Edgar Filing: BAKER HUGHES INC

e10vq

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 September 30, 2008


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 (State or other jurisdiction of incorporation or organization)		76-0207995 (I.R.S. Employer Identification No.)

2929 Allen Parkway, Suite 2100, Houston, Texas (Address of principal executive offices)		77019-2118 (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 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 October 24, 2008, the registrant has outstanding 307,530,773 shares of Common Stock, $1 par value per share.

INDEX


		Page No.

PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)

	Consolidated Condensed Statements of Operations (Unaudited) - Three months and nine months ended September 30, 2008 and 2007		2

	Consolidated Condensed Balance Sheets (Unaudited) - September 30, 2008 and December 31, 2007		3

	Consolidated Condensed Statements of Cash Flows (Unaudited) - Nine months ended September 30, 2008 and 2007		4

	Notes to Unaudited Consolidated Condensed Financial Statements		5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		17

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		30

Item 4.	Controls and Procedures		30

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings		31

Item 1A.	Risk Factors		31

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		32

Item 3.	Defaults Upon Senior Securities		32

Item 4.	Submission of Matters to a Vote of Security Holders		32

Item 5.	Other Information		32

Item 6.	Exhibits		32

Signatures			34
EX-3.2
EX-31.1
EX-31.2
EX-32

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						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007

Revenues:
Sales	$	1,446.2		$	1,359.5		$	4,164.5		$	3,819.4
Services and rentals		1,563.4			1,318.1			4,513.0			3,868.5

Total revenues		3,009.6			2,677.6			8,677.5			7,687.9


Costs and expenses:
Cost of sales		1,031.9			906.7			2,951.8			2,600.0
Cost of services and rentals		995.9			859.1			2,842.0			2,437.5
Research and engineering		103.2			94.2			311.9			278.4
Marketing, general and administrative		278.2			235.0			798.6			692.1
Litigation settlement		—			—			62.0			—

Total costs and expenses		2,409.2			2,095.0			6,966.3			6,008.0


Operating income		600.4			582.6			1,711.2			1,679.9
Equity in income (loss) of affiliates		(0.2	)		—			1.5			0.4
Gain on sale of product line		—			—			28.2			—
Interest expense		(20.5	)		(16.7	)		(53.3	)		(49.7	)
Interest and dividend income		9.9			10.5			22.1			32.7


Income before income taxes		589.6			576.4			1,709.7			1,663.3
Income taxes		(160.7	)		(187.3	)		(506.5	)		(549.9	)

Net income	$	428.9		$	389.1		$	1,203.2		$	1,113.4


Basic earnings per share	$	1.40		$	1.23		$	3.91		$	3.49

Diluted earnings per share	$	1.39		$	1.22		$	3.89		$	3.47

See accompanying notes to unaudited consolidated condensed financial statements.

Baker Hughes Incorporated
Consolidated Condensed Balance Sheets
(In millions)


	September 30,			December 31,
	2008			2007
	(Unaudited)

ASSETS

Current Assets:
Cash and cash equivalents	$	1,127.0		$	1,054.4
Accounts receivable, net		2,794.6			2,382.9
Inventories		1,988.8			1,714.4
Deferred income taxes		212.2			181.5
Other current assets		175.9			122.4

Total current assets		6,298.5			5,455.6

Property, plant and equipment		2,623.1			2,344.6
Goodwill		1,397.1			1,354.2
Intangible assets, net		180.7			176.6
Other assets		508.2			525.6

Total assets	$	11,007.6		$	9,856.6


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Accounts payable	$	824.8		$	704.2
Short-term borrowings and current portion of long-term debt		589.1			15.4
Accrued employee compensation		515.6			456.8
Income taxes payable		130.5			190.9
Other accrued liabilities		260.1			250.6

Total current liabilities		2,320.1			1,617.9

Long-term debt		1,041.4			1,069.4
Deferred income taxes and other tax liabilities		435.3			415.6
Liabilities for pensions and other postretirement benefits		323.6			332.1
Other liabilities		101.3			116.0
Commitments and contingencies

Stockholders’ Equity:
Common stock		307.9			315.4
Capital in excess of par value		713.3			1,216.1
Retained earnings		5,894.9			4,818.3
Accumulated other comprehensive loss		(130.2	)		(44.2	)

Total stockholders’ equity		6,785.9			6,305.6

Total liabilities and stockholders’ equity	$	11,007.6		$	9,856.6

See accompanying notes to unaudited consolidated condensed financial statements.

