BAKER HUGHES a GE (BHI) 10-Q 2011 Q1 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2011

OR

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

Commission File Number 1-9397

Baker Hughes Incorporated

(Exact name of registrant as specified in its charter)

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

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

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

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

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

As of April 26, 2011, the registrant has outstanding 434,634,726 shares of Common Stock, $1 par value per share.

INDEX

	Page No.
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Consolidated Condensed Statements of Operations (Unaudited) — Three months ended March 31, 2011 and 2010		2
Consolidated Condensed Balance Sheets (Unaudited) — March 31, 2011 and December 31, 2010		3
Consolidated Condensed Statements of Cash Flows (Unaudited) — Three months ended March 31, 2011 and 2010		4
Notes to Unaudited Consolidated Condensed Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
Item 3. Quantitative and Qualitative Disclosures About Market Risk		23
Item 4. Controls and Procedures		24
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		24
Item 1A. Risk Factors		24
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		25
Item 3. Defaults Upon Senior Securities		25
Item 4. [Removed and Reserved]		25
Item 5. Other Information		25
Item 6. Exhibits		25
Signatures		27
EX-10.77
EX-31.1
EX-31.2
EX-32
EX-99.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

1

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Baker Hughes Incorporated

Consolidated Condensed Statements of Operations

(In millions, except per share amounts)

(Unaudited)

	Three Months Ended
	March 31,
	2011			2010
Revenues:
Sales	$	1,433		$	1,253
Services and rentals		3,092			1,286
Total revenues		4,525			2,539
Costs and expenses:
Cost of sales		1,166			943
Cost of services and rentals		2,331			969
Research and engineering		106			94
Marketing, general and administrative		282			305
Acquisition-related costs		—			10
Total costs and expenses		3,885			2,321
Operating income		640			218
Interest expense, net		(52	)		(24	)
Income before income taxes		588			194
Income taxes		204			65
Net income		384			129
Net income attributable to noncontrolling interests		3			—
Net income attributable to Baker Hughes	$	381		$	129
Basic earnings per share attributable to Baker Hughes	$	0.88		$	0.41
Diluted earnings per share attributable to Baker Hughes	$	0.87		$	0.41
Cash dividends per share	$	0.15		$	0.15

See accompanying notes to unaudited consolidated condensed financial statements.

2

Baker Hughes Incorporated

Consolidated Condensed Balance Sheets

(In millions)

(Unaudited)

	March 31,			December 31,
	2011			2010
ASSETS
Current Assets:
Cash and cash equivalents	$	1,144		$	1,456
Short-term investments		251			250
Accounts receivable — less allowance for doubtful accounts (2011 - $174; 2010 - $162)		4,371			3,942
Inventories, net		2,805			2,594
Deferred income taxes		234			234
Other current assets		240			231
Total current assets		9,045			8,707
Property, plant and equipment, net		6,432			6,310
Goodwill		5,943			5,869
Intangible assets, net		1,541			1,569
Other assets		536			531
Total assets	$	23,497		$	22,986
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	1,549		$	1,496
Short-term borrowings and current portion of long-term debt		296			331
Accrued employee compensation		566			589
Income taxes payable		197			219
Other accrued liabilities		531			504
Total current liabilities		3,139			3,139
Long-term debt		3,545			3,554
Deferred income taxes and other tax liabilities		1,332			1,360
Liabilities for pensions and other postretirement benefits		496			483
Other liabilities		162			164
Commitments and contingencies
Stockholders’ Equity:
Common stock		434			432
Capital in excess of par value		7,090			7,005
Retained earnings		7,399			7,083
Accumulated other comprehensive loss		(355	)		(420	)
Baker Hughes stockholders’ equity		14,568			14,100
Noncontrolling interest		255			186
Total stockholders’ equity		14,823			14,286
Total liabilities and stockholders’ equity	$	23,497		$	22,986

See accompanying notes to unaudited consolidated condensed financial statements.

3

Baker Hughes Incorporated

Consolidated Condensed Statements of Cash Flows

(In millions)

(Unaudited)

	Three Months Ended
	March 31,
	2011			2010
Cash flows from operating activities:
Net income	$	384		$	129
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		315			189
Stock-based compensation costs		29			19
Provision (benefit) for deferred income taxes		1			(40	)
Gain on disposal of assets		(47	)		(29	)
Provision for doubtful accounts		15			(2	)
Changes in operating assets and liabilities:
Accounts receivable		(398	)		(154	)
Inventories		(186	)		(47	)
Accounts payable		34			56
Accrued employee compensation and other accrued liabilities		(32	)		(22	)
Income taxes payable		(10	)		(53	)
Other		(29	)		(41	)
Net cash flows from operating activities		76			5
Cash flows from investing activities:
Expenditures for capital assets		(429	)		(190	)
Proceeds from disposal of assets		75			45
Other		(2	)		—
Net cash flows from investing activities		(356	)		(145	)
Cash flows from financing activities:
Net (payments) borrowings of commercial paper and other short-term debt		(36	)		218
Proceeds from issuance of common stock		57			2
Dividends		(65	)		(47	)
Excess tax benefits from stock-based compensation costs		4			1
Net cash flows from financing activities		(40	)		174
Effect of foreign exchange rate changes on cash		8			(15	)
(Decrease) increase in cash and cash equivalents		(312	)		19
Cash and cash equivalents, beginning of period		1,456			1,595
Cash and cash equivalents, end of period	$	1,144		$	1,614
Supplemental cash flows disclosures:
Income taxes paid (net of refunds)	$	236		$	158
Interest paid	$	64		$	20
Supplemental disclosure of noncash investing activities:
Capital expenditures included in accounts payable	$	67		$	15

See accompanying notes to unaudited consolidated condensed financial statements.

4

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 leading supplier of wellbore-related products and technology services and systems and provide products and services for drilling, pressure pumping, formation evaluation, completion and production, and reservoir technology and consulting to the worldwide oil and natural gas industry. We also provide products and services to the downstream refining, and process and pipeline industries.

Basis of Presentation

     Our unaudited consolidated condensed financial statements included herein have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) for interim financial information. Accordingly, certain information and disclosures normally included in our annual financial statements have been condensed or omitted. 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, 2010 (“2010 Annual Report”). We believe the unaudited consolidated condensed financial statements included herein reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. In the notes to the unaudited consolidated condensed financial statements, all dollar and share amounts in tabulations are in millions of dollars and shares, respectively, unless otherwise indicated.

NOTE 2. ACQUISITIONS

ACQUISITION OF BJ SERVICES

     On April 28, 2010, we acquired 100% of the outstanding common stock of BJ Services Company (“BJ Services”) in a cash and stock transaction valued at $6,897 million. BJ Services is a leading provider of pressure pumping and other oilfield services and was acquired to expand the product offerings of the Company. Total consideration consisted of $793 million in cash, 118 million shares valued at $6,048 million, and Baker Hughes options with a fair value of $56 million in exchange for BJ Services options. We also assumed all outstanding stock options held by BJ Services employees and directors.

