 million for the three months ended March 31, 2010 and 2009, respectively. While the majority of these expenditures were for rental tools, including wireline tools, and machinery and equipment, we have also increased our spending on new facilities, expansions of existing facilities and other infrastructure projects.

Proceeds from the disposal of assets were $45 million and $47 million for the three months ended March 31, 2010 and 2009, respectively. These disposals relate to rental tools that were lost-in-hole, as well as machinery, rental tools and equipment no longer used in operations that were sold throughout the period.

Financing Activities

We had net borrowings of commercial paper and other short-term debt of $218 million and $4 million in the three months ended March 31, 2010 and 2009, respectively. Total debt outstanding at March 31, 2010 was $2.02 billion, an increase of $220 million compared with December 31, 2009. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was 0.22 at March 31, 2010 and 0.20 at December 31, 2009.

We received proceeds of $2 million from the issuance of common stock from the exercise of stock options in the three months ended March 31, 2010. No such proceeds were received during the three months ended March 31, 2009.

Our Board of Directors has authorized a plan to repurchase our common stock from time to time. In the three months ended March 31, 2010 and 2009, we did not repurchase any shares of our common stock. At March 31, 2010, we had authorization remaining to repurchase approximately $1.2 billion of our common stock.

We paid dividends of $47 million and $46 million in the three months ended March 31, 2010 and 2009, respectively.

Available Credit Facilities

On March 19, 2010, we entered into a credit agreement (the “2010 Credit Agreement”). The 2010 Credit Agreement is a three-year committed $1.2 billion revolving credit facility that expires on March 19, 2013; $800 million of the revolving credit facility was available immediately and the remaining $400 million of such facility became available after consummation of the merger with BJ Services, which occurred on April 28, 2010. Also on March 19, 2010, we terminated our 364-day credit agreement in the amount of $500 million, dated as of March 30, 2009 and expiring March 29, 2010. At March 31, 2010, we had $1.3 billion of committed revolving credit facilities with commercial banks, consisting of the 2010 Credit Agreement ($800 million) and a $500 million facility expiring on July 7, 2012. Both facilities contain certain covenants which, among other things, require the maintenance of a funded indebtedness to total capitalization ratio (a defined formula per the facility), restrict certain merger transactions or the sale of all or substantially all of our assets or a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the occurrence of certain events of default, our obligations under the facilities may be accelerated. Such events of default include payment defaults to lenders under the facilities, covenant defaults and other customary defaults.

At March 31, 2010, we were in compliance with all of the facility covenants of both committed credit facilities. There were no direct borrowings under the committed credit facilities during the quarter ended March 31, 2010. We also have a commercial paper program under which we may issue up to $1.0 billion in commercial paper with maturity of no more than 270 days. To the extent we have commercial paper outstanding, our ability to borrow under the facilities is reduced. At quarter end, we had $215 million of commercial paper outstanding.

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. There are no ratings triggers that would accelerate the maturity of any borrowings under the committed credit facilities. However, a downgrade in our credit ratings could increase the cost of borrowings under the facilities 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 facilities.

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 2010, we believe cash on hand and operating cash flows will provide us with sufficient capital resources and liquidity to manage our working capital needs, meet contractual obligations, fund capital expenditures, and support the development of our short-term and long-term operating strategies. We may issue commercial paper or other short-term debt to fund cash needs in the U.S. in excess of the cash generated in the U.S. The expectations described below exclude any amounts related to the merger with BJ Services that occurred subsequent to the quarter.

In 2010, we expect capital expenditures to be between $1.2 billion to $1.3 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. A significant portion of our capital expenditures can be adjusted based on future activity of our customers. We expect to manage our capital expenditures to match market demand.

In 2010, we also expect to make interest payments of between $125 million and $130 million based on our current expectations of debt levels during 2010. We anticipate making income tax payments of between $475 million and $525 million in 2010.

As of March 31, 2010, we have authorization remaining to repurchase approximately $1.2 billion in common stock. We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. We anticipate paying dividends of between $180 million and $190 million in 2010; however, the Board of Directors can change the dividend policy at anytime.

