BAKER HUGHES a GE (BHI) 10-Q 2011 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2011

OR

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

Commission File Number 1-9397

Baker Hughes Incorporated

(Exact name of registrant as specified in its charter)

Delaware	76-0207995
(State or other jurisdiction	(I.R.S. Employer Identification No.)
of incorporation or organization)
2929 Allen Parkway, Suite 2100, Houston, Texas	77019-2118
(Address of principal executive offices)	(Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YESþ NOo

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

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

Large accelerated filerþ	Accelerated filero	Non-accelerated 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 October 27, 2011, the registrant has outstanding 436,465,887 shares of Common Stock, $1 par value per share.

INDEX

	Page No.
PART I — FINANCIAL INFORMATION
Item 1.    Financial Statements (Unaudited)
Consolidated Condensed Statements of Operations (Unaudited) — Three and nine months ended September 30, 2011 and 2010		2
Consolidated Condensed Balance Sheets (Unaudited) — September 30, 2011 and December 31, 2010		3
Consolidated Condensed Statements of Cash Flows (Unaudited) — Nine months ended September 30, 2011 and 2010		4
Notes to Unaudited Consolidated Condensed Financial Statements		5
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
Item 3.    Quantitative and Qualitative Disclosures About Market Risk		24
Item 4.    Controls and Procedures		24
PART II — OTHER INFORMATION
Item 1.    Legal Proceedings		25
Item 1A. Risk Factors		25
Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds		25
Item 3.    Defaults Upon Senior Securities		26
Item 4.    [Removed and Reserved]		26
Item 5.    Other Information		26
Item 6.    Exhibits		26
Signatures		27
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

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Baker Hughes Incorporated
Consolidated Condensed Statements of Operations
(In millions, except per share amounts)
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Revenue:
Sales	$	1,670		$	1,391		$	4,660		$	4,001
Services		3,508			2,687			9,784			5,990
Total revenue		5,178			4,078			14,444			9,991
Costs and expenses:
Cost of sales		1,353			1,176			3,785			3,132
Cost of services		2,578			2,013			7,361			4,631
Research and engineering		117			118			337			324
Marketing, general and administrative		313			354			887			971
Acquisition-related costs		—			12			—			78
Total costs and expenses		4,361			3,673			12,370			9,136
Operating income		817			405			2,074			855
Interest expense, net		(58	)		(39	)		(164	)		(93	)
Loss on early extinguishment of debt		(40	)		—			(40	)		—
Income before income taxes		719			366			1,870			762
Income taxes		(13	)		(111	)		(445	)		(285	)
Net income		706			255			1,425			477
Net income (loss) attributable to noncontrolling interests		—			—			—			—
Net income attributable to Baker Hughes	$	706		$	255		$	1,425		$	477
Basic income per share attributable to Baker Hughes	$	1.62		$	0.59		$	3.27		$	1.25
Diluted income per share attributable to Baker Hughes	$	1.61		$	0.59		$	3.25		$	1.25
Cash dividends per share	$	0.15		$	0.15		$	0.45		$	0.45

See accompanying notes to unaudited consolidated condensed financial statements.

2

Baker Hughes Incorporated
Consolidated Condensed Balance Sheets
(In millions)
(Unaudited)

	September 30,			December 31,
	2011			2010
ASSETS
Current Assets:
Cash and cash equivalents	$	803		$	1,456
Short-term investments		—			250
Accounts receivable — less allowance for doubtful accounts (2011 - $223; 2010 - $162)		4,977			3,942
Inventories, net		3,053			2,594
Deferred income taxes		254			234
Other current assets		254			231
Total current assets		9,341			8,707
Property, plant and equipment — net of accumulated depreciation (2011 - $5,035; 2010 - $4,367)		6,966			6,310
Goodwill		5,947			5,869
Intangible assets, net		1,494			1,569
Other assets		603			531
Total assets	$	24,351		$	22,986
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	1,688		$	1,496
Short-term borrowings and current portion of long-term debt		54			331
Accrued employee compensation		686			589
Income taxes payable		53			219
Other accrued liabilities		517			504
Total current liabilities		2,998			3,139
Long-term debt		3,846			3,554
Deferred income taxes and other tax liabilities		1,125			1,360
Liabilities for pensions and other postretirement benefits		469			483
Other liabilities		150			164
Commitments and contingencies
Stockholders’ Equity:
Common stock		436			432
Capital in excess of par value		7,244			7,005
Retained earnings		8,313			7,083
Accumulated other comprehensive loss		(447	)		(420	)
Baker Hughes stockholders’ equity		15,546			14,100
Noncontrolling interest		217			186
Total stockholders’ equity		15,763			14,286
Total liabilities and stockholders’ equity	$	24,351		$	22,986

See accompanying notes to unaudited consolidated condensed financial statements.

3

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

	Nine Months Ended
	September 30,
	2011			2010
Cash flows from operating activities:
Net income	$	1,425		$	477
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		978			743
Stock-based compensation costs		85			66
Provision (benefit) for deferred income taxes		(312	)		(155	)
Gain on disposal of assets		(124	)		(79	)
Loss on early extinguishment of debt		40			—
Provision for doubtful accounts		76			19
Changes in operating assets and liabilities:
Accounts receivable		(1,107	)		(504	)
Inventories		(463	)		(161	)
Accounts payable		183			177
Accrued employee compensation and other accrued liabilities		84			97
Income taxes payable		(189	)		(68	)
Other		6			(34	)
Net cash flows from operating activities		682			578
Cash flows from investing activities:
Expenditures for capital assets		(1,651	)		(1,005	)
Proceeds from disposal of assets		215			152
Purchase of short-term investments		—			(250	)
Proceeds from maturities of short-term investments		250			—
Acquisition of businesses, net of cash acquired		(5	)		(852	)
Other investing items, net		14			39
Net cash flows from investing activities		(1,177	)		(1,916	)
Cash flows from financing activities:
Net (payments) borrowings of commercial paper and other short-term debt		(41	)		9
Net proceeds of long-term debt		742			1,479
Repayment of long-term debt		(813	)		—
Proceeds from termination of interest rate swap agreements		26			—
Proceeds from issuance of common stock		144			29
Dividends		(195	)		(175	)
Purchase of noncontrolling interest		(26	)		—
Other financing items, net		(1	)		2
Net cash flows from financing activities		(164	)		1,344
Effect of foreign exchange rate changes on cash		6			5
Increase (decrease) in cash and cash equivalents		(653	)		11
Cash and cash equivalents, beginning of period		1,456			1,595
Cash and cash equivalents, end of period	$	803		$	1,606
Supplemental cash flows disclosures:
Income taxes paid, net of refunds	$	934		$	516
Interest paid	$	184		$	96
Supplemental disclosure of noncash investing activities:
Capital expenditures included in accounts payable	$	78		$	33

See accompanying notes to unaudited consolidated condensed financial statements.

4

Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 1. GENERAL

Nature of Operations

     Baker Hughes Incorporated (“Baker Hughes,” “Company,” “we,” “our” or “us”) is engaged in the oilfield services industry. We are a leading supplier of wellbore-related products and technology services and provide products and services for drilling, pressure pumping, formation evaluation, completion and production, and reservoir development services 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 and pursuant to the rules and regulations of the Securities and Exchange Commission 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/A for the year ended December 31, 2010 (“2010 Annual Report”). We believe the unaudited consolidated condensed financial statements included herein reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. In the notes to the unaudited consolidated condensed financial statements, all dollar and share amounts in tabulations are in millions of dollars and shares, respectively, unless otherwise indicated.

Accounting Standards Updates

     In May 2011, the Financial Accounting Standards Board (“FASB”) issued an update to Accounting Standards Codification (“ASC”) 820,Fair Value Measurement. The Accounting Standards Update (“ASU”) conforms certain sections of ASC 820 to International Financial Reporting Standards in order to provide a single converged guidance on the measurement of fair value. This update also expands the existing disclosure requirements for fair value measurements. This ASU is effective for interim and annual periods beginning after December 15, 2011. We will adopt this ASU prospectively in the first quarter of 2012. We currently do not expect this ASU to have a material impact, if any, on our consolidated condensed financial statements.

