UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 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 July 17, 2014, the registrant has outstanding 435,042,740 shares of Common Stock, $1 par value per share.

Baker Hughes Incorporated

Table of Contents

		Page No.
PART I -	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Condensed Statements of Income (Unaudited) Three and six months ended June 30, 2014 and 2013	2
	Consolidated Condensed Statements of Comprehensive Income (Loss) (Unaudited) Three and six months ended June 30, 2014 and 2013	3
	Consolidated Condensed Balance Sheets (Unaudited) June 30, 2014 and December 31, 2013	4
	Consolidated Condensed Statements of Changes in Equity (Unaudited) Six months ended June 30, 2014 and 2013	5
	Consolidated Condensed Statements of Cash Flows (Unaudited) Six months ended June 30, 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	14
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	27
Item 4.	Controls and Procedures	27
PART II -	OTHER INFORMATION
Item 1.	Legal Proceedings	28
Item 1A.	Risk Factors	28
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	28
Item 3.	Defaults Upon Senior Securities	28
Item 4.	Mine Safety Disclosures	28
Item 5.	Other Information	29
Item 6.	Exhibits	30
	Signatures	31

1

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)

Baker Hughes Incorporated

Consolidated Condensed Statements of Income

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions, except per share amounts)	2014			2013			2014			2013
Revenue:
Sales	$	1,975		$	1,869		$	3,832		$	3,618
Services	3,960			3,618			7,834			7,099
Total revenue	5,935			5,487			11,666			10,717
Costs and expenses:
Cost of sales	1,530			1,467			3,031			2,851
Cost of services	3,215			3,124			6,434			6,066
Research and engineering	159			131			302			258
Marketing, general and administrative	338			329			654			651
Litigation settlements	62			—			62			—
Total costs and expenses	5,304			5,051			10,483			9,826
Operating income	631			436			1,183			891
Interest expense, net	(59		)	(60		)	(116		)	(115		)
Income before income taxes	572			376			1,067			776
Income taxes	(213		)	(131		)	(372		)	(263		)
Net income	359			245			695			513
Net income attributable to noncontrolling interests	(6		)	(5		)	(14		)	(6		)
Net income attributable to Baker Hughes	$	353		$	240		$	681		$	507
Basic earnings per share attributable to Baker Hughes	$	0.81		$	0.54		$	1.56		$	1.14
Diluted earnings per share attributable to Baker Hughes	$	0.80		$	0.54		$	1.55		$	1.14
Cash dividends per share	$	0.15		$	0.15		$	0.30		$	0.30

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

2

Baker Hughes Incorporated

Consolidated Condensed Statements of Comprehensive Income (Loss)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2014			2013			2014			2013
Net income	$	359		$	245		$	695		$	513
Other comprehensive income (loss):
Foreign currency translation adjustments during the period	29			(30		)	3			(110		)
Pension and other postretirement benefits, net of tax	(4		)	3			(8		)	13
Hedge transactions, net of tax	—			(3		)	—			(3		)
Other comprehensive income (loss)	25			(30		)	(5		)	(100		)
Comprehensive income	384			215			690			413
Comprehensive income attributable to noncontrolling interests	(6		)	(5		)	(14		)	(6		)
Comprehensive income attributable to Baker Hughes	$	378		$	210		$	676		$	407

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

3

Baker Hughes Incorporated

Consolidated Condensed Balance Sheets

(Unaudited)

(In millions)	June 30, 2014			December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	1,163		$	1,399
Accounts receivable - less allowance for doubtful accounts (2014 - $215; 2013 - $238)	5,361			5,138
Inventories, net	4,075			3,884
Deferred income taxes	392			380
Other current assets	556			494
Total current assets	11,547			11,295
Property, plant and equipment - less accumulated depreciation (2014 - $7,815; 2013 - $7,219)	9,087			9,076
Goodwill	5,999			5,966
Intangible assets, net	836			883
Other assets	808			714
Total assets	$	28,277		$	27,934
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	2,536		$	2,574
Short-term debt and current portion of long-term debt	657			499
Accrued employee compensation	569			778
Income taxes payable	306			213
Other accrued liabilities	527			514
Total current liabilities	4,595			4,578
Long-term debt	3,900			3,882
Deferred income taxes and other tax liabilities	773			821
Liabilities for pensions and other postretirement benefits	577			583
Other liabilities	181			158
Commitments and contingencies
Equity:
Common stock	435			438
Capital in excess of par value	7,123			7,341
Retained earnings	10,988			10,438
Accumulated other comprehensive loss	(509		)	(504		)
Baker Hughes stockholders’ equity	18,037			17,713
Noncontrolling interests	214			199
Total equity	18,251			17,912
Total liabilities and equity	$	28,277		$	27,934

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

4

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							681						14		695
Other comprehensive loss										(5		)			(5		)
Activity related to stock plans	3			113											116
Repurchase and retirement of common stock	(6		)	(394		)									(400		)
Stock-based compensation				63											63
Cash dividends ($0.30 per share)							(131		)						(131		)
Net activity related to noncontrolling interests													1		1
Balance at June 30, 2014	$	435		$	7,123		$	10,988		$	(509	)	$	214	$	18,251

	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					507						6			513
Other comprehensive loss								(100		)				(100		)
Activity related to stock plans	2		22											24
Stock-based compensation			60											60
Cash dividends ($0.30 per share)					(132		)							(132		)
Net activity related to noncontrolling interests											(6		)	(6		)
Balance at June 30, 2013	$	443	$	7,577	$	9,984		$	(576	)	$	199		$	17,627

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

5

Baker Hughes Incorporated

Consolidated Condensed Statements of Cash Flows

(Unaudited)

