SEC Filing | Baker Hughes

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2012.9.30 10Q

Table of Contents

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, 2012



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. YES þ NO o

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).

YES þ NO o

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



Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o

(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).

YES o NO þ

As of October 17, 2012, the registrant has outstanding 439,646,900 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 Income (Unaudited) - Three months and nine months ended September 30, 2012 and 2011	2

	Consolidated Condensed Statements of Comprehensive Income (Unaudited) - Three months and nine months ended September 30, 2012 and 2011	3

	Consolidated Condensed Balance Sheets (Unaudited) - September 30, 2012 and December 31, 2011	4

	Consolidated Condensed Statements of Equity (Unaudited) - Nine months ended September 30, 2012 and 2011	5

	Consolidated Condensed Statements of Cash Flows (Unaudited) - Nine months ended September 30, 2012 and 2011	6

	Notes to Unaudited Consolidated Condensed Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28

Item 4.	Controls and Procedures	28

PART II -	OTHER INFORMATION

Item 1.	Legal Proceedings	29

Item 1A.	Risk Factors	29

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	29

Item 3.	Defaults Upon Senior Securities	29

Item 4.	Mine Safety Disclosures	29

Item 5.	Other Information	30

Item 6.	Exhibits	30

	Signatures	31

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Baker Hughes Incorporated

Consolidated Condensed Statements of Income

(In millions, except per share amounts)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Revenue:
Sales	$	1,832		$	1,663		$	5,345		$	4,635
Services	3,396			3,401			10,363			9,501
Total revenue	5,228			5,064			15,708			14,136
Costs and expenses:
Cost of sales	1,474			1,342			4,227			3,766
Cost of services	2,831			2,501			8,433			7,134
Research and engineering	117			115			366			331
Marketing, general and administrative	344			301			975			862
Total costs and expenses	4,766			4,259			14,001			12,093
Operating income	462			805			1,707			2,043
Interest expense, net	(49		)	(58		)	(153		)	(164		)
Loss on early extinguishment of debt	—			(40		)	—			(40		)
Income from continuing operations before income taxes	413			707			1,554			1,839
Income taxes	(143		)	(9		)	(479		)	(434		)
Income from continuing operations	270			698			1,075			1,405
Income from discontinued operations, net of tax	14			8			27			20
Net income	284			706			1,102			1,425
Net (income) loss attributable to noncontrolling interests	(5		)	—			(5		)	—
Net income attributable to Baker Hughes	$	279		$	706		$	1,097		$	1,425

Amounts attributable to Baker Hughes:
Income from continuing operations	$	265		$	698		$	1,070		$	1,405
Income from discontinued operations	14			8			27			20
Net Income attributable to Baker Hughes	$	279		$	706		$	1,097		$	1,425

Basic earnings per share:
Income from continuing operations	$	0.60		$	1.60		$	2.43		$	3.22
Income from discontinued operations	0.03			0.02			0.06			0.05
Basic earnings per share attributable to Baker Hughes	$	0.63		$	1.62		$	2.49		$	3.27

Diluted earnings per share:
Income from continuing operations	$	0.60		$	1.59		$	2.43		$	3.21
Income from discontinued operations	0.03			0.02			0.06			0.04
Diluted earnings per share attributable to Baker Hughes	$	0.63		$	1.61		$	2.49		$	3.25

Cash dividends per share	$	0.15		$	0.15		$	0.45		$	0.45

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

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Baker Hughes Incorporated

Consolidated Condensed Statements of Comprehensive Income

(In millions)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Net Income	$	284		$	706		$	1,102		$	1,425
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments during the period	63			(116		)	61			(33		)
Pension and other postretirement benefits	—			5			19			5
Net gain on hedge transactions	—			—			1			—
Other comprehensive income (loss), net of tax	63			(111		)	81			(28		)
Comprehensive income	347			595			1,183			1,397
Comprehensive (income) loss attributable to noncontrolling interests	(5		)	1			(5		)	1
Comprehensive income (loss) attributable to Baker Hughes	$	342		$	596		$	1,178		$	1,398

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

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Baker Hughes Incorporated

Consolidated Condensed Balance Sheets

(In millions)

(Unaudited)



	September 30, 2012			December 31, 2011
ASSETS
Current Assets:
Cash and cash equivalents	$	1,007		$	1,050
Accounts receivable - less allowance for doubtful accounts (2012 - $255; 2011 - $226)	5,003			4,794
Inventories, net	3,879			3,211
Deferred income taxes	252			251
Other current assets	432			393
Assets of discontinued operations	707			646
Total current assets	11,280			10,345

Property, plant and equipment - less accumulated depreciation (2012 - $5,961; 2011 - $5,192)	8,225			7,245
Goodwill	5,612			5,637
Intangible assets, net	989			1,086
Other assets	650			534
Total assets	$	26,756		$	24,847

LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable	$	1,829		$	1,774
Short-term debt and current portion of long-term debt	1,306			224
Accrued employee compensation	661			695
Income taxes payable	205			288
Other accrued liabilities	476			464
Liabilities of discontinued operations	55			56
Total current liabilities	4,532			3,501

Long-term debt	3,839			3,845
Deferred income taxes and other tax liabilities	602			810
Liabilities for pensions and other postretirement benefits	579			578
Other liabilities	133			149
Commitments and contingencies

Equity:
Common stock	439			437
Capital in excess of par value	7,447			7,303
Retained earnings	9,461			8,561
Accumulated other comprehensive loss	(474		)	(555		)
Baker Hughes stockholders’ equity	16,873			15,746
Noncontrolling interests	198			218
Total equity	17,071			15,964
Total liabilities and equity	$	26,756		$	24,847

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

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Baker Hughes Incorporated

Consolidated Condensed Statements of Equity

(In millions)

(Unaudited)



	Common Stock		Capital in Excess of Par Value		Retained Earnings			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total
Balance at December 31, 2011	$	437	$	7,303	$	8,561		$	(555	)	$	218		$	15,964
Comprehensive income:
Net income					1,097						5			1,102
Other comprehensive income								81						81
Activity related to stock plans	2		28											30
Stock-based compensation cost			94											94
Cash dividends ($0.45 per share)					(197		)							(197		)
Net activity related to noncontrolling interests			22								(25		)	(3		)
Balance at September 30, 2012	$	439	$	7,447	$	9,461		$	(474	)	$	198		$	17,071



	Common Stock		Capital in Excess of Par Value		Retained Earnings			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total
Balance at December 31, 2010	$	432	$	7,005	$	7,083		$	(420	)	$	186		$	14,286
Comprehensive income:
Net income					1,425									1,425
Other comprehensive income								(27		)	(1		)	(28		)
Activity related to stock plans	4		143											147
Stock-based compensation cost			85											85
Cash dividends ($0.45 per share)					(195		)							(195		)
Net activity related to noncontrolling interests			11								32			43
Balance at September 30, 2011	$	436	$	7,244	$	8,313		$	(447	)	$	217		$	15,763

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

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Baker Hughes Incorporated

Consolidated Condensed Statements of Cash Flows

(In millions)

(Unaudited)



	Nine Months Ended September 30,
	2012			2011
Cash flows from operating activities:
Income from continuing operations	$	1,075		$	1,405
Adjustments to reconcile income from continuing operations to net cash flows from operating activities:
Depreciation and amortization	1,122			951
Benefit for deferred income taxes	(236		)	(312		)
Gain on disposal of assets	(169		)	(124		)
Stock-based compensation cost	94			85
Loss on early extinguishment of debt	—			40
Provision for doubtful accounts	37			76
Loss on impairment of assets	55			—
Changes in operating assets and liabilities:
Accounts receivable	(199		)	(1,074		)
Inventories	(660		)	(465		)
Accounts payable	47			179
Accrued employee compensation and other accrued liabilities	(20		)	81
Income taxes payable	(62		)	(189		)
Other operating items, net	(147		)	3
Net cash flows from continuing operations	937			656
Net cash flows from discontinued operations	10			26
Net cash flows from operating activities	947			682
Cash flows from investing activities:
Expenditures for capital assets	(2,160		)	(1,624		)
Proceeds from maturities of short-term investments	—			250
Proceeds from disposal of assets	285			215
Other investing items, net	—			9
Net cash flows from continuing operations	(1,875		)	(1,150		)
Net cash flows from discontinued operations	(21		)	(27		)
Net cash flows from investing activities	(1,896		)	(1,177		)
Cash flows from financing activities:
Net proceeds (payments) of commercial paper and other short-term debt	1,075			(41		)
Net proceeds of long-term debt	—			742
Repayment of long-term debt	—			(813		)
Proceeds from termination of interest rate swap agreements	—			26
Proceeds from issuance of common stock	42			144
Dividends paid	(197		)	(195		)
Purchase of noncontrolling interest	(4		)	(26		)
Other financing items, net	(14		)	(1		)
Net cash flows from financing activities	902			(164		)
Effect of foreign exchange rate changes on cash	4			6
Decrease in cash and cash equivalents	(43		)	(653		)
Cash and cash equivalents, beginning of period	1,050			1,456
Cash and cash equivalents, end of period	$	1,007		$	803