     In June 2011, the FASB issued an update to ASC 220,Comprehensive Income. This ASU requires entities to present components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements that would include reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statements. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We will adopt the new presentation requirements of this ASU retrospectively in the first quarter of 2012.

     In September 2011, the FASB issued an update to ASC 350,Intangibles — Goodwill and Other. This ASU amends the guidance in ASC 350-20 on testing for goodwill impairment. The revised guidance allows entities testing for goodwill impairment to have the option of performing a qualitative assessment before calculating the fair value of the reporting unit. The ASU does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirement to test annually for impairment. The ASU is limited to goodwill and does not amend the annual requirement for testing other indefinite-lived intangible assets for impairment. The ASU is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We will adopt this ASU for our 2012 goodwill impairment testing. We do not expect this ASU to have a material 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 (“BJ Services”) in a cash and stock transaction valued at $6,897 million. BJ Services is a leading provider of pressure pumping and other oilfield services and was acquired to expand the product offerings of the Company. Total consideration consisted of $793 million in cash, 118 million shares valued at $6,048 million, and Baker Hughes options with a fair value of $56 million in exchange for BJ Services options. We also assumed all outstanding stock options held by BJ Services employees and directors.

5

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

Recording of Assets Acquired and Liabilities Assumed

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

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

     During the quarter ended March 31, 2011, we increased our step-up adjustment related to noncontrolling interests in certain BJ Services entities by $68 million to $202 million and reduced our step-up adjustment related to deferred tax liabilities and other taxes by $21 million to $1,262 million as part of the acquisition accounting related to fair market value adjustments for acquired intangible assets and property, plant and equipment (“PP&E”) as well as for uncertain tax positions taken in prior years.

Pro Forma Impact of the Acquisition

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

	Nine Months Ended
	September 30, 2010
	Pro Forma
Revenue	$	11,480
Net income	$	493
Basic net income per share	$	1.14
Diluted net income per share	$	1.14

6

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

NOTE 3. SEGMENT INFORMATION

     We conduct our business primarily through operating segments that are aligned with our geographic regions, which have been aggregated into the following five reportable segments:

• North America (U.S. Land, U.S. Gulf of Mexico and Canada)

• Latin America

• Europe/Africa/Russia Caspian

• Middle East/Asia Pacific

• Industrial Services and Other

     We have aggregated our operating segments within each reportable segment because they have similar economic characteristics and because the long-term financial performance of the segments is affected by similar economic conditions. The performance of our segments is evaluated based on profit before tax, which is defined as income before income taxes, net interest expense, corporate expenses, 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 on April 28, 2010.

     Summarized financial information is shown in the following table.

	Three Months Ended					Three Months Ended
	September 30, 2011					September 30, 2010
Segments	Revenue		Profit (loss)			Revenue		Profit (loss)
North America	$	2,716	$	607		$	2,006	$	340
Latin America		568		71			431		9
Europe/Africa/Russia Caspian		850		105			757		47
Middle East/Asia Pacific		708		84			606		39
Industrial Services and Other		336		28			278		36
Total Operations		5,178		895			4,078		471
Corporate and Other		—		(78	)		—		(54	)
Interest expense, net		—		(58	)		—		(39	)
Loss on early extinguishment of debt		—		(40	)		—		—
Acquisition-related costs		—		—			—		(12	)
Total	$	5,178	$	719		$	4,078	$	366

	Nine Months Ended					Nine Months Ended
	September 30, 2011					September 30, 2010
Segments	Revenue		Profit (loss)			Revenue		Profit (loss)
North America	$	7,436	$	1,507		$	4,411	$	685
Latin America		1,583		205			1,087		31
Europe/Africa/Russia Caspian		2,427		243			2,213		196
Middle East/Asia Pacific		2,068		251			1,590		109
Industrial Services and Other		930		76			690		71
Total Operations		14,444		2,282			9,991		1,092
Corporate and Other		—		(208	)		—		(159	)
Interest expense, net		—		(164	)		—		(93	)
Loss on early extinguishment of debt		—		(40	)		—		—
Acquisition-related costs		—		—			—		(78	)
Total	$	14,444	$	1,870		$	9,991	$	762

7

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

NOTE 4. EARNINGS PER SHARE

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
Weighted average common shares outstanding for basic EPS		437		432		436		381
Effect of dilutive securities — stock plans		2		1		2		1
Adjusted weighted average common shares outstanding for diluted EPS		439		433		438		382
Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than the average market price for the period		3		7		3		7

NOTE 5. INCOME TAXES

     In the third quarter of 2011, total income tax expense of $13 million included a $214 million tax benefit associated with the reorganization of certain foreign subsidiaries to better align the Baker Hughes and BJ Services entities. As a result of the reorganization, previously accrued U.S. deferred income taxes related to those subsidiaries have been reduced by Baker Hughes foreign tax credits now available to offset future U.S. taxes.

NOTE 6. INVENTORIES

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

	September 30,		December 31,
	2011		2010
Finished goods	$	2,683	$	2,283
Work in process		222		181
Raw materials		148		130
Total	$	3,053	$	2,594

NOTE 7. GOODWILL AND INTANGIBLE ASSETS

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

							Europe/		Middle			Industrial
							Africa/		East/			Services
	North			Latin			Russia		Asia			and
	America			America			Caspian		Pacific			Other		Total
Balance as of December 31, 2010	$	2,731		$	879		$	936	$	895		$	428	$	5,869
Purchase price adjustments for previous acquisitions		314			(293	)		86		(42	)		12		77
Acquisitions		4			—			—		—			—		4
Other adjustments		(3	)		—			—		—			—		(3	)
Balance as of September 30, 2011	$	3,046		$	586		$	1,022	$	853		$	440	$	5,947

8

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

     Intangible assets are comprised of the following:

	September 30, 2011						December 31, 2010
	Gross		Less:				Gross		Less:
	Carrying		Accumulated				Carrying		Accumulated
	Amount		Amortization		Net		Amount		Amortization		Net
Definite lived intangibles:
Technology	$	761	$	218	$	543	$	760	$	181	$	579
Contract-based		18		9		9		20		11		9
Trade names		80		18		62		84		18		66
Customer relationships		496		66		430		495		39		456
Subtotal		1,355		311		1,044		1,359		249		1,110
Indefinite-lived intangibles:
Trade name		360		—		360		360		—		360
In-process research and development		90		—		90		99		—		99
Total	$	1,805	$	311	$	1,494	$	1,818	$	249	$	1,569

     Intangible assets are amortized either on a straight-line basis with estimated useful lives ranging from 2 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 ranges from 15 to 30 years.

     Amortization expense for intangible assets included in net income for the three months and nine months ended September 30, 2011 was $25 million and $71 million, respectively, and is estimated to be $24 million for the remainder of fiscal year 2011. Estimated amortization expense for each of the subsequent five fiscal years is expected to be as follows: 2012 — $94 million; 2013 — $93 million; 2014 — $92 million; 2015 — $90 million; and 2016 — $89 million.

NOTE 8. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

     Our financial instruments include cash and cash equivalents, 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, 2011 and December 31, 2010 approximates their carrying value as reflected in our consolidated condensed balance sheets.

Short-term Investments

     During the year ended December 31, 2010, we purchased short-term investments consisting of $250 million in U.S. Treasury Bills, which matured in May 2011 and were used to repay the $250 million principal amount of our 5.75% notes that matured in June 2011 (“5.75% Notes”).

Debt

     The estimated fair value of total debt at September 30, 2011 and December 31, 2010 was $4,635 million and $4,298 million, respectively, which differs from the carrying amount of $3,900 million and $3,885 million, respectively, included in our consolidated condensed balance sheets. The fair value was determined using Level 2 inputs including quoted period end market prices.

