BAKER HUGHES a GE (BHI) 10-Q 2012 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2012

OR

¨ 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 of incorporation or organization)	(I.R.S. Employer Identification No.)
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  x    NO  ¨

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  x    NO  ¨

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	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	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  ¨    NO  x

As of April 25, 2012, the registrant has outstanding 438,479,000 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 ended March 31,  2012 and 2011	2
	Consolidated Condensed Statements of Comprehensive Income (Unaudited) - Three months ended March  31, 2012 and 2011	3
	Consolidated Condensed Balance Sheets (Unaudited) - March 31, 2012 and December 31,  2011	4
	Consolidated Condensed Statements of Equity (Unaudited) - Three months ended March 31,  2012 and 2011	5
	Consolidated Condensed Statements of Cash Flows (Unaudited) - Three months ended March 31,  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	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	21
Item 4.	Controls and Procedures	21
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	21
Item 1A.	Risk Factors	21
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	22
Item 3.	Defaults Upon Senior Securities	22
Item 4.	Mine Safety Disclosures	22
Item 5.	Other Information	22
Item 6.	Exhibits	22
Signatures		24

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 March 31,
	2012			2011
Revenue:
Sales	$	1,729		$	1,433
Services		3,626			3,092
Total revenue		5,355			4,525
Costs and expenses:
Cost of sales		1,368			1,166
Cost of services		2,897			2,331
Research and engineering		124			106
Marketing, general and administrative		339			282
Total costs and expenses		4,728			3,885
Operating income		627			640
Interest expense, net		(54	)		(52)
Income before income taxes		573			588
Income taxes		(193	)		(204)
Net income		380			384
Net income attributable to noncontrolling interests		(1	)		(3)
Net income attributable to Baker Hughes	$	379		$	381
Basic earnings per share attributable to Baker Hughes	$	0.86		$	0.88
Diluted earnings per share attributable to Baker Hughes	$	0.86		$	0.87
Cash dividends per share	$	0.15		$	0.15

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 March 31,
	2012			2011
Net income	$	380		$	384
Other comprehensive income, net of tax:
Foreign currency translation adjustments during the period		55			66
Pension and other postretirement benefits		13			(1)
Other comprehensive income, net of tax		68			65
Comprehensive income		448			449
Comprehensive income attributable to noncontrolling interests		(1	)		(3)
Comprehensive income attributable to Baker Hughes	$	447		$	446

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

3

Baker Hughes Incorporated

Consolidated Condensed Balance Sheets

(In millions)

(Unaudited)

	March 31, 2012			December 31, 2011
ASSETS
Current Assets:
Cash and cash equivalents	$	780		$	1,050
Accounts receivable - less allowance for doubtful accounts (2012 - $227; 2011 - $229)		5,046			4,878
Inventories, net		3,643			3,222
Deferred income taxes		251			251
Other current assets		451			396
Total current assets		10,171			9,797
Property, plant and equipment - less accumulated depreciation (2012 - $5,531; 2011 - $5,251)		7,746			7,415
Goodwill		5,958			5,956
Intangible assets, net		1,110			1,143
Other assets		573			536
Total assets	$	25,558		$	24,847
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable	$	1,932		$	1,810
Short-term debt and current portion of long-term debt		675			224
Accrued employee compensation		622			704
Income taxes payable		197			289
Other accrued liabilities		435			475
Total current liabilities		3,861			3,502
Long-term debt		3,843			3,845
Deferred income taxes and other tax liabilities		796			810
Liabilities for pensions and other postretirement benefits		538			578
Other liabilities		138			148
Commitments and contingencies
Equity:
Common stock		438			437
Capital in excess of par value		7,361			7,303
Retained earnings		8,875			8,561
Accumulated other comprehensive loss		(487	)		(555)
Baker Hughes stockholders’ equity		16,187			15,746
Noncontrolling interests		195			218
Total equity		16,382			15,964
Total liabilities and equity	$	25,558		$	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 Interest			Total
Balance at December 31, 2010	$	432	$	7,005		$	7,083		$	(420	)	$	186		$	14,286
Comprehensive income:
Net income							381						3			384
Other comprehensive income										65						65
Activity related to stock plans		2		57												59
Stock-based compensation cost				29												29
Cash dividends ($0.15 per share)							(65	)								(65)
Net activity related to noncontrolling interests				(1	)								66			65
Balance at March 31, 2011	$	434	$	7,090		$	7,399		$	(355	)	$	255		$	14,823
	Common Stock		Capital in Excess of Par Value			Retained Earnings			Accumulated Other Comprehensive Loss			Noncontrolling Interest			Total
Balance at December 31, 2011	$	437	$	7,303		$	8,561		$	(555	)	$	218		$	15,964
Comprehensive income:
Net income							379						1			380
Other comprehensive income										68						68
Activity related to stock plans		1		(2	)											(1)
Stock-based compensation cost				38												38
Cash dividends ($0.15 per share)							(65	)								(65)
Net activity related to noncontrolling interests				22									(24	)		(2)
Balance at March 31, 2012	$	438	$	7,361		$	8,875		$	(487	)	$	195		$	16,382