Baker Hughes Incorporated
Consolidated Condensed Statements of Cash Flows
(In millions)
(Unaudited)


	Nine Months Ended
	September 30,
	2008			2007

Cash flows from operating activities:
Income from continuing operations	$	1,203.2		$	1,113.4
Adjustments to reconcile income from continuing operations to net cash flows from operating activities:
Depreciation and amortization		460.6			380.3
Amortization of net deferred gains on derivatives		(3.8	)		(3.8	)
Stock-based compensation costs		47.2			40.0
Benefit for deferred income taxes		(7.7	)		(28.4	)
Gain on sale of product line		(28.2	)		—
Gain on disposal of assets		(73.5	)		(70.3	)
Equity in income of affiliates		(1.5	)		(0.4	)
Changes in operating assets and liabilities:
Accounts receivable		(415.8	)		(257.6	)
Inventories		(277.8	)		(160.8	)
Accounts payable		141.5			(31.6	)
Accrued employee compensation and other accrued liabilities		23.2			(203.1	)
Income taxes payable		(66.2	)		103.5
Income taxes paid on sale of interest in affiliate		—			(111.7	)
Other		(35.7	)		20.1

Net cash flows from operating activities		965.5			789.6


Cash flows from investing activities:
Expenditures for capital assets		(839.4	)		(811.1	)
Proceeds from disposal of property, plant and equipment		141.6			146.2
Proceeds from sale of product line		31.0			—
Acquisition of businesses, net of cash acquired		(81.5	)		—
Purchases of short-term investments		—			(2,520.7	)
Proceeds from maturities of short-term investments		—			2,812.2

Net cash flows from investing activities		(748.3	)		(373.4	)


Cash flows from financing activities:
Net borrowings of short-term debt		547.2			3.2
Repurchases of common stock		(610.6	)		(280.0	)
Proceeds from issuance of common stock		51.4			50.8
Dividends		(126.6	)		(124.5	)
Excess tax benefits from stock-based compensation		2.4			6.1

Net cash flows from financing activities		(136.2	)		(344.4	)


Effect of foreign exchange rate changes on cash		(8.4	)		24.0

Increase in cash and cash equivalents		72.6			95.8
Cash and cash equivalents, beginning of period		1,054.4			750.0

Cash and cash equivalents, end of period	$	1,127.0		$	845.8


Income taxes paid (net of refunds)	$	578.0		$	580.8
Interest paid	$	73.8		$	67.9

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 (“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, 2007. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year.

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

Reclassifications

During the fourth quarter of 2007, we began classifying certain expenses as cost of sales and cost of services and rentals that were previously classified as selling, general and administrative expenses. The change was the result of an internal review to improve management reporting. The reclassified expenses relate to selling and field service costs which are closely related to operating activities. In addition, we have renamed selling, general and administrative expenses on the statement of operations to marketing, general and administrative expenses to more accurately describe the costs included therein. The impact of these reclassifications for the three months ended September 30, 2007 is to increase cost of sales by $92.8 million; increase cost of services and rentals by $32.5 million and decrease marketing, general and administrative expenses by $125.3 million and for the nine months ended September 30, 2007 is to increase cost of sales by $269.9 million; increase cost of services and rentals by $88.5 million and decrease marketing, general and administrative expenses by $358.4 million. These reclassifications had no impact on total costs and expenses as these changes offset one another. All prior periods have been reclassified to conform to this new presentation.