Recording of Assets Acquired and Liabilities Assumed

     The transaction has been accounted for using the acquisition method of accounting and accordingly, assets acquired and liabilities assumed were recorded at their fair values as of the acquisition date. The excess of the consideration transferred over those fair values totaling $4,406 million was recorded as goodwill. The following table summarizes the amounts recognized for assets acquired and liabilities assumed.

	Fair Values
Assets:
Cash and cash equivalents	$	113
Accounts receivable		951
Inventories		419
Other current assets		125
Property, plant and equipment		2,745
Intangible assets		1,404
Goodwill		4,406
Other long-term assets		109

5

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

	Fair Values
Liabilities:
Liabilities for change in control and transaction fees		210
Current liabilities		776
Deferred income taxes and other tax liabilities		1,428
Long-term debt		531
Pension and other postretirement liabilities		154
Other long-term liabilities		29
Noncontrolling interests		247
Net assets acquired	$	6,897

Property, plant and equipment (“PP&E”)

     A step-up adjustment of $406 million was recorded to present the PP&E acquired at its fair value. The weighted average useful life used to calculate depreciation of the step-up related to PP&E is approximately six years.

Intangible assets

     We identified intangible assets including trade names, technology, in-process research and development (“IPR&D”), and customer relationships. We consider the BJ Services trade name to be an indefinite life intangible asset, which will not be amortized and will be subject to an annual impairment test.

     The following table summarizes the fair values recorded for the identifiable intangible assets and their estimated useful lives:

	Fair Values		Useful Lives
Customer relationships	$	428	3-16 years
Technology		451	5-15 years
BJ Services trade name		360	Indefinite
Other trade names		38	5-12 years
IPR&D		127	Indefinite
Total identifiable intangible assets	$	1,404

Deferred taxes

     We provided deferred taxes and other tax liabilities as part of the acquisition accounting related to the fair market value adjustments for acquired intangible assets and PP&E, as well as for uncertain tax positions taken in prior year tax returns. An adjustment of $1,262 million was recorded to present the deferred taxes and other tax liabilities at fair value.

Debt

     Our acquisition subsidiary assumed all of the obligations of BJ Services in respect of $250 million principal amount of 5.75% senior notes due June 2011 and $250 million principal amount of 6.00% senior notes due June 2018. A step-up adjustment of $34 million was recorded to present these notes at fair value.

Liabilities for pensions and other postretirement benefits

     We assumed several defined benefit pension plans covering certain employees primarily in the U.K., Norway and Canada. Additionally, we assumed a non-qualified supplemental executive retirement plan (“SERP”), as well as postretirement benefit plans that provide certain health care and life insurance benefits for retired employees, primarily in the United States, who meet specified age and service requirements. A step-up adjustment of $32 million was recorded to present these liabilities at fair value.

6

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

Noncontrolling Interests

     We obtained certain entities which were not wholly owned by BJ Services. A step-up adjustment of $202 million was recorded to present the noncontrolling interests in these entities at fair value.

Pro Forma Impact of the Acquisition

     The following unaudited supplemental pro forma results present consolidated information as if the acquisition had been completed as of January 1, 2010. The pro forma results include: (i) the amortization associated with an estimate of the acquired intangible assets, (ii) interest expense associated with debt used to fund a portion of the acquisition and reduced interest income associated with cash used to fund a portion of the acquisition, (iii) the impact of certain fair value adjustments such as additional depreciation expense for adjustments to property, plant and equipment and reduction to interest expense for adjustments to debt, and (iv) costs directly related to acquiring BJ Services. The pro forma results do not include any potential synergies, cost savings or other expected benefits of the acquisition. Accordingly, the pro forma results should not be considered indicative of the results that would have occurred if the acquisition and related borrowings had been consummated as of January 1, 2010, nor are they indicative of future results.

	Three Months Ended
	March 31, 2010
	Pro Forma
Revenues	$	3,657
Net income	$	139
Basic net income per share	$	0.32
Diluted net income per share	$	0.32

NOTE 3. SEGMENT INFORMATION

     Baker Hughes operates under five reportable segments as detailed below. The four geographic segments represent our oilfield operations.

• North America (Canada, U.S., and Trinidad)

• Latin America (Central and South America including Mexico and excluding Trinidad)

• Europe/Africa/Russia Caspian (“EARC”) (Europe, Africa — excluding Egypt, and Russia and the republics of the former Soviet Union)

• Middle East/Asia Pacific (“MEAP”) (including Egypt)

• Industrial Services and Other (downstream chemicals, process and pipeline services, reservoir and technology consulting businesses)

     The performance of our segments is evaluated based on profit before tax, which is defined as income before income taxes, interest expense, interest income, and certain gains and losses not allocated to the segments. The financial results of BJ Services are included in each of the five reportable segments from the date of acquisition forward; therefore, the summarized financial information below does not include BJ Services financial results for the three months ended March 31, 2010.

     Summarized financial information is shown in the following table:

	Three Months Ended					Three Months Ended
	March 31, 2011					March 31, 2010
Segments	Revenues		Profit (loss)			Revenues		Profit (loss)
North America	$	2,352	$	460		$	919	$	141
Latin America		473		63			272		9
Europe/Africa/Russia Caspian		771		91			720		80
Middle East/Asia Pacific		659		79			439		30
Industrial Services and Other		270		14			189		17
Total Oilfield Operations		4,525		707			2,539		277
Corporate and Other		—		(119	)		—		(83	)
Total	$	4,525	$	588		$	2,539	$	194

7

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

NOTE 4. STOCK-BASED COMPENSATION

     We grant various forms of equity based awards to directors, officers and other key employees. These equity based awards consist primarily of stock options, restricted stock awards and restricted stock units. The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes option pricing model. The fair value of restricted stock awards and units is based on the market price of our common stock on the date of grant. We also offer an Employee Stock Purchase Plan (“ESPP”) which provides for eligible employees to purchase shares on an after-tax basis at a 15% discount of the fair market value of our common stock, at a prescribed measurement date.

