BAKER HUGHES a GE (BHI) 10-Q 2012 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2012

OR

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

Commission File Number 1-9397

Baker Hughes Incorporated

(Exact name of registrant as specified in its charter)

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 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 July 23, 2012, the registrant has outstanding 439,558,000 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 six months ended June 30, 2012 and 2011	2
	Consolidated Condensed Statements of Comprehensive Income (Unaudited) - Three months and six months ended June 30, 2012 and 2011	3
	Consolidated Condensed Balance Sheets (Unaudited) - June 30, 2012 and December 31, 2011	4
	Consolidated Condensed Statements of Equity (Unaudited) - Six months ended June 30, 2012 and 2011	5
	Consolidated Condensed Statements of Cash Flows (Unaudited) - Six months ended June 30, 2012 and 2011	6
	Notes to Unaudited Consolidated Condensed Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	24
Item 4.	Controls and Procedures	24
PART II -	OTHER INFORMATION
Item 1.	Legal Proceedings	25
Item 1A.	Risk Factors	25
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	25
Item 3.	Defaults Upon Senior Securities	25
Item 4.	Mine Safety Disclosures	25
Item 5.	Other Information	26
Item 6.	Exhibits	26
	Signatures	27

1

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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenue:
Sales	$	1,811		$	1,557		$	3,540		$	2,990
Services	3,515			3,184			7,141			6,276
Total revenue	5,326			4,741			10,681			9,266
Costs and expenses:
Cost of sales	1,404			1,266			2,772			2,432
Cost of services	2,850			2,452			5,747			4,783
Research and engineering	128			114			252			220
Marketing, general and administrative	305			292			644			574
Total costs and expenses	4,687			4,124			9,415			8,009
Operating income	639			617			1,266			1,257
Interest expense, net	(50		)	(54		)	(104		)	(106		)
Income before income taxes	589			563			1,162			1,151
Income taxes	(151		)	(228		)	(344		)	(432		)
Net income	438			335			818			719
Net loss attributable to noncontrolling interests	1			3			—			—
Net income attributable to Baker Hughes	$	439		$	338		$	818		$	719
Basic earnings per share attributable to Baker Hughes	$	1.00		$	0.78		$	1.86		$	1.65
Diluted earnings per share attributable to Baker Hughes	$	1.00		$	0.77		$	1.86		$	1.64
Cash dividends per share	$	0.15		$	0.15		$	0.30		$	0.30

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

2

Baker Hughes Incorporated

Consolidated Condensed Statements of Comprehensive Income

(In millions)

(Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Net Income	$	438		$	335	$	818		$	719
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments during the       period	(57		)	17		(2		)	83
Pension and other postretirement benefits	6			1		19			—
Net gain on hedge transactions	1			—		1			—
Other comprehensive income (loss), net of tax	(50		)	18		18			83
Comprehensive income	388			353		836			802
Comprehensive loss attributable to noncontrolling        interests	1			3		—			—
Comprehensive income attributable to Baker Hughes	$	389		$	356	$	836		$	802

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

3

Baker Hughes Incorporated

Consolidated Condensed Balance Sheets

(In millions)

(Unaudited)

	June 30, 2012			December 31, 2011
ASSETS
Current Assets:
Cash and cash equivalents	$	792		$	1,050
Accounts receivable - less allowance for doubtful accounts (2012 - $223;      2011 - $229)	4,985			4,878
Inventories, net	3,811			3,222
Deferred income taxes	265			251
Other current assets	594			396
Total current assets	10,447			9,797
Property, plant and equipment - less accumulated depreciation (2012 - $5,733;       2011 - $5,251)	8,111			7,415
Goodwill	5,957			5,956
Intangible assets, net	1,076			1,143
Other assets	597			536
Total assets	$	26,188		$	24,847
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable	$	1,859		$	1,810
Short-term debt and current portion of long-term debt	1,191			224
Accrued employee compensation	535			704
Income taxes payable	232			289
Other accrued liabilities	420			475
Total current liabilities	4,237			3,502
Long-term debt	3,841			3,845
Deferred income taxes and other tax liabilities	667			810
Liabilities for pensions and other postretirement benefits	550			578
Other liabilities	134			148
Commitments and contingencies
Equity:
Common stock	439			437
Capital in excess of par value	7,415			7,303
Retained earnings	9,248			8,561
Accumulated other comprehensive loss	(537		)	(555		)
Baker Hughes stockholders’ equity	16,565			15,746
Noncontrolling interests	194			218
Total equity	16,759			15,964
Total liabilities and equity	$	26,188		$	24,847

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

4

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					818									818
Other comprehensive income								18						18
Activity related to stock plans	2		29											31
Stock-based compensation cost			61											61
Cash dividends ($0.30 per share)					(131		)							(131		)
Net activity related to noncontrolling      interests			22								(24		)	(2		)
Balance at June 30, 2012	$	439	$	7,415	$	9,248		$	(537	)	$	194		$	16,759

