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 March 31, 2014

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 April 17, 2014, the registrant has outstanding 435,977,068 shares of Common Stock, $1 par value per share.

Baker Hughes Incorporated

INDEX

		Page No.
PART I -	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Condensed Statements of Income (Unaudited) Three months ended March 31, 2014 and 2013	2
	Consolidated Condensed Statements of Comprehensive Income (Loss) (Unaudited) Three months ended March 31, 2014 and 2013	3
	Consolidated Condensed Balance Sheets (Unaudited) March 31, 2014 and December 31, 2013	4
	Consolidated Condensed Statements of Changes in Equity (Unaudited) Three months ended March 31, 2014 and 2013	5
	Consolidated Condensed Statements of Cash Flows (Unaudited) Three months ended March 31, 2014 and 2013	6
	Notes to Unaudited Consolidated Condensed Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	12
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	23
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 (UNAUDITED)

Baker Hughes Incorporated

Consolidated Condensed Statements of Income

(Unaudited)

	Three Months Ended March 31,
(In millions, except per share amounts)	2014			2013
Revenue:
Sales	$	1,857		$	1,749
Services	3,874			3,481
Total revenue	5,731			5,230
Costs and expenses:
Cost of sales	1,501			1,384
Cost of services	3,219			2,942
Research and engineering	143			127
Marketing, general and administrative	316			322
Total costs and expenses	5,179			4,775
Operating income	552			455
Interest expense, net	(57		)	(55		)
Income before income taxes	495			400
Income taxes	(159		)	(132		)
Net income	336			268
Net income attributable to noncontrolling interests	(8		)	(1		)
Net income attributable to Baker Hughes	$	328		$	267
Basic earnings per share attributable to Baker Hughes	$	0.75		$	0.60
Diluted earnings per share attributable to Baker Hughes	$	0.74		$	0.60
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 (Loss)

(Unaudited)

	Three Months Ended March 31,
(In millions)	2014			2013
Net income	$	336		$	268
Other comprehensive income (loss):
Foreign currency translation adjustments during the period	(26		)	(80		)
Pension and other postretirement benefits, net of tax	(4		)	10
Other comprehensive loss	(30		)	(70		)
Comprehensive income	306			198
Comprehensive income attributable to noncontrolling interests	(8		)	(1		)
Comprehensive income attributable to Baker Hughes	$	298		$	197

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

3

Baker Hughes Incorporated

Consolidated Condensed Balance Sheets

(Unaudited)

(In millions)	March 31, 2014			December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	1,200		$	1,399
Accounts receivable - less allowance for doubtful accounts (2014 - $244; 2013 - $238)	5,267			5,138
Inventories, net	3,995			3,884
Deferred income taxes	364			380
Other current assets	440			494
Total current assets	11,266			11,295
Property, plant and equipment - less accumulated depreciation (2014 - $7,503; 2013 - $7,219)	9,055			9,076
Goodwill	5,997			5,966
Intangible assets, net	862			883
Other assets	716			714
Total assets	$	27,896		$	27,934
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	2,486		$	2,574
Short-term debt and current portion of long-term debt	625			499
Accrued employee compensation	662			778
Income taxes payable	300			213
Other accrued liabilities	453			514
Total current liabilities	4,526			4,578
Long-term debt	3,878			3,882
Deferred income taxes and other tax liabilities	728			821
Liabilities for pensions and other postretirement benefits	582			583
Other liabilities	181			158
Commitments and contingencies
Equity:
Common stock	436			438
Capital in excess of par value	7,195			7,341
Retained earnings	10,700			10,438
Accumulated other comprehensive loss	(534		)	(504		)
Baker Hughes stockholders’ equity	17,797			17,713
Noncontrolling interests	204			199
Total equity	18,001			17,912
Total liabilities and equity	$	27,896		$	27,934

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

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Baker Hughes Incorporated

Consolidated Condensed Statements of Changes in Equity

(Unaudited)

(In millions, except per share amounts)	Common Stock			Capital in Excess of Par Value			Retained Earnings			Accumulated Other Comprehensive Loss			Non-controlling Interests			Total
Balance at December 31, 2013	$	438		$	7,341		$	10,438		$	(504	)	$	199		$	17,912
Comprehensive income:
Net income							328						8			336
Other comprehensive loss										(30		)				(30		)
Activity related to stock plans	1			19												20
Repurchase and retirement of common stock	(3		)	(197		)										(200		)
Stock-based compensation				32												32
Cash dividends ($0.15 per share)							(66		)							(66		)
Net activity related to noncontrolling interests													(3		)	(3		)
Balance at March 31, 2014	$	436		$	7,195		$	10,700		$	(534	)	$	204		$	18,001

	Common Stock		Capital in Excess of Par Value			Retained Earnings			Accumulated Other Comprehensive Loss			Non-controlling Interests			Total
Balance at December 31, 2012	$	441	$	7,495		$	9,609		$	(476	)	$	199		$	17,268
Comprehensive income:
Net income						267						1			268
Other comprehensive loss									(70		)				(70		)
Activity related to stock plans	1		(13		)										(12		)
Stock-based compensation			36												36
Cash dividends ($0.15 per share)						(66		)							(66		)
Net activity related to noncontrolling interests												(6		)	(6		)
Balance at March 31, 2013	$	442	$	7,518		$	9,810		$	(546	)	$	194		$	17,418

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

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Baker Hughes Incorporated

Consolidated Condensed Statements of Cash Flows

(Unaudited)

	Three Months Ended March 31,
(In millions)	2014			2013
Cash flows from operating activities:
Net income	$	336		$	268
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	437			415
Other noncash items	(33		)	(3		)
Changes in operating assets and liabilities:
Accounts receivable	(161		)	(378		)
Inventories	(116		)	(124		)
Accounts payable	(85		)	312
Other operating items, net	(75		)	(104		)
Net cash flows provided by operating activities	303			386
Cash flows from investing activities:
Expenditures for capital assets	(439		)	(490		)
Proceeds from disposal of assets	100			94
Other investing items, net	(25		)	—
Net cash flows used in investing activities	(364		)	(396		)
Cash flows from financing activities:
Net proceeds of commercial paper borrowings and other debt with three months or less original maturity	125			200
Net repayments of short-term debt with greater than three months original maturity	(11		)	(24		)
Repurchase of common stock	(200		)	—
Dividends paid	(66		)	(66		)
Other financing items, net	14			(10		)
Net cash flows (used in) provided by financing activities	(138		)	100
Effect of foreign exchange rate changes on cash and cash equivalents	—			(4		)
(Decrease) increase in cash and cash equivalents	(199		)	86
Cash and cash equivalents, beginning of period	1,399			1,015
Cash and cash equivalents, end of period	$	1,200		$	1,101
Supplemental cash flows disclosures:
Income taxes paid, net of refunds	$	57		$	133
Interest paid	$	73		$	71
Supplemental disclosure of noncash investing activities:
Capital expenditures included in accounts payable	$	93		$	80

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

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

Basis of Presentation

Our unaudited consolidated condensed financial statements included herein have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S.”) 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, 2013 (“2013 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 Unaudited Consolidated Condensed Financial Statements, all dollar and share amounts in tabulations are in millions of dollars and shares, respectively, unless otherwise indicated.

