2014.09.30 10-Q

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).



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions, except per share amounts)	2014			2013			2014			2013
Revenue:
Sales	$	2,013		$	1,936		$	5,845		$	5,554
Services	4,237			3,851			12,071			10,950
Total revenue	6,250			5,787			17,916			16,504
Costs and expenses:
Cost of sales	1,620			1,490			4,651			4,341
Cost of services	3,487			3,260			9,921			9,326
Research and engineering	159			142			461			400
Marketing, general and administrative	323			319			977			970
Litigation settlements	—			—			62			—
Total costs and expenses	5,589			5,211			16,072			15,037
Operating income	661			576			1,844			1,467
Interest expense, net	(59		)	(58		)	(175		)	(173		)
Income before income taxes	602			518			1,669			1,294
Income taxes	(233		)	(178		)	(605		)	(441		)
Net income	369			340			1,064			853
Net loss (income) attributable to noncontrolling interests	6			1			(8		)	(5		)
Net income attributable to Baker Hughes	$	375		$	341		$	1,056		$	848

Basic earnings per share attributable to Baker Hughes	$	0.86		$	0.77		$	2.42		$	1.91

Diluted earnings per share attributable to Baker Hughes	$	0.86		$	0.77		$	2.40		$	1.91

Cash dividends per share	$	0.17		$	0.15		$	0.47		$	0.45



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2014			2013			2014			2013
Net income	$	369		$	340		$	1,064		$	853
Other comprehensive (loss) income:
Foreign currency translation adjustments during the period	(111		)	60			(108		)	(50		)
Pension and other postretirement benefits, net of tax	4			(4		)	(4		)	9
Hedge transactions, net of tax	—			2			—			(1		)
Other comprehensive (loss) income	(107		)	58			(112		)	(42		)
Comprehensive income	262			398			952			811
Comprehensive loss (income) attributable to noncontrolling interests	6			1			(8		)	(5		)
Comprehensive income attributable to Baker Hughes	$	268		$	399		$	944		$	806



(In millions)	September 30, 2014			December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	1,209		$	1,399
Accounts receivable - less allowance for doubtful accounts (2014 - $247; 2013 - $238)	5,539			5,138
Inventories, net	4,150			3,884
Deferred income taxes	426			380
Other current assets	487			494
Total current assets	11,811			11,295
Property, plant and equipment - less accumulated depreciation (2014 - $8,025; 2013 - $7,219)	9,081			9,076
Goodwill	6,074			5,966
Intangible assets, net	857			883
Other assets	819			714
Total assets	$	28,642		$	27,934
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	2,745		$	2,574
Short-term debt and current portion of long-term debt	519			499
Accrued employee compensation	777			778
Income taxes payable	368			213
Other accrued liabilities	553			514
Total current liabilities	4,962			4,578
Long-term debt	3,894			3,882
Deferred income taxes and other tax liabilities	742			821
Liabilities for pensions and other postretirement benefits	584			583
Other liabilities	176			158
Commitments and contingencies
Equity:
Common stock	433			438
Capital in excess of par value	6,977			7,341
Retained earnings	11,289			10,438
Accumulated other comprehensive loss	(616		)	(504		)
Baker Hughes stockholders’ equity	18,083			17,713
Noncontrolling interests	201			199
Total equity	18,284			17,912
Total liabilities and equity	$	28,642		$	27,934



	Baker Hughes Stockholders' Equity
(In millions, except per share amounts)	Common Stock			Capital in Excess of Par Value			Retained Earnings			Accumulated Other Comprehensive Loss			Non-controlling Interests			Total Equity
Balance at December 31, 2013	$	438		$	7,341		$	10,438		$	(504	)	$	199		$	17,912
Comprehensive income:
Net income							1,056						8			1,064
Other comprehensive loss										(112		)				(112		)
Activity related to stock plans	4			134												138
Repurchase and retirement of common stock	(9		)	(591		)										(600		)
Stock-based compensation				93												93
Cash dividends ($0.47 per share)							(205		)							(205		)
Net activity related to noncontrolling interests													(6		)	(6		)
Balance at September 30, 2014	$	433		$	6,977		$	11,289		$	(616	)	$	201		$	18,284



	Baker Hughes Stockholders' Equity
(In millions, except per share amounts)	Common Stock		Capital in Excess of Par Value		Retained Earnings			Accumulated Other Comprehensive Loss			Non-controlling Interests			Total Equity
Balance at December 31, 2012	$	441	$	7,495	$	9,609		$	(476	)	$	199		$	17,268
Comprehensive income:
Net income					848						5			853
Other comprehensive loss								(42		)				(42		)
Activity related to stock plans	2		26											28
Stock-based compensation			93											93
Cash dividends ($0.45 per share)					(200		)							(200		)
Net activity related to noncontrolling interests											(7		)	(7		)
Balance at September 30, 2013	$	443	$	7,614	$	10,257		$	(518	)	$	197		$	17,993



