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 September 30, 2010~~FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2011


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

Commission File Number 1-9397

Baker Hughes Incorporated

(Exact name of registrant as specified in its charter)


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

2929 Allen Parkway, Suite 2100, Houston, Texas		~~77019-2118~~
(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 ~~November 2, 2010,~~April 26, 2011, the registrant has outstanding ~~431,273,706~~434,634,726 shares of Common Stock, $1 par value per share.

Baker Hughes Incorporated

Consolidated Condensed Balance Sheets

(In millions)
~~(Unaudited)~~

September 30, December 31,
2010 2009

ASSETS

Current Assets:
Cash and cash equivalents $ 1,606 $ 1,595
Short-term investments 250 —
Accounts receivable — less allowance for doubtful accounts (2010 - $165; 2009 - $157) 3,763 2,331
Inventories, net 2,509 1,836
Deferred income taxes 285 268
Other current assets 297 195

Total current assets 8,710 6,225

Property, plant and equipment, net 6,108 3,161
Goodwill 5,714 1,418
Intangible assets, net 1,512 195
Other assets 418 440

Total assets $ 22,462 $ 11,439

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Accounts payable $ 1,371 $ 821
Short-term borrowings and current portion of long-term debt 291 15
Accrued employee compensation 849 448
Income taxes payable 25 95
Other accrued liabilities 500 234

Total current liabilities 3,036 1,613

Long-term debt 3,555 1,785
Deferred income taxes and other tax liabilities 1,387 309
Liabilities for pensions and other postretirement benefits 525 379
Other liabilities 202 69
Commitments and contingencies

Stockholders’ Equity:
Common stock 431 312
Capital in excess of par value 6,949 874
Retained earnings 6,814 6,512
Accumulated other comprehensive loss (437 ) (414 )

Total stockholders’ equity 13,757 7,284

Total liabilities and stockholders’ equity $ 22,462 $ 11,439

(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.

Baker Hughes Incorporated

Consolidated Condensed Statements of Cash Flows

(In millions)
~~(Unaudited)~~

Nine Months Ended
September 30,
2010 2009

Cash flows from operating activities:
Net income $ 477 $ 337
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization 743 532
Stock-based compensation costs 66 68
Benefit for deferred income taxes (155 ) (165 )
Gain on disposal of assets (79 ) (57 )
Provision for doubtful accounts 19 71
Changes in operating assets and liabilities:
Accounts receivable (504 ) 530
Inventories (161 ) 104
Accounts payable 177 (245 )
Accrued employee compensation and other accrued liabilities 97 (96 )
Income taxes payable (68 ) (211 )
Other (34 ) 19

Net cash flows from operating activities 578 887

Cash flows from investing activities:
Expenditures for capital assets (1,005 ) (794 )
Proceeds from disposal of assets 152 134
Proceeds from sale of businesses, net of disposition costs 39 —
Acquisition of businesses, net of cash acquired (852 ) (48 )
Purchase of short-term investments (250 ) —

Net cash flows from investing activities (1,916 ) (708 )

Cash flows from financing activities:
Net proceeds (payments) of commercial paper and other short-term debt 9 (8 )
Net proceeds of long-term debt 1,479 —
Repayment of long-term debt — (525 )
Proceeds from issuance of common stock 29 1
Dividends (175 ) (139 )
Excess tax benefits from stock-based compensation 2 —

Net cash flows from financing activities 1,344 (671 )

Effect of foreign exchange rate changes on cash 5 24

Increase (decrease) in cash and cash equivalents 11 (468 )
Cash and cash equivalents, beginning of period 1,595 1,955

Cash and cash equivalents, end of period $ 1,606 $ 1,487

Supplemental cash flows disclosures:
Income taxes paid (net of refunds) $ 516 $ 523
Interest paid $ 96 $ 106
Supplemental disclosure of noncash investing activities:
Capital expenditures included in accounts payable $ 33 $ 13
(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.

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~~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, ~~2009~~2010 (“~~2009~~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.

~~New Accounting Standards~~

~~In October 2009, the Financial Accounting Standards Board (“FASB”) issued an update to Accounting Standards Codification (“ASC”) 605,~~~~Revenue Recognition — Multiple Deliverable Revenue Arrangements~~. This Accounting Standards Update (“ASU”) addresses accounting for multiple-deliverable arrangements to enable vendors to account for deliverables separately. The provision establishes a selling price hierarchy for determining the selling price of a deliverable. This update requires expanded disclosures for multiple deliverable revenue arrangements. The ASU will be effective for us for revenue arrangements entered into or materially modified on or after January 1, 2011. We have not determined the impact, if any, on our consolidated condensed financial statements.

NOTE 2. ACQUISITIONS

ACQUISITION OF BJ SERVICES

On April 28, 2010, we acquired 100% of the outstanding common stock of BJ Services Company ~~(including its successor “BJ~~(“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. ~~For the year ended September 30, 2009, BJ Services’ revenues were $4,122 million. They employed approximately 14,000 people and operated in over 50 countries. Revenues and net income~~Total consideration consisted of BJ Services from the acquisition date included in our consolidated condensed statement of operations for the three months ended September 30, 2010 were $1,403 million and $134 million, respectively, and for the nine months ended September 30, 2010 were $2,202 million and $164 million, respectively.

Pursuant to a final agreement with the Antitrust Division of the U.S. Department of Justice (“DOJ”) in connection with the governmental approval of the acquisition, we were required to divest two leased stimulation vessels (the~~HR Hughesand~~~~Blue Ray~~) and certain other assets used to perform sand control services in the U.S. Gulf of Mexico. Additionally, pursuant to a Hold Separate Stipulation and Order, the operation of our U.S. business and the U.S. business of BJ Services were required to be operated separately until these assets were divested. On August 30, 2010, we completed the sale of such assets for approximately $55 million in cash. Upon the completion of the sale, the Hold Separate Stipulation and Order terminated and we commenced to fully integrate BJ Services into Baker Hughes globally.

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

~~Consideration~~

Under the terms of the acquisition agreement, BJ Services stockholders received $2.69 per share in cash and 0.40035 Baker Hughes shares of common stock for each BJ Services share of common stock they owned. In total, we paid $793 million in cash, ~~and issued~~ 118 million shares valued at $6,048 million, ~~(based upon the closing price~~and Baker Hughes options with a fair value of ~~our common stock on the acquisition date of $51.24).~~$56 million in exchange for BJ Services options. We also assumed all outstanding stock options held by BJ Services employees and directors.

The BJ Services stock options outstanding at closing were converted into Baker Hughes options at the conversion ratio. The estimated fair value associated with the Baker Hughes options issued in exchange for the BJ Services options was $58 million based on a Black-Scholes valuation model. All BJ Services stock options became fully vested and exercisable in accordance with pre-existing change-in-control provisions. Accordingly, $56 million of the estimated fair value was recorded as part of the consideration transferred, with the remaining $2 million recorded as an expense as of the date of the acquisition when all options vested and no further service was required.

~~Total consideration transferred in acquiring BJ Services is summarized as follows:~~

Cash consideration paid: 295 million shares at $2.69 $ 793
Equity consideration paid: 118 million shares valued $51.24 6,048
Fair value of BJ Services options assumed 56

Fair value of consideration transferred $ 6,897

Recording of Assets Acquired and Liabilities Assumed

The transaction has been accounted for using the acquisition method of accounting ~~which requires that, among other things,~~and accordingly, assets acquired and liabilities assumed bewere recorded at their fair values as of the acquisition date. The excess of the consideration transferred over those fair values istotaling $4,406 million was recorded as goodwill. We have not finalized the determination of the fair values of the assets acquired and liabilities assumed and therefore, the fair values set forth below are subject to adjustment once the valuations are completed. We will finalize these items as we obtain the information necessary to complete the analysis, and we expect to be substantially complete with this analysis during the fourth quarter of 2010. Under U.S. GAAP, companies have one year after an acquisition to finalize the acquisition accounting. The following table summarizes the ~~provisional~~ amounts recognized for assets acquired and liabilities ~~assumed as of the acquisition date.~~assumed.


	Estimated Fair Value			Fair Values

Assets:
Cash and cash equivalents	$	113		$	113
Accounts receivable		954			951
Inventories		425			419
Other current assets		123			125
Property, plant and equipment		2,754			2,745
Intangible assets		1,333			1,404
Goodwill		4,192			4,406
Other long-term assets		36			109
Liabilities:
Liabilities for change in control and transaction fees		(212	)
Current liabilities		(649	)
Deferred income taxes and other tax liabilities		(1,419	)
Debt		(531	)
Pension and other postretirement liabilities		(146	)
Other long-term liabilities		(76	)

Net Assets Acquired	$	6,897

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 ~~$415~~$406 million was recorded to present the PP&E acquired at its ~~estimated~~ fair value. The ~~preliminary~~ weighted average useful life used to calculate depreciation of the step-up related to ~~PPE~~PP&E is approximately six years.