NOTE 2. VENEZUELAN CURRENCY DEVALUATION

In January 2014, the Venezuelan government modified the currency exchange system whereby the official exchange rate of 6.3 Bolivares Fuertes (“BsF”) to the U.S. Dollar applies to certain economic sectors related to purchases of “essential goods and services” while other sectors of the economy apply an exchange rate determined by an auction process conducted by Venezuela's Complimentary System of Foreign Currency Administration (“SICAD 1”). Participation in the SICAD 1 mechanism is controlled by the Venezuelan government and is limited to certain companies that operate in designated industry sectors. In late March 2014, a third currency exchange mechanism was established (“SICAD 2”), which is expected to allow other economic sectors and companies to participate in the auction process.

While the functional currency of our operations in Venezuela is the U.S. Dollar, a portion of the transactions and balances are denominated in BsF. For financial reporting purposes, we remeasure the local currency balances into U.S. Dollars at the official exchange rate of 6.3 BsF to the U.S. Dollar. We are assessing the applicability and impact, if any, on our business of the change in the currency exchange mechanisms and exchange rates. We do not believe the changes will have a material impact on our financial position, results of operations or cash flows. If we applied a higher exchange rate, we would incur a loss in 2014. For example, if we were to apply an exchange rate of 10.7 BsF per U.S. Dollar, the closing rate of the last SICAD 1 auction in March 2014, to our local currency denominated balances at March 31, 2014, it would result in a loss of approximately $7 million.

In February 2013, Venezuela's currency was devalued from the prior exchange rate of 4.3 BsF per U.S. Dollar to 6.3 BsF per U.S. Dollar, which applies to our local currency denominated balances. The impact of this devaluation was a loss of $23 million that was recorded in marketing, general and administrative expense in the first quarter of 2013.

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 3. EARNINGS PER SHARE

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

	Three Months Ended March 31,
	2014	2013
Weighted average common shares outstanding for basic EPS	439	443
Effect of dilutive securities - stock plans	2	1
Adjusted weighted average common shares outstanding for diluted EPS	441	444
Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than the average market price for the period	3	8

NOTE 4. INVENTORIES

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

	March 31, 2014		December 31, 2013
Finished goods	$	3,541	$	3,438
Work in process	234		215
Raw materials	220		231
Total inventories	$	3,995	$	3,884

NOTE 5. INTANGIBLE ASSETS

Intangible assets are comprised of the following:

	March 31, 2014						December 31, 2013
	Gross Carrying Amount		Less: Accumulated Amortization		Net		Gross Carrying Amount		Less: Accumulated Amortization		Net
Technology	$	817	$	350	$	467	$	814	$	337	$	477
Customer relationships	496		167		329		494		157		337
Trade names	120		85		35		120		82		38
Other (1)	43		12		31		43		12		31
Total intangible assets	$	1,476	$	614	$	862	$	1,471	$	588	$	883

⁽¹⁾  Includes indefinite-lived intangibles of $27 million at March 31, 2014 and December 31, 2013 related to in-process research and development projects.

Intangible assets are generally amortized on a straight-line basis with estimated useful lives ranging from 3 to 30 years. Amortization expense included in net income for the three months ended March 31, 2014 was $26 million, as compared to $30 million reported in 2013 for the same period.

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

Amortization expense of these intangibles over the remainder of 2014 and for each of the subsequent five fiscal years is expected to be as follows:

Year	Estimated Amortization Expense
Remainder of 2014	$	78
2015	97
2016	95
2017	91
2018	86
2019	83

NOTE 6. FINANCIAL INSTRUMENTS

Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable, debt and foreign currency forward contracts. Except as described below, the estimated fair value of such financial instruments at March 31, 2014 and December 31, 2013 approximates their carrying value as reflected in our unaudited consolidated condensed balance sheets.

The estimated fair value of total debt at March 31, 2014 and December 31, 2013 was $5,097 million and $4,857 million, respectively, which differs from the carrying amounts of $4,503 million and $4,381 million, respectively, included in our unaudited consolidated condensed balance sheets. The fair value was determined using quoted period-end market prices.

NOTE 7. SEGMENT INFORMATION

We are a supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas business, referred to as oilfield operations, which are managed through operating segments that are aligned with our geographic regions. We also provide services and products to the downstream chemicals, and process and pipeline industries, referred to as Industrial Services.

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 operating segments.

Summarized financial information is shown in the following table:

	Three Months Ended					Three Months Ended
	March 31, 2014					March 31, 2013
Segments	Revenue		Profit (Loss) Before Taxes			Revenue		Profit (Loss) Before Taxes
North America	$	2,776	$	258		$	2,603	$	235
Latin America	530		55			590		49
Europe/Africa/Russia Caspian	996		142			854		93
Middle East/Asia Pacific	1,108		135			894		116
Industrial Services	321		27			289		24
Total Operations	5,731		617			5,230		517
Corporate and other	—		(65		)	—		(62		)
Interest expense, net	—		(57		)	—		(55		)
Total	$	5,731	$	495		$	5,230	$	400

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 8. EMPLOYEE BENEFIT PLANS

We have both funded and unfunded noncontributory defined benefit pension plans ("Pension Benefits") covering certain employees primarily in the U.S., the United Kingdom, Germany and Canada. We also provide certain postretirement health care benefits (“Other Postretirement Benefits”), through an unfunded plan, to a closed group of 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 Benefits						Non-U.S. Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013			2014			2013
Service cost	$	17		$	16		$	3		$	4		$	1		$	2
Interest cost	7			6			9			8			2			1
Expected return on plan assets	(11		)	(10		)	(10		)	(10		)	—			—
Amortization of prior service credit	—			—			—			—			(1		)	(2		)
Amortization of net actuarial loss	2			3			1			2			1			1
Other	—			—			—			—			(4		)	—
Net periodic cost	$	15		$	15		$	3		$	4		$	(1	)	$	2

NOTE 9. COMMITMENTS AND CONTINGENCIES

LITIGATION

We are subject to a number of lawsuits and claims arising out of the conduct of our business. The ability to predict the ultimate outcome of such matters involves judgments, estimates and inherent uncertainties. We record a liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated, including accruals for self-insured losses which are calculated based on historical claim data, specific loss development factors and other information. A range of total possible losses for all litigation matters cannot be reasonably estimated. Based on a consideration of all relevant facts and circumstances, we do not expect the ultimate outcome of any currently pending lawsuits or claims against us will have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these matters.