	Nine Months Ended September 30,
(In millions)	2014			2013
Cash flows from operating activities:
Net income	$	1,064		$	853
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	1,346			1,262
Other noncash items	(102		)	(53		)
Changes in operating assets and liabilities:
Accounts receivable	(572		)	(651		)
Inventories	(280		)	(191		)
Accounts payable	186			749
Other operating items, net	112			189
Net cash flows provided by operating activities	1,754			2,158
Cash flows from investing activities:
Expenditures for capital assets	(1,288		)	(1,552		)
Proceeds from disposal of assets	295			276
Acquisition of businesses, net of cash acquired	(313		)	(22		)
Other investing items, net	—			(6		)
Net cash flows used in investing activities	(1,306		)	(1,304		)
Cash flows from financing activities:
Net proceeds (repayments) of commercial paper borrowings and other debt with original maturity of three months or less	89			(391		)
Repayments of short-term debt with original maturity greater than three months	(182		)	(119		)
Proceeds from short-term debt with greater than three months original maturity	144			178
Repurchase of common stock	(600		)	—
Proceeds from issuance of common stock	147			50
Dividends paid	(205		)	(200		)
Other financing items, net	(27		)	(17		)
Net cash flows used in financing activities	(634		)	(499		)
Effect of foreign exchange rate changes on cash and cash equivalents	(4		)	(2		)
(Decrease) increase in cash and cash equivalents	(190		)	353
Cash and cash equivalents, beginning of period	1,399			1,015
Cash and cash equivalents, end of period	$	1,209		$	1,368
Supplemental cash flows disclosures:
Income taxes paid, net of refunds	$	571		$	498
Interest paid	$	199		$	194
Supplemental disclosure of noncash investing activities:
Capital expenditures included in accounts payable	$	123		$	99

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.

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. 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.

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.

On September 2, 2014, we completed the acquisition of the pipeline and specialty services business of Weatherford International Ltd. ("PSS") for total cash consideration of $246 million, subject to post-closing working capital adjustments. PSS will provide an expanded range of pre-commissioning, deepwater and in-line inspection services worldwide and will be included in our Industrial Services segment. The transaction has been accounted for using the acquisition method of accounting and, accordingly, assets acquired and liabilities assumed were recorded at their preliminary fair values as of the acquisition date subject to adjustment upon completion of the final fair value estimates. As a result of the acquisition, we recorded approximately $60 million of goodwill and approximately $40

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

The performance of our operating segments is evaluated based on profit before tax, which is defined as income before income taxes and before the following: net interest expense, corporate expenses and certain gains and losses not allocated to the operating segments. During the third quarter of 2014, profit before tax for the Europe/Africa/Russia Caspian ("EARC") segment was impacted by a charge of $58 million associated with the restructuring of our North Africa business and impairment of certain assets, resulting primarily from the recent disruption of our operations in Libya. Concurrent with the restructuring of this business, certain North African entities previously reported in our Middle East/Asia Pacific segment were realigned and are now reported within our EARC segment to reflect how we manage the business. Accordingly, all prior segment disclosures for revenue and profit (loss) before taxes for these two segments have been reclassified to reflect this realignment. There were no material changes in segment revenue, profit (loss) before taxes or assets as a result of this change.



	Three Months Ended					Three Months Ended
	September 30, 2014					September 30, 2013
Segments	Revenue		Profit (Loss) Before Taxes			Revenue		Profit (Loss) Before Taxes
North America	$	3,155	$	380		$	2,854	$	295
Latin America	571		71			557		(23		)
Europe/Africa/Russia Caspian	1,114		91			1,036		177
Middle East/Asia Pacific	1,077		155			1,012		149
Industrial Services	333		35			328		38
Total Operations	6,250		732			5,787		636
Corporate and other	—		(71		)	—		(60		)
Interest expense, net	—		(59		)	—		(58		)
Total	$	6,250	$	602		$	5,787	$	518



	Nine Months Ended					Nine Months Ended
	September 30, 2014					September 30, 2013
Segments	Revenue		Profit (Loss) Before Taxes			Revenue		Profit (Loss) Before Taxes
North America	$	8,774	$	978		$	8,134	$	741
Latin America	1,645		172			1,704		8
Europe/Africa/Russia Caspian	3,269		421			2,948		430
Middle East/Asia Pacific	3,241		448			2,785		371
Industrial Services	987		96			933		101
Total Operations	17,916		2,115			16,504		1,651
Corporate and other	—		(209		)	—		(184		)
Interest expense, net	—		(175		)	—		(173		)
Litigation settlements	—		(62		)	—		—
Total	$	17,916	$	1,669		$	16,504	$	1,294

Total income tax expense was $233 million and $605 million for the three and nine months ended September 30, 2014, respectively. Our effective tax rate on income before income taxes for the three and nine months ended September 30, 2014 was 38.7% and 36.2%, respectively. Our effective tax rates are higher than the U.S. statutory income tax rate of 35% primarily due to the third quarter 2014 charge of $58 million associated with the restructuring of our North Africa business and other losses where there is no tax benefit.

In early 2014, the Venezuelan government modified the currency exchange system by establishing two new exchange mechanisms, SICAD 1 and SICAD2, where participation in the auction process of each mechanism is controlled by the Venezuelan government depending on the economic sector within which a company operates. These mechanisms are in addition to the existing official exchange rate. There could be additional changes to exchange mechanisms in the future.

We have not been eligible to apply for exchange at the official rate nor have we been allowed to participate in the SICAD 1 auctions. We 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 was and continues to be 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 devaluation in the currency 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.