Foreign Currency Forward Contracts

     We conduct our business in over 80 countries around the world, and we are exposed to market risks resulting from fluctuations in foreign currency exchange rates. A number of our significant foreign subsidiaries have designated the local currency as their functional currency. We transact in various foreign currencies and have established a program that primarily utilizes foreign currency forward contracts to reduce the risks associated with the effects of certain foreign currency exposures. Under this program, our strategy is to have gains or losses on the foreign currency forward contracts mitigate the foreign currency transaction gains or losses to the extent practical. These foreign currency exposures typically arise from changes in the value of assets and liabilities which are denominated in currencies other than the functional currency. Our foreign currency forward contracts generally settle in less than 180

9

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

days. We do not use these forward contracts for trading or speculative purposes. We designate these forward contracts as fair value hedging instruments and, accordingly, we record the fair value of these contracts as of the end of our reporting period to our consolidated 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.

     We had outstanding foreign currency forward contracts with notional amounts aggregating $157 million and $156 million to hedge exposure to currency fluctuations in various foreign currencies at September 30, 2011 and December 31, 2010, respectively. These contracts are designated and qualify as fair value hedging instruments. The fair value was determined using 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. We may use interest rate swaps to manage the economic effect of fixed rate obligations associated with certain debt.

     In September 2011, we redeemed in full our $500 million 6.5% fixed rate senior notes maturing November 2013 (“6.5% Notes”). Consequently, we terminated two related interest rate swap agreements resulting in a gain on the swap agreements of $25 million. The two swap agreements were entered into in June 2009 for a notional amount of $250 million each in order to hedge changes in the fair market value of the debt. The swap agreements had been designated and each qualified as a fair value hedging instrument.

Fair Value of Derivative Instruments

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

		Fair Value
Derivative	Balance Sheet Location	September 30, 2011		December 31, 2010
Foreign Currency Forward Contracts	Other current assets	$	3	$	—
Foreign Currency Forward Contracts	Other accrued liabilities	$	8	$	2
Interest Rate Swaps	Other assets	$	—	$	24

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

		Gain (Loss) Recognized in Income
		Three Months Ended					Nine Months Ended
		September 30,					September 30,
Derivative	Statement of Operations Location	2011			2010		2011			2010
Foreign Currency Forward Contracts	Marketing, general and administrative	$	(3	)	$	11	$	(6	)	$	1
Interest Rate Swaps	Interest expense	$	2		$	2	$	8		$	12

NOTE 9. INDEBTEDNESS

     In August 2011, we completed a private placement of $750 million 3.2% senior notes that have registration rights and will mature in August 2021 (“3.2% Notes”) under our Indenture dated October 28, 2008. Net proceeds from the offering were approximately $742 million after deducting the underwriting discounts and expenses of the offering. Interest is payable February 15 and August 15 of each year. The 3.2% Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future 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 3.2% Notes at any time, at the applicable make-whole redemption prices plus accrued and unpaid interest to the date of redemption. In September 2011, we used $563 million of the net proceeds from the offering to redeem in full our 6.5% Notes, and the remainder will be used for general corporate purposes, which could include funding on-going operations, business acquisitions and repurchases of our common stock. The redemption of our 6.5% Notes resulted in a payment of a redemption premium of $63 million and in a pretax loss on the early extinguishment of this debt of $40 million, which includes the redemption

10

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

premium, the write off of the remaining original debt issuance costs and debt discount, partially offset by the $25 million gain from the termination of two related interest rate swap agreements.

     In June 2011, we repaid the $250 million principal amount of our 5.75% Notes using proceeds from U.S. Treasury Bills that matured in May 2011.

     In September 2011, we entered into a five-year committed $2.5 billion revolving credit facility maturing in September 2016. The new revolving credit facility replaced our existing committed revolving credit facilities of $500 million maturing in July 2012 and $1.2 billion maturing in March 2013, both of which were terminated in September 2011. There were no direct borrowings under committed revolving credit facilities during the nine months ended September 30, 2011. We also have a commercial paper program under which we may issue up to $1.0 billion in commercial paper with maturity of no more than 270 days. To the extent we have outstanding commercial paper, our ability to borrow under the facility is reduced. At September 30, 2011, we had no outstanding commercial paper.

NOTE 10. EMPLOYEE BENEFIT PLANS

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

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

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

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

													Other Postretirement
	U.S. Pension Benefits						Non-U.S. Pension Benefits						Benefits
	2011			2010			2011			2010			2011			2010
Service cost	$	28		$	24		$	6		$	5		$	6		$	7
Interest cost		15			16			24			20			6			8
Expected return on plan assets		(24	)		(21	)		(24	)		(17	)		—			—
Amortization of prior service cost (benefit)		—			—			—			—			(2	)		1
Amortization of net loss		7			9			3			3			—			—
Net periodic cost (benefit)	$	26		$	28		$	9		$	11		$	10		$	16

     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 changes in the fair value of our U.S. and Non-U.S. pension plans’ assets using Level 3 unobservable inputs for the three months and nine months ended September 30, 2011 were as follows:

	Three Months Ended September 30, 2011
	U.S.			Global					Non-U.S.			Non-U.S.
	Property			Property		Hedge			Property			Insurance
	Fund			Fund		Funds			Fund			Contracts		Total
Ending balance at June 30, 2011	$	15		$	—	$	102		$	20		$	16	$	153
Purchases (sales)		(7	)		3		4			—			—		—
Unrealized gains (loss)		—			—		(4	)		(1	)		—		(5	)
Transfers from Level 2 to Level 3		—			—		—			—			—		—
Ending balance at September 30, 2011	$	8		$	3	$	102		$	19		$	16	$	148

11

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

	Nine Months Ended September 30, 2011
	U.S.			Global				Non-U.S.		Non-U.S.
	Property			Property		Hedge		Property		Insurance
	Fund			Fund		Funds		Fund		Contracts		Total
Ending balance at December 31, 2010	$	14		$	—	$	—	$	19	$	16	$	49
Purchases (sales)		(7	)		3		4		—		—		—
Unrealized gains (loss)		1			—		—		—		—		1
Transfers from Level 2 to Level 3		—			—		98		—		—		98
Ending balance at September 30, 2011	$	8		$	3	$	102	$	19	$	16	$	148

     Beginning in 2011, the U.S. pension plan began purchasing 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.

NOTE 11. COMMITMENTS AND CONTINGENCIES

LITIGATION

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

     We were among several unrelated companies who received a subpoena from the Office of the New York Attorney General, dated June 17, 2011. The subpoena received by the Company seeks information and documents relating to, among other things, natural gas development and hydraulic fracturing. We are reviewing the subpoena and discussing its contents with the New York Attorney General’s office in anticipation of our responding as appropriate.

     In July 2011, the Company settled the previously reported customer claim against BJ Services relating to the move of a stimulation vessel out of the North Sea market. The settlement did not have a material effect on our consolidated condensed financial statements.

OTHER

     In the normal course of business with customers, vendors and others, we have entered into off-balance sheet arrangements, such as surety bonds for performance, letters of credit and other bank issued guarantees, which totaled approximately $1.2 billion at September 30, 2011. None of the off-balance sheet arrangements either has, or is likely to have, a material effect on our consolidated condensed financial statements.

12

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

NOTE 12. STOCKHOLDERS’ EQUITY

     The following tables summarize our stockholders’ equity activity.