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

5

Baker Hughes Incorporated

Consolidated Condensed Statements of Cash Flows

(In millions)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Cash flows from operating activities:
Net income	$	380		$	384
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		363			315
Provision (benefit) for deferred income taxes		(23	)		1
Gain on disposal of assets		(58	)		(47)
Stock-based compensation cost		38			29
Provision for doubtful accounts		3			15
Changes in operating assets and liabilities:
Accounts receivable		(131	)		(398)
Inventories		(401	)		(186)
Accounts payable		109			34
Accrued employee compensation and other accrued liabilities		(117	)		(32)
Income taxes payable		(85	)		(10)
Other operating items, net		(154	)		(29)
Net cash flows from operating activities		(76	)		76
Cash flows from investing activities:
Expenditures for capital assets		(671	)		(429)
Proceeds from disposal of assets		103			75
Other investing items, net		—			(2)
Net cash flows from investing activities		(568	)		(356)
Cash flows from financing activities:
Net proceeds (payments) of commercial paper and other short-term debt		449			(36)
Proceeds from issuance of common stock		3			57
Dividends paid		(65	)		(65)
Other financing items, net		(16	)		4
Net cash flows from financing activities		371			(40)
Effect of foreign exchange rate changes on cash		3			8
Decrease in cash and cash equivalents		(270	)		(312)
Cash and cash equivalents, beginning of period		1,050			1,456
Cash and cash equivalents, end of period	$	780		$	1,144
Supplemental cash flows disclosures:
Income taxes paid, net of refunds	$	299		$	236
Interest paid	$	70		$	64
Supplemental disclosure of noncash investing activities:
Capital expenditures included in accounts payable	$	108		$	67

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 will adopt this ASU for our 2012 goodwill impairment testing and are evaluating the options provided in the ASU.

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 March 31,
	2012		2011
Weighted average common shares outstanding for basic EPS		439		435
Effect of dilutive securities - stock plans		1		2
Adjusted weighted average common shares outstanding for diluted EPS		440		437
Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than the average market price for the period		6		3

7

Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 3. INVENTORIES

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

	March 31, 2012		December 31, 2011
Finished goods	$	3,209	$	2,830
Work in process		249		231
Raw materials		185		161
Total	$	3,643	$	3,222

NOTE 4. INTANGIBLE ASSETS

Intangible assets are comprised of the following:

	March 31, 2012						December 31, 2011
	Gross Carrying Amount		Less: Accumulated Amortization		Net		Gross Carrying Amount		Less: Accumulated Amortization		Net
Definite lived intangibles:
Technology	$	758	$	241	$	517	$	755	$	231	$	524
Contract-based		16		9		7		17		9		8
Trade names		121		27		94		121		16		105
Customer relationships		500		87		413		497		77		420
Subtotal		1,395		364		1,031		1,390		333		1,057
Indefinite lived intangibles:
In-process research and development		79		—		79		86		—		86
Total	$	1,474	$	364	$	1,110	$	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 ended March 31, 2012 was $34 million, and is estimated to be $101 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 - $113 million; 2014 - $97 million; 2015 - $91 million; 2016 - $89 million; and 2017 - $88 million.

NOTE 5. FINANCIAL INSTRUMENTS

Fair Value of 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 March 31, 2012 and December 31, 2011 approximates their carrying value as reflected in our unaudited consolidated condensed balance sheet.