	Six Months Ended June 30,
(In millions)	2014			2013
Cash flows from operating activities:
Net income	$	695		$	513
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	891			839
Other noncash items	(48		)	(107		)
Changes in operating assets and liabilities:
Accounts receivable	(349		)	(494		)
Inventories	(192		)	(89		)
Accounts payable	(31		)	502
Other operating items, net	(270		)	(86		)
Net cash flows provided by operating activities	696			1,078
Cash flows from investing activities:
Expenditures for capital assets	(863		)	(1,041		)
Proceeds from disposal of assets	203			183
Other investing items, net	(26		)	(4		)
Net cash flows used in investing activities	(686		)	(862		)
Cash flows from financing activities:
Net proceeds (repayments) of commercial paper borrowings and other debt with original maturity of three months or less	190			(40		)
Net (repayments) proceeds of short-term debt with original maturity greater than three months	(12		)	40
Repurchase of common stock	(400		)	—
Proceeds from issuance of common stock	129			43
Dividends paid	(131		)	(132		)
Other financing items, net	(21		)	(14		)
Net cash flows used in financing activities	(245		)	(103		)
Effect of foreign exchange rate changes on cash and cash equivalents	(1		)	(5		)
(Decrease) increase in cash and cash equivalents	(236		)	108
Cash and cash equivalents, beginning of period	1,399			1,015
Cash and cash equivalents, end of period	$	1,163		$	1,123
Supplemental cash flows disclosures:
Income taxes paid, net of refunds	$	360		$	343
Interest paid	$	124		$	121
Supplemental disclosure of noncash investing activities:
Capital expenditures included in accounts payable	$	119		$	102

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 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 (“GAAP”) 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.

New Accounting Standards Updates

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers. The ASU will supersede most of the existing revenue recognition requirements in U.S. GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Company expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires significantly expanded disclosures regarding the qualitative and quantitative information of an entity's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The pronouncement is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period and is to be applied retrospectively, with early application not permitted. We are currently evaluating the impact the pronouncement will have on our consolidated financial statements and related disclosures.

In April 2014, the FASB issued ASU No. 2014-08, Presentation of Financial Statements and Property, Plant, and Equipment - Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which amends the definition of a discontinued operation by raising the threshold for a disposal to qualify as discontinued operations. The ASU will also require entities to provide additional disclosures about discontinued operations as well as disposal transactions that do not meet the discontinued operations criteria. The pronouncement is effective prospectively for all disposals (except disposals classified as held for sale before the adoption date) or components initially classified as held for sale in periods beginning on or after December 15, 2014. Early adoption is permitted. We adopted the ASU in the second quarter of 2014 and it did not impact our consolidated financial statements or the notes to our financial statements.

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 (“USD”) would only apply to certain economic sectors related to purchases of “essential goods and services” while other sectors of the economy would apply a new exchange rate, SICAD 1, determined by an auction process conducted by Venezuela's Complimentary System of Foreign Currency Administration. Participation in the SICAD 1 mechanism is controlled by the Venezuelan government and is limited to certain companies that operate in designated industry sectors. As of June 30, 2014, we have not been able to participate in any SICAD 1 auctions.

7

Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

In March 2014, another currency exchange mechanism was established by the Venezuelan government that allows other economic sectors and companies to participate in the auction process (“SICAD 2”) and during the second quarter of 2014, we successfully participated in SICAD 2 auctions.

We have not been eligible to apply for exchange at the official rate nor do we expect to be allowed to participate in the SICAD 1 auctions. We are both eligible and have successfully participated in SICAD 2 auctions. As a result, during the second quarter of 2014, we adopted the SICAD 2 exchange rate of approximately 50 BsF per USD for purposes of remeasuring BsF denominated assets and liabilities and revenue and expenses because we believe the SICAD 2 rate is the rate most representative of the economics in which we operate. Prior to this change, we were using the official exchange rate of 6.3 BsF per USD. The impact of this change was a loss of $12 million resulting from the write down of our BsF denominated monetary assets and liabilities. This loss was recorded in marketing, general and administrative expense in the second quarter of 2014.

In February 2013, Venezuela's currency was devalued from the prior official exchange rate of 4.3 BsF per USD to 6.3 BsF per USD, which applied to our BsF denominated monetary assets and liabilities. The impact of this devaluation was a loss of $23 million and was recorded in marketing, general and administrative expense in the first quarter of 2013.

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 June 30,		Six Months Ended June 30,
	2014	2013	2014	2013
Weighted average common shares outstanding for basic EPS	437	443	438	443
Adjustment for effect of dilutive securities - stock plans	3	1	2	1
Weighted average common shares outstanding for diluted EPS	440	444	440	444
Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than the average market price for the period	2	7	2	7

NOTE 4. INVENTORIES

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

	June 30, 2014		December 31, 2013
Finished goods	$	3,616	$	3,438
Work in process	237		215
Raw materials	222		231
Total inventories	$	4,075	$	3,884

8

Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 5. INTANGIBLE ASSETS

Intangible assets are comprised of the following:

	June 30, 2014						December 31, 2013
	Gross Carrying Amount		Less: Accumulated Amortization		Net		Gross Carrying Amount		Less: Accumulated Amortization		Net
Technology	$	817	$	364	$	453	$	814	$	337	$	477
Customer relationships	496		177		319		494		157		337
Trade names	120		87		33		120		82		38
Other (1)	43		12		31		43		12		31
Total intangible assets	$	1,476	$	640	$	836	$	1,471	$	588	$	883

⁽¹⁾  Includes indefinite-lived intangibles of $27 million at June 30, 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 and six months ended June 30, 2014 was $27 million and $53 million, respectively, as compared to $30 million and $59 million reported in 2013 for the same period.

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	$	52
2015	98
2016	96
2017	93
2018	87
2019	84

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 June 30, 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 June 30, 2014 and December 31, 2013 was $5,218 million and $4,857 million, respectively, which differs from the carrying amounts of $4,557 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.