Intangible assets

We identified ~~other~~ intangible assets ~~associated with pressure pumping and other services,~~ 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. ~~We have not finalized the determination of the estimated useful lives and methods to be used in calculating the amortization expense related to these intangible assets.~~

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


	Estimated Fair Value		Estimated Useful Life	Fair Values		Useful Lives

Customer relationships	$	313	2-17 years	$	428	3-16 years
Technology		449	5-15 years		451	5-15 years
BJ Services trade name		383	Indefinite		360	Indefinite
Other trade names		41	5-12 years		38	5-12 years
IPR&D		147	6-14 years		127	Indefinite

Total Identifiable Intangible Assets	$	1,333
Total identifiable intangible assets				$	1,404

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

~~The following is a summary of the funded position of the assumed BJ Services plans as of the acquisition date, as well as associated weighted-average assumptions used to determine benefit obligations:~~

Other Postretirement
Pension Benefit Plans Benefit Plans

Projected benefit obligation $ 280 $ 26
Fair value of plan assets 160 —

Net Unfunded Status $ 120 $ 26

Amounts recognized in the Consolidated Condensed Balance Sheet:

Liabilities for pensions and other postretirement benefits $ 120 $ 26

~~Weighted average assumption used to determine benefit obligations at the acquisition date and net periodic benefit cost from the acquisition date through December 31, 2010:~~

Other Postretirement
Pension Benefit Plans Benefit Plans

Discount rate 5.24 % 6.18 %
Rate of compensation increase 4.30 % n/a

~~Goodwill~~Noncontrolling Interests

~~Goodwill~~We obtained certain entities which were not wholly owned by BJ Services. A step-up adjustment of ~~$4,192~~$202 million was ~~recognized for this acquisition and is calculated as~~recorded to present the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. It specifically includes the expected synergies and other benefits that we believe will result from combining the operations of BJ Services with the operations of Baker Hughes and any intangible assets that do not qualify for separate recognition such as the assembled workforce. During the third quarter of 2010, we allocated the goodwill to our reporting units based on the provisional amounts recognized for thenoncontrolling interests in these entities at fair value of the assets acquired and liabilities assumed (See Note 9 — Goodwill and Intangible Assets). Goodwill in the amount of $43 million is deductible for tax purposes as a result of previous taxable acquisitions made by BJ Services.

~~Acquisition-Related Costs~~

Acquisition-related costs are being expensed as incurred. They include expenses directly related to acquiring BJ Services and integration expenses incurred in combining the companies. These costs are classified as acquisition-related costs on our consolidated condensed statement of operations.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 and January 1, 2009.~~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, ~~2009, or 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

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

Three Months Ended Nine Months Ended
September 30, September 30,
2010 2009 2010 2009
Pro Forma Pro Forma Pro Forma

Revenues $ 4,078 $ 3,110 $ 11,480 $ 9,941
Net income $ 255 $ 31 $ 493 $ 290
Basic net income per share $ 0.59 $ 0.07 $ 1.14 $ 0.68
Diluted net income per share $ 0.59 $ 0.07 $ 1.14 $ 0.68

~~OTHER ACQUISITIONS~~

During the nine months ended September 30, 2010, we completed several other acquisitions having an aggregate purchase price of approximately $172 million, net of cash acquired of $5 million. As a result of these acquisitions, we recorded $96 million of goodwill, which is subject to final acquisition accounting adjustments. Pro forma results of operations for these acquisitions have not been presented because the effect of these acquisitions was not material to our consolidated condensed financial statements.

NOTE 3. SEGMENT INFORMATION

Beginning in the second quarter of 2010, we changed our internal reporting structure to align with our geographical organization for which separate financial information is available and results are evaluated regularly by the Chief Operating Decision Makers (“CODM”). Accordingly, we now report our financial results based on theBaker 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 and Other (downstream chemicals, process and pipeline services, reservoir and technology consulting businesses)~~

All prior period segment disclosures have been restated to reflect the new segments. The financial results of BJ Services have been included in each of the five reportable segments from the date of acquisition on April 28, 2010, through September 30, 2010, in a manner consistent with our internal reporting structure.

	•		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 ~~segment~~ profit ~~(loss),~~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.~~table:


	Three Months Ended					Three Months Ended					Three Months Ended					Three Months Ended
	September 30, 2010					September 30, 2009					March 31, 2011					March 31, 2010
Segments	Revenues		Profit(loss)			Revenues		Profit(loss)			Revenues		Profit (loss)			Revenues		Profit (loss)

North America	$	2,006	$	340		$	714	$	28		$	2,352	$	460		$	919	$	141
Latin America		431		9			257		16			473		63			272		9
Europe/Africa/Russia Caspian		757		47			626		79			771		91			720		80
Middle East/Asia Pacific		606		39			463		50			659		79			439		30
Industrial and Other		278		36			172		14
Industrial Services and Other												270		14			189		17

Total Oilfield Operations		4,078		471			2,232		187			4,525		707			2,539		277
Corporate and Other		—		(105	)		—		(104	)		—		(119	)		—		(83	)

Total	$	4,078	$	366		$	2,232	$	83		$	4,525	$	588		$	2,539	$	194

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

Nine Months Ended Nine Months Ended
September 30, 2010 September 30, 2009
Segments Revenues Profit(loss) Revenues Profit(loss)

North America $ 4,411 $ 685 $ 2,378 $ 129
Latin America 1,087 31 798 70
Europe/Africa/Russia Caspian 2,213 196 2,078 365
Middle East/Asia Pacific 1,590 109 1,468 196
Industrial and Other 690 71 514 47

Total Oilfield Operations 9,991 1,092 7,236 807
Corporate and Other — (330 ) — (318 )

Total $ 9,991 $ 762 $ 7,236 $ 489

Total Assets September 30, 2010 December 31, 2009

North America $ 8,071 $ 2,596
Latin America 2,600 1,168
Europe/Africa/Russia Caspian 3,425 2,248
Middle East/Asia Pacific 2,910 1,731
Industrial and Other 3,551 2,127

Total Oilfield Operations 20,557 9,870
Corporate and Other 1,905 1,569

Total $ 22,462 $ 11,439

~~Assets of our supply chain and products and technology organizations are included in the Industrial and Other segment.~~

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

Three Months Ended Nine Months Ended
September 30, September 30,
2010 2009 2010 2009

Corporate and other expenses $ (54 ) $ (76 ) $ (159 ) $ (225 )
Acquisition-related costs (12 ) — (78 ) —
Interest expense (40 ) (29 ) (95 ) (98 )
Interest income 1 1 2 5

Total $ (105 ) $ (104 ) $ (330 ) $ (318 )

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

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


	Three Months Ended				Nine Months Ended				Three Months Ended
	September 30,				September 30,				March 31,
	2010		2009		2010		2009		2011		2010

Stock Options	$	8	$	12	$	22	$	21	$	10	$	7
Restricted Stock Awards and Units		12		9		33		29		14		10
ESPP		5		5		11		18		5		2

Total	$	25	$	26	$	66	$	68	$	29	$	19

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

~~NOTE 5. INCOME TAXES~~

In the third quarter of 2010, total income tax expense of $111 million includes a $12 million tax benefit on costs associated with the BJ Services acquisition. Excluding the impact of the acquisition-related costs, our effective tax rate on operating profits in the third quarter of 2010 is 32.5%, which is lower than the U.S. statutory income tax rate of 35% due to tax benefits arising from the repatriation of foreign earnings partially offset by higher rates of tax on certain international operations and state income taxes.

For the first nine months of 2010, total income tax expense of $285 million includes a $20 million tax benefit on costs associated with the BJ Services acquisition. Excluding the impact of the acquisition-related costs, our effective tax rate on operating profits for the first nine months of 2010 is 36%, which is higher than the U.S. statutory income tax rate of 35% due to higher rates of tax on certain international operations and state income taxes partially offset by tax benefits arising from the repatriation of foreign earnings.

NOTE 6.5. 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				Nine Months Ended				Three Months Ended
	September 30,				September 30,				March 31,
	2010		2009		2010		2009		2011		2010

Weighted average common shares outstanding for basic EPS		432		310		381		310		435		313
Effect of dilutive securities — stock plans		1		1		1		—		2		—

Adjusted weighted average common shares outstanding for diluted EPS		433		311		382		310		437		313


Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than the average market price for the period		7		4		7		4		3		2

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

March 31, 2010 to the new reportable segments on a relative fair value basis. Goodwill of $4,192 million was recognized for the BJ Services acquisition (See Note 2 — Acquisitions) which has been allocated to our reporting units based on the provisional amounts recognized for the fair value of the assets acquired and liabilities assumed.

Europe/ Middle
Drilling Completion Africa/ East/
and and North Latin Russia Asia Industrial
Evaluation Production America America Caspian Pacific & Other Total

Balance as of December 31, 2009 $ 979 $ 439 $ — $ — $ — $ — $ — $ 1,418

Reallocation for change in segments (980 ) (439 ) 494 175 412 267 71 —
Acquisitions — — 2,585 501 413 459 330 4,288
Other adjustments 1 — (4 ) (2 ) (7 ) 3 17 8

Balance as of September 30, 2010 $ — $ — $ 3,075 $ 674 $ 818 $ 729 $ 418 $ 5,714


						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:

September 30, 2010 December 31, 2009
Gross Gross
Carrying Accumulated Carrying Accumulated
Amount Amortization Net Amount Amortization Net

Technology-based $ 865 $ (167 ) $ 698 $ 277 $ (140 ) $ 137
Contract-based 17 (11 ) 6 13 (9 ) 4
Marketing-related 87 (17 ) 70 36 (13 ) 23
Customer-based 379 (24 ) 355 41 (10 ) 31
Other 1 (1 ) — 1 (1 ) —

Subtotal 1,349 (220 ) 1,129 368 (173 ) 195

Marketing-related intangible asset with an indefinite useful life 383 — 383 — — —

Total $ 1,732 $ (220 ) $ 1,512 $ 368 $ (173 ) $ 195


	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. As a result of the acquisition of BJ Services, we recognized intangible assets of $1,333 million (See Note 2 - Acquisitions). We have not finalized the determination of the estimated useful lives and amortization methods to be used in calculating the amortization expense related to the intangibles recorded as a result of the acquisition of BJ Services.