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Supplemental cash flows disclosures:
Income taxes paid, net of refunds	$	811	$	934
Interest paid	$	191	$	184
Supplemental disclosure of noncash investing activities:
Capital expenditures included in accounts payable	$	115	$	78

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Baker Hughes Incorporated (“Baker Hughes,” “Company,” “we,” “our,” or “us,”) is a leading supplier of oilfield services, products, technology and systems used for drilling, formation evaluation, completion and production, pressure pumping, and reservoir development in the worldwide oil and natural gas industry. We also provide products and services for other businesses, including downstream refining, specialty polymers and process and pipeline services.

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 (“SEC”) for interim financial information. Accordingly, certain information and disclosures normally included in our annual financial statements have been condensed or omitted. These unaudited consolidated condensed financial statements should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 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. In addition, all prior periods reflect the reclassification of certain operations as discontinued. For further discussion see Note 2. Discontinued Operations. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. In the notes to the unaudited consolidated condensed financial statements, all dollar and share amounts in tabulations are in millions of dollars and shares, respectively, unless otherwise indicated.

New Accounting Standards Updates

In June 2011, the Financial Accounting Standards Board (“FASB”) issued an update to Accounting Standards Codification (“ASC”) 220, Comprehensive Income. This Accounting Standards Update (“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 by component for items that are reclassified from other comprehensive income to net income on the face of the financial statements. In December 2011, the FASB issued an update to this ASU indefinitely deferring the implementation of the reclassification adjustments by component requirement of the ASU issued in June 2011. We adopted the new presentation requirement in the first quarter of 2012. We elected the two-statement approach presenting other comprehensive income in a separate statement immediately following the unaudited consolidated condensed statement of income.

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 goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We adopted this ASU effective January 1, 2012, with no impact to our unaudited consolidated condensed financial statements.

In July 2012, the FASB issued an update to ASC 350, Intangibles - Goodwill and Other. This ASU amends the guidance in ASC 350-30 on testing indefinite-lived intangible assets for impairment. The revised guidance permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test. The ASU is effective for impairment tests performed for fiscal years beginning after September 15, 2012. We will adopt this ASU for our 2013 impairment testing. We do not expect this ASU to have a material impact, if any, on our unaudited consolidated condensed financial statements.

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 2. DISCONTINUED OPERATIONS

Our Board of Directors approved and we have initiated a plan to sell the Process and Pipeline Services (“PPS”) business unit, which was previously reported as part of the Industrial Services segment. PPS is a global provider of pre-commissioning, maintenance and inspection services for upstream, midstream and downstream oil and gas facilities and pipelines. Accordingly, we have reclassified the financial results and related notes thereto for all prior periods presented herein to reflect these operations as discontinued.

Summarized financial information from discontinued operations is as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Revenue	$	128		$	114		$	328		$	308

Income before income taxes	$	24		$	13		$	45		$	31
Income taxes	(10		)	(5		)	(18		)	(11		)
Income from discontinued operations	$	14		$	8		$	27		$	20

Assets and liabilities of discontinued operations are as follows:



	September 30, 2012		December 31, 2011
Assets
Total current assets	$	142	$	98
Property, plant and equipment, net	166		170
Goodwill	346		319
Other assets	53		59
Assets of discontinued operations	$	707	$	646

Liabilities
Accounts payable	$	44	$	36
Other liabilities	11		20
Liabilities of discontinued operations	$	55	$	56

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 3. 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 September 30,		Nine Months Ended September 30,
	2012	2011	2012	2011
Weighted average common shares outstanding for basic EPS	440	437	440	436
Effect of dilutive securities - stock plans	1	2	1	2
Adjusted weighted average common shares outstanding for diluted EPS	441	439	441	438
Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than the average market price for the period	8	3	8	3

NOTE 4. INVENTORIES

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



	September 30, 2012		December 31, 2011
Finished goods	$	3,435	$	2,820
Work in process	241		231
Raw materials	203		160
Total	$	3,879	$	3,211

NOTE 5. INTANGIBLE ASSETS

Intangible assets are comprised of the following:



	September 30, 2012						December 31, 2011
	Gross Carrying Amount		Less: Accumulated Amortization		Net		Gross Carrying Amount		Less: Accumulated Amortization		Net
Definite lived intangibles:
Technology	$	714	$	238	$	476	$	686	$	206	$	480
Contract-based	17		10		7		17		9		8
Trade names	116		47		69		116		14		102
Customer relationships	483		102		381		483		73		410
Subtotal	1,330		397		933		1,302		302		1,000
Indefinite lived intangibles:
In-process research and development	56		—		56		86		—		86
Total	$	1,386	$	397	$	989	$	1,388	$	302	$	1,086

Intangible assets are generally amortized on a straight-line basis with estimated useful lives ranging from 2 to 20 years. Amortization expense included in net income for the three months and nine months ended September 30, 2012 was $34 million

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

and $97 million, respectively, and is estimated to be $33 million for the remainder of fiscal year 2012. Estimated amortization expense for each of the subsequent five fiscal years is expected to be as follows: 2013 - $108 million; 2014 - $94 million; 2015 - $88 million; 2016 - $83 million; and 2017 - $81 million.

NOTE 6. FINANCIAL INSTRUMENTS

Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable, debt and foreign currency forward contracts. Except as described below, the estimated fair value of such financial instruments at September 30, 2012 and December 31, 2011 approximates their carrying value as reflected in our unaudited consolidated condensed balance sheets.

The estimated fair value of total debt at September 30, 2012 and December 31, 2011 was $6,147 million and $4,910 million, respectively, which differs from the carrying amounts of $5,145 million and $4,069 million, respectively, included in our unaudited consolidated condensed balance sheets. The fair value was determined using Level 2 inputs including quoted period end market prices.

NOTE 7. SEGMENT INFORMATION

We conduct our business primarily through operating segments that are aligned with our geographic regions, which have been aggregated into five reportable segments. We aggregate our operating segments within each reportable segment because they have similar economic characteristics and because the long-term financial performance of the operating segments is affected by similar economic conditions. The performance of our operating segments is evaluated based on profit before tax, which is defined as income from continuing operations before income taxes and before the following: net interest expense, corporate expenses, and certain gains and losses not allocated to the operating segments.

In the first quarter of 2012, we changed our reporting structure to include the reservoir development services business (“RDS”) within our four oilfield geographic segments. All prior period segment disclosures for revenue and profit before tax have been reclassified to include RDS within our four oilfield geographic segments. The impact of these changes to the Industrial Services segment was to reduce revenue by $23 million and $75 million, respectively, for the three months and nine months ended September 30, 2011; and increase profit before tax by $16 million and $35 million for the three months and nine months ended September 30, 2011.

Summarized financial information is shown in the following table.



