e10vq

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

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, 2009


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


2929 Allen Parkway, Suite 2100, Houston, Texas		77019-2118
(Address of principal executive offices)		(Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES þ NO o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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 31, 2009, the registrant has outstanding 309,876,683 shares of Common Stock, $1 par value per share.

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Baker Hughes Incorporated

Consolidated Condensed Statements of Operations

(In millions, except per share amounts)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008

Revenues:
Sales	$	1,156		$	1,466		$	2,467		$	2,719
Services and rentals		1,180			1,532			2,537			2,949

Total revenues		2,336			2,998			5,004			5,668


Costs and expenses:
Cost of sales		926			1,055			1,953			1,920
Cost of services and rentals		871			942			1,804			1,846
Research and engineering		102			106			211			209
Marketing, general and administrative		284			270			565			520
Litigation settlement		—			62			—			62

Total costs and expenses		2,183			2,435			4,533			4,557


Operating income		153			563			471			1,111
Equity in income of affiliates		—			1			—			1
Gain on sale of product line		—			—			—			28
Interest expense		(34	)		(17	)		(69	)		(32	)
Interest and dividend income		3			4			4			12


Income before income taxes		122			551			406			1,120
Income taxes		(35	)		(172	)		(124	)		(346	)

Net income	$	87		$	379		$	282		$	774


Basic earnings per share	$	0.28		$	1.24		$	0.91		$	2.51

Diluted earnings per share	$	0.28		$	1.23		$	0.91		$	2.50

Cash dividends per share	$	0.15		$	0.13		$	0.30		$	0.26

See accompanying notes to unaudited consolidated condensed financial statements.

Baker Hughes Incorporated

Consolidated Condensed Balance Sheets

(In millions)

(Unaudited)


	June 30,			December 31,
	2009			2008

ASSETS

Current Assets:
Cash and cash equivalents	$	1,362		$	1,955
Accounts receivable – less allowance for doubtful accounts (2009 - $133; 2008 - $74)		2,313			2,759
Inventories, net		2,024			2,021
Deferred income taxes		236			231
Other current assets		195			179

Total current assets		6,130			7,145

Property, plant and equipment, net		3,017			2,833
Goodwill		1,407			1,389
Intangible assets, net		193			198
Other assets		352			296

Total assets	$	11,099		$	11,861


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Accounts payable	$	737		$	888
Short-term borrowings and current portion of long-term debt		52			558
Accrued employee compensation		407			530
Income taxes payable		78			272
Other accrued liabilities		192			263

Total current liabilities		1,466			2,511

Long-term debt		1,777			1,775
Deferred income taxes and other tax liabilities		321			384
Liabilities for pensions and other postretirement benefits		355			317
Other liabilities		67			67
Commitments and contingencies

Stockholders’ Equity:
Common stock		309			309
Capital in excess of par value		786			745
Retained earnings		6,465			6,276
Accumulated other comprehensive loss		(447	)		(523	)

Total stockholders’ equity		7,113			6,807

Total liabilities and stockholders’ equity	$	11,099		$	11,861

See accompanying notes to unaudited consolidated condensed financial statements.

Baker Hughes Incorporated

Consolidated Condensed Statements of Cash Flows

(In millions)

(Unaudited)


	Six Months Ended
	June 30,
	2009			2008

Cash flows from operating activities:
Net income	$	282		$	774
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		355			302
Stock-based compensation costs		42			29
(Benefit)/provision for deferred income taxes		(87	)		1
Gain on disposal of assets		(38	)		(34	)
Gain on sale of product line		—			(28	)
Changes in operating assets and liabilities:
Accounts receivable		484			(283	)
Inventories		33			(172	)
Accounts payable		(162	)		138
Accrued employee compensation and other accrued liabilities		(187	)		(16	)
Income taxes payable		(195	)		(110	)
Other		(21	)		(44	)

Net cash flows from operating activities		506			557


Cash flows from investing activities:
Expenditures for capital assets		(572	)		(539	)
Proceeds from disposal of assets		90			97
Proceeds from sale of product line		—			31
Acquisition of businesses, net of cash acquired		(35	)		(72	)

Net cash flows from investing activities		(517	)		(483	)


Cash flows from financing activities:
Net borrowings of commercial paper and other short-term debt		20			538
Repayment of long-term debt		(525	)		—
Repurchases of common stock		—			(572	)
Proceeds from issuance of common stock		1			51
Dividends		(92	)		(81	)
Excess tax benefits from stock-based compensation		—			1

Net cash flows from financing activities		(596	)		(63	)


Effect of foreign exchange rate changes on cash		14			6

(Decrease)/increase in cash and cash equivalents		(593	)		17
Cash and cash equivalents, beginning of period		1,955			1,055

Cash and cash equivalents, end of period	$	1,362		$	1,072

Supplemental cash flows disclosures:
Income taxes paid (net of refunds)	$	405		$	433
Interest paid	$	90		$	41
Supplemental disclosure of noncash investing activities:
Capital expenditures included in accounts payable	$	23		$	17

See accompanying notes to unaudited consolidated condensed financial statements.

Baker Hughes Incorporated

Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 1. GENERAL

Nature of Operations

Baker Hughes Incorporated (“Company,” “we,” “our” or “us”) is engaged in the oilfield services industry. We are a major supplier of wellbore-related products and technology services and systems and provide products and services for drilling, formation evaluation, completion and production, and reservoir technology and consulting to the worldwide oil and natural gas industry.

Basis of Presentation

Our unaudited consolidated condensed financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain information and disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) have been condensed or omitted. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited consolidated condensed financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. 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, 2008 (“2008 Annual Report”). 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 connection with the preparation of the consolidated condensed financial statements and in accordance with the recently issued Statement of Financial Accounting Standards No. 165, Subsequent Events, we have evaluated all subsequent events through August 6, 2009, the date the financial statements were issued.

In the notes to the unaudited consolidated condensed financial statements, all dollar and share amounts in tabulations are in millions of dollars and shares, respectively, unless otherwise indicated.

New Accounting Standards

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurements (“SFAS 157”), which is intended to increase consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value and expanding disclosures about fair value measurements. On January 1, 2008, we adopted the provisions of SFAS 157 related to financial assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a recurring basis and on January 1, 2009, we adopted the provisions related to nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis. There was no material impact to our consolidated condensed financial statements related to these adoptions. Additionally, in April 2009, the FASB issued the following three FASB Staff Positions (“FSP”): (i) FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, (ii) FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments, and (iii) FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments, which collectively provide additional guidance and require additional disclosure regarding determining and reporting fair values for certain assets and liabilities. We adopted the three FSPs in the second quarter of 2009 with no material impact to our consolidated condensed financial statements. The new disclosure requirements of FSP FAS 107-1 and APB 28-1 are reflected in Note 9. Financial Instruments.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51 (“SFAS 160”). SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary in an effort to improve the relevance, comparability and transparency of the financial information that a reporting entity provides. On January 1, 2009, we adopted SFAS 160 with no change to our consolidated condensed financial statements as amounts are immaterial.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS 141(R)”). SFAS 141(R) replaces FASB Statement No. 141, Business Combinations (“SFAS 141”). The statement retains the purchase method of accounting used in business combinations but replaces SFAS 141 by establishing principles and requirements for the recognition and measurement of assets, liabilities and goodwill, and requires that most transaction and restructuring costs related to the acquisition be expensed. We have applied the provisions of SFAS 141(R) for business combinations with an acquisition date on or after January 1, 2009.

Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements (continued)

In June 2008, the FASB issued FSP Emerging Issues Task Force (“EITF”) 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”). This FSP clarifies that all unvested share-based payments that contain rights to non-forfeitable dividends are participating securities and shall be included in the computation of both basic and diluted earnings per share. On January 1, 2009, we adopted FSP EITF 03-6-1. FSP EITF 03-6-1 has not been applied to prior year quarters as the impact is immaterial.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133 (“SFAS 161”). SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives and quantitative data about the fair value of and gains and losses on derivative contracts. We adopted the new disclosure requirements in the first quarter of 2009 as reflected in Note 9. Financial Instruments.

In December 2008, the FASB issued FSP FAS 132(R)-1 Employers’ Disclosures about Postretirement Benefit Plan Assets. This FSP requires the disclosures of investment policies and strategies, major categories of plan assets, fair value measurement of plan assets and significant concentration of credit risks. We will adopt the new disclosure requirements in the fourth quarter of 2009.

NOTE 2. GAIN ON SALE OF PRODUCT LINE

In February 2008, we sold the assets associated with the Completion and Production segment’s Surface Safety Systems (“SSS”) product line and received cash proceeds of $31 million. The SSS assets sold included hydraulic and pneumatic actuators, bonnet assemblies and control systems. We recorded a pre-tax gain of $28 million (approximately $18 million after-tax) in the first quarter of 2008.

NOTE 3. STOCK-BASED COMPENSATION

We grant various forms of equity based awards to directors, officers and other key employees. These equity based awards consist primarily of stock options, restricted stock awards and restricted stock units. The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes option pricing model. The fair value of restricted stock awards and units is based on the market price of our common stock on the date of grant.

We also have an Employee Stock Purchase Plan (“ESPP”) available for eligible employees to purchase shares of our common stock. Our ESPP allows eligible employees to elect to contribute on an after-tax basis between 1% and 10% of their annual pay to purchase our common stock; provided, however, an employee may not contribute more than $25,000 annually to the plan pursuant to Internal Revenue Service restrictions. Shares are purchased at a 15% discount of the fair market value of our common stock on January 1^st or December 31^st, whichever is lower.

The following summarizes stock-based compensation expense recognized in our consolidated condensed statements of operations:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008

Stock Options	$	2	$	2	$	9	$	8
Restricted Stock Awards and Units		10		9		20		15
ESPP		7		3		13		6

Total	$	19	$	14	$	42	$	29

Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements (continued)

NOTE 4. EARNINGS PER SHARE

On January 1, 2009, we adopted FSP EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. This FSP clarifies that all unvested share-based payments that contain rights to non-forfeitable dividends are participating securities and shall be included in the computation of both basic and diluted earnings per share. FSP EITF 03-6-1 has not been applied to prior year quarters as the impact is immaterial.