9

Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

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
	June 30, 2014					June 30, 2013
Segments	Revenue		Profit (Loss) Before Taxes			Revenue		Profit (Loss) Before Taxes
North America	$	2,843	$	340		$	2,677	$	211
Latin America	544		46			557		(18		)
Europe/Africa/Russia Caspian	1,066		178			966		151
Middle East/Asia Pacific	1,149		168			971		115
Industrial Services	333		34			316		39
Total Operations	5,935		766			5,487		498
Corporate and other	—		(73		)	—		(62		)
Interest expense, net	—		(59		)	—		(60		)
Litigation settlements	—		(62		)	—		—
Total	$	5,935	$	572		$	5,487	$	376

	Six Months Ended					Six Months Ended
	June 30, 2014					June 30, 2013
Segments	Revenue		Profit (Loss) Before Taxes			Revenue		Profit (Loss) Before Taxes
North America	$	5,619	$	598		$	5,280	$	446
Latin America	1,074		101			1,147		31
Europe/Africa/Russia Caspian	2,062		320			1,820		244
Middle East/Asia Pacific	2,257		303			1,865		231
Industrial Services	654		61			605		63
Total Operations	11,666		1,383			10,717		1,015
Corporate and other	—		(138		)	—		(124		)
Interest expense, net	—		(116		)	—		(115		)
Litigation settlements	—		(62		)	—		—
Total	$	11,666	$	1,067		$	10,717	$	776

10

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, when they retire, have met certain age and service requirements.

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

	U.S. Pension Benefits						Non-U.S. Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013			2014			2013
Service cost	$	18		$	16		$	4		$	4		$	2		$	2
Interest cost	7			5			9			8			1			1
Expected return on plan assets	(11		)	(10		)	(10		)	(10		)	—			—
Amortization of prior service credit	—			—			—			—			(2		)	(2		)
Amortization of net actuarial loss	2			4			1			2			—			1
Other	—			—			—			—			1			—
Net periodic cost	$	16		$	15		$	4		$	4		$	2		$	2

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

	U.S. Pension Benefits						Non-U.S. Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013			2014			2013
Service cost	$	35		$	32		$	7		$	8		$	3		$	4
Interest cost	14			11			18			16			3			2
Expected return on plan assets	(22		)	(20		)	(20		)	(20		)	—			—
Amortization of prior service credit	—			—			—			—			(3		)	(4		)
Amortization of net actuarial loss	4			7			2			4			1			2
Other	—			—			—			—			(3		)	—
Net periodic cost	$	31		$	30		$	7		$	8		$	1		$	4

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.

11

Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

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.

We are a defendant in various labor claims including the following matters. On April 28, 2014, 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 ("FLSA") was filed titled Michael Ciamillo, individually, etc., et al. vs. Baker Hughes Incorporated in the U.S. District Court for the District of Alaska. On December 10, 2013, a class and collective action lawsuit alleging that we failed to pay a nationwide class of workers overtime in compliance with the FLSA 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 ("Lea"). 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 FLSA 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.

During the second quarter of 2014, the parties agreed to settle the Lea lawsuit, subject to final court approval, and we recorded a charge of $62 million, which includes the Lea settlement amount and associated costs and an amount for settlement of another wage and hour lawsuit. As it relates to the Zamora and Ciamillo lawsuits, 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 U.S. 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 pumping services in the U.S. 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 June 30, 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) income before    reclassifications		(8		)		3				(5		)
Amounts reclassified from accumulated other    comprehensive loss		1				—				1
Deferred taxes		(1		)		—				(1		)
Balance at June 30, 2014		$	(225	)		$	(284	)		$	(509	)

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Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

	Hedge Transactions				Pensions and Other Postretirement Benefits				Foreign Currency Translation Adjustments				Accumulated Other Comprehensive Loss
Balance at December 31, 2012		$	—			$	(250	)		$	(226	)		$	(476	)
Other comprehensive (loss) income before reclassifications		(3		)		7				(110		)		(106		)
Amounts reclassified from accumulated other comprehensive loss		—				9				—				9
Deferred taxes		—				(3		)		—				(3		)
Balance at June 30, 2013		$	(3	)		$	(237	)		$	(336	)		$	(576	)

The amounts reclassified from accumulated other comprehensive loss during thesix months ended June 30, 2014 and 2013 represent the amortization of prior service credit, net actuarial loss, and other which are included in the computation of net periodic cost (see Note 8. Employee Benefit Plans for additional details). Net periodic 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 second quarter of 2014, we generated revenue of $5.94 billion, an increase of $448 million, or 8%, compared to the second quarter of 2013, and an increase of $204 million, or 4%, compared to the first quarter of 2014, or sequentially. Net income attributable to Baker Hughes was $353 million for the second quarter of 2014 compared to $240 million for the second quarter of 2013, and $328 million for the first quarter of 2014.

North America oilfield revenue for the second quarter of 2014 was $2.84 billion, an increase of $166 million, or 6%, compared to the second quarter of 2013, and an increase of $67 million, or 2%, compared to the first quarter of 2014. North America oilfield profit before tax for the second quarter of 2014 was $340 million compared to $211 million for the second quarter of 2013, and $258 million for the first quarter of 2014. Our revenue in the second quarter of 2014 compared to the same quarter a year ago increased as a result of strong activity growth, mainly in our drilling services, drill bits and artificial lift product lines. Profitability in North America increased $129 million, or 61%, year over year primarily attributed to operational leverage from activity growth, higher margin on the increase in revenue from recently introduced well construction and production technologies, and continued improvement of our pressure pumping business. Sequentially, our North America oilfield revenue and profit margins improved due to increased activity in the U.S. onshore business, which more than offset the seasonal decline in Canada. U.S. offshore operations also grew sequentially with increased drilling and well completion activity in the quarter.

Oilfield revenue outside of North America for the second quarter of 2014 was $2.76 billion, an increase of $265 million, or 11%, compared to the second quarter of 2013, and an increase of $125 million, or 5%, sequentially. Oilfield profitability outside of North America for the second quarter of 2014 was $392 million compared to $248 million for the second quarter of 2013, and $332 million for the first quarter of 2014. The increase in revenue in the second quarter of 2014 compared to the same quarter a year ago was driven by strong growth in both the Europe/Africa/Russia Caspian ("EARC") and Middle East/Asia Pacific ("MEAP") segments, predominately in Saudi Arabia, Africa and Russia. Profitability increased in all three geographic segments outside of North America compared to the second quarter of 2013, but particularly in Latin America due to continued focus on operational efficiencies and favorable geographic mix. Profitability in the second quarter of 2014 was impacted by a foreign exchange loss of $12 million related to the Venezuela currency devaluation. Sequentially, oilfield revenue outside of North America increased as a result of the rebound of activity in Russia and the North Sea following adverse weather conditions in the first quarter, strong drilling services activity in Saudi Arabia with a historical high rig count, increased activity and

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share in Africa as a result of recently awarded contracts, and increased product sales in Australia, China and South East Asia. Sequentially, our profitability increased primarily due to revenue growth in the EARC and MEAP segments.