	Three Months Ended					Three Months Ended
	September 30, 2012					September 30, 2011
Segments	Revenue		Profit (Loss) Before Taxes			Revenue		Profit (Loss) Before Taxes
North America	$	2,742	$	288		$	2,721	$	602
Latin America	583		45			570		71
Europe/Africa/Russia Caspian	866		104			863		103
Middle East/Asia Pacific	844		71			711		75
Industrial Services	193		13			199		32
Total Operations	5,228		521			5,064		883
Corporate and Other	—		(59		)	—		(78		)
Interest Expense, net	—		(49		)	—		(58		)
Loss on early extinguishment of debt	—		—			—		(40		)
Total	$	5,228	$	413		$	5,064	$	707

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements



	Nine Months Ended					Nine Months Ended
	September 30, 2012					September 30, 2011
Segments	Revenue		Profit (Loss) Before Taxes			Revenue		Profit (Loss) Before Taxes
North America	$	8,277	$	1,046		$	7,451	$	1,491
Latin America	1,760		189			1,588		204
Europe/Africa/Russia Caspian	2,684		413			2,462		235
Middle East/Asia Pacific	2,393		233			2,088		241
Industrial Services	594		58			547		80
Total Operations	15,708		1,939			14,136		2,251
Corporate and Other	—		(232		)	—		(208		)
Interest Expense, net	—		(153		)	—		(164		)
Loss on early extinguishment of debt	—		—			—		(40		)
Total	$	15,708	$	1,554		$	14,136	$	1,839

NOTE 8. EMPLOYEE BENEFIT PLANS

We have both funded and unfunded noncontributory defined benefit pension plans covering certain employees primarily in the U.S., the U.K., Germany and Canada. 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 Plans						Non-U.S. Pension Plans						Other Postretirement Benefits
	2012			2011			2012			2011			2012		2011
Service cost	$	16		$	10		$	2		$	2		$	3	$	2
Interest cost	5			5			8			8			2		2
Expected return on plan assets	(9		)	(8		)	(9		)	(8		)	—		—
Amortization of net loss	4			3			2			1			—		—
Net periodic cost	$	16		$	10		$	3		$	3		$	5	$	4

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



	U.S. Pension Plans						Non-U.S. Pension Plans						Other Postretirement Benefits
	2012			2011			2012			2011			2012			2011
Service cost	$	48		$	28		$	6		$	6		$	9		$	6
Interest cost	15			15			24			24			6			6
Expected return on plan assets	(27		)	(24		)	(27		)	(24		)	—			—
Amortization of prior service benefit	—			—			—			—			(2		)	(2		)
Amortization of net loss	12			7			5			3			1			—
Benefit settlement	—			—			6			—			—			—
Net periodic cost	$	48		$	26		$	14		$	9		$	14		$	10

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

We invest the assets of our pension plans in investments according to the policies developed by our investment committees. The majority of these assets are in investments whose fair values are determined using Level 2 observable inputs. The changes in the fair value of pension plan assets determined using Level 3 unobservable inputs are as follows:



	Three Months Ended September 30, 2012
	U.S. Private Equity Fund			U.S. Property Fund		U.S. Hedge Funds		Non-U.S. Property Fund		Non-U.S. Insurance Contracts		Total
Ending balance at June 30, 2012	$	17		$	6	$	163	$	19	$	15	$	220
Unrealized gains	—			—		5		1		—		6
Unrealized losses	(2		)	—		—		—		—		(2		)
Purchases	1			1		—		—		—		2
Ending balance at September 30, 2012	$	16		$	7	$	168	$	20	$	15	$	226



	Nine Months Ended September 30, 2012
	U.S. Private Equity Fund			U.S. Property Fund		U.S. Hedge Funds		Non-U.S. Property Fund		Non-U.S. Insurance Contracts		Total
Ending balance at December 31, 2011	$	—		$	5	$	110	$	19	$	15	$	149
Unrealized gains	—			—		6		1		—		7
Unrealized losses	(2		)	—		—		—		—		(2		)
Purchases	18			2		52		—		—		72
Ending balance at September 30, 2012	$	16		$	7	$	168	$	20	$	15	$	226

NOTE 9. INCOME TAXES

Our effective tax rate on income from continuing operations before income taxes for the three months and nine months ended September 30, 2012 was 34.6% and 30.8%, respectively. The tax rate for the three months ended September 30, 2012 is lower than the U.S. statutory income tax rate of 35% primarily due to lower rates of tax in certain foreign jurisdictions, partially offset by an increase in tax reserves and state income taxes.

The tax rate for the nine months ended September 30, 2012 is lower than the U.S. statutory income tax rate of 35% primarily due to lower rates of tax in certain foreign jurisdictions and the net reversal of tax reserves arising from audit settlements and the expiration of statutes of limitations, partially offset by state income taxes.

NOTE 10. 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.

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

OTHER

In the normal course of business with customers, vendors and others, we have entered into off-balance sheet arrangements, including surety bonds for performance, letters of credit and other bank guarantees, which totaled approximately $1.5 billion at September 30, 2012. It is not practicable to estimate the fair value of these financial instruments. None of the off-balance sheet arrangements either has, or is likely to have, a material effect on our unaudited consolidated condensed financial statements.

NOTE 11. ACCUMULATED OTHER COMPREHENSIVE LOSS

Total accumulated other comprehensive loss attributable to Baker Hughes, net of tax, consisted of the following:



	September 30, 2012			December 31, 2011
Foreign currency translation adjustments	$	(243	)	$	(304	)
Pension and other postretirement benefits	(232		)	(251		)
Net gain on hedge transactions	1			—
Total accumulated other comprehensive loss attributable to Baker Hughes	$	(474	)	$	(555	)

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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 the unaudited consolidated condensed financial statements and the related notes thereto, as well as our Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Annual Report”). Phrases such as “Company,” “we,” “our” and “us” intend to refer to Baker Hughes Incorporated when used.

EXECUTIVE SUMMARY

Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry. The products and services we provide from our ongoing operations are:


•	drilling and evaluation of oil and natural gas wells;


•	completion and production of oil and natural gas wells; and


•	other businesses, including downstream refining and specialty polymers.

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. 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 2012, we generated revenue of $5.23 billion, an increase of $164 million or 3% compared to the same quarter a year ago. North America oilfield revenue for the third quarter of 2012 was $2.74 billion, an increase of 1% compared to the same quarter a year ago. Our results continued to be impacted by the pressure pumping business, which remains unbalanced primarily due to excess capacity in the market combined with lower Canadian activity. Oilfield revenue outside of North America for the third quarter of 2012 was $2.29 billion, an increase of 7% compared to the same quarter a year ago driven by strong growth in the Middle East and Asia Pacific regions.

Income from continuing operations attributable to Baker Hughes was $265 million for the third quarter of 2012 compared to $698 million for the same quarter a year ago. Profitability in North America was adversely impacted by the continued volatility related to our pressure pumping product line including both pricing pressure, as a result of the increasing supply of pressure pumping capacity in the market, and increased personnel and raw material costs. Our other product lines in U.S. Land, particularly drilling services, upstream chemicals, artificial lift and completions, experienced increased demand in the third quarter of 2012 compared to the same quarter a year ago. International profitability decreased in the third quarter of 2012 compared to the same quarter a year ago. Although activity has increased in many of our international regions, particularly Africa, Europe and the Middle East, increases in personnel and other operating costs have reduced profitability. Additionally, the third quarter of 2012 includes charges of $63 million before-tax ($43 million after-tax) primarily related to the impairment of information technology assets and the closing of a chemical manufacturing facility. The third quarter of 2011 was favorably impacted by a $214 million tax benefit associated with the reorganization of certain foreign subsidiaries.

The Company recently made the decision to sell its Process and Pipeline Services (“PPS”) business, which is a provider of precommissioning, maintenance and inspection services for oil and gas facilities and pipelines. As a result, the financial results of PPS have been reclassified to discontinued operations. PPS was previously a component of the Industrial Services segment, which now consists primarily of the Company's downstream refining and specialty polymers businesses.

As of September 30, 2012, we had approximately 58,800 employees compared to approximately 57,700 employees as of December 31, 2011, which included employees from our PPS business of approximately 1,200 and 1,100, respectively.