	Three Months Ended September 30,		Nine Months Ended September 30,
	2014	2013	2014	2013
Weighted average common shares outstanding for basic EPS	436	444	437	443
Adjustment for effect of dilutive securities - stock plans	2	1	3	1
Weighted average common shares outstanding for diluted EPS	438	445	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	5	2	8



	September 30, 2014						December 31, 2013
	Gross Carrying Amount		Less: Accumulated Amortization		Net		Gross Carrying Amount		Less: Accumulated Amortization		Net
Technology	$	850	$	378	$	472	$	814	$	337	$	477
Customer relationships	509		187		322		494		157		337
Trade names	122		90		32		120		82		38
Other ⁽¹⁾	43		12		31		43		12		31
Total intangible assets	$	1,524	$	667	$	857	$	1,471	$	588	$	883

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.



	U.S. Pension Benefits						Non-U.S. Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013			2014			2013
Service cost	$	17		$	16		$	3		$	4		$	1		$	1
Interest cost	7			5			8			8			1			1
Expected return on plan assets	(11		)	(9		)	(9		)	(9		)	—			—
Amortization of prior service credit	—			—			—			—			(2		)	(2		)
Amortization of net actuarial loss	2			3			1			2			1			1
Net periodic cost	$	15		$	15		$	3		$	5		$	1		$	1



	U.S. Pension Benefits						Non-U.S. Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013			2014			2013
Service cost	$	52		$	48		$	10		$	12		$	4		$	5
Interest cost	21			16			26			24			4			3
Expected return on plan assets	(33		)	(29		)	(29		)	(29		)	—			—
Amortization of prior service credit	—			—			—			—			(5		)	(6		)
Amortization of net actuarial loss	6			10			3			6			2			3
Other	—			—			—			—			(3		)	—
Net periodic cost	$	46		$	45		$	10		$	13		$	2		$	5

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

We insure against risks arising from our business to the extent deemed prudent by our management and to the extent insurance is available, but no assurance can be given that the nature and amount of that insurance will be sufficient to fully indemnify us against liabilities arising out of pending or future legal proceedings or other claims. Most of our insurance policies contain deductibles or self-insured retentions in amounts we deem prudent and for which we are responsible for payment. In determining the amount of self-insurance, it is our policy to self-insure those losses that are predictable, measurable and recurring in nature, such as claims for automobile liability, general liability and workers compensation.

During the third quarter of 2014, we investigated customer notifications related to a possible equipment failure in a natural gas storage system in the EARC region, which includes certain of our products. We are currently investigating the cause of the possible failure and, if necessary, possible repair and replacement options for our products. Similar products were utilized in other natural gas storage systems for this and other customers. At this time, we are not able to predict whether our products will need to be repaired or replaced and are not able to reasonably estimate the impact, if any, such repairs or replacements or other damages would have on our financial position, results of operations or cash flows.

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 (“Ciamillo”). We have accrued an estimate of potential damages for the Ciamillo lawsuit, the amount of which was not material to our financial position, results of operations or cash flows. 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"). 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. On October 21, 2013, a collective action lawsuit alleging that we

failed to pay a 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 (“Zamora”). In October of 2014, the parties agreed to settle the Zamora lawsuit, subject to final court approval, for an amount that was not material to our financial position, results of operations or cash flows.

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.

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 $1.6 billion at September 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.



	Pensions and Other Postretirement Benefits				Foreign Currency Translation Adjustments				Accumulated Other Comprehensive Loss
Balance at December 31, 2013		$	(217	)		$	(287	)		$	(504	)
Other comprehensive loss before reclassifications		(5		)		(108		)		(113		)
Amounts reclassified from accumulated other comprehensive loss		3				—				3
Deferred taxes		(2		)		—				(2		)
Balance at September 30, 2014		$	(221	)		$	(395	)		$	(616	)



	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 before reclassifications		(1		)		—				(50		)		(51		)
Amounts reclassified from accumulated other comprehensive loss		—				13				—				13
Deferred taxes		—				(4		)		—				(4		)
Balance at September 30, 2013		$	(1	)		$	(241	)		$	(276	)		$	(518	)

The amounts reclassified from accumulated other comprehensive loss during the nine months ended September 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 10. 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.

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.

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 third quarter of 2014, we generated revenue of $6.25 billion, an increase of $463 million, or 8%, compared to the third quarter of 2013, and an increase of $315 million, or 5%, compared to the second quarter of 2014, or sequentially. Net income attributable to Baker Hughes was $375 million for the third quarter of 2014 compared to $341 million for the third quarter of 2013, and $353 million for the second quarter of 2014.

North America oilfield revenue for the third quarter of 2014 was $3.16 billion, an increase of $301 million, or 11%, compared to the third quarter of 2013, and an increase of $312 million, or 11%, compared to the second quarter of 2014. North America oilfield profit before tax for the third quarter of 2014 was $380 million compared to $295 million for the third quarter of 2013, and $340 million for the second quarter of 2014. Revenue increased in the third quarter of 2014, compared to the same quarter a year ago, as a result of activity growth across most product lines, with particularly strong results coming from the pressure pumping product line, and increased share in our artificial lift product line as a result of recent technology introductions. Profitability in North America increased $85 million, or 29%, year over year primarily due to operational leverage from activity growth, higher margins from the increase in revenue from recently introduced well construction and production technologies, and continued improvement of our pressure pumping business. This increase more than offset the deepwater activity delays in the Gulf of Mexico caused by unusually strong ocean currents, which caused several key customers to suspend operations. Sequentially, our North America oilfield revenue and profit improved due to increased activity in our U.S. onshore business and the seasonal rebound in Canada, which more than offset the decline in the Gulf of Mexico.