We insure against risks arising from our business 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 or future legal proceedings or other claims. Most of our 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.

On October 21, 2013, a collective action lawsuit alleging that we failed to pay an as-yet-undetermined class of workers overtime in compliance with the Fair Labor Standards Act was filed titled Zamora et al. v. Baker Hughes Incorporated in the U.S. District Court for the Southern District of Texas, Corpus Christi Division. On October 10, 2013, a class and collective action lawsuit alleging that we failed to pay a nationwide class of workers overtime in compliance with the Fair Labor Standards Act and certain state laws was filed titled Lea et al. v. Baker Hughes, Inc. in the U.S. District Court for the Southern District of Texas, Galveston Division. We are evaluating the background facts and at this time are not able to predict the outcome of these lawsuits or the amount of any loss that may arise from them.

On May 30, 2013, we received a Civil Investigative Demand ("CID") from the United States Department of Justice ("DOJ") pursuant to the Antitrust Civil Process Act. The CID seeks documents and information from us for the period from May 29, 2011 through the date of the CID in connection with a DOJ investigation related to pressure

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

pumping services in the United States. We are working with the DOJ to provide the requested documents and information. We are not able to predict what action, if any, might be taken in the future by the DOJ or other governmental authorities as a result of the investigation.

OTHER

In the normal course of business with customers, vendors and others, we have entered into off-balance sheet arrangements, such as surety bonds for performance, letters of credit and other bank issued guarantees, which totaled approximately $1.5 billion at March 31, 2014. 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 financial position, results of operations or cash flows.

NOTE 10. ACCUMULATED OTHER COMPREHENSIVE LOSS

The following tables present the changes in accumulated other comprehensive loss, net of tax:

	Pensions and Other Postretirement Benefits				Foreign Currency Translation Adjustments				Accumulated Other Comprehensive Loss
Balance at December 31, 2013		$	(217	)		$	(287	)		$	(504	)
Other comprehensive loss before reclassifications		(4		)		(26		)		(30		)
Amounts reclassified from accumulated other comprehensive loss		(1		)		—				(1		)
Deferred taxes		1				—				1
Balance at March 31, 2014		$	(221	)		$	(313	)		$	(534	)

	Pensions and Other Postretirement Benefits				Foreign Currency Translation Adjustments				Accumulated Other Comprehensive Loss
Balance at December 31, 2012		$	(250	)		$	(226	)		$	(476	)
Other comprehensive loss before reclassifications		—				(80		)		(80		)
Amounts reclassified from accumulated other comprehensive loss		16				—				16
Deferred taxes		(6		)		—				(6		)
Balance at March 31, 2013		$	(240	)		$	(306	)		$	(546	)

The amounts reclassified from accumulated other comprehensive loss during thethree months ended March 31, 2014 and 2013 represent the amortization of net actuarial loss, prior service credit, and other which are included in the computation of net periodic pension cost (see Note 8. Employee Benefit Plans for additional details). Net periodic pension cost is recorded in cost of sales and services, research and engineering, and marketing, general and administrative expenses.

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the unaudited consolidated condensed financial statements and the related notes included in Item 1 thereto, as well as our Annual Report on Form 10-K for the year ended December 31, 2013 (“2013 Annual Report”). As used herein, phrases such as "Baker Hughes," “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, referred to as our oilfield operations. We manage our oilfield operations through four geographic segments consisting of North America, Latin America, Europe/Africa/Russia Caspian, and Middle East/Asia Pacific. Our Industrial Services businesses are reported in a fifth segment.

The main products and services provided by oilfield operations fall into one of two categories, Drilling and Evaluation, or Completion and Production. This classification is based on the two major phases of constructing an oil and/or natural gas well, the drilling phase and the completion phase, and how our products and services are utilized in each phase. We also provide products and services to the downstream chemicals, and process and pipeline industries, referred to as Industrial Services.

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 2014, we generated revenue of $5.73 billion, an increase of $501 million, or 10%, compared to the first quarter of 2013, and a decrease of $129 million, or 2%, compared to the fourth quarter of 2013, or sequentially. Net income attributable to Baker Hughes was $328 million for the first quarter of 2014 compared to $267 million for the first quarter of 2013, and $248 million for the fourth quarter of 2013.

North America oilfield revenue for the first quarter of 2014 was $2.78 billion, an increase of $173 million, or 7%, compared to the first quarter of 2013, and an increase of $32 million, or 1%, compared to the fourth quarter of 2013. North America oilfield profit before tax for the first quarter of 2014 was $258 million compared to $235 million for the first quarter of 2013, and $227 million for the fourth quarter of 2013. Our revenue in the first quarter of 2014 compared to the same quarter a year ago increased predominantly due to continued improvement in our onshore pressure pumping business in the U.S. as well as growth in our drilling services, drill bits and artificial lift product lines. Profitability in North America increased $23 million, or 10%, year over year, despite being adversely impacted by $29 million of severance charges and $13 million of costs associated with a technology royalty agreement. Sequentially, our North America oilfield revenue and profit margins improved due to peak seasonal activity levels in Canada. The revenue impact from adverse weather conditions in parts of the U.S. were offset by increased activity and favorable mix in the Permian basin, including strong sales of drilling services and drill bits. Strong sales of newly introduced completions and artificial lift technologies across North America also contributed.

Oilfield revenue outside of North America for the first quarter of 2014 was $2.63 billion, an increase of $296 million, or 13%, compared to the first quarter of 2013, and a decrease of $136 million, or 5%, sequentially. Oilfield profitability outside North America for the first quarter of 2014 was $332 million compared to $258 million for the first quarter of 2013, and $305 million for the fourth quarter of 2013. Revenue in the first quarter of 2014 was driven by strong growth in both the Europe/Africa/Russia Caspian and Middle East/Asia Pacific segments. Sequentially, oilfield revenue outside of North America decreased primarily due to typical seasonal declines in product sales in the first quarter compared to the fourth quarter, particularly in Latin America, Russia and Asia Pacific. This was partially offset by increased revenue in Iraq, where activity resumed following a disruption to our operations in the fourth quarter of 2013. Profitability increased in all three segments relative to the first quarter of 2013 primarily due to increased revenue. Sequentially, our profitability increased due to improvement in Middle East/Asia Pacific as a result of the resumption of operations in Iraq. This improvement was offset by the impact of the seasonal reduction

12

in product sales from the fourth quarter to the first quarter. The first quarter of 2014 includes costs totaling $15 million associated with a technology royalty agreement. The first quarter of 2013 includes a foreign exchange loss of $23 million associated with the devaluation of the Venezuelan currency.