BUSINESS ENVIRONMENT

In North America, rig counts declined 6% in the third quarter of 2012 compared to the same period a year ago. Increased production in the unconventional natural gas shale plays continued to contribute to high natural gas working inventories and

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ultimately lower commodity prices. Customer spending in the natural gas shale plays remained limited, and as a result, natural gas-directed rig activity declined 45% in the third quarter of 2012 compared to the same period a year ago. This was partly offset by a 23% increase in oil-directed rig activity for the same time periods. Customer spending for oil in the U.S. remained strong during the third quarter of 2012 as evidenced by the fact that oil-directed rig activity increased 36% compared to the same period in 2011. However, this was offset by reduced activity in Canada where periods of wet weather and sluggish customer spending resulted in a 26% reduction in rig counts for the same time periods.

Outside of North America, customer spending is most heavily influenced by Brent oil prices. On average, Brent oil prices decreased 2% in the third quarter of 2012 compared to the same period a year ago as Europe's economic concerns increased, growth in China showed signs of contraction and global oil supplies increased. However, compared to the third quarter of 2011, our customers’ activity and spending levels increased in the third quarter of 2012. Due to the long-term planning cycles associated with many international projects, customers do not tend to react to short-term movements in oil prices.

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,
	2012		2011		2012		2011
Brent oil prices ($/Bbl) ⁽¹⁾	$	109.90	$	112.38	$	112.46	$	111.44
WTI oil prices ($/Bbl) ⁽²⁾	92.16		89.54		96.15		95.47
Natural gas prices ($/mmBtu) ⁽³⁾	2.88		4.05		2.54		4.21


(1)	Bloomberg Dated Brent (“Brent”)


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


(3)	Bloomberg Henry Hub Natural Gas Spot Price

Brent oil prices averaged $109.90/Bbl in the third quarter of 2012. Oil prices generally increased throughout the third quarter of 2012 primarily due to increasing geopolitical concerns in the Middle East and supply interruptions in the Gulf of Mexico due to Hurricane Isaac. However, renewed concerns about the global economy had an offsetting effect on prices and resulted in volatility in oil prices during the quarter. Prices ranged from a low of $96.59/Bbl at the beginning of July 2012 to a high of $117.59/Bbl in mid-September 2012. In its October 2012 Oil Market Report, the International Energy Agency (“IEA”) revised its 2012 estimated global oil demand downward to 89.7 million barrels per day from its original estimate of 89.9 million barrels. Despite the downward adjustment, the estimated 2012 global demand still exceeds 2011 global demand of 89.1 million barrels per day.

WTI oil prices averaged $92.16/Bbl in the third quarter of 2012. Similar to the Brent oil prices, WTI oil prices generally increased throughout the third quarter of 2012. Prices ranged from a low of $83.75/Bbl in early July 2012 to a high of $99.00/Bbl in mid-September 2012.

Natural gas prices averaged $2.88/mmBtu in the third quarter of 2012. Natural gas prices, which have been low since late 2011, continued to rebound during the early part of the quarter as warm weather in key consuming regions of the U.S. increased demand. However, natural gas storage injections outpaced analyst expectations throughout much of the quarter, resulting in lower prices in August and much of September. Overall for the quarter, prices ranged from a high of $3.20/mmBtu at the end of July 2012 to a low of $2.63/mmBtu at the end of August 2012. Prices closed at $3.08/mmBtu at the end of September, as natural gas rig counts declined to 13 year lows in the U.S. According to the U.S. Department of Energy (“DOE”), working natural gas in storage at the end of the third quarter of 2012 was 3,653/Bcf, which was 7% or 244/Bcf above the corresponding week in 2011.

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

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sources. This data is then compiled and distributed to various wire services and trade associations and is published on our website. We believe the counting process and resulting data is reliable; however, it is subject to our ability to obtain accurate and timely information. Rig counts are compiled weekly for the U.S. and Canada and monthly for all international rigs. Published international rig counts do not include rigs drilling in certain locations, such as Russia, the Caspian, Iran and onshore China because this information is not readily available. Baker Hughes resumed publication in June 2012 of the rig count in Iraq for the first time since August 1990.

Rigs in the U.S. and Canada 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. In international areas, rigs are counted on a weekly basis and deemed active if drilling activities occurred during the majority of the week. The weekly results are then averaged for the month and published accordingly. 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.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012	2011	% Change		2012	2011	% Change
U.S. - land and inland waters	1,855	1,911	(3	)%	1,909	1,805	6	%
U.S. - offshore	51	34	50	%	47	30	57	%
Canada	325	441	(26	)%	362	401	(10	)%
North America	2,231	2,386	(6	)%	2,318	2,236	4	%
Latin America	414	437	(5	)%	428	421	2	%
North Sea	38	38	—	%	38	40	(5	)%
Continental Europe	79	85	(7	)%	78	77	1	%
Africa	108	71	52	%	93	76	22	%
Middle East	390	289	35	%	348	288	21	%
Asia Pacific	230	249	(8	)%	240	258	(7	)%
Outside North America	1,259	1,169	8	%	1,225	1,160	6	%
Worldwide	3,490	3,555	(2	)%	3,543	3,396	4	%

Third Quarter of 2012 Compared to the Third Quarter of 2011

The rig count in North America decreased 6% in the third quarter of 2012 compared to the same period a year ago as natural gas-directed rig counts declined 45%, partially offset by an increase in oil-directed rig counts of 23%. The natural gas-directed rig count reflected a 46% decrease in the U.S. and a 39% decrease in Canada. The oil-directed rig count increased 36% in the U.S., but was offset by a 21% decrease in Canada. Natural gas-directed drilling was negatively impacted by the continued weakness in North America natural gas prices which discouraged new investment in natural gas fields. The growth in oil-directed drilling in the U.S. was primarily a result of strong oil prices and the industry’s ability to apply drilling and completion techniques to unconventional oil reservoirs that were originally applied to similar natural gas reservoirs. In Canada, many operators curtailed their drilling plans during the third quarter of 2012 due to recent oil price volatility, reduced cash flows and wet weather.

Outside North America, the rig count increased 8%. Starting June 2012, the Middle East rig count included Iraq. Excluding Iraq, which had 76 rigs during the third quarter of 2012, the international rig count increased 1%. The rig count in Latin America decreased primarily due to lower rig activity in Brazil, Colombia and Venezuela, partially offset by increased rig activity in Ecuador, Mexico and Argentina. The rig count in the North Sea remained flat. In Continental Europe, the rig count decreased primarily due to lower activity in Norway, Poland and Romania. The rig count increased in Africa primarily due to resumption of drilling activities in Libya, as well as higher activity in Algeria and Nigeria. The rig count increased in the Middle East due to higher activity in Saudi Arabia, Oman and Egypt, as well as the inclusion of Iraq. In Asia Pacific, the rig count decreased as a result of decreased activity in Indonesia and offshore China, offset by modest increased activity in Malaysia and Australia.

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RESULTS OF OPERATIONS

The discussions below relating to significant line items from our unaudited consolidated condensed statements of income 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. In addition, the discussions below for revenue and cost of revenue are on a total basis as the business drivers for the individual components of product sales and services are similar. All dollar amounts in tabulations in this section are in millions of dollars, unless otherwise stated.

We conduct our business primarily through operating segments that are aligned with our geographic regions, which have been aggregated into five reportable segments. Prior to 2012, our reservoir development services business (“RDS”), consisting of consulting services provided to third parties and internal support to our oilfield operations, was included within the Industrial Services segment. In the first quarter of 2012, we changed our reporting structure to include RDS within our four oilfield geographic segments. All prior period segment disclosures for revenue and profit before tax have been reclassified to include RDS within our four oilfield geographic segments. The impact of this change to the Industrial Services segment was to reduce revenue by $23 million and $75 million for the three months and nine months ended September 30, 2011, respectively; and increase profit before tax by $16 million and $35 million for the three months and nine months ended September 30, 2011, respectively.

We recently initiated a plan to sell our PPS business, which was previously reported as part of the Industrial Services segment. Accordingly, we have reclassified the financial results for all prior periods to discontinued operations. Revenue was $114 million and $308 million for the three months and nine months ended September 30, 2011, respectively; and profit before tax was $13 million and $31 million for the three months and nine months ended September 30, 2011, respectively.