A reconciliation of the number of shares used for the basic and diluted EPS calculation is as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008

Weighted average common shares outstanding for basic EPS		310		307		310		308
Effect of dilutive securities – stock plans		—		1		—		2

Adjusted weighted average common shares outstanding for diluted EPS		310		308		310		310


Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than the average market price for the period		3		—		3		1

NOTE 5. INVENTORIES

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


	June 30,		December 31,
	2009		2008

Finished goods	$	1,711	$	1,693
Work in process		168		175
Raw materials		145		153

Total	$	2,024	$	2,021

NOTE 6. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are comprised of the following:


	June 30,			December 31,
	2009			2008

Land	$	87		$	85
Buildings and improvements		976			878
Machinery and equipment		3,266			3,082
Rental tools and equipment		2,146			1,991

Subtotal		6,475			6,036
Accumulated depreciation		(3,458	)		(3,203	)

Total	$	3,017		$	2,833

Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements (continued)

NOTE 7. GOODWILL AND INTANGIBLE ASSETS

The changes in the carrying amount of goodwill are detailed below by segment:


	Drilling		Completion
	and		and
	Evaluation		Production		Total

Balance as of December 31, 2008	$	951	$	438	$	1,389
Goodwill acquired during the period		9		—		9
Purchase price and other adjustments		2		—		2
Impact of foreign currency translation adjustments		6		1		7

Balance as of June 30, 2009	$	968	$	439	$	1,407

Intangible assets are comprised of the following:


	June 30, 2009							December 31, 2008
	Gross							Gross
	Carrying		Accumulated					Carrying		Accumulated
	Amount		Amortization			Net		Amount		Amortization			Net

Technology-based	$	263	$	(132	)	$	131	$	256	$	(122	)	$	134
Contract-based		13		(8	)		5		12		(7	)		5
Marketing-related		36		(13	)		23		33		(6	)		27
Customer-based		41		(7	)		34		37		(5	)		32
Other		—		—			—		1		(1	)		—

Total	$	353	$	(160	)	$	193	$	339	$	(141	)	$	198

Intangible assets with finite useful lives are amortized either on a straight-line basis with estimated useful lives ranging from 1 to 20 years, or on a basis that reflects the pattern in which the economic benefits of the intangible assets are expected to be realized, which range from 15 to 30 years.

Amortization expense for intangible assets included in net income for the three months and six months ended June 30, 2009 was $12 million and $19 million, respectively, and is estimated to be $31 million for 2009. Estimated amortization expense for each of the subsequent five fiscal years is expected to be as follows: 2010 – $23 million; 2011 – $20 million; 2012 – $18 million; 2013 - $15 million; and 2014 – $14 million.

NOTE 8. FAIR VALUE OF CERTAIN FINANCIAL ASSETS AND LIABILITIES

Financial assets and liabilities measured at fair value are based on a hierarchy that prioritizes the inputs to valuation techniques into three broad levels, which are described below:

•

Level 1 inputs are quoted market prices in active markets for identical assets or liabilities (these are observable market inputs).

•

Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability (includes quoted market prices for similar assets or identical or similar assets in markets in which there are few transactions, prices that are not current or vary substantially).

•

Level 3 inputs are unobservable inputs that reflect the entity’s own assumptions in pricing the asset or liability (used when little or no market data is available).

Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements (continued)

The table below details the financial assets and liabilities included in our financial statements and measured at fair value as of June 30, 2009 classified based on the valuation technique level.


	June 30, 2009
Description	Total		Level 1		Level 2		Level 3

Assets:
Auction rate securities	$	15	$	—	$	—	$	15
Non-qualified defined contribution plan assets		122		—		122		—

Total assets at fair value	$	137	$	—	$	122	$	15


Liabilities:

Non-qualified defined contribution plan liabilities	$	122	$	—	$	122	$	—

The following is a reconciliation of activity for the three and six months ended June 30, 2009 for assets measured at fair value based on Level 3 inputs.

Level 3 Fair Value Measurements Auction Rate Securities


	Three Months Ended
	June 30, 2009

Balance as of March 31, 2009	$	11
Total gains or (losses) realized:
Included in earnings (or changes to net assets)		—
Included in other comprehensive income		4

Balance as of June 30, 2009	$	15


	Six Months Ended
	June 30, 2009

Balance as of December 31, 2008	$	11
Total gains or (losses) realized:
Included in earnings (or changes to net assets)		—
Included in other comprehensive income		4

Balance as of June 30, 2009	$	15

Auction Rate Securities

The Company owns auction rate securities (“ARS”) that were purchased in 2007 at an original cost of $36 million and have a fair value of $15 million at June 30, 2009. These ARS represent interests in three variable rate debt securities, which are credit linked notes that generally combine low risk assets and credit default swaps (“CDS”) to create a security that pays interest from the assets’ coupon payments and the periodic sale proceeds of the CDS. As of June 30, 2009, the three notes carried split ratings, ranging from B to BBB-, as provided by Standard & Poor’s and Fitch rating agencies.

We estimate the fair value of our ARS investments using Level 3 inputs, incorporating the most recent market data available as of the valuation date. These inputs are based on the underlying structure of each security and their collateral values, including assessments of the credit quality, the default risk, the expected cash flows, the discount rates and the overall capital market liquidity. Based on this analysis, we recorded an increase of $4 million in the fair value of these available-for-sale securities to other comprehensive income; however, these markets still remain largely illiquid. The valuation of our ARS investments is subject to uncertainties that are difficult to predict and require significant judgment. Based on our ability and intent to hold such investments for a period of time sufficient to allow for any anticipated recovery in the fair value, we have classified all of our auction rate securities as noncurrent investments.

Non-qualified Defined Contribution Plan Assets and Liabilities

We have a non-qualified defined contribution plan that provides basically the same benefit as our Thrift Plan for certain non-U.S. employees who are not eligible to participate in the Thrift Plan. In addition, we provide a non-qualified supplemental retirement plan for certain officers and employees whose benefits under the Thrift Plan and/or U.S. defined benefit pension plan are limited by federal

Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements (continued)

tax law. The assets of both plans consist primarily of mutual funds and to a lesser extent equity securities. We hold the assets of these plans under a grantor trust and have recorded the assets along with the related deferred compensation liability at fair value. The assets and liabilities were valued using Level 2 inputs at the reporting date and were based on quoted market prices from various major stock exchanges.

NOTE 9. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

During the second quarter of 2009, we adopted FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments. This FSP requires fair value disclosure of financial instruments for interim and annual reporting periods.

Our financial instruments include cash and short-term investments, noncurrent investments in auction rate securities, accounts receivable, accounts payable, accrued payroll taxes, debt, foreign currency forward contracts and interest rate swaps. Except as described below, the estimated fair value of such financial instruments at June 30, 2009 approximates their carrying value as reflected in our consolidated condensed balance sheet.

The estimated fair value of total debt at June 30, 2009 was $2,037 million, which differs from the carrying amounts of $1,777 million included in our consolidated condensed balance sheet. The fair value of our debt has been estimated based on quoted market prices as of June 30, 2009.

Foreign Currency Forward Contracts

We conduct our business in over 90 countries around the world, and we are exposed to market risks resulting from fluctuations in foreign currency exchange rates. A number of our significant foreign subsidiaries have designated the local currency as their functional currency. We transact in various foreign currencies and have established a program that primarily utilizes foreign currency forward contracts to reduce the risks associated with the effects of certain foreign currency exposures. Under this program, our strategy is to have gains or losses on the foreign currency forward contracts mitigate the foreign currency transaction gains or losses to the extent practical. These foreign currency exposures typically arise from changes in the value of assets and liabilities which are denominated in currencies other than the functional currency. Our foreign currency forward contracts generally settle within 90 days. We do not use these forward contracts for trading or speculative purposes. We designate these forward contracts as fair value hedging instruments pursuant to SFAS 133. The hedging objective is to mitigate exposure to fluctuations in the non functional currency exchange rate. Accordingly, we record the fair value of these contracts as of the end of our reporting period to our consolidated condensed balance sheet with changes in fair value recorded in our consolidated condensed statement of operations along with the change in fair value of the hedged item.

At June 30, 2009, we had outstanding foreign currency forward contracts with notional amounts aggregating $130 million to hedge exposure to currency fluctuations in various foreign currencies. These contracts expire on various dates prior to September 30, 2009. These contracts are designated and qualify as fair value hedging instruments. The fair value was determined using a model with Level 2 inputs including quoted market prices for contracts with similar terms and maturity dates.

Interest Rate Swaps

We are subject to interest rate risk on our debt and investment of cash and cash equivalents arising in the normal course of our business, as we do not engage in speculative trading strategies. We maintain an interest rate management strategy, which primarily uses a mix of fixed and variable rate debt that is intended to mitigate the exposure to changes in interest rates in the aggregate for our investment portfolio. In addition, we use interest rate swaps to manage the economic effect of fixed rate obligations associated with our senior notes so that the interest payable on the senior notes effectively becomes linked to variable rates.

In June 2009, we entered into two interest rate swap agreements (“the Swap Agreements”) for a notional amount of $250 million each in order to hedge changes in the fair market value of our $500 million 6.5% senior notes maturing on November 15, 2013. Under the Swap Agreements, we receive interest at a fixed rate of 6.5% and pay interest at a floating rate of one-month Libor plus a spread of 3.67% on one swap and three-month Libor plus a spread of 3.54% on the second swap both through November 15, 2013. The counterparties are primarily the lenders in our credit facilities. The Swap Agreements are designated and each qualifies as a fair value hedging instrument and are both determined to be highly effective resulting in no gain or loss recorded in the consolidated condensed statement of operations. The fair value of the Swap Agreements was based on quoted market prices for contracts with similar terms and maturity dates.

Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements (continued)

Fair Value of Derivative Instruments

The fair value of derivative instruments included in our consolidated condensed balance sheet was as follows as of June 30, 2009:

The effects of derivative instruments in our consolidated condensed statement of operations were as follows (amounts exclude any income tax effects):


		Amount of Gain/(Loss) Recognized in Income
	Statement of	Three Months Ended		Six Months Ended
	Operations Location	June 30, 2009		June 30, 2009

Foreign Currency Forward Contracts	Marketing, general and administrative expense	$	6	$	4

NOTE 10. INDEBTEDNESS

During the first quarter of 2009, we repaid $325 million principal amount of our 6.25% notes, which matured on January 15, 2009, and $200 million principal amount of our 6.00% notes, which matured on February 15, 2009.

On March 30, 2009, we entered into a credit agreement (the “2009 Credit Agreement”) for a committed $500 million revolving credit facility that expires in March 2010. At June 30, 2009, we had $1.5 billion of credit facilities with commercial banks, of which $1.0 billion are committed revolving credit facilities, which includes the 2009 Credit Agreement. The committed facilities expire on July 7, 2012 ($500 million), unless extended, and on March 29, 2010 ($500 million). The $500 million facility that expires on July 7, 2012 provides for a one year extension, subject to the approval and acceptance by the lenders, among other conditions. In addition, this facility contains a provision to allow for an increase in the facility amount of an additional $500 million, subject to the approval and acceptance by the lenders, among other conditions. Both facilities contain certain covenants which, among other things, require the maintenance of a funded indebtedness to total capitalization ratio (a defined formula per each agreement), restrict certain merger transactions or the sale of all or substantially all of our assets or a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the occurrence of certain events of default, our obligations under the facilities may be accelerated. Such events of default include payment defaults to lenders under the facilities, covenant defaults and other customary defaults.

At June 30, 2009, we were in compliance with all of the covenants of both committed credit facilities. There were no direct borrowings under the committed credit facilities during the quarter ended June 30, 2009. We also have an outstanding commercial paper program under which we may issue from time to time up to $1.0 billion in commercial paper with maturity of no more than 270 days. To the extent we have outstanding commercial paper, our ability to borrow under the facilities is reduced. At June 30, 2009, we had no outstanding commercial paper.

NOTE 11. SEGMENT AND RELATED INFORMATION

We are a major supplier of wellbore-related products and technology services and systems and provide products and services for drilling, formation evaluation, completion and production, and reservoir technology and consulting to the worldwide oil and natural gas industry. In May 2009, we reorganized the Company by product lines and geography; however, at this time we continue to review product line financial information as well as geographic information in deciding how to allocate resources and in assessing performance. Accordingly, we report results for our product lines under two segments: the Drilling and Evaluation segment and the Completion and Production segment. We have aggregated the product lines within each segment because they have similar economic characteristics and because the long-term financial performance of these product lines is affected by similar economic conditions. They also operate in the same markets, which includes all of the major oil and natural gas producing regions of the world.

•

The Drilling and Evaluation segment consists of the following product lines: drilling fluids, oilfield drill bits, drilling, measurement-while-drilling and logging-while-drilling, wireline formation evaluation, wireline completion services and reservoir technology and consulting. The Drilling and Evaluation segment provides products and services used to drill and evaluate oil and natural gas wells as well as consulting services used in the analysis of oil and gas reservoirs.

Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements (continued)

•

The Completion and Production segment consists of the following product lines: workover, fishing and completion equipment, oilfield specialty chemicals, electrical submersible pumps, progressing cavity pumps, production optimization, permanent monitoring, integrated operations and project management. The Completion and Production segment provides equipment and services used from the completion phase through the productive life of oil and natural gas wells.

The performance of our segments is evaluated based on segment profit (loss), which is defined as income before income taxes, interest expense, interest and dividend income, and certain gains and losses not allocated to the segments.

Summarized financial information is shown in the following table.


	Drilling		Completion
	and		and		Total		Corporate
	Evaluation		Production		Oilfield		and Other			Total

*Revenues*
Three months ended June 30, 2009	$	1,116	$	1,220	$	2,336	$	—		$	2,336
Three months ended June 30, 2008		1,528		1,470		2,998		—			2,998

Six months ended June 30, 2009	$	2,419	$	2,585	$	5,004	$	—		$	5,004
Six months ended June 30, 2008		2,919		2,749		5,668		—			5,668

*Segment profit (loss)*
Three months ended June 30, 2009	$	73	$	166	$	239	$	(117	)	$	122
Three months ended June 30, 2008		367		322		689		(138	)		551

Six months ended June 30, 2009	$	223	$	396	$	619	$	(213	)	$	406
Six months ended June 30, 2008		716		585		1,301		(181	)		1,120

*Total assets*
As of June 30, 2009	$	5,328	$	4,458	$	9,786	$	1,313		$	11,099
As of December 31, 2008		5,468		4,518		9,986		1,875			11,861

The following table presents the details of “Corporate and Other” segment loss:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008

Corporate and other expenses	$	(86	)	$	(63	)	$	(148	)	$	(127	)
Litigation settlement		—			(62	)		—			(62	)
Gain on sale of product line		—			—			—			28
Interest expense		(34	)		(17	)		(69	)		(32	)
Interest and dividend income		3			4			4			12

Total	$	(117	)	$	(138	)	$	(213	)	$	(181	)

NOTE 12. EMPLOYEE BENEFIT PLANS

We have noncontributory defined benefit pension plans (“Pension Benefits”) covering employees primarily in the U.S., the U.K. and Germany. We also provide certain postretirement health care benefits (“other postretirement benefits”), through an unfunded plan, to substantially all U.S. employees who retire and have met certain age and service requirements.

Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements (continued)

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


													Other Postretirement
	U.S. Pension Benefits						Non-U.S. Pension Benefits						Benefits
	2009			2008			2009			2008			2009		2008

Service cost	$	7		$	8		$	1		$	1		$	2	$	2
Interest cost		5			5			4			5			3		3
Expected return on plan assets		(6	)		(10	)		(4	)		(6	)		—		—
Amortization of net loss		3			—			—			—			—		—
Curtailment loss		1			—			—			—			—		—

Net periodic benefit cost	$	10		$	3		$	1		$	—		$	5	$	5

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


													Other Postretirement
	U.S. Pension Benefits						Non-U.S. Pension Benefits						Benefits
	2009			2008			2009			2008			2009		2008

Service cost	$	14		$	15		$	1		$	1		$	4	$	4
Interest cost		10			9			7			9			5		5
Expected return on plan assets		(12	)		(19	)		(7	)		(11	)		—		—
Amortization of prior service cost		—			—			—			—			1		—
Amortization of net loss		6			—			1			1			—		—
Curtailment loss		1			—			—			—			—		—

Net periodic benefit cost	$	19		$	5		$	2		$	—		$	10	$	9

During the first six months of 2009, there was a reduction in our work force resulting in a significant reduction in the expected years of future service of our employees in certain pension plans and other post retirement benefit plans. In connection with this, in the second quarter of 2009, we recorded a one-time curtailment loss of $1 million. As a result of this curtailment, the impacted plans have been remeasured as of June 30, 2009 using a discount rate of 6.2% as compared to 6.4% at December 31, 2008. The curtailment and remeasurement resulted in a net increase in our liabilities for pensions and other postretirement benefits and accumulated other comprehensive loss of $14 million.

NOTE 13. COMMITMENTS AND CONTINGENCIES

Litigation

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

On April 26, 2007, the United States District Court, Southern District of Texas, Houston Division (the “Court”) unsealed a three-count criminal information (the “Information”) that had been filed against us as part of the execution of a Deferred Prosecution Agreement (the “DPA”) between us and the Department of Justice (“DOJ”). The three counts arose out of payments made to an agent in connection with a project in Kazakhstan and included conspiracy to violate the Foreign Corrupt Practices Act (“FCPA”), a substantive violation of the antibribery provisions of the FCPA, and a violation of the FCPA’s books-and-records provisions. All three counts related to our operations in Kazakhstan during the period from 2000 to 2003. The DPA relates to our March 29, 2002 announcement that the SEC and the DOJ were conducting investigations into allegations of violations of law relating to Nigeria and other related matters. In connection therewith, the SEC had issued a formal order of investigation into possible violations of provisions under the FCPA and issued subpoenas regarding our operations in Nigeria, Angola and Kazakhstan.

On April 26, 2009, the DPA expired and pursuant to a motion filed by the DOJ, the Court issued an order on April 28, 2009, dismissing the Information on the basis that the Company had fully complied with its obligations under the DPA.

Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements (continued)

The DPA also required us to retain an independent monitor (the “Monitor”) for a term of three years to assess and make recommendations about our compliance policies and procedures and our implementation of those procedures. In addition, the Monitor was required to perform two follow up reviews and to “certify whether the anti-bribery compliance program of Baker Hughes, including its policies and procedures, is appropriately designed and implemented to ensure compliance with the FCPA, U.S. commercial bribery laws and foreign bribery laws.” On April 8, 2009, the Monitor issued his report for the first of such follow up reviews, and the Monitor issued his certification that our compliance program is appropriately designed and implemented to ensure such compliance. Pursuant to the DPA, the DOJ has agreed not to prosecute us for violations of the FCPA based on information that we have disclosed to the DOJ regarding our operations in Nigeria, Angola, Kazakhstan, Indonesia, Russia, Uzbekistan, Turkmenistan, and Azerbaijan, among other countries.

On April 26, 2007, the Court also accepted a plea of guilty by our subsidiary Baker Hughes Services International, Inc. (“BHSII”) pursuant to a plea agreement between BHSII and the DOJ (the “Plea Agreement”) based on similar charges relating to the same conduct. Pursuant to the Plea Agreement, BHSII agreed to a three-year term of organizational probation. The Plea Agreement contains provisions requiring BHSII to cooperate with the government, to comply with all federal criminal law, and to adopt a Compliance Code similar to the one that the DPA requires of the Company.