Oilfield revenue outside of North America for the third quarter of 2014 was $2.76 billion, an increase of $157 million, or 6%, compared to the third quarter of 2013, and basically unchanged, sequentially. Oilfield profitability outside of North America for the third quarter of 2014 was $317 million compared to $303 million for the third quarter of 2013, and $392 million for the second quarter of 2014. The increase in revenue in the third quarter of 2014 compared to the same quarter a year ago was driven by growth in both the Europe/Africa/Russia Caspian ("EARC") and Middle East/Asia Pacific ("MEAP") segments, predominately in Saudi Arabia, United Kingdom and Angola. In Latin America, revenue growth from Mexico and Argentina was partially offset by a decline in Venezuela as a result of lower revenue from the devaluation that occurred in the second quarter of 2014 and lower market share. The increase in profitability outside of North America compared to the third quarter of 2013, can be largely attributed to

Latin America due to our continued focus on operational efficiencies and favorable geographic mix. Profitability in Latin America in the third quarter of 2013 was impacted by a severance charge of $19 million. Profitability in EARC in the third quarter of 2014 was impacted negatively by several items including a charge of $58 million associated with the restructuring of our operations in North Africa and the impairment of certain assets, resulting primarily from recent disruptions in Libya, and foreign exchange losses mainly as a result of the sharp decline in value of the Russian Ruble. Sequentially, oilfield revenue outside of North America remained unchanged. Despite flat revenue sequentially, our profitability declined outside of North America primarily due to costs associated with the restructuring of our operations in North Africa, foreign exchange losses in EARC and unfavorable product mix in Asia. Profitability in the second quarter of 2014 was impacted by a foreign exchange loss of $12 million related to the Venezuela currency devaluation.

In North America, active rig counts increased 8% in the third quarter of 2014 compared to the same period a year ago. In the U.S., the rig count increased 8% as higher than expected commodity prices and increased drilling efficiencies have contributed to increased customer spending in highly productive oil basins, such as the Permian and Eagle Ford. In Canada, recovering North America gas prices have improved the economics of drilling in Canada, and largely contributed to the 10% increase in total Canadian rig activity in the third 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, especially in the deepwater market and state owned oilfields. On average, Brent oil prices were down 7% in the third quarter of 2014 compared to the same period a year ago as global oil supplies have remained high despite conflicts in the Middle East, Ukraine and Libya, and economic sanctions in Russia. Despite lower oil prices and conflicts around the world, the international rig count grew by 5% in the third quarter of 2014 compared to the same quarter in 2013, with the largest drilling activity growth seen in Saudi Arabia, Argentina, Oman, offshore China, and Turkey.

weakening oil demand growth and plentiful supply continues to be apparent as Libyan oil exports reached the highest level in over a year. In its September 2014 Oil Market Report, the International Energy Agency has trimmed the forecast of oil demand growth for 2014 by 150 thousand bpd to 0.9 million barrels per day ("bpd"), taking projected demand for the year to 92.6 million bpd from the 92.8 million bpd forecast published in June 2014. Curbed outlooks for China and Europe are the key downside contributors. During the quarter, Brent oil prices ranged from a high of $111.32/Bbl at the beginning of July 2014 to a twenty seven month low of $93.17/Bbl at the end of September 2014.

WTI oil prices averaged $97.70/Bbl in the third quarter of 2014. Overall, prices were extremely volatile ranging from a high of $107.62/Bbl in July 2014 when crude oil inventory levels at the Cushing, Oklahoma storage hub, the futures market's delivery point for WTI, fell below 18 million barrels, the lowest level since October 2008; to a low of $91.16/Bbl at the end of September 2014 as crude oil inventories then built for four consecutive weeks to reach 20.7 million barrels at the end of August. In its October 2014 Short-Term Energy Outlook, the Energy Information Administration ("EIA") has reported that total U.S. crude oil production averaged an estimated 8.7 million bpd in September, the highest monthly production since July 1986.

In North America, natural gas prices, as measured by the Henry Hub Natural Gas Spot Price, averaged $3.94/mmBtu in the third quarter of 2014 as bigger-than-normal storage builds were offset by hot weather and strong air conditioning demand in key consuming regions. Overall for the quarter, prices ranged from a high of $4.43/mmBtu in early July 2014 to a low of $3.74/mmBtu in late July 2014. Henry Hub Natural Gas Spot prices closed the quarter at $4.14/mmBtu as a result of expectations for cooler weather and rising heating demand, which could potentially reduce storage injections needed for the upcoming winter. Despite the lower stocks at the start of this winter's heating season, EIA in the October 2014 Short-Term Energy Outlook, expects the Henry Hub natural gas spot price to be lower this winter compared with last winter. This forecast reflects both lower expected heating demand and significantly higher natural gas production this winter. According to the U.S. Department of Energy, working natural gas in storage at the end of the third quarter of 2014 was 3,205 billion cubic feet ("Bcf"), which was 10%, or 359 Bcf, below the corresponding period in 2013.