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 still pending antitrust approval by regulatory authorities in various countries.

As of June 30, 2014, we had approximately 59,200 employees compared to approximately 59,400 employees as of December 31, 2013.

BUSINESS ENVIRONMENT

In North America, rig counts increased 7% in the second quarter of 2014 compared to the same period a year ago, comprised of a 9% increase in the oil-directed rig count and a flat natural gas-directed rig count. In the U.S., the oil-directed rig count increased 10% as higher West Texas Intermediate (“WTI”) oil prices and modest economic growth predictions have contributed to increased customer spending in oil basins, such as the Permian and Eagle Ford. In Canada, the oil-directed rig count is up 5% where oil drilling activity resumed at an accelerated pace after the seasonal spring break up. The natural gas-directed rig count had a decrease of 11% in the U.S. during the second quarter of 2014 compared to the same period a year ago reaching a 21 year low at 310 rigs. This rig count decrease was offset by a 69% increase in the natural gas-directed rig count in Canada which was driven by drilling in condensate rich zones in Alberta to service activity in the oil sands. This increase in the natural gas-directed rig count combined with a short spring break up ultimately resulted in a 31% increase in total Canadian rig activity in the second 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 up 7% in the second quarter of 2014 compared to the same period a year ago driven by supply concerns over instability in Iraq and Ukraine. Despite higher oil prices, the international rig count only grew by 3% in the second quarter of 2014 compared to the same quarter in 2013, with the largest gains seen in the Middle East, Europe and Africa.

Oil and Natural Gas Prices

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Brent oil price ($/Bbl) (1)	$	109.77	$	103.00	$	108.85	$	107.87
WTI oil price ($/Bbl) (2)	103.11		94.13		100.88		94.24
Natural gas price ($/mmBtu) (3)	4.59		4.02		4.86		3.76

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

⁽²⁾  Bloomberg 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 $109.77/Bbl in the second quarter of 2014, increasing steadily throughout the period as a result of lingering concerns that violence in Iraq, OPEC's (Organization of the Petroleum Exporting Countries) second-largest producer, might lead to supply disruptions. Additionally, continued record-high levels of Chinese crude oil imports in 2014, and ongoing delays to Libyan oil exports have contributed to upward price pressure. During the quarter, Brent oil prices ranged from a low of $103.95/Bbl at the beginning of April 2014 to a nine month high of $115.00/Bbl towards the end of June 2014. Brent oil prices closed the quarter slightly down at $112.09/Bbl

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as worries about an immediate disruption of Iraqi oil supply continued to recede as output from Iraq's southern oilfields, which produce most of the nation's 3.3 million barrels per day ("bpd"), remained unaffected by fighting in the north and west. According to the June 2014 Oil Market Report published by the International Energy Agency (“IEA”), recent demand growth has raised the 2014 oil demand forecast marginally upward to 92.8 million bpd from 92.7 million bpd in March 2014, which is an increase of 1.4 million bpd over 2013. Much of this growth is anticipated in emerging markets, most notably in Asia.

WTI oil prices averaged $103.11/Bbl in the second quarter of 2014. During the quarter, WTI prices rose roughly in line with Brent oil prices as concerns persisted that an insurgency in Iraq could disrupt oil exports. The January 2014 startup of TransCanada’s Marketlink pipeline, moving crude oil from Cushing, Oklahoma to the Gulf Coast, and strong refinery runs also contributed to an increase in the WTI crude oil price. Overall, prices ranged from a low of $99.42/Bbl in early May 2014 to a high of $107.26/Bbl in late June 2014. WTI prices closed the quarter slightly down at $105.37/Bbl due to reduced concerns over exports from strife-torn Iraq as the situation tempered.

In North America, natural gas prices, as measured by the Henry Hub Natural Gas Spot Price, averaged $4.59/mmBtu in the second quarter of 2014. Natural gas prices increased slightly during the quarter as natural gas storage levels continue to drop below five year averages as a result of the cold weather in the first quarter of 2014 in many parts of the U.S. which contributed to significant withdrawals of natural gas from storage. Overall for the quarter, prices ranged from a low of $4.35/mmBtu in early April 2014 to a high of $4.83/mmBtu in early May 2014. Henry Hub Natural Gas Spot prices closed the quarter at $4.42/mmBtu as expectations for a bigger-than-normal storage build offset short-term forecasts for hot weather and strong air conditioning demand in key consuming regions. According to the U.S. Department of Energy, working natural gas in storage at the end of the second quarter of 2014 was 1,929 billion cubic feet ("Bcf"), which was 26%, or 676 Bcf, below the corresponding period in 2013 but a 1,107 Bcf, or 135%, above the end of the first quarter of 2014.

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 June 30,				Six Months Ended June 30,
	2014	2013	% Change		2014	2013	% Change
U.S. - land and inland waters	1,796	1,710	5	%	1,760	1,708	3	%
U.S. - offshore	56	52	8	%	56	52	8	%
Canada	199	152	31	%	362	342	6	%
North America	2,051	1,914	7	%	2,178	2,102	4	%
Latin America	402	425	(5	%)	402	426	(6	%)
North Sea	44	42	5	%	41	45	(9	%)
Continental Europe	105	91	15	%	101	88	15	%
Africa	133	127	5	%	137	121	13	%
Middle East	415	369	12	%	408	362	13	%
Asia Pacific	249	252	(1	%)	253	248	2	%
Outside North America	1,348	1,306	3	%	1,342	1,290	4	%
Worldwide	3,399	3,220	6	%	3,520	3,392	4	%