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

	Three Months Ended
	March 31,
	2011		2010
Stock Options	$	10	$	7
Restricted Stock Awards and Units		14		10
ESPP		5		2
Total	$	29	$	19

NOTE 5. EARNINGS PER SHARE

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

	Three Months Ended
	March 31,
	2011		2010
Weighted average common shares outstanding for basic EPS		435		313
Effect of dilutive securities — stock plans		2		—
Adjusted weighted average common shares outstanding for diluted EPS		437		313
Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than the average market price for the period		3		2

NOTE 6. INVENTORIES

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

	March 31,		December 31,
	2011		2010
Finished goods	$	2,466	$	2,283
Work in process		199		181
Raw materials		140		130
Total	$	2,805	$	2,594

NOTE 7. PROPERTY, PLANT AND EQUIPMENT

     Property, plant and equipment are comprised of the following:

	March 31,		December 31,
	2011		2010
Land	$	191	$	191
Buildings and improvements		1,673		1,605
Machinery and equipment		6,600		6,409
Rental tools and equipment		2,568		2,472
Subtotal		11,032		10,677
Less: Accumulated depreciation		4,600		4,367
Total	$	6,432	$	6,310

8

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

NOTE 8. GOODWILL AND INTANGIBLE ASSETS

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

						Europe/		Middle			Industrial
						Africa/		East/			Services
	North		Latin			Russia		Asia			and
	America		America			Caspian		Pacific			Other		Total
Balance as of December 31, 2010	$	2,731	$	879		$	936	$	895		$	428	$	5,869
Purchase price adjustments for previous acquisitions		313		(293	)		86		(42	)		8		72
Other adjustments		1		—			1		—			—		2
Balance as of March 31, 2011	$	3,045	$	586		$	1,023	$	853		$	436	$	5,943

     Intangible assets are comprised of the following:

	March 31, 2011						December 31, 2010
	Gross		Less:				Gross		Less:
	Carrying		Accumulated				Carrying		Accumulated
	Amount		Amortization		Net		Amount		Amortization		Net
Definite lived intangibles:
Technology	$	758	$	193	$	565	$	760	$	181	$	579
Contract-based		19		12		7		20		11		9
Trade names		84		20		64		84		18		66
Customer relationships		495		46		449		495		39		456
Subtotal		1,356		271		1,085		1,359		249		1,110
Indefinite lived intangibles:
Trade name		360		—		360		360		—		360
IPR&D		96		—		96		99		—		99
Total	$	1,812	$	271	$	1,541	$	1,818	$	249	$	1,569

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

     Amortization expense for intangible assets included in net income for the three months ended March 31, 2011 was $22 million, and is estimated to be $98 million for fiscal year 2011. Estimated amortization expense for each of the subsequent five fiscal years is expected to be as follows: 2012 — $106 million; 2013 — $107 million; 2014 — $106 million; 2015 — $98 million; and 2016 — $95 million.

NOTE 9. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

     Our financial instruments include cash and cash equivalents and short-term investments, accounts receivable, accounts payable, debt, foreign currency forward contracts and interest rate swaps. Except as described below, the estimated fair value of such financial instruments at March 31, 2011 and December 31, 2010 approximates their carrying value as reflected in our consolidated condensed balance sheets. The fair value of our debt, foreign currency forward contracts and interest rate swaps has been estimated based on quoted period end market prices.

Short-term Investments

     During the year ended December 31, 2010, we purchased short-term investments consisting of U.S. Treasury Bills, which will mature in May 2011. These investments are classified as available-for-sale and are recorded at fair value, which approximates cost, at March 31, 2011 and at December 31, 2010 of $251 million and $250 million, respectively.

9

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

Debt

     The estimated fair value of total debt at March 31, 2011 and December 31, 2010, was $4,255 million and $4,298 million, respectively, which differs from the carrying amount of $3,841 million and $3,885 million, respectively, included in our consolidated condensed balance sheets.

Foreign Currency Forward Contracts

     We conduct our business in over 80 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 and, accordingly, we record the fair value of these contracts as of the end of our reporting period to our consolidated balance sheet with changes in fair value recorded in our consolidated statement of operations along with the change in fair value of the hedged item.

     We had outstanding foreign currency forward contracts with notional amounts aggregating $156 million to hedge exposure to currency fluctuations in various foreign currencies at March 31, 2011 and December 31, 2010. These contracts are designated and qualify as fair value hedging instruments. The fair value was determined using a model with Level 2 inputs including quoted market prices for contracts with similar terms and maturity dates.

Interest Rate Swaps

     We are subject to interest rate risk on our debt and investment of cash and cash equivalents arising in the normal course of our business, as we do not engage in speculative trading strategies. We maintain an interest rate management strategy, which primarily uses a mix of fixed and variable rate debt that is intended to mitigate the exposure to changes in interest rates in the aggregate for our investment portfolio. In addition, we are currently using interest rate swaps to manage the economic effect of fixed rate obligations associated with our senior notes so that the interest payable on the senior notes effectively becomes linked to variable rates. Our interest rate swaps are designated and each qualifies as a fair value hedging instrument. The fair value of our interest rate swaps was determined using a model with Level 2 inputs including quoted market prices for contracts with similar terms and maturity dates.

Fair Value of Derivative Instruments

     The fair values of derivative instruments included in our consolidated condensed balance sheets were as follows:

		Fair Value
		March 31,		December 31,
Derivative	Balance Sheet Location	2011		2010
Foreign Currency Forward Contracts	Other accrued liabilities	$	—	$	2
Interest Rate Swaps	Other assets	$	20	$	24

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

		Amount of Gain (Loss) Recognized in Income
		Three Months Ended March 31,
Derivative	Statement of Operations Location	2011			2010
Foreign Currency Forward Contracts	Marketing, general and administrative	$	(1	)	$	(5	)
Interest Rate Swaps	Interest expense	$	3		$	7

10

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

NOTE 10. INDEBTEDNESS

     At March 31, 2011, we had $1.7 billion of committed revolving credit facilities with commercial banks. These 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, 2011, we were in compliance with all of the facilities’ covenants. There were no direct borrowings under the committed credit facilities during the quarter ended March 31, 2011. We also have a commercial paper program under which we may issue up to $1.0 billion in commercial paper with maturity of no more than 270 days. To the extent we have outstanding commercial paper, our ability to borrow under the facilities is reduced. At March 31, 2011, we had no outstanding commercial paper.

NOTE 11. EMPLOYEE BENEFIT PLANS

     We have both funded and unfunded noncontributory defined benefit pension plans (“Pension Benefits”) covering certain employees primarily in the U.S., Canada, the U.K., Germany and several countries in the Middle East and Asia Pacific region. We also provide certain postretirement health care benefits (“other postretirement benefits”), through an unfunded plan, to substantially all U.S. employees who retire and have met certain age and service requirements.