Also on April 26, 2007, the SEC filed a Complaint (the “SEC Complaint”) and a proposed order (“2007 Order”) against us in the Court. The SEC Complaint and the 2007 Order were filed as part of a settled civil enforcement action by the SEC, to resolve the civil portion of the government’s investigation of us. As part of our agreement with the SEC, we consented to the filing of the SEC Complaint without admitting or denying the allegations in the Complaint, and also consented to the entry of the 2007 Order. The SEC Complaint alleged civil violations of the FCPA’s antibribery provisions related to our operations in Kazakhstan, the FCPA’s books-and-records and internal-controls provisions related to our operations in Nigeria, Angola, Kazakhstan, Indonesia, Russia, and Uzbekistan, and the cease and desist order that we had entered into with the SEC on September 12, 2001 (“2001 Order”). In entering into the 2001 Order, we had neither admitted nor denied the factual allegations contained therein including alleged violations of Section 13(b)(2)(A) and Section 13(b)(2)(B) of the Securities Exchange Act of 1934 that require issuers to: (x) make and keep books, records and accounts, which, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the issuer and (y) devise and maintain a system of internal accounting controls sufficient to provide reasonable assurances that: (i) transactions are executed in accordance with management’s general or specific authorization; and (ii) transactions are recorded as necessary: (I) to permit preparation of financial statements in conformity with generally accepted accounting principles or any other criteria applicable to such statements, and (II) to maintain accountability for assets. The 2007 Order became effective on May 1, 2007, which is the date it was confirmed by the Court. The 2007 Order enjoins us from violating the FCPA’s antibribery, books-and-records, and internal-controls provisions. As in the DPA, it requires that we retain the independent monitor to assess our FCPA compliance policies and procedures for the three-year period.

Under the terms of the settlements with the DOJ and the SEC, the Company and BHSII paid, in the second quarter of 2007, $44 million ($11 million in criminal penalties, $10 million in civil penalties, $20 million in disgorgement of profits and $3 million in pre-judgment interest) to settle these investigations. In the fourth quarter of 2006, we recorded a financial charge for the potential settlement.

On May 4, 2007 and May 15, 2007, the Sheetmetal Workers’ National Pension Fund and Chris Larson, respectively, instituted shareholder derivative lawsuits for and on the Company’s behalf against certain current and former members of the Board of Directors and certain current and former officers, and the Company as a nominal defendant, following the Company’s settlement with the DOJ and SEC in April 2007. On August 17, 2007, the Alaska Plumbing and Pipefitting Industry Pension Trust also instituted a shareholder derivative lawsuit for and on the Company’s behalf against certain current and former members of the Board of Directors and certain current and former officers, and the Company as a nominal defendant. On June 6, 2008, the Midwestern Teamsters Pension Trust Fund and Oppenheim Kapitalanlagegesellschaft mbH instituted a shareholder derivative lawsuit for and on the Company’s behalf against certain current and former members of the Board of Directors and certain current and former officers, and the Company as a nominal defendant. The complaints in all four lawsuits allege, among other things, that the individual defendants failed to implement adequate controls and compliance procedures to prevent the events addressed by the settlement with the DOJ and SEC. The relief sought in the lawsuits includes a declaration that the defendants breached their fiduciary duties, an award of damages sustained by the Company as a result of the alleged breach and monetary and injunctive relief, as well as attorneys’ and experts’ fees. On May 15, 2008, the consolidated complaint of the Sheetmetal Workers’ National Pension Fund and the Alaska Plumbing and Pipefitting Industry Pension Trust was dismissed for lack of subject matter jurisdiction by the Houston Division of the United States District Court for the Southern District of Texas. The lawsuit brought by Chris Larson in the 215th District Court of Harris County, Texas was dismissed on September 15, 2008. The lawsuit brought by the Midwestern Teamsters Pension Trust Fund and Oppenheim Kapitalanlagegesellschaft mbH in the Houston Division of the United States District Court for the Southern District of Texas was dismissed on May 26, 2009. The time period for plaintiffs to file a Notice of Appeal in each of the cases has expired.

Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements (continued)

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 $670 million at June 30, 2009. None of the off-balance sheet arrangements either has, or is likely to have, a material effect on our consolidated condensed financial statements.

NOTE 14. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) includes all changes in equity during a period except those resulting from investments by and distributions to owners. The components of our comprehensive income (loss), net of related tax, are as follows:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008

Net income	$	87		$	379		$	282		$	774
Other comprehensive income (loss):
Foreign currency translation adjustments during the period		98			(8	)		82			20
Pension and other postretirement benefits		(12	)		3			(10	)		(2	)
Unrealized gain/(loss) on available-for-sale securities		4			(7	)		4			(7	)

Total comprehensive income	$	177		$	367		$	358		$	785

Total accumulated other comprehensive loss consisted of the following:


	June 30,			December 31,
	2009			2008

Foreign currency translation adjustments	$	(260	)	$	(342	)
Pension and other postretirement benefits		(191	)		(181	)
Unrealized gain on available-for-sale securities		4			—

Total accumulated other comprehensive loss	$	(447	)	$	(523	)

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 our consolidated condensed financial statements and the related notes thereto, as well as our Annual Report on Form 10-K for the year ended December 31, 2008 (“2008 Annual Report”).

EXECUTIVE SUMMARY

Prior to May 4, 2009, the business operations were organized around four primary geographic regions: North America; Latin America; Europe, Africa, Russia, Caspian; and Middle East, Asia Pacific. As of June 30, 2009, we had approximately 36,100 employees, with approximately 60% of these employees working outside the United States.

On May 4, 2009, we reorganized the Company by geography and product lines. Global operations are now organized into a number of geomarket organizations, which report to nine Region Presidents who in turn report to two Hemisphere Presidents (Eastern and Western). The product-line marketing and technology organizations report to a Products and Technology President. The Products and Technology President and the two Hemisphere Presidents report to our Chief Operating Officer. The reorganization of the Company by geography and product lines is intended to strengthen our client-focused operations by moving management into the countries where we conduct our business. The product-line organizations will continue to be responsible for product development and manufacturing, technology, marketing and delivery of solutions for our customers to advance their reservoir performance. The new organization structure will also improve cross-product-line technology development, sales processes and integrated operations capabilities.

The primary driver of our business 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, future economic growth, hydrocarbon demand and estimates of future oil and natural gas production.

During the first half of 2009, as the global economy continued to weaken, many of our customers announced reductions in their planned 2009 spending, and we have seen significant decreases in drilling activity, particularly in the U.S. land market and Canada, and a decline in prices for our products and services. In this challenging environment, we generated revenues of $2.34 billion in the second quarter of 2009, which is down $662 million or 22% compared to the second quarter of 2008, and compared to a 36% decrease in the worldwide average rig count for the same time period. Our North American revenues for the second quarter of 2009 were $794 million, a decrease of 38% compared to a 50% decrease in the U.S. rig count and a 46% decrease in the Canadian rig count, which reflects the severe contraction in customer spending and activity. Revenues outside of North America were $1.54 billion, a decrease of 10% compared to the second quarter of 2008. As a result of the decline in activity and contractions in customer spending, we took actions to adjust our operating cost base, which consisted primarily of a reduction in workforce. In connection with this reduction in workforce, we recorded expenses of $10 million and $64 million in the three months and six months ended June 30, 2009, respectively, related to employee severance costs. Net income for the second quarter of 2009 was $87 million compared with $379 million in the second quarter of 2008.

BUSINESS ENVIRONMENT

Our business environment and its corresponding operating results are affected significantly by the level of energy industry spending for the exploration, development and production of oil and natural gas reserves. Spending by oil and natural gas exploration and production companies is dependent upon their forecasts regarding the expected future supply and future demand for oil and natural gas products and their estimates of costs to find, develop, and produce reserves. Changes in oil and natural gas exploration and production spending will normally result in increased or decreased demand for our products and services, which will be reflected in the rig count and other measures.

The credit crisis, lower oil and natural gas prices, and the global economic recession are all impacting our business environment. Our customers typically fund their activity through a combination of borrowed funds and internally-generated cash flow. The limited

availability of commercial credit is having a negative effect on the general economy and the ability of our customers to continue to operate at pre-crisis levels. The decline in oil prices and natural gas prices from 2008 mid-summer highs reduced our customers’ operational cash flow, further challenging their ability to continue to operate at past levels and reducing the near-term outlook for our products and services. The economic slowdown is also negatively impacting the incremental demand for hydrocarbon products around the world.

Oil and Natural Gas Prices

Oil (West Texas Intermediate (WTI)/Cushing Crude Oil Spot Price) and natural gas (Henry Hub Natural Gas Spot Price) prices are summarized in the table below as averages of the daily closing prices during each of the periods indicated.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008

Oil prices ($/Bbl)	$	59.69	$	123.80	$	51.57	$	111.14
Natural gas prices ($/mmBtu)		3.71		11.36		4.12		10.03

Oil prices averaged $59.69/Bbl in the second quarter of 2009. Prices ranged from a low of $45.88/Bbl in mid-April to a quarter high of $72.68/Bbl in mid-June supported by expectations for an improvement in global economic activity and a late-May decision by OPEC to maintain existing output levels. Prices peaked in mid-June and declined into July as a result of persistently high inventories, weak near-term demand and lowered expectations for a global economic recovery. The International Energy Agency (“IEA”) estimated in its July 2009 Oil Market Report that worldwide demand would decrease 2.9% to 83.8 million barrels per day in 2009, down from an estimated 86.2 million barrels per day in 2008.

Natural gas prices averaged $3.71/mmBtu in the second quarter of 2009. Natural gas prices ranged from a high of $4.42/mmBtu to a low of $3.19/mmBtu in the quarter. During the quarter, the discount relative to oil prices increased on a Btu equivalent basis. This was due to a number of factors including weak natural gas demand, continued increases in natural gas production despite reductions in drilling activity, high storage levels, moderate temperatures and increased receipts of LNG.

Rig Counts

Baker Hughes has been providing rig counts to the public since 1944. We gather all relevant data through our field service personnel, who obtain the necessary data from routine visits to the various rigs, customers, contractors and/or other outside sources. This data is then compiled and distributed to various wire services and trade associations and is published on our website. Rig counts are compiled weekly for the U.S. and Canada and monthly for all international and U.S. workover rigs. Published international rig counts do not include rigs drilling in certain locations, such as Russia, the Caspian and onshore China, because this information is not readily available.