The rig count in North America increased 7% in the second quarter of 2014 compared to the same period a year ago as oil-directed rig counts increased 9%, while natural gas-directed rig counts remained flat. The oil-directed rig count increased 10% in the U.S. as activity increased in the Permian basin and South East Texas. Canada had a 5% increase due to a quicker recovery in the Canadian rig activity following the spring break up this year. This increase in oil directed rig counts in North America is driven predominately by an increase of investment in oil exploration and production as a result of the WTI oil price averaging 10% higher than the same period last year. The natural gas-directed rig count reflected an 11% decrease in the U.S. Although U.S. natural gas prices were above the average for the same period last year, overall prices remain below levels that are considered to be economic for new investments in many natural gas fields. However, this rig count decrease in the U.S. was fully offset by a 69% 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 second quarter of 2014 increased 3% compared to the same period a year ago. The rig count in Latin America decreased 5% primarily due to reduced offshore rig activity in Brazil, lower land and offshore activity in Mexico and a slight decline in rig activity in Venezuela. This was partially offset by increased land rig activity in Argentina. In Europe, the rig count in the North Sea increased 5% primarily due to increased offshore rig activity in the Netherlands while in Continental Europe, the rig count increased 15% primarily due to higher activity in Turkey and Romania. The rig count increased 5% in Africa primarily due to increased drilling activities in Kenya, Chad and offshore Angola, partially offset by decreased drilling in the north in Nigeria, Libya and Tunisia. In the Middle East, the rig count increased 12% primarily due to increased activity in Saudi Arabia, Oman and Iraq. In Asia Pacific, the rig count decreased 1% as a result of reduced drilling activity in Indonesia, Malaysia and New Zealand, partially offset by increased activity in India and offshore China.

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 due to the limited time between the end of the

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quarter and our publish date. Well count data may be subsequently revised as additional information is accumulated and analyzed.

During the second quarter of 2014, 9,394 wells were spud on land in the U.S. This compares to 9,011 wells spud in the second quarter of 2013, or an increase of 4%. For the six months ended June 30, 2014, 18,360 wells were spud on land in the U.S. This compares to 17,545 wells spud during the first six months of 2013, an increase of 5%. This increase is primarily associated with well count growth in the Permian and Eagle Ford basins.

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 June 30,				$ Change			% Change		Six Months Ended June 30,				$ Change			% Change
	2014		2013							2014		2013
Revenue:
North America	$	2,843	$	2,677	$	166		6	%	$	5,619	$	5,280	$	339		6	%
Latin America	544		557		(13		)	(2	%)	1,074		1,147		(73		)	(6	%)
Europe/Africa/Russia Caspian	1,066		966		100			10	%	2,062		1,820		242			13	%
Middle East/Asia Pacific	1,149		971		178			18	%	2,257		1,865		392			21	%
Industrial Services	333		316		17			5	%	654		605		49			8	%
Total	$	5,935	$	5,487	$	448		8	%	$	11,666	$	10,717	$	949		9	%

	Three Months Ended June 30,						$ Change			% Change		Six Months Ended June 30,						$ Change			% Change
	2014			2013								2014			2013
Profit Before Tax:
North America	$	340		$	211		$	129		61	%	$	598		$	446		$	152		34	%
Latin America	46			(18		)	64			N/M		101			31			70			226	%
Europe/Africa/Russia Caspian	178			151			27			18	%	320			244			76			31	%
Middle East/Asia Pacific	168			115			53			46	%	303			231			72			31	%
Industrial Services	34			39			(5		)	(13	%)	61			63			(2		)	(3	%)
Total Operations	766			498			268			54	%	1,383			1,015			368			36	%
Corporate and other	(73		)	(62		)	(11		)	18	%	(138		)	(124		)	(14		)	11	%
Interest expense, net	(59		)	(60		)	1			(2	%)	(116		)	(115		)	(1		)	1	%
Litigation settlements	(62		)	—			(62		)	—	%	(62		)	—			(62		)	—	%
Total	$	572		$	376		$	196		52	%	$	1,067		$	776		$	291		38	%

"N/M" represents not meaningful.

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Second Quarter of 2014 Compared to the Second Quarter of 2013

Revenue for the second quarter of 2014increased$448 million, or 8%, compared to the second quarter of 2013. International revenue increased 11% as a result of strong growth in MEAP and to a lesser extent EARC. North America revenue increased 6% due to activity growth in the U.S. onshore business primarily in the drilling services, drill bits, and artificial lift product lines, all of which achieved record revenue in the quarter.

Profit before tax for the second quarter of 2014increased$196 million, or 52%, compared to the second quarter of 2013. This improvement can be attributed primarily to revenue growth and favorable sales mix in North America, EARC, and MEAP, as well as improved operating efficiencies in the U.S. and Latin America. Profit for the second quarter was negatively impacted by a charge of $62 million related to certain litigation settlements for wage and hour lawsuits and a $12 million foreign exchange loss in Venezuela.

North America

North America revenue increased$166 million, or 6%, in the second quarter of 2014 compared to the second quarter of 2013, consistent with the 7% increase in the rig count. The increase in North America revenue is primarily attributed to the U.S., where our onshore business experienced significant activity growth with record revenue in our drilling services, drill bits and artificial lift product lines. Increased demand for newly introduced well construction and well production technologies across the region also contributed to the increase. Additionally, a quicker recovery in the Canadian rig activity following the spring break up favorably impacted our revenue in Canada. These increases were partially offset by reduced deepwater activity in the Gulf of Mexico for drilling and completion fluids.

North America profit before tax was $340 million in the second quarter of 2014, an increase of $129 million, or 61%, compared to the second quarter of 2013. The increase was primarily driven by the continued improvement in our onshore U.S. pressure pumping business, which resulted from higher asset utilization, better supply chain efficiencies, and reduced consumption of certain raw materials. North America profitability was also favorably impacted by higher margin on the increase in revenue in our drilling services, drill bits and artificial lift product lines.

Latin America

Latin America revenue decreased$13 million, or 2%, in the second quarter of 2014 compared to the second quarter of 2013, primarily due to reduced revenue in Venezuela, partially offset by increased revenue in Argentina and Mexico. Revenue in Venezuela declined across most product lines as contracts expired and were not renewed. These reductions were partially offset by increased activity and share gains in Argentina for our pressure pumping, drill bits and wireline product lines, and increased drilling activity in Mexico's marine region.