			Capital					Accumulated
			in Excess					Other
	Common		of		Retained			Comprehensive			Noncontrolling
	Stock		Par Value		Earnings			Loss			Interest			Total
Balance at December 31, 2010	$	432	$	7,005	$	7,083		$	(420	)	$	186		$	14,286
Comprehensive income:
Net income attributable to Baker Hughes						1,425
Foreign currency translation adjustments									(32	)		(1	)
Defined benefit pension plan, net of tax of ($4)									5
Total comprehensive income															1,397
Issuance of common stock pursuant to employee stock plans		4		126											130
Tax benefit on stock plans				17											17
Stock-based compensation costs				85											85
Cash dividends ($0.45 per share)						(195	)								(195	)
Purchase of subsidiary shares of noncontrolling interests				11								(37	)		(26	)
Dividends paid to noncontrolling interests												(5	)		(5	)
Capital contribution from noncontrolling interest, and other												8			8
Change in noncontrolling interest associated with purchase price adjustment												66			66
Balance at September 30, 2011	$	436	$	7,244	$	8,313		$	(447	)	$	217		$	15,763

			Capital					Accumulated
			in Excess					Other
	Common		of		Retained			Comprehensive			Noncontrolling
	Stock		Par Value		Earnings			Loss			Interest		Total
Balance at December 31, 2009	$	312	$	874	$	6,512		$	(414	)	$	—	$	7,284
Comprehensive income:
Net income						477
Foreign currency translation adjustments									(41	)
Defined benefit pension plans, net of tax of $(5)									18
Total comprehensive income														454
Issuance of common stock pursuant to employee stock plans		1		21										22
Issuance of common stock to acquire BJ Services		118		5,986										6,104
Tax benefit on stock plans				2										2
Stock-based compensation costs				66										66
Cash dividends ($0.45 per share)						(175	)							(175	)
Balance at September 30, 2010	$	431	$	6,949	$	6,814		$	(437	)	$	—	$	13,757

     Total accumulated other comprehensive loss, net of tax, consisted of the following:

	September 30, 2011			December 31, 2010
Foreign currency translation adjustments	$	(293	)	$	(261	)
Pension and other postretirement benefits		(154	)		(159	)
Total accumulated other comprehensive loss	$	(447	)	$	(420	)

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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/A for the year ended December 31, 2010 (“2010 Annual Report”). Phrases such as “Company,” “we,” “our” and “us” intend to refer to Baker Hughes Incorporated when used.

EXECUTIVE SUMMARY

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

• drilling and evaluation of oil and gas wells;

• completion and production of oil and gas wells;

• other industries, including downstream refining and process and pipeline industries; and reservoir development services.

     We operate our business primarily through geographic regions that have been aggregated into five reportable segments: North America, Latin America, Europe/Africa/Russia Caspian, Middle East/Asia Pacific and Industrial Services and Other. The four geographical segments represent our oilfield operations.

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

     For the third quarter of 2011, we generated revenue of $5.18 billion, an increase of $1.10 billion or 27% compared to the same quarter a year ago. For the first nine months of 2011, revenue was $14.44 billion, an increase of $4.45 billion or 45% compared to the first nine months of 2010. The increase in revenue for both periods was due to the increase in activity and service intensity primarily in North America, driven by oil-directed drilling mainly in unconventional reservoirs. The increase in revenue for the first nine months of 2011 was also due to the acquisition of BJ Services Company (“BJ Services”) which occurred in April of 2010.

     Net income attributable to Baker Hughes was $706 million for the third quarter of 2011 compared to $255 million for the same quarter a year ago; and was $1.43 billion for the first nine months of 2011 compared to $477 million for the same period a year ago. The increase in net income for both periods was chiefly due to increased activity in North America and to a lesser extent internationally. Additionally, we recorded a $214 million tax benefit associated with the reorganization of certain foreign subsidiaries in the third quarter of 2011. The increase in net income for the first nine months of 2011 was also due to the acquisition of BJ Services.

     At September 30, 2011, we had approximately 55,100 employees compared to approximately 53,100 employees at December 31, 2010.

BUSINESS ENVIRONMENT

     Global economic growth and the resultant demand for oil and natural gas are the primary drivers of our customers’ expenditures to develop and produce oil and gas. The expansion of the global economy, following the recession of 2008/2009, continued through 2010 and into 2011. Spending by oil and natural gas exploration and production companies, which is dependent upon their forecasts regarding the expected future supply and future demand for oil and natural gas products and their estimates of costs to find, develop, and produce reserves, increased in the first nine months of 2011 compared to the same period a year ago. Changes in oil and natural gas exploration and production spending resulted in increased demand for our products and services, which is reflected in the rig count and other measures. Although growth in our customers’ activity has expanded throughout the first nine months of 2011, commodity prices experienced a significant decline in the third quarter of 2011. This decline was primarily driven by concerns surrounding European fiscal issues, growth reduction in China and the threat of a U.S. recession; all are factors that can affect the demand for oil and natural gas.

     In North America, customer spending on oil projects increased in 2011, resulting in a 58% increase in the North America oil-directed rig count in the third quarter of 2011 compared to the same period a year ago. The increase in oil-directed drilling reflected the global price of oil, which contracted somewhat during the third quarter of 2011, but continues to trade at an energy equivalent

14

premium relative to natural gas in North America. Gas-directed drilling activity declined 8% in the third quarter of 2011 compared to the same period a year ago, as decreased activity in unconventional shale gas plays with relatively little associated natural gas liquids (dry gas) was partially offset by increased activity in the unconventional liquid-rich shale gas plays with relatively high volumes of associated natural gas liquids (wet gas). Despite relatively weak natural gas prices, spending on gas-directed projects in the third quarter of 2011 was supported by: (1) associated production of natural gas liquids and crude oil in certain basins; (2) hedges on production made in prior periods when future prices were higher; (3) the need of companies to drill and produce natural gas to hold leases acquired in earlier periods; and (4) the influx of equity from companies interested in developing a position in the unconventional shale resource plays.

     Outside of North America, customer spending is most heavily influenced by Brent oil prices, which were 47% higher in the third quarter of 2011 compared to the third quarter of 2010. While oil prices were higher year over year, recent concerns about European fiscal issues, growth reduction in China and the threat of a U.S. recession have restrained oil prices; however our customers’ spending was not adversely affected in the third quarter of 2011. This was reflected in a 5% increase in the rig count outside of North America.

Oil and Natural Gas Prices

     Oil and natural gas prices are summarized in the table below as averages of the daily closing prices during each of the periods indicated.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
WTI oil prices ($/Bbl)(1)	$	89.54	$	76.09	$	95.47	$	77.58
Brent oil prices ($/Bbl)(2)		112.38		76.41		111.44		77.26
Natural gas prices ($/mmBtu)(3)		4.05		4.28		4.21		4.56

⁽¹⁾     Bloomberg West Texas Intermediate (“WTI”) Cushing Crude Oil Spot Price

⁽²⁾     Bloomberg Dated Brent (“Brent”)

⁽³⁾     Bloomberg Henry Hub Natural Gas Spot Price

     WTI oil prices averaged $89.54/Bbl in the third quarter of 2011. Prices ranged from a high of $99.87/Bbl in July 2011 to a low of $79.20/Bbl in September 2011. Oil prices weakened throughout the third quarter of 2011 driven by expectations of a slowdown of the worldwide economic recovery and energy demand growth, particularly in Europe. The International Energy Agency (“IEA”) estimated in its October 2011 Oil Market Report that worldwide demand would increase one million barrels per day or 1% to 89.2 million barrels per day in 2011, up from 88.2 million barrels per day in 2010.

     Natural gas prices averaged $4.05/mmBtu in the third quarter of 2011. Natural gas prices traded in a range between $4.55/mmBtu and $3.67/mmBtu in the third quarter of 2011. At the end of the quarter, working natural gas in storage was 3,409 Bcf, which remained relatively flat compared to the corresponding week in 2010.

Rig Counts

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

     Rigs in the U.S. are counted as active if, on the day the count is taken, the well being drilled has been started but drilling has not been completed and the well is anticipated to be of sufficient depth to be a potential consumer of our drill bits. Rigs in Canada are counted as active if data obtained by the Canadian Association of Oilwell Drillers and Contractors indicates that drilling operations have occurred during the week and we are able to verify this information. In most international areas, rigs are counted as active if drilling operations have taken place for at least 15 days during the month; however, in certain international areas where better data is available, we compute a weekly or daily average of active rigs. In international areas where there is poor availability of data, the rig counts are estimated from third-party data. The rig count does not include rigs that are in transit from one location to another, rigging up, being used in non-drilling activities, including production testing, completion and workover, and are not expected to be significant consumers of drill bits.

