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, 2009


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

Commission File Number 1-9397

Baker Hughes Incorporated

(Exact name of registrant as specified in its charter)


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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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). Yes o No o

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 filer þ

Accelerated filer o

Non-accelerated filer o
(Do not check if a smaller reporting company)

Smaller reporting company o

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

As of May 4, 2009, the registrant has outstanding 309,701,106 shares of common stock, $1 par value
per share.

Baker Hughes Incorporated
Consolidated Condensed Balance Sheets
(In millions)


	March 31,			December 31,
	2009			2008
	(Unaudited)

ASSETS

Current Assets:
Cash and cash equivalents	$	1,179		$	1,955
Accounts receivable – less allowance for doubtful accounts (2009 - $103; 2008 - $74)		2,521			2,759
Inventories, net		2,104			2,021
Deferred income taxes		231			231
Other current assets		182			179

Total current assets		6,217			7,145

Property, plant and equipment, net		2,914			2,833
Goodwill		1,392			1,389
Intangible assets, net		195			198
Other assets		296			296

Total assets	$	11,014		$	11,861


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Accounts payable	$	728		$	888
Short-term borrowings and current portion of long-term debt		37			558
Accrued employee compensation		405			530
Income taxes payable		98			272
Other accrued liabilities		224			263

Total current liabilities		1,492			2,511

Long-term debt		1,776			1,775
Deferred income taxes and other tax liabilities		397			384
Liabilities for pensions and other postretirement benefits		317			317
Other liabilities		66			67

Stockholders’ Equity:
Common stock		310			309
Capital in excess of par value		769			745
Retained earnings		6,424			6,276
Accumulated other comprehensive loss		(537	)		(523	)

Total stockholders’ equity		6,966			6,807

Total liabilities and stockholders’ equity	$	11,014		$	11,861

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,
	2009			2008

Cash flows from operating activities:
Net income	$	195		$	395
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		173			147
Stock-based compensation costs		23			15
Provision(benefit) for deferred income taxes		10			(13	)
Gain on disposal of assets		(21	)		(8	)
Gain on sale of product line		—			(28	)
Changes in operating assets and liabilities:
Accounts receivable		258			(30	)
Inventories		(96	)		(118	)
Accounts payable		(145	)		(21	)
Accrued employee compensation and other accrued liabilities		(171	)		(130	)
Income taxes payable		(161	)		64
Other		(31	)		(37	)

Net cash flows from operating activities		34			236


Cash flows from investing activities:
Expenditures for capital assets		(281	)		(227	)
Proceeds from disposal of assets		47			36
Proceeds from sale of product line		—			31

Net cash flows from investing activities		(234	)		(160	)


Cash flows from financing activities:
Net borrowings of commercial paper and other short-term debt		4			466
Repayment of long-term debt		(525	)		—
Proceeds from issuance of common stock		—			36
Repurchases of common stock		—			(567	)
Dividends		(46	)		(41	)

Net cash flows from financing activities		(567	)		(106	)


Effect of foreign exchange rate changes on cash		(9	)		6

Decrease in cash and cash equivalents		(776	)		(24	)
Cash and cash equivalents, beginning of period		1,955			1,054

Cash and cash equivalents, end of period	$	1,179		$	1,030


Supplemental cash flows disclosures:
Income taxes paid (net of refunds)	$	249		$	125
Interest paid	$	33		$	31
Supplemental disclosure of noncash investing activities:
Capital expenditures included in accounts payable	$	21		$	24

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, 2008 (“2008 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 September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurements (“SFAS 157”), which is intended to increase consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value and expanding disclosures about fair value measurements. On January 1, 2008, we adopted the provisions of SFAS 157 related to financial assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a recurring basis and on January 1, 2009, we adopted the provisions related to nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis. There was no material impact to our consolidated condensed financial statements related to these adoptions. Additionally, in April 2009, the FASB issued the following three FASB Staff Positions (“FSP”): (i) FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, (ii) FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairment, and (iii) FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instrument, which collectively provide additional guidance and require additional disclosure regarding determining and reporting fair values for certain assets and liabilities. We will adopt these three FSPs in the second quarter of 2009 and have not determined the impact, if any, on our consolidated condensed financial statements.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51 (“SFAS 160”). SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary in an effort to improve the relevance, comparability and transparency of the financial information that a reporting entity provides. On January 1, 2009, we adopted SFAS 160 with no change to our consolidated condensed financial statements as amounts are immaterial.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS 141(R)”). SFAS 141(R) replaces FASB Statement No. 141, Business Combinations (“SFAS 141”). The statement retains the purchase method of accounting used in business combinations but replaces SFAS 141 by establishing principles and requirements for the recognition and measurement of assets, liabilities and goodwill, and requires that most transaction and restructuring costs related to the acquisition be expensed. We will apply the provisions of SFAS 141(R) for business combinations with an acquisition date on or after January 1, 2009.

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

months ended March 31, 2009 is to increase the weighted average shares outstanding for basic and diluted shares by 3 million and 2 million, respectively. FSP EITF 03-6-1 has not been applied to prior year quarters as the impact is immaterial.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133 (“SFAS 161”). SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in hedged positions. We adopted the new disclosure requirements in the first quarter of 2009 as reflected in Note 9. Derivative Instruments and Hedging Activities.

In December 2008, the FASB issued FSP FAS 132(R)-1 Employers’ Disclosures about Postretirement Benefit Plan Assets. This FSP requires the disclosures of investment policies and strategies, major categories of plan assets, fair value measurement of plan assets and significant concentration of credit risks. We will adopt the new disclosure requirements in the fourth quarter of 2009.

NOTE 2. GAIN ON SALE OF PRODUCT LINE

In February 2008, we sold the assets associated with the Completion and Production segment’s Surface Safety Systems (“SSS”) product line and received cash proceeds of $31 million. The SSS assets sold included hydraulic and pneumatic actuators, bonnet assemblies and control systems. We recorded a pre-tax gain of $28 million (approximately $18 million after-tax) in the first quarter of 2008.

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. We also have an Employee Stock Purchase Plan available for eligible employees to purchase shares of our common stock at a 15% discount. We recorded $23 million and $15 million of total stock-based compensation expense for the three months ended March 31, 2009 and 2008, respectively.

Stock Options

Our stock option plans provide for the issuance of incentive and non-qualified stock options to directors, officers and other key employees at an exercise price equal to the fair market value of the stock at the date of grant. We typically grant options twice a year in the first and third quarters.

The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes option pricing model. The following table presents the weighted-average assumptions used in the option pricing model for the three months ended March 31, 2009 and 2008.


	2009			2008

Expected life (years)		6.0			5.5
Risk-free interest rate		2.2	%		2.8	%
Volatility		43.0	%		30.1	%
Dividend yield		2.1	%		0.7	%
Weighted-average fair value per share at grant date	$	10.42		$	21.36

We granted 997,284 options during the three months ended March 31, 2009 at a weighted-average exercise price per option of $29.18.

Restricted Stock Awards and Units

In addition to stock options, the directors, officers and key employees may be granted restricted stock awards (“RSA”), which is an award of common stock with no exercise price, or restricted stock units (“RSU”), where each unit represents the right to receive at the end of a stipulated period one unrestricted share of stock with no exercise price. We typically grant RSAs and RSUs once a year in January. We determine the fair value of RSAs and RSUs based on the market price of our common stock on the date of grant.