Debt

The estimated fair value of total debt at March 31, 2012 and December 31, 2011 was $5,264 million and $4,910 million, respectively, which differs from the carrying amounts of $4,518 million and $4,069 million, respectively, included in our unaudited consolidated condensed balance sheet. 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.

8

Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

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 and increase profit before tax of $23 million and $9 million, respectively, for the three months ended March 31, 2011. There were no material changes in segment assets as a result of this change.

Summarized financial information is shown in the following table.

	Three Months Ended March 31, 2012					Three Months Ended March 31, 2011
Segments	Revenue		Profit (Loss)			Revenue			Profit (Loss)
North America	$	2,863	$	401		$	2,358		$	455
Latin America		573		67			474			62
Europe/Africa/Russia Caspian		893		153			782			88
Middle East/Asia Pacific		745		75			664			79
Industrial Services		281		22			247			23
Total Operations		5,355		718			4,525			707
Corporate and Other		—		(91	)		—			(67)
Interest Expense, net		—		(54	)		—			(52)
Total	$	5,355	$	573		$	4,525	��	$	588

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 March 31:

	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 cost (benefit)		—			—			—			—			(1	)		(1)
Amortization of net loss		4			2			1			1			1			—
Benefit settlement		—			—			6			—			—			—
Net periodic cost	$	16		$	8		$	8		$	3		$	5		$	3

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 ended March 31, 2012 were as follows:

	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		—		3		—		—		3
Purchases		—		52		—		—		52
Ending balance at March 31, 2012	$	5	$	165	$	19	$	15	$	204

9

Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 8. 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 $1.2 billion at March 31, 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 9. ACCUMULATED OTHER COMPREHENSIVE LOSS

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

	March 31, 2012			December 31, 2011
Foreign currency translation adjustments	$	(249	)	$	(304)
Pension and other postretirement benefits		(238	)		(251)
Total accumulated other comprehensive loss	$	(487	)	$	(555)

10

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 first quarter of 2012, we generated revenue of $5.36 billion, an increase of $830 million or 18% compared to the same quarter a year ago. North America oilfield revenue for the first quarter of 2012 was $2.86 billion, an increase of 21% compared to the same quarter a year ago. Oilfield revenue outside of North America for the first quarter of 2012 was $2.21 billion, an increase of 15% compared to the same quarter a year ago. These increases are primarily due to the increase in activity and service intensity primarily in North America, driven by oil-directed drilling mainly in unconventional reservoirs. Industrial Services revenue for the first quarter of 2012 was $281 million, an increase of 14% compared to the same quarter a year ago.

Net income attributable to Baker Hughes was $379 million for the first quarter of 2012 compared to $381 million for the same quarter a year ago. Profitability in North America was adversely impacted by several issues primarily related to our pressure pumping product line including the market shift from natural gas to oil-directed drilling, the increasing supply of pressure pumping capacity in the market, increased personnel costs and other supply chain challenges. Our other product lines in North America, particularly drilling services, upstream chemicals, artificial lift and completions, experienced increased demand in the first quarter of 2012 compared to the same quarter a year ago, as well as sequentially. International profitability increased in the first quarter of 2012 compared to the same quarter a year ago driven by activity increases in the Europe/Africa/Russia Caspian region.

As of March 31, 2012, we had approximately 58,800 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 12% increase in the North America rig count in the first quarter of 2012 compared to the same period a year ago. Oil-directed drilling increased 39% in the first 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 18% in the first 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, which increased 13% in the first quarter of 2012 compared to the same period a year ago as the economic recovery continued. Compared to the first quarter of 2011, our customers’ activity and spending levels have increased as a result of the increase in Brent oil prices. However, due to geopolitical

11

instability in certain regions combined with the long planning cycles associated with many international projects, the rate of growth has lagged behind the increase 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 March 31,
	2012		2011
Brent oil prices ($/Bbl)(1)	$	118.52	$	105.21
WTI oil prices ($/Bbl)(2)		102.87		94.60
Natural gas prices ($/mmBtu)(3)		2.45		4.20

⁽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 $118.52/Bbl in the first quarter of 2012. Oil prices increased throughout the first quarter of 2012 due to geopolitical disputes in Africa and the Middle East, which reduced output and threatened future supplies, as well as unplanned production outages in the North Sea and Canada. Prices ranged from a low of $107.58/Bbl in January 2012 to a high of $126.65/Bbl in February 2012. The International Energy Agency (“IEA”) estimated in its April 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 $102.87/Bbl in the first quarter of 2012. Similar to the Brent oil prices, WTI oil prices climbed through the first quarter of 2012, but to a lesser extent due to increasing storage in the U.S. resulting from increased oil-directed drilling in North America. Prices ranged from a low of $96.36/Bbl to a high of $109.49/Bbl, both in February 2012.