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

	Three Months Ended							Nine Months Ended
	September 30,				%			September 30,				%
	2011		2010		Change			2011		2010		Change
U.S. — land and inland waters		1,911		1,601		19	%		1,805		1,459		24	%
U.S. — offshore		34		18		89	%		30		35		(14	)%
Canada		441		360		23	%		401		327		23	%
North America		2,386		1,979		21	%		2,236		1,821		23	%
Latin America		437		385		14	%		421		383		10	%
North Sea		38		39		(3	)%		40		42		(5	)%
Continental Europe		85		53		60	%		77		50		54	%
Africa		71		84		(15	)%		76		83		(8	)%
Middle East		289		273		6	%		288		263		10	%
Asia Pacific		249		276		(10	)%		258		267		(3	)%
Outside North America		1,169		1,110		5	%		1,160		1,088		7	%
Worldwide		3,555		3,089		15	%		3,396		2,909		17	%

Third Quarter of 2011 Compared to the Third Quarter of 2010

     The rig count in North America increased 21% reflecting a 65% increase in the U.S. oil-directed rig count partially offset by an 8% decrease in the U.S. gas-directed rig count, and a 39% increase in the Canadian oil-directed rig count partially offset by a 3% decrease in the Canadian gas-directed rig count. Outside North America the rig count increased 5%. The rig count in Latin America increased due to higher rig activity in all geomarkets within the region. The increase in the Continental Europe geomarket was led by Turkey, Poland and Germany. The rig count in Africa decreased chiefly due to the shutdown of activity in Libya partially offset with stronger activity in Algeria, Gabon and Congo. The rig count increased in the Middle East primarily due to higher activity in Kuwait, Egypt and Abu Dhabi, partially offset by declines in activity in Yemen and Syria. In the Asia Pacific region, activity decreased primarily in Indonesia, Malaysia and Vietnam while activity increased in India.

RESULTS OF OPERATIONS

     The discussions below relating to significant line items from our consolidated condensed statements of operations are based on available information and represent our analysis of significant changes or events that impact the comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect comparability or trends and, where possible and practical, have quantified the impact of such items. We acquired BJ Services on April 28, 2010; therefore, our results of operations for the nine months ended September 30, 2010 include the results of its operations from that date. In addition, the discussion below for revenue and cost of revenue is on a total basis as the business drivers for the individual components of product sales and services are similar. All dollar amounts in tabulations in this section are in millions of dollars, unless otherwise stated.

Revenue and Profit Before Tax

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

	Three Months Ended									Nine Months Ended
	September 30,				Increase					September 30,				Increase
	2011		2010		(decrease)		% Change			2011		2010		(decrease)		% Change
Revenue:
North America	$	2,716	$	2,006	$	710		35	%	$	7,436	$	4,411	$	3,025		69	%
Latin America		568		431		137		32	%		1,583		1,087		496		46	%
Europe/Africa/Russia Caspian		850		757		93		12	%		2,427		2,213		214		10	%
Middle East/Asia Pacific		708		606		102		17	%		2,068		1,590		478		30	%
Industrial Services and Other		336		278		58		21	%		930		690		240		35	%
Total	$	5,178	$	4,078	$	1,100		27	%	$	14,444	$	9,991	$	4,453		45	%

16

	Three Months Ended										Nine Months Ended
	September 30,				Increase						September 30,				Increase
	2011		2010		(decrease)			% Change			2011		2010		(decrease)		% Change
Profit Before Tax:
North America	$	607	$	340	$	267			79	%	$	1,507	$	685	$	822		120	%
Latin America		71		9		62			689	%		205		31		174		561	%
Europe/Africa/Russia Caspian		105		47		58			123	%		243		196		47		24	%
Middle East/Asia Pacific		84		39		45			115	%		251		109		142		130	%
Industrial Services and Other		28		36		(8	)		(22	)%		76		71		5		7	%
Total	$	895	$	471	$	424			90	%	$	2,282	$	1,092	$	1,190		109	%

Third Quarter of 2011 Compared to the Third Quarter of 2010

     Revenue for the third quarter of 2011 increased $1.10 billion or 27% compared to the third quarter of 2010. The primary drivers of the change included increased activity and improved pricing in the U.S. Land and Canada markets and to a lesser extent, increased activity in our international segments.

     Profit before tax for the third quarter of 2011 increased $424 million or 90% compared to the third quarter of 2010. These increases were primarily due to strong activity in the North America segment where increased service intensity in the unconventional markets has led to increased efficiency, utilization, and pricing improvement. Additionally, profit before tax also benefitted from worldwide cost management initiatives.

North America

     North America revenue increased 35% or $710 million in the third quarter of 2011 compared with the third quarter of 2010. Revenue and pricing increases were supported by a 19% increase in the U.S. land and inland waters rig count and a 23% 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. Revenue in the Gulf of Mexico improved appreciably compared to the third quarter of 2010, as permitting modestly improved.

     North America profit before tax increased 79% or $267 million in the third quarter of 2011 compared with the third quarter of 2010. In addition to increased revenue, the primary drivers of the increased profitability included improved tool utilization, improved absorption of manufacturing and other overhead, and higher pricing. Although there is positive progress in the Gulf of Mexico, the pace of re-permitting has not enabled activity to return to pre-Macondo levels.

Latin America

     Latin America revenue increased 32% or $137 million in the third quarter of 2011 compared with the third quarter of 2010 outpacing the 14% increase in the Latin America rig count. The primary drivers of the increase were sales of artificial lift and drilling systems in the Andean and Venezuela geomarkets, and drilling systems in the Brazil geomarket.

     Latin America profit before tax increased $62 million in the third quarter of 2011 compared to the third quarter of 2010 primarily due to revenue improvements in the Andean, Venezuela and Mexico geomarkets and price improvements in Argentina, partially offset by an increase in costs in the Brazil geomarket.

Europe/Africa/Russia Caspian (“EARC”)

     EARC revenue increased 12% or $93 million in the third quarter of 2011 compared to the third quarter of 2010. The primary drivers of the increase were sales of drilling fluids in the Norway geomarket; directional drilling and wireline sales in the Continental Europe geomarket; and higher drilling fluids and drilling systems activity in Nigeria; partially offset by the impact of decreased sales in Libya where our operations have ceased pending normal resumption of operations upon resolution of the conflict.

     EARC profit before tax increased 123% or $58 million in the third quarter of 2011 compared to the third quarter of 2010. Improved profit before tax in the Europe and Africa regions were driven by higher activity in Norway and Sub Sahara Africa geomarkets, partially offset by an unfavorable product mix and transient costs in Europe in the third quarter of 2011.

17

Middle East/Asia Pacific (“MEAP”)

     MEAP revenue increased $102 million or 17% in the third quarter of 2011 compared to the third quarter of 2010. The increase in this segment was attributable to higher activity in directional drilling and artificial lift systems and share gains from the Saudi Arabia geomarket and increased wireline and completion activity in the Southeast Asia geomarket, with significant revenue gain in Iraq on production enhancement activity, partially offset by slower deliveries in Egypt.

     MEAP profit before tax increased 115% or $45 million in the third quarter of 2011 compared to the third quarter of 2010 in line with the revenue increases in Southeast Asia and Saudi Arabia geomarkets, compensating for start-up activities in Iraq.

Industrial Services and Other

     Industrial Services and Other revenue increased 21% in the third quarter of 2011 compared to the third quarter of 2010. Industrial Services and Other profit before tax decreased 22% or $8 million in the third quarter of 2011 compared to the third quarter of 2010, primarily driven by an overall increase in cost of goods and services sold.

Nine months ended September 30, 2011 compared to nine months ended September 30, 2010

     Revenue for the nine months ended September 30, 2011 increased $4.45 billion or 45% compared to the nine months ended September 30, 2010. The primary drivers of the change included increased activity and improved pricing in the U.S. Land and Canada markets and to a lesser extent, increased activity in our international segments. The increase is also due to the acquisition of BJ Services in April 2010.

     Profit before tax for the nine months ended September 30, 2011 increased $1.19 billion or 109% compared to the nine months ended September 30, 2010, primarily due to strong activity in the North America segment where increased activity has led to increased utilization, improved absorption of manufacturing and other overhead costs, and realized pricing improvement, and to a lesser extent, higher profits in the Latin America and Middle East/Asia Pacific segments as a result of cost management, improvements in operational efficiency and improved absorption of fixed costs. The increase is also due to the acquisition of BJ Services in April 2010.

Costs and Expenses

     The table below details certain consolidated condensed statement of operations data and their percentage of revenue for the periods indicated.