Revenue and Profit Before Tax

The performance of our operating segments is evaluated based on profit before tax, which is defined as income from continuing operations before income taxes and before the following: net interest expense, corporate expenses, and certain gains and losses not allocated to the segments.



	Three Months Ended September 30,				$ Change			% Change		Nine Months Ended September 30,				$ Change		% Change
	2012		2011		$ Change			% Change		2012		2011		$ Change		% Change
Revenue:
North America	$	2,742	$	2,721	$	21		1	%	$	8,277	$	7,451	$	826	11	%
Latin America	583		570		13			2	%	1,760		1,588		172		11	%
Europe/Africa/ Russia Caspian	866		863		3			—	%	2,684		2,462		222		9	%
Middle East/ Asia Pacific	844		711		133			19	%	2,393		2,088		305		15	%
Industrial Services	193		199		(6		)	(3	%)	594		547		47		9	%
Total	$	5,228	$	5,064	$	164		3	%	$	15,708	$	14,136	$	1,572	11	%

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	Three Months Ended September 30,						$ Change			% Change		Nine Months Ended September 30,						$ Change			% Change
	2012			2011			$ Change			% Change		2012			2011			$ Change			% Change
Profit Before Tax:
North America	$	288		$	602		$	(314	)	(52	%)	$	1,046		$	1,491		$	(445	)	(30	)%
Latin America	45			71			(26		)	(37	%)	189			204			(15		)	(7	)%
Europe/Africa/ Russia Caspian	104			103			1			1	%	413			235			178			76	%
Middle East/ Asia Pacific	71			75			(4		)	(5	%)	233			241			(8		)	(3	)%
Industrial Services	13			32			(19		)	(59	%)	58			80			(22		)	(28	)%
Total Operations	521			883			(362		)	(41	%)	1,939			2,251			(312		)	(14	)%
Corporate and Other	(59		)	(78		)	19			(24	%)	(232		)	(208		)	(24		)	12	%
Interest Expense, net	(49		)	(58		)	9			(16	%)	(153		)	(164		)	11			(7	)%
Loss on early extinguishment of debt	—			(40		)	40			(100	%)	—			(40		)	40			(100	)%
Total	$	413		$	707		$	(294	)	(42	%)	$	1,554		$	1,839		$	(285	)	(15	)%

Third Quarter of 2012 Compared to the Third Quarter of 2011

Revenue for the third quarter of 2012 increased $164 million or 3% compared to the third quarter of 2011, driven by increased activity across all segments, particularly in the Middle East/Asia Pacific (“MEAP”), North America and Latin America segments.

Profit before tax for the third quarter of 2012 decreased $294 million or 42% compared to the third quarter of 2011. Despite the increase in revenue, our profit before tax was significantly impacted by pricing pressure, higher personnel costs, and increased raw material expenses in our pressure pumping product line in North America. Increased allowance for doubtful accounts in Latin America and Europe, high operating costs and third party expenses related to new integrated operations contracts in the Middle East further eroded profits. In the third quarter of 2012, we incurred a charge of $43 million before-tax related to the impairment of certain information technology assets primarily associated with internally developed software and other assets. Additionally, in the third quarter of 2012, we incurred a charge of $20 million before-tax related to the closure of a chemical manufacturing facility that is part of the cost saving initiative in our global supply chain organization. As our information technology and supply chain organizations support our global operations, these charges have been allocated to all segments.

North America

North America revenue increased 1% in the third quarter of 2012 compared to the third quarter of 2011, despite rig counts declining 6%. The primary catalysts for the growth seen in North America include sustained high oil prices during the third quarter of 2012 compared to historical prices; new innovative technologies for drilling systems and completion systems that have resulted in increased market share, particularly in the unconventional reservoirs in U.S. Land; a continuing shift of drilling activities from the natural gas-directed unconventional reservoirs to the oil-directed reservoirs in U.S. Land; and improved rig activity in the offshore Gulf of Mexico. In the third quarter of 2012, there were significant increases in completions systems, drilling services, artificial lift, upstream chemicals and drill bits activities. In the Gulf of Mexico, revenue increased 30% in the third quarter of 2012 compared to the third quarter of 2011 as rig counts increased 50%, driven by increased deepwater activity, which more than offset the impact of Hurricane Isaac. These increases in revenue were offset by reduced demand and pricing in our pressure pumping product line in the U.S. and Canada. Additionally, as a result of reduced customer spending in Canada, oil-directed rig counts decreased 21% and natural gas-directed rig counts were down 39% compared to the third quarter of 2011. Overall, this resulted in a 14% reduction in our Canadian revenue during the third quarter of 2012 compared to the third quarter of 2011.

North America profit before tax was $288 million in the third quarter of 2012, a decrease of $314 million compared to the third quarter of 2011. Despite slightly higher revenue, profits in U.S. Land and Canada declined due to decreased fleet utilization and lower pricing, higher personnel costs, increased costs for critical raw materials and higher depreciation expenses primarily in our pressure pumping product line. Partially offsetting these reductions were improved profits in the Gulf of Mexico, where both revenue and profit margins have returned to pre-moratorium levels as activity levels have increased substantially. North America profit before tax was negatively impacted by a $33 million charge associated with the information technology expenses and the facility closure.

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Latin America

Latin America revenue increased 2% in the third quarter of 2012 compared to the third quarter of 2011. The primary drivers of the increase were higher activity benefiting our drill bit, wireline services and artificial lift product lines in Venezuela. This was partially offset by reduced activity in Mexico field lab projects.

Latin America profit before tax decreased 37% in the third quarter of 2012 compared to the third quarter of 2011. While revenue modestly increased, profits were negatively impacted by an increase of $22 million in our allowance for doubtful accounts with a major customer and higher personnel costs. Latin America profit before tax was also negatively impacted by a $7 million charge associated with the information technology expenses and the facility closure.

Europe/Africa/Russia Caspian

Europe/Africa/Russia Caspian (“EARC”) revenue remained relatively flat in the third quarter of 2012 compared to the third quarter of 2011. Strong growth was seen in Africa, particularly with drilling systems in Mozambique and Nigeria, completion systems in Nigeria, Angola and Ghana and wireline services in Nigeria, Uganda and Angola. Revenue increases in Africa were offset by declines in our Europe region due primarily to reduced drilling fluids activity in Norway and unfavorable currency fluctuations.

EARC profit before tax also remained relatively flat in the third quarter of 2012 compared to the third quarter of 2011. A favorable change in sales mix in Sub Sahara Africa and Russia contributed to improved margins and increased profitability but were offset by a $7 million increase in our allowance for doubtful accounts due to a customer bankruptcy and an $11 million charge associated with the information technology expenses and the facility closure.

Middle East/Asia Pacific

MEAP revenue increased 19% in the third quarter of 2012 compared to the third quarter of 2011. The increase in this segment was attributable to new integrated operations contracts in Iraq; higher demand for drilling services, drilling fluids, and completions systems in Saudi Arabia; and improved demand for completions systems in Australia and Indonesia. This increase was partially offset by reduced activity for pressure pumping, drilling fluids and drill bits in India.

MEAP profit before tax remained relatively flat in the third quarter of 2012 compared to the third quarter of 2011. While revenue increased, profit before tax was impacted by high operating and third party costs associated with the new integrated operations activities in Iraq and increased personnel costs. MEAP profit before tax was also negatively impacted by a $10 million charge associated with the information technology expenses and the facility closure.

Industrial Services

For Industrial Services, which now excludes our PPS business, revenue decreased $6 million and profit before tax decreased $19 million in the third quarter of 2012 compared to the third quarter of 2011. The decrease in revenue and profit before tax was primarily driven by reduced demand for polymers in Europe and Asia Pacific due to unfavorable economic conditions. Industrial Services profit before tax was also negatively impacted by a $2 million charge associated with the information technology expenses and the facility closure.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Revenue for the nine months ended September 30, 2012 increased $1.57 billion or 11% compared to the nine months ended September 30, 2011, driven by increased activity across all segments, particularly in the North America and MEAP segments. Increased revenue in North America is attributed to the strong performance of our product lines other than pressure pumping, while MEAP revenue is being driven by our integrated operations contracts in Iraq and higher demand for completions systems in Saudi Arabia and Australia.