Latin America profit before tax was $46 million in the second quarter of 2014, an increase of $64 million compared to the second 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 with particular focus on Brazil. Profit before tax in the second quarter of 2013 had declined primarily due to Brazil where activity and market share had decreased as we transitioned to a new drilling services contract at lower prices. Increased activity in Argentina and Mexico also contributed to the profitability improvement in the second quarter of 2014.

Profitability was negatively impacted by a $12 million foreign exchange loss due to a currency devaluation in Venezuela. During the second quarter, we adopted the SICAD 2 exchange rate of approximately 50 Bolivares Fuertes (“BsF”) per U.S. Dollar ("USD"). Prior to this change, we were using the official exchange rate of 6.3 BsF per USD.

Europe/Africa/Russia Caspian

EARC revenue increased$100 million, or 10%, in the second quarter of 2014 compared to second quarter of 2013 due primarily to strong growth across Africa, as well as improvements in Russia. In Africa, revenue increases are a result of activity growth and share gains across all our product lines in both the onshore and offshore market, primarily in Central and West Africa. In Russia, strong growth was experienced in our drilling services and

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completion product lines as we expand our business in this region. Revenue growth in Continental Europe was driven by strong completion and production activity and in the United Kingdom revenue increased due to strong wireline services activity. These increases were partially offset by a decline in activity in Norway primarily for our drilling services and drilling and completion fluids products and services.

EARC profit before tax was $178 million, an increase of $27 million, or 18%, in the second quarter of 2014 compared to the second quarter of 2013. The improvement in profitability is due to our ability to maintain a fixed cost base with increased revenues, improved market conditions and improved sales mix throughout the segment with strong growth in wireline, completions and pressure pumping product lines.

Middle East/Asia Pacific

MEAP revenue increased$178 million, or 18%, in the second quarter of 2014 compared to the second quarter of 2013. The strong revenue increase in this segment was largely attributable to solid growth in Saudi Arabia, South East Asia, China and United Arab Emirates (“UAE”). In Saudi Arabia, revenue increases were primarily related to growth with our integrated operations contracts with strong demand for our drilling services and pressure pumping product lines as the rig count reached record levels. 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 both the UAE and China, activity growth was led by our drilling and completion services product lines.

MEAP profit before tax was $168 million, an increase of $53 million, or 46%, in the second quarter of 2014 compared to the second quarter of 2013. In addition to the increase in revenue, profit before tax was favorably impacted by strong incremental margins on increased revenue in our drilling services and wireline services product lines. Profitability was negatively impacted by third party costs associated with our integrated operations turnkey contracts in Iraq where we began to demobilize on one of our contracts.

Industrial Services

For Industrial Services, revenue increased$17 million and profit before tax decreased $5 million in the second quarter of 2014 compared to the second quarter of 2013. The increase in revenue was primarily driven by increased activity in our process and pipeline services business. The decrease in profit before tax was due to increased product costs.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Revenue for the six months ended June 30, 2014 increased $949 million, or 9%, compared to the six months ended June 30, 2013. Revenue increased in all segments except for Latin America which was impacted by reductions in both Venezuela and Brazil. The reduction in Brazil is attributed primarily to reduced drilling activity and pricing deterioration in the country. Revenue in Venezuela declined across most product lines as contracts expired and were not renewed.

Profit before tax for the six months ended June 30, 2014 increased $291 million, or 38%, compared to the six months ended June 30, 2013. North America profit increased $152 million, or 34%, as a result of efficiency gains in the pressure pumping product line, activity growth in U.S. onshore and increased demand for new innovative technology. The Latin America segment, despite lower revenue, experienced an increase in profit of $70 million, or 226%, due to cost reduction initiatives throughout the region and favorable geographic mix. The EARC segment experienced an increase in profit of $76 million, or 31%, due to increased revenues across almost all product lines, primarily in Africa and Russia Caspian. The MEAP segment experienced an increase in profit of $72 million, or 31%, as revenue increased across all product lines. MEAP profitability was negatively impacted by increased losses in Iraq.

Profit before tax for the six months ended June 30, 2014 was negatively impacted by a $12 million foreign exchange loss due to a currency devaluation in Venezuela; $29 million of severance charges in North America; and $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

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America - $13 million; Latin America - $3 million; Europe/Africa/Russia Caspian - $6 million; Middle East/Asia Pacific - $6 million; and Industrial Services - $1 million.

Profit before tax for the six months ended June 30, 2013 was negatively impacted by a $23 million foreign exchange loss due to a currency devaluation in Venezuela.

Costs and Expenses

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

	Three Months Ended June 30,								Six Months Ended June 30,
	2014				2013				2014				2013
	$		%		$		%		$		%		$		%
Revenue	$	5,935	100	%	$	5,487	100	%	$	11,666	100	%	$	10,717	100	%
Cost of revenue	4,745		80	%	4,591		84	%	9,465		81	%	8,917		83	%
Research and engineering	159		3	%	131		2	%	302		3	%	258		2	%
Marketing, general and administrative	338		6	%	329		6	%	654		6	%	651		6	%

Cost of Revenue

Cost of revenue as a percentage of revenue was 80% and 81% for the three and six months ended June 30, 2014, respectively, and 84% and 83% for the same periods a year ago. The improvement in cost of revenue as a percentage of revenue for the six months ended June 30, 2014 was due primarily to the continued improvement in our onshore U.S. pressure pumping business, which resulted in higher asset utilization and organizational efficiencies. In Latin America, margins improved due to cost reduction strategies implemented in the second half of 2013 throughout the region and favorable geographic mix. Margins also improved in Russia, Africa, Saudi Arabia and South East Asia. These improvements 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, both incurred in the first quarter of 2014.