Amortization expense for intangible assets included in net income for the three months ~~and nine months~~ ended ~~September 30, 2010~~March 31, 2011 was ~~$18~~$22 million, ~~and $48 million, respectively,~~ and is estimated to be ~~$70~~$98 million for ~~2010.~~fiscal year 2011. Estimated amortization expense for each of the subsequent five fiscal years is expected to be as follows: ~~2011 — $90 million;~~ 2012 — ~~$86~~$106 million; 2013 — ~~$85~~$107 million; 2014 — ~~$84~~$106 million; 2015 — $98 million; and ~~2015~~2016 — ~~$79~~$95 million.

NOTE ~~10.~~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 ~~September 30,~~March 31, 2011 and December 31, 2010 approximates their carrying value as reflected in our consolidated condensed balance ~~sheet approximates their carrying~~sheets. The fair value ~~due to the short maturities~~ of ~~these instruments.~~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 ~~nine months~~year ended ~~September 30,~~December 31, 2010, we purchased ~~$250 million of~~ 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 ~~2011.~~$251 million and $250 million, respectively.

129

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

Debt

The estimated fair value of total debt at ~~September 30, 2010~~March 31, 2011 and December 31, ~~2009,~~2010, was ~~$4,369~~$4,255 million and ~~$2,126~~$4,298 million, respectively, which differs from the carrying amount of ~~$3,846~~$3,841 million and ~~$1,800~~$3,885 million, respectively, included in our consolidated condensed balance ~~sheet. The fair value of our debt has been estimated based on quoted market prices for the respective period.~~sheets.

Foreign Currency Forward Contracts

We conduct our business in over 9080 countries around the world, and we are exposed to market risks resulting from fluctuations in foreign currency exchange rates. A number of our significant foreign subsidiaries have designated the local currency as their functional currency. We transact in various foreign currencies and ~~seek to balance our foreign currency exposures by matching our revenue and costs in non-functional currencies where practical. Where imbalances in the non-functional currencies remain we~~ have established a program that primarily utilizes foreign currency forward contracts to reduce the risks associated with the effects of certain foreign currency exposures. Under this program, our strategy is to have gains or losses on the foreign currency forward contracts mitigate the foreign currency transaction gains or losses to the extent practical. These foreign currency exposures typically arise from changes in the value of assets and liabilities which are denominated in currencies other than the functional currency. Our foreign currency forward contracts generally settle within ~~180~~90 days. We do not use these forward contracts for trading or speculative purposes. We designate these forward contracts as fair value hedging ~~instruments. Accordingly,~~instruments and, accordingly, we record the fair value of these contracts as of the end of our reporting period to our consolidated ~~condensed~~ balance sheet with changes in fair value recorded in our consolidated ~~condensed~~ statement of operations along with the change in fair value of the hedged item.

~~At September 30, 2010, we~~We had outstanding foreign currency forward contracts with notional amounts aggregating ~~$187~~$156 million to hedge exposure to currency fluctuations in various foreign ~~currencies. These contracts expire on various dates prior to the end of~~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.

~~In June 2009, we entered into two~~ Our interest rate swap agreements (“the Swap Agreements”) for a notional amount of $250 million each in order to hedge changes in the fair market value of our $500 million 6.5% senior notes maturing on November 15, 2013. Under the Swap Agreements, we receive interest at a fixed rate of 6.5% and pay interest at a floating rate of one-month Libor plus a spread of 3.67% on one swap and three-month Libor plus a spread of 3.54% on the second swap both through November 15, 2013. The counterparties are primarily the lenders in our credit facilities. The Swap Agreementsswaps are designated and each qualifies as a fair value hedging instrument. The swap to three-month Libor is deemed to be 100 percent effective resulting in no gain or loss recorded in the consolidated condensed statement of operations. The effectiveness of the swap to one-month Libor, which is highly effective, is calculated as of each period end and any ineffective portion is recognized in the consolidated condensed statement of operations. The fair value of ~~the Swap Agreements~~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 ~~value~~values of derivative instruments included in our consolidated condensed balance ~~sheet was~~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 ~~as of September 30, 2010:~~(amounts exclude any income tax effects):


					Amount of Gain (Loss) Recognized in Income
					Three Months Ended March 31,
Derivative	Balance Sheet Location	Fair Value		Statement of Operations Location	2011			2010

Foreign Currency Forward Contracts	Other assets	$	7	Marketing, general and administrative	$	(1	)	$	(5	)
Interest Rate Swaps	Other assets	$	30	Interest expense	$	3		$	7

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

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

Amount of Gain/(Loss) Recognized in Income
Three Months Ended Nine Months Ended
Derivative Statement of Operations Location September 30, 2010 September 30, 2010

Foreign Currency Forward Contracts Marketing, general and administrative $ 11 $ 1
Interest Rate Swaps Interest Expense $ 2 $ 12

NOTE ~~11.~~10. INDEBTEDNESS

OnAt March 19, 2010, we entered into a credit agreement (the “2010 Credit Agreement”). The 2010 Credit Agreement is a three-year committed $1.2 billion revolving credit facility that expires on March 19, 2013. At September 30, 2010,31, 2011, we had $1.7 billion of committed revolving credit facilities with commercial ~~banks, consisting of the 2010 Credit Agreement ($1.2 billion) and a $500 million facility expiring on July 7, 2012. Both~~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.

~~Concurrent with the acquisition of BJ Services, we assumed and guaranteed the BJ Services outstanding notes, namely its $250 million 5.75% notes due June~~ At March 31, 2011, ~~and its $250 million 6.00% notes due June 2018.~~

On August 24, 2010, we sold $1,500 million of 5.125% Senior Notes that will mature September 15, 2040 (the “Notes”) under our Indenture dated as of October 28, 2008. Net proceeds from the offering were approximately $1,479 million after deducting the underwriting discounts and expenses of the offering. We used $511 million of the net proceeds to repay our outstanding commercial paper. We will use $250 million of the net proceeds to repay the BJ Services 5.75% notes maturing June 2011. The remaining net proceeds from the offering will be used for general corporate purposes, which could include funding on-going operations, business acquisitions and repurchases of our common stock. Interest on the Notes is payable March 15 and September 15 of each year. The first interest payment will be made on March 15, 2011, and will consist of accrued interest from August 24, 2010. The Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to any future subordinated indebtedness; and effectively junior to our future secured indebtedness, if any, and structurally subordinated to all existing and future indebtedness of our subsidiaries. We may redeem, at our option, all or part of the Notes at any time, at the applicable make-whole redemption prices plus accrued and unpaid interest to the date of redemption.

~~At September 30, 2010,~~ we were in compliance with all of the ~~facility covenants of both committed credit facilities.~~facilities’ covenants. There were no direct borrowings under the committed credit facilities during the quarter ended ~~September 30, 2010.~~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, ~~outstanding,~~ our ability to borrow under the facilities is reduced. At ~~September 30, 2010,~~March 31, 2011, we had no outstanding commercial ~~paper outstanding.~~paper.

NOTE ~~12.~~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 ~~plans,~~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.

1411

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

~~The components of net periodic benefit cost are as follows for the three months ended September 30:~~

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

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

Net periodic benefit cost $ 9 $ 10 $ 4 $ 1 $ 5 $ 5

~~The components of net periodic benefit cost are as follows for the nine months ended September 30:~~

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

Service cost $ 24 $ 22 $ 5 $ 2 $ 7 $ 6
Interest cost 16 14 20 11 8 8
Expected return on plan assets (21 ) (18 ) (17 ) (11 ) — —
Amortization of prior service cost — — — — 1 1
Amortization of net loss 9 10 3 1 — —
Curtailment loss — 1 — — — —

Net periodic benefit cost $ 28 $ 29 $ 11 $ 3 $ 16 $ 15

During the nine months ended September 30, 2010, we made contributions of $31 million to our defined benefit pension plans, $11 million to our other postretirement benefit plans, and $125 million to our defined contribution plans. We presently anticipate contributing an additional $61 million to our defined benefit pension plans, $4 million to our other postretirement plans, and $46 million to our defined contribution plans during the fourth quarter of 2010.

NOTE ~~13.~~12. COMMITMENTS AND CONTINGENCIES

LITIGATION

We are involved in litigation or proceedings that have arisen in our ordinary business ~~activities as well as litigation or proceedings assumed in connection with the acquisition of BJ Services.~~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.