Profit before tax for the nine months ended September 30, 2012 decreased $285 million or 15% compared to the nine months ended September 30, 2011. In North America, despite the increase in revenue, profit before tax was significantly impacted by pricing pressure, higher personnel costs, and increased raw material expenses in our pressure pumping product line. Profitability in our EARC segment has improved mainly as a result of increased revenue in Norway, Nigeria, Libya and Sub Sahara Africa. High operating costs and third party expenses related to new integrated operations contracts in the Middle East reduced profitability. Additionally, increased information technology expenses, charges associated with the closing of a chemical manufacturing facility along with increased amortization also impacted profitability.

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Costs and Expenses

The table below details certain unaudited consolidated condensed statement of income data and their percentage of revenue.



	Three Months Ended September 30,								Nine Months Ended September 30,
	2012				2011				2012				2011
	$		%		$		%		$		%		$		%
Revenue	$	5,228	100	%	$	5,064	100	%	$	15,708	100	%	$	14,136	100	%
Cost of revenue	4,305		82	%	3,843		76	%	12,660		81	%	10,900		77	%
Research and engineering	117		2	%	115		2	%	366		2	%	331		2	%
Marketing, general and administrative	344		7	%	301		6	%	975		6	%	862		6	%

Cost of Revenue

Cost of revenue as a percentage of revenue was 82% and 81% for the three months and nine months ended September 30, 2012, respectively, compared to 76% and 77% for the three months and nine months ended September 30, 2011, respectively. The increase in cost of revenue as a percentage of revenue for the three and nine months was due primarily to lower pricing and higher costs with respect to our pressure pumping product line in North America, start-up and third party costs associated with the new integrated operations activities in Iraq, as well as increased expenses related to amortization. Additionally, during the third quarter of 2012, we recorded a charge of $20 million related to the closure of a chemical manufacturing facility as part of our supply chain cost saving initiative, and a $29 million charge to increase our allowance for doubtful accounts in Latin America and Europe.

Research and Engineering

Research and engineering expenses increased 2% and 11% for the three months and nine months ended September 30, 2012, respectively, compared to the same periods a year ago. The increase in research and engineering expenses was primarily driven by an increase in research materials and personnel costs associated with the opening and staffing of technology centers in Brazil and Saudi Arabia.

Marketing, General and Administrative

Marketing, general and administrative (“MG&A”) expenses increased 14% and 13% for the three months and nine months ended September 30, 2012, respectively, compared to the same periods a year ago. The increase in expenses for the three months is primarily due to a charge of $43 million related to the impairment of certain information technology assets primarily associated with internally developed software and other assets. In addition to these costs, the increase in expenses for the nine months resulted from ongoing activities to further improve productivity and efficiency through the coordination and integration of our worldwide operations, including software implementations, partially offset by decreased personnel costs.

Income Taxes

Total income tax expense was $143 million and $479 million for the three months and nine months ended September 30, 2012, respectively. Our effective tax rate on income from continuing operations before income taxes for the three months and nine months ended September 30, 2012 was 34.6% and 30.8%, respectively. The tax rate for the three months ended September 30, 2012 is lower than the U.S. statutory income tax rate of 35% primarily due to lower rates of tax in certain foreign jurisdictions, partially offset by an increase in tax reserves and state income taxes. The tax rate for the nine months ended September 30, 2012 is lower than the U.S. statutory income tax rate of 35% primarily due to lower rates of tax in certain foreign jurisdictions and the net reversal of tax reserves arising from audit settlements and the expiration of statutes of limitations, partially offset by state income taxes.

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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 natural gas, their ability to fund their capital programs, and the impact of new government regulations.

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 that oil and natural gas companies expect for developing oil and natural gas reserves. Our forecasts are based on evaluating a number of external sources as well as our internal estimates. External sources include publications by the International Energy Agency (“IEA”), Organization of Petroleum Exporting Countries (“OPEC”), the Energy Information Administration (“EIA”), and the Organization for Economic Cooperation and Development (“OECD”). We acknowledge that there is a substantial amount of uncertainty regarding these forecasts, thus, while we have internal estimates regarding economic expansion, hydrocarbon demand and overall oilfield activity, we position ourselves to be flexible and responsive to a wide range of potential outcomes.

The primary drivers impacting the 2012 business environment include the following:

•

Worldwide Economic Growth - In general there is a strong linkage between overall economic activity, growth and the demand for hydrocarbons. Although we continue to see modest economic growth across the OECD countries and relatively strong growth among many developing economies, there is substantial concern regarding the economic outlook through the rest of 2012 and the beginning of 2013. These concerns are primarily fueled by sovereign debt issues in Europe, an apparent slowdown in the Chinese economy, and the moderate rate of the economic growth in the U.S. The European sovereign debt crisis and the reduction in economic activity have impacted the economies of major exporters, including the U.S. and China. Although steps are being taken by governments to resolve this issue, there is still concern that further downward adjustments to economic growth will occur in the coming months. China's rapid economic growth and industrialization has been a major factor in driving up world-wide economic growth since the recession of 2008/2009. While it is expected that China will continue to grow at a meaningful pace, there has been a slowdown in China's growth rate through September 2012 which is expected to continue during the remainder of the year. In the U.S., there has been a slow recovery from the recession of 2008/2009 as the economy continues to deal with the effects of the financial crisis, and the expectation is for only modest economic growth in the U.S. throughout 2012. However, this growth may be hampered by weakness or further deterioration of the global economy, particularly in China and Europe.

•

Demand for Hydrocarbons - In its October 2012 Oil Market Report, the IEA forecasted global demand for oil to increase 0.7 million barrels per day to a record 89.7 million barrels per day in 2012. Oil demand is expected to further increase by 0.8 million barrels per day in 2013. This expected increase in demand for oil should support increased expenditures within the oil and gas sector. In addition, natural gas is an increasingly important hydrocarbon to meet the world’s energy needs. In its October 2012 Short-Term Energy and Winter Fuels Outlook, the EIA stated that U.S. natural gas demand will reach a record 69.8 billion cubic feet per day in 2012. Although slightly down from 2012, U.S. natural gas demand in 2013 is forecasted to remain high at 69.6 billion cubic feet per day. Global demand for natural gas is also expected to increase as production from major gas fields in the Middle East, Africa and Asia Pacific are imported into the consuming regions, particularly in Europe and Asia.

•

Oil Production - OPEC considers global spare oil production capacity to be at comfortable levels with healthy commercial stock levels. However, sustained higher oil prices have led non-OPEC producers, particularly in the U.S., to increase capital spending and apply new technology to increase oil production. Although this is a positive trend for the U.S. that is expected to continue for many years to come, increased price volatility, driven by global economic and geopolitical uncertainties, may lead to delays in operator investment decisions across the rest of the world.

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•

Natural Gas Production - Worldwide natural gas production continues to grow. Despite this overall trend, low natural gas prices in North America have resulted in a reduction in the natural gas-directed rig activity in this region. This has begun to impact North America natural gas production, though not enough to result in a substantial increase in prices. Overall, worldwide natural gas production will, however, tend to be more stable as high natural gas prices in places such as Europe and Asia encourage sustained global growth of natural gas production. In addition, the announced shift away from nuclear power generation by several countries is expected to further support natural gas prices, and the development of natural gas projects in the OECD outside North America.

•

Oil Prices - With WTI oil prices trading between $78/Bbl and $109/Bbl, and Brent trading between $89/Bbl and $127/Bbl during the first nine months of 2012, we believe most oil developments globally will continue to provide adequate returns to encourage incremental investment. Based on oil supply forecasts and modest anticipated economic growth globally, we would expect oil prices to remain relatively strong throughout 2012 barring any major macro-economic event.

•

Natural Gas Prices - With natural gas prices trading between $1.84/mmBtu and $3.20/mmBtu during the first nine months of 2012, which are particularly low when compared to oil on a BTU equivalent basis, we believe that the economics of many dry natural gas-directed investments in North America have become marginal. This is primarily due to the abundant supplies available from the unconventional plays in North America, including natural gas produced in association with unconventional oil. The EIA, however, expects natural gas prices in North America to moderately increase in 2013 as a result of the reduction in natural gas-directed drilling activity throughout 2012.