We granted 882,029 RSAs and 324,152 RSUs during the three months ended March 31, 2009, each at a weighted-average price per award or unit of $29.18.

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

Employee Stock Purchase Plan

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


	2009			2008

Expected life (years)		1.0			1.0
Risk-free interest rate		0.3	%		3.3	%
Volatility		69.5	%		32.8	%
Dividend Yield		1.9	%		0.6	%

Fair value per share of 15% cash discount	$	4.81		$	10.01
Fair value per share of look-back provision	$	8.44		$	11.44

Total weighted-average fair value per share at grant date	$	13.25		$	21.45

Based on contributions as currently elected by eligible employees and based on our stock price on January 1, 2009, we estimate we will issue approximately 1.9 million shares under our ESPP on or around January 1, 2010.

NOTE 4. EARNINGS PER SHARE

On January 1, 2009, we adopted FSP EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. This FSP clarifies that all outstanding unvested share-based payments that contain rights to non-forfeitable dividends are participating securities and shall be included in the computation of both basic and diluted earnings per share. The impact in the three months ended March 31, 2009 is to increase the weighted average shares outstanding for basic and diluted shares by 3 million and 2 million, respectively. FSP EITF 03-6-1 has not been applied to prior year quarters as the impact is immaterial.

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


	Three Months Ended
	March 31,
	2009		2008

Weighted average common shares outstanding for basic EPS		310		310
Effect of dilutive securities – stock plans		—		1

Adjusted weighted average common shares outstanding for diluted EPS		310		311


Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than average market price for the period		3		1

NOTE 5. INVENTORIES

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


	March 31,		December 31,
	2009		2008

Finished goods	$	1,755	$	1,693
Work in process		189		175
Raw materials		160		153

Total	$	2,104	$	2,021

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

NOTE 6. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are comprised of the following:


	March 31,			December 31,
	2009			2008

Land	$	88		$	85
Buildings and improvements		908			878
Machinery and equipment		3,151			3,082
Rental tools and equipment		2,067			1,991

Subtotal		6,214			6,036
Accumulated depreciation		(3,300	)		(3,203	)

Total	$	2,914		$	2,833

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, 2008	$	951	$	438	$	1,389
Purchase price and other adjustments		2		—		2
Impact of foreign currency translation adjustments		1		—		1

Balance as of March 31, 2009	$	954	$	438	$	1,392

Intangible assets are comprised of the following:


	March 31, 2009							December 31, 2008
	Gross							Gross
	Carrying		Accumulated					Carrying		Accumulated
	Amount		Amortization			Net		Amount		Amortization			Net

Technology-based	$	259	$	(126	)	$	133	$	256	$	(122	)	$	134
Contract-based		13		(8	)		5		12		(7	)		5
Marketing-related		33		(7	)		26		33		(6	)		27
Customer-based		37		(6	)		31		37		(5	)		32
Other		—		—			—		1		(1	)		—

Total	$	342	$	(147	)	$	195	$	339	$	(141	)	$	198

Intangible assets with finite useful lives 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, 2009 was $7 million and is estimated to be $25 million for the year 2009. Estimated amortization expense for each of the subsequent five fiscal years is expected to be as follows: 2010 – $23 million; 2011 – $20 million; 2012 – $19 million; 2013 – $16 million; and 2014 – $13 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).

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

•

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).

The table below details the financial assets and liabilities included in our financial statements and measured at fair value as of March 31, 2009 classified based on the valuation technique level.


	March 31, 2009
Description	Total		Level 1		Level 2		Level 3

Assets:
Auction rate securities	$	11	$	—	$	—	$	11
Non-qualified defined contribution plan assets		109		—		109		—

Total assets at fair value	$	120	$	—	$	109	$	11


Liabilities:

Non-qualified defined contribution plan liabilities	$	109	$	—	$	109	$	—

Auction Rate Securities

The Company owns auction rate securities (“ARS”) that were purchased in 2007 at an original cost of $36 million and have a fair value of $11 million at March 31, 2009. These ARS represent interests in three variable rate debt securities, which are credit linked notes that generally combine low risk assets and credit default swaps (“CDS”) to create a security that pays interest from the assets’ coupon payments and the periodic sale proceeds of the CDS. As of March 31, 2009, the three notes carried the same split ratings as they had at December 31, 2008, ranging from A to BB, as provided by Standard & Poor’s and Fitch rating agencies.

We utilized Level 3 inputs to estimate the fair value of our ARS investments based on the underlying structure of each security and their collateral values, including assessments of counterparty credit quality, default risk underlying the security, expected cash flows, discount rates and overall capital market liquidity. The fair value of the securities at March 31, 2009 did not change from the beginning of the quarterly period. The valuation of our ARS investments is subject to uncertainties that are difficult to predict and require significant judgment. Based on our ability and intent to hold such investments for a period of time sufficient to allow for any anticipated recovery in the fair value, we have classified all of our auction rate securities as noncurrent investments.

Non-qualified Defined Contribution Plan Assets and Liabilities

We have a non-qualified defined contribution plan that provides basically the same benefit 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. The assets of both plans consist primarily of mutual funds and to a lesser extent equity securities. 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 2 inputs at the reporting date and were based on quoted market prices from various major stock exchanges.

NOTE 9. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVTIES

On January 1, 2009, we adopted SFAS 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement 133. The adoption of SFAS 161 had no financial impact on our consolidated condensed financial statements and only required additional financial statement disclosures. We have applied the requirements of SFAS 161 on a prospective basis.

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 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 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 SFAS 133. The hedging objective is to mitigate exposure to fluctuations in the non functional currency exchange rate. Accordingly, we record the fair value of these contracts as of the end of our reporting period to our consolidated

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

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, 2009, we had outstanding foreign currency forward contracts with notional amounts aggregating $154 million to hedge exposure to currency fluctuations in various foreign currencies. These contracts expire on various dates prior to June 30, 2009. These contracts are designated and qualify as fair value hedging instruments. The fair value of these contracts outstanding at March 31, 2009, was approximately $1 million and was included in other current assets in the consolidated condensed balance sheet. The fair value was determined using a model with Level 2 inputs including quoted market prices for contracts with similar terms and maturity dates.

The effect of derivative instruments, which consisted primarily of foreign currency forward contracts, on the consolidated statement of operations for the three months ended March 31, 2009 is $2 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.

NOTE 10. INDEBTEDNESS

During the first quarter of 2009, we repaid $325 million principal amount of our 6.25% notes, which matured on January 15, 2009, and $200 million principal amount of our 6.00% notes, which matured on February 15, 2009.

On March 30, 2009, we entered into a credit agreement (the “2009 Credit Agreement”) for a committed $500 million revolving credit facility that expires in March 2010. At March 31, 2009, we had $1.51 billion of credit facilities with commercial banks, of which $1.0 billion are committed revolving credit facilities, which includes the 2009 Credit Agreement. The committed facilities expire on July 7, 2012 ($500 million), unless extended, and on March 29, 2010 ($500 million). The $500 million facility that expires on July 7, 2012 provides for a one year extension, subject to the approval and acceptance by the lenders, among other conditions. In addition, this facility contains a provision to allow for an increase in the facility amount of an additional $500 million, subject to the approval and acceptance by the lenders, among other conditions. 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, 2009, 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, 2009. We also have an outstanding commercial paper program under which we may issue from time to time up to $1.0 billion in commercial paper with maturity of no more than 270 days. To the extent we have outstanding commercial paper, our ability to borrow under the facilities is reduced. At March 31, 2009, we had no outstanding commercial paper.