     The components of net periodic cost (benefit) are as follows for the three months ended March 31:

	U.S. Pension Benefits						Non-U.S. Pension Benefits						Other Postretirement Benefits
	2011			2010			2011			2010			2011			2010
Service cost	$	9		$	8		$	2		$	1		$	2		$	2
Interest cost		5			6			8			5			2			3
Expected return on plan assets		(8	)		(7	)		(8	)		(4	)		—			—
Amortization of prior service cost (benefit)		—			—			—			—			(1	)		1
Amortization of net loss		2			3			1			1			—			—
Net periodic cost (benefit)	$	8		$	10		$	3		$	3		$	3		$	6

     We invest the plan assets of our U.S. and Non-U.S. pension plans in investments according to the policies developed by our investment committees. The following table presents the changes in the fair value of our U.S. and Non-U.S. pension plans’ assets using Level 3 unobservable inputs:

					Non-U.S.		Non-U.S.
	U.S. Property		Hedge		Property		Insurance
	Fund		Funds		Fund		Contracts		Total
Ending balance at December 31, 2010	$	14	$	—	$	19	$	16	$	49
Unrealized gains		—		2		1		—		3
Transfers from Level 2 to Level 3		—		96		—		—		96
Ending balance at March 31, 2011	$	14	$	98	$	20	$	16	$	148

     In January 2011, the U.S. pension plan purchased $96 million of shares in three hedge funds, which the Company deems to be Level 3 investments. These hedge funds take long and short positions in equities, fixed income securities, currencies and derivative contracts.

11

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

NOTE 12. 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. The accruals for losses are calculated by estimating losses for claims using historical claim data, specific loss development factors and other information as necessary.

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 $1.21 billion at March 31, 2011. None of the off-balance sheet arrangements either has, or is likely to have, a material effect on our consolidated condensed financial statements.

NOTE 13. STOCKHOLDERS’ EQUITY

			Capital
			in Excess
	Common		of			Retained			Accumulated Other			Noncontrolling
	Stock		Par Value			Earnings			Comprehensive Loss			Interest		Total
Balance, December 31, 2010	$	432	$	7,005		$	7,083		$	(420	)	$	186	$	14,286
Purchase of subsidiary shares for noncontrolling interests				(1	)										(1	)
Comprehensive income:
Net income							381						3
Foreign currency translation adjustments										66
Defined benefit pension plans, net of tax of $2										(1	)
Total comprehensive income															449
Issuance of common stock pursuant to employee stock plans		2		52											54
Tax provision on stock plans				5											5
Stock-based compensation				29											29
Cash dividends ($0.15 per share)							(65	)							(65	)
Change in noncontrolling interest associated with purchase price adjustment													66		66
Balance, March 31, 2011	$	434	$	7,090		$	7,399		$	(355	)	$	255	$	14,823

			Capital
			in Excess
	Common		of			Retained			Accumulated Other			Noncontrolling
	Stock		Par Value			Earnings			Comprehensive Loss			Interest		Total
Balance, December 31, 2009	$	312	$	874		$	6,512		$	(414	)	$	—	$	7,284
Comprehensive income:
Net income							129
Foreign currency translation adjustments										(44	)
Defined benefit pension plans, net of tax of $3										9
Total comprehensive income															94
Issuance of common stock pursuant to employee stock plans				(5	)										(5	)
Tax provision on stock plans				2											2
Stock-based compensation				19											19
Cash dividends ($0.15 per share)							(47	)							(47	)
Balance, March 31, 2010	$	312	$	890		$	6,594		$	(449	)	$	—	$	7,347

12

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

     Total accumulated other comprehensive loss consisted of the following:

	March 31,			December 31,
	2011			2010
Foreign currency translation adjustments	$	(195	)	$	(261	)
Pension and other postretirement benefits		(160	)		(159	)
Total accumulated other comprehensive loss	$	(355	)	$	(420	)

13

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, 2010 (“2010 Annual Report”).

EXECUTIVE SUMMARY

     Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry. We provide:

• products and services for drilling and evaluation of oil and gas wells;

• products and services for completion and production of oil and gas wells; and

• industrial and other services including downstream refining, and process and pipeline industries, and reservoir technology and consulting services.

     The primary driver of our businesses 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, economic growth, hydrocarbon demand and estimates of current and future oil and natural gas production.

     For the first quarter of 2011, we generated revenues of $4.53 billion, an increase of $1.99 billion or 78% compared to the same quarter a year ago. Our North America revenues for the first quarter of 2011 were $2.35 billion, an increase of 156% compared to the first quarter of 2010. Revenues outside of North America were $1.90 billion, an increase of 33% compared to the first quarter of 2010. Industrial Services and Other revenues were $270 million, an increase of 43% compared to the first quarter of 2010. These increases in revenues were primarily due to the acquisition of BJ Services during the second quarter of 2010, which provided revenues of $1.62 billion for the first quarter of 2011; and the strength of the North America segment driven by oil-directed drilling primarily in unconventional reservoirs.

     Net income attributable to Baker Hughes was $381 million for the first quarter of 2011, compared to $129 million for the same quarter a year ago. The increase is primarily due to the acquisition of BJ Services, which provided $109 million of net income in the first quarter of 2011, improved profitability in North America, and to a lesser extent, improved profitability internationally.

     At March 31, 2011, Baker Hughes had approximately 53,700 employees compared to approximately 53,100 employees at December 31, 2010.

BUSINESS ENVIRONMENT

     Global economic growth and the resultant demand for oil and natural gas are the primary drivers of our customers’ expenditures to develop and produce oil and gas. The expansion of the global economy following the recession of 2008/2009 continued through 2010 and into 2011. Increasing economic activity, particularly in the emerging economies in Asia and the Middle East, and expectations for continued economic growth supported expectations for increasing demand for oil and natural gas. Spending by oil and natural gas exploration and production companies, which is dependent upon their forecasts regarding the expected future supply and future demand for oil and natural gas products and their estimates of costs to find, develop, and produce reserves, increased in the first quarter of 2011 compared to the first quarter of 2010. Changes in oil and natural gas exploration and production spending result in increased demand for our products and services, which is reflected in the rig count and other measures.

     In North America, customer spending on oil projects increased, resulting in a 71% increase in the North America oil-directed rig count in the first quarter of 2011 compared to the same period a year ago. The increase in oil-directed drilling reflected the global price of oil, which is trading at a premium, on a Btu-equivalent basis, relative to natural gas in North America. Gas-directed drilling activity was unchanged as increased activity in the unconventional shale gas plays with relatively high volumes of associated natural gas liquids (wet gas), was offset by decreased activity in unconventional shale gas plays with relatively little associated natural gas liquids (dry gas). Spending on gas-directed projects in the first quarter of 2011 was supported by: (1) hedges on production made in prior periods when future prices were higher; (2) the need to drill and produce natural gas to hold leases acquired in earlier periods; (3) the influx of equity from companies interested in developing a position in the shale resource plays; and (4) associated production of natural gas liquids in certain basins.

14

     Outside of North America, customer spending is most heavily influenced by oil prices, which increased 37% in the first quarter of 2011 compared to the first quarter of 2010, as the economic recovery continued. In response to higher oil prices and expectations that the expanding economy would support prices well in excess of $70/Bbl, our customers’ spending increased. This was reflected in a 10% increase in the rig count outside North America.