In March 2014, we announced that we have signed an agreement for the purchase of Weatherford International Ltd.'s pipeline and specialty services business for a total consideration of $250 million, comprised of $241 million in cash and $9 million in working capital, subject to adjustments. This business will be included in our Industrial Services segment. The sale is pending antitrust approval by regulatory authorities in various countries.

As of March 31, 2014, we had approximately 59,000 employees compared to approximately 59,400 employees as of December 31, 2013.

BUSINESS ENVIRONMENT

In North America, rig counts increased 1% in the first quarter of 2014 compared to the same period a year ago, comprised of a 2% increase in the oil-directed rig count and a 4% decrease in the natural gas-directed rig count. During the quarter, an extremely cold winter in many parts of the U.S. resulted in natural gas storage levels falling below the five year average and overall higher natural gas prices. Despite this, customer spending in the natural gas shale plays was limited as natural gas production in the unconventional shale plays remained high during the quarter. As a result, natural gas-directed rig activity declined 18% in the U.S. during the first quarter of 2014 compared to the same period a year ago. During March 2014, U.S. natural gas-directed rig counts reached a 21 year low at 318 rigs. In Canada, high oil price differentials primarily due to constrained refinery and pipeline capacity resulted in a 14% reduction in oil-directed customer activity. This was offset by a 37% increase in natural gas-directed rigs driven by drilling in condensate rich zones in Alberta to service activity in the oil sands. These issues ultimately resulted in a 1% reduction in Canadian rig activity in the first quarter of 2014 compared to the same quarter in 2013.

Outside of North America, customer spending is most heavily influenced by Brent oil prices. 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. On average, Brent oil prices were down slightly in the first quarter of 2014 compared to the same period a year ago. Despite flat oil prices, the international rig count grew by 5% in the first quarter of 2014 compared to the same quarter in 2013, with the largest gains seen in Africa and the Middle East.

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,
	2014		2013
Brent oil price ($/Bbl) (1)	$	107.90	$	112.82
WTI oil price ($/Bbl) (2)	98.61		94.35
Natural gas price ($/mmBtu) (3)	5.14		3.49

⁽¹⁾  Bloomberg Dated Brent (“Brent”) Oil Spot Price per Barrel

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

⁽³⁾  Bloomberg Henry Hub Natural Gas Spot Price per million British Thermal Unit

Brent oil prices averaged $107.90/Bbl in the first quarter of 2014, and were relatively stable throughout the period. During the quarter, Brent oil prices ranged from a low of $105.77/Bbl in mid-March 2014 to a high of $110.94/Bbl at the beginning of March 2014. Brent oil prices closed the quarter at $106.98/Bbl. According to the March 2014 Oil Market Report published by the International Energy Agency (“IEA”), recent demand growth has raised the 2014 oil demand forecast to 92.7 million barrels per day, which is an increase of 1.4 million barrels per day over 2013. Much of this growth is anticipated in emerging markets, most notably in Asia.

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WTI oil prices averaged $98.61/Bbl in the first quarter of 2014. During the quarter, WTI prices were more volatile than Brent oil prices as a bitterly cold winter and strong refiner demand, particularly in February and early March, resulted in prices over $100/Bbl for the first time in five months. Overall, prices ranged from a low of $91.66/Bbl in early January 2014 to a high of $104.92/Bbl in early March 2014. WTI prices closed the quarter at $101.58/Bbl.

In North America, natural gas prices, as measured by the Henry Hub Natural Gas Spot Price, averaged $5.14/mmBtu in the first quarter of 2014. Natural gas prices increased significantly during the quarter as extreme periods of cold weather in many parts of the U.S. contributed to significant withdrawals of natural gas from storage. Overall for the quarter, prices ranged from a low of $3.95/mmBtu in early January 2014 to a high of $7.92/mmBtu in early March 2014. According to the U.S. Department of Energy (“DOE”), working natural gas in storage at the end of the first quarter of 2014 was 822/Bcf, which was 52%, or 878/Bcf, below the corresponding period in 2013.

Baker Hughes Rig Count

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. We base the classification of a well as either oil or natural gas primarily upon filings made by operators in the relevant jurisdiction. 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.

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 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 Baker Hughes Rig Counts are an important business barometer for the drilling industry and its suppliers. When drilling rigs are active they consume products and services produced by the oil service industry. Rig count trends are governed by the exploration and development spending by oil and gas companies, which in turn is influenced by current and future price expectations for oil and gas. Therefore, the counts may reflect the relative strength and stability of energy prices and overall market activity. However, these counts should not be solely relied on as other specific and pervasive conditions may exist that affects overall energy prices and market activity.

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

	Three Months Ended March 31,
	2014	2013	% Change
U.S. - land and inland waters	1,724	1,706	1	%
U.S. - offshore	56	52	8	%
Canada	525	531	(1	%)
North America	2,305	2,289	1	%
Latin America	402	426	(6	%)
North Sea	38	48	(21	%)
Continental Europe	97	86	13	%
Africa	142	114	25	%
Middle East	400	355	13	%
Asia Pacific	258	245	5	%
Outside North America	1,337	1,274	5	%
Worldwide	3,642	3,563	2	%

The rig count in North America increased 1% in the first quarter of 2014 compared to the same period a year ago as oil-directed rig counts increased 2%, partially offset by a 4% decrease in the natural gas-directed rig counts. The oil-directed rig count increased 7% in the U.S. in part due to increased activity in the Permian and Eagle Ford basins, but was down 14% in Canada as high oil price differentials as compared to WTI curtailed activity. The natural gas-directed rig count reflected an 18% decrease in the U.S. Although U.S. natural gas prices increased in the first quarter, overall prices remain below levels that are considered to be economic for new investments in many natural gas fields. However, this decrease was partially offset by a 37% increase in Canada primarily resulting from increased drilling in condensate rich zones in Alberta to service oil sands drilling activity.