~~BJ Services Acquisition Related Stockholder Lawsuits~~

As previously reported, the stockholder lawsuits filed in connection with the BJ Services acquisition have been settled. On July 15, 2010, the Delaware Chancery Court certified the Class of BJ Services stockholders, approved the settlement terms, awarded $500,000 in attorneys’ fees and $36,000 in costs to the Class counsel, and entered a Final Judgment dismissing all of the Class claims with prejudice, In re: BJ Services Company Shareholders Litigation, C.A. No. 4851-VCN. On July 23, 2010, the 80^th Judicial District Court of Harris County, Texas, entered a Final Judgment dismissing the plaintiff’s claims with prejudice in the consolidated actions styled as Garden City Employees’ Retirement System, et al. v. BJ Services Company, et al., Cause No. 2009-57320, 80^th ~~Judicial District Court of Harris County, Texas.~~

~~Customer Claim~~

On November 19, 2009, BJ Services received correspondence from a customer operating in the North Sea, claiming that BJ Services’ decision to move a stimulation vessel out of the North Sea market constituted a breach of contract. The customer alleges that it was forced to purchase well stimulation services from other providers at a higher cost than in the original agreement between

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

the customer and BJ Services. The customer further alleges that it has incurred actual and estimated future damages of $40 million plus an undisclosed amount for production loss and/or production deferral. The customer has initiated a request for arbitration and we are responding accordingly. We believe that this claim is without merit, and we intend to vigorously defend ourselves in this matter based on the information available to us at this time. We do not expect the outcome of this matter to have a material adverse effect on our consolidated condensed financial statements; however, there can be no assurance as to the ultimate outcome of this matter.

~~ENVIRONMENTAL~~

BJ Services operations included activities which are subject to domestic (including U.S. federal, state and local) and international environmental regulations with regard to air, land and water quality and other environmental matters. BJ Services has conducted environmental investigations and remedial actions at current and former locations of BJ Services and, along with other companies, are currently named as a potentially responsible party at five waste disposal sites owned by third parties. As a result of the acquisition of BJ Services, we have recorded approximately $11 million as a preliminary estimate for environmental remediation. As of September 30, 2010, our total accrual for environmental remediation on a combined company basis is $32 million.

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 ~~$1,067 million~~$1.21 billion at ~~September 30, 2010.~~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 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 Nine Months Ended
September 30, September 30,
2010 2009 2010 2009

Net income $ 255 $ 55 $ 477 $ 337
Other comprehensive income (loss):
Foreign currency translation adjustments during the period 79 33 (41 ) 115
Pension and other postretirement benefits (3 ) 4 18 (6 )
Unrealized gain on available-for-sale securities — — — 4

Total comprehensive income $ 331 $ 92 $ 454 $ 450

~~Total accumulated other comprehensive loss consisted of the following:~~

September 30, December 31,
2010 2009

Foreign currency translation adjustments $ (261 ) $ (220 )
Pension and other postretirement benefits (176 ) (194 )

Total accumulated other comprehensive loss $ (437 ) $ (414 )

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with our consolidated condensed financial statements and the related notes thereto, as well as our Annual Report on Form 10-K for the year ended December 31, ~~2009~~2010 (“~~2009~~2010 Annual Report”).

EXECUTIVE SUMMARY

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

products and services ~~include:~~for drilling and evaluation of oil and gas wells;

	•		~~technology and services used in drilling and evaluating oil and gas wells (drill bits, drilling systems, drilling fluids and wireline);~~

	•		~~technology and services used to complete and produce oil and gas (completion systems, wellbore intervention, intelligent production systems, upstream chemicals and artificial lift);~~

	•		~~pressure pumping services (cementing, hydraulic fracturing and other stimulation, and nitrogen services and coiled tubing); and~~

	•		~~industrial and other (downstream chemicals, process and pipeline services, and reservoir and technology consulting business).~~

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.

On April 28, 2010, we completed the acquisition of BJ Services, a leading provider of pressure pumping and other oilfield services, for $6.9 billion in cash and stock. This acquisition provides us with a proven leader in the areas of pressure pumping, stimulation and fracturing and complements our existing product portfolio, allowing us to provide a full suite of products and services to meet the needs of our customers. For its fiscal year ended September 30, 2009, BJ Services’ revenues were $4.1 billion; they employed approximately 14,000 people; and operated in over 50 countries. For the first ~~nine months of 2010, our results are inclusive of BJ Services results from the acquisition date through September 30, 2010.~~

On August 30, 2010, we completed the sale of two stimulation vessels and certain other assets as required by the Antitrust Division of the U.S. Department of Justice (“DOJ”) in connection with the acquisition of BJ Services. As a result of the completion of this sale, the Hold Separate Stipulation and Order requiring BJ Services and Baker Hughes to be operated separately in the U.S. terminated. The sale was not material to our business or the financial performance of the combined company.

~~Total revenue for the third~~ quarter of ~~2010 was $4.08~~2011, we generated revenues of $4.53 billion, an increase of ~~$1.85~~$1.99 billion or ~~83% over~~78% compared to the same quarter a year ago. ~~Total revenue~~Our North America revenues for the first ~~nine months~~quarter of ~~2010 was $9.99~~2011 were $2.35 billion, an increase of ~~$2.76~~156% compared to the first quarter of 2010. Revenues outside of North America were $1.90 billion, ~~or 38% over~~an increase of 33% compared to the ~~same period a year ago.~~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 ~~are~~in revenues were primarily due to the acquisition of BJ Services ~~on April 28,~~during the second quarter of 2010, which provided ~~$1.40~~revenues of $1.62 billion ~~of revenue in~~for the ~~third~~first quarter of ~~2010, and $2.20 billion in the first nine months of 2010;~~2011; and the strength of the North America segment driven by ~~oil and gas-directed~~oil-directed drilling primarily in unconventional reservoirs.

~~We reported net~~Net income ~~of $255~~attributable to Baker Hughes was $381 million in the third quarter of 2010 compared to net income of $55 million reported for the third quarter of 2009. For the first nine months of 2010, we reported net income of $477 million compared to net income of $337 million reported for the first ~~nine months~~quarter of ~~2009. These increases are~~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 ~~$134~~$109 million of net income in the ~~third~~first quarter of ~~2010 and $164 million of net income for the first nine months of 2010, and~~2011, improved profitability in ~~our~~ North America, ~~segment offset by lower profits~~and to a lesser extent, improved profitability internationally.

~~As of September 30, 2010,~~At March 31, 2011, Baker Hughes had approximately ~~52,000~~53,700 employees as compared ~~with~~to approximately ~~34,400~~53,100 employees ~~as of~~at December 31, ~~2009.~~

~~Segment Reporting Change~~

Effective with the second quarter of 2010, we changed our internal reporting structure to align with our geographical organization which became the primary vehicle for allocating resources and assessing performance. All prior period segment disclosures have been restated to reflect the new segments. As a result, beginning with the second quarter of 2010, we reported our results for the following five segments:

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

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 ~~the third quarter of 2010.~~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.~~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 ~~will normally~~ result in increased ~~or decreased~~ demand for our products and services, which ~~will be~~is reflected in the rig count and other measures. ~~At current oil prices, many international projects have attractive economic returns.~~

In ~~the U.S., both oil-directed and gas-directed drilling~~North America, customer spending on oil projects increased, ~~from the trough levels experienced~~resulting in ~~mid-2009. Fifty-six percent of the incremental drilling~~a 71% increase in the ~~U.S.~~North America oil-directed rig count in the ~~third~~first quarter of ~~2010,~~2011 compared to the ~~third quarter of 2009, was targeted to develop oil reserves.~~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.

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, ~~and the development of several new oil shale plays. Incremental gas-directed drilling~~our customers’ spending increased. This was ~~driven by activity~~reflected in a 10% increase in the ~~gas shale plays where lower costs and the availability of cash from prior hedge activity and new equity investments supported higher drilling activity.~~

Prices for our products and services in the third quarter of 2010 remain significantly below pricing levels a year ago despite the increase in oil and natural gas prices. Price trends are improving for some products in certain geographies, such asrig count outside North ~~America; however, they remain stable or deteriorating in others (primarily in the Eastern Hemisphere).~~America.

Oil and Natural Gas Prices

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


	Three Months Ended				Nine Months Ended				Three Month Ended March 31,
	September 30,				September 30,				2011		2010
	2010		2009		2010		2009

Oil prices ($/Bbl)	$	76.09	$	68.14	$	77.58	$	57.21
WTI oil prices ($/Bbl)									$	94.60	$	78.84
Brent oil prices ($/Bbl)										105.21		76.78
Natural gas prices ($/mmBtu)		4.28		3.17		4.56		3.80		4.20		5.09

The rig count in North America increased ~~71%~~27% reflecting, ~~a 42% increase~~ in the U.S. ~~gas-directed rig count and a 133%~~, an 80% increase in the oil-directed rig count and ~~similar patterns in Canada. Changes in regulation of drilling activity~~a 2% increase in the ~~Gulf of Mexico as~~gas-directed rig count; and in Canada, a ~~result of the Deepwater Horizon accident and resultant oil spill negatively impacted activity~~57% increase in the ~~quarter where the U.S. offshore~~oil-directed rig count ~~averaged only 18 rigs as compared to 34 rigs~~and a 14% decrease in the ~~third quarter of 2009.~~gas-directed rig count. Outside North America, the rig count increased ~~15%~~10%. The rig count in Latin America increased primarily due to higher activity in the ~~Southern Cone geomarket (Argentina, Bolivia and Chile) and the~~ Andean geomarket (Colombia, Peru and Ecuador) and ~~was~~in Venezuela, partially offset by lower activity in ~~the Mexico geomarket.~~Mexico. The increase in the Continental Europe geomarket was led by Turkey, ~~Italy~~Poland, Romania, Hungary and ~~Romania.~~Germany. The rig count in Africa increased primarily due to higher activity in ~~the~~Algeria, Nigeria, Gabon and ~~Angola geomarkets.~~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, ~~Kuwait, Syria and Yemen,~~partially offset ~~partially~~ by declines in activity in ~~Pakistan.~~Pakistan, Oman and Saudi Arabia. In the Asia Pacific region, activity increased primarily in India and ~~Vietnam, offset partially by lower activity in~~ Indonesia.