Natural gas prices averaged $2.45/mmBtu in the first quarter of 2012. Natural gas prices have continued the decline noted in 2011 primarily due to a mild winter across much of the U.S. and Canada, as well as strong production levels, particularly in the unconventional natural gas shale plays in North America. During the quarter, prices ranged from a high of $2.98/mmBtu in January 2012 to a low of $1.98/mmBtu in March 2012. According to the U.S. Department of Energy (“DOE”), working natural gas in storage at the end of the first quarter of 2012 was 2,479/Bcf, which was 53% or 855/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. Rig counts are compiled weekly for the U.S. and Canada and monthly for all international and U.S. workover rigs. Published international rig counts do not include rigs drilling in certain locations, such as Russia, the Caspian, Iraq and onshore China, because this information is not readily available.

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.

12

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

	Three Months Ended March 31,
	2012		2011		% Change
U.S. - land and inland waters		1,947		1,691		15%
U.S. - offshore		43		26		65%
Canada		584		587		(1)%
North America		2,574		2,304		12%
Latin America		432		410		5%
North Sea		36		44		(18)%
Continental Europe		76		74		3%
Africa		83		82		1%
Middle East		311		283		10%
Asia Pacific		250		273		(8)%
Outside North America		1,188		1,166		2%
Worldwide		3,762		3,470		8%

First Quarter of 2012 Compared to the First Quarter of 2011

The rig count in North America increased 12% reflecting a 56% increase in the U.S. oil-directed rig count partially offset by a 20% decrease in the U.S. natural gas-directed rig count, and a 4% increase in the Canadian oil-directed rig count partially offset by a 10% decrease in the Canadian natural gas-directed rig count. The growth in oil-directed drilling was primarily a result of increasing 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 2%. 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, Colombia and Brazil, partially offset by decreased rig activity in Venezuela and Argentina. The rig count in the North Sea decreased primarily due to lower rig activity in Norway and the United Kingdom as inclement weather delayed activity. The rig count in Continental Europe and Africa was relatively flat. The rig count increased in the Middle East primarily due to higher activity in Saudi Arabia, Oman and Egypt, partially offset by a decline in activity in Yemen. In Asia Pacific, activity decreased primarily in Vietnam, offshore China and Indonesia while activity increased in Malaysia.

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. 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 and increase profit before tax (as defined below) of $23 million and $9 million, respectively, for the three months ended March 31, 2011.

13

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 March 31,						Favorable (Unfavorable)			% Change
	2012			2011
Revenue:
North America	$	2,863		$	2,358		$	505			21%
Latin America		573			474			99			21%
Europe/Africa/Russia Caspian		893			782			111			14%
Middle East/Asia Pacific		745			664			81			12%
Industrial Services		281			247			34			14%
Total	$	5,355		$	4,525		$	830			18%
	Three Months Ended March 31,						Favorable (Unfavorable)			% Change
	2012			2011
Profit Before Tax:
North America	$	401		$	455		$	(54	)		(12)%
Latin America		67			62			5			8%
Europe/Africa/Russia Caspian		153			88			65			74%
Middle East/Asia Pacific		75			79			(4	)		(5)%
Industrial Services		22			23			(1	)		(4)%
Total Operations		718			707			11			2%
Corporate and Other		(91	)		(67	)		(24	)		(36)%
Interest Expense, net		(54	)		(52	)		(2	)		(4)%
Total	$	573		$	588		$	(15	)		(3)%

Revenue for the first quarter of 2012 increased $830 million or 18% compared to the first quarter of 2011, driven by increased activity across all segments, particularly in the North America and Europe/Africa/Russia Caspian (“EARC”) segments.

Profit before tax for the first quarter of 2012 decreased $15 million or 3% compared to the first quarter of 2011. Despite the increase in revenue, our profit before tax was significantly impacted by increased personnel costs and other supply chain challenges in our pressure pumping business in North America as well as higher corporate expenses related to integration efforts and increased amortization, partially offset by the improving market conditions internationally, particularly in the EARC segment.