Rigs in the U.S. are counted as active if, on the day the count is taken, the well being drilled has been started but drilling has not been completed and the well is anticipated to be of sufficient depth to be a potential consumer of our drill bits. Rigs in Canada are counted as active if data obtained by the Canadian Association of Oilwell Drillers and Contractors indicates that drilling operations have occurred during the week and we are able to verify this information. In most international areas, rigs are counted as active if drilling operations have taken place for at least 15 days during the month. In some active international areas where better data is available, we compute a weekly or daily average of active rigs. In international areas where there is poor availability of data, the rig counts are estimated from third-party data. 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 is not expected to be significant consumers of drill bits.

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


	Three Months Ended				%			Six Months Ended				%
	June 30,				Increase			June 30,				Increase
	2009		2008		(Decrease)			2009		2008		(Decrease)

U.S. – land and inland waters		885		1,797		(51	%)		1,086		1,755		(38	%)
U.S. – offshore		50		67		(25	%)		53		62		(15	%)
Canada		89		166		(46	%)		211		341		(38	%)

North America		1,024		2,030		(50	%)		1,350		2,158		(37	%)

Latin America		350		382		(8	%)		360		377		(5	%)
North Sea		42		46		(9	%)		46		43		7	%
Other Europe		40		51		(22	%)		40		51		(22	%)
Africa		63		68		(7	%)		61		67		(9	%)
Middle East		251		278		(10	%)		259		275		(6	%)
Asia Pacific		237		259		(8	%)		238		252		(6	%)

Outside North America		983		1,084		(9	%)		1,004		1,065		(6	%)

Worldwide		2,007		3,114		(36	%)		2,354		3,223		(27	%)

Second Quarter of 2009 Compared to the Second Quarter of 2008

The rig count in North America decreased 50% reflecting declines in natural gas drilling activity. Outside North America, the rig count decreased 9%. The rig count in Latin America decreased due to lower activity in Argentina, Venezuela and Colombia, partially offset by increases in Brazil and Mexico. The North Sea rig count decreased primarily due to decreases in the Norwegian and U.K. sectors. The rig count in Africa decreased primarily due to lower activity in West Africa. The rig count decreased in the Middle East due to lower activity in Egypt, Saudi Arabia, Yemen and Qatar and in the Asia Pacific region due to lower activity in Australia and India.

RESULTS OF OPERATIONS

The discussions below relating to significant line items from our consolidated condensed statements of operations are based on available information and represent our analysis of significant changes or events that impact the comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect comparability or trends and, where possible and practical, have quantified the impact of such items. In addition, the discussions below for revenues and cost of revenues are on a combined basis as the business drivers for the individual components of product sales and services and rentals are similar.

The table below details certain consolidated condensed statement of operations data and their percentage of revenues for the three months and six months ended June 30, 2009 and 2008, respectively.


	Three Months Ended June 30,
	2009				2008

Revenues	$	2,336	100	%	$	2,998	100	%
Cost of revenues		1,797	77	%		1,997	67	%
Research and engineering		102	4	%		106	4	%
Marketing, general and administrative		284	12	%		270	9	%


	Six Months Ended June 30,
	2009				2008

Revenues	$	5,004	100	%	$	5,668	100	%
Cost of revenues		3,757	75	%		3,766	66	%
Research and engineering		211	4	%		209	4	%
Marketing, general and administrative		565	11	%		520	9	%

Revenues


	Three Months Ended June 30,				Increase
	2009		2008		(decrease)			% Change

Geographic Revenues:
North America	$	794	$	1,278	$	(484	)		(38	)%
Latin America		276		266		10			4	%
Europe Africa Russia Caspian		743		906		(163	)		(18	)%
Middle East Asia Pacific		523		548		(25	)		(5	)%

Total revenues	$	2,336	$	2,998	$	662			(22	)%


	Six Months Ended June 30,				Increase
	2009		2008		(decrease)			% Change

Geographic Revenues:
North America	$	1,876	$	2,455	$	(579	)		(24	)%
Latin America		565		501		64			13	%
Europe Africa Russia Caspian		1,519		1,668		(149	)		(9	)%
Middle East Asia Pacific		1,044		1,044		—			—	%

Total revenues	$	5,004	$	5,668	$	(664	)		(12	)%

Second Quarter of 2009 Compared to the Second Quarter of 2008

Revenues for the second quarter of 2009 decreased compared with the second quarter of 2008, primarily due to declines in North America as a result of contractions in customer spending resulting in sharp reductions in activity, lower pricing for our products and services and the weak global economic environment. The worldwide rig count decreased 36% during the second quarter of 2009 compared with the second quarter of 2008.

Revenues in North America, which accounted for 34% of total revenues, decreased 38% in the second quarter of 2009 compared to the second quarter of 2008. In North America, our customers continued to adapt to a market characterized by low natural gas prices, strong production, decreased demand and ample natural gas in storage by trimming their spending in the second quarter of 2009. This was reflected in the North America rig count which averaged 1,024 in the second quarter of 2009, down 50% compared to the second quarter of 2008.

The Latin America region revenues increased 4% in the second quarter of 2009 compared to the second quarter of 2008 and compared to an 8% decrease in the rig count. The growth in Latin America revenue was led by our Mexico / Central America geomarket, where operations on the Alma Marine Integrated Operations project for Petroleos Mexicanos (“PEMEX”) increased from two to four offshore rigs. The Andean (Colombia/Ecuador/Peru) geomarket led by increased revenues for directional drilling and completions and the Brazil geomarket also contributed to year-over-year growth.

The Europe Africa Russia Caspian (“EARC”) region revenues decreased 18% in the second quarter of 2009 compared to the second quarter of 2008. The revenue decline in the EARC region was led by the overall decline in spending in the Russia and Caspian geomarkets, where customer activity decreased by approximately 30%. Also contributing to the year-over-year decline were project delays and completions of existing projects in the Norway, Sub Sahara Africa, Nigeria and North Africa geomarkets.

The Middle East Asia Pacific (“MEAP”) region revenues decreased 5% for the second quarter of 2009 compared to the second quarter of 2008 as revenue increases in the Southeast Asia and Gulf geomarkets were offset by lower revenues throughout the region.

First Six Months of 2009 Compared to the First Six Months of 2008

Revenues for the six months ended June 30, 2009 decreased 12% compared with the six months ended June 30, 2008, primarily due to declines in North America as a result of contractions in customer spending resulting in sharp reductions in activity, lower pricing for our products and services and the weakening global economic environment. Revenues in North America decreased 24% primarily due to a decrease in drilling activity and outside North America revenues decreased 3%. Latin America revenues increased 13% which was primarily led by directional drilling in Mexico; EARC revenues decreased 9% due to a decrease in sales in the U.K., Russia and Caspian; and MEAP revenues were flat compared to the six months ended June 30, 2008.

Cost of Revenues

Cost of revenues for the three months ended June 30, 2009 decreased 10% compared with the three months ended June 30, 2008. Cost of revenues as a percentage of consolidated revenues was 77% and 67% for the three months ended June 30, 2009 and 2008, respectively. Cost of revenues for the six months ended June 30, 2009 was flat compared with the six months ended June 30, 2008. Cost of revenues as a percentage of consolidated revenues was 75% and 66% for the six months ended June 30, 2009 and 2008, respectively. The increase in both periods in cost of revenues as a percentage of revenues is primarily due to significant declines in activity worldwide resulting in excess manufacturing capacity, lower utilization of our rental tools and price deterioration, primarily in North America. Additional contributing factors to this increase include costs associated with employee severance of $8 million and $53 million for the three and six months ended June 30, 2009, respectively; costs associated with increasing our allowance for doubtful accounts of $38 million and $67 million for the three months and six months ended June 30, 2009, respectively; and a change in the geographic and product mix from the sale of our products and services as we continue to emphasize productivity and cost improvements.

Research and Engineering

Research and engineering expenses decreased 4% in the three months ended June 30, 2009 compared with the three months ended June 30, 2008 and increased 1% in the six months ended June 30, 2009 compared with the six months ended June 30, 2008. We continue to be committed to developing and commercializing new technologies as well as investing in our core product offerings.

Marketing, General and Administrative

Marketing, general and administrative expenses increased 5% in the three months ended June 30, 2009 compared with the three months ended June 30, 2008 and increased 9% in the six months ended June 30, 2009 compared with the six months ended June 30, 2008. The increase in both periods resulted primarily from costs associated with enterprise-wide accounting system implementations, reorganization, employee severance and foreign exchange losses.

Litigation Settlement

In connection with the settlement of litigation with ReedHycalog, in June 2008, the Company paid ReedHycalog $70 million in royalties for prior use of certain patented technologies, and ReedHycalog paid the Company $8 million in royalties for the license of certain Company patented technologies. The net charge of $62 million for the settlement of this litigation is reflected in the consolidated condensed statement of operations.

Interest Expense

Interest expense increased $17 million for the three months ended June 30, 2009 compared with the three months ended June 30, 2008 and increased $37 million in the six months ended June 30, 2009 compared with the six months ended June 30, 2008. The increase in both periods is primarily due to higher average debt levels as a result of the long-term debt issuances of $1.25 billion in October 2008.

Interest and Dividend Income

Interest and dividend income decreased $1 million in the three months ended June 30, 2009 compared with the three months ended June 30, 2008 and decreased $8 million in the six months ended June 30, 2009 compared with the six months ended June 30, 2008. The decrease in both periods was primarily due to a reduction of the average interest rate earned partially offset by an increase in the average investment balance.

Income Taxes

Our effective tax rate in the second quarter of 2009 is 28.2%, which is lower than the U.S. statutory income tax rate of 35% due to lower rates of tax on certain international operations, a decrease in tax reserves as a result of favorable audit settlements, offset by state income taxes and a net increase in the valuation allowance associated with certain foreign deferred tax assets.