Outside North America, the rig count in the first quarter of 2014 increased 5% compared to the same period a year ago. The rig count in Latin America decreased 6% primarily due to reduced land rig activity in Brazil and Mexico and lower offshore activity in Brazil. This was partially offset by increased rig activity in Argentina. In Europe, the rig count in the North Sea decreased 21% primarily due to poor weather conditions in the U.K. and Norway, while in Continental Europe, the rig count increased 13% primarily due to higher activity in Turkey. The rig count increased 25% in Africa primarily due to increased drilling activities in Kenya, Angola and Chad. In the Middle East, the rig count increased 13% primarily due to increased activity in Iraq, Oman and Saudi Arabia. In Asia Pacific, the rig count increased 5% as a result of higher activity in India and offshore China, offset by reductions New Zealand.

Baker Hughes Well Count

Baker Hughes began providing U.S. well count data to the oil and natural gas industry in July 2013. The Baker Hughes Well Count is an extension of the Baker Hughes Rig Count, and provides a quarterly census of the number of new onshore oil and natural gas wells where drilling began, or spud, in the U.S. The Baker Hughes Well Count includes wells that are identified to be significant consumers of oilfield services and supplies, and excludes wells categorized as workover, plugged and abandoned or completed. Well count trends are governed by oil company exploration and development spending in the U.S., which in turn is influenced by the current and expected price of oil and natural gas. Well counts therefore may reflect the strength and stability of energy prices. However, there are many other factors that can influence the well count, including new technologies, pad drilling, weather, seasonal spending and changes to local regulations. We believe the counting process and resulting data is reliable; however, it is subject to our ability to obtain accurate and timely information.

During the first quarter of 2014, 8,853 wells were spud on land in the U.S. This compares to 8,534 wells spud in the first quarter of 2013, or an increase of 4%. This increase is primarily associated with well count growth in the Permian and Williston basins.

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RESULTS OF OPERATIONS

The discussions below relating to significant line items from our unaudited consolidated condensed statements of income are based on available information and represent our analysis of significant changes or events that impact the comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect comparability or trends and, where reasonably practicable, 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 product sales and services are similar. All dollar amounts in tabulations in this section are in millions of dollars, unless otherwise stated.

Revenue and Profit Before Tax

Revenue and profit before tax for each of our five operating segments is provided below. The performance of our 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,				$ Change			% Change
	2014		2013
Revenue:
North America	$	2,776	$	2,603	$	173		7	%
Latin America	530		590		(60		)	(10	%)
Europe/Africa/Russia Caspian	996		854		142			17	%
Middle East/Asia Pacific	1,108		894		214			24	%
Industrial Services	321		289		32			11	%
Total	$	5,731	$	5,230	$	501		10	%

	Three Months Ended March 31,						$ Change			% Change
	2014			2013
Profit Before Tax:
North America	$	258		$	235		$	23		10	%
Latin America	55			49			6			12	%
Europe/Africa/Russia Caspian	142			93			49			53	%
Middle East/Asia Pacific	135			116			19			16	%
Industrial Services	27			24			3			13	%
Total Operations	617			517			100			19	%
Corporate and other	(65		)	(62		)	(3		)	5	%
Interest expense, net	(57		)	(55		)	(2		)	4	%
Total	$	495		$	400		$	95		24	%

First Quarter of 2014 Compared to the First Quarter of 2013

Revenue for the first quarter of 2014increased$501 million, or 10%, compared to the first quarter of 2013. North America revenue increased in nearly every product line, most notably in our onshore U.S. pressure pumping business. International revenue increased primarily as a result of strong growth and increased activity in Europe/Africa/Russia Caspian and Middle East/Asia Pacific.

Profit before tax for the first quarter of 2014increased$95 million, or 24%, compared to the first quarter of 2013. This improvement can be attributed primarily to revenue growth and favorable sales mix in North America, Europe/Africa/Russia Caspian, and Middle East/Asia Pacific, as well as improved operating efficiencies in the U.S.

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and Latin America. During the first quarter of 2014, we recognized $29 million of severance charges in North America, as well as $29 million of costs associated with a technology royalty agreement. The costs related to the technology royalty agreement pertain to our global operations and therefore have been allocated to each segment as follows: North America - $13 million; Latin America - $3 million; Europe/Africa/Russia Caspian - $6 million; Middle East/Asia Pacific - $6 million; and Industrial Services - $1 million. In the first quarter of 2013, we incurred a $23 million loss in Latin America due to the devaluation of the Venezuelan currency.

North America

North America revenue increased$173 million, or 7%, in the first quarter of 2014 compared to the first quarter of 2013, despite only 1% increase in the rig count. The increase in North America revenue is primarily attributed to the U.S., where our onshore pressure pumping business experienced significant growth as ongoing revenue improvement initiatives are beginning to take hold. Our revenue growth was further augmented by record revenue in our drilling services and drill bits product lines, new technology introductions in our artificial lift product line across North America and growth in our completions and wireline services business in the Gulf of Mexico. The revenue increase in the U.S. was partially offset by Canada, where a 14% reduction in the oil-directed rig count and increased competition for hydraulic fracturing services resulted in reduced revenue.

North America profit before tax was $258 million in the first quarter of 2014, an increase of $23 million, or 10%, compared to the first quarter of 2013. The improvement was primarily driven by the continued improvement in our onshore U.S. pressure pumping business, as well as strong incrementals on increased revenues in our drilling services, drill bits, and artificial lift product lines. Gulf of Mexico profitability improved due to increased activity for our completions and wireline services product lines, which provide higher margins. These improvements were partially offset by $29 million of severance costs and $13 million of costs associated with a technology royalty agreement recognized in the first quarter of 2014.

Latin America

Latin America revenue decreased$60 million, or 10%, in the first quarter of 2014 compared to the first quarter of 2013, primarily due to reduced revenue in Brazil and Venezuela, partially offset by increased revenue in Ecuador and Argentina. The reduction in Brazil relates predominately to a new drilling services contract that started in the second quarter of 2013 which resulted in lower activity and pricing. Revenue in Venezuela declined across most product lines as contracts expired and were not renewed. These reductions were partially offset by increased activity in Ecuador for our artificial lift and drilling services product lines and in Argentina for our completions and wireline services product lines.

Latin America profit before tax increased$6 million, or 12%, in the first quarter of 2014 compared to the first quarter of 2013 despite the revenue decline. Incremental profitability can be primarily attributed to cost reduction strategies implemented in the region in the second half of 2013, coupled with increased activity in Ecuador and Argentina. Profitability was negatively impacted by unfavorable movements of exchange rates in Argentina and costs associated with the technology royalty agreement. Additionally, the first quarter of 2013 included a loss of $23 million related to the devaluation of the Venezuelan Bolivares Fuertes.