Marketing, General and Administrative

Marketing, general and administrative ("MG&A") expenses increased 3% and were flat for the three and six months ended June 30, 2014, respectively, compared to the same periods a year ago. Included in MG&A expenses for the three and six months ended June 30, 2014, is a foreign exchange loss of $12 million in Venezuela due to our decision to adopt the SICAD 2 exchange rate of approximately 50 BsF per USD for purposes of remeasuring BsF denominated net monetary assets. We believe the SICAD 2 rate is the rate most representative of the economics in which we operate. Prior to this change, we were using the official exchange rate of 6.3 BsF per USD. In the first six months of 2013, we had foreign exchange losses of $23 million due to the currency devaluation in Venezuela that occurred in February 2013.

Litigation Settlements

During the second quarter of 2014, we recorded a charge of $62 million related to litigation settlements for wage and hour lawsuits. For further discussion, see Note 9. "Commitments and Contingencies - Litigation" in the Notes to Unaudited Consolidated Condensed Financial Statements in Item 1 herein.

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Income Taxes

Total income tax expense was $213 million and $372 million for the three and six months ended June 30, 2014, respectively. Our effective tax rate on income before income taxes for the three and six months ended June 30, 2014 was 37.2% and 34.9%, respectively. The tax rate for the three months ended June 30, 2014 is higher than the U.S. statutory income tax rate of 35% primarily due to geographical mix of earnings, losses in certain jurisdictions with no tax relief and 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 International Energy Agency (“IEA”), Organization of Petroleum Exporting Countries (“OPEC”), the Energy Information Administration (“EIA”), and the Organization for Economic Cooperation and Development (“OECD”). We acknowledge that there is a substantial amount of uncertainty regarding these forecasts, thus, while we have internal estimates regarding economic expansion, hydrocarbon demand and overall oilfield activity, we position ourselves to be flexible and responsive to a wide range of potential outcomes.

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 growth but also some embedded risks. A major driver to global growth has come from the advanced economies, although their recoveries remain uneven. In the U.S., the International Monetary Fund (“IMF”) forecasts a 2.8% growth in 2014, an increase over 2013, driven by continued strong private demand, and in particular, a recovering housing market. This is expected to continue with a 3% growth rate projected for 2015. In Europe, growth has turned positive but is expected to remain weak and fragile as high debt and fragmented financial markets hold back domestic demand. In addition, the lingering geopolitical risks around the Ukraine and the possibility of additional sanctions against Russia continue to bring uncertainty to this region. The growth in the emerging markets and developing economies, contributing more than two-thirds of global growth, is projected to increase from 4.7% in 2013 to 4.9% in 2014 and 5.3% in 2015. 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. The IMF estimates China’s economic growth will be even lower at 7.5% for 2014 and 7.3% for 2015. For India, economic growth is expected to strengthen to 5.4% in 2014 and 6.4% in 2015, assuming government efforts to revive investment growth succeed and export growth strengthens after recent rupee depreciation.

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• Demand for Hydrocarbons - In its June 2014 Oil Market Report, the IEA revised its global oil demand forecast marginally upward for 2014 to 92.8 million barrels per day (“bpd”), from the 92.7 million bpd projected in March. The 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 July 2014 Short-Term Energy Outlook, the EIA estimated that gas demand in the U.S. will see a 1.7% annual increase due to increased industrial demand for natural gas in the U.S. being only partially offset by declines in gas-fired power output and a decline in residential and commercial consumption. Overall, U.S. natural gas demand is expected to reach around 72.5 billion cubic feet per day (“bcfd”) in 2014.

• Oil Production - The IEA projects a growth in oil supply driven by non-OPEC countries with production expected 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 May 2014, the U.S. oil output averaged 8.4 million bpd, the highest average since 1988, U.S. total crude oil production, which averaged 7.4 million bpd in 2013, is expected to average 8.5 million bpd in 2014 and 9.3 million bpd in 2015. The 2015 forecast represents the highest annual average level of oil production since 1972. On the other hand, OPEC oil production has been decreasing primarily reflecting production declines in Iran, increased unplanned outages in Libya, Nigeria, and Iraq, and strong non-OPEC supply growth. EIA expects crude oil production to decline 0.1 million bpd in 2014 and an additional 0.1 million bpd in 2015. Militant unrest in Iraq continues to be a concern, with approximately 300 thousand bpd of northern Iraqi production already off the global market, and further supply outages possible if disruption impacts southern Iraq where most of the oil production resides.

• Natural Gas Production - Natural gas production continues to grow worldwide, including in North America even though 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 April 2014. In its July 2014 Short-Term Energy Outlook, the EIA published that total gas production in April reached a record high at 73.5 bcfd, according to EIA's most recent data, with the largest increases coming from areas in Texas. EIA expects natural gas marketed production to grow by an average rate of 4.1% in 2014 and 1.2% in 2015. 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 $99.42/Bbl and $107.26/Bbl, and Brent trading between $103.95/Bbl and $115.00/Bbl during the second 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 or geopolitical changes. EIA projects Brent crude oil prices to average $110/Bbl in 2014 and $105/Bbl in 2015.

• Natural Gas Prices - Henry Hub natural gas prices traded between $4.35/mmBtu and $4.83/mmBtu during the second quarter of 2014, as gas prices stabilized after the extremely cold and long winter season. EIA expects spot prices will remain near current levels until the start of the next winter heating season. According to the EIA, they projected in their July 2014 Short-Term Energy Outlook an average price of $4.77/mmBtu in 2014 and $4.50/mmBtu in 2015. 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 in 2014 compared to 2013, with the average annual rig count expected to grow 5%. 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 2 or 3 new deepwater exploration rigs in the remainder of the year. Completions and development

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activity in the Gulf of Mexico will also continue to grow in 2014, as we begin to see a greater proportion of deepwater rigs performing completion work. In Canada, overall rig activity in 2014 is expected to be up approximately 8% as compared to 2013, an increase from our earlier estimate of 5%.

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 an 8% increase in international rig activity relative to 2013, with improvements anticipated in all international regions. This is down slightly from our original estimate of 10% due to less onshore activity in Latin America, most notably in Mexico and Venezuela. Areas that are expected to see the largest increases include the Middle East, in particular Saudi Arabia, 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 South East 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 June 30, 2014, we had cash and cash equivalents of $1.16 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 June 30, 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 June 30, 2014, we had outstanding commercial paper of $453 million; therefore, the amount available for borrowing under the facility as of June 30, 2014 was $2.05 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 six months ended June 30, 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.