Activity and Spending Outlook for North America - Overall customer spending in North America is expected to increase in 2012 compared to 2011, but the average annual rig count is expected to decrease 1%. The slowdown in the spending directly related to natural gas development has been largely offset by incremental investment to develop unconventional plays with crude oil and natural gas liquids content. However, due to recent volatility in oil prices, customer spending is expected to hold at current levels in the near term, resulting in a flat oil rig count for the remainder of the year. In the unconventional dry gas plays, while investment has declined throughout the year due to historically low natural gas pricing levels, we expect the reductions in rig counts will slow going forward as gas prices have rebounded moderately. Overall service intensity has increased in North America during the year as customers are demanding key technologies, such as advanced directional drilling, more complex completion systems and pressure pumping to develop the unconventional plays with liquids content. Despite this increase in demand, however, pricing has declined in some basins, particularly for hydraulic fracturing where current pressure pumping capacity exceeds demand. This pricing pressure is expected to continue for the remainder of 2012 and into early 2013. In the Gulf of Mexico, the active rig count has increased to near pre-moratorium levels. Activity on the continental shelf has been strong, and there has been a steady increase in the granting of new deepwater permits. It is expected that exploration drilling as well as completions and development activity in the Gulf of Mexico will continue to increase throughout the remainder of 2012 and 2013, with additional deepwater rigs being added.

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 and some major gas export projects. Customers are expected to increase spending to develop new resources and offset declines from existing developed reserves. Areas that are expected to see increased spending throughout the rest of the year and into 2013 include: the Middle East, in particular Iraq, including the Kurdistan province, and Saudi Arabia; and Latin America, with the largest growth expected in Brazil, Mexico and Colombia. In Africa, traditional growth areas such as Angola and Nigeria are being augmented by new provinces such as Ghana, Uganda and Mozambique. Russia is striving to maintain 10 million barrels of oil per day until the end of the decade by investing in Eastern Siberia and eventually in the Arctic offshore. Australia is leading the expansion of export LNG projects, requiring conventional offshore gas drilling in the northwest shelf as well as coal bed methane operations onshore Queensland. While overall unconventional drilling outside North America is still at its infancy, activities in Australia, China, Saudi Arabia and Argentina are showing early promise.

LIQUIDITY AND CAPITAL RESOURCES

Our objective in financing our business is to maintain adequate financial resources and access to sufficient liquidity. At September 30, 2012, we had cash and cash equivalents of $1.01 billion, of which substantially all was held by foreign subsidiaries. A substantial portion of the cash held by foreign subsidiaries at September 30, 2012 was reinvested in our international operations as our intent is to use this 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 have a $2.5 billion committed revolving credit facility with commercial banks and a commercial paper program under which we may issue up to $2.5 billion. The maximum

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combined borrowing at any time under both the credit facility and commercial paper program is $2.5 billion. We had $1.19 billion of outstanding commercial paper at September 30, 2012. We believe that cash on hand, cash flows from operating activities, and the available credit facility, including the issuance of commercial paper, will provide sufficient liquidity to manage our global 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, 2012, we used cash to pay for a variety of activities including working capital needs, capital expenditures and payment of dividends.

Cash Flows

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



(In millions)	2012			2011
Operating activities	$	937		$	656
Investing activities	(1,875		)	(1,150		)
Financing activities	902			(164		)

Operating Activities

Cash flows from operating activities provided $937 million and $656 million in the nine months ended September 30, 2012 and 2011, respectively. Despite a decrease in income from continuing operations of $330 million, cash flows from operating activities increased $281 million. This increase is primarily due to the change in net operating assets and liabilities, which used less cash in the nine months ended September 30, 2012 compared to the same period in 2011.

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

•

An increase in accounts receivable used cash of $199 million and $1,074 million in the nine months ended September 30, 2012 and 2011, respectively. The change in accounts receivable in the nine months ended September 30, 2012 was primarily due to an increase in activity. The change in accounts receivable in the nine months ended September 30, 2011 was primarily due to an increase in activity as well as an increase in days sales outstanding (defined as the average number of days our net trade receivables are outstanding based on quarterly revenue) due to temporary invoicing delays resulting from the implementation of our enterprise wide software system for BJ Services in North America.


•	An increase in inventory used cash of $660 million and $465 million in the nine months ended September 30, 2012 and 2011, respectively, driven by an increase in production of finished goods to support current activity levels.


•	Accrued employee compensation and other accrued liabilities used cash of $20 million and provided cash of $81 million in the nine months ended September 30, 2012 and 2011, respectively. The net change of $101 million was due primarily to an increase in payments related to employee bonuses earned in 2011 but paid in 2012 coupled with lower employee compensation accruals in 2012.


•	Income taxes payable used cash of $62 million and $189 million in the nine months ended September 30, 2012 and 2011, respectively. The net change of $127 million was primarily due to a decrease in income taxes paid in 2012 compared to 2011.


•	Other operating items used cash of $147 million and provided cash of $3 million in the nine months ended September 30, 2012 and 2011, respectively. The net change of $150 million was primarily due to an increase in payments for prepaid assets and an increase in contributions to our pension plans.

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 $2,160 million and $1,624 million in the nine months ended September 30, 2012 and 2011, 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.

Proceeds from the disposal of assets were $285 million and $215 million in the nine months ended September 30, 2012

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and 2011, respectively. These disposals related to equipment that was lost-in-hole, and property, machinery, and equipment no longer used in operations that were sold throughout the period.

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

Financing Activities

We had net proceeds from borrowings of $1,075 million as compared to net repayments of $41 million related to commercial paper and other short-term debt in the nine months ended September 30, 2012 and 2011, respectively.

In August 2011, we completed a private placement of $750 million 3.2% senior notes that will mature in August 2021, resulting in net proceeds of approximately $742 million after deducting the underwriting discounts and expenses of the offering. In September 2011, we used $563 million of the net proceeds from the senior notes to redeem our 6.5% notes in full. The remaining net proceeds from the senior notes were used for general corporate purposes. In June 2011, we repaid $250 million of our 5.75% notes that matured.

In March 2012, pursuant to a registration rights agreement, we filed a registration statement with the SEC that became effective with respect to an offer to exchange the unregistered 3.2% senior notes for substantially identical registered notes without the existing transfer restrictions. The offer closed in May 2012 with all notes exchanged. This exchange had no impact to our financial statements or cash flows.

Total debt outstanding at September 30, 2012 was $5.15 billion, an increase of $1.08 billion compared to December 31, 2011. The total debt to total capitalization (defined as total debt plus equity) ratio was 0.23 at September 30, 2012 and 0.20 at December 31, 2011. We received proceeds of $42 million and $144 million in the nine months ended September 30, 2012 and 2011, respectively, from the issuance of common stock through the exercise of stock options and the employee stock purchase plan.

Our Board of Directors has authorized a program to repurchase our common stock from time to time. In the nine months ended September 30, 2012 and 2011, we did not repurchase any shares of common stock. At September 30, 2012, we had authorization remaining to repurchase approximately $1.2 billion in common stock.

We paid dividends of $197 million and $195 million in the nine months ended September 30, 2012 and 2011, respectively.

Available Credit Facility

We have a $2.5 billion committed revolving credit facility with commercial banks that matures in September 2016, and at September 30, 2012, we were in compliance with all of the facility’s covenants. There were no direct borrowings under the committed credit facility during the quarter ended September 30, 2012. We also have an outstanding commercial paper program under which we may issue from time to time up to $2.5 billion in commercial paper with maturity of no more than 270 days. The maximum combined borrowing at any point in time under both the commercial paper program and the credit facility is $2.5 billion. At September 30, 2012, we had $1.19 billion of commercial paper outstanding.

If market conditions were to change and our revenue was reduced significantly 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 facility. However, a downgrade in our credit ratings could increase the cost of borrowings under the facility 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 facility.

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

Cash Requirements

In 2012, we believe cash on hand, commercial paper borrowings, cash flows from operating activities and the available credit facility 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

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strategies.