	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						719								719
Other comprehensive income									83					83
Activity related to stock plans	4		110											114
Stock-based compensation cost			53											53
Cash dividends ($0.30 per share)						(130		)						(130		)
Net activity related to noncontrolling       interests			(1		)							66		65
Balance at June 30, 2011	$	436	$	7,167		$	7,672		$	(337	)	$	252	$	15,190

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

5

Baker Hughes Incorporated

Consolidated Condensed Statements of Cash Flows

(In millions)

(Unaudited)

	Six Months Ended June 30,
	2012			2011
Cash flows from operating activities:
Net income	$	818		$	719
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	743			646
Benefit for deferred income taxes	(147		)	(52		)
Gain on disposal of assets	(115		)	(90		)
Stock-based compensation cost	61			53
Provision for doubtful accounts	1			76
Changes in operating assets and liabilities:
Accounts receivable	(130		)	(512		)
Inventories	(597		)	(314		)
Accounts payable	60			57
Accrued employee compensation and other accrued liabilities	(178		)	(25		)
Income taxes payable	(84		)	(160		)
Other operating items, net	(308		)	(1		)
Net cash flows from operating activities	124			397
Cash flows from investing activities:
Expenditures for capital assets	(1,442		)	(1,023		)
Proceeds from maturities of short-term investments	—			250
Proceeds from disposal of assets	203			142
Acquisition of businesses, net of cash acquired	—			(5		)
Net cash flows from investing activities	(1,239		)	(636		)
Cash flows from financing activities:
Net proceeds (payments) of commercial paper and other short-term debt	962			(21		)
Repayment of long-term debt	—			(250		)
Proceeds from issuance of common stock	39			115
Dividends paid	(131		)	(130		)
Other financing items, net	(15		)	(9		)
Net cash flows from financing activities	855			(295		)
Effect of foreign exchange rate changes on cash	2			15
Decrease in cash and cash equivalents	(258		)	(519		)
Cash and cash equivalents, beginning of period	1,050			1,456
Cash and cash equivalents, end of period	$	792		$	937
Supplemental cash flows disclosures:
Income taxes paid, net of refunds	$	697		$	647
Interest paid	$	119		$	121
Supplemental disclosure of noncash investing activities:
Capital expenditures included in accounts payable	$	146		$	33

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

6

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 to the downstream refining and process and pipeline industries.

Basis of Presentation

Our unaudited consolidated condensed financial statements included herein have been prepared in accordance with generally accepted accounting principles in the United States of America and pursuant to the rules and regulations of the Securities and Exchange Commission (“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. 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 annual and interim 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.

7

Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 2. 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 June 30,		Six Months Ended June 30,
	2012	2011	2012	2011
Weighted average common shares outstanding for basic EPS	439	436	439	435
Effect of dilutive securities - stock plans	1	2	1	3
Adjusted weighted average common shares outstanding for      diluted EPS	440	438	440	438
Future potentially dilutive shares excluded from diluted      EPS:
Options with an exercise price greater than the average      market price for the period	8	2	8	3

NOTE 3. INVENTORIES

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

	June 30, 2012		December 31, 2011
Finished goods	$	3,385	$	2,830
Work in process	242		231
Raw materials	184		161
Total	$	3,811	$	3,222

NOTE 4. INTANGIBLE ASSETS

Intangible assets are comprised of the following:

	June 30, 2012						December 31, 2011
	Gross Carrying Amount		Less: Accumulated Amortization		Net		Gross Carrying Amount		Less: Accumulated Amortization		Net
Definite lived intangibles:
Technology	$	760	$	253	$	507	$	755	$	231	$	524
Contract-based	16		9		7		17		9		8
Trade names	121		38		83		121		16		105
Customer relationships	497		97		400		497		77		420
Subtotal	1,394		397		997		1,390		333		1,057
Indefinite lived intangibles:
In-process research and      development	79		—		79		86		—		86
Total	$	1,473	$	397	$	1,076	$	1,476	$	333	$	1,143

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 six months ended June 30, 2012 was $34 million and $68 million, respectively, and is estimated to be $68 million for the remainder of fiscal year 2012. Estimated amortization

8

Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

expense for each of the subsequent five fiscal years is expected to be as follows: 2013 - $112 million; 2014 - $96 million; 2015 - $89 million; 2016 - $88 million; and 2017 - $85 million.

NOTE 5. 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 June 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 June 30, 2012 and December 31, 2011 was $5,893 million and $4,910 million, respectively, which differs from the carrying amounts of $5,032 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 6. 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 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 before income taxes and before the following: net interest expense, corporate expenses, and certain gains and losses not allocated to the 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. Beginning in the first quarter of 2012, we changed our reporting structure to include the RDS business within our four oilfield geographic segments. All prior period segment disclosures for revenue and profit before tax have been reclassified to reflect this new presentation. The impact of this change to the Industrial Services segment was to reduce revenue by $29 million and $52 million, respectively, for the three months and six months ended June 30, 2011; and increase profit before tax by $10 million and $19 million, respectively, for the three months and six months ended June 30, 2011.

Summarized financial information is shown in the following table.