Revenues and Profit Before Tax

Three Months Ended
September 30, Increase
2010 2009 (decrease) % Change

Segment Revenues:
North America $ 2,006 $ 714 $ 1,292 181 %
Latin America 431 257 174 68 %
Europe/Africa/Russia Caspian 757 626 131 21 %
Middle East/Asia Pacific 606 463 143 31 %
Industrial and Other 278 172 106 62 %

Segment revenues $ 4,078 $ 2,232 $ 1,846 83 %

Three Months Ended
September 30, Increase
2010 2009 (decrease) % Change

Segment Profit Before Tax:
North America $ 340 $ 28 $ 312 1,114 %
Latin America 9 16 (7 ) (44 )%
Europe/Africa/Russia Caspian 47 79 (32 ) (41 )%
Middle East/Asia Pacific 39 50 (11 ) (22 )%
Industrial and Other 36 14 22 157 %

Segment profit before tax $ 471 $ 187 $ 284 152 %

Nine Months Ended
September 30, Increase
2010 2009 (decrease) % Change

Segment Revenues:
North America $ 4,411 $ 2,378 $ 2,033 85 %
Latin America 1,087 798 289 36 %
Europe/Africa/Russia Caspian 2,213 2,078 135 6 %
Middle East/Asia Pacific 1,590 1,468 122 8 %
Industrial and Other 690 514 176 34 %

Segment revenues $ 9,991 $ 7,236 $ 2,755 38 %

Nine Months Ended
September 30, Increase
2010 2009 (decrease) % Change

Segment Profit Before Tax:
North America $ 685 $ 129 $ 556 431 %
Latin America 31 70 (39 ) (56 )%
Europe/Africa/Russia Caspian 196 365 (169 ) (46 )%
Middle East/Asia Pacific 109 196 (87 ) (44 )%
Industrial and Other 71 47 24 51 %

Segment profit before tax $ 1,092 $ 807 $ 285 35 %

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.

Profit before tax for the ~~third~~first quarter of ~~2010~~2011 increased ~~152%~~$430 million or 155% compared ~~with~~to the ~~third~~first quarter of ~~2009.~~2010. Excluding BJ Services, profit before tax was up ~~30%. The primary drivers of the increase included improved profits~~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, ~~partially offset by price degradation~~ and ~~lower~~to a lesser extent, higher profits in ~~our international segments.~~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 ~~revenue~~revenues increased ~~181%~~156% in the ~~third~~first quarter of ~~2010~~2011 compared with the ~~third~~first quarter of ~~2009.~~2010. Excluding BJ Services, revenues ~~for the third quarter of 2010 were up 42%~~increased 29%. ~~Revenue~~Revenues and pricing increases were supported by a ~~71%~~30% increase in the U.S. land and inland waters rig count and a ~~94%~~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 ~~revenue.~~revenues. This improvement was partially offset by a decline in our U.S. Gulf of Mexico ~~revenue from~~revenues directly attributable to the ~~drilling moratorium~~slow pace of re-permitting in the Gulf of Mexico ~~estimated to be between $75 million and $80 million.~~following the lifting of the drilling moratorium.

North America profit before tax ~~was $340 million~~increased 226% in the ~~third~~first quarter of ~~2010, an increase of $312 million~~2011 compared with the ~~third~~first quarter of ~~2009.~~2010. Excluding BJ Services, profit before tax ~~for~~increased 74%. In addition to increased revenues, the ~~third quarter of 2010 was up $93 million. 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 ~~due~~directly attributable to the ~~drilling moratorium~~slow pace of re-permitting in the Gulf of Mexico ~~estimated to be between $45 million and $50 million.~~following the lifting of the drilling moratorium.

~~Outside North~~Latin America

Latin America

~~Latin America revenue~~ revenues increased ~~68%~~74% in the ~~third~~first quarter of ~~2010~~2011 compared with the ~~third~~first quarter of ~~2009.~~2010. Excluding BJ Services, ~~revenue for the third quarter 2010 was up 21%~~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 ~~and Brazil geomarkets, offset partially by activity and revenue declines in the Venezuela/Mexico geomarket driven primarily by customer budgetary constraints in Mexico.~~geomarket.

Latin America profit before tax ~~decreased 44%~~increased 600% in the ~~third~~first quarter of ~~2010~~2011 compared to the ~~third~~first quarter of ~~2009 as increases in~~2010. Excluding BJ Services, profit before tax increased 500%. Improved profit before tax from directional drilling systems in the ~~Andean~~Brazil geomarket and ~~Brazil geomarkets were more than offset by decreased profit before tax~~ from artificial lift in the Venezuela/Mexico geomarket ~~resulting from lower activity~~were the primary drivers of improved profitability in ~~Mexico.~~addition to increased revenues.

Europe/Africa/Russia Caspian

Europe/Africa/Russia Caspian ~~revenue~~revenues increased ~~21%~~7% in the ~~third~~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 ~~compared to~~in the ~~third quarter~~Africa region, civil unrest in the North Africa geomarket, in particular Libya where our operations have currently ceased, pending resolution of ~~2009. Excluding BJ Services, revenue for~~ the ~~third quarter of 2010 was up 6%. The increase~~conflict, and weather delays in ~~this region was led~~the Norway geomarket. These decreases were offset by ~~strong demand for directional drilling and artificial lift products and services. Increased~~general activity ~~and commensurate revenue~~ increases ~~occurred~~ in the Russia Caspian ~~UK,~~region and ~~Nigeria geomarkets, offset partially by reduced revenue from~~ the ~~North Africa, Sub Saharan Africa and~~ Continental Europe ~~geomarkets.~~geomarket.

Europe/Africa/Russia Caspian profit before tax ~~decreased 41%~~increased 14% in the ~~third~~first quarter of ~~2010~~2011 compared to the ~~third~~first quarter of ~~2009 as improved~~2010. Excluding BJ Services, profit before tax increased 9%. Improved profit before tax in the ~~UK and~~ Russia Caspian ~~geomarkets~~and Europe regions on higher activity were ~~more than~~partially offset by ~~decreased profit before tax~~lower profits in the ~~Sub Saharan~~ Africa region attributable to project completions and civil unrest in the North Africa ~~and Norway geomarkets due to higher overhead costs and lower realized pricing.~~geomarket.

Middle East/Asia Pacific

Middle East/Asia Pacific ~~revenue~~revenues increased ~~31%~~50% in the ~~third~~first quarter of ~~2010~~2011 compared to the ~~third~~first quarter of ~~2009.~~2010. Excluding BJ Services, ~~revenue for the third quarter of 2010 was up 6%~~revenues increased 21%. The increase in this ~~region~~segment was driven by higher ~~activity that benefitted our chemicals, artificial lift and completion systems products and services. Increased~~revenues attributable to higher activity and ~~commensurate revenue increases occurred primarily in~~share gains from the ~~Egypt, Southeast~~Saudi Arabia, Gulf, and Iraq geomarkets. Asia ~~North Asia and Australasia geomarkets. These increases~~Pacific revenues were ~~offset partially by decreased revenue primarily in the Indonesia geomarket.~~essentially unchanged.

Middle East/Asia Pacific profit before tax ~~decreased 22%~~increased 163% in the ~~third~~first quarter of ~~2010~~2011 compared to the ~~third~~first quarter of ~~2009 as improved profit before tax in the Egypt and North Asia geomarkets was more than offset by lower realized pricing and higher overhead costs throughout the rest of the region.~~

~~Industrial and Other~~

Industrial and Other revenue increased 62% in the third quarter of 2010 compared to the third quarter of 2009. Excluding BJ Services, revenue for the third quarter of 2010 increased 16%. Industrial and Other profit before tax increased $22 million in the third quarter of 2010 compared to the third quarter of 2009.2010. Excluding BJ Services, profit before tax increased ~~$12 million.~~133%. The improvement in profit before tax was driven primarily by the increased revenues in the Saudi Arabia and Gulf geomarkets.

~~First Nine Months~~Industrial Services and Other

Industrial Services and Other revenues increased 43% in the first quarter of ~~2010 Compared~~2011 compared to the ~~First Nine Months~~first quarter of ~~2009~~

~~Revenues for the first nine months of 2010 increased 38% compared with the first nine months of 2009, primarily due to the acquisition of BJ Services and expansion of the North America market.~~2010. Excluding BJ Services, ~~revenue for the first nine months of 2010~~revenues increased 8%2%.

~~Profit before tax for the first nine months of 2010 increased 35% compared with the first nine months of 2009, as increased profit from the acquisition of BJ~~ Industrial Services and ~~increased~~Other profit before tax ~~from the North America segment was offset by price degradation~~decreased 18% or $3 million in the ~~international segments.~~first quarter of 2011 compared to the first quarter of 2010. Excluding BJ Services, profit before tax ~~for the first nine months of 2010 was unchanged.~~decreased 41%.

Costs and Expenses

The table below details certain consolidated condensed statement of operations data and their percentage of ~~revenues for the three months and nine months ended September 30, 2010 and 2009, respectively.~~revenues.