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. We report results for our product-line focused divisions under two segments: the Drilling and Evaluation segment and the Completion and Production segment. We have aggregated the divisions within each segment because they have similar economic characteristics and because the long-term financial performance of these divisions is affected by similar economic conditions. They also operate in the same markets, which includes all of the major oil and natural gas producing regions of the world. The results of each segment are evaluated regularly by our chief operating decision maker in deciding how to allocate resources and in assessing performance.

	•		The Drilling and Evaluation segment consists of the Baker Hughes Drilling Fluids (drilling fluids), Hughes Christensen (oilfield drill bits), INTEQ (drilling, measurement-while-drilling and logging-while-drilling) and Baker Atlas (wireline formation evaluation and wireline completion services) divisions and also includes our reservoir technology and consulting group. 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.

	•		The Completion and Production segment consists of the Baker Oil Tools (workover, fishing and completion equipment), Baker Petrolite (oilfield specialty chemicals), Centrilift (electrical submersible pumps and progressing cavity pumps)

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

divisions, the ProductionQuest (production optimization and permanent monitoring) business unit and 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 and dividend income, and certain gains and losses not allocated to the segments.

Summarized financial information is shown in the following table.


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

*Revenues*
Three months ended March 31, 2009	$	1,304	$	1,364	$	2,668	$	—		$	2,668
Three months ended March 31, 2008		1,391		1,279		2,670		—			2,670

*Segment profit (loss)*
Three months ended March 31, 2009	$	150	$	230	$	380	$	(96	)	$	284
Three months ended March 31, 2008		349		263		612		(43	)		569

*Total assets*
As of March 31, 2009	$	5,414	$	4,533	$	9,947	$	1,067		$	11,014
As of December 31, 2008		5,468		4,518		9,986		1,875			11,861

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


	Three Months Ended
	March 31,
	2009			2008

Corporate and other expenses	$	(62	)	$	(64	)
Gain on sale of product line		—			28
Interest expense		(35	)		(15	)
Interest and dividend income		1			8

Total	$	(96	)	$	(43	)

NOTE 12. EMPLOYEE BENEFIT PLANS

We have noncontributory defined benefit pension plans (“Pension Benefits”) covering employees primarily in the U.S., the U.K. and Germany. 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:


													Other Postretirement
	U.S. Pension Benefits						Non-U.S. Pension Benefits						Benefits
	Three Months Ended						Three Months Ended						Three Months Ended
	March 31,						March 31,						March 31,
	2009			2008			2009			2008			2009		2008

Service cost	$	7		$	8		$	1		$	1		$	2	$	2
Interest cost		5			5			4			5			3		3
Expected return on plan assets		(6	)		(10	)		(4	)		(6	)		—		—
Amortization of net loss		3			—			—			—			—		—

Net periodic benefit cost	$	9		$	3		$	1		$	—		$	5	$	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. 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. We record accruals for the uninsured portion of losses. The accruals for losses are calculated by estimating losses for claims using historical claim data, specific loss development factors and other information as necessary.

On September 12, 2001, we, without admitting or denying the factual allegations contained in the Order, consented with the SEC to the entry of an Order making Findings and Imposing a Cease-and-Desist Order (the “Order”) for violations of Section 13(b)(2)(A) and Section 13(b)(2)(B) of the Securities Exchange Act of 1934 (the “Exchange Act”). Such Sections of the Exchange Act require issuers to: (x) make and keep books, records and accounts, which, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the issuer and (y) devise and maintain a system of internal accounting controls sufficient to provide reasonable assurances that: (i) transactions are executed in accordance with management’s general or specific authorization; and (ii) transactions are recorded as necessary: (I) to permit preparation of financial statements in conformity with generally accepted accounting principles or any other criteria applicable to such statements, and (II) to maintain accountability for assets.

On March 29, 2002, we announced that we had been advised that the SEC and the Department of Justice (“DOJ”) were conducting investigations into allegations of violations of law relating to Nigeria and other related matters. The SEC issued a formal order of investigation into possible violations of provisions under the Foreign Corrupt Practices Act (“FCPA”) regarding anti-bribery, books and records and internal controls. In connection with the investigations, the SEC issued subpoenas seeking information about our operations in Angola and Kazakhstan as part of its investigation.

On April 26, 2007, the United States District Court, Southern District of Texas, Houston Division (the “Court”) unsealed a three-count criminal information (the “Information”) that had been filed against us as part of the execution of a Deferred Prosecution Agreement (the “DPA”) between us and the DOJ. The three counts arise out of payments made to an agent in connection with a project in Kazakhstan and include conspiracy to violate the FCPA, a substantive violation of the antibribery provisions of the FCPA, and a violation of the FCPA’s books-and-records provisions. All three counts relate to our operations in Kazakhstan during the period from 2000 to 2003.

On April 26, 2009, the DPA expired and pursuant to a motion filed by the DOJ, the Court issued an order on April 28, 2009, dismissing the Information on the basis that the Company had fully complied with its obligations under the DPA.

The DPA also required us to retain an independent monitor (the “Monitor”) for a term of three years to assess and make recommendations about our compliance policies and procedures and our implementation of those procedures. In addition, the Monitor was 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. Pursuant to the DPA, the DOJ has agreed not to prosecute us for violations of the FCPA based on information that we have disclosed to the DOJ regarding our operations in Nigeria, Angola, Kazakhstan, Indonesia, Russia, Uzbekistan, Turkmenistan, and Azerbaijan, among other countries.

On April 26, 2007, the Court also accepted a plea of guilty by our subsidiary Baker Hughes Services International, Inc. (“BHSII”) pursuant to a plea agreement between BHSII and the DOJ (the “Plea Agreement”) based on similar charges relating to the same conduct. Pursuant to the Plea Agreement, BHSII agreed to a three-year term of organizational probation. The Plea Agreement contains provisions requiring BHSII to cooperate with the government, to comply with all federal criminal law, and to adopt a Compliance Code similar to the one that the DPA requires of the Company.

Also on April 26, 2007, the SEC filed a Complaint (the “SEC Complaint”) and a proposed order (the “SEC Order”) against us in the Court. The SEC Complaint and the SEC Order were filed as part of a settled civil enforcement action by the SEC, to resolve the civil portion of the government’s investigation of us. As part of our agreement with the SEC, we consented to the filing of the SEC

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

Complaint without admitting or denying the allegations in the Complaint, and also consented to the entry of the SEC Order. The SEC Complaint alleges civil violations of the FCPA’s antibribery provisions related to our operations in Kazakhstan, the FCPA’s books-and-records and internal-controls provisions related to our operations in Nigeria, Angola, Kazakhstan, Indonesia, Russia, and Uzbekistan, and the SEC’s cease and desist order of September 12, 2001. The SEC Order became effective on May 1, 2007, which is the date it was confirmed by the Court. The SEC order enjoins us from violating the FCPA’s antibribery, books-and-records, and internal-controls provisions. As in the DPA, it requires that we retain the independent monitor to assess our FCPA compliance policies and procedures for the three-year period.