	Three Months Ended September 30,								Nine Months Ended September 30,
	2011				2010				2011				2010
Revenue	$	5,178	100	%	$	4,078	100	%	$	14,444	100	%	$	9,991	100	%
Cost of revenue		3,931	76	%		3,189	78	%		11,146	77	%		7,763	78	%
Research and engineering		117	2	%		118	3	%		337	2	%		324	3	%
Marketing, general and administrative		313	6	%		354	9	%		887	6	%		971	10	%

Cost of Revenue

     Cost of revenue as a percentage of revenue was 76% and 78% for the three months ended September 30, 2011 and 2010, respectively; and was 77% and 78% for the nine months ended September 30, 2011 and 2010, respectively. These decreases were due primarily to improved pricing in North America, and efficiency and cost management initiatives globally.

Research and Engineering

     Research and engineering expenses increased 4% for the nine months ended September 30, 2011, compared to the same period a year ago as we continue to be committed to developing and commercializing new technologies as well as investing in our core product offerings.

Marketing, General and Administrative

     Marketing, general and administrative (“MG&A”) expenses decreased 12% and 9% for the three months and nine months ended September 30, 2011, respectively, compared to the same periods a year ago. These decreases resulted primarily from reductions in

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expenses as a result of cost cutting measures implemented in the latter half of 2010 and synergies we are realizing as we continue to integrate BJ Services into our operations.

Interest Expense, net

     Interest expense, net of interest income, increased $19 million and $71 million for the three months and nine months ended September 30, 2011, respectively, compared to the same periods a year ago. These increases were primarily due to the issuance of $1.5 billion of debt in August 2010 and the issuance of $750 million of debt in August 2011. In addition, the increase for the nine months ended September 30, 2011 is due to the assumption of $500 million of debt associated with the acquisition of BJ Services in April 2010.

Loss on Early Extinguishment of Debt

     In September 2011, we redeemed in full our $500 million 6.5% fixed rate senior notes maturing November 2013 and paid a redemption premium of $63 million. The redemption resulted in a pretax loss on the early extinguishment of debt of $40 million which includes the redemption premium, the write off of the remaining original debt issuance costs and debt discount, partially offset by the $25 million gain from the termination of two related interest rate swap agreements.

Income Taxes

     Total income tax expense was $13 million and $445 million for the three months and nine months ended September 30, 2011, respectively. These amounts include a $214 million tax benefit associated with the reorganization of certain foreign subsidiaries. Excluding the impact of the reorganization, our effective tax rate on operating profits for the three months and nine months ended September 30, 2011 was 31.6% and 35.2%, respectively. The third quarter tax expense also included other discrete tax benefits of $23 million and was positively impacted by a more favorable mix of geographic income, partially offset by state income taxes. For the nine months ended September 30, 2011, the effective tax rate was negatively impacted by the $70 million impairment of assets in Libya recorded in the second quarter for which there was no tax benefit.

     During the third quarter, we reorganized a portion of our foreign subsidiaries to better align certain Baker Hughes and BJ Services entities. As a result of the reorganization, previously accrued U.S. deferred income taxes related to those subsidiaries have been reduced by Baker Hughes foreign tax credits now available to offset future U.S. taxes.

     Our tax filings for various periods are subject to audit by the tax authorities in most jurisdictions where we conduct business. These audits may result in assessment of additional taxes that are resolved with the authorities or through the courts. We believe these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. We have received tax assessments from various taxing authorities and are currently at varying stages of appeals and/or litigation regarding these matters. We believe we have substantial defenses to the questions being raised and will pursue all legal remedies should an unfavorable outcome result. Resolution of any tax matter involves uncertainties and there are no assurances that the outcomes will be favorable.

OUTLOOK

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

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

     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 theShort Term Energy Outlook(“STEO”) published by the Energy Information Administration (“EIA”) of the U.S. Department of Energy (“DOE”), theOil Market Reportpublished by the IEA and theMonthly Oil

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Market Reportpublished by Organization of the Petroleum Exporting Countries (“OPEC”). Our outlook for economic growth is based on our analysis of information published by a number of sources including the International Monetary Fund (“IMF”), the Organization for Economic Cooperation and Development (“OECD”) and the World Bank.

     The primary drivers impacting the 2011 business environment include the following:

• Worldwide Economic Growth — The global economy is continuing its expansion following the recession of 2008/2009. Economic growth has been strongest in China and the other emerging and developing countries outside the OECD. While important in terms of total consumption, the developed economies of OECD countries are expected to experience relatively modest economic growth and will not contribute meaningfully to incremental oil or natural gas demand. In contrast, the emerging and developing countries outside the OECD are expected to drive most of the world’s incremental energy demand. As of the third quarter 2011, the risks to the global economic recovery continue to be the sovereign and financial troubles within the Euro area and policies to redress fiscal imbalances in the advanced economies in general.

• Demand for Hydrocarbons — The IEA in its October 2011 Oil Market Report said that it expects global demand for oil to increase one million barrels per day in 2011 relative to 2010. While forecasts by IEA, EIA and OPEC have been revised modestly lower in the past few months, primarily as a reaction to higher oil prices and uncertainty regarding the strength of the economic recovery, the expected increase in demand for hydrocarbons is expected to support increased spending to develop oil and natural gas resources.

• Production of Hydrocarbons — Global spare production capacity is relatively limited and is proving to be inadequate to decouple oil prices from geopolitical supply disruptions throughout North Africa and the Middle East. Several key OPEC countries have announced plans to increase their exploration and development efforts to develop resources to meet the expected increase in global demand. In response to higher oil prices, certain OPEC countries have stated they will increase productive capacity.

• Oil and Natural Gas Prices — With oil prices trading between $80/Bbl and $100/Bbl most resource plays will provide adequate returns to encourage incremental investment. In North America, natural gas prices are lower, on a Btu-equivalent basis, but are supporting attractive returns in those conventional and unconventional resource plays with relatively high portions of associated crude oil or natural gas liquids production.

     Activity and Spending Outlook for North America— Overall customer spending in North America is expected to increase in the fourth quarter of 2011 compared to the fourth quarter of 2010. Resource plays with crude oil and natural gas liquids content are attracting incremental investment while investment in dry gas plays has declined. Service intensity has increased in North America as customers are demanding advanced directional drilling, more complex completion systems and pressure pumping to develop the unconventional shale resource plays. The demand for these key technologies has grown faster than the industry’s ability to produce resulting in support for higher prices. Activity in Canada is expected to increase sequentially in the fourth quarter, recovering from its seasonally low second quarter and building to a seasonally high peak in the first quarter. In the Gulf of Mexico, activity on the continental shelf has remained steady, while the third quarter saw an increase in deep water permits and subsequently deep water drilling. The level of activity in the deep water Gulf of Mexico remains well below pre-moratorium levels; however, we have confidence that as the permitting process is better understood deepwater activity will ultimately return to pre-Macondo levels. We are investing in our people and processes to ensure that we will be fully compliant with the new and more stringent regulatory requirements in the Gulf of Mexico, for which costs will continue over the next several quarters.

     Activity and Spending Outlook Outside North America— International activity is driven primarily by the price of oil which is high enough to provide attractive economic returns in almost every region. Customers are expected to increase spending to develop new resources and offset declines from existing developed resources. Areas that are expected to see increased spending throughout the rest of the year include: the Middle East, in particular Saudi Arabia, Kuwait and Abu Dhabi, which have announced significant increases to their spending plans; Brazil with the investment in the pre-salt resources; and Colombia which has seen a rapid expansion associated with improved fiscal terms for our customers.

     Capital Expenditures— Our capital expenditures, excluding acquisitions, are expected to be between $2.3 billion and $2.4 billion for 2011. A significant portion of our planned capital expenditures can be adjusted to reflect changes in our expectations for future customer spending. We will manage our capital expenditures to match market demand.