Oil and Natural Gas Prices

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

	Three Month Ended March 31,
	2011		2010
WTI oil prices ($/Bbl)	$	94.60	$	78.84
Brent oil prices ($/Bbl)		105.21		76.78
Natural gas prices ($/mmBtu)		4.20		5.09

     Brent oil prices averaged $105.21/Bbl in the first quarter of 2011. Prices ranged from a low of $92.98/Bbl in January 2011 to a high of $117.25/Bbl in March 2011. Brent is expected to be a better 2011 benchmark crude indicator than WTI, as structural restrictions in Cushing, Oklahoma have caused WTI to sell at a significant discount (approximately $14/Bbl) to Brent. Oil prices strengthened throughout the first quarter of 2011, driven by expectations of worldwide economic recovery and energy demand growth, particularly in Asia and the Middle East. Temporary disruptions to oil supplies in the Middle East and North Africa, and the cessation of oil exports from Libya, also contributed to the rise in oil prices.

     Natural gas prices averaged $4.20/mmBtu, and traded in a range between $3.78/mmBtu and $4.74/mmBtu, in the first quarter of 2011. At the end of the first quarter of 2011, working natural gas in storage was 1,624 Bcf, which was 1% or 14 Bcf below the corresponding week in 2010.

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 active international areas where better data is available, we compute a weekly or daily average of active rigs. In some international areas, rigs are counted as active if drilling operations have taken place for at least 15 days during the month. 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.

15

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

	Three Months Ended				%
	March 31,				Increase
	2011		2010		(Decrease)
U.S. — land and inland waters		1,691		1,300		30	%
U.S. — offshore		26		46		(43	)%
Canada		587		469		25	%
North America		2,304		1,815		27	%
Latin America		410		378		8	%
North Sea		44		43		2	%
Continental Europe		74		45		64	%
Africa		82		80		3	%
Middle East		283		260		9	%
Asia Pacific		273		257		6	%
Outside North America		1,166		1,063		10	%
Worldwide		3,470		2,878		21	%

First Quarter of 2011 Compared to the First Quarter of 2010

     The rig count in North America increased 27% reflecting, in the U.S., an 80% increase in the oil-directed rig count and a 2% increase in the gas-directed rig count; and in Canada, a 57% increase in the oil-directed rig count and a 14% decrease in the gas-directed rig count. Outside North America, the rig count increased 10%. The rig count in Latin America increased primarily due to higher activity in the Andean geomarket (Colombia, Peru and Ecuador) and in Venezuela, partially offset by lower activity in Mexico. The increase in the Continental Europe geomarket was led by Turkey, Poland, Romania, Hungary and Germany. The rig count in Africa increased primarily due to higher activity in Algeria, Nigeria, Gabon and Ghana, partially offset by a decline in Libya, where activity ceased in March 2011 due to civil unrest. The rig count increased in the Middle East due to higher activity in Syria, Kuwait and Egypt, partially offset by declines in activity in Pakistan, Oman and Saudi Arabia. In the Asia Pacific region, activity increased primarily in India and Indonesia.

RESULTS OF OPERATIONS

     The discussions below relating to significant line items from our consolidated condensed statements of operations are based on available information and represent our analysis of significant changes or events that impact the comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect comparability or trends and, where possible and practical, have quantified the impact of such items. We acquired BJ Services on April 28, 2010; therefore, our results of operations for the first quarter of 2010 do not include BJ Services. In addition, the discussions below for revenues and cost of revenues are on a total basis as the business drivers for the individual components of product sales and services are similar. All dollar amounts in tabulations in this section are in millions of dollars, unless otherwise stated.

Revenues and Profit Before Tax

     The performance of our segments is evaluated based on segment profit before tax, which is defined as income before income taxes, interest expense, interest income, and certain gains and losses not allocated to the segments.

16

First Quarter of 2011 Compared to the First Quarter of 2010

	Three Months Ended
	March 31,
					Increase
	2011		2010		(decrease)		% Change
Revenues:
North America	$	2,352	$	919	$	1,433		156	%
Latin America		473		272		201		74	%
Europe/Africa/Russia Caspian		771		720		51		7	%
Middle East/Asia Pacific		659		439		220		50	%
Industrial Services and Other		270		189		81		43	%
Total	$	4,525	$	2,539	$	1,986		78	%

	Three Months Ended
	March 31,
					Increase
	2011		2010		(decrease)			% Change
Profit Before Tax:
North America	$	460	$	141	$	319			226	%
Latin America		63		9		54			600	%
Europe/Africa/Russia Caspian		91		80		11			14	%
Middle East/Asia Pacific		79		30		49			163	%
Industrial Services and Other		14		17		(3	)		(18	)%
Total	$	707	$	277	$	430			155	%

     Revenues for the first quarter of 2011 increased $1.99 billion or 78% compared to the first quarter of 2010. Excluding BJ Services, revenues were up 15%. The primary drivers of the change included increased activity and improved pricing in the U.S. Land and Canada markets and to a lesser extent, increased activity in our international segments.

     Profit before tax for the first quarter of 2011 increased $430 million or 155% compared to the first quarter of 2010. Excluding BJ Services, profit before tax was up 68% primarily due to strong activity in the North America segment where increased activity has led to increased utilization, improved absorption of manufacturing and other overhead costs, and realized pricing improvement, and to a lesser extent, higher profits in the Latin America and Middle East Asia Pacific segments as a result of cost management, improvements in operational efficiency and improved absorption of fixed costs.

North America

     North America revenues increased 156% in the first quarter of 2011 compared with the first quarter of 2010. Excluding BJ Services, revenues increased 29%. Revenues and pricing increases were supported by a 30% increase in the U.S. land and inland waters rig count and a 25% increase in the Canada rig count. The unconventional reservoirs are demanding our best technology to deliver longer horizontals, complex completions, increasing hydraulic fracturing (“frac”) horsepower and more frac stages resulting in improved pricing and higher revenues. This improvement was partially offset by a decline in our U.S. Gulf of Mexico revenues directly attributable to the slow pace of re-permitting in the Gulf of Mexico following the lifting of the drilling moratorium.

     North America profit before tax increased 226% in the first quarter of 2011 compared with the first quarter of 2010. Excluding BJ Services, profit before tax increased 74%. In addition to increased revenues, the primary drivers included improved tool utilization, improved absorption of manufacturing and other overhead, and higher pricing. This improvement was partially offset by a decline in our profitability in the U.S. Gulf of Mexico directly attributable to the slow pace of re-permitting in the Gulf of Mexico following the lifting of the drilling moratorium.