	Three Months Ended					Three Months Ended
	June 30, 2012					June 30, 2011
Segments	Revenue		Profit (Loss)			Revenue		Profit (Loss)
North America	$	2,672	$	357		$	2,372	$	434
Latin America	604		77			544		71
Europe/Africa/Russia Caspian	925		156			817		44
Middle East/Asia Pacific	804		87			713		87
Industrial Services	321		44			295		44
Total Operations	5,326		721			4,741		680
Corporate and Other	—		(82		)	—		(63		)
Interest Expense, net	—		(50		)	—		(54		)
Total	$	5,326	$	589		$	4,741	$	563

9

Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

	Six Months Ended					Six Months Ended
	June 30, 2012					June 30, 2011
Segments	Revenue		Profit (Loss)			Revenue		Profit (Loss)
North America	$	5,535	$	758		$	4,730	$	889
Latin America	1,177		144			1,018		133
Europe/Africa/Russia Caspian	1,818		309			1,599		132
Middle East/Asia Pacific	1,549		162			1,377		166
Industrial Services	602		66			542		67
Total Operations	10,681		1,439			9,266		1,387
Corporate and Other	—		(173		)	—		(130		)
Interest Expense, net	—		(104		)	—		(106		)
Total	$	10,681	$	1,162		$	9,266	$	1,151

NOTE 7. 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 June 30:

	U.S. Pension Plans						Non-U.S. Pension Plans						Other Postretirement Benefits
	2012			2011			2012			2011			2012			2011
Service cost	$	16		$	9		$	2		$	2		$	3		$	2
Interest cost	5			5			8			8			2			2
Expected return on plan assets	(9		)	(8		)	(9		)	(8		)	—			—
Amortization of prior service      benefit	—			—			—			—			(1		)	(1		)
Amortization of net loss	4			2			2			1			—			—
Net periodic cost	$	16		$	8		$	3		$	3		$	4		$	3

The components of net periodic cost are as follows for the six months ended June 30:

	U.S. Pension Plans						Non-U.S. Pension Plans						Other Postretirement Benefits
	2012			2011			2012			2011			2012			2011
Service cost	$	32		$	18		$	4		$	4		$	6		$	4
Interest cost	10			10			16			16			4			4
Expected return on plan assets	(18		)	(16		)	(18		)	(16		)	—			—
Amortization of prior service     benefit	—			—			—			—			(2		)	(2		)
Amortization of net loss	8			4			3			2			1			—
Benefit settlement	—			—			6			—			—			—
Net periodic cost	$	32		$	16		$	11		$	6		$	9		$	6

10

Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

We invest the assets of our U.S. and Non-U.S. 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 that were determined by using Level 3 unobservable inputs for the three months and six months ended June 30, 2012 were as follows:

	Three Months Ended June 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 March 31, 2012	$	—	$	5	$	165		$	19	$	15	$	204
Unrealized gains	—		—		1			—		—		1
Unrealized losses	—		—		(3		)	—		—		(3		)
Purchases	17		1		—			—		—		18
Ending balance at June 30, 2012	$	17	$	6	$	163		$	19	$	15	$	220

	Six Months Ended June 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	—		—		4			—		—		4
Unrealized losses	—		—		(3		)	—		—		(3		)
Purchases	17		1		52			—		—		70
Ending balance at June 30, 2012	$	17	$	6	$	163		$	19	$	15	$	220

NOTE 8. INCOME TAXES

Our effective tax rate on income before income taxes for the three months and six months ended June 30, 2012 was 25.6% and 29.6%, respectively, which is lower than the U.S. statutory income tax rate of 35% primarily due to the reversal of certain tax reserves arising from tax audit settlements and the expiration of statutes of limitations partially offset by state income taxes.

NOTE 9. COMMITMENTS AND CONTINGENCIES

LITIGATION

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

OTHER

In the normal course of business with customers, vendors and others, we have entered into off-balance sheet arrangements, including surety bonds for performance, letters of credit and other bank guarantees, which totaled approximately $1.4 billion at June 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.

11

Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 10. ACCUMULATED OTHER COMPREHENSIVE LOSS

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

	June 30, 2012			December 31, 2011
Foreign currency translation adjustments	$	(306	)	$	(304	)
Pension and other postretirement benefits	(232		)	(251		)
Net gain on hedge transactions	1			—
Total accumulated other comprehensive loss	$	(537	)	$	(555	)

12

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. We provide products and services for:

• drilling and evaluation of oil and natural gas wells;

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

• other industries, including downstream refining and process and pipeline industries.

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 second quarter of 2012, we generated revenue of $5.33 billion, an increase of $585 million or 12% compared to the same quarter a year ago. For the first six months of 2012, we generated revenue of $10.68 billion, an increase of $1.42 billion or 15% compared to the first six months of 2011. North America oilfield revenue for the second quarter of 2012 was $2.67 billion, an increase of 13% compared to the same quarter a year ago. North America oilfield revenue for the first six months of 2012 was $5.54 billion, an increase of 17% compared to the first six months of 2011. The increases in North America are primarily due to the increase in activity and service intensity in U.S. Land and Gulf of Mexico, driven by oil-directed drilling mainly in unconventional reservoirs. Oilfield revenue outside of North America for the second quarter of 2012 was $2.33 billion, an increase of 12% compared to the same quarter a year ago. Oilfield revenue outside of North America for the first six months of 2012 was $4.54 billion, an increase of 14% compared to the first six months of 2011. The increases outside of North America are primarily due to the increase in activity in Europe, Africa and the Middle East. Industrial Services revenue for the second quarter of 2012 was $321 million, an increase of 9% compared to the same quarter a year ago. Industrial Services revenue for the first six months of 2012 was $602 million, an increase of 11% compared to the first six months of 2011.