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Cash Flows

Cash flows provided by (used in) each type of activity were as follows for the six months ended June 30:

(In millions)	2014			2013
Operating activities	$	696		$	1,078
Investing activities	(686		)	(862		)
Financing activities	(245		)	(103		)

Operating Activities

Cash flows from operating activities provided $696 million in the six months ended June 30, 2014. Before changes in operating assets and liabilities, the major source of funds was net income, including noncontrolling interests, of $695 million. Net changes in operating assets and liabilities used cash of $842 million in the six months ended June 30, 2014. This was primarily the result of an increase in accounts receivable of $349 million due to increased activity and slower collections, an increase in inventory of $192 million due to increased activity, a decrease in net other operating items of $270 million primarily due to an increase in payments of accrued employee compensation, and a decrease in accounts payable of $31 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 $863 million in the six months ended June 30, 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 $203 million in the six months ended June 30, 2014, which related primarily to equipment that was lost-in-hole, and to a lesser extent, 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 $178 million in the six months ended June 30, 2014. Total debt outstanding at June 30, 2014 was $4.56 billion, an increase of $176 million compared to December 31, 2013. The total debt-to-capital (defined as total debt plus equity) ratio was 0.20 at June 30, 2014 and December 31, 2013. We paid dividends of $131 million in the six months ended June 30, 2014.

We received proceeds of $129 million in the six months ended June 30, 2014 from the issuance of common stock through the exercise of stock options and the employee stock purchase plan.

Our Board of Directors has previously authorized a program to repurchase our common stock from time to time. In the six months ended June 30, 2014, we repurchased 6.2 million shares of our common stock at an average price of $64.30 per share, for a total of $400 million. We had authorization remaining to repurchase approximately $1.25 billion in common stock at June 30, 2014. During the six months endedJune 30, 2013, we did not repurchase any shares of common stock.

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Available Credit Facility

We have a $2.50 billion committed revolving credit facility with commercial banks that matures in September 2016. At June 30, 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 June 30, 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 June 30, 2014, we had $453 million of commercial paper outstanding resulting in $2.05 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.

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 $1.9 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 and managed by us to match market demand and activity levels. In 2014, we also expect to make interest payments of between $240 million to $250 million, based on debt levels as of June 30, 2014. We anticipate making income tax payments of between $0.9 billion to $1.0 billion in 2014.

We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. In May 2014, the Board of Directors approved a $0.02 per share increase in the quarterly cash dividend to $0.17 per share of common stock for the August 2014 holders of record over the previous quarter's dividend of $0.15 per share of common stock. We anticipate paying dividends of between $277 million and $281 million in 2014; however, the Board of Directors can change the dividend policy at any time.

During the six months ended June 30, 2014, we contributed approximately $234 million to our defined benefit, defined contribution and other postretirement plans. We expect to make additional contributions in the range of $140 million to $170 million to these plans for the remainder of 2014.

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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 six months ended June 30, 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.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this Quarterly Report, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act of 1934, as amended (the “Exchange Act”). This evaluation was carried out under the supervision and with the participation of our management, including our principal executive officer and principal financial officer. Based on this evaluation, these officers have concluded that, as of June 30, 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 June 30, 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 June 30, 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)
April 1-30, 2014	193	$	70.38	—
May 1-31, 2014	2,059,611	69.83		2,009,814
June 1-30, 2014	843,777	70.73		843,777
Total	2,903,581	$	70.09	2,853,591	$	1,249,826,401

⁽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 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 June 30, 2014, we repurchased 2.9 million shares of our common stock at an average price of $70.09 per share (including commissions), for a total of $200 million. We had authorization remaining to repurchase up to a total of approximately $1.25 billion of our common stock as of June 30, 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

On July 14, 2014, the Compensation Committee of the Board of Directors of the Company approved modifications to the Company's various forms of award agreements for grants under the Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan and the Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan. Each form of the new award agreements is consistent with the terms of the applicable plan and past award practices and has been amended to include technical revisions, including a removal of contingency language related to stockholder approval of increases in dedicated shares under the plans (which approval was obtained on April 24, 2014). Copies of the new forms of award agreements are attached as Exhibits 10.3, 10.4, 10.5, 10.6, 10.7, 10.8, 10.9 and 10.10, respectively, to this Quarterly Report on Form 10-Q and are incorporated herein by reference.

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ITEM 6. EXHIBITS

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

3.1	Restated Bylaws of Baker Hughes Incorporated effective as of June 5, 2014 (filed as Exhibit 3.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on June 10, 2014).
10.1+	The Amended and Restated Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan effective April 24, 2014 (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on April 29, 2014).
10.2+	The Amended and Restated Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan effective April 24, 2014 (filed as Exhibit 10.2 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on April 29, 2014).
10.3 +*	Form of Baker Hughes Incorporated Performance Unit Award Agreement and Terms and Conditions payable in cash for certain officers pursuant to the Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan.
10.4 +*	Form of Baker Hughes Incorporated Performance Unit Award Agreement and Terms and Conditions payable in shares for certain officers pursuant to the Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan.
10.5 +*	Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and Conditions for officers pursuant to the Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan.
10.6 +*	Form of Baker Hughes Incorporated Nonqualified Stock Option Award Agreement and Terms and Conditions for officers pursuant to the Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan.
10.7 +*	Form of Baker Hughes Incorporated Incentive Stock Option Award Agreement and Terms and Conditions for officers pursuant to the Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan.
10.8 +*	Form of Baker Hughes Incorporated Performance Unit Award Agreement and Terms and Conditions payable in cash for certain employees pursuant to the Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan.
10.9 +*	Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and Conditions for employees pursuant to the Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan.
10.10 +*	Form of Baker Hughes Incorporated Nonqualified Stock Option Award Agreement and Terms and Conditions for employees pursuant to the Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan.
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:	July 22, 2014	By:	/s/ PETER A. RAGAUSS
		Peter A. Ragauss
		Senior Vice President and Chief Financial Officer
Date:	July 22, 2014	By:	/s/ ALAN J. KEIFER
		Alan J. Keifer
		Vice President and Controller

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