North America

North America revenue increased 21% in the first quarter of 2012 compared to the first quarter of 2011. Revenue increases were supported by a 15% increase in the U.S. land and inland waters rig count and a relatively flat Canada rig count. Increasing oil prices during the first quarter of 2012 led to increased oil-directed drilling in unconventional reservoirs, which continues to be the primary catalyst for the growth seen in North America. The unconventional reservoirs require a substantially higher proportion of services from Baker Hughes across all product lines. In the first quarter of 2012, there were significant increases in completions systems, drilling services, artificial lift, upstream chemicals and drilling fluids activities. In Canada, the lower natural gas-directed pressure pumping activity and early spring break-up negatively impacted revenue. Revenue in the Gulf of Mexico increased 45% in the first quarter of 2012 compared to the first quarter of 2011 as rig counts increased dramatically, particularly in deepwater as permitting continued to increase.

North America profit before tax was $401 million in the first quarter of 2012, a decrease of $54 million compared to the first quarter of 2011. Despite higher revenue, profits in U.S. Land and Canada declined due to decreased fleet utilization and lower pricing as well as higher personnel and logistics costs, shortages of and higher costs for critical raw materials, and higher repair and maintenance costs primarily in our pressure pumping business. Although there is positive progress in the Gulf of Mexico, profits have not improved at the same rate as revenue due to the current predominant focus of rigs on exploration rather than completions, higher

14

internal costs to meet regulatory requirements and increased downtime on many deepwater rigs to comply with new regulatory requirements.

Latin America

Latin America revenue increased 21% in the first quarter of 2012 compared to the first quarter of 2011. The primary drivers of the increase were the acceleration of activity benefitting nearly all of our product lines in the Andean area as well as robust deepwater growth through the use of our drilling services, artificial lift and pressure pumping product lines in Brazil.

Latin America profit before tax increased 8% in the first quarter of 2012 compared to the first quarter of 2011. While increased revenue was the primary contributor to the increased profitability, profits were negatively impacted by an unfavorable change in the sales mix towards lower margin products and services, higher employee costs, and project delays.

Europe/Africa/Russia Caspian

EARC revenue increased 14% in the first quarter of 2012 compared to the first quarter of 2011. The primary drivers of the increase were increased activity for completion tools, drilling fluids, and wireline services in Norway; increased drilling services activity in Nigeria and Mozambique; and modestly improving market conditions for wireline services and artificial lift in Russia.

EARC profit before tax increased 74% in the first quarter of 2012 compared to the first quarter of 2011 primarily as a result of improved margins as well as an increase in overall revenue within the segment due to increased activity in Norway, Nigeria and Sub Sahara Africa.

Middle East/Asia Pacific

Middle East/Asia Pacific (“MEAP”) revenue increased 12% in the first quarter of 2012 compared to the first quarter of 2011. The increase in this segment was attributable to new integrated operations contracts in Iraq and higher demand for completions systems in Saudi Arabia, Australia and Southeast Asia. Increased pressure pumping, wireline and drilling services activity in Southeast Asia also contributed.

MEAP profit before tax decreased 5% in the first quarter of 2012 compared to the first quarter of 2011 primarily as a result of unfavorable sales mix toward products and services with lower margins, start-up costs associated with the new integrated operations activities in Iraq, and higher operating expenses in certain areas within the region.

Industrial Services

Industrial Services revenue increased 14% and profit before tax decreased 4% in the first quarter of 2012 compared to the first quarter of 2011. Profit before tax was impacted by an overall increase in cost of goods and services sold.

Costs and Expenses

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

	Three Months Ended March 31,
	2012					2011
	$		%			$		%
Revenue	$	5,355		100	%	$	4,525		100%
Cost of revenue		4,265		80	%		3,497		77%
Research and engineering		124		2	%		106		2%
Marketing, general and administrative		339		6	%		282		6%

15

Cost of Revenue

Cost of revenue as a percentage of revenue was 80% and 77% for the first quarter of 2012 and 2011, respectively. The increase 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, as well as a general shift to a less favorable mix of products and services internationally.