Net income attributable to Baker Hughes was $439 million for the second quarter of 2012 compared to $338 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 second quarter of 2012 compared to the same quarter a year ago, as well as sequentially. International profitability increased in the second quarter of 2012 compared to the same quarter a year ago driven primarily by activity increases in Europe, Africa and the Middle East.

As of June 30, 2012, we had approximately 58,500 employees compared to approximately 57,700 employees as of December 31, 2011.

BUSINESS ENVIRONMENT

In North America, despite a reduction in customer spending for natural gas projects, increased customer spending for oil projects resulted in a 7% increase in the North America rig count in the second quarter of 2012 compared to the same period a year ago. Oil-directed drilling increased 42% in the second quarter of 2012 compared to the same period a year ago, reflecting an energy equivalent premium relative to natural gas in North America. Natural gas-directed drilling activity declined 32% in

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the second quarter of 2012 compared to the same period a year ago, as mild winter conditions and increased production in unconventional natural gas shale plays contributed to high natural gas working inventories. As the supply of natural gas has exceeded demand, the resulting decline in natural gas prices has rapidly shifted customer spending away from natural gas-directed drilling.

Outside of North America, customer spending is most heavily influenced by Brent oil prices. Brent oil prices decreased 7% in the second 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 second quarter of 2011, our customers’ activity and spending levels have increased. 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 June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Brent oil prices ($/Bbl) (1)	$	108.95	$	116.81	$	113.74	$	110.96
WTI oil prices ($/Bbl) (2)	93.42		102.34		98.14		98.50
Natural gas prices ($/mmBtu) (3)	2.29		4.38		2.37		4.29

(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 $108.95/Bbl in the second quarter of 2012. Oil prices decreased throughout the second quarter of 2012 primarily due to the deepening economic crisis in Europe, growing concerns over a slowing Chinese economy, and rising global oil supplies. Prices ranged from a high of $125.60/Bbl at the beginning of April 2012 to a low of $88.74/Bbl in June 2012. The oil price did rebound moderately, back to $97.00/Bbl at the close of June 2012. The International Energy Agency (“IEA”) estimated in its July 2012 Oil Market Report that worldwide demand would increase 0.8 million barrels per day, or 0.9%, to 89.9 million barrels per day in 2012, up from 89.1 million barrels per day in 2011.

WTI oil prices averaged $93.42/Bbl in the second quarter of 2012. Similar to the Brent oil prices, WTI oil prices declined throughout the second quarter of 2012. Prices ranged from a high of $106.16/Bbl in May 2012 to a low of $77.69/Bbl in late June 2012. The WTI oil price rebounded to $84.96/Bbl at the close of June 2012.

Natural gas prices averaged $2.29/mmBtu in the second quarter of 2012. Natural gas prices, which have been low since late 2011, started to rebound during the quarter as warm weather in key consuming regions of the United States increased demand. Further, natural gas rig counts, which continued to decline during the quarter, resulted in lower natural gas storage injections relative to expectations and ultimately higher prices. During the quarter, prices ranged from a low of $1.84/mmBtu in April 2012 to a high of $2.87/mmBtu in June 2012. According to the U.S. Department of Energy (“DOE”), working natural gas in storage at the end of the second quarter of 2012 was 3,102/Bcf, which was 28% or 670/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 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.

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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  June 30,				Six Months Ended June 30,
	2012	2011	% Change		2012	2011	% Change
U.S. - land and inland waters	1,924	1,795	7	%	1,935	1,745	11	%
U.S. - offshore	47	31	52	%	45	28	61	%
Canada	177	187	(5	)%	380	379	—	%
North America	2,148	2,013	7	%	2,360	2,152	10	%
Latin America	438	417	5	%	435	413	5	%
North Sea	41	38	8	%	39	41	(5	)%
Continental Europe	76	74	3	%	76	74	3	%
Africa	90	76	18	%	86	79	9	%
Middle East	343	291	18	%	327	287	14	%
Asia Pacific	241	251	(4	)%	246	262	(6	)%
Outside North America	1,229	1,147	7	%	1,209	1,156	5	%
Worldwide	3,377	3,160	7	%	3,569	3,308	8	%

Second Quarter of 2012 Compared to the Second Quarter of 2011

The rig count in North America increased 7% reflecting a 46% increase in the U.S. oil-directed rig count and a 9% increase in the Canadian oil-directed rig count, partially offset by a 33% decrease in the U.S. natural gas-directed rig count, and a 28% decrease in the Canadian natural gas-directed rig count. The growth in oil-directed drilling 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. Natural gas-directed drilling was negatively impacted by the continued weakness in U.S. natural gas prices, which discouraged new investment in natural gas fields.