In 2012, we expect our capital expenditures to be between approximately $2.7 billion to $2.9 billion, excluding any amount related to acquisitions. The expenditures are expected to be used primarily for normal, recurring items necessary to support 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 2012, we also expect to make interest payments of between $225 million and $240 million, based on debt levels as of September 30, 2012. We anticipate making income tax payments of between $1.0 billion and $1.1 billion in 2012.

We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. We anticipate paying dividends of between $259 million and $269 million in 2012; however, the Board of Directors can change the dividend policy at any time.

For all defined benefit pension plans, we make contributions to the plans in amounts equal to or greater than amounts necessary to meet minimum governmental funding requirements. During the nine months ended September 30, 2012, we contributed approximately $280 million to our post retirement, defined benefit and defined contribution plans. We expect to make additional contributions of between $75 million to $80 million to these plans during the fourth quarter of 2012.

New Accounting Standards Updates

FORWARD-LOOKING STATEMENTS

MD&A and certain statements in the Notes to Unaudited Consolidated Condensed Financial Statements, includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act (each a “forward-looking statement”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “probable,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “potential, “ “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward-looking statements. Our forward-looking statements are based on assumptions that we believe to be reasonable but that may not prove to be accurate. The statements do not include the potential impact of future transactions, such as an acquisition, disposition, merger, joint venture or other transactions that could occur. We undertake no obligation to publicly update or revise any forward-looking statement. Our expectations regarding our business outlook, including changes in revenue, pricing, capital spending, profitability, strategies for our operations, impact of any common stock repurchases, oil and natural gas market conditions, the business plans of our customers, market share and

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contract terms, costs and availability of resources, legal, economic and regulatory conditions, and environmental matters are only our forecasts regarding these matters.

All of our forward-looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in “Part II, Item 1A. Risk Factors” section contained herein, as well as the risk factors described in our 2011 Annual Report, this filing and those set forth from time to time in our filings with the SEC. These documents are available through our website or through the SEC’s Electronic Data Gathering and Analysis Retrieval System (“EDGAR”) at http://www.sec.gov.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the nine months ended September 30, 2012, does not differ materially from that discussed under Part II, Item 7(a), “Quantitative and Qualitative Disclosures About Market Risk,” in our 2011 Annual Report on Form 10-K.

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, 2012, 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, 2012 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

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

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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 legal matters in Note 10 of the Notes to Unaudited Consolidated Condensed Financial Statements.

For additional discussion of legal proceedings see also, Item 3 of Part I of our 2011 Annual Report, Note 13 of the Notes to Consolidated Financial Statements included in Item 8 of our 2011 Annual Report, Item 1 of Part II of our Form 10-Q for the quarter ended March 31, 2012 and Item 1 of Part II of our Form 10-Q for the quarter ended June 30, 2012.

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 2011 Annual Report.

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, 2012.



Period	Total Number of Shares Purchased ⁽¹⁾	Average Price Paid Per Share ⁽¹⁾		Total Number of Shares Purchased as Part of a Publicly Announced Program ⁽²⁾	Average Price Paid Per Share ⁽²⁾		Total Number of Shares Purchased in the Aggregate	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Program ⁽³⁾
July 1-31, 2012	37,420	$	44.88	—	$	—	37,420	$	—
August 1-31, 2012	402	45.68		—	—		402	—
September 1-30, 2012	1,114	46.67		—	—		1,114	—
Total	38,936	$	44.94	—	$	—	38,936	$	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, 2012 as part of a publicly announced program.


(3)	Our Board of Directors has authorized a program to repurchase our common stock from time to time. During the three months ended September 30, 2012, we did not repurchase any shares of our common stock under the program. We had authorization remaining to repurchase up to a total of approximately $1.2 billion of our common stock.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

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 Item 104 of Regulation S-K is included in Exhibit 95 to this quarterly report.

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ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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



31.1*		Certification of Martin S. Craighead, President and 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 Martin S. Craighead, President and 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.

95*		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:	October 24, 2012	By:	/s/ PETER A. RAGAUSS
		Peter A. Ragauss
		Senior Vice President and Chief Financial Officer

Date:	October 24, 2012	By:	/s/ ALAN J. KEIFER
		Alan J. Keifer
		Vice President and Controller

2012.9.30 Exhibit 31.1

Exhibit 31.1

CERTIFICATION

I, Martin S. Craighead, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Baker Hughes Incorporated;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.




Date:	October 24, 2012	By:	/s/ Martin S. Craighead
			Martin S. Craighead
			President and Chief Executive Officer

2012.9.30 Exhibit 31.2

Exhibit 31.2

CERTIFICATION

I, Peter A. Ragauss, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Baker Hughes Incorporated;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.




Date:	October 24, 2012	By:	/s/ Peter A. Ragauss
			Peter A. Ragauss
			Senior Vice President and Chief Financial Officer

2012.9.30 Exhibit 32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Baker Hughes Incorporated (the “Company”) on Form 10-Q for the period ended September 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Martin S. Craighead, President and Chief Executive Officer of the Company, and Peter A. Ragauss, the Chief Financial Officer of the Company, each of the undersigned hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:


(i)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(ii)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Report.

The certification is given to the knowledge of the undersigned.





				/s/ Martin S. Craighead
		Name:		Martin S. Craighead
		Title:		President and Chief Executive Officer
		Date:		October 24, 2012

				/s/ Peter A. Ragauss
		Name:		Peter A. Ragauss
		Title:		Chief Financial Officer
		Date:		October 24, 2012

Q3 FY2012 Mine Safety Disclosure

Exhibit 95

Mine Safety Disclosure

The following disclosures are provided pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K, which require certain disclosures by companies required to file periodic reports under the Securities Exchange Act of 1934, as amended, that operate mines regulated under the Federal Mine Safety and Health Act of 1977.

The table that follows reflects citations, orders, violations and proposed assessments issued by the Mine Safety and Health Administration (the “MSHA”) for each mine of which Baker Hughes and/or its subsidiaries is an operator. The disclosure is with respect to the three months ended September 30, 2012. Due to timing and other factors, the data may not agree with the mine data retrieval system maintained by the MSHA at www.MSHA.gov.

Three Months Ended September 30, 2012



Mine or Operating Name/MSHA Identification Number	Section 104 S&S Citations	Section 104(b) Orders	Section 104(d) Citations and Orders	Section 110(b)(2) Violations	Section 107(a) Orders	Proposed MSHA Assessments ⁽¹⁾	Mining Related Fatalities	Received Notice of Pattern of Violations Under Section 104(e) (yes/no)	Received Notice of Potential to Have Pattern Under Section 104(e) (yes/no)	Legal Actions Pending as of Last Day of Period	Legal Actions Initiated During Period	Legal Actions Resolved During Period
Morgan City Grinding Plant/1601357	1	0	0	0	0	$108	0	N	N	0	0	0
Argenta Mine and Mill/2601152	1 ⁽²⁾	0	0	0	0	2,861 ⁽³⁾	0	N	N	0	0	0
Corpus Christi Grinding Plant/4103112	1	0	0	0	0	0 ⁽⁴⁾	0	N	N	0	0	0

⁽¹⁾

Amounts included are the total dollar value of proposed assessments received from MSHA during the three months ended September 30, 2012, regardless of whether the assessment has been challenged or appealed. Citations and orders can be contested and appealed, and as part of that process, are sometimes reduced in severity and amount, and sometimes dismissed. The number of citations, orders, and proposed assessments vary by inspector and also vary depending on the size and type of the operation.


⁽²⁾	One Section 104 S&S citation issued to an independent contractor (who is not a subsidiary of Baker Hughes) who is working at the Argenta Mine and Mill.


⁽³⁾	Amount includes $2,103 of assessments proposed by MSHA that relate to citations and orders issued to independent contractors (who are not subsidiaries of Baker Hughes) who are working at the Argenta Mine and Mill. As of September 30, 2012, MSHA had not yet proposed assessments on some citations relating to this site.


⁽⁴⁾	As of September 30, 2012, the MSHA had not yet proposed assessments on some citations relating to this site.