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. SFAS 157 was originally effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In November 2007, the FASB placed a one year deferral for the implementation of SFAS 157 for nonfinancial assets and liabilities; however, SFAS 157 is effective for fiscal years beginning after November 15, 2007 for financial assets and liabilities. We adopted all requirements of SFAS 157 on January 1, 2008, except as they relate to nonfinancial assets and liabilities, which will be adopted on January 1, 2009, as allowed under SFAS 157. See “Note 9. Fair Value of Certain Financial Assets” for further information on the impact of this standard to financial assets and liabilities. We have not yet determined the impact, if any, on our consolidated condensed financial statements for nonfinancial assets and liabilities.

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

financial position is effective for fiscal years ending after December 15, 2008. We adopted all requirements of SFAS 158 on December 31, 2006, except for the funded status measurement date requirement, which will be adopted on December 31, 2008, as allowed under SFAS 158. We estimate the impact of moving our funded status measurement date from our current measurement date of October 1^st to December 31^st to be a reduction of approximately $1.6 million to beginning retained earnings which will be recorded in December 2008.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115 (“SFAS 159”). SFAS 159 permits entities to choose to measure eligible financial assets and liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We adopted SFAS 159 on January 1, 2008, and there was no impact on our consolidated condensed financial statements as we did not choose to measure any eligible financial assets or liabilities at fair value.

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 in its consolidated financial statements. SFAS 160 is effective for fiscal years beginning after December 15, 2008. We will adopt SFAS 160 on January 1, 2009, and have not yet determined the impact, if any, on our consolidated condensed financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS 141R”). SFAS 141R 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, including the requirement that most transaction and restructuring costs related to the acquisition be expensed. In addition, the statement requires disclosures to enable users to evaluate the nature and financial effects of the business combination. SFAS 141R is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We will adopt SFAS 141R on January 1, 2009 for acquisitions on or after this date.

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, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in hedged positions. The statement also requires enhanced disclosures regarding how and why entities use derivative instruments, how derivative instruments and related hedged items are accounted and how derivative instruments and related hedged items affect entities’ financial position, financial performance, and cash flows. SFAS 161 is effective for fiscal years beginning after November 15, 2008. We will adopt the new disclosure requirements of SFAS 161 in the first quarter of 2009.

In April 2008, the FASB issued FASB Staff Position SFAS 142-3, Determination of the Useful Life of Intangible Assets (“FSP SFAS 142-3”). FSP SFAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, Goodwill and Other Intangible Assets. The objective of this FSP is to improve the consistency between the useful life of a recognized intangible asset under Statement 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141R, Business Combinations, and other U.S. GAAP principles. FSP SFAS 142-3 is effective for fiscal years beginning after December 15, 2008. We will adopt FSP SFAS 142-3 on January 1, 2009 and have not yet determined the impact, if any, on our consolidated condensed financial statements.

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 $31.0 million. The SSS assets sold included hydraulic and pneumatic actuators, bonnet assemblies and control systems. We recorded a pre-tax gain of $28.2 million ($18.4 million after-tax).

NOTE 3. ACQUISITIONS

In April 2008, we acquired two reservoir consulting firms – Gaffney, Cline & Associates (“GCA”) and GeoMechanics International (“GMI”) – for $76.9 million in cash, including $3.5 million of direct transaction costs. These firms provide consulting services related to reservoir engineering, technical and managerial advisory services and reservoir geomechanics. As a result of these acquisitions, we recorded $42.9 million of goodwill and $18.9 million of intangibles, both subject to final purchase accounting

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

adjustments. Pro forma results of operations have not been presented because the effect of these acquisitions was not material to our consolidated condensed financial statements. Under the terms of the purchase agreements, we may be required to make additional payments of up to approximately $46.0 million based on the performance of the businesses during 2008, 2009 and 2010.

NOTE 4. 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. We also have an Employee Stock Purchase Plan available for eligible employees to purchase shares of our common stock at a 15% discount. We recorded total stock-based compensation expense of $18.1 million and $15.9 million for the three months ended September 30, 2008 and 2007, respectively, and $47.2 million and $40.0 million for the nine months ended September 30, 2008 and 2007, respectively.