Outside North America, the rig count increased 7%. In general, the international rig count increased as operators responded to relatively strong oil prices that were well above the level considered economical to develop new reserves in the primary hydrocarbon basins of the world. The rig count in Latin America increased primarily due to higher rig activity in Mexico and Brazil, partially offset by decreased rig activity in Colombia and Venezuela. The rig count in the North Sea increased primarily due to higher rig activity in the United Kingdom. The rig count in Continental Europe was relatively flat. The rig count increased in Africa primarily due to resumption of drilling activities in Libya, and higher activity in Angola, particularly offshore. 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 the June 2012 monthly rig count for the first time since August 1990. In the month of June 2012, 79 rigs were reported, which equates to a monthly average of 26 rigs for the quarter. In Asia Pacific, the rig count decreased as a result of decreased activity in offshore China, Indonesia, and Vietnam, while activity increased in Australia.

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.

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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. Beginning in the first quarter of 2012, we changed our reporting structure to include the RDS business within our four oilfield geographic segments. All prior period segment disclosures for revenue and profit before tax have been reclassified to reflect this new presentation. The impact of this change to the Industrial Services segment was to reduce revenue by $29 million and $52 million, respectively, for the three and six months ended June 30, 2011; and increase profit before tax (as defined below) by $10 million and $19 million, respectively, for the three and six months ended June 30, 2011.

Revenue and Profit Before Tax

The performance of our operating segments is evaluated based on profit before tax, which is defined as income 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 June 30,						$ Change			% Change		Six Months Ended June 30,						$ Change			% Change
	2012			2011								2012			2011
Revenue:
North America	$	2,672		$	2,372		$	300		13	%	$	5,535		$	4,730		$	805		17	%
Latin America	604			544			60			11	%	1,177			1,018			159			16	%
Europe/Africa/      Russia Caspian	925			817			108			13	%	1,818			1,599			219			14	%
Middle East/      Asia Pacific	804			713			91			13	%	1,549			1,377			172			12	%
Industrial Services	321			295			26			9	%	602			542			60			11	%
Total	$	5,326		$	4,741		$	585		12	%	$	10,681		$	9,266		$	1,415		15	%
	Three Months Ended June 30,						$ Change			% Change		Six Months Ended June 30,						$ Change			% Change
	2012			2011								2012			2011
Profit Before Tax:
North America	$	357		$	434		$	(77	)	(18	%)	$	758		$	889		$	(131	)	(15	)%
Latin America	77			71			6			8	%	144			133			11			8	%
Europe/Africa/      Russia Caspian	156			44			112			255	%	309			132			177			134	%
Middle East/      Asia Pacific	87			87			—			—	%	162			166			(4		)	(2	)%
Industrial Services	44			44			—			—	%	66			67			(1		)	(1	)%
Total Operations	721			680			41			6	%	1,439			1,387			52			4	%
Corporate and Other	(82		)	(63		)	(19		)	30	%	(173		)	(130		)	(43		)	33	%
Interest Expense, net	(50		)	(54		)	4			(7	%)	(104		)	(106		)	2			(2	)%
Total	$	589		$	563		$	26		5	%	$	1,162		$	1,151		$	11		1	%

Second Quarter of 2012 Compared to the Second Quarter of 2011

Revenue for the second quarter of 2012increased $585 million or 12% compared to the second quarter of 2011, driven by increased activity across all segments, particularly in the North America, Europe/Africa/Russia Caspian (“EARC”), and Middle East/Asia Pacific (“MEAP”) segments.

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Profit before tax for the second quarter of 2012increased $26 million or 5% compared to the second quarter of 2011. Despite the increase in revenue, our profit before tax was significantly impacted by increased personnel and raw material costs in our pressure pumping business in North America as well as higher corporate expenses related to worldwide integration efforts and increased amortization. Profit before tax was also favorably impacted by the improving market conditions internationally, particularly in the EARC segment.

North America

North America revenue increased13% in the second quarter of 2012 compared to the second quarter of 2011. Revenue increases were supported by an 8% increase in the U.S. rig count, offset by a 5% reduction in the Canada rig count, which has seasonally low activity during the second quarter due to the spring break-up. The primary catalysts for the growth seen in North America include sustained high oil prices during the second quarter of 2012 compared to historical prices; improved rig activity in the offshore Gulf of Mexico; and a continuing shift of drilling activities from the natural gas-directed unconventional reservoirs to the oil-directed reservoirs in U.S. Land. The oil-directed unconventional reservoirs on land require a substantially higher proportion of services from Baker Hughes across all product lines. In the second quarter of 2012, there were significant increases in completions systems, drilling services, artificial lift, upstream chemicals and drilling fluids activities. In Canada, despite the normal activity declines following the spring break-up, higher pressure pumping activity on key projects favorably impacted revenue. Revenue in the Gulf of Mexico increased 28% in the second quarter of 2012 compared to the second quarter of 2011 as rig counts increased 52%, particularly in deepwater as permitting continued to increase.