Latin America

     Latin America revenues increased 74% in the first quarter of 2011 compared with the first quarter of 2010. Excluding BJ Services, revenues increased 24%. The primary drivers included increased activity and commensurate revenue increases for drilling systems in the Brazil geomarket, artificial lift in the Venezuela /Mexico geomarket, and drilling fluids in the Andean geomarket.

     Latin America profit before tax increased 600% in the first quarter of 2011 compared to the first quarter of 2010. Excluding BJ Services, profit before tax increased 500%. Improved profit before tax from directional drilling systems in the Brazil geomarket and from artificial lift in the Venezuela/Mexico geomarket were the primary drivers of improved profitability in addition to increased revenues.

17

Europe/Africa/Russia Caspian

     Europe/Africa/Russia Caspian revenues increased 7% in the first quarter of 2011 compared to the first quarter of 2010. Excluding BJ Services, revenues decreased 8%. The primary drivers of the decrease were project completions since the first quarter of 2010 in the Africa region, civil unrest in the North Africa geomarket, in particular Libya where our operations have currently ceased, pending resolution of the conflict, and weather delays in the Norway geomarket. These decreases were offset by general activity increases in the Russia Caspian region and the Continental Europe geomarket.

     Europe/Africa/Russia Caspian profit before tax increased 14% in the first quarter of 2011 compared to the first quarter of 2010. Excluding BJ Services, profit before tax increased 9%. Improved profit before tax in the Russia Caspian and Europe regions on higher activity were partially offset by lower profits in the Africa region attributable to project completions and civil unrest in the North Africa geomarket.

Middle East/Asia Pacific

     Middle East/Asia Pacific revenues increased 50% in the first quarter of 2011 compared to the first quarter of 2010. Excluding BJ Services, revenues increased 21%. The increase in this segment was driven by higher revenues attributable to higher activity and share gains from the Saudi Arabia, Gulf, and Iraq geomarkets. Asia Pacific revenues were essentially unchanged.

     Middle East/Asia Pacific profit before tax increased 163% in the first quarter of 2011 compared to the first quarter of 2010. Excluding BJ Services, profit before tax increased 133%. The improvement in profit before tax was driven primarily by the increased revenues in the Saudi Arabia and Gulf geomarkets.

Industrial Services and Other

     Industrial Services and Other revenues increased 43% in the first quarter of 2011 compared to the first quarter of 2010. Excluding BJ Services, revenues increased 2%. Industrial Services and Other profit before tax decreased 18% or $3 million in the first quarter of 2011 compared to the first quarter of 2010. Excluding BJ Services, profit before tax decreased 41%.

Costs and Expenses

     The table below details certain consolidated condensed statement of operations data and their percentage of revenues.

	Three Months Ended
	March 31,
	2011				2010
Revenues	$	4,525	100	%	$	2,539	100	%
Cost of revenues		3,497	77	%		1,912	75	%
Research and engineering		106	2	%		94	4	%
Marketing, general and administrative		282	6	%		305	12	%

Cost of Revenues

     Cost of revenues as a percentage of revenues was 77% and 75% for the first quarter of 2011 and 2010, respectively. The increase was primarily due to the impacts of civil unrest in the North Africa geomarket, weather delays in the Norway geomarket, and incremental depreciation and amortization expense of $41 million for tangible and intangible assets associated with the BJ Services acquisition.

Research and Engineering

     Research and engineering expenses increased 13% for the first quarter of 2011 compared to the first quarter of 2010. The increase was primarily due to the acquisition of BJ Services in 2010. We continue to be committed to developing and commercializing new technologies as well as investing in our core product offerings.

Marketing, General and Administrative

     Marketing, general and administrative (“MG&A”) expenses decreased 8% for the first quarter of 2011 compared to the first quarter of 2010. Excluding BJ Services, MG&A for the first quarter of 2011 decreased by 23%. This decrease resulted primarily

18

from a reduction in costs associated with finance redesign efforts and software implementation activities, which were completed during 2010.

Interest Expense, net

     Net interest expense increased $28 million for the first quarter of 2011 compared to the first quarter of 2010. The increase was primarily due to the issuance of $1.5 billion of debt in August 2010 and the assumption of $500 million of debt associated with the acquisition of BJ Services.

Income Taxes

     Total income tax expense for the first quarter of 2011 was $204 million. Our effective tax rate on operating profits for the first quarter of 2011 was 34.7%, 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. Resolution of any tax matter involves uncertainties and there are no assurances that the outcomes will be favorable.

OUTLOOK

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

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

     The primary drivers impacting the 2011 business environment include: (1) the depth and pace of economic recovery from the 2008/2009 global economic recession; (2) the negative impact of sustained oil prices over $100/Bbl on economic growth and oil demand; (3) the potential for additional geopolitical disruption in the oil exporting countries in North Africa and the Middle East, and its impact on spare production capacity; (4) the pace of re-permitting in the Gulf of Mexico; (5) the resolution of fiscal issues facing national governments; and (6) China’s efforts to address inflation and its economic growth.

     As the worldwide economy recovers, demand for hydrocarbons is increasing. In its April 2011World Economic Outlook, the International Monetary Fund (“IMF”) forecasted that global output would increase 4.4% in 2011 compared to 2010. Advanced economies’ economic growth is expected to remain sluggish at 2.4% in 2011 compared to 2010, while emerging and developing economies are expected to grow at 6.5% in 2011 compared to 2010. The IMF also noted that the downside risks to the recovery were elevated, primarily due to sovereign and financial troubles with the Euro area, and policies to redress fiscal imbalances in the advance economies in general. The IMF also said that oil price increases recognized since January 2011, and the disruptions in oil supply would have only mild effects on economic activity. The earthquake in Japan in March 2011 was expected to have little macroeconomic impact.

     The International Energy Agency (“IEA”) estimated in its April 2011 Oil Market Report that worldwide demand would increase 1.5 million barrels per day or 1.6% to 89.4 million barrels per day in 2011, up from 87.9 million barrels per day in 2010. The largest incremental demand for oil is expected to be generated by the developing and emerging economies in Asia, the Middle East and Latin America. While oil prices are expected to remain above $100/Bbl, they are close to levels that could slow the global economic recovery and negatively impact incremental oil demand.

     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

19

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 theShort Term Energy Outlook(“STEO”) published by the Energy Information Administration of the U.S. Department of Energy (“DOE”), theOil Market Reportpublished by the IEA and theMonthly Oil Market Reportpublished by 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 IMF, the Organization for Economic Cooperation and Development (“OECD”) and the World Bank.