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.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014	2013	% Change		2014	2013	% Change
U.S. - land and inland waters	1,842	1,709	8	%	1,787	1,708	5	%
U.S. - offshore	61	61	—	%	58	55	5	%
Canada	386	350	10	%	370	344	8	%
North America	2,289	2,120	8	%	2,215	2,107	5	%
Latin America	406	407	—	%	403	419	(4	%)
North Sea	35	43	(19	%)	39	44	(11	%)
Continental Europe	113	97	16	%	105	91	15	%
Africa	126	124	2	%	134	122	10	%
Middle East	411	373	10	%	409	366	12	%
Asia Pacific	256	241	6	%	254	246	3	%
Outside North America	1,347	1,285	5	%	1,344	1,288	4	%
Worldwide	3,636	3,405	7	%	3,559	3,395	5	%

The rig count in North America increased 8% in the third quarter of 2014 compared to the same period a year ago as oil-directed rig counts increased 12%, while natural gas-directed rig counts declined 3%. The oil-directed rig count increased 14% in the U.S. as activity increased in highly productive shale resources, such as the Permian basin, while operators strive to benefit from higher than expected cash flows and increased drilling efficiencies. On the other hand, the Canada oil-directed rig count reflects a 2% decrease as many operators curtailed their heavy oil-directed drilling plans in the second half of 2013 and into 2014 as a result of high oil differentials compared to the WTI. The natural gas-directed rig count reflects a 15% decrease in the U.S compared to the same period last year. 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. The decline in the rig count in the U.S. was partially offset by a 33% increase in the natural gas-directed drilling activity 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 third quarter of 2014 increased 5% compared to the same period a year ago. The rig count in Latin America remained flat as reduced offshore rig activity in Brazil and lower land activity in Mexico, was offset by increased onshore drilling activity in Argentina. In Europe, the rig count in the North Sea decreased 19% primarily due to reduced offshore drilling activity in Norway; while in Continental Europe, the rig count increased 16% primarily due to higher activity in Turkey and Romania. The rig count increased 2% in Africa primarily due to increased drilling activities in offshore Angola and land activity in Chad and Kenya, partially offset by decreased drilling in Libya as a result of the industry-wide shut down in the current quarter. In the Middle East, the rig count increased 10% primarily due to increased activity in Saudi Arabia, Oman and Kuwait. This was partially offset by decreased activity in Iraq, predominately in the north, where militant activity continues to have an impact on drilling activity. In Asia Pacific, the rig count increased 6% as a result of increased drilling activity in offshore China, India and Australia, partially offset by decreased activity in Indonesia and Malaysia.

For the nine months ended September 30, 2014, the North America rig count increased 5% compared to the same period last year. This increase was driven by a 5% increase in the U.S. rig count, predominantly in the Permian and DJ Niobrara basins, and by an 8% increase in drilling activity in Canada. Outside of North America, for the same period, the rig count increased 4% compared to the prior year with drilling activity growth in all geographic regions, except for Latin America. The increase in drilling activity in Argentina, Saudi Arabia, Oman, Turkey, Kenya and offshore China were partially offset by a decline in drilling activity in Mexico and Brazil.

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

During the third quarter of 2014, 9,566 wells were spud on land in the U.S. This compares to 9,075 wells spud in the third quarter of 2013, or an increase of 5%. For the nine months ended September 30, 2014, 27,988 wells were spud on land in the U.S. This compares to 26,620 wells spud during the first nine months of 2013, an increase of 5%. This increase is primarily associated with well count growth in the Permian and Eagle Ford basins.

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 for each of our five operating segments is provided below. 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. During the third quarter of 2014, we restructured our operations in North Africa primarily due to the recent disruptions in Libya resulting from the political instability. Concurrent with the restructuring of this business, certain entities in North Africa previously reported in our MEAP segment were realigned and are now reported within our EARC segment to reflect how we manage the business. Accordingly, all prior segment disclosures for revenue and profit (loss) before taxes for these two segments have been reclassified to reflect this realignment. There were no material changes in segment revenue or profit (loss) before taxes as a result of this change.



	Three Months Ended September 30,				$ Change		% Change		Nine Months Ended September 30,				$ Change			% Change
	2014		2013		$ Change		% Change		2014		2013		$ Change			% Change
Revenue:
North America	$	3,155	$	2,854	$	301	11	%	$	8,774	$	8,134	$	640		8	%
Latin America	571		557		14		3	%	1,645		1,704		(59		)	(3	%)
Europe/Africa/Russia Caspian	1,114		1,036		78		8	%	3,269		2,948		321			11	%
Middle East/Asia Pacific	1,077		1,012		65		6	%	3,241		2,785		456			16	%
Industrial Services	333		328		5		2	%	987		933		54			6	%
Total	$	6,250	$	5,787	$	463	8	%	$	17,916	$	16,504	$	1,412		9	%