We expect to contribute between $20 million and $25 million to our U.S. pension plans and between $15 million and $20 million to the non-U.S. pension plans. We also expect to make benefit payments related to postretirement welfare plans of between $18 million and $20 million, and we estimate we will contribute between $142 million and $154 million to our defined contribution plans.

Cash Requirements for Merger with BJ Services

On April 28, 2010, we completed the merger with BJ Services. In order to fund the cash portion of the merger consideration of approximately $800 million, we used approximately $480 million of cash on hand and approximately $320 million from the issuance of commercial paper. In addition, we intend to use such internal cash resources and available financing to pay for the estimated direct merger transaction costs and professional services as well as pre-existing change of control contractual payments to certain BJ Services employees that are estimated to be approximately $240 million to be paid out throughout 2010 as contractually required.

NEW ACCOUNTING STANDARDS

In January 2010, the FASB issued an update to ASC 820, Fair Value Measurements and Disclosures - Improving Disclosures about Fair Value Measurements. This update provides a greater level of enhanced information and disclosures about valuation techniques and inputs to fair value measurements. The new disclosures are effective for interim and annual reporting periods beginning after December 15, 2009. We adopted the new disclosure requirements in the first quarter of 2010 as reflected in Note 8. Fair Value of Certain Financial Assets and Liabilities. Disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years.

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,” “probable,” “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 and business plans; the business plans of our customers; oil and natural gas market conditions; costs and availability of resources; economic, legal and regulatory conditions and other 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. The following additional factors, among others, with respect to the merger with BJ Services, could cause actual results to differ from those set forth in the forward-looking statements: the risk that the cost savings and any other synergies from the transaction may not be realized or take longer to realize than expected; disruption from the transaction making it more difficult to maintain relationships with customers, employees or suppliers; the ability to successfully integrate the businesses; unexpected costs or unexpected liabilities that may arise from the transaction; the inability to retain key personnel; continuation or deterioration of current market conditions; the outcome of any pending litigation; future regulatory or legislative actions that could adversely affect the companies; and the business plans of the customers of the respective parties. 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 our 2009 Annual Report, this filing and those set forth from time to time in our filings with the SEC. These documents are available through our web site or through the SEC’s Electronic Data Gathering and Analysis Retrieval System (“EDGAR”) at http://www.sec.gov.


ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We conduct operations around the world in a number of different currencies. The majority of our significant foreign subsidiaries have designated the local currency as their functional currency. As such, future earnings are subject to change due to changes in foreign currency exchange rates when transactions are denominated in currencies other than our functional currencies. To minimize

the need for foreign currency forward contracts to hedge this exposure, our objective is to manage foreign currency exposure by maintaining a minimal consolidated net asset or net liability position in a currency other than the functional currency.

Foreign Currency Forward Contracts

At March 31, 2010, we had outstanding foreign currency forward contracts with notional amounts aggregating $175 million to hedge exposure to currency fluctuations in various foreign currencies. These contracts are designated and qualify as fair value hedging instruments. The fair value of these contracts outstanding at March 31, 2010, was approximately $1 million which was included in other accrued liabilities in the consolidated condensed balance sheet. The fair value was determined using a model including quoted market prices for contracts with similar terms and maturity dates.

The effect of foreign currency forward contracts on the consolidated condensed statement of operations for the three months ended March 31, 2010 was $5 million of foreign exchange losses, which are included in marketing, general and administrative expenses. These losses offset designated foreign exchange gains resulting from the underlying exposures of the hedged items.

Interest Rate Swaps

In June 2009, we entered into two interest rate swap agreements (the “Swap Agreements”) for a notional amount of $250 million each in order to hedge changes in the fair market value of our $500 million 6.5% senior notes maturing on November 15, 2013. Under the Swap Agreements we receive interest at a fixed rate of 6.5% and pay interest at a floating rate of one-month Libor plus a spread of 3.67% on one swap and three-month Libor plus a spread of 3.54% on the second swap through November 15, 2013. The Swap Agreements are designated and each qualifies as a fair value hedging instrument. The fair value of the Swap Agreements at March 31, 2010, was $13 million and was based on quoted market prices for contracts with similar terms and maturity dates.