North America profit before tax was $357 million in the second quarter of 2012, a decrease of $77 million compared to the second quarter of 2011. Despite higher revenue, profits in U.S. Land and Canada declined due to decreased fleet utilization and lower pricing. Also contributing were higher personnel costs, increased costs for critical raw materials, and increased freight and demurrage costs primarily in our pressure pumping business. Offsetting these reductions are improved profits in the Gulf of Mexico, where both revenues and profit margins have returned to pre-moratorium levels as activity levels have increased substantially.

Latin America

Latin America revenue increased11% in the second quarter of 2012 compared to the second quarter of 2011. The primary drivers of the increase were higher activity benefiting nearly all of our product lines in the Andean area and Venezuela. In Brazil, continued deepwater growth through the use of our drilling services and artificial lift product lines also contributed.

Latin America profit before tax increased8% in the second quarter of 2012 compared to the second quarter of 2011. While increased revenue was the primary contributor to the increased profitability, profits were negatively impacted by unfavorable currency fluctuations in Brazil, as well as higher personnel costs.

Europe/Africa/Russia Caspian

EARC revenue increased13% in the second quarter of 2012 compared to the second quarter of 2011. The primary drivers of the increase were increased activity for artificial lift, drilling services, and wireline services in Norway; increased completion systems and drilling fluids activity in Continental Europe; increased drilling services activity in Nigeria, Angola and Mozambique; and improving market conditions for wireline services and completions systems in Russia.

EARC profit before tax increased255% in the second quarter of 2012 compared to the second quarter of 2011 primarily as a result of a $70 million non-recurring charge related to Libya recorded in the second quarter of 2011. The increase in overall revenue within the segment due to increased activity in Norway, Continental Europe, Nigeria, Sub Sahara Africa, and Russia also contributed to profitability. Further, the favorable sales mix in Sub Sahara Africa and Russia improved margins and increased profitability.

Middle East/Asia Pacific

MEAP revenue increased13% in the second quarter of 2012 compared to the second 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 and drilling fluids in Australia. Increased pressure pumping, wireline services and upstream chemicals activity in Southeast Asia also contributed.

MEAP profit before tax remained relatively flat in the second quarter of 2012 compared to the second quarter of 2011. While revenue increased, profit before tax was offset by start-up and third party costs associated with the new integrated

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operations activities in Iraq. Higher operating expenses in certain areas within the region also offset profit before tax.

Industrial Services

Industrial Services revenue increased9% and profit before tax remained relatively flat in the second quarter of 2012 compared to the second quarter of 2011. The increase in revenue was driven by increased polymer activity. Despite the increase in revenue, profit before tax was impacted by an overall increase in cost of goods and services sold.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Revenue for the six months ended June 30, 2012increased$1.42 billion or 15% compared to the six months ended June 30, 2011, driven by increased activity across all segments, particularly in the North America and EARC segments.

Profit before tax for the six months ended June 30, 2012increased$11 million or 1% compared to the six months ended June 30, 2011. Improving market conditions, cost management, and a $70 million non-recurring charge related to Libya recorded in the second quarter of 2011 resulted in a comparatively higher profit before tax in our EARC segment. This is offset by our North America segment where despite the increase in revenue, profit before tax was significantly impacted by increased personnel costs, raw materials costs, and freight and demurrage costs in our pressure pumping business. Higher corporate expenses related to worldwide integration efforts and increased amortization also impacted profitability.

Costs and Expenses

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

	Three Months Ended June 30,								Six Months Ended June 30,
	2012				2011				2012				2011
	$		%		$		%		$		%		$		%
Revenue	$	5,326	100	%	$	4,741	100	%	$	10,681	100	%	$	9,266	100	%
Cost of revenue	4,254		80	%	3,718		78	%	8,519		80	%	7,215		78	%
Research and engineering	128		2	%	114		2	%	252		2	%	220		2	%
Marketing, general and     administrative	305		6	%	292		6	%	644		6	%	574		6	%

Cost of Revenue

Cost of revenue as a percentage of revenue was 80% for the three months and six months ended June 30, 2012, and 78% for the three months and six months ended June 30, 2011. The increase in cost of revenue as a percentage of revenue for the three and six months was due primarily to lower pricing and higher personnel, raw materials, logistics and repairs and maintenance 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.

Research and Engineering

Research and engineering expenses increased 12% and 15% for the three months and six months ended June 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, and increased costs related to patents.

Marketing, General and Administrative

Marketing, general and administrative (“MG&A”) expenses increased 4% and 12% for the three months and six months ended June 30, 2012, respectively, compared to the same periods a year ago. The increase in expenses resulted from ongoing activities to further improve productivity and efficiency through the coordination and integration of our worldwide operations, including software implementations, offset by decreased personnel costs.

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Income Taxes

Total income tax expense was $151 million and $344 million for the three months and six months ended June 30, 2012, respectively. Our effective tax rate on income before income taxes for the three months and six months ended June 30, 2012 was 25.6% and 29.6%, respectively, which is lower than the U.S. statutory income tax rate of 35% primarily due to the reversal of certain tax reserves arising from tax audit settlements and the expiration of statutes of limitations partially offset by state income taxes.