Europe/Africa/Russia Caspian

Europe/Africa/Russia Caspian (“EARC”) revenue increased$142 million, or 17%, in the first quarter of 2014 compared to first quarter of 2013 due to strong growth across Africa, as well as improvements in Russia and Europe. In Africa, revenue increases can be attributed to growth in our drilling services, completions and drilling fluids product lines in Nigeria and Central Africa, as well as new pressure pumping and drill bits contracts in Angola. In Russia, strong growth was experienced in our drilling services, pressure pumping and artificial lift product lines. Revenue growth in Europe was primarily the result of increased completions and pressure pumping activity in the North Sea, despite poor weather conditions.

EARC profit before tax increased$49 million, or 53%, in the first quarter of 2014 compared to the first quarter of 2013 primarily due to increased revenues, as well as improved sales mix throughout the segment with strong growth in drilling services, pressure pumping and wireline services. Profit before tax was negatively impacted by

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unfavorable movements of exchange rates in Russia and Kazakhstan and costs associated with a technology royalty agreement.

Middle East/Asia Pacific

Middle East/Asia Pacific (“MEAP”) revenue increased$214 million, or 24%, in the first quarter of 2014 compared to the first quarter of 2013. The strong revenue increase in this segment was largely attributable to solid growth in Iraq, Saudi Arabia, South East Asia and India. In Iraq, revenue increases were primarily related to growth with our integrated operations contracts. In Saudi Arabia, we experienced a strong demand for our completions, drilling services, pressure pumping and wireline services product lines as the rig count reached a historical high in the month of March. In South East Asia, growth was led by increased activity and new contracts in our drilling services and wireline services product lines in Malaysia and Vietnam. In India, activity growth was visible across all our product lines, most notably in pressure pumping, drilling services and wireline services.

MEAP profit before tax increased$19 million, or 16%, in the first quarter of 2014 compared to the first quarter of 2013. In addition to the increased revenue in South East Asia and India year over year, profit before tax was favorably impacted by strong incremental margins on increased revenue in our drilling services and wireline services product lines. Incremental profits were negatively impacted by high third party costs associated with our integrated operations contracts in Iraq. The first quarter of 2014 also included costs associated with a technology royalty agreement.

Industrial Services

For Industrial Services, revenue increased$32 million and profit before tax increased $3 million in the first quarter of 2014 compared to the first quarter of 2013. The increase in revenue and profit before tax was primarily driven by increased demand for our process and pipeline services business.

Costs and Expenses

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

	Three Months Ended March 31,
	2014				2013
	$		%		$		%
Revenue	$	5,731	100	%	$	5,230	100	%
Cost of revenue	4,720		82	%	4,326		83	%
Research and engineering	143		2	%	127		2	%
Marketing, general and administrative	316		6	%	322		6	%

Cost of Revenue

Cost of revenue increased 9% for the three months ended March 31, 2014, compared to the same period a year ago, consistent with the increase in revenue recognized year over year. However, cost of revenue as a percentage of revenue declined to 82% for the three months ended March 31, 2014, compared to 83% for the three months ended March 31, 2013. The decrease in cost of revenue as a percentage of revenue was driven primarily by improved margins in our pressure pumping product line in North America, cost reduction strategies implemented in Latin America and improved margins in Africa and South East Asia. These improvements during the first quarter of 2014 were partially offset by severance charges of $29 million in North America as a result of a realignment of our business to match current market conditions and costs associated with a technology royalty agreement of $29 million.

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Marketing, General and Administrative

Marketing, general and administrative expenses decreased 2% for the three months ended March 31, 2014, compared to the same period a year ago. The main driver of the decrease is the reduction in foreign exchange losses in 2014. In the first quarter of 2013, we incurred a foreign exchange loss of $23 million due to the currency devaluation in Venezuela. In the first quarter of 2014, we incurred foreign exchange losses of $11 million due primarily to unfavorable movements of exchange rates in Russia, Kazakhstan and Argentina.

Income Taxes

Total income tax expense was $159 million for the three months ended March 31, 2014. Our effective tax rate on income before income taxes for the three months ended March 31, 2014 was 32.1%. The tax rate for the three months ended March 31, 2014 is lower than the U.S. statutory income tax rate of 35% primarily due to lower rates of tax in certain foreign jurisdictions and adjustments to prior years' tax positions 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 investment 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 global 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, Organization of Petroleum Exporting Countries (“OPEC”), the Energy Information Administration (“EIA”), and the Organization for Economic Cooperation and Development (“OECD”). We acknowledge that there is a substantial amount of uncertainty regarding these forecasts, thus, while we have internal estimates regarding economic expansion, hydrocarbon demand and overall oilfield activity, we position ourselves to be flexible and responsive to a wide range of potential outcomes.

We consider the primary drivers impacting the 2014 business environment to include the following:

• Worldwide Economic Growth - In general, there is a strong correlation between overall economic growth and global demand for hydrocarbons. The economic outlook for 2014 includes strengthened economic activity but also some embedded risks. Europe is starting to emerge from the sovereign debt crisis, but faces renewed uncertainty as tensions and the possibility of sanctions against Russia, in light of the political crisis in Ukraine, could lead to structural shifts in European energy demand. China's economy is experiencing a slowdown in growth, but will remain the most significant driver of global growth in 2014. Since the recession of 2008/2009, China's rapid development and industrialization has been a major factor in driving up worldwide economic growth; however, China's economic growth rates have slowed in recent years to as low as 7.7% in 2013. For 2014, the International Monetary Fund (“IMF”) estimates China’s economic growth will be even lower at 7.5% as policymakers refrain from stimulating activity amid inflation concerns. This figure is expected to decrease slightly again in 2015 to 7.3%. In the U.S., the IMF forecasts 2.8% Gross Domestic Product growth in 2014, an increase over 2013, driven by continued strong private

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demand, and in particular, a recovering housing market. However, this growth may be hampered by any deterioration of the global economy, particularly in China and Europe.

• Demand for Hydrocarbons - In its March 2014 Oil Market Report, the IEA forecasted global demand for oil to increase by 1.4 million barrels per day (“bpd”) in 2014, reaching 92.7 million bpd. This expected increase is mainly driven by emerging market countries outside the OECD and should support upstream investment in oil and natural gas production around the world. In addition to the global growth in oil demand, natural gas will remain important in meeting the world’s energy needs. In its March 2014 Short-Term Energy Outlook, the EIA estimated that gas demand in the U.S. will be flat as compared to 2013 due to increased industrial demand for natural gas in the U.S. being offset by declines in gas-fired power output and a decline in residential and commercial consumption. Overall, U.S. natural gas demand will remain around 71.3 billion cubic feet per day (“bcfd”) in 2014.