Our tax filings for various periods are subject to audit by the tax authorities in most jurisdictions where we conduct business. These audits may result in assessment of additional taxes that are resolved with the authorities or through the courts. We believe these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. We have received tax assessments from various taxing authorities and are currently at varying stages of appeals and/or litigation regarding these matters.

We believe we have substantial defenses to the questions being raised and will pursue all legal remedies should an unfavorable outcome result. However, resolution of these matters involves uncertainties and there are no assurances that the outcomes will be favorable. We provide for uncertain tax positions pursuant to Financial Interpretation (“FIN”) 48, Accounting for Uncertainty in Income Taxes: an Interpretation of FASB Statement No. 109.

OUTLOOK

Worldwide Oil and Natural Gas Industry 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.

The credit crisis, lower oil and natural gas prices, the global economic recession and the uncertainty regarding governmental policies are all impacting our business environment. Our customers typically fund their activity through a combination of borrowed funds and internally-generated cash flow. The continued limited availability of commercial credit is having a negative effect on both the general economy and the ability of our customers to continue to operate at pre-crisis levels. The decline in oil prices and natural gas prices from 2008 mid-summer highs has also reduced our customers’ operational cash flow, further challenging their ability to continue to operate at past levels as well as their future spending for our products and services. The economic slowdown is also negatively impacting the incremental demand for hydrocarbon products.

Our outlook for exploration and development spending is based upon our expectations for customer spending in the markets in which we operate, and is driven primarily by our perception of industry expectations for oil and natural gas prices and their likely impact on customer capital and operating budgets as well as other factors that could impact the economic return oil and gas companies expect for developing oil and gas reserves. Our forecasts are based on our analysis of information provided by our customers as well as market research and analyst reports including the Short Term Energy Outlook (“STEO”) published by the Energy Information Administration of the U.S. Department of Energy (“DOE”), the Oil Market Report published by the International Energy Agency (“IEA”) and the Monthly Oil Market Report published by the Organization for Petroleum Exporting Countries (“OPEC”). Our outlook for economic growth is based on our analysis of information published by a number of sources including the International Monetary Fund (“IMF”), OECD and the World Bank.

As an oil service 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 their forecasts of future energy demand, their expectations for future energy prices, their access to resources to develop and produce oil and gas and their ability to fund their capital programs.

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. The current down cycle is different in that the primary driver is the rapid deterioration of the global economy, which has led to declining demand and forecasts for further reductions in future demand. The drop in commodity prices, in conjunction with reduced access to the debt markets, has forced many oil and gas companies to reduce their spending to levels supportable by their expected free cash flow.

In North America, the outlook for spending in 2009 is also dependent on the outlook for the natural gas industry. The drop in demand coupled with increased drilling activity through September 2008 and the application of horizontal drilling and advanced fracturing and completion technologies in the unconventional gas fields has resulted in gas production exceeding demand. Natural gas prices have fallen from mid-2008 highs and are not expected to increase until drilling is reduced to a level below the rate necessary to offset depletion, and supply and demand come back into balance. The commodity cycle in North American natural gas is being aggravated by the recession, mid-summer storage levels that are approximately 25% greater than last year, low natural gas prices and reduced access to credit for many of our customers.

The outlook for the global economy, the depth and duration of the recession, and the timing and pace of the recovery remain uncertain. We use third-party forecasts, including forecasts by the IMF, World Bank and OECD, to set our expectations for global economic growth.

Expectations for Oil Prices - As a result of the global economic recession, demand for oil is expected to decrease in a range from 1.6 million to 2.4 million barrels per day in 2009 relative to 2008. Non-OPEC supply growth is expected to grow modestly in response to decreased spending and is now expected to increase 190 to 360 thousand barrels per day. Decreased demand and

moderate growth in non-OPEC production are expected to pressure OPEC to manage its production levels to support oil prices. Inventories and spare productive capacity, which buffer oil markets from supply disruptions, are expected to increase as the gap between increasing supply and decreasing demand grows. In its July 2009 STEO report, the DOE forecasted oil prices to average near $70/Bbl in the second half of 2009. The DOE expects prices to rise slowly in 2010 to an average of $72/Bbl for 2010 as economic conditions improve. Variables that could significantly affect this forecast include changes in the assumption for global economic growth and energy demand, changes or delays in non-OPEC supply additions and OPEC production quota discipline.

Expectations for North American Natural Gas Prices - The combination of rising natural gas production and recession-driven decreases in natural gas demand are expected to drive gas prices lower in 2009 relative to 2008. In its July 2009 STEO report, the DOE forecasted that U.S. natural gas demand would decrease 2% in 2009 compared to 2008, assuming continued economic weakness and that natural gas prices would average about $4.22/mmBtu in 2009, down from $8.89/mmBtu in 2008. North American gas-directed drilling activity is expected to remain depressed in the second half of 2009, resulting in fewer supply additions from new wells to offset production declines from existing wells. Gas prices are expected to remain soft until the gap between supply and demand tightens as gas demand growth exceeds gas supply growth for some period of time. The DOE forecasts gas prices to increase modestly to $5.93/mmBtu in 2010. Prices remain volatile with the economy, weather-driven demand, imports of Canadian gas, LNG imports, gas storage levels, and production from the lower 48 states’ gas fields playing significant roles in determining both prices and price volatility. Variations in the supply demand balance will be reflected in gas storage levels.

Industry Activity and Customer Spending - Our forecasts of activity and customer spending are based upon our discussions with major customers, reviews of published industry reports, our outlook for oil and natural gas prices described above, and our outlook for drilling activity, as measured by the Baker Hughes rig count. We believe that our customers’ 2009 spending plans are based on forecasts of oil and gas prices and energy demand similar to those stated above. In addition, each company’s 2009 spending plans also reflect company-specific drivers such as their ability to finance their 2009 spending plans as well as their assessments of the uncertainty associated with their forecasts. At current and expected oil and natural gas prices, some projects that were planned in 2008 to begin in 2009 or 2010 may no longer be economically attractive. In light of current economic conditions and current oil and gas prices, we believe that our customers, as a group, will decrease spending in 2009 relative to 2008.

	•		North America – Both customer spending and drilling activity in North America, primarily directed at developing natural gas supplies, are expected to decrease approximately 25% to 40% in 2009 relative to 2008. Spending on producing oil and gas from developed fields is expected to remain flat or decrease modestly in 2009, reflecting the stability in oil and gas production levels.

	•		Outside North America – Both customer spending and drilling activity, primarily directed at developing oil supplies, are expected to decrease approximately 5% to 10% in 2009 relative to 2008. Spending on producing oil and gas from developed fields is expected to remain flat or decrease modestly in 2009, reflecting the stability in oil and gas production levels.

Our customers are likely to reduce their planned spending relative to the above outlook if oil prices were expected to trade below $40/Bbl for an extended period of time. The risks to oil prices falling below $40/Bbl for a significant period of time include (1) incremental weakness in the global economic outlook; (2) significant unexpected increases in non-OPEC production; (3) significant disruption to worldwide demand; (4) reduced geo-political tensions; (5) poor OPEC quota discipline; or (6) other factors that result in increased spare productive capacity, higher oil inventory levels or decreased demand.

Company 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 our expectation for oil and natural gas demand, oil and natural gas prices and drilling activity.

North American revenue is expected to decline approximately 25% to 35% in 2009 relative to 2008 reflecting reduced customer spending and deterioration of pricing. Decreases in revenue for our Drilling and Evaluation segment are expected to be greater than the decline in revenue for our Completion and Production segment.

Outside of North America we expect revenues to decline approximately 5% to 10% in 2009 relative to 2008 with the most significant declines occurring in the Eastern Hemisphere. Share gains and activity increase in Latin America could result in an increase in Latin America revenues in 2009 compared to 2008. Spending on large projects by National Oil Companies (“NOCs”) in the second half of 2009 is not expected to follow established seasonal trends as projects and activities planned for 2009 have been delayed in many countries.

Profit is expected to decline in 2009 relative to 2008 as a result of lower activity levels and deterioration of pricing offset only partially by cost reductions. Factors that could have a significant positive impact on profitability include less than expected price deterioration for our products and services, lower than expected raw material and labor costs, and/or higher than expected planned activity. Conversely, greater than expected price deterioration, higher than expected raw material and labor costs and/or lower than expected activity would have a negative impact on profitability. Our ability to limit price deterioration is dependent on demand for our products and services, our competitors’ strategies for managing capacity in a declining market, our competitors’ strategies for defending market share and price, and our customers’ strategies for obtaining price concessions.

Our 2009 capital budget supports the continuation of the infrastructure expansion we began in late 2006 and early 2007. Capital expenditures are expected to be approximately $1.1 billion for 2009, including approximately $350 million to $400 million that we expect to spend on infrastructure, primarily outside North America, but excluding any acquisitions. A significant portion of our planned capital expenditures can be adjusted to reflect changes in our expectations for future customer spending. We expect to manage our capital expenditures to match market demand.

The execution of our 2009 business plan and the ability to meet our 2009 financial objectives are dependent on a number of factors. Key factors include: activity and spending levels in each of our markets; the relative strength of the oilfield services competition in each market and our ability to limit price decreases and manage raw material and labor costs. Other factors include, but are not limited to, our ability to: adjust our workforce to control costs while recruiting, training and retaining the skilled and diverse workforce necessary to meet our future business needs; continue to expand our business in sectors that are expected to grow most rapidly when the economy and energy market recover and in areas where we have market share opportunities; manage raw material and component costs (steel alloys, copper, tungsten carbide, lead, nickel, chemicals and electronic components); continue to make ongoing improvements in the productivity of our manufacturing organization and manage our spending in the North American and international markets.