Three Months Ended September 30,
2010 2009

Revenues $ 4,078 100 % $ 2,232 100 %
Cost of revenues 3,189 78 % 1,761 79 %
Research and engineering 118 3 % 88 4 %
Marketing, general and administrative 354 9 % 272 12 %


									Three Months Ended
	Nine Months Ended September 30,								March 31,
	2010				2009				2011				2010

Revenues	$	9,991	100	%	$	7,236	100	%	$	4,525	100	%	$	2,539	100	%
Cost of revenues		7,763	78	%		5,518	76	%		3,497	77	%		1,912	75	%
Research and engineering		324	3	%		299	4	%		106	2	%		94	4	%
Marketing, general and administrative		971	10	%		837	12	%		282	6	%		305	12	%

~~months ended September 30, 2009. The increase~~from a reduction in ~~both periods resulted primarily from~~ costs associated with finance ~~organization~~ redesign efforts and software implementation activities, ~~and the acquisition of BJ Services.~~

~~Acquisition-Related Costs~~

Acquisition-related costs are being expensed as incurred. They include expenses directly related to acquiring BJ Services and integration expenses incurred in combining the companies. During the three and nine months ended September 30, 2010, we incurred $12 million and $78 million, respectively, of total acquisition-related costs.which were completed during 2010.

Interest Expense, net

~~Interest~~Net interest expense increased ~~$11~~$28 million for the ~~three months ended September 30, 2010~~first quarter of 2011 compared ~~with~~to the ~~three months ended September 30, 2009~~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. Interest expense decreased $3 million in the nine months ended September 30, 2010 compared with the nine months ended September 30, 2009 as the interest expense related to the new debt was more than offset by gains on interest rate swaps.

Income Taxes

Total income tax expense infor the ~~third~~first quarter of 2010 is $111 million, which includes a $12 million tax benefit on costs associated with the BJ Services acquisition. Excluding the impact of the acquisition-related costs, our effective tax rate on operating profits in the third quarter of 2010 is 32.5%, which is lower than the U.S. statutory income tax rate of 35% due to tax benefits arising from the repatriation of foreign earnings partially offset by higher rates of tax on certain international operations and state income taxes.

For the first nine months of 2010, total income tax expense of $285 million includes a $20 million tax benefit on costs associated with the BJ Services acquisition. Excluding the impact of the acquisition-related costs, our2011 was $204 million. Our effective tax rate on operating profits for the first nine months of 2010 is 36%, which is higher than the U.S. statutory income tax rate of 35% due to higher rates of tax on certain international operations and state income taxes partially offset by tax benefits arising from the repatriation of foreign earnings.

~~Our effective tax rate in the third~~ quarter of ~~2009~~2011 was ~~34%~~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. ~~However, resolution~~Resolution of ~~these matters~~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 ~~revenue is~~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,~~recession; (2) the negative impact of sustained oil prices over $100/Bbl on economic growth and oil demand; (3) the ~~moratorium~~potential for additional geopolitical disruption in the oil exporting countries in North Africa and ~~new regulations following~~ the ~~Deepwater Horizon accident~~Middle East, and its impact on spare production capacity; (4) the pace of re-permitting in the Gulf of ~~Mexico,~~Mexico; (5) the resolution of fiscal issues facing national governments; and ~~drilling in the U.S. oil-and-gas shale plays are the primary drivers impacting the 2010 business environment.~~(6) China’s efforts to address inflation and its economic growth.

As the worldwide economy recovers, demand for hydrocarbons ~~will increase.~~is increasing. In ~~July 2010,~~its April 2011World Economic Outlook, the International Monetary Fund (“IMF”) ~~observed strong~~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 ~~many~~2011 compared to 2010, while emerging and developing ~~and emerging~~ economies ~~while noting~~are expected to grow at 6.5% in 2011 compared to 2010. The IMF also noted that the ~~modest growth~~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 ~~advanced~~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 ~~threatened by a drop~~expected to have little macroeconomic impact.

The International Energy Agency (“IEA”) estimated in ~~confidence about fiscal sustainability, policy responses and future growth prospects.~~

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 ~~demands~~demand for oil ~~are~~is expected to be generated by the developing and emerging economies in ~~China, India~~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.

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 ~~Middle East. Increasing oil demand is expected to support oil prices between $60/Bbl and $85/Bbl.~~World Bank.

In North America, the near-month futures prices for natural gas, as quoted in ~~early October 2010,~~April 2011 for May 2011, were ~~below $4/~~approximately $4.30/mmBtu, and the ~~12-month~~twelve months futures ~~price was~~were trading ~~slightly below $4.50/~~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. Capital discipline on the part of our competitors, attrition of existing rental fleets and rising demand are expected to result in an environment that we believe will support continued price increases for our products and services in some markets by late 2010. In addition, project ~~economies~~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 ~~mcf.~~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 iscontinues to negatively ~~impacting~~impact the U.S. offshore drilling activity. ~~The impact appears~~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 ~~be isolated~~more active areas have now been redeployed to the Gulf of Mexico ~~at this time. Where possible, equipment and people are being assigned to opportunities away from the Gulf Coast.~~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.

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

In North America, the outlook for ~~spending for the remainder of 2010~~2011 will be significantly influenced by the outlook for both the oil and natural gas industry. ~~However, oil-directed~~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 ~~improved~~ expectations for the continued global ~~economy,~~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 ~~2.1~~1.5 million barrels per day in ~~2010~~2011 relative to ~~2009. Non-Organization for Petroleum Exporting Countries (“OPEC”)~~2010. Non-OPEC supply growth is expected to increase by ~~900~~550 thousand barrels per day in ~~2010.~~2011 as forecasted by the EIA. In its ~~October 14,~~December 2010 meeting in ~~Vienna,~~Quito, Ecuador, OPEC left its production policy unchanged. ~~The EIA projects that OPEC production will increase by 300 thousand barrels per day in 2010. OPEC spare productive capacity is expected to be essentially unchanged through 2011.~~ In its ~~October 2010~~April 2011 STEO report, the DOE forecasted WTI oil prices ~~(West Texas Intermediate)~~ to average ~~$79/~~$106/Bbl for the ~~fourth quarter~~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 ~~2010 and $83/Bbl in 2011.~~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 despite hot weather and increase in demand. Peak storage levels are~~prices. Storage is expected to ~~approximate the~~remain at or near historically high ~~record~~ levels ~~reached in~~throughout the ~~fall of 2009.~~year. In its ~~October 2010~~April 2011 STEO ~~report,~~ the ~~DOE~~EIA forecasted ~~that U.S.~~Henry Hub natural gas prices ~~would~~to average ~~$4.16/~~$4.10/mmBtu ~~in the fourth quarter of 2010. The DOE forecasts gas prices to increase to an average of $4.58/mmBtu in~~for 2011.

Our capital expenditures, excluding acquisitions, are expected to be ~~approximately $1.7~~between $2.3 billion ~~to $1.8~~and $2.7 billion for ~~2010, including approximately $350 million to $400 million that we expect to spend on infrastructure, primarily outside North America.~~2011. A significant portion of our planned capital expenditures can be adjusted to reflect changes in our expectations for future customer spending. We ~~expect to~~will manage our capital expenditures to match market demand.

2520

~~Compliance~~

In connection with our previously reported settlements with the DOJ and SEC, we retained an independent monitor (the “Monitor”) to assess and make recommendations about our compliance policies and procedures. The Monitor was retained for a term of three years. That term ended on July 1, 2010. In response to the Monitor’s recommendations, we have continued our reduction of the use of commercial sales representatives (“CSRs”) and processing agents, including the reduction of customs agents. We have also continued to enhance our channels of communication regarding agents while streamlining our compliance due diligence process for agents, including more clearly delineating the responsibilities of participants in the compliance due diligence process. We have adopted a risk-based compliance due diligence procedure for professional agents, enhancing our process for classifying distributors and creating a formal policy to guide business personnel in determining when subcontractors should be subjected to compliance due diligence. We have also instituted a program to ensure that each of our internal sponsors regularly reviews their CSRs, including a review with senior management.

In addition, we have reviewed and expanded the use of our centralized finance organization, including further implementation of our enterprise-wide accounting system and company-wide policies regarding expense reporting, petty cash, the approval of invoice payments and general ledger account coding. We also have consolidated our divisional audit functions and redeployed some of these resources for corporate audits. Further, we have restructured our corporate audit function, and are incorporating additional anti-corruption procedures into some of our audits, which are applied on a country-wide basis. We are also continuing to refine and enhance our procedures for Foreign Corrupt Practices Act (“FCPA”) compliance reviews, risk assessments, and legal audit procedures.

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

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

~~We have analyzed the BJ Services’ compliance programs and since the closing of the acquisition have begun to integrate our compliance programs within the operations of BJ Services as appropriate.~~

In June 2010, the Monitor issued his final reports certifying that “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.”

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

LIQUIDITY AND CAPITAL RESOURCES

Our objective in financing our business is to maintain adequate financial resources and access to sufficient liquidity. At ~~September 30, 2010,~~March 31, 2011, we had cash and cash equivalents of ~~$1.6~~$1.14 billion, short-term investments of ~~$250~~$251 million, and ~~we had~~ $1.7 billion available for borrowing under committed revolving credit facilities with commercial banks.

	•		An increase in accounts receivable in the first nine months of 2010 used $504 million in cash compared with providing $530 million in cash in the first nine months of 2009. The change in accounts receivable was primarily due to an increase in activity and an increase in the days of sales outstanding (defined as the average number of days our net trade receivables are outstanding based on quarterly revenues excluding the impact of the BJ Services acquisition) by approximately two days.