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 IEA, Organization of Petroleum Exporting Countries (“OPEC”), 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 throughout 2012. These concerns are primarily fueled by a concern over sovereign debt issues in Europe and a slowdown in the Chinese economy. The European sovereign debt crisis poses substantial risk to the worldwide economy as any substantial reduction in economic activity in Europe is likely to impact other major economies such as China, India and the U.S. Although steps are being taken to resolve this issue, there is still concern in the financial and equity markets that European economic activity will continue to slow in 2012. 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. It is expected that China will continue to grow at a meaningful pace, however, there is concern that the Chinese central bank’s efforts to limit inflation may temper growth prospects. 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 modest economic growth in the U.S. throughout 2012. However, weakness or deterioration of the global economy, particularly in China, India and Europe, could curtail U.S. economic growth from current estimates.

• Demand for Hydrocarbons - In its July 2012 Oil Market Report, the IEA maintained its forecasts that it expects global demand for oil to increase 0.8 million barrels per day in 2012 relative to 2011. The expected increase in demand for hydrocarbons should support increased spending to develop oil. Natural gas is an increasingly important hydrocarbon to meet the world’s energy needs, and recent innovations in the U.S. have substantially improved the production of natural gas in the U.S. As a result, natural gas demand remains near all-time highs in the U.S. Further, Europe and Asia are increasing their demand for natural gas as production from major gas fields in the Middle East, Africa and Asia Pacific are imported into the consuming regions.

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• Oil Production - Global spare oil production capacity is relatively limited and is proving to be inadequate to decouple oil prices from geopolitical supply disruptions throughout North Africa and the Middle East. Several key OPEC countries have announced plans to increase their exploration and development efforts to develop resources to offset reduced supplies from Iran and meet the expected increase in global demand. 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, it will provide only a modest offset to any potential supply disruption across the rest of the world.

• Natural Gas Production - Worldwide natural gas production continues to grow as a result of the emergence of the unconventional shale plays in North America as well as an abundance of large conventional fields in the Middle East, Asia and Latin America. Low natural gas prices in the U.S. have driven a reduction in the natural gas-directed rig activity in the U.S., which has begun to impact natural gas production, though not enough to result in a substantial increase in prices. Worldwide natural gas production will tend to be more stable as high natural gas prices in places such as Europe and Asia encourage natural gas production at current levels.

• Oil and Natural Gas Prices - With WTI oil prices trading between $77.69/Bbl and $109.49/Bbl during the first six months of 2012, we believe most unconventional oil plays in the U.S. as well as most conventional oil developments internationally will provide adequate returns to encourage incremental investment. Internationally, most oil developments are based on Brent oil prices which have also been at a high enough level to justify further investment in field development. Based on the tightness of the oil supply and the anticipated modest economic growth, we would expect oil prices to remain relatively strong throughout 2012 barring a major macro-economic event. Currently oil prices are somewhat elevated from levels seen early in the second quarter 2012 due to concern over geopolitical uncertainty in Iran and labor disputes in the North Sea. In North America, natural gas prices are particularly low when compared to oil on a BTU equivalent basis. This low price is driven by a combination of far more efficient production from the unconventional plays in the U.S. as well as a particularly warm winter. Although industrial demand, a warm summer in the U.S. thus far, and power generation are gradually increasing and demanding more natural gas, it is not enough to offset the increase in production from the unconventional plays. As a result, the expectation is that natural gas prices will remain particularly low throughout 2012.

Activity and Spending Outlook for North America - Overall customer spending in North America is expected to increase in 2012 compared to 2011, with the average annual rig count increasing 3%. Unconventional plays with crude oil and natural gas liquids content have been attracting incremental investment, resulting in increased oil rig counts through June 2012. 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 rebounded moderately and U.S. inventory injections declined in the second quarter. 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. The demand for these products has grown faster than the industry’s ability to supply them resulting in support for higher prices. However, due to the rapid shift from natural gas to oil and liquids rich drilling in North America, combined with new pressure pumping capacity in the market, pricing has declined in some basins, particularly for hydraulic fracturing. In the Gulf of Mexico, the active rig count has recently increased to near pre-moratorium levels. Activity on the continental shelf has been strong, and we have seen a steady increase in deepwater permits and subsequently deepwater drilling. We expect that exploration drilling activity in the Gulf of Mexico will continue to increase throughout the remainder of 2012, 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. Customers are expected to increase spending to develop new resources and offset declines from existing developed resources. Areas that are expected to see increased spending throughout the rest of the year include: the Middle East, in particular Iraq and Saudi Arabia; Latin America, with the largest growth coming from Brazil, Mexico, and Colombia; Africa, including Libya, Angola and Mozambique; and Russia.

Capital Expenditures - Our capital expenditures, excluding acquisitions, are expected to be between $2.7 billion and $2.9 billion for 2012. A portion of our planned capital expenditures can be adjusted to reflect changes in our expectations for future customer spending.