Under the terms of the settlements with the DOJ and the SEC, the Company and BHSII paid, in the second quarter of 2007, $44 million ($11 million in criminal penalties, $10 million in civil penalties, $20 million in disgorgement of profits and $3 million in pre-judgment interest) to settle these investigations. In the fourth quarter of 2006, we recorded a financial charge for the potential settlement.

On May 4, 2007 and May 15, 2007, the Sheetmetal Workers’ National Pension Fund and Chris Larson, respectively, instituted shareholder derivative lawsuits for and on the Company’s behalf against certain current and former members of the Board of Directors and certain current and former officers, and the Company as a nominal defendant, following the Company’s settlement with the DOJ and SEC in April 2007. On August 17, 2007, the Alaska Plumbing and Pipefitting Industry Pension Trust also instituted a shareholder derivative lawsuit for and on the Company’s behalf against certain current and former members of the Board of Directors and certain current and former officers, and the Company as a nominal defendant. On June 6, 2008, the Midwestern Teamsters Pension Trust Fund and Oppenheim Kapitalanlagegesellschaft mbH instituted a shareholder derivative lawsuit for and on the Company’s behalf against certain current and former members of the Board of Directors and certain current and former officers, and the Company as a nominal defendant. The complaints in all four lawsuits allege, among other things, that the individual defendants failed to implement adequate controls and compliance procedures to prevent the events addressed by the settlement with the DOJ and SEC. The relief sought in the lawsuits includes a declaration that the defendants breached their fiduciary duties, an award of damages sustained by the Company as a result of the alleged breach and monetary and injunctive relief, as well as attorneys’ and experts’ fees. On May 15, 2008, the consolidated complaint of the Sheetmetal Workers’ National Pension Fund and the Alaska Plumbing and Pipefitting Industry Pension Trust was dismissed for lack of subject matter jurisdiction by the Houston Division of the United States District Court for the Southern District of Texas. The lawsuit brought by Chris Larson in the 215th District Court of Harris County, Texas was dismissed on September 15, 2008. The lawsuit brought by the Midwestern Teamsters Pension Trust Fund and Oppenheim Kapitalanlagegesellschaft mbH is pending in the Houston Division of the United States District Court for the Southern District of Texas. An estimate of the possible loss or range of loss in connection with this lawsuit cannot be made. However, we do not expect this lawsuit to have a material adverse effect on our consolidated condensed financial statements.

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 $633 million at March 31, 2009. 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,
	2009			2008

Net income	$	195		$	395
Other comprehensive income (loss):
Foreign currency translation adjustments during the period		(16	)		28
Pension and other postretirement benefits		2			(5	)

Total comprehensive income	$	181		$	418

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, 2008 (“2008 Annual Report”).

EXECUTIVE SUMMARY

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. We report our results under two segments: the Drilling and Evaluation segment and the Completion and Production segment, which are aligned by product line based upon the types of products and services provided to our customers and upon the business characteristics of the product lines divisions during business cycles. Collectively, we refer to the results of these two segments as Oilfield Operations.

Prior to May 4, 2009, the business operations of our divisions were organized around four primary geographic regions: North America; Latin America; Europe, Africa, Russia, Caspian; and Middle East, Asia Pacific. As of March 31, 2009, we had approximately 37,900 employees, with approximately 58% of these employees working outside the United States.

On May 4, 2009, we reorganized the Company by geography and product lines. Global operations are now organized into a number of geomarket organizations, which report to nine Region Presidents who in turn report to two Hemisphere Presidents (Eastern and Western). The product-line marketing and technology organizations report to a Products and Technology President. The Products and Technology President and the two Hemisphere Presidents report to our Chief Operating Officer. The reorganization of the Company by geography and product lines is intended to strengthen our client-focused operations by moving management into the countries where we conduct our business. The product-line organizations will continue to be responsible for product development and manufacturing, technology, marketing and delivery of solutions for our customers to advance their reservoir performance. The new organization structure will also improve cross-product-line technology development, sales processes and integrated operations capabilities.

The primary driver of our business is our customers’ capital and operating expenditures dedicated to oil and natural gas exploration, field development and production. Our business is cyclical and is dependent upon our customers’ expectations for future oil and natural gas prices, future economic growth, hydrocarbon demand and estimates of future oil and natural gas production.

During the first quarter of 2009, as the global economy continued to weaken, many of our customers announced reductions in their planned 2009 spending, and we have seen significant decreases in drilling activity, particularly in the U.S. land market and Canada. In this challenging environment, we generated revenues of $2.67 billion in the first quarter of 2009, which is flat compared to the first quarter of 2008, despite a 19% decrease in the worldwide average rig count for the same time period. Our North American revenues for the first quarter of 2009 were $1.08 billion, a decrease of 8% compared to a 25% decrease in the U.S. rig count and a 36% decrease in the Canadian rig count, which reflects the severe contraction in customer spending and activity. Revenues outside of North America were $1.59 billion, an increase of 6% compared to the first quarter of 2008. As a result of the decline in activity and contractions in customer spending, we took actions to adjust our operating cost base, which consisted primarily of a reduction in workforce. In connection with this reduction in workforce, we recorded expenses of $54 million related to employee severance costs. Net income for the first quarter of 2009 was $195 million compared with $395 million in the first quarter of 2008.

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 credit crisis, lower oil and natural gas prices and weakening global economic outlook impact our business environment. Our customers typically fund their activity through a combination of borrowed funds and internally-generated cash flow. The limited availability of commercial credit is having a negative effect on the general economy and the ability of our customers to continue to operate at pre-crisis levels. The decline in oil prices and natural gas prices from 2008 mid-summer highs reduced our customers’

operational cash flow, further challenging their ability to continue to operate at past levels and reducing the near-term outlook for our products and services. The economic slowdown is also negatively impacting the incremental demand for hydrocarbon products especially in OECD (Organization for Economic Cooperation and Development) countries.

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,
	2009		2008

Oil prices ($/Bbl)	$	43.18	$	97.86
Natural gas prices ($/mmBtu)		4.55		8.64

Oil prices averaged $43.18/Bbl in the first quarter of 2009. Prices ranged from a low of $33.98/Bbl in mid-February to a quarter high of $54.34/Bbl in late March. Low oil prices throughout much of the quarter reflected concerns about weak worldwide demand relative to supply. Oil prices strengthened in late March on reports of lower OPEC production levels. The International Energy Agency (“IEA”) estimated in its April 2009 Oil Market Report that worldwide demand would decrease 3% to 83.4 million barrels per day in 2009, down from an estimated 85.8 million barrels per day in 2008.

Natural gas prices averaged $4.55/mmBtu in the first quarter of 2009. Natural gas prices decreased from a high of $6.11/mmBtu in early January to a low of $3.59/mmBtu in late March. The decrease in natural gas prices was the result of a number of factors, including a weak demand forecast, high production levels and high levels of natural gas in storage relative to the five-year average. In addition, gas prices reflect growing concern that imports of liquefied natural gas (“LNG”) to the U.S. could rise in 2009 as global supply of LNG increases and demand for LNG weakens in international markets.