Research and Engineering

Research and engineering expenses increased 17% for the first quarter of 2012 compared to the first quarter of 2011, but were flat as a percentage of revenue. The increase in research and engineering expenses was primarily driven by an increase in technology research projects in the first quarter of 2012. Additionally, personnel costs increased as a result of the opening and staffing of technology centers in Brazil and Saudi Arabia in the fourth quarter of 2011 and the first quarter of 2012, respectively.

Marketing, General and Administrative

Marketing, general and administrative (“MG&A”) expenses increased 20% for the first quarter of 2012 compared to the first quarter of 2011, but were flat as a percentage of revenue. The increase in expenses resulted from ongoing activities to further coordinate and integrate our worldwide operations, including software implementation.

Interest Expense, net

Interest expense, net of interest income, increased $2 million in the first quarter of 2012 compared to the first quarter of 2011. The increase was primarily due to the issuance of $750 million of debt in August 2011 as well as capital leases entered into in the second and third quarters of 2011. The increase in interest expense was partially offset by the repayment of $250 million of debt and the early extinguishment of $500 million debt in the second and third quarters of 2011, respectively.

Income Taxes

Total income tax expense for the first quarter of 2012 was $193 million. Our effective tax rate on operating profits for the three months ended March 31, 2012 was 33.7%, which is lower than the U.S. statutory income tax rate of 35% due to lower tax rates on certain of our international operations 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 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, 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.

16

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 substantially 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. In 2011 substantial concern grew over a double dip recession, more recently these fears have waned, 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 April 2012 Oil Market Report, the IEA said that it expects global demand for oil to increase 0.8 million barrels per day in 2012 relative to 2011. While forecasts by IEA, EIA and OPEC have been revised modestly lower during the quarter, primarily as a reaction to higher oil prices and uncertainty regarding the strength of the economic recovery, 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 is at an all-time high 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.

• 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 meet the expected increase in global demand. Sustained higher oil prices have led 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., and it is anticipated that this will begin to impact natural gas production. 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 $96/Bbl and $110/Bbl 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 commodity prices to remain relatively strong throughout 2012 barring a major macro-economic event. Currently oil prices are somewhat elevated due to concern over geopolitical uncertainty in Iran. The resolution of this uncertainty could drive substantial volatility of global oil prices throughout 2012. 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 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. Unconventional plays with crude oil and natural gas liquids content are attracting incremental investment while investment in dry gas plays are expected to continue to decline due to historically low natural gas pricing levels. Service

17

intensity has increased in North America 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, activity on the continental shelf has improved and we have seen a steady increase in deepwater permits and subsequently deepwater drilling. The level of activity in the deepwater Gulf of Mexico remains below pre-moratorium levels; however, we believe that deepwater activity could ultimately return to pre-moratorium levels. We are investing in our people and processes to ensure that we will be fully compliant with the new and more stringent regulatory requirements in the Gulf of Mexico.

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; Brazil with the investment in the pre-salt resources; and Colombia which has seen a rapid expansion associated with improved fiscal terms for our customers.

Capital Expenditures - Our capital expenditures, excluding acquisitions, are expected to be between $2.7 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.

LIQUIDITY AND CAPITAL RESOURCES

Our objective in financing our business is to maintain adequate financial resources and access to sufficient liquidity. At March 31, 2012, we had cash and cash equivalents of $780 million, of which substantially all was held by foreign subsidiaries. A substantial portion of the cash held by foreign subsidiaries at March 31, 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 $555 million of outstanding commercial paper at March 31, 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 three months ended March 31, 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 three months ended March 31:

(In millions)	2012			2011
Operating activities	$	(76	)	$	76
Investing activities		(568	)		(356)
Financing activities		371			(40)

Operating Activities

Cash flows from operating activities used $76 million and provided $76 million in the three months ended March 31, 2012 and 2011, respectively. This decrease in cash flows of $152 million is primarily due to the change in net operating assets and liabilities, which used more cash in the three months ended March 31, 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 $131 million and $398 million in the three months ended March 31, 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 3 days and 6 days for the three months ended March 31, 2012 and 2011, respectively.

18

• An increase in inventory used cash of $401 million and $186 million in the three months ended March 31, 2012 and 2011, respectively, driven by an increase in production of finished goods due to continued high activity levels, and increased costs of certain raw materials.