Compliance

In connection with our settlements with the DOJ and SEC, we retained an independent monitor (the “Monitor”) to assess and make recommendations about our compliance policies and procedures. In response to the Monitor’s initial recommendations, we have continued our reduction of the use of commercial sales representatives (“CSRs”) and processing agents, including the reduction of customs agents. We have also continued to enhance our channels of communication regarding agents while streamlining our compliance due diligence process for agents, including more clearly delineating the responsibilities of participants in the compliance due diligence process. We have adopted a risk-based compliance due diligence procedure for professional agents, enhancing our process for classifying distributors and creating a formal policy to guide business personnel in determining when subcontractors should be subjected to compliance due diligence. We have also instituted a program to ensure that each of our internal sponsors regularly reviews their CSRs, including a review with senior management.

In addition, we have reviewed and expanded the use of our centralized finance organization including further implementation of our enterprise-wide accounting system and company-wide policies regarding expense reporting, petty cash, the approval of invoice payments and general ledger account coding. We also have consolidated our divisional audit functions and redeployed some of these resources for corporate audits. Further, we have restructured our corporate audit function, and are incorporating additional anti-corruption procedures into some of our audits, which are applied on a country-wide basis. We are also continuing to refine and enhance our procedures for Foreign Corrupt Practices Act (“FCPA”) compliance reviews, risk assessments, and legal audit procedures.

Further, we continue to work to ensure that we have adequate legal compliance coverage around the world, including the coordination of compliance advice and training across the divisions in each of our regions. We have also worked to create simplified summaries, flow charts, and FAQs (Frequently Asked Questions) to accompany each of our compliance related policies and we are supplementing our existing policies. At the same time, we are taking steps to achieve further centralization of our customs and logistics function including the development of uniform and simplified customs policies and procedures. We are also developing uniform procedures for the verification and documentation of services provided by customs agents and a training program in which customs and logistics personnel receive specialized training focused specifically on risks associated with the customs process. We are also adopting a written plan for reviewing and reducing the number of our customs agents and freight forwarders.

We are continuing to centralize our human resources function, including creating consistent standards for pre-hire screening of employees, the screening of existing employees prior to promoting them to positions where they may be exposed to corruption-related risks, and creating a uniform policy for on-boarding training. We are implementing a training program that identifies employees for compliance training and sets appropriate training schedules based on job function and risk profile in addition to employment grade. Further, the contents of our training programs are being tailored to address the different risks posed by different categories of

employees. We are supplementing our FCPA electronic training module while taking steps to ensure that training is available in the principal local languages of our employees and that local anti-corruption laws are discussed as part of our compliance training. We have also worked to ensure that our helpline is easily accessible to employees in their own language as well as taking actions to counter any cultural norms that might discourage employees from using the helpline. We continue to provide a regular and consistent message from senior management of zero tolerance for FCPA violations, and emphasize that compliance is a positive factor in the continued success of our business.

The Monitor is required to perform two follow up reviews and to “certify whether the anti-bribery compliance program of Baker Hughes, including its policies and procedures, is appropriately designed and implemented to ensure compliance with the FCPA, U.S. commercial bribery laws and foreign bribery laws.” On April 8, 2009, the Monitor issued his report for the first of such follow up reviews and the Monitor issued his certification that our compliance program is appropriately designed and implemented to ensure such compliance.

For a further description of our compliance programs see, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Compliance” in our 2008 Annual Report.

LIQUIDITY AND CAPITAL RESOURCES

Our objective in financing our business is to maintain adequate financial resources and access to additional liquidity. During the six months ended June 30, 2009, cash flows from operations was the principal source of funding. At June 30, 2009, we had cash and cash equivalents of $1.36 billion and $1.51 billion of credit facilities with commercial banks, of which $1.0 billion are committed revolving credit facilities that provide additional liquidity. In the normal course of business, we have agreements with banks under which approximately $670 million of letters of credit, surety bonds, or bank guarantees were outstanding as of June 30, 2009. In addition, during the second quarter of 2009, we filed a shelf registration statement to facilitate raising additional funds in the capital markets as deemed appropriate. See further discussion below under “Available Credit Facilities.”

The declines in commodity prices are leading to reductions in cash flows of many of our customers. In addition, the tight credit markets and increased costs of borrowing have affected the availability of credit. These factors may have adverse effects on the financial condition of our customers, which may result in delays, partial payment or non-payment of amounts owed to us thus negatively impacting our operating cash flows.

Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of our company. During the six months ended June 30, 2009, we used cash to pay for a variety of activities including working capital needs, dividends, debt maturities and capital expenditures.

Cash Flows

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


	2009			2008

Operating activities	$	506		$	557
Investing activities		(517	)		(483	)
Financing activities		(596	)		(63	)

Statements of cash flows for entities with international operations that are local currency functional exclude the effects of the changes in foreign currency exchange rates that occur during any given period, as these are noncash charges. As a result, changes reflected in certain accounts on the consolidated condensed statements of cash flows may not reflect the changes in corresponding accounts on the consolidated condensed balance sheets.

Operating Activities

Cash flows from operating activities of continuing operations provided $506 million in the six months ended June 30, 2009 compared with $557 million in the six months ended June 30, 2008. This decrease in cash flows of $51 million is primarily due to a decrease in net income offset by the change in net operating assets and liabilities that used less cash in the six months ended June 30, 2009 compared to the same period in 2008.

The underlying drivers of the changes in net operating assets and liabilities are as follows:

	•		A decrease in accounts receivable in the six months of 2009 provided $484 million in cash compared with using $283 million in cash in the second quarter of 2008. The change in accounts receivable was primarily due to the decrease in activity offset by an increase in the days of sales outstanding by approximately twelve days, reflecting a slowdown in customer payments.

	•		Inventory provided $33 million in cash in the six months ended June 30, 2009 compared with using $172 million in cash in the six months ended June 30, 2008 due to activity decreases.

	•		Accrued employee compensation and other accrued liabilities used $187 million in cash in the six months ended June 30, 2009 compared with using $16 million in cash in the six months ended June 30, 2008. The increase was primarily due to an increase in payments in the first six months of 2009 compared to the first six months of 2008 primarily related to employee bonuses, non income taxes, and interest.

	•		Income taxes payable used $195 million in cash in the six months ended 2009 compared to using $110 million in cash in the first six months of 2008. The increase in cash used was primarily due to federal income tax payments made in 2009 of $155 million for two quarterly installment payments from 2008. The U.S. Internal Revenue Service allowed companies impacted by Hurricane Ike to defer the third and fourth quarter installment payments for 2008 until January 2009.

Investing Activities

Our principal recurring investing activity is the funding of capital expenditures to ensure that we have the appropriate levels and types of rental tools in place to generate revenues from operations. Expenditures for capital assets totaled $572 million and $539 million for the six months ended June 30, 2009 and 2008, respectively. While the majority of these expenditures were for rental tools, including wireline tools, and machinery and equipment, we have also increased our spending on new facilities, expansions of existing facilities and other infrastructure projects.

Proceeds from the disposal of assets were $90 million and $97 million for the six months ended June 30, 2009 and 2008, respectively. These disposals relate to rental tools that were lost-in-hole, as well as machinery, rental tools and equipment no longer used in operations that were sold throughout the period.

We routinely evaluate potential acquisitions of businesses of third parties that may enhance our current operations or expand our operations into new markets or product lines. In the second quarter of 2009, we paid $24 million, net of cash acquired of $4 million, for several acquisitions and as a result, recorded $9 million of goodwill and $8 million of intangible assets. We also paid $11 million for additional purchase price consideration for past acquisitions. In April 2008, we paid cash of $72 million, including $4 million of direct transaction costs, and net of cash acquired of $5 million, for acquisitions and as a result, recorded $43 million of goodwill and $19 million of intangible assets.

We may also from time to time sell business operations that are not considered part of our core business. In February 2008, we sold the assets associated with the Completion and Production segment’s Surface Safety Systems product line and received cash proceeds of $31 million.

Financing Activities

We had net borrowings of commercial paper and/or other short-term debt of $20 million and $538 million in the six months ended June 30, 2009 and 2008, respectively. In addition, we repaid $525 million of maturing long-term debt in the three months ended March 31, 2009. Total debt outstanding at June 30, 2009 was $1.83 billion, a decrease of $504 million compared with December 31, 2008. We have no maturities of long-term debt prior to November 15, 2013. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratios was 0.20 at June 30, 2009 and 0.25 at December 31, 2008.

We received proceeds of $1 million and $51 million in the six months ended June 30, 2009 and 2008, respectively, from the issuance of common stock from the exercise of stock options.

Our Board of Directors has authorized a program to repurchase our common stock from time to time. For the six months ended June 30, 2009 we did not repurchase any shares of common stock. At June 30, 2009, we had authorization remaining to repurchase up to a total of $1.2 billion of our common stock. During the six months ended June 30, 2008, we repurchased 8 million shares of our commons stock at an average price of $69.09 per share for a total of $572 million.

We paid dividends of $92 million and $81 million in the six months ended June 30, 2009 and 2008, respectively.

Available Credit Facilities

On March 30, 2009, we entered into a credit agreement (the “2009 Credit Agreement”). The 2009 Credit Agreement is a committed $500 million revolving credit facility that expires on March 29, 2010. At June 30, 2009, we had $1.51 billion of credit facilities with commercial banks, of which $1.0 billion are committed revolving credit facilities, which includes the 2009 Credit Agreement. The committed facilities expire on July 7, 2012 ($500 million), unless extended, and on March 29, 2010 ($500 million). The $500 million facility that expires on July 7, 2012 provides for a one year extension, subject to the approval and acceptance by the lenders, among other conditions. In addition, the facility contains a provision to allow for an increase in the facility amount of an additional $500 million, subject to the approval and acceptance by the lenders, among other conditions. Both facilities contain certain covenants which, among other things, require the maintenance of a funded indebtedness to total capitalization ratio (a defined formula per the facility), restrict certain merger transactions or the sale of all or substantially all of our assets or a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the occurrence of certain events of default, our obligations under the facilities may be accelerated. Such events of default include payment defaults to lenders under the facilities, covenant defaults and other customary defaults.