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
	2009		2008		(Decrease)

U.S. – land and inland waters		1,287		1,712		(25	%)
U.S. – offshore		57		58		(2	%)
Canada		332		516		(36	%)

North America		1,676		2,286		(27	%)

Latin America		371		373		(1	%)
North Sea		50		40		25	%
Other Europe		39		51		(24	%)
Africa		59		65		(9	%)
Middle East		267		272		(2	%)
Asia Pacific		239		245		(2	%)

Outside North America		1,025		1,046		(2	%)

Worldwide		2,701		3,332		(19	%)

The rig count in North America decreased 27% primarily due to declines in natural gas drilling activity. Outside North America, the rig count decreased 2%. The rig count in Latin America decreased due to lower activity in Argentina, Venezuela and Colombia. The North Sea rig count increased primarily due to increases in the Norwegian sector. The rig count in Africa decreased primarily due to lower activity in Nigeria and Algeria. The rig count decreased in the Middle East due to lower activity in Saudi Arabia, Oman and Qatar and in the Asia Pacific region due to lower activity in India and Australia.

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, 2009 and 2008, respectively.


	Three Months Ended March 31,
	2009				2008

Revenues	$	2,668	100	%	$	2,670	100.0	%
Cost of revenues		1,960	73	%		1,769	66	%
Research and engineering		109	4	%		103	4	%
Marketing, general and administrative		281	11	%		250	9	%

Revenues


	Three Months Ended
	March 31,				Increase
	2009		2008		(Decrease)			% Change

Geographic Revenues:
North America	$	1,083	$	1,177	$	(94	)		(8	)%
Latin America		288		235		53			23	%
Europe, Africa, Russia, Caspian		776		762		14			2	%
Middle East, Asia Pacific		521		496		25			5	%

Total revenues	$	2,668	$	2,670	$	(2	)		0	%

Revenues for the three months ended March 31, 2009 were flat compared with the three months ended March 31, 2008, primarily due to declines in North America as a result of contractions in customer spending resulting in sharp reductions in activity, lower pricing for our products and services and the weakening global economic environment offset by increases in activity outside of North

America in key geographic areas. The worldwide rig count decreased 19% for the three months ended March 31, 2009 compared with the three months ended March 31, 2008.

North America

Revenues in North America, which accounted for 41% of total revenues, decreased 8% for the three months ended March 31, 2009 compared to the three months ended March 31, 2008, due primarily to the drop in drilling activity in North America. U.S. revenues were down 5% compared to a rig count that was down 24%. The activity declined as customers adapted to a market characterized by lower natural gas and oil prices, scarce commercial credit, ample natural gas supplies, and reduced natural gas demand. Our results highlight the differential performance of our Completion and Production segment, where U.S. revenues were up 13%, compared to our Drilling and Evaluation segment, where U.S. revenues were down 23% in line with the rig count decline. Canada revenues decreased 19% as a result of decreased activity evidenced by a 36% decrease in the rig count. A weaker Canadian dollar was also a contributing factor to the decline in Canadian revenue.

Outside North America

Revenues outside North America, which accounted for 59% of total revenues, increased 6% for the three months ended March 31, 2009 compared with the three months ended March 31, 2008. This increase reflected the relative strength of certain international markets, including Latin America, Norway, and Africa, partially offset by the contraction in the Saudi Arabia, Russia, Caspian, and U.K. markets.

Latin America revenues increased 23% compared to the first quarter of 2008 and compared to a 1% decrease in the rig count. The largest revenue increases occurred in Brazil, Mexico, Colombia and Ecuador. The improved revenue in Latin America was led by directional drilling and drilling fluids product lines in Brazil, completion systems in Mexico and directional drilling and artificial lift product lines in Colombia.

Europe, Africa, Russia, Caspian (“EARC”) revenues increased 2% compared to the first quarter of 2008. The increase in revenues was led by the Africa region with an increase in directional drilling, completions and artificial lift activity in Libya and by completions activity in Nigeria. The increase was partially offset by a decrease in Europe as increased sales for directional drilling in Norway was more than offset by weaker sales in the U.K. and a decrease in Russia and the Caspian in our completion product-line sales.

Activity in the Middle East, Asia Pacific (“MEAP”) region continued to expand, reflected by a 5% increase in revenues compared to the first quarter of 2008. Middle East revenues increased 2% compared to a 2% decrease in the rig count, and Asia Pacific revenues were up 8% compared to a 2% decrease in the rig count. The improvement in revenues from the region was led by higher activity in the United Arab Emirates, Egypt, Oman, Indonesia, Brunei, and India partially offset by lower revenues from Saudi Arabia and Qatar.

Cost of Revenues

Cost of revenues for the three months ended March 31, 2009 increased 11% compared to the three months ended March 31, 2008. Cost of revenues as a percentage of revenues was 73% and 66% for the three months ended March 31, 2009 and 2008, respectively. The increase in cost of revenues as a percentage of revenues is primarily due to lower activity worldwide, price deterioration primarily in North America, costs associated with employee severance of $45 million, costs associated with our provision for doubtful accounts, and a change in the geographic and product mix from the sale of our products and services.

Research and Engineering

Research and engineering expenses increased 6% for the three months ended March 31, 2009 compared to the three months ended March 31, 2008. We continue to be committed to developing and commercializing new technologies as well as investing in our core product offerings. The increase in research and engineering expenses includes $3 million associated with employee severance.

Marketing, General and Administrative

Marketing, general and administrative expenses increased 12% for the three months ended March 31, 2009 compared to the three months ended March 31, 2008. The increase resulted primarily from costs associated with finance redesign efforts, software implementation activities and $6 million associated with employee severance.

Interest Expense

Interest expense increased $20 million for the three months ended March 31, 2009 compared with the three months ended March 31, 2008 due to higher average debt levels as a result of the long-term debt issuances of $1.25 billion in October 2008.

Income Taxes

Our effective tax rate in the first quarter of 2009 is 31.5%, 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 FIN 48, Accounting for Uncertainty in Income Taxes: an Interpretation of FASB Statement No. 109.

OUTLOOK

Worldwide Oil and Natural Gas Industry Outlook

This section should be read in conjunction with the factors described in “Part II, Item 1A. Risk Factors” and in the “Forward-Looking Statements” section in this Part I, Item 2, both contained herein. These factors could impact, either positively or negatively, our expectation for: oil and natural gas demand; oil and natural gas prices; exploration and development spending and drilling activity; and production spending.

The credit crisis, lower oil and natural gas prices, and a weakening global economic outlook are all impacting our business environment. Our customers typically fund their activity through a combination of borrowed funds and internally-generated cash flow. The continued limited availability of commercial credit is having a negative effect on both the general economy and the ability of our customers to continue to operate at pre-crisis levels. The decline in oil prices and natural gas prices from 2008 mid-summer highs has also reduced our customers’ operational cash flow, further challenging their ability to continue to operate at past levels as well as their future spending for our products and services. The economic slowdown is also negatively impacting the incremental demand for hydrocarbon products.

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 International Energy Agency (“IEA”) and the Monthly Oil Market Report published by the Organization for Petroleum Exporting Countries (“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”), OECD and the World Bank.

As an oil service 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 their forecasts of future energy demand, their expectations for future energy prices, their access to reserves to develop and produce oil and gas and their ability to fund their capital programs.

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. The current down cycle is different in that the primary driver is the rapid deterioration of the global economy, which has led to declining demand and forecasts for further reductions in future demand. The drop in commodity prices, in conjunction with reduced access to the debt markets, has forced many oil and gas companies to reduce their spending to levels supportable by their expected free cash flow.