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LIQUIDITY AND CAPITAL RESOURCES

Our objective in financing our business is to maintain adequate financial resources and access to sufficient liquidity. At June 30, 2012, we had cash and cash equivalents of $792 million, of which substantially all was held by foreign subsidiaries. A substantial portion of the cash held by foreign subsidiaries at June 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 combined borrowing at any time under both the credit facility and commercial paper program is $2.5 billion. We had $1.09 billion of outstanding commercial paper at June 30, 2012. We believe that cash on hand 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 six months ended June 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 six months ended June 30:

(In millions)	2012			2011
Operating activities	$	124		$	397
Investing activities	(1,239		)	(636		)
Financing activities	855			(295		)

Operating Activities

Cash flows from operating activities provided $124 million and $397 million in the six months ended June 30, 2012 and 2011, respectively. This decrease in cash flows of $273 million is primarily due to the change in net operating assets and liabilities, which used more cash in the six months ended June 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 $130 million and $512 million in the six months ended June 30, 2012 and 2011, respectively. The change in accounts receivable was primarily due to an increase in activity and an increase in days sales outstanding (defined as the average number of days our net trade receivables are outstanding based on quarterly revenue) of approximately 2 days and 4 days for the six months ended June 30, 2012 and 2011, respectively.

• An increase in inventory used cash of $597 million and $314 million in the six months ended June 30, 2012 and 2011, respectively, driven by an increase in production of finished goods due to continued high activity levels.

• Accrued employee compensation and other accrued liabilities used $178 million and $25 million in cash in the six months ended June 30, 2012 and 2011, respectively. The increase in cash used was due primarily to an increase in payments in 2012 compared to 2011 related to employee bonuses earned in 2011 but paid in 2012.

• Other operating items used cash of $308 million and $1 million in the six months ended June 30, 2012 and 2011, respectively. The increase was primarily due to an increase in payments for pensions and other postretirement benefits and an increase in prepaid assets.

Investing Activities

Our principal recurring investing activity was the funding of capital expenditures to ensure that we have the appropriate levels and types of machinery and equipment in place to generate revenue from operations. Expenditures for capital assets totaled $1,442 million and $1,023 million in the six months ended June 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.

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Proceeds from the disposal of assets were $203 million and $142 million in the six months ended June 30, 2012 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.

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 $962 million as compared to net repayments of $21 million related to commercial paper and other short-term debt in the six months ended June 30, 2012 and 2011, respectively. Total debt outstanding at June 30, 2012 was $5.03 billion, an increase of $963 million compared to December 31, 2011. The total debt to total capitalization (defined as total debt plus equity) ratio was 0.23 at June 30, 2012 and 0.20 at December 31, 2011.

In March 2012, we filed a registration statement with the SEC pursuant to which we offered to exchange our unregistered 3.2% senior notes that were issued in a private placement for registered notes with substantially identical terms pursuant to a registration rights agreement. In April 2012, upon the registration statement being declared effective by the SEC, we commenced an exchange offer, which provided holders of our 3.2% senior notes the opportunity to exchange their unregistered notes for registered notes with substantially identical terms 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.

We received proceeds of $39 million and $115 million in the six months ended June 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 six months ended June 30, 2012 and 2011, we did not repurchase any shares of common stock. At June 30, 2012, we had authorization remaining to repurchase approximately $1.2 billion in common stock.

We paid dividends of $131 million and $130 million in the six months ended June 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 June 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 June 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 June 30, 2012, we had $1.09 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 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

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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 June 30, 2012. We anticipate making income tax payments of between $1.2 billion and $1.3 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 pension plans, we make annual contributions to the plans in amounts equal to or greater than amounts necessary to meet minimum governmental funding requirements. In 2012, we expect to contribute between $92 million and $102 million to our defined benefit pension plans. In 2012, we also expect to make benefit payments related to postretirement welfare plans of between $16 million and $18 million, and we estimate we will contribute between $240 million and $266 million to our defined contribution plans.

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 annual and interim 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.

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 transaction that could occur. We undertake no obligation to publicly update or revise any forward-looking statement. Our expectations regarding our business outlook, including changes in revenue, pricing, 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 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 six months ended June 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 June 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 June 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 9 of 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 and Item 1 of Part II of our Form 10-Q for the quarter ended March 31, 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 June 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)
April 1-30, 2012	31,615	$	41.67	—	$	—	31,615	$	—
May 1-31, 2012	2,093	43.85		—	—		2,093	—
June 1-30, 2012	—	—		—	—		—	—
Total	33,708	$	41.81	—	$	—	33,708	$	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 June 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 June 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

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Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this quarterly report.

ITEM 5. OTHER INFORMATION

On July 16, 2012, the Board of Directors of the Company approved a form of Change in Control Agreement to be used for all newly hired eligible executive officers, which is filed as Exhibit 10.1 to this quarterly report.

ITEM 6. EXHIBITS

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

3.1	Restated Bylaws of Baker Hughes Incorporated effective as of May 21, 2012 (filed as Exhibit 3.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed May 21, 2012).
10.1* +	Form of Change in Control Agreement between Baker Hughes Incorporated and certain of its executive officers effective July 16, 2012.
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:	July 26, 2012	By:	/s/ PETER A. RAGAUSS
		Peter A. Ragauss
		Senior Vice President and Chief Financial Officer
Date:	July 26, 2012	By:	/s/ ALAN J. KEIFER
		Alan J. Keifer
		Vice President and Controller

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