Stock Options

Our stock option plans provide for the issuance of incentive and non-qualified stock options to directors, officers and other key employees at an exercise price equal to the market price of our common stock on the date of grant. We typically grant options twice a year in the first and third quarters.

The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes option pricing model. The following table presents the weighted-average assumptions used in the option pricing model for the nine months ended September 30, 2008 and 2007.


	2008			2007

Expected life (years)		5.5			5.1
Risk-free interest rate		3.1	%		4.8	%
Volatility		31.3	%		28.6	%
Dividend yield		0.8	%		0.7	%
Weighted-average fair value per share at grant date	$	23.72		$	24.20

We granted 694,800 options during the nine months ended September 30, 2008 at a weighted-average exercise price per option of $73.84.

Restricted Stock Awards and Units

In addition to stock options, the directors, officers and key employees may be granted restricted stock awards (“RSA”), which is an award of common stock with no exercise price, or restricted stock units (“RSU”), where each unit represents the right to receive at the end of a stipulated period one unrestricted share of stock with no exercise price. We typically grant RSAs and RSUs once a year in January. We determine the fair value of restricted stock awards and restricted stock units based on the market price of our common stock on the date of grant.

We granted 524,528 RSAs and 255,438 RSUs during the nine months ended September 30, 2008 at a weighted-average value per award or unit of $73.01 and $76.31, respectively.

Employee Stock Purchase Plan

Our Employee Stock Purchase Plan (“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. We determined the fair value of our ESPP shares using the Black-Scholes option pricing model with the following assumptions.

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


	2008			2007

Expected life (years)		1.0			1.0
Risk-free interest rate		3.2	%		4.9	%
Volatility		32.8	%		30.5	%
Dividend Yield		0.6	%		0.7	%
Weighted-average fair value per share	$	11.43		$	10.39

Based on contributions as currently elected by eligible employees and based on our stock price at the end of September 2008 of $63.40, we estimate we will issue approximately 756,000 shares under the ESPP on or around January 1, 2009.

NOTE 5. EARNINGS AND CASH DIVIDENDS PER SHARE

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007

Weighted average common shares outstanding for basic EPS		306.7		317.6		307.7		318.6
Effect of dilutive securities — stock plans		1.6		2.2		1.6		2.1

Adjusted weighted average common shares outstanding for diluted EPS		308.3		319.8		309.3		320.7


Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than the average market price for the period		0.9		—		0.9		0.6


Cash dividends per share	$	0.15	$	0.13	$	0.41	$	0.39

NOTE 6. INVENTORIES

Inventories are comprised of the following:


	September 30,		December 31,
	2008		2007

Finished goods	$	1,642.1	$	1,414.0
Work in process		205.5		177.5
Raw materials		141.2		122.9

Total	$	1,988.8	$	1,714.4

NOTE 7. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are comprised of the following:


	September 30,			December 31,
	2008			2007

Land	$	72.0		$	62.0
Buildings and improvements		834.5			774.7
Machinery and equipment		2,995.0			2,745.0
Rental tools and equipment		1,943.8			1,739.3

Subtotal		5,845.3			5,321.0
Accumulated depreciation		(3,222.2	)		(2,976.4	)

Total	$	2,623.1		$	2,344.6

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

NOTE 8. 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, 2007	$	914.0		$	440.2	$	1,354.2
Goodwill from acquisitions during the period		42.9			2.0		44.9
Translation adjustments and other		(2.2	)		0.2		(2.0	)

Balance as of September 30, 2008	$	954.7		$	442.4	$	1,397.1

Intangible assets are comprised of the following:


	September 30, 2008							December 31, 2007
	Gross							Gross
	Carrying		Accumulated					Carrying		Accumulated
	Amount		Amortization			Net		Amount		Amortization			Net

Technology-based	$	250.9	$	(117.6	)	$	133.3	$	240.6	$	(105.1	)	$	135.5
Contract-based		15.2		(10.