     In North America, the near-month futures prices for natural gas, as quoted in April 2011 for May 2011, were approximately $4.30/mmBtu, and the twelve months futures were trading at approximately $4.60/mmBtu. Higher natural gas futures prices in 2008 and early 2009 provided an opportunity for many of our customers to hedge natural gas production. Cash flow of these customers benefited from the attractive prices received on hedged production allowing them to maintain exploration and development activity. However, the decline in natural gas prices in 2010 and the roll-off of attractive hedge positions is placing increased emphasis on well economics, cash flow and capital budgets for many of our customers. In the near-term, the impact of lower cash flows from sales and hedging activity is being offset by investments by international oil companies seeking exposure to the U.S. shale plays. In addition, project economics will be favorably impacted if the production is expected to include a significant amount of natural gas liquids or condensates, which can be sold at a higher price per mmBtu. Capital discipline on the part of our competitors, attrition of existing rental fleets and rising demand are expected to result in an environment that supports continued price increases for our products and services in some markets.

     The impact of changes in the regulation of offshore drilling in the U.S. Gulf of Mexico continues to negatively impact the U.S. offshore drilling activity. Less than one-third of the deepwater rigs permitted at the time of the moratorium being enacted have been re-permitted and none have resumed work. Some equipment and people deployed to more active areas have now been redeployed to the Gulf of Mexico in anticipation of resumption of deepwater drilling. The negative impact is expected to be partially offset by incremental spending in other regions and on the Gulf of Mexico shelf as oil and gas companies adjust their spending plans.

     In North America, the outlook for 2011 will be significantly influenced by the outlook for both the oil and natural gas industry. Oil-directed rig activity has increased to levels not seen since early 1991, and is expected to continue to increase with oil prices greater than $70/Bbl, as many operators seek to diversify activity away from natural gas. The increase in gas-directed rig count from mid-2009 low levels and continued advances in horizontal drilling and advanced fracturing and completion technologies has led to increasing rates of initial production in the unconventional gas fields, resulting in high levels of gas production relative to demand. The gas rig count was essentially unchanged in the first quarter of 2011 as the increase in drilling in wet gas plays almost offset the decline in drilling in dry gas plays.

     Expectations for Oil Prices- Due to expectations for the continued global economic expansion, the Energy Information Administration (“EIA”) in its April 2011 Short Term Energy Outlook (STEO) said that it expects global demand for oil to increase 1.5 million barrels per day in 2011 relative to 2010. Non-OPEC supply growth is expected to increase by 550 thousand barrels per day in 2011 as forecasted by the EIA. In its December 2010 meeting in Quito, Ecuador, OPEC left its production policy unchanged. In its April 2011 STEO report, the DOE forecasted WTI oil prices to average $106/Bbl for the year 2011. In early April 2011, WTI oil prices, which normally trade at a premium to Brent oil prices, were trading at a significant discount (approximately $14/Bbl). The structural causes of this difference are expected to exist through the end of 2012.

     Expectations for North America Natural Gas Prices —Increasing production and near record high storage levels are placing downward pressure on natural gas prices. Storage is expected to remain at or near historically high levels throughout the year. In its April 2011 STEO the EIA forecasted Henry Hub natural gas prices to average $4.10/mmBtu for 2011.

     Our capital expenditures, excluding acquisitions, are expected to be between $2.3 billion and $2.7 billion for 2011. A significant portion of our planned capital expenditures can be adjusted to reflect changes in our expectations for future customer spending. We will manage our capital expenditures to match market demand.

20

LIQUIDITY AND CAPITAL RESOURCES

     Our objective in financing our business is to maintain adequate financial resources and access to sufficient liquidity. At March 31, 2011, we had cash and cash equivalents of $1.14 billion, short-term investments of $251 million, and $1.7 billion available for borrowing under committed revolving credit facilities with commercial banks.

     Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of our company. In the three months ended March 31, 2011, we used cash to pay for a variety of activities including working capital needs, dividends and capital expenditures.

Cash Flows

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

	2011			2010
Operating activities	$	76		$	5
Investing activities		(356	)		(145	)
Financing activities		(40	)		174

     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 cash of $76 million and $5 million in the three months ended March 31, 2011 and 2010, respectively. This increase in cash flows of $71 million was primarily due to an increase in net income of $255 million partially offset by a change in net operating assets and liabilities, which used more cash in the three months ended March 31, 2011 compared to the same period in 2010.

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

• An increase in accounts receivable used cash of $398 million and $154 million in the first quarter of 2011 and 2010, respectively. The change in accounts receivable was primarily due to an increase in activity and an increase in the days sales outstanding (defined as the average number of days our net trade receivables are outstanding based on quarterly revenues) of approximately 5 days.

• Inventory used cash of $186 million and $47 million in the first quarter of 2011 and 2010, respectively, driven by increases in activity.

• An increase in accounts payable provided cash of $34 million and $56 million in the first quarter of 2011 and 2010, respectively. The increase was primarily due to an increase in operating assets to support increased activity.

Investing Activities

     Our principal recurring investing activity was the funding of capital expenditures to ensure that we have the appropriate levels and types of rental tools and machinery and equipment in place to generate revenues from operations. Expenditures for capital assets totaled $429 million and $190 million in the three months ended March 31, 2011 and 2010, respectively. While the majority of these expenditures were for rental tools and machinery and equipment, we have continued our spending on new facilities, expansions of existing facilities and other infrastructure projects.

     Proceeds from the disposal of assets were $75 million and $45 million in the three months ended March 31, 2011 and 2010, respectively. These disposals related to rental tools which were lost-in-hole, as well as machinery, rental tools and equipment no longer used in operations which were sold throughout the period.

Financing Activities

     We had net repayments of commercial paper and other short-term debt of $36 million compared to net borrowings of $218 million in the three months ended March 31, 2011 and 2010, respectively. Total debt outstanding at March 31, 2011 was $3.84 billion, and

21

$3.89 billion at December 31, 2010. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was 21% at March 31, 2011 and December 31, 2010.

     We received proceeds of $57 million and $2 million in the three months ended March 31, 2011 and 2010, respectively, from the issuance of common stock through the exercise of stock options.

     Our Board of Directors has authorized a program to repurchase our common stock from time to time. In the three months ended March 31, 2011 and 2010, we did not repurchase shares of our common stock. At March 31, 2011, we had authorization remaining to repurchase up to a total of $1.2 billion of our common stock.

     We paid dividends of $65 million and $47 million in the three months ended March 31, 2011 and 2010, respectively.

Available Credit Facilities

     At March 31, 2011, we had $1.7 billion of committed revolving credit facilities with commercial banks. These 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, 2011, we were in compliance with all of the facilities’ covenants. There were no direct borrowings under the committed credit facilities during the quarter ended March 31, 2011. We also have a commercial paper program under which we may issue up to $1.0 billion in commercial paper with maturity of no more than 270 days. To the extent we have outstanding commercial paper our ability to borrow under the facilities is reduced. At March 31, 2011, 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 our 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 current credit ratings 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 2011, we believe cash on hand and operating cash flows will provide us with sufficient capital resources and liquidity to manage our working capital needs, meet contractual obligations, fund capital expenditures, and support the development of our short-term and long-term operating strategies. We may issue commercial paper or other short-term debt to fund cash needs in the U.S. in excess of the cash generated in the U.S.