• An increase in accounts payable provided cash of $109 million and $34 million in the three months ended March 31, 2012 and 2011, respectively, resulting from an increase in operating assets to support increased activity.

• Accrued employee compensation and other accrued liabilities used $117 million and $32 million in cash in the three months ended March 31, 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 $154 million and $29 million in the three months ended March 31, 2012 and 2011, respectively. The increase in cash used was primarily due to an increase in payments for pensions and other postretirement benefits and liabilities 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 $671 million and $429 million in the three months ended March 31, 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 $103 million and $75 million in the three months ended March 31, 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.

Financing Activities

We had net proceeds from borrowings of $449 million and net repayments of $36 million related to commercial paper and other short-term debt in the three months ended March 31, 2012 and 2011, respectively. Total debt outstanding at March 31, 2012 was $4.52 billion, an increase of $449 million compared to December 31, 2011. The total debt to total capitalization (defined as total debt plus equity) ratio was 0.22 at March 31, 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 provides 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 is expected to remain open until May 3, 2012. This exchange had no impact to our financial statements or cash flows.

We received proceeds of $3 million and $57 million in the three months ended March 31, 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 three months ended March 31, 2012 and 2011, we did not repurchase any shares of common stock. At March 31, 2012, we had authorization remaining to repurchase approximately $1.2 billion in common stock.

We paid dividends of $65 million in the three months ended March 31, 2012 and 2011.

Available Credit Facility

We have a $2.5 billion committed revolving credit facility with commercial banks that matures in September 2016, and at March 31, 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 March 31, 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 March 31, 2012, we had $555 million 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

19

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 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 March 31, 2012. We anticipate making income tax payments of between $1.3 billion and $1.4 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 $80 million and $95 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 $263 million and $286 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 will adopt this ASU for our 2012 goodwill impairment testing and are evaluating the options provided in the ASU.

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

20

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”) athttp://www.sec.gov.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the three months ended March 31, 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 March 31, 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 March 31, 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.

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 8 of Notes to Unaudited Consolidated Condensed Financial Statements.

In February 2012, a subsidiary of the Company entered into a Compromise Agreement with the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) within the United States Department of Transportation. In August 2009, the PHMSA alleged nine violations, one of which was subsequently dismissed, of the Hazardous Material Regulations at a facility operated by the subsidiary. In the Compromise Agreement, the PHMSA found that corrective actions taken by the subsidiary have corrected the alleged violations and no further corrective actions are required. The Compromise Agreement provides for civil penalty of $100,000, which the subsidiary agreed to pay within 30 days of the date of the Compromise Agreement.

For additional discussion of legal proceedings see also, Item 3 of Part I of our 2011 Annual Report and Note 13 of the Notes to Consolidated Financial Statements included in Item  8 of our 2011 Annual Report.

ITEM 1A. RISK FACTORS

As of the date of this filing, the Company and its operations continue to be subject to the risk factors previously disclosed in our “Risk Factors” in the 2011 Annual Report.

21

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table contains information about our purchases of equity securities during the three months ended March 31, 2012.

Issuer Purchases of Equity Securities

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)
January 1-31, 2012		247,459	$	48.63		—	$	—		247,459	$	—
February 1-29, 2012		3,999		50.00		—		—		3,999		—
March 1-31, 2012		199		50.02		—		—		199		—
Total		251,657	$	48.65		—	$	—		251,657	$	1,197,127,803

(1) Represents shares purchased from employees to pay the option exercise price related to stock-for-stock exchanges in option exercises or to satisfy the tax withholding obligations in connection with the vesting of restricted stock awards and restricted stock units.

(2) There were no share repurchases during the three months ended March 31, 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 March 31, 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 the recently proposed Item 104 of Regulation S-K is included in Exhibit 95 to this quarterly report.

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.

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 Disclosures.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document

22

101.CAL*	XBRL Calculation Linkbase Document
101.LAB*	XBRL Label Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document

23

SIGNATURES

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

	BAKER HUGHES INCORPORATED
	(Registrant)
Date: May 1, 2012	By: /s/ PETER A. RAGAUSS
	Peter A. Ragauss
	Senior Vice President and Chief Financial Officer
Date: May 1, 2012	By: /s/ ALAN J. KEIFER
	Alan J. Keifer
	Vice President and Controller

24