	Three Months Ended September 30,						$ Change			% Change		Nine Months Ended September 30,						$ Change			% Change
	2014			2013			$ Change			% Change		2014			2013			$ Change			% Change
Profit (Loss) Before Taxes:
North America	$	380		$	295		$	85		29	%	$	978		$	741		$	237		32	%
Latin America	71			(23		)	94			N/M		172			8			164			2,050	%
Europe/Africa/Russia Caspian	91			177			(86		)	(49	%)	421			430			(9		)	(2	%)
Middle East/Asia Pacific	155			149			6			4	%	448			371			77			21	%
Industrial Services	35			38			(3		)	(8	%)	96			101			(5		)	(5	%)
Total Operations	732			636			96			15	%	2,115			1,651			464			28	%
Corporate and other	(71		)	(60		)	(11		)	18	%	(209		)	(184		)	(25		)	14	%
Interest expense, net	(59		)	(58		)	(1		)	2	%	(175		)	(173		)	(2		)	1	%
Litigation settlements	—			—			—			—	%	(62		)	—			(62		)	—	%
Total	$	602		$	518		$	84		16	%	$	1,669		$	1,294		$	375		29	%

Revenue for the third quarter of 2014 increased $463 million, or 8%, compared to the third quarter of 2013. North America revenue increased 11% due primarily to growth in the U.S. onshore business, mainly in the pressure pumping and artificial lift product lines. International revenue increased 6% as a result of growth in MEAP and EARC, and to a lesser extent in Latin America.

Profit before tax for the third quarter of 2014 increased $84 million, or 16%, compared to the third quarter of 2013. This improvement can be attributed primarily to operational leverage from revenue growth and improved operating efficiencies in the U.S. and Latin America. Profitability for the third quarter of 2014 was negatively impacted by a charge of $58 million related to the restructuring of our operations in North Africa and impairment of certain assets resulting primarily from recent disruptions in Libya. Profit before tax for the third quarter of 2013 includes a severance related charge of $19 million in Latin America.

North America revenue increased $301 million, or 11%, in the third quarter of 2014 compared to the third quarter of 2013, and above the 8% increase in the rig count. The increase in North America revenue is primarily attributed to the U.S., where our onshore business experienced significant growth across most product lines, with particularly strong growth coming from the pressure pumping and artificial lift product lines. This growth is primarily a result of increased service intensity, with more horizontal drilling, longer laterals, more stages per well and increased proppant per stage, as customers look for ways to optimize production. Stronger demand for newly introduced well construction and well production technologies across the region also contributed to the increase. The activity increase for our U.S. onshore business was partially offset by deepwater rig activity delays in the Gulf of Mexico as a result of stronger than usual ocean currents which caused several key customers to suspend operations.

North America profit before tax was $380 million in the third quarter of 2014, an increase of $85 million, or 29%, compared to the third 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. These increases were partially offset by lower profit in the Gulf of Mexico, as high margin revenue was delayed as a result of strong ocean currents.

Latin America revenue increased $14 million, or 3%, in the third quarter of 2014 compared to the third quarter of 2013, primarily due to increased activity and share gains in Argentina, mainly in pressure pumping, as unconventional activity continues to grow, and in offshore drilling in Mexico's marine region. These increases in revenue are partially offset by a decline in revenue in Venezuela as a result of lower revenue from the currency devaluation that occurred in the second quarter of 2014 and lower market share.

Latin America profit before tax was $71 million in the third quarter of 2014, an increase of $94 million compared to the third quarter of 2013. Incremental profitability can be primarily attributed to cost reduction strategies implemented throughout the region in the second half of 2013 with particular focus on Brazil. These actions resulted in a charge for severance of $19 million in the third quarter of 2013. Increased activity in Argentina and Mexico, and reduced losses in Venezuela, also contributed to the profitability improvement in the third quarter of 2014.

EARC revenue increased $78 million, or 8%, in the third quarter of 2014 compared to the third quarter of 2013 due primarily to strong growth in the United Kingdom, Continental Europe, Angola and East and Central Africa. Revenue growth in the United Kingdom was driven by increased drilling and evaluation activity, and in Continental Europe revenue increased as a result of higher activity across our drilling and completion services product lines. In Angola and East Africa, revenue increases are a result of activity growth and share gains across most of our product lines in both the onshore and offshore market. These increases were partially offset by a decline in activity in North Africa as a result of the industry-wide disruptions in Libya during the quarter which resulted from the political instability in the country. In response, we are consolidating several operations and restructuring our geomarket to streamline our business and improve efficiencies. Revenue in the Russia Caspian region was flat when compared to the third quarter of 2013.

EARC profit before tax was $91 million, a decrease of $86 million, or 49%, in the third quarter of 2014 compared to the third quarter of 2013. The decrease in profitability for the quarter is primarily related to a charge of $58 million associated with the restructuring of our operations in North Africa and impairment of certain assets, mainly due to the recent disruption in our operations in Libya. The charge includes reserves for doubtful accounts, and the impairment of inventory, property and equipment, and certain other assets, along with severance costs. In addition, we incurred foreign exchange losses in the quarter as a result of the devaluation of several currencies including the Russian Ruble, which declined 15% in value during the third quarter of 2014.

MEAP revenue increased $65 million, or 6%, in the third quarter of 2014 compared to the third quarter of 2013. The revenue increase in this segment was largely attributable to solid growth in Saudi Arabia, India and United Arab Emirates (“UAE”). In Saudi Arabia, revenue increases were primarily related to growth in our integrated operations contracts with strong demand for our drilling services and completion services product lines as the average rig count reached another record this quarter and is up 33% compared to the prior year. In India and UAE, activity growth was led by our drilling services and pressure pumping product lines.