• Oil Production - The March 2014 IEA Oil Market Report projected non-OPEC production to grow by 1.7 million bpd in 2014. This increase is largely due to continued production growth from U.S. unconventional oil formations and Canadian oil sands, fostered by sustained higher oil prices. Further, in March 2014, OPEC production eclipsed 30 million bpd due to oil output from Iraq reaching a 35-year high. For the duration of 2014, OPEC’s production target is expected to remain unchanged at 30 million bpd, with slight changes possible if there is substantial movement in the oil price. Significant investments are expected to be required to increase production capacity, especially as output from mature fields decline and production rates from early wells at unconventional deposits continue to drop.

• Natural Gas Production - Natural gas production continues to grow worldwide, including in North America where drilling activity has slowed. U.S. natural gas production continues to increase despite natural gas-directed rig counts being down 31% in 2013 compared to 2012 and reaching 21-year lows in March 2014. In its March 2014 Short-Term Energy Outlook, the EIA estimated that U.S. natural gas production will increase by 3% in 2014, from 70.2 bcfd to 72.3 bcfd. Overall, global natural gas output will tend to be up in 2014 due to the increased production in the U.S., as well as in the Eastern Hemisphere as high natural gas prices in Europe and Asia should encourage growth.

• Oil Prices - With WTI oil prices trading between $91.66/Bbl and $104.92/Bbl, and Brent trading between $105.77/Bbl and $110.94/Bbl during the first quarter of 2014, most global oil activity will continue to provide adequate returns to encourage incremental investment. Based on oil supply forecasts and modest anticipated economic growth globally, oil prices are expected to remain relatively stable throughout 2014, barring any major macroeconomic changes.

• Natural Gas Prices - Although Henry Hub natural gas prices traded between $3.95/mmBtu and $7.92/mmBtu during the first quarter of 2014, prices are expected to stabilize and remain on average at the lower end of this range for the duration of the year. According to the EIA, they projected in their March 2014 Short-term Energy Outlook an average price of $4.44/mmBtu in 2014. Based on this, we estimate that the economics of most dry natural gas-directed investments in North America will likely continue to be marginal. This is primarily due to the abundant supplies from unconventional plays in North America, including associated gas produced at liquids-rich unconventional plays.

Activity and Spending Outlook for North America - Overall customer spending in North America is expected to increase approximately 5% in 2014 compared to 2013, with the average annual rig count growing 4%. Additional customer spending above the rig count can be attributed in part to improved efficiencies in drilling performance. Overall service activity has increased in North America as customers demand robust technologies such as advanced directional drilling, complex completion systems and pressure pumping to develop liquids-rich unconventional plays such as the Permian and the Eagle Ford basins. Drilling activity in the Gulf of Mexico is expected to increase in 2014, with the addition of 4 or 5 new deepwater exploration rigs. Completions and development activity in the Gulf of Mexico will also continue to grow in 2014. In Canada, overall rig activity in 2014 is expected to be up approximately 5% as compared to 2013.

Activity and Spending Outlook Outside North America - International activity is driven primarily by the oil and gas price environment, which currently provides attractive economic returns in almost every geographic region and is strong enough to support major natural gas export projects, in particular via liquefied natural gas ("LNG"). Customers are expected to increase spending to develop new resources and offset declines from existing producing fields, relying on advanced drilling techniques to support exploration and production activities in deepwater, heavy or viscous oils and tight reservoirs. For 2014, we anticipate a 9% increase in international rig activity relative to 2013, with improvements anticipated in all international regions. This is down slightly from our previous estimate of

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10% due to less onshore activity in Latin America, most notably in Mexico. Areas that are expected to see the largest increases include the Middle East, in particular Saudi Arabia, Iraq, and the Gulf States; Africa and Asia Pacific. Looking beyond 2014, one potential major change is the planned opening of Mexico’s oil and gas resources to foreign investors, which could lead to a surge in new spending and new investment upstream in Mexico, both onshore and offshore.

Around the world, the drivers of oil and gas commercialization have changed. Within Southeast Asia, there is an increased focus on exploration and development of oil and natural gas resources to meet high local demand growth rather than the historic focus on exports. In Africa, traditional growth areas such as Angola and Nigeria are being augmented by new producers such as Ghana, Uganda, Mozambique and Tanzania. Russia is striving to maintain 10 million barrels of oil production per day through 2020 by investing in Eastern Siberia and eventually in technically challenging offshore Arctic deposits. Efforts in Russia at developing tight oil using vertical drilling are already underway, and the government provided support for pilot projects in 2013 featuring more complex horizontal drilling and completions. In natural gas, Australia is leading the expansion of LNG export projects, using offshore gas drilling in the northwest shelf as well as onshore coal-bed methane operations. Large-scale gas pipeline exports from the Caspian region to China and Europe are expected to grow significantly in the next five years, spurring drilling for deeper targets, both onshore and offshore, and increased natural gas process plant capacity for sour gas.

While the development of unconventional oil and natural gas deposits is still in its infancy outside North America, there is a general consensus that unconventional resources will play a growing role in the future of global energy supply. Countries taking active steps to develop their unconventional reserves base include Australia, China, Saudi Arabia, Argentina and Poland. However, there is demonstrated interest at ministry and national oil company levels in defining unconventional resource potential in almost all countries with active hydrocarbon industries.

LIQUIDITY AND CAPITAL RESOURCES

Our objective in financing our business is to maintain sufficient liquidity, adequate financial resources and financial flexibility in order to fund the requirements of our business. At March 31, 2014, we had cash and cash equivalents of $1.20 billion, compared to $1.40 billion of cash and cash equivalents held at December 31, 2013. Substantially all of the consolidated cash balances were held by foreign subsidiaries. A substantial portion of the cash held by foreign subsidiaries at March 31, 2014 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 $2.50 billion committed revolving credit facility with commercial banks and a commercial paper program under which we may issue up to $2.50 billion. The maximum combined borrowing at any time under both the credit facility and commercial paper program is $2.50 billion. At March 31, 2014, we had outstanding commercial paper of $373 million; therefore, the amount available for borrowing under the facility as of March 31, 2014 was $2.13 billion. We believe that cash on hand, cash flows generated from operations and the available credit facility, including the issuance of commercial paper, will provide sufficient liquidity to manage our global cash needs. In the three months ended March 31, 2014, we used cash to fund a variety of activities including working capital needs, capital expenditures, repurchase of our common stock and payment of dividends.