The financial institutions that are counterparties to the Swap Agreements are primarily the lenders in our credit facilities. Under the terms of the credit support documents governing the Swap Agreements, the relevant party will have to post collateral in the event such party’s long-term debt rating falls below investment grade or is no longer rated.


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 Exchange Act of 1934, as amended (the “Exchange Act”). This evaluation was carried out under the supervision and with the participation of our management, including our principal executive officer and principal financial officer. Based on this evaluation, these officers have concluded that, as of March 31, 2010, our disclosure controls and procedures, as defined by Rule 13a-15(e) of the Exchange Act, are effective at a reasonable assurance level. There has been no change in our internal controls over financial reporting during the quarter ended March 31, 2010 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

We are subject to a number of lawsuits, investigations and claims (some of which involve substantial amounts) arising out of the conduct of our business. See a further discussion of litigation matters in Note 13 of Notes to Unaudited Consolidated Condensed Financial Statements.

For additional information see also, “Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Outlook” of this Form 10-Q and Item 3 of Part I of our 2009 Annual Report for additional discussion of legal proceedings.


ITEM 1A.		RISK FACTORS

As of the date of this filing, the Company and its operations continue to be subject to the risk factors previously disclosed in our “Risk Factors” in the 2009 Annual Report as well as the following risk factors:

Many of our customers’ activity levels and spending for our products and services and ability to pay amounts owed us may be impacted by deterioration in the credit markets.

Access to capital is dependent on our customers’ ability to access the funds necessary to develop economically attractive projects based upon their expectations of future energy prices, required investments and resulting returns. Limited access to external sources of funding has caused many customers to reduce their capital spending plans to levels supported by internally-generated cash flow. In addition, the combination of a reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may impact the ability of our customers to pay amounts owed to us. Starting in late 2008 and continuing through the first quarter of 2010, we are experiencing a delay in receiving payments from our customers in Venezuela. As of March 31, 2010, our accounts receivable in Venezuela totaled approximately 3% of our total accounts receivable. For the three months ended March 31, 2010, Venezuela revenues were approximately 1% of our total consolidated revenues.

In connection with the approval by the United States Department of Justice of the closing of the merger with BJ Services, we are required to maintain the operations of BJ Services in the United States separate from our operations until certain assets are divested.

Pursuant to a final agreement with the Antitrust Division of the DOJ in connection with the governmental approval of the merger between us and BJ Services, we are required to divest two chartered stimulation vessels (the HR Hughes and Blue Ray) and certain other assets used to perform sand control services in the U.S. Gulf of Mexico. We expect to divest these assets in the next several months but cannot provide any assurance on the amount of proceeds that we will receive in the sale. Pursuant to a Hold Separate Stipulation and Order, the operation of our U.S. business and the U.S. business of BJ Services will be required to be operated separately until these assets are divested. This will likely delay certain synergies and savings expected from the merger with BJ Services. If the divestiture of the assets is delayed and the operations must be maintained separate for an extended period, significant value expected from the merger could be lost. In addition, the operation of the businesses separately could result in a loss of combined market share and an inability to retain employees. In addition, the final agreement is subject to a 60-day public comment period, after which time the court may approve the final agreement as written, or it may modify it. We can provide no assurance that the final agreement will be approved by the court in the form that we had agreed to it with the Antitrust Division of the DOJ.

Changes in and compliance with environmental and safety regulations may adversely affect our business and operating results.

The continuing oil leak in the Gulf of Mexico could result in increased regulation of the drilling industry as a whole resulting in higher operating costs, which could, in turn, adversely affect our operating results. In addition, increased regulation could result in restrictions on new or ongoing offshore drilling programs or otherwise delay drilling activity in the Gulf of Mexico and hurt demand for our services.


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 March 31, 2010.