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LIQUIDITY AND CAPITAL RESOURCES

     Our objective in financing our business is to maintain adequate financial resources and access to sufficient liquidity. At September 30, 2011, we had cash and cash equivalents of $803 million, of which approximately $701 million was held by foreign subsidiaries. A substantial portion of the cash held by foreign subsidiaries at September 30, 2011, was reinvested in our international operations as our intent is to use cash to, among other things, fund the operations of our foreign subsidiaries. If we decide at a later date to repatriate those funds to the U.S., we may be required to provide taxes on certain of those funds based on applicable U.S. tax rates net of foreign taxes. In addition, we had $2.5 billion available for borrowing under committed revolving credit facilities with commercial banks. We believe that cash on hand and cash flows from operations will provide sufficient liquidity to manage our global cash needs. We may, if necessary, also issue commercial paper or other short-term debt to fund cash needs.

     Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of our company. In the nine months ended September 30, 2011, we used cash to fund a variety of activities including working capital needs, capital expenditures, repayment of debt and dividends.

Cash Flows

     Cash flows provided (used) by continuing operations, by type of activity, were as follows for the nine months ended September 30:

	2011			2010
Operating activities	$	682		$	578
Investing activities		(1,177	)		(1,916	)
Financing activities		(164	)		1,344

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

Operating Activities

     Cash flows from operating activities provided cash of $682 million and $578 million in the nine months ended September 30, 2011 and 2010, respectively. This increase in cash flows of $104 million was primarily due to an increase in net income, adjusted for noncash items, partially offset by a change in net operating assets and liabilities, which used more cash in the nine months ended September 30, 2011 compared to the same period in 2010.

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

• An increase in accounts receivable used cash of $1,107 million and $504 million in the nine months ended September 30, 2011 and 2010, respectively, resulting from revenue growth. 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 revenue) of approximately 5 days due primarily to temporary invoicing delays resulting from the implementation of our enterprise wide software for BJ Services in North America.

• Inventory used cash of $463 million and $161 million in the nine months ended September 30, 2011 and 2010, respectively, driven by higher inventory levels required to support anticipated increases in production volume.

• An increase in accounts payable provided cash of $183 million and $177 million in the nine months ended September 30, 2011 and 2010, respectively, resulting from an increase in operating assets to support increased activity.

• A decrease in income taxes payable used cash of $189 million and $68 million in the nine months ended September 30, 2011 and 2010, respectively. This change is due primarily to an increase in income taxes paid of $418 million partially offset by the increase in the provision for income taxes in the first nine months of 2011 compared to the same period in 2010.

Investing Activities

     Our principal recurring investing activity was the funding of capital expenditures to ensure that we have the appropriate levels and types of machinery and equipment in place to generate revenue from operations. Expenditures for capital assets totaled $1,651 million and $1,005 million in the nine months ended September 30, 2011 and 2010, respectively. While the majority of these expenditures were for machinery and equipment, we have continued our spending on new facilities, expansions of existing facilities and other infrastructure projects.

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     Proceeds from the disposal of assets were $215 million and $152 million in the nine months ended September 30, 2011 and 2010, respectively. These disposals related to equipment that was lost-in-hole, and property, machinery and equipment no longer used in operations that was sold during the period.

     During the nine months ended September 30, 2010, we purchased $250 million of short-term investments consisting of U.S. Treasury Bills. The U.S. Treasury Bills matured in May of 2011 and we received proceeds of $250 million.

     We routinely evaluate potential acquisitions of businesses of third parties that may enhance our current operations or expand our operations into new markets or product lines. During the nine months ended September 30, 2010, we paid cash of $680 million, net of cash acquired of $113 million, related to the BJ Services acquisition, and $172 million, net of cash acquired of $5 million, for several other acquisitions.

Financing Activities

     We had net repayments of commercial paper and other short-term debt of $41 million compared to net borrowings of $9 million in the nine months ended September 30, 2011 and 2010, respectively. In addition, in August 2011, we completed a private placement of $750 million 3.2% senior notes that have registration rights and will mature in August 2021, resulting in net proceeds of approximately $742 million after deducting the underwriting discounts and expenses of the offering. The 3.2% notes may only be transferred or resold in a transaction registered under or exempt from registration requirements of federal and state securities laws. In September 2011, we used $563 million of the net proceeds to redeem our 6.5% notes. 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. In June 2011, we repaid $250 million of our 5.75% notes that matured. Total debt outstanding at September 30, 2011 was $3.90 billion and $3.89 billion at December 31, 2010. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was 20% at September 30, 2011 and 21% at December 31, 2010.

     We received proceeds of $144 million and $29 million in the nine months ended September 30, 2011 and 2010, respectively, from the issuance of common stock through the exercise of stock options and the employee stock purchase plan. Additionally, we paid dividends of $195 million and $175 million in the nine months ended September 30, 2011 and 2010, respectively.

     Our Board of Directors has authorized a program to repurchase our common stock from time to time. In the nine months ended September 30, 2011 and 2010, we did not repurchase any shares of our common stock. At September 30, 2011, we had authorization remaining to repurchase up to a total of $1.2 billion of our common stock.

Available Credit Facilities

     At September 30, 2011, we had a $2.5 billion committed revolving credit facility with commercial banks. This facility contains certain covenants which, among other things, 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 facility may be accelerated. Such events of default include payment defaults to lenders under the facility, covenant defaults and other customary defaults. At September 30, 2011, we were in compliance with all of the facility’s covenants. There were no direct borrowings under committed credit facilities during the nine months ended September 30, 2011. We also have a commercial paper program under which we may issue up to $1.0 billion in commercial paper with maturity of no more than 270 days. To the extent we have outstanding commercial paper our ability to borrow under the facility is reduced. At September 30, 2011, we had no outstanding commercial paper.

     If market conditions were to change and revenue was to be significantly reduced or operating costs were to increase, our cash flows and liquidity could be reduced. Additionally, it could cause the rating agencies to lower our credit rating. There are no ratings triggers that would accelerate the maturity of any borrowings under our committed credit facilities. However, a downgrade in our credit ratings could increase the cost of borrowings under the facilities and could also limit or preclude our ability to issue commercial paper. Should this occur, we would seek alternative sources of funding, including borrowing under the facilities.

     We believe our current credit ratings would allow us to obtain interim financing over and above our existing credit facilities for any currently unforeseen significant needs or growth opportunities. We also believe that such interim financings could be funded with subsequent issuances of long-term debt or equity, if necessary.

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Cash Requirements

     In 2011, we believe cash on hand and operating cash flows will provide us with sufficient capital resources and liquidity to manage our working capital needs, meet contractual obligations, fund capital expenditures, and support the development of our short-term and long-term operating strategies. We may issue commercial paper or other short-term debt to fund cash needs in the U.S. in excess of the cash generated in the U.S.

     In 2011, we expect capital expenditures to be between $2.3 billion and $2.4 billion, excluding any amount related to acquisitions. The expenditures are expected to be used primarily for normal, recurring items necessary to support the growth of our business and operations. A significant portion of our capital expenditures can be adjusted based on future activity of our customers. We will manage our capital expenditures to match market demand.

     In 2011, we expect to make interest payments of between $215 million and $225 million, based on our current expectations of debt levels. We anticipate making income tax payments of between $1.1 billion and $1.2 billion in 2011.

     We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. We anticipate paying dividends of between $255 million and $265 million in 2011; however, the Board of Directors can change the dividend policy at any time.

     For all pension plans, we make annual contributions to the plans in amounts equal to or greater than amounts necessary to meet minimum governmental funding requirements. In 2011, we expect to contribute between $65 million and $85 million to our defined benefit pension plans. We also expect to make benefit payments related to postretirement welfare plans of between $16 million and $18 million, and we estimate we will contribute between $187 million and $203 million to our defined contribution plans.

Accounting Standards Updates

     In May 2011, the Financial Accounting Standards Board (“FASB”) issued an update to Accounting Standards Codification (“ASC”) 820,Fair Value Measurement. The Accounting Standards Update (“ASU”) conforms certain sections of ASC 820 to International Financial Reporting Standards in order to provide a single converged guidance on the measurement of fair value. This update also expands the existing disclosure requirements for fair value measurements. This ASU is effective for interim and annual periods beginning after December 15, 2011. We will adopt this ASU prospectively in the first quarter of 2012. We currently do not expect this ASU to have a material impact, if any, on our consolidated condensed financial statements.