Cash Flows

Cash flows provided by (used in) each type of activity were as follows for the three months ended March 31:

(In millions)	2014			2013
Operating activities	$	303		$	386
Investing activities	(364		)	(396		)
Financing activities	(138		)	100

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Operating Activities

Cash flows from operating activities provided $303 million in the three months ended March 31, 2014. Before changes in operating assets and liabilities, the major source of funds was net income, including noncontrolling interests, of $336 million plus the noncash provision for depreciation and amortization of $437 million. Net changes in operating assets and liabilities used cash of $437 million in the three months ended March 31, 2014. This was primarily the result of an increase in accounts receivable of $161 million due to slower collections, an increase in inventory of $116 million due to increased activity, and a decrease in accounts payable of $85 million.

Investing Activities

Our principal recurring investing activity is 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 $439 million in the three months ended March 31, 2014. While the majority of these expenditures were for machinery and equipment, it also includes spending on new facilities, expansions of existing facilities and other infrastructure projects.

Proceeds from the disposal of assets were $100 million in the three months ended March 31, 2014. These disposals related to equipment that was lost-in-hole and property, machinery and equipment no longer used in operations that was sold throughout the period.

Financing Activities

We had net proceeds from commercial paper and other short-term debt of $114 million in the three months ended March 31, 2014. Total debt outstanding at March 31, 2014 was $4.50 billion, an increase of $122 million compared to December 31, 2013. The total debt-to-capital (defined as total debt plus equity) ratio was 0.20 at March 31, 2014 and December 31, 2013. We paid dividends of $66 million in the three months ended March 31, 2014.

Our Board of Directors has authorized a program to repurchase our common stock from time to time. In the three months ended March 31, 2014, we repurchased 3.4 million shares of our common stock at an average price of $59.40 per share, for a total of $200 million. We had authorization remaining to repurchase approximately $1.45 billion in common stock at March 31, 2014. During the three months ended March 31, 2013, we did not repurchase any shares of common stock.

Available Credit Facility

We have a $2.50 billion committed revolving credit facility with commercial banks that matures in September 2016. At March 31, 2014, 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, 2014. We also have a commercial paper program under which we may issue from time to time up to $2.50 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 $2.50 billion. At March 31, 2014, we had $373 million of commercial paper outstanding resulting in $2.13 billion available under the credit facility.

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

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Cash Requirements

In 2014, we believe cash on hand, 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. If necessary, we may issue commercial paper or other short-term debt to fund cash needs in the U.S. in excess of the cash generated in the U.S.

In 2014, we expect our capital expenditures to be approximately $2.0 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 and managed by us to match market demand and activity levels. In 2014, we also expect to make interest payments of between $235 million to $255 million, based on debt levels as of March 31, 2014. We anticipate making income tax payments of between $1.0 billion to $1.1 billion in 2014.

We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. We anticipate paying dividends of between $263 million and $273 million in 2014; however, the Board of Directors can change the dividend policy at any time.

During the three months ended March 31, 2014, we contributed approximately $102 million to our defined benefit, defined contribution and other postretirement plans. We expect to make additional contributions in the range of $279 million to $311 million to these plans for the remainder of 2014.

FORWARD-LOOKING STATEMENTS

MD&A and certain statements in the Notes to Unaudited Consolidated Condensed Financial Statements, includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act (each a “forward-looking statement”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “probable,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “potential,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward-looking statements. Our forward-looking statements are based on assumptions that we believe to be reasonable but that may not prove to be accurate. The statements do not include the potential impact of future transactions, such as an acquisition, disposition, merger, joint venture or other transactions that could occur. We undertake no obligation to publicly update or revise any forward-looking statement. Our expectations regarding our business outlook, including changes in revenue, pricing, capital spending, profitability, strategies for our operations, impact of any common stock repurchases, oil and natural gas market conditions, the business plans of our customers, market share and 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 2013 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 (“EDGAR”) system at http://www.sec.gov.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the three months ended March 31, 2014, does not differ materially from that discussed under Part II, Item 7(a), “Quantitative and Qualitative Disclosures About Market Risk,” in our 2013 Annual Report on Form 10-K.

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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, 2014, 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, 2014 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

See discussion of legal proceedings in Note 9 of the Notes to Unaudited Consolidated Condensed Financial Statements in this Quarterly Report, Item 3 of Part I of our 2013 Annual Report and Note 11 of the Notes to Consolidated Financial Statements included in Item 8 of our 2013 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 2013 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 March 31, 2014.

Period	Total Number of Shares Purchased (1)	Average Price Paid Per Share (2)		Total Number of Shares Purchased as Part of a Publicly Announced Program (3)	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Program (4)
January 1-31, 2014	1,028,314	$	56.48	715,000	$	—
February 1-28, 2014	2,473,800	59.96		2,471,588	—
March 1-31, 2014	268,012	63.09		180,500	—
Total	3,770,126	$	59.23	3,367,088	$	1,449,829,028

⁽¹⁾  Includes shares purchased from employees to pay the option exercise price related to stock-for-stock exchanges in option exercises; shares purchased from employees to satisfy the tax withholding obligations in connection with the vesting of restricted stock awards and restricted stock units; and shares purchased in the open market under our publicly announced purchase program.

⁽²⁾  Average price paid includes commissions for shares purchased in the open market under our publicly announced purchase program.

⁽³⁾  Repurchases were made under our previously announced purchase program, including under a Letter Agreement with an agent that complied with the requirements of Rule 10b-18 of the Exchange Act (the “Agreement”). Shares were repurchased under the Agreement by the agent at the prevailing market prices, in open market transactions.

⁽⁴⁾  During the three months ended March 31, 2014, we repurchased 3.4 million shares of our common stock at an average price of $59.40 per share (including commissions), for a total of $200 million. We had authorization remaining to repurchase up to a total of approximately $1.45 billion of our common stock as of March 31, 2014.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Our barite mining operations, in support of our drilling fluids products and services business, are subject to regulation by the federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Quarterly Report.

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ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

31.1*	Certification of Martin S. Craighead, Chairman 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, Senior Vice President and 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, Chairman and Chief Executive Officer, and Peter A. Ragauss, Senior Vice President and 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:	April 23, 2014	By:	/s/ PETER A. RAGAUSS
		Peter A. Ragauss
		Senior Vice President and Chief Financial Officer
Date:	April 23, 2014	By:	/s/ ALAN J. KEIFER
		Alan J. Keifer
		Vice President and Controller

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