Issuer Purchases of Equity Securities


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

January 1-31, 2010		170,869	$	45.92		—	$	—		170,869	$	—
February 1-28, 2010		444		47.13		—		—		444		—
March 1-31, 2010		4,296		46.61		—		—		4,296		—

Total		175,609	$	45.94		—	$	—		175,609	$	1,197,127,803


⁽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⁾		There were no share repurchases as part of a repurchase program during the three months ended March 31, 2010.

⁽³⁾		Our Board of Directors has authorized a plan to repurchase our common stock from time to time. During the first quarter of 2010, we did not repurchase shares of our common stock. We had authorization remaining to repurchase approximately $1.2 billion of our common stock.


ITEM 3.		DEFAULTS UPON SENIOR SECURITIES

None.


ITEM 4.		[REMOVED AND RESERVED]


ITEM 5.		OTHER INFORMATION

In our earnings release dated May 4, 2010 and included with our Current Report on Form 8-K filed on May 4, 2010 (the “Earnings Release”), we reported an amount for capital expenditures during the quarter ended March 31, 2010 of approximately $246 million. In preparing the complete set of financial statements for the quarter ended March 31, 2010, we confirmed the actual amount for capital expenditures during the quarter was approximately $190 million or approximately $56 million less than the amount reported in the Earnings Release.


ITEM 6.		EXHIBITS

Each exhibit identified below is filed as a part of this report. Exhibits designated with an “*” are filed as an exhibit to this Quarterly Report on Form 10-Q. Exhibits designated with a “+” are identified as management contracts or compensatory plans or arrangements. Exhibits previously filed as indicated below are incorporated by reference.


3.1*		Certificate of Amendment dated April 22, 2010 and the Restated Certificate of Incorporation.

3.2		Restated Bylaws of Baker Hughes Incorporated effective as of April 28, 2010 (filed as Exhibit 3.2 to Current Report on Baker Hughes Incorporated Form 8-K filed April 29, 2010).

4.1		Indenture, dated June 8, 2006, between BJ Services Company, as issuer, and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to Current Report on BJ Services Company Form 8-K filed on June 12, 2006).

4.2		First Supplemental Indenture, dated June 8, 2006, between BJ Services Company, as issuer, and Wells Fargo Bank, N.A., as trustee, with respect to the 5.75% Senior Notes due 2011 (incorporated by reference to Exhibit 4.2 to Current Report on BJ Services Company Form 8-K filed on June 12, 2006).


4.3		Third Supplemental Indenture, dated May 19, 2008, between BJ Services Company, as issuer, and Wells Fargo Bank, N.A., as trustee, with respect to the 6% Senior Notes due 2018 (incorporated by reference to Exhibit 4.2 to Current Report on BJ Services Company Form 8-K filed on May 23, 2008).

4.4		Fourth Supplemental Indenture, dated April 28, 2010, between BJ Services Company, as issuer, BSA Acquisition LLC, Baker Hughes Incorporated and Wells Fargo Bank, N.A., as trustee, with respect to the 5.75% Senior Notes due 2011 and the 6% Senior Notes due 2018 (incorporated by reference to Exhibit 4.4 to Current Report on Baker Hughes Incorporated Form 8-K filed on April 29, 2010).

4.5+		Form of Incentive Stock Option Assumption Agreement for BJ Services incentive plans (incorporated by reference to Exhibit 4.5 to Current Report on Baker Hughes Incorporated Form 8-K filed on April 29, 2010).

4.6+		Form of Nonqualified Stock Option Assumption Agreement for BJ Services incentive plans (incorporated by reference to Exhibit 4.6 to Current Report on Baker Hughes Incorporated Form 8-K filed on April 29, 2010).

10.1+		Amendment to Baker Hughes Incorporated Executive Severance Plan dated April 22, 2010 (filed as Exhibit 10.1 to Current Report on Baker Hughes Incorporated Form 8-K filed on April 23, 2010).

10.2+		Amendment to Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan dated March 31, 2010 (filed as Annex G to the Registration Statement No. 333-162463 on Form S-4 filed on February 9, 2010).