In North America, the outlook for spending in 2009 is also dependent on the outlook for the natural gas industry. Increased drilling activity through September 2008 and the application of horizontal drilling and advanced fracturing and completion technologies in the unconventional gas fields has resulted in gas production exceeding demand. Natural gas prices have fallen from mid-2008 highs and are not expected to increase until drilling is reduced to a level below the rate necessary to offset depletion, and supply and demand come back into balance. The commodity cycle in North American natural gas is being aggravated by the recession, storage levels that are approximately 35% greater than last year, low natural gas prices and reduced access to credit for many of our customers.

The outlook for the global economy and the depth and duration of the recession remain uncertain. We use third-party forecasts, including forecasts by the IMF, World Bank and OECD, to set our expectations for global economic growth. Through April 2009, each month has brought incremental negative revisions to the forecasted economic level for 2009. The IEA, OPEC and the Energy Information Administration (“EIA”) have also made significant negative revisions to their forecasts of 2009 oil demand over the past ten months.

Expectations for Oil Prices – As a result of the global economic recession, demand for oil is expected to decrease in a range from 1.4 million to 2.4 million barrels per day in 2009 relative to 2008. Non-OPEC supply growth is expected to moderate in response to decreased spending and is now expected to be unchanged (+/- 0.3 million barrels per day). Decreased demand and flat non-OPEC production are expected to pressure OPEC to make significant cuts in its production levels in an attempt to support oil prices. Inventories and spare productive capacity, which buffer oil markets from supply disruptions, are expected to increase as the gap between increasing supply and decreasing demand grows. In its April 2009 STEO report, the DOE forecasted oil prices to average $53/Bbl in 2009. The DOE expects the balance of supply in 2010 to tighten, allowing prices to increase to an average of $63/Bbl for 2010. Variables that could significantly affect this forecast include changes in the assumption for global economic growth and energy demand, changes or delays in non-OPEC supply additions and OPEC production quota discipline.

Expectations for North American Natural Gas Prices – The combination of rising natural gas production and recession-driven decreases in natural gas demand are expected to drive gas prices lower in 2009 relative to 2008. In its April 2009 STEO report, the DOE forecasted that U.S. natural gas demand would decrease 2% in 2009 compared to 2008, assuming continued economic weakness and that natural gas prices would average about $4.24/mmBtu in 2009, down from $8.89/mmBtu in 2008. North American gas-directed drilling activity is expected to decrease in the U.S., resulting in fewer supply additions from new wells to offset production declines from existing wells. Gas prices are expected to remain soft until the gap between supply and demand tightens as gas demand growth exceeds gas supply growth for some period of time. The DOE forecasts gas prices to increase modestly to $5.80/mmBtu in 2010. Prices remain volatile with the economy, weather-driven demand, imports of Canadian gas, LNG imports, gas storage levels, and production from the lower 48 states’ gas fields playing significant roles in determining both prices and price volatility. Variations in the supply demand balance will be reflected in gas storage levels.

Industry Activity and Customer Spending – Our forecasts of activity and customer spending are based upon our discussions with major customers, reviews of published industry reports, our outlook for oil and natural gas prices described above, and our outlook for drilling activity, as measured by the Baker Hughes rig count. We believe that our customers’ 2009 spending plans are based on forecasts of oil and gas prices and energy demand similar to those stated above. In addition, each company’s 2009 spending plans also reflect company-specific drivers such as their ability to finance their 2009 spending plans as well as their assessments of the uncertainty associated with their forecasts. At current and expected oil and natural gas prices, some projects that were planned in 2008 to begin in 2009 or 2010 may no longer be economically attractive. In light of current economic conditions and current oil and gas prices, we believe that our customers, as a group, will decrease spending in 2009 relative to 2008.

	•		North America – Both customer spending and drilling activity in North America, primarily directed at developing natural gas supplies, are expected to decrease approximately 25% to 40% in 2009 relative to 2008. Spending on producing oil and gas from developed fields is expected to remain flat or decrease modestly in 2009, reflecting the stability in oil and gas production levels.

	•		Outside North America – Both customer spending and drilling activity, primarily directed at developing oil supplies, are expected to decrease approximately 10% to 15% in 2009 relative to 2008. Spending on producing oil and gas from developed fields is expected to remain flat or decrease modestly in 2009, reflecting the stability in oil and gas production levels.

Our customers are likely to reduce their planned spending relative to the above outlook if oil prices were expected to trade below $40/Bbl for an extended period of time. The risks to oil prices falling below $40/Bbl for a significant period of time include (1) incremental weakness in the global economic outlook; (2) significant unexpected increases in non-OPEC production; (3) significant disruption to worldwide demand; (4) reduced geo-political tensions; (5) poor OPEC quota discipline; or (6) other factors that result in increased spare productive capacity, higher oil inventory levels or decreased demand.

Company 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 our expectation for oil and natural gas demand, oil and natural gas prices and drilling activity.

North American revenue is expected to decline approximately 25% to 35% in 2009 relative to 2008 reflecting reduced customer spending and deterioration of pricing offset by modest share gains or losses. Decreases in revenue for our Drilling and Evaluation segment are expected to be greater than the decline in revenue for our Completion and Production segment. In 2008, 2007 and 2006, North American revenues were 44%, 42%, and 44% of total revenues, respectively.

Outside of North America we expect revenues to decline approximately 5% to 15% in 2009 relative to 2008 with the most significant declines occurring in the Eastern Hemisphere. Share gains and activity increases in Brazil and Latin America could result in an increase in Latin America revenues in 2009 compared to 2008. Spending on large projects by National Oil Companies (“NOCs”) is expected to reflect established seasonal trends. In addition, customer spending could be affected by weather-related reductions in the North Sea in the first and second quarters of 2009. In 2008, 2007 and 2006, revenues outside North America were 56%, 58% and 56% of total revenues, respectively.

Profit is expected to decline in 2009 relative to 2008 as a result of lower activity levels and deterioration of pricing offset only partially by cost reductions. Factors that could have a significant positive impact on profitability include less than expected price deterioration for our products and services, lower than expected raw material and labor costs, and/or higher than expected planned activity. Conversely, greater than expected price deterioration, higher than expected raw material and labor costs and/or lower than expected activity would have a negative impact on profitability. Our ability to limit price deterioration is dependent on demand for our products and services, our competitors’ strategies for managing capacity in a declining market, our competitors’ strategies for defending market share and price, and our customers’ strategies for obtaining price concessions.

Our 2009 capital budget supports the continuation of the infrastructure expansion we began in late 2006 and early 2007. Capital expenditures are expected to be approximately $1.1 billion to $1.2 billion for 2009, including approximately $350 million to $400 million that we expect to spend on infrastructure, primarily outside North America. 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.

The execution of our 2009 business plan and the ability to meet our 2009 financial objectives are dependent on a number of factors. Key factors include: activity and spending levels in each of our markets; the relative strength of the oilfield services competition in each market and our ability to limit price decreases and manage raw material and labor costs. Other factors include, but are not limited to, our ability to: adjust our workforce to control costs while recruiting, training and retaining the skilled and diverse workforce necessary to meet our future business needs; continue to expand our business in areas that are expected to grow most rapidly when the economy and energy market recover (such as NOCs), and in areas where we have market share opportunities (such as the Middle East, Russia, Caspian, and India); manage raw material and component costs (steel alloys, copper, tungsten carbide, lead, nickel, chemicals and electronic components); continue to make ongoing improvements in the productivity of our manufacturing organization and manage our spending in the North American and international markets.