	•		~~Inventory used $161 million in cash in the first nine months of 2010 compared with providing $104 million in cash in the first nine months of 2009 driven by activity increases.~~

	•		An increase in accounts payable in the first nine months of 2010 provided $177 million in cash compared with using $245 million in cash in the first nine months of 2009. The increase was primarily due to an increase in operating assets to support increased activity.

	•		Accrued employee compensation and other accrued liabilities provided $97 million in cash in the first nine months of 2010 compared with using $96 million in cash in the first nine months of 2009. The increase was primarily due to a decrease in annual payments of employee bonuses and other benefits in the first nine months of 2010 compared to the prior year.

	•		Income taxes payable used $68 million in cash in the first nine months of 2010 compared with using $211 million in cash in the first nine months of 2009. The decrease in cash used was primarily due to federal income tax payments made in 2009 of $155 million for two quarterly installment payments from 2008. 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.

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.

$3.89 billion ~~compared with~~at December 31, ~~2009. This increase is primarily due to the sale of our $1.5 billion Notes and the assumption of $500 million principal amount of long-term debt from the BJ Services acquisition.~~2010. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was ~~0.22~~21% at ~~September 30, 2010~~March 31, 2011 and ~~0.20 at~~ December 31, ~~2009.~~2010.

We received proceeds of ~~$29~~$57 million and $1$2 million in the ~~nine~~three months ended ~~September 30,~~March 31, 2011 and 2010, ~~and 2009,~~ respectively, from the issuance of common stock ~~from~~through the exercise of stock options.

Our Board of Directors has authorized a program to repurchase our common stock from time to time. ~~For~~In the ~~nine~~three months ended ~~September 30,~~March 31, 2011 and 2010, ~~and 2009,~~ we did not repurchase ~~any~~ shares of our common stock. At ~~September 30, 2010,~~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 ~~$175~~$65 million and ~~$139~~$47 million in the ~~nine~~three months ended ~~September 30,~~March 31, 2011 and 2010, ~~and 2009,~~ respectively.

Available Credit Facilities

OnAt March 19, 2010, we entered into a credit agreement (the “2010 Credit Agreement”). The 2010 Credit Agreement is a three-year committed $1.2 billion revolving credit facility that expires on March 19, 2013. At September 30, 2010,31, 2011, we had $1.7 billion of committed revolving credit facilities with commercial ~~banks, consisting of the 2010 Credit Agreement ($1.2 billion) and a $500 million facility expiring on July 7, 2012. Both~~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 ~~the facility)~~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 ~~September 30, 2010,~~March 31, 2011, we were in compliance with all of the ~~facility covenants of both committed credit facilities.~~facilities’ covenants. There were no direct borrowings under the committed credit facilities during the quarter ended ~~September 30, 2010.~~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 ~~outstanding,~~ our ability to borrow under the facilities is reduced. At ~~quarter end,~~March 31, 2011, we had no outstanding commercial ~~paper outstanding.~~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~~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 ~~and relationships with major commercial and investment banks~~ would allow us to obtain interim financing over and above our existing credit facilities for any currently unforeseen significant needs or growth opportunities. We also believe that such interim financings could be funded with subsequent issuances of long-term debt or equity, if necessary.

Cash Requirements

In ~~2010,~~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 ~~2010,~~2011, we expect capital expenditures to be between ~~$1.7~~$2.3 billion ~~to $1.8~~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 ~~expect to~~will manage our capital expenditures to match market demand.

In ~~2010,~~2011, we ~~also~~ expect to make interest payments of between ~~$160~~$215 million and ~~$165~~$225 million, based on our current expectations of debt ~~levels during 2010.~~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 ~~$600 million~~$1.1 billion and ~~$650 million in 2010.~~

~~As of September 30, 2010, we have authorization remaining to repurchase approximately~~ $1.2 billion in ~~common stock.~~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 ~~$240~~$260 million and ~~$245~~$270 million in ~~2010;~~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 ~~2010,~~2011, we expect to contribute between ~~$90~~$65 million and ~~$110~~$85 million to our defined

benefit pension plans. We also expect to make benefit payments related to postretirement welfare plans of between ~~$15~~$16 million and $18 million, and we estimate we will contribute between ~~$171~~$185 million and ~~$180~~$200 million to our defined contribution plans.

We intend to use internal cash resources and available financing to pay for the pre-existing change of control and other contractual payments to certain BJ Services employees triggered by the acquisition that as of September 30, 2010 were $190 million, which we expect to be paid out in the fourth quarter of 2010.

~~NEW ACCOUNTING STANDARDS~~

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. The following additional factors, among others, with respect to the acquisition of BJ Services, could cause actual results to differ from those set forth in the forward-looking statements: preliminary estimates of acquisition accounting may change; the risk that the cost savings and any other synergies from the acquisition may not be realized or take longer to realize than expected; and the ability to successfully integrate the businesses. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in “Part II, Item 1A. Risk Factors” section contained herein, as well as the risk factors described in our ~~2009~~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”) athttp://~~www.sec.gov~~.www.sec.gov.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We conduct operations around the world in a number of different currencies. ~~The majority~~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 ~~September 30, 2010,~~March 31, 2011, we had outstanding foreign currency forward contracts with notional amounts aggregating ~~$187~~$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 ~~these~~the contracts outstanding at ~~September 30, 2010,~~March 31, 2011, based on quoted market prices as of March 31, 2011, for contracts with similar terms and maturity dates, was ~~approximately $7 million~~nominal, and was included in other 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 condensed statement of operations for the three ~~and nine~~ months ended ~~September 30, 2010~~March 31, 2011 was ~~$11 million and~~ $1 million ~~respectively,~~ of foreign exchange ~~gains,~~losses, which ~~are~~were included in marketing, general and administrative expenses. These ~~gains~~losses offset designated foreign exchange ~~losses~~gains resulting from the underlying exposures of the hedged items.

Interest Rate Swaps

~~In June 2009, we entered into two~~We are subject to interest rate ~~swap agreements (“~~risk on our debt and investment of cash and cash equivalents arising in the ~~Swap Agreements”) for~~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 ~~notional amount~~mix of ~~$250 million each in order~~fixed and variable rate debt that is intended to ~~hedge~~mitigate the exposure to changes in interest rates in the ~~fair market value~~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 ~~$500 million 6.5%~~ senior notes ~~maturing on November 15, 2013. Under~~so that the ~~Swap Agreements, we receive~~ interest ~~at a fixed rate of 6.5% and pay interest at a floating rate of one-month Libor plus a spread of 3.67% on one swap and three-month Libor plus a spread of 3.54%~~payable on the ~~second swap through November 15, 2013. The Swap Agreements~~senior notes effectively becomes linked to variable rates. Our interest rate swaps are designated and each qualifies as a fair value hedging ~~instrument~~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 ~~are both determined to be highly effective.~~maturity dates. The fair value of the ~~Swap Agreements~~swap agreements at ~~September 30, 2010,~~March 31, 2011, was ~~$30~~$20 million and was included in other assets in the consolidated condensed balance sheet. ~~The fair value was based on quoted market prices for contracts with similar terms and maturity dates.~~ The effect of interest rate swaps on the consolidated condensed statement of operations for the three ~~and nine~~ months ended ~~September 30, 2010~~March 31, 2011 was a reduction toin interest expense of ~~$2 million and $12 million, respectively.~~$3 million.

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 1312 of Notes to Unaudited Consolidated Condensed Financial Statements.

For additional ~~information~~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, ~~and~~ Item 3 of Part I of our ~~2009~~2010 Annual Report ~~for additional discussion~~and Note 14 of ~~legal proceedings.~~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 ~~2009~~2010 Annual Report ~~the Form 10-Q for the period ended March 31, 2010 and the Form 10-Q for the period ended June 30, 2010~~ as well as the following risk ~~factors:~~factor:

~~Many of our customers’ activity levels~~Our business is subject to geopolitical, terrorism risks and ~~spending for our products and services and ability to pay amounts owed us may be impacted by deterioration in the credit markets.~~other threats.

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 investmentsGeopolitical 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 third quarter of 2010, we are experiencing a delay in receiving payments from our customers in Venezuela. As of September 30, 2010, our accounts receivable in Venezuela totaled approximately 4% of our total accounts receivable. For the nine months ended September 30, 2010, Venezuela revenues were approximately 1% of our total consolidated revenues.