MEAP profit before tax was $155 million, an increase of $6 million, or 4%, in the third quarter of 2014 compared to the third quarter of 2013. Improved profitability in Saudi Arabia was partially offset by an unfavorable product mix in Australia and South East Asia. Profitability for the third quarter of 2014 was negatively impacted by demobilization costs associated with exiting one of our integrated operations turnkey contracts in Iraq. The demobilization was completed during the quarter.

Revenue for the nine months ended September 30, 2014 increased $1,412 million, or 9%, compared to the nine months ended September 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; and as a result of the devaluation of the local currency.

Profit before tax for the nine months ended September 30, 2014 increased $375 million, or 29%, compared to the nine months ended September 30, 2013. North America profit increased $237 million, or 32%, 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 partially offset by severance charges of $29 million incurred in the first quarter of 2014. The Latin America segment, despite lower revenue, experienced an increase in profit of $164 million, due to cost reduction initiatives throughout the region and favorable geographic mix partially offset by $12 million of foreign exchange loss. Profit before tax in Latin America for the nine months ended September 30, 2013, included $23 million of foreign exchange loss and $19 million for severance costs. The EARC segment experienced a decrease in profit of $9 million, or 2%, due to a $58 million charge associated with the restructuring of our operations in North Africa, and foreign exchange losses as a result of the devaluation of various currencies, mainly the Russian Ruble. The MEAP segment experienced an increase in profit of $77 million, or 21%, as revenue increased across all product lines. However, MEAP profitability was negatively impacted by increased losses in Iraq during the year. Profit before tax for the nine months ended September 30, 2014 includes $29 million of costs associated with a technology royalty agreement that pertain to our global operations and therefore such costs have been allocated to each segment as follows: North America - $13 million; Latin America - $3 million; Europe/Africa/Russia Caspian - $6 million; Middle East/Asia Pacific - $6 million; and Industrial Services - $1 million.



	Three Months Ended September 30,								Nine Months Ended September 30,
	2014				2013				2014				2013
	$		%		$		%		$		%		$		%
Revenue	$	6,250	100	%	$	5,787	100	%	$	17,916	100	%	$	16,504	100	%
Cost of revenue	5,107		82	%	4,750		82	%	14,572		81	%	13,667		83	%
Research and engineering	159		3	%	142		2	%	461		3	%	400		2	%
Marketing, general and administrative	323		5	%	319		6	%	977		5	%	970		6	%

Cost of revenue as a percentage of revenue was 82% and 81% for the three and nine months ended September 30, 2014, respectively, and 82% and 83% for the same periods a year ago. The improvement in cost of revenue as a percentage of revenue for the nine months ended September 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. These improvements were partially offset by the following: $58 million of third quarter 2014 costs associated with a restructuring of operations in North Africa and impairment of certain assets, resulting primarily from recent disruptions in Libya; second quarter 2014 severance charges of $29 million in North America as a result of a realignment of our business to match current market conditions; and second quarter 2014 costs associated with a technology royalty agreement of $29 million.

Marketing, general and administrative ("MG&A") expenses increased 1% for both the three and nine months ended September 30, 2014, respectively, compared to the same periods a year ago. Included in MG&A expenses for the three and nine months ended September 30, 2014, is a charge of $14 million related to the impairment of a technology investment. Included in the nine months ended September 30, 2014 is a foreign exchange loss that occurred in the second quarter of 2014 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 nine months of 2013, we had foreign exchange losses of $23 million due to the currency devaluation in Venezuela that occurred in the first quarter of 2013.

Total income tax expense was $233 million and $605 million for the three and nine months ended September 30, 2014, respectively. Our effective tax rate on income before income taxes for the three and nine months ended September 30, 2014 was 38.7% and 36.2%, respectively. The effective tax rate for the three and nine months ended September 30, 2014 is higher than the U.S. statutory income tax rate of 35% primarily due to the charge of $58 million associated with the restructuring of our North Africa business and other losses where there is no tax benefit.

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. 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.

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 well count expected to grow 5%. Onshore, service activity has increased in North America as the trend of more horizontal wells, longer laterals, more stages, and more proppant per stage has increased the pressure pumping intensity as our customers search for economic ways to improve well efficiencies and optimize production in unconventional plays. Offshore, activity in the Gulf of Mexico is now expected to have similar activity levels to those seen in 2013, as delays in deepwater activity caused by ongoing unusually strong ocean currents has impacted certain deepwater rigs in the second half of the year. In Canada, overall rig activity in 2014 is expected to be up compared to 2013, as the year-to-date rig count is already 8% above the same nine months last year.

Activity and Spending Outlook Outside North America - International activity is driven primarily by the oil and natural gas price environment which has entered a period of increased volatility and rapid decline in the past few months. If prices remain at these lower levels for a prolonged period of time, it could impact cash flow for our customers and translate into less spending. In the near term, we could begin to see certain customers curtail activity, especially ones who are more sensitive to commodity prices or pursuing marginal onshore and shallow water plays. However, for national oil companies and deepwater customers, we do not expect to see a meaningful change in activity in the near future.