At June 30, 2009, we were in compliance with all of the facility covenants of both committed credit facilities. There were no direct borrowings under the committed credit facilities during the quarter ended June 30, 2009. We also have an outstanding commercial paper program under which we may issue from time to time up to $1.0 billion in commercial paper with maturity of no more than 270 days. To the extent we have outstanding commercial paper, our ability to borrow under the committed credit facilities is reduced by a similar amount. At June 30, 2009, we had no outstanding commercial paper.

If market conditions were to change and revenues were to be significantly reduced 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 the committed credit facilities. However, a downgrade in our credit ratings could increase the cost of borrowings under the facilities 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 facilities.

We believe our credit ratings and relationships with major commercial and investment banks would allow us to obtain interim financing over and above our existing credit facilities 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 2009, we believe cash on-hand and operating cash flows will provide us with sufficient capital resources and liquidity to manage our working capital needs, meet contractual obligations, fund capital expenditures, pay dividends, repurchase common stock and support the development of our short-term and long-term operating strategies.

In 2009, we expect capital expenditures to be approximately $1.1 billion, excluding acquisitions. The expenditures are expected to be used primarily for normal, recurring items necessary to support the growth of our business and operations. A significant portion of our capital expenditures can be adjusted based on future activity of our customers. We expect to manage our capital expenditures to match market demand.

In 2009, we also expect to make interest payments of between $145 million and $150 million based on our current expectations of debt levels during 2009, and we anticipate making income tax payments of between $450 million and $500 million in 2009.

As of June 30, 2009, we have authorization remaining to repurchase up to $1.2 billion in common stock. We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. We anticipate paying dividends of between $180 million and $190 million in 2009; however, the Board of Directors can change the dividend policy at anytime.

We have updated our expectations for our benefit plan contributions. We currently anticipate contributing approximately $35 million to our defined benefit pension plans and approximately $15 million to our postretirement welfare plans. We currently estimate we will contribute between $130 million and $140 million to our defined contribution plans, which is an adjustment downward due to declines in employee headcount resulting in reductions in employer contributions.

NEW ACCOUNTING STANDARDS

FORWARD-LOOKING STATEMENTS

MD&A and certain statements in the Notes to Consolidated Condensed Financial Statements include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, (each a “forward-looking statement”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “probable,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward-looking statements. Our forward-looking statements are based on assumptions that we believe to be reasonable but that may not prove to be accurate. The statements do not include the potential impact of future transactions, such as an acquisition, disposition, merger, joint venture or other transaction that could occur. We undertake no obligation to publicly update or revise any forward-looking statement. Our expectations regarding our business outlook and business plans; the business plans of our customers; oil and natural gas market conditions; costs and availability of resources; economic, legal and regulatory conditions and other 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 2008 Annual Report, this filing and those set forth from time to time in our filings with the Securities and Exchange Commission (“SEC”). These documents are available through our web site or through the SEC’s Electronic Data Gathering and Analysis Retrieval System (“EDGAR”) at http://www.sec.gov.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We conduct operations around the world in a number of different currencies. The majority of our significant foreign subsidiaries have designated the local currency as their functional currency. As such, future earnings are subject to change due to changes in foreign currency exchange rates when transactions are denominated in currencies other than our functional currencies. To minimize the need for foreign currency forward contracts to hedge this exposure, our objective is to manage foreign currency exposure by maintaining a minimal consolidated net asset or net liability position in a currency other than the functional currency.

Foreign Currency Forward Contracts

At June 30, 2009, we had outstanding foreign currency forward contracts with notional amounts aggregating $130 million to hedge exposure to currency fluctuations in various foreign currencies. These contracts are designated and qualify as fair value hedging instruments. The fair value of these contracts outstanding at June 30, 2009, was approximately $2 million and was included in other accrued liabilities in the consolidated condensed balance sheet. The fair value was determined using a model including quoted market prices for contracts with similar terms and maturity dates.

The effect of foreign currency forward contracts on the consolidated condensed statement of operations for the three months ended June 30, 2009 was $6 million of foreign exchange gains, which are included in marketing, general and administrative expenses. These gains offset designated foreign exchange losses resulting from the underlying exposures of the hedged items.

The counterparties to the forward contracts are major financial institutions. The credit ratings and concentration of risk of these financial institutions are monitored on a continuing basis. In the event that the counterparties fail to meet the terms of a foreign currency contract, our exposure is limited to the foreign currency rate differential.

Interest Rate Swaps

In June 2009, we entered into two interest rate swap agreements (“the Swap Agreements”) for a notional amount of $250 million each in order to hedge changes in the fair market value of our $500 million 6.5% senior notes maturing on November 15, 2013. Under the Swap Agreements we receive interest at a fixed rate of 6.5% and pay interest at a floating rate of one-month Libor plus a spread of 3.67% on one swap and three-month Libor plus a spread of 3.54% on the second swap through November 15, 2013. The Swap Agreements are designated and each qualifies as a fair value hedging instrument and are both determined to be highly effective. The fair value of the Swap Agreements at June 30, 2009, was $2 million and was based on quoted market prices for contracts with similar terms and maturity dates.

The financial institutions that are counterparties to the Swap Agreements are primarily the lenders in our credit facilities. Under the terms of the credit support documents governing the Swap Agreements, the relevant party will have to post collateral in the event such party’s long-term debt rating falls below investment grade or is no longer rated.

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, 2009, 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, 2009 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are subject to a number of lawsuits, investigations and claims (some of which involve substantial amounts) arising out of the conduct of our business. See a further discussion of litigation matters in Note 13 of Notes to Unaudited Consolidated Condensed Financial Statements.

For additional information see also, “Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Outlook” of this Form 10-Q and Item 3 of Part I of our 2008 Annual Report for additional discussion of legal proceedings.

ITEM 1A. RISK FACTORS

As of the date of this filing, there have been no material changes from the risk factors previously disclosed in our “Risk Factors” in the 2008 Annual Report and the Form 10-Q for the period ended March 31, 2009 except as follows:

Many of our customers’ activity levels and spending for our products and services and ability to pay amounts owed us have been impacted by current economic conditions.

Access to capital is dependent on our customers’ ability to access the funds necessary to develop economically attractive projects based upon their expectations of future energy prices, required investments and resulting returns. Limited access to external sources of funding has caused many customers to reduce their capital spending plans to levels supported by internally-generated cash flow. In addition, the combination of a reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may impact the ability of our customers to pay amounts owed to us. Starting in late 2008 and continuing through the second quarter of 2009, we are experiencing a delay in receiving payments from our customers in Venezuela. As of June 30, 2009, our accounts receivable in Venezuela totaled approximately 7% of our total accounts receivable. For the six months ended June 30, 2009, Venezuela revenues were approximately 2% of our total consolidated revenues.

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, 2009.

Issuer Purchases of Equity Securities


											Maximum
											Number (or
					Total Number						Approximate
					of Shares						Dollar Value) of
					Purchased as						Shares that May
					Part of a				Total Number		Yet Be
	Total Number		Average Price		Publicly		Average Price		of Shares		Purchased
	of Shares		Paid Per		Announced		Paid Per		Purchased in		Under the
Period	Purchased ⁽¹⁾		Share ⁽¹⁾		Program ⁽²⁾		Share ⁽²⁾		the Aggregate		Program ⁽³⁾

April 1-30, 2009		5,705	$	35.96		—	$	—		5,705	$	—
May 1-31, 2009		1,762		30.97		—		—		1,762		—
June 1-30, 2009		1,525		38.14		—		—		1,525		—

Total		8,992	$	35.35		—	$	—		8,992	$	1,197,127,803



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

(2)		There were no share repurchases during the three months ended June 30, 2009.

(3)		Our Board of Directors has authorized a plan to repurchase our common stock from time to time. During the second quarter of 2009, we did not repurchase shares of our common stock. We had authorization remaining to repurchase up to a total of $1,197 million of our common stock.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On April 23, 2009, we held our Annual Meeting of Stockholders. Information regarding our meeting is included under Item 4 of Part II of our Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2009.

ITEM 5. OTHER INFORMATION

Item 8.01 Other Events.

On July 20, 2009, the Company amended Exhibit A to its Executive Severance Plan to clarify the group of employees covered by the Plan.

ITEM 6. EXHIBITS

Each exhibit identified below is filed as a part of this report. Exhibits designated with a “+” are identified as management contracts or compensatory plans or arrangements.


10.1+		Amendment to Exhibit A of the Executive Severance Plan dated as of July 20, 2009.

31.1		Certification of Chad C. Deaton, Chief Executive Officer, dated August 6, 2009, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.

31.2		Certification of Peter A. Ragauss, Chief Financial Officer, dated August 6, 2009, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.

32		Statement of Chad C. Deaton, Chief Executive Officer, and Peter A. Ragauss, Chief Financial Officer, dated August 6, 2009, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.

*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

* Furnished with this Form 10-Q, not filed


	Page No.
PART I — FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

Consolidated Condensed Statements of Operations (Unaudited) — Three months and six months ended June 30, 2009 and 2008		2

Consolidated Condensed Balance Sheets (Unaudited) — June 30, 2009 and December 31, 2008		3

Consolidated Condensed Statements of Cash Flows (Unaudited) — Six months ended June 30, 2009 and 2008		4

Notes to Unaudited Consolidated Condensed Financial Statements		5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		16

Item 3. Quantitative and Qualitative Disclosures About Market Risk		28

Item 4. Controls and Procedures		28

PART II — OTHER INFORMATION

Item 1. Legal Proceedings		30

Item 1A. Risk Factors		30

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		30

Item 3. Defaults Upon Senior Securities		31

Item 4. Submission of Matters to a Vote of Security Holders		31

Item 5. Other Information		31

Item 6. Exhibits		31

Signatures		32
EX-10.1
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT


	BAKER HUGHES INCORPORATED (Registrant)
Date: August 6, 2009	By:	/s/PETER A. RAGAUSS
		Peter A. Ragauss
		Senior Vice President and Chief Financial Officer


Date: August 6, 2009	By:	/s/ALAN J. KEIFER
		Alan J. Keifer
		Vice President and Controller

Balance Sheet

Location

Fair Value

Foreign Currency Forward Contracts

Other accrued liabilities

Interest Rate Swaps

Other assets