     In 2011, we expect capital expenditures to be between $2.3 billion and $2.7 billion, excluding any amount related to 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 will manage our capital expenditures to match market demand.

     In 2011, we expect to make interest payments of between $215 million and $225 million, based on our current expectations of debt levels. We currently have $251 million of U.S. Treasury Bills which will mature in May 2011, and will be used to repay the $250 million principal amount of 5.75% senior notes maturing in June 2011. We also anticipate making income tax payments of between $1.1 billion and $1.2 billion in 2011.

     We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. We anticipate paying dividends of between $260 million and $270 million in 2011; however, the Board of Directors can change the dividend policy at any time.

     For all pension plans, we make annual contributions to the plans in amounts equal to or greater than amounts necessary to meet minimum governmental funding requirements. In 2011, we expect to contribute between $65 million and $85 million to our defined

22

benefit pension plans. We also expect to make benefit payments related to postretirement welfare plans of between $16 million and $18 million, and we estimate we will contribute between $185 million and $200 million to our defined contribution plans.

FORWARD-LOOKING STATEMENTS

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

     All of our forward-looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. 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 2010 Annual Report, this filing and those set forth from time to time in our filings with the SEC. These documents are available through our web site or through the SEC’s Electronic Data Gathering and Analysis Retrieval System (“EDGAR”) at http://www.sec.gov.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     We conduct operations around the world in a number of different currencies. 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, 2011, we had outstanding foreign currency forward contracts with notional amounts aggregating $156 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 the contracts outstanding at March 31, 2011, based on quoted market prices as of March 31, 2011, for contracts with similar terms and maturity dates, was nominal, and was included in other assets in the consolidated condensed balance sheet. The effect of foreign currency forward contracts on the consolidated condensed statement of operations for the three months ended March 31, 2011 was $1 million of foreign exchange losses, which were included in marketing, general and administrative expenses. These losses offset designated foreign exchange gains resulting from the underlying exposures of the hedged items.

Interest Rate Swaps

     We are subject to interest rate risk on our debt and investment of cash and cash equivalents arising in the normal course of our business, as we do not engage in speculative trading strategies. We maintain an interest rate management strategy, which primarily uses a mix of fixed and variable rate debt that is intended to mitigate the exposure to changes in interest rates in the aggregate for our investment portfolio. In addition, we are currently using interest rate swaps to manage the economic effect of fixed rate obligations associated with our senior notes so that the interest payable on the senior notes effectively becomes linked to variable rates. Our interest rate swaps are designated and each qualifies as a fair value hedging instrument. The fair value of our interest rate swaps was determined using a model with Level 2 inputs including quoted market prices for contracts with similar terms and maturity dates. The fair value of the swap agreements at March 31, 2011, was $20 million and was included in other assets in the consolidated condensed balance sheet. The effect of interest rate swaps on the consolidated condensed statement of operations for the three months ended March 31, 2011 was a reduction in interest expense of $3 million.

23

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, 2011, 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, 2011 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 12 of Notes to Unaudited Consolidated Condensed Financial Statements.

     For additional discussion of legal proceedings see also, “Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Outlook” of this Form 10-Q, Item 3 of Part I of our 2010 Annual Report and Note 14 of the Notes to the Consolidated Financial Statements included in Item 8 of our 2010 Annual Report.

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 2010 Annual Report as well as the following risk factor:

Our business is subject to geopolitical, terrorism risks and other threats.

     Geopolitical and terrorism risks continue to grow in several key countries where we do business. Geopolitical and terrorism risks could lead to, among other things, a loss of our investment in the country, impair the safety of our employees and impair our ability to conduct our operations. During the first quarter of 2011, there was political unrest in North Africa, and in particular Libya, where our operations have currently ceased pending resolution of the conflict. We have assets in Libya consisting primarily of accounts receivable, inventory and property, plant and equipment totaling approximately $160 million as of March 31, 2011.

24

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, 2011.

Issuer Purchases of Equity Securities

					Total						Maximum
					Number of						Number (or
					Shares				Total		Approximate
					Purchased				Number of		Dollar Value) of
					as Part of a				Shares		Shares that May
	Total Number		Average		Publicly		Average		Purchased		Yet Be
	of Shares		Price Paid		Announced		Price Paid		in the		Purchased Under
Period	Purchased(1)		Per Share(1)		Program(2)		Per Share(2)		Aggregate		the Program(3)
January 1-31, 2011		199,905	$	58.82		—	$	—		199,905	$	—
February 1-28, 2011		3,323		70.03		—		—		3,323		—
March 1-31, 2011		513		68.97		—		—		513		—
Total		203,741	$	59.03		—	$	—		203,741	$	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, 2011.
(3)	Our Board of Directors has authorized a plan to repurchase our common stock from time to time. During the first quarter of 2011, we did not repurchase shares of our common stock. We had authorization remaining to repurchase up to a total of approximately $1.2 billion of our common stock.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

     None.

ITEM 4. [REMOVED AND RESERVED]

ITEM 5. OTHER INFORMATION

     Our barite mining operations, in support of our drilling fluids products and services business, are subject to regulation by the federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and the recently proposed Item 106 of Regulation S-K (17 CFR 229.106) is included in Exhibit 99.1 to this quarterly report.

ITEM 6. EXHIBITS

     Each exhibit identified below is filed as a part of this report. Exhibits designated with an “*” are filed as an exhibit to this Quarterly Report on Form 10-Q. Exhibit designated with a “+” is identified as a compensatory arrangement.

10.77+*	Compensation Table for Named Executive Officers and Directors.
31.1*	Certification of Chad C. Deaton, Chief Executive Officer, furnished 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, furnished 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, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.
99.1*	Mine Safety Disclosure.
**101.INS	XBRL Instance Document

25

**101.SCH	XBRL Schema Document
**101.CAL	XBRL Calculation Linkbase Document
**101.LAB	XBRL Label Linkbase Document
**101.PRE	XBRL Presentation Linkbase Document
**101.DEF	XBRL Definition Linkbase Document
**      Furnished with this Form 10-Q, not filed

26

SIGNATURES

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

	BAKER HUGHES INCORPORATED (Registrant)
Date: May 3, 2011	By:	/s/ PETER A. RAGAUSS
		Peter A. Ragauss
		Senior Vice President and Chief Financial Officer
Date: May 3, 2011	By:	/s/ ALAN J. KEIFER
		Alan J. Keifer
		Vice President and Controller

27