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 September 30, 2014, we had cash and cash equivalents of $1.21 billion, compared to $1.40 billion of cash and cash equivalents held at December 31, 2013. Substantially all of the cash and cash equivalents were held by foreign subsidiaries. A substantial portion of the cash held by foreign subsidiaries at September 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 September 30, 2014, we had outstanding commercial paper of $332 million; therefore, the amount available for borrowing under the facility as of September 30, 2014 was $2.17 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 nine months ended September 30, 2014, we used cash to fund a variety of activities including working capital needs, capital expenditures, acquisitions, repurchase of our common stock and payment of dividends.

in the nine months ended September 30, 2014. This use of cash was primarily the result of an increase in working capital to support the growth in our business as evidenced by the increase in accounts receivable of $572 million, an increase in inventory of $280 million offset by an increase in accounts payable of $186 million. Net other operating items provided cash of $112 million primarily due to an increase in income taxes payable.

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 $1,288 million in the nine months ended September 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.

We had net proceeds from commercial paper and other short-term debt of $51 million in the nine months ended September 30, 2014. Total debt outstanding at September 30, 2014 was $4.41 billion, an increase of $32 million compared to December 31, 2013. The total debt-to-capital (defined as total debt plus equity) ratio was 0.19 at September 30, 2014 and 0.20 at December 31, 2013. We paid dividends of $205 million in the nine months ended September 30, 2014.

Our Board of Directors has previously authorized a program to repurchase our common stock from time to time. In the nine months ended September 30, 2014, we repurchased 9.1 million shares of our common stock at an average price of $65.75 per share, for a total of $600 million. We had authorization remaining to repurchase approximately $1.05 billion in common stock at September 30, 2014. During the nine months ended September 30, 2013, we did not repurchase any shares of common stock.

We have a $2.50 billion committed revolving credit facility with commercial banks that matures in September 2016. At September 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 September 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 September 30, 2014, we had $332 million of commercial paper outstanding resulting in $2.17 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.

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 $1.8 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 September 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 $278 million and $280 million in 2014; however, the Board of Directors can change the dividend policy at any time.

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.

As of the end of the period covered by this Quarterly Report, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act of 1934, as amended (the “Exchange Act”). This evaluation was carried out under the supervision and with the participation of our management, including our principal executive officer and principal financial officer. Based on this evaluation, these officers have concluded that, as of September 30, 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 September 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.

In addition to other geopolitical and terrorism risks, civil unrest continues to grow in a number of key countries where we do business. Our ability to conduct business operations may be impacted by that civil unrest and our assets in these countries may also be subject to expropriation by governments or other parties involved in civil unrest. Recent epidemic outbreaks may also impact our business operations by, among other things, restricting travel to protect the health and welfare of our employees and decisions by our customers to curtail or stop operations in impacted areas.



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⁾
July 1-31, 2014	439,320	$	70.86	425,000	$	1,219,754,738
August 1-31, 2014	2,196,049	$	68.50	2,195,511	$	1,069,368,546
September 1-30, 2014	285,375	$	68.65	284,534	$	1,049,832,435
Total	2,920,744	$	68.87	2,905,045

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.



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



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)



Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)



		Page No.
PART I -	FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)

	Consolidated Condensed Statements of Income (Unaudited) Three and nine months ended September 30, 2014 and 2013	2

	Consolidated Condensed Statements of Comprehensive Income (Loss) (Unaudited) Three and nine months ended September 30, 2014 and 2013	3

	Consolidated Condensed Balance Sheets (Unaudited) September 30, 2014 and December 31, 2013	4

	Consolidated Condensed Statements of Changes in Equity (Unaudited) Nine months ended September 30, 2014 and 2013	5

	Consolidated Condensed Statements of Cash Flows (Unaudited) Nine months ended September 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	29

Item 5.	Other Information	29

Item 6.	Exhibits	29

	Signatures	30



	September 30, 2014		December 31, 2013
Finished goods	$	3,674	$	3,438
Work in process	258		215
Raw materials	218		231
Total inventories	$	4,150	$	3,884



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Brent oil price ($/Bbl) ⁽¹⁾	$	102.16	$	110.04	$	106.58	$	108.61
WTI oil price ($/Bbl) ⁽²⁾	97.70		105.78		99.81		98.15
Natural gas price ($/mmBtu) ⁽³⁾	3.94		3.55		4.55		3.69



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



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


⁽¹⁾	Includes indefinite-lived intangibles of $26 million at September 30, 2014 and $27 million at December 31, 2013 related to in-process research and development projects.



Year	Estimated Amortization Expense
Remainder of 2014	$	28
2015	102
2016	101
2017	97
2018	91
2019	88


⁽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


•	Oil Prices - Oil prices have been dropping steadily throughout the quarter due to increasing supplies, led by the U.S., and weakening demand growth for hydrocarbons. Forecasts of future oil prices are highly uncertain due to recent changes in supply and demand for hydrocarbons.


⁽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 September 30, 2014, we repurchased 2.9 million shares of our common stock at an average price of $68.85 per share (including commissions), for a total of $200 million. We had authorization remaining to repurchase up to a total of approximately $1.05 billion of our common stock as of September 30, 2014.



		BAKER HUGHES INCORPORATED (Registrant)

Date:	October 21, 2014	By:	/s/ PETER A. RAGAUSS
		Peter A. Ragauss
		Senior Vice President and Chief Financial Officer

Date:	October 21, 2014	By:	/s/ ALAN J. KEIFER
		Alan J. Keifer
		Vice President and Controller