Compliance

In connection with our 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 divisions 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 taking 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 of zero tolerance for FCPA violations, 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” in our 2008 Annual Report.

LIQUIDITY AND CAPITAL RESOURCES

Our objective in financing our business is to maintain adequate financial resources and access to additional liquidity. During the three months ended March 31, 2009, cash on hand was the principal source of funding. At March 31, 2009, we had cash and cash equivalents of $1.18 billion and $1.51 billion of credit facilities with commercial banks, of which $1.0 billion are committed revolving credit facilities that provides additional liquidity. See further discussion below under “Available Credit Facilities.”

The declines in commodity prices are leading to reductions in cash flows of many of our customers. In addition, the tightening of the credit markets and increased costs of borrowing have affected the availability of credit. These factors may have adverse effects on the financial condition of our customers, which may result in delays, partial payment or non-payment of amounts owed to us thus negatively impacting our operating cash flows.

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, 2009, we used cash to pay for a variety of activities including working capital needs, dividends, debt maturities 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:


	2009			2008
Operating activities	$	34		$	236
Investing activities		(234	)		(160	)
Financing activities		(567	)		(106	)

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 $34 million in the three months ended March 31, 2009 compared with $236 million in the three months ended March 31, 2008. This decrease in cash flows of $202 million is primarily due to a decrease in net income plus higher net operating assets and liabilities in the three months ended March 31, 2009 compared to the same period in 2008.

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

	•		A decrease in accounts receivable in the first quarter of 2009 provided $258 million in cash compared with using $30 million in cash in the first quarter of 2008. 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 seven days reflecting a slowdown in customer payments.

	•		Inventory used $96 million in cash in the first quarter of 2009 compared with using $118 million in cash in the first quarter of 2008.

	•		Accrued employee compensation and other accrued liabilities used $171 million in cash in the first quarter of 2009 compared with using $130 million in cash in the first quarter of 2008. The primary use of cash in each quarter was the annual payment of employee bonuses in March of each year.

	•		Income taxes payable used $161 million in cash in the first quarter of 2009 compared to providing $64 million in cash in the first quarter of 2008. The increase in cash used was primarily due to federal income tax payments of $155 million for two quarterly installment payments. 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 $281 million and $227 million for the three months ended March 31, 2009 and 2008, 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 $47 million and $36 million for the three months ended March 31, 2009 and 2008, 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.

In February 2008, we sold the assets associated with the Completion and Production segment’s SSS product line and received cash proceeds of $31 million.

Financing Activities

We had net borrowings of commercial paper and other short-term debt of $4 million and $466 million in the three months ended March 31, 2009 and 2008, respectively. In addition, we repaid $525 million of maturing long-term debt in the three months ended March 31, 2009. Total debt outstanding at March 31, 2009 was $1.81 billion, a decrease of $520 million compared with December 31, 2008. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was 0.21 at March 31, 2009 and 0.25 at December 31, 2008.

We received proceeds of $36 million for the three months ended March 31, 2008 from the issuance of common stock from the exercise of stock options. We did not receive any proceeds from the issuance of common stock from the exercise of stock options for the three months ended March 31, 2009.

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

repurchase up to a total of $1.20 billion of our common stock. During the three months ended March 31, 2008, we repurchased 8 million shares of our common stock at an average price of $68.97 per share for a total of $567 million.

We paid dividends of $46 million and $41 million in the three months ended March 31, 2009 and 2008, respectively.

Available Credit Facilities

On March 30, 2009, we entered into a credit agreement (the “2009 Credit Agreement”). The 2009 Credit Agreement is a committed $500 million revolving credit facility that expires on March 29, 2010. At March 31, 2009, we had $1.51 billion of credit facilities with commercial banks, of which $1.0 billion are committed revolving credit facilities, which includes the 2009 Credit Agreement. The committed facilities expire on July 7, 2012 ($500 million), unless extended, and on March 29, 2010 ($500 million). The $500 million facility that expires on July 7, 2012 provides for a one year extension, subject to the approval and acceptance by the lenders, among other conditions. In addition, the facility contains a provision to allow for an increase in the facility amount of an additional $500 million, subject to the approval and acceptance by the lenders, among other conditions. 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, 2009, 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, 2009. We also have an outstanding commercial paper program under which we may issue from time to time up to $1.0 billion in commercial paper with maturity of no more than 270 days. To the extent we have outstanding commercial paper, our ability to borrow under the committed credit facilities is reduced. At March 31, 2009, we had no outstanding commercial paper.

If market conditions were to change and revenues were to be significantly reduced or operating costs were to increase, our cash flows and liquidity could be reduced. Additionally, it could cause the rating agencies to lower our credit rating. 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 2009, 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, pay dividends, repurchase common stock and support the development of our short-term and long-term operating strategies.

In 2009, we expect capital expenditures to be between $1.1 billion to $1.2 billion, excluding acquisitions. The expenditures are expected to be used primarily for normal, recurring items necessary to support the growth of our business and operations. 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 2009, we also expect to make interest payments of between $150 million and $155 million based on our current expectations of debt levels during 2009. We anticipate making income tax payments of between $325 million and $375 million in 2009.

As of March 31, 2009, we have authorization remaining to repurchase up to $1.20 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 2009; however, the Board of Directors can change the dividend policy at anytime.

We expect to contribute between $2 million and $3 million to our nonqualified U.S. pension plans and between $12 million and $14 million to the non-U.S. pension plans. We will also make benefit payments related to postretirement welfare plans of between $15 million and $16 million, and we estimate we will contribute between $139 million and $150 million to our defined contribution

plans.

NEW ACCOUNTING STANDARDS

In June 2008, the FASB issued FSP Emerging Issues Task Force (“EITF”) 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”). This FSP clarifies that all outstanding unvested share-based payments that contain rights to non-forfeitable dividends are participating securities and shall be included in the computation of both basic and diluted earnings per share. On January 1, 2009, we adopted FSP EITF 03-6-1. The impact in the three months ended March 31, 2009 is to increase the weighted average shares outstanding for basic and diluted shares by 3 million and 2 million, respectively. FSP EITF 03-6-1 has not been applied to prior year quarters as the impact is immaterial.

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, including changes in revenue, pricing, expenses, capital spending, profitability, strategies for our operations, impact of any common stock repurchases, oil and natural gas market conditions, market share and contract terms, costs and availability of resources, economic and regulatory conditions, and environmental matters are only our forecasts regarding these matters.

All of our forward-looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in “Part II, Item 1A. Risk Factors” section contained herein, as well as the risk factors described in our 2008 Annual Report, this filing and those set forth from time to time in our filings with the Securities and Exchange Commission (“SEC”). These documents are available through our web site or through the SEC’s Electronic Data Gathering and Analysis Retrieval System (“EDGAR”) at http://www.sec.gov.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We conduct operations around the world in a number of different currencies. A number 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, 2009, we had outstanding foreign currency forward contracts with notional amounts aggregating $154 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, 2009, was approximately $1 million and was included in other current assets 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 statement of operations for the three months ended March 31, 2009 is $2 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.