10.3		Amendment to Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan dated March 31, 2010 (filed as Annex H to the Registration Statement No. 333-162463 on Form S-4 filed on February 9, 2010).

10.4		Credit Agreement dated as of March 19, 2010, among Baker Hughes Incorporated, JP Morgan Chase Bank, N.A., as Administrative Agent and twenty-one lenders for $1.2 billion, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report on Baker Hughes Incorporated Form 8-K filed on March 22, 2010).

10.5		BJ Services Company 1995 Incentive Plan (filed as Exhibit 4.5 to BJ Services Company’s Registration Statement on Form S-8 (Reg. No. 33-58637) and incorporated herein by reference).

10.6		Amendments effective January 25, 1996, and December 12, 1996, to BJ Services Company 1995 Incentive Plan (filed as Exhibit 10.9 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 1996 (file no. 1-10570), and incorporated herein by reference).

10.7		Amendment effective July 22, 1999 to BJ Services Company 1995 Incentive Plan (filed as Exhibit 10.25 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 1999 (file no. 1-10570), and incorporated herein by reference).

10.8		Amendment effective January 27, 2000 to BJ Services Company 1995 Incentive Plan (filed as Appendix B to BJ Services Company’s Proxy Statement dated December 20, 1999 (file no. 1-10570) and incorporated herein by reference).

10.9		Amendment effective May 10, 2001 to BJ Services Company 1995 Incentive Plan (filed as Appendix B to BJ Services Company’s Proxy Statement dated April 10, 2001 and (file no. 1-10570) incorporated herein by reference).

10.10		Eighth Amendment effective October 15, 2001 to BJ Services Company 1995 Incentive Plan (filed as Exhibit 10.12 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 2001 (file no. 1-10570) and incorporated herein by reference).

10.11		Tenth Amendment effective December 5, 2008 to BJ Services Company 1995 Incentive Plan (filed as Exhibit 10.1 to BJ Services Company’s Quarterly Report on Form 10-Q for the quarterly period ended December 31, 2008 (file no. 1-10570) and incorporated herein by reference).

10.12		BJ Services Company 1997 Incentive Plan (filed as Appendix B to BJ Services Company’s Proxy Statement dated December 22, 1997 (file no. 1-10570) and incorporated herein by reference).


10.13		Amendment effective July 22, 1999 to BJ Services Company 1997 Incentive Plan (filed as Exhibit 10.26 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 1999 (file no. 1-10570) and incorporated herein by reference).

10.14		Amendment effective January 27, 2000 to BJ Services Company 1997 Incentive Plan (filed as Appendix C to BJ Services Company’s Proxy Statement dated December 20, 1999 (file no. 1-10570) and incorporated herein by reference).

10.15		Amendment effective May 10, 2001 to BJ Services Company 1997 Incentive Plan (filed as Appendix C to BJ Services Company’s Proxy Statement dated April 10, 2001 (file no. 1-10570) and incorporated herein by reference).

10.16		Fifth Amendment effective October 15, 2001 to BJ Services Company 1997 Incentive Plan (filed as Exhibit 10.17 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 2001 (file no. 1-10570) and incorporated herein by reference).

10.17		Eighth Amendment effective November 15, 2006 to BJ Services Company 1997 Incentive Plan (filed as Exhibit 10.3 to BJ Services Company’s Current Report on Form 8-K filed on December 13, 2006 and incorporated herein by reference).

10.18		Ninth Amendment effective October 13, 2008 to BJ Services Company 1997 Incentive Plan (filed as Exhibit 10.16 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 2008 (file no. 1-10570) and incorporated herein by reference).

10.19		Tenth Amendment effective December 5, 2008 to BJ Services Company 1997 Incentive Plan (filed as Exhibit 10.2 to BJ Services Company’s Quarterly Report for the quarterly period ended December 31, 2008 (file no. 1-10570) and incorporated herein by reference).