The moratorium on drilling offshore in the United States, as well as changes in and compliance with restrictions or regulations on offshore drilling in the U.S. Gulf of Mexico and in other areas around the world, has and mayterrorism risks continue to ~~adversely affect our business and operating results and reduce the need for our services~~grow in ~~those areas.~~

While the moratorium on drilling offshore in the United States was lifted on October 12, 2010, there is a delay in resuming operations related to drilling offshore in the United States and there is no assurance that operations related to drilling offshore in the United States will reach the same levels that existed prior to the moratorium. Any delay in resuming these activities or the failure of these activities to reach levels that existed prior to the moratorium has and could continue to adversely impact our operating results. The April 2010 Deepwater Horizon accident in the Gulf of Mexico and its aftermath has resulted in new and proposed legislation and regulation in the United States of the offshore oil and gas industry, which may result in substantial increases in costs or delays in drilling or other operations in the Gulf of Mexico, oil and gas projects becoming potentially non-economic, and a corresponding reduced demand for our services. We cannot predict with any certainty the impact of the moratorium or the substance or effect of any new or additional regulations. If the United States or otherseveral key countries where we ~~operate enact stricter restrictions on offshore drilling or further regulate offshore drilling or contracting services operations, higher operating costs~~do business. Geopolitical and terrorism risks could ~~result, which could, in turn, adversely affect~~lead to, among other things, a loss of our ~~business and operating results.~~

~~Uninsured claims and litigation.~~

~~While we were not involved~~investment in the ~~Deepwater Horizon accident, such events highlight~~country, impair the ~~risk involved~~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 ~~oil and gas industry. We could be impacted by the outcome of pending litigation as well as unexpected litigation or proceedings.~~conflict. We have ~~insurance coverage against operating hazards, including product liability claims~~assets in Libya consisting primarily of accounts receivable, inventory and ~~personal injury claims related to our products, to the extent deemed prudent by our management~~property, plant and ~~to the extent insurance is available; however, no assurance can be given that the nature and amount~~equipment totaling approximately $160 million as of ~~that insurance will be sufficient to fully indemnify us against liabilities arising out of pending and future claims and~~March 31, 2011.

3124

litigation. This insurance has deductibles or self-insured retentions and contains certain coverage exclusions. The insurance does not cover damages from breach of contract by us or based on alleged fraud or deceptive trade practices. In addition, the following risks apply with respect to our insurance coverage:

	•		~~we may not be able to continue to obtain insurance on commercially reasonable terms;~~

	•		~~we may be faced with types of liabilities that will not be covered by our insurance;~~

	•		~~our insurance carriers may not be able to meet their obligations under the policies; or~~

	•		~~the dollar amount of any liabilities may exceed our policy limits.~~

Whenever possible, we obtain agreements from customers that limit our liability. Insurance and customer agreements do not provide complete protection against losses and risks, and our results of operations could be adversely affected by unexpected claims not covered by insurance.

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 ~~September 30, 2010.~~March 31, 2011.

Issuer Purchases of Equity Securities

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

July 1-31, 2010 23,548 $ 48.27 — $ — 23,548 $ —
August 1-31, 2010 11,528 40.69 — — 11,528 —
September 1-30, 2010 4,162 39.20 — — 4,162 —

Total 39,238 $ 45.08 — $ — 39,238 $ 1,197,127,803


					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 ~~September 30, 2010.~~March 31, 2011.

(3)		Our Board of Directors has authorized a plan to repurchase our common stock from time to time. During the ~~third~~first quarter of ~~2010,~~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.

~~4.1~~		~~Indenture, dated October 28, 2008, between Baker Hughes Incorporated~~
10.77+*		Compensation Table for Named Executive Officers and ~~The Bank of New York Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 29, 2008).~~Directors.

~~4.2~~		Officers’ Certificate of Baker Hughes Incorporated dated August 24, 2010 establishing the 5.125% Senior Notes due 2040 (filed as Exhibit 4.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed August 24, 2010).

~~4.3~~		~~Form of 5.125% Senior Notes due 2040 (filed as Exhibit 4.3 to Current Report of Baker Hughes Incorporated on Form 8-K filed August 24, 2010).~~

~~10.1+~~		Performance Goals adopted October 21, 2010 for the Performance Unit Awards Granted in 2009 under the Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 22, 2010).

~~10.2+~~		Performance Goals adopted October 21, 2010 for the Performance Unit Awards Granted in 2010 under the Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan (filed as Exhibit 10.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 22, 2010).

~~10.3+~~		Performance Goals adopted October 21, 2010 for the Performance Unit Awards to be Granted in 2011 under the Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan (filed as Exhibit 10.3 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 22, 2010).

31.1*		Certification of Chad C. Deaton, Chief Executive Officer, ~~dated November 5, 2010,~~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, ~~dated November 5, 2010,~~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, ~~dated November 5, 2010,~~ 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


	Page No.
PART I — FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

Consolidated Condensed Statements of Operations (Unaudited) — Three months ended March 31, 2011 and ~~nine months ended September 30,~~ 2010 ~~and 2009~~		2

Consolidated Condensed Balance Sheets (Unaudited) — ~~September 30, 2010~~March 31, 2011 and December 31, ~~2009~~2010		3

Consolidated Condensed Statements of Cash Flows (Unaudited) — ~~Nine~~Three months ended ~~September 30,~~March 31, 2011 and 2010 ~~and 2009~~		4

Notes to Unaudited Consolidated Condensed Financial Statements		5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		1814

Item 3. Quantitative and Qualitative Disclosures About Market Risk		3023

Item 4. Controls and Procedures		3024

PART II — OTHER INFORMATION

Item 1. Legal Proceedings		3124

Item 1A. Risk Factors		3124

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		3225

Item 3. Defaults Upon Senior Securities		3225

Item 4. [Removed and Reserved]		3225

Item 5. Other Information		3225

Item 6. Exhibits		3225

Signatures		3427
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


	September 30,			December 31,			March 31,		December 31,
	2010			2009			2011		2010

Land	$	182		$	81		$	191	$	191
Buildings and improvements		1,506			1,136			1,673		1,605
Machinery and equipment		6,097			3,384			6,600		6,409
Rental tools and equipment		2,399			2,228			2,568		2,472

Subtotal		10,184			6,829			11,032		10,677
Accumulated depreciation		(4,076	)		(3,668	)
Less: Accumulated depreciation								4,600		4,367

Total	$	6,108		$	3,161		$	6,432	$	6,310


Cash consideration paid: 295 million shares at $2.69	$	793
Equity consideration paid: 118 million shares valued $51.24		6,048
Fair value of BJ Services options assumed		56

Fair value of consideration transferred	$	6,897


			Other Postretirement
	Pension Benefit Plans		Benefit Plans

Projected benefit obligation	$	280	$	26
Fair value of plan assets		160		—

Net Unfunded Status	$	120	$	26


Amounts recognized in the Consolidated Condensed Balance Sheet:

Liabilities for pensions and other postretirement benefits	$	120	$	26


Total Assets	September 30, 2010		December 31, 2009

North America	$	8,071	$	2,596
Latin America		2,600		1,168
Europe/Africa/Russia Caspian		3,425		2,248
Middle East/Asia Pacific		2,910		1,731
Industrial and Other		3,551		2,127

Total Oilfield Operations		20,557		9,870
Corporate and Other		1,905		1,569

Total	$	22,462	$	11,439


													Europe/			Middle
	Drilling			Completion									Africa/			East/
	and			and			North			Latin			Russia			Asia		Industrial
	Evaluation			Production			America			America			Caspian			Pacific		& Other		Total

Balance as of December 31, 2009	$	979		$	439		$	—		$	—		$	—		$	—	$	—	$	1,418

Reallocation for change in segments		(980	)		(439	)		494			175			412			267		71		—
Acquisitions		—			—			2,585			501			413			459		330		4,288
Other adjustments		1			—			(4	)		(2	)		(7	)		3		17		8

Balance as of September 30, 2010	$	—		$	—		$	3,075		$	674		$	818		$	729	$	418	$	5,714


			Capital					Accumulated								Capital
			in Excess					Other								in Excess
	Common		of		Retained			Comprehensive						Common		of			Retained			Accumulated Other			Noncontrolling
	Stock		Par Value		Earnings			Loss			Total			Stock		Par Value			Earnings			Comprehensive Loss			Interest		Total

Balance, December 31, 2009	$	312	$	874	$	6,512		$	(414	)	$	7,284
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						477														381						3
Foreign currency translation adjustments									(41	)													66
Defined benefit pension plans									18
Defined benefit pension plans, net of tax of $2																							(1	)
Total comprehensive income												454																449
Issuance of common stock pursuant to employee stock plans		1		23								24			2		52											54
Issuance of common stock to acquire BJ Services		118		5,986								6,104
Tax provision on stock plans																	5											5
Stock-based compensation				66								66					29											29
Cash dividends ($0.45 per share)						(175	)					(175	)
Cash dividends ($0.15 per share)																				(65	)							(65	)
Change in noncontrolling interest associated with purchase price adjustment																										66		66

Balance, September 30, 2010	$	431	$	6,949	$	6,814		$	(437	)	$	13,757
Balance, March 31, 2011														$	434	$	7,090		$	7,399		$	(355	)	$	255	$	14,823


	Three Months Ended
	September 30,				Increase
	2010		2009		(decrease)		% Change

Segment Revenues:
North America	$	2,006	$	714	$	1,292		181	%
Latin America		431		257		174		68	%
Europe/Africa/Russia Caspian		757		626		131		21	%
Middle East/Asia Pacific		606		463		143		31	%
Industrial and Other		278		172		106		62	%

Segment revenues	$	4,078	$	2,232	$	1,846		83	%


	Three Months Ended September 30,
	2010				2009

Revenues	$	4,078	100	%	$	2,232	100	%
Cost of revenues		3,189	78	%		1,761	79	%
Research and engineering		118	3	%		88	4	%
Marketing, general and administrative		354	9	%		272	12	%


**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


	BAKER HUGHES INCORPORATED (Registrant)
Date: ~~November 5, 2010~~May 3, 2011	By: ~~/s/~~	/s/ PETER A. RAGAUSS
		Peter A. Ragauss
		Senior Vice President and Chief Financial Officer


Date: ~~November 5, 2010~~May 3, 2011	By: ~~/s/~~	/s/ ALAN J. KEIFER
		Alan J. Keifer
		Vice President and Controller