The counterparties to the forward contracts are major financial institutions. The credit ratings and concentration of risk of these financial institutions are monitored on a continuing basis. In the unlikely event that the counterparties fail to meet the terms of a foreign currency contract, our exposure is limited to the foreign currency rate differential.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this quarterly report, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the 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, 2009, 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, 2009 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 2008 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 2008 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 2009, we are experiencing a delay in receiving payments from our customers in Venezuela. As of March 31, 2009, our accounts receivable in Venezuela totaled approximately 6% of our total accounts receivable. For the year ended December 31, 2008, Venezuela revenues were approximately 2% of our total consolidated revenues for that year.

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, 2009.

Issuer Purchases of Equity Securities


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

January 1-31, 2009		99,887	$	31.64		—	$	—		99,887	$	—
February 1-28, 2009		160		33.90		—		—		160		—
March 1-31, 2009		3,626		30.03		—		—		3,626		—

Total		103,673	$	31.58		—	$	—		103,673	$	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 during the three months ended March 31, 2009.

⁽³⁾		Our Board of Directors has authorized a plan to repurchase our common stock from time to time. During the first quarter of 2009, we did not repurchase shares of our common stock. We had authorization remaining to repurchase up to a total of $1,197 million of our common stock.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

Our Annual Meeting of Stockholders was held on April 23, 2009 (i) to elect eleven members of the Board of Directors to serve for one-year terms; (ii) to ratify Deloitte & Touche LLP as our Independent Registered Public Accounting Firm for 2009; (iii) to approve the amendment to the Employee Stock Purchase Plan; and (iv) to vote on Stockholder Proposal No. 1 regarding the calling of special shareholder meetings. Following are the final results of the Annual Meeting.

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


	Number of		Number
	Affirmative		of Votes
Names	Votes		Withheld

Larry D. Brady		264,299,144		3,164,279
Clarence P. Cazalot, Jr.		264,291,999		3,171,424
Chad C. Deaton		257,648,036		9,815,387
Edward P. Djerejian		212,531,377		54,932,046
Anthony G. Fernandes		264,346,040		3,117,383
Claire W. Gargalli		212,383,535		55,079,888
Pierre H. Jungels		207,986,092		59,477,331
James A. Lash		264,294,185		3,169,238
J. Larry Nichols		210,837,076		56,626,347
H. John Riley, Jr.		212,449,184		55,014,239
Charles L. Watson		261,178,230		5,681,193

The number of affirmative votes, the number of negative votes and the number of abstentions with respect to the ratification of Deloitte & Touche LLP as Independent Registered Public Accounting Firm for 2009 was as follows:


Number of	Number of
Affirmative	Negative
Votes	Votes		Abstentions

265,436,138		1,884,472		142,813

The number of affirmative votes, the number of negative votes, the number of abstentions and the number of broker non-votes with respect to the approval of the amendment to the Employee Stock Purchase Plan was as follows:

Number of

Affirmative

Negative

Broker

Votes

Abstentions

Non-Votes

240,466,894

1,368,423

244,231

25,383,876

The number of affirmative votes, the number of negative votes, the number of abstentions and the number of broker non-votes with respect to Stockholder Proposal No. 1 regarding the calling of special shareholder meetings:

Number of

Affirmative

Negative

Broker

Votes

Abstentions

Non-Votes

128,834,722

112,890,646

354,181

25,383,876

As of February 26, 2009, the record date, there were 308,874,934 shares issued and outstanding and entitled to vote at the Company’s Annual Meeting of Stockholders. The information above reflects the number of votes cast by the holders of such Common Stock.

ITEM 5. OTHER INFORMATION

Item 5.02 Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers:

On May 1, 2009, the Compensation Committee of the Board of Directors of the Company approved compensation increases for Martin S. Craighead, Senior Vice President and Chief Operating Officer of the Company, and Peter A. Ragauss, Senior Vice President and Chief Financial Officer of the Company. Messrs. Craighead and Ragauss’ base salary will be increased to $650,000 effective May 3, 2009, and their bonus target eligibility will be increased to 90% of their base salary.

As previously disclosed, Mr. Craighead was promoted to Senior Vice President and Chief Operating Officer of the Company effective as of April 30, 2009. Mr. David H. Barr retired from the Company on April 30, 2009. Copies of Mr. Barr’s agreements, which were previously described, incorporated herein by reference and are listed as Exhibits 10.4 and 10.5. Mr. Barr will serve as a consultant to the Company until October 31, 2010.

ITEM 6. EXHIBITS


10.1		Credit Agreement dated as of March 30, 2009, among Baker Hughes Incorporated, JPMorgan Chase Bank, N.A., as Administrative Agent and thirteen lenders for $500 million, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed March 31, 2009).

10.2		Form of Performance Unit Award Agreement for the 2009 Performance Units, including terms and conditions (filed as Exhibit 10.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed March 31, 2009).

10.3		Baker Hughes Incorporated Employee Stock Purchase Plan, as amended and restated, effective as of February 26, 2009.

10.4		Letter Agreement between Baker Hughes Incorporated and David H. Barr dated February 25, 2009 (filed as Exhibit 10.59 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2008).

10.5		Consulting Agreement between Baker Hughes Oilfield Operations, Inc. and David H. Barr dated February 25, 2009 (filed as Exhibit 10.60 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2008).

31.1		Certification of Chad C. Deaton, Chief Executive Officer, dated May 7, 2009, 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, 2009, 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, 2009, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.


		Page No.
PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)
	Consolidated Condensed Statements of Operations (Unaudited) – Three months ended March 31, 2009 and 2008		2
	Consolidated Condensed Balance Sheets (Unaudited) – March 31, 2009 and December 31, 2008		3
	Consolidated Condensed Statements of Cash Flows (Unaudited) – Three months ended March 31, 2009 and 2008		4
	Notes to Unaudited Consolidated Condensed Financial Statements		5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		26
Item 4.	Controls and Procedures		26

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings		27
Item 1A.	Risk Factors		27
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		27
Item 3.	Defaults Upon Senior Securities		27
Item 4.	Submission of Matters to a Vote of Security Holders		28
Item 5.	Other Information		28
Item 6.	Exhibits		29
Signatures			30
EX-10.3
EX-31.1
EX-31.2
EX-32


	Three Months Ended
	March 31,
	2009			2008

Revenues:
Sales	$	1,311		$	1,253
Services and rentals		1,357			1,417

Total revenues		2,668			2,670


Costs and expenses:
Cost of sales		1,027			865
Cost of services and rentals		933			904
Research and engineering		109			103
Marketing, general and administrative		281			250

Total costs and expenses		2,350			2,122


Operating income		318			548
Gain on sale of product line		—			28
Interest expense		(35	)		(15	)
Interest and dividend income		1			8


Income before income taxes		284			569
Income taxes		(89	)		(174	)

Net income	$	195		$	395


Basic earnings per share	$	0.63		$	1.28

Diluted earnings per share	$	0.63		$	1.27

Cash dividends per share	$	0.15		$	0.13


	BAKER HUGHES INCORPORATED (Registrant)
Date: May 7, 2009	By:	/s/ PETER A. RAGAUSS
		Peter A. Ragauss
		Senior Vice President and Chief Financial Officer


Date: May 7, 2009	By:	/s/ ALAN J. KEIFER
		Alan J. Keifer
		Vice President and Controller

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