10.20+		BJ Services Company 2000 Incentive Plan (filed as Appendix B to BJ Services Company’s Proxy Statement dated December 20, 2000 (file no. 1-10570) and incorporated herein by reference).

10.21+		First Amendment effective March 22, 2001 to BJ Services Company 2000 Incentive Plan (filed as Exhibit 10.2 to BJ Services Company’s Registration Statement on Form S-8 (Reg. No. 333-73348) and incorporated herein by reference).

10.22+		Second Amendment effective May 10, 2001 to BJ Services Company 2000 Incentive Plan (filed as Appendix D to BJ Services Company’s Proxy Statement dated April 10, 2001 (file no. 1-10570) and incorporated herein by reference).

10.23+		Third Amendment effective October 15, 2001 to BJ Services Company 2000 Incentive Plan (filed as Exhibit 10.24 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 2001 (file no. 1-10570) and incorporated herein by reference).

10.24+		Fifth Amendment effective November 15, 2006 to BJ Services Company 2000 Incentive Plan (filed as Exhibit 10.4 to BJ Services Company’s Current Report on Form 8-K filed on December 13, 2006 (file no. 1-10570) and incorporated herein by reference).

10.25+		Sixth Amendment effective October 13, 2008 to BJ Services Company 2000 Incentive Plan (filed as Exhibit 10.22 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 2008 (file no. 1-10570) and incorporated herein by reference).

10.26+		Seventh Amendment effective December 5, 2008 to BJ Services Company 2000 Incentive Plan (filed as Exhibit 10.3 to BJ Services Company’s Quarterly Report for the quarterly period ended December 31, 2008 (file no. 1-10570) and incorporated herein by reference).

10.27+		Amended and Restated BJ Services Company 2003 Incentive Plan (filed as Appendix A to BJ Services Company’s Proxy Statement dated December 15, 2008 (file no. 1-10570) and incorporated herein by reference).


10.28+		First Amendment to the Amended and Restated BJ Services Company 2003 Incentive Plan (filed as Exhibit 10.1 to BJ Services Company’s Quarterly Report for the quarterly period ended March 31, 2008 (file no. 1-10570) and incorporated herein by reference).

10.29+		Amended and Restated BJ Services Company Directors’ Benefit Plan, effective January 1, 2008 (filed as Exhibit 10.31 to BJ Services Company’s Annual Report on Form 10-K for the year ended September 30, 2008 (file no. 1-10570) and incorporated herein by reference).

31.1*		Certification of Chad C. Deaton, Chief Executive Officer, dated May 7, 2010, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.

31.2*		Certification of Peter A. Ragauss, Chief Financial Officer, dated May 7, 2010, 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 May 7, 2010, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.

**101.INS		XBRL Instance Document

**101.SCH		XBRL Schema Document

**101.CAL		XBRL Calculation Linkbase Document

**101.LAB		XBRL Label Linkbase Document

**101.PRE		XBRL Presentation Linkbase Document


**	Furnished with this Form 10-Q, not filed.


	Page No.
PART I — FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

Consolidated Condensed Statements of Operations (Unaudited) — Three months ended March 31, 2010 and 2009		2

Consolidated Condensed Balance Sheets (Unaudited) — March 31, 2010 and December 31, 2009		3

Consolidated Condensed Statements of Cash Flows (Unaudited) — Three months ended March 31, 2010 and 2009		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		24

Item 4. Controls and Procedures		25

PART II — OTHER INFORMATION

Item 1. Legal Proceedings		26

Item 1A. Risk Factors		26

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		27

Item 3. Defaults Upon Senior Securities		27

Item 4. [Removed and Reserved]		27

Item 5. Other Information		27

Item 6. Exhibits		27

Signatures		31
EX-3.1
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT


		BAKER HUGHES INCORPORATED (Registrant)

Date: May 7, 2010		By: /s/ PETER A. RAGAUSS Peter A. Ragauss
		Senior Vice President and Chief Financial Officer

Date: May 7, 2010		By: /s/ ALAN J. KEIFER Alan J. Keifer
		Vice President and Controller

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