     In June 2011, the FASB issued an update to ASC 220,Comprehensive Income. This ASU requires entities to present components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements that would include reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statements. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We will adopt the new presentation requirements of this ASU retrospectively in the first quarter of 2012.

     In September 2011, the FASB issued an update to ASC 350,Intangibles — Goodwill and Other. This ASU amends the guidance in ASC 350-20 on testing for goodwill impairment. The revised guidance allows entities testing for goodwill impairment to have the option of performing a qualitative assessment before calculating the fair value of the reporting unit. The ASU does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirement to test annually for impairment. The ASU is limited to goodwill and does not amend the annual requirement for testing other indefinite-lived intangible assets for impairment. The ASU is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We will adopt this ASU for our 2012 goodwill impairment testing. We do not expect this ASU to have a material impact, if any, on our consolidated condensed financial statements.

FORWARD-LOOKING STATEMENTS

     MD&A and certain statements in the Notes to Consolidated Condensed Financial Statements include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, (each a “forward-looking statement”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “probable,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “probable,” “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

23

business outlook and business plans; the business plans of our customers; oil and natural gas market conditions; costs and availability of resources; the on-going integration of BJ Services; economic, legal and regulatory conditions and other matters are only our forecasts regarding these matters.

     All of our forward-looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in “Part II, Item 1A. Risk Factors” section contained herein, as well as the risk factors described in our 2010 Annual Report, this filing and those set forth from time to time in our filings with the SEC. These documents are available through our web site or through the SEC’s Electronic Data Gathering and Analysis Retrieval System (“EDGAR”) at http://www.sec.gov.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     We conduct operations around the world in a number of different currencies. A number of our significant foreign subsidiaries have designated the local currency as their functional currency. As such, future earnings are subject to change due to changes in foreign currency exchange rates when transactions are denominated in currencies other than our functional currencies. To minimize the need for foreign currency forward contracts to hedge this exposure, our objective is to manage foreign currency exposure by maintaining a minimal consolidated net asset or net liability position in a currency other than the functional currency.

Foreign Currency Forward Contracts

     At September 30, 2011, we had outstanding foreign currency forward contracts with notional amounts aggregating $157 million to hedge exposure to currency fluctuations in various foreign currencies. These contracts are designated and qualify as fair value hedging instruments. The fair value of the contracts outstanding at September 30, 2011, based on quoted market prices as of September 30, 2011, for contracts with similar terms and maturity dates, was $3 million included in other current assets and $8 million included in other accrued liabilities in the consolidated condensed balance sheet. The effect of foreign currency forward contracts on the consolidated condensed statement of operations for the three months and nine months ended September 30, 2011 was $3 million and $6 million, respectively, of foreign exchange losses, which were included in marketing, general and administrative expenses. These net losses offset designated foreign exchange net gains resulting from the underlying exposures of the hedged items.

Interest Rate Swaps

     We are subject to interest rate risk on our debt and investment of cash and cash equivalents arising in the normal course of our business, as we do not engage in speculative trading strategies. We maintain an interest rate management strategy, which primarily uses a mix of fixed and variable rate debt that is intended to mitigate the exposure to changes in interest rates in the aggregate for our investment portfolio. We use interest rate swaps to manage the economic effect of fixed rate obligations associated with certain debt when appropriate.

     In September 2011, we redeemed in full our 6.5% notes. Consequently, we terminated two related interest rate swap agreements resulting in a gain on the swaps of $25 million. The two swap agreements were entered into in June 2009 for a notional amount of $250 million each in order to hedge changes in the fair market value of the related notes. The swap agreements had been designated and each qualified as a fair value hedging instrument. The effect of the swaps on the consolidated condensed statement of operations for the three months and nine months ended September 30, 2011 was a reduction in interest expense of $2 million and $8 million, respectively.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

     As of the end of the period covered by this quarterly report, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act of 1934, as amended (the “Exchange Act”). This evaluation was carried out under the supervision and with the participation of our management, including our principal executive officer and principal financial officer. Based on this evaluation, these officers have concluded that, as of September 30, 2011, our disclosure controls and procedures, as defined by Rule 13a-15(e) of the Exchange Act, are effective at a reasonable assurance level. There has been no change in our internal controls over financial reporting during the quarter ended September 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

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     Disclosure controls and procedures are our controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act, such as this quarterly report, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

     We are subject to a number of lawsuits, investigations and claims (some of which involve substantial amounts) arising out of the conduct of our business. See a further discussion of litigation matters in Note 11 of Notes to Unaudited Consolidated Condensed Financial Statements.

     For additional discussion of legal proceedings see also, Item 3 of Part I of our 2010 Annual Report and Note 14 of the Notes to the Consolidated Financial Statements included in Item 8 of our 2010 Annual Report.

ITEM 1A. RISK FACTORS

     As of the date of this filing, the Company and its operations continue to be subject to the risk factors previously disclosed in our “Risk Factors” in the 2010 Annual Report, the Form 10-Q for the period ended March 31, 2011, and the Form 10-Q for the period ended June 30, 2011 as well as the following risk factor:

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

     Geopolitical and terrorism risks continue to grow in several key countries where we do business. Geopolitical and terrorism risks could lead to, among other things, a loss of our investment in the country, impair the safety of our employees and impair our ability to conduct our operations. During the nine months ended September 30, 2011, there was political unrest in North Africa, and in particular Libya, where our operations have ceased pending resolution of the conflict. As of September 30, 2011, we have assets remaining in Libya totaling approximately $77 million.

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, 2011.

Issuer Purchases of Equity Securities
											Maximum
					Total Number						Number (or
					of Shares						Approximate
					Purchased as						Dollar Value) of
					Part of a				Total Number		Shares that May
	Total Number		Average Price		Publicly		Average Price		of Shares		Yet Be Purchased
	of Shares		Paid Per Share		Announced		Paid Per Share		Purchased in		Under the
Period	Purchased(1)		(1)		Program(2)		(2)		the Aggregate		Program(3)
July 1-31, 2011		40,584	$	78.86		—	$	—		40,584	$	—
August 1-31, 2011		10,557		58.61		—		—		10,557		—
September 1-30, 2011		1,120		52.20		—		—		1,120		—
Total		52,261	$	74.20		—	$	—		52,261	$	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, 2011.
(3)	Our Board of Directors has authorized a plan to repurchase our common stock from time to time. During the three months ended September 30, 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.

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ITEM 3. DEFAULTS UPON SENIOR SECURITIES

     None.

ITEM 4. [REMOVED AND RESERVED]

ITEM 5. OTHER INFORMATION

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

ITEM 6. EXHIBITS

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

4.1	First Supplemental Indenture dated August 17, 2011 between Baker Hughes Incorporated and The Bank of New York Mellon Trust Company, N.A., as trustee (including form of the Notes) (filed as Exhibit 4.2 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on August 23, 2011).
10.1	Purchase Agreement dated August 10, 2011 among Baker Hughes Incorporated and J.P. Morgan Securities LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representatives of the several initial purchasers named therein (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on August 15, 2011).
10.2	Registration Rights Agreement dated August 17, 2011 among Baker Hughes Incorporated and J.P. Morgan Securities LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representatives of the several initial purchasers named therein (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on August 23, 2011).
10.3	Credit Agreement dated as of September 13, 2011, among Baker Hughes Incorporated, JPMorgan Chase Bank, N.A., as Administrative Agent and twenty-one lenders for $2.5 billion, in the aggregate for all banks (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on September 15, 2011).
31.1*	Certification of Chad C. Deaton, Chief Executive Officer, furnished pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.
31.2*	Certification of Peter A. Ragauss, Chief Financial Officer, furnished pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.
32*	Statement of Chad C. Deaton, Chief Executive Officer, and Peter A. Ragauss, Chief Financial Officer, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.
99.1*	Mine Safety Disclosure.
101.INS*	XBRL Instance Document
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

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SIGNATURES

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

	BAKER HUGHES INCORPORATED (Registrant)
Date: November 2, 2011	By:	/s/ PETER A. RAGAUSS
	Peter A. Ragauss
	Senior Vice President and Chief Financial Officer
Date: November 2, 2011	By:	/s/ ALAN J. KEIFER
	Alan J. Keifer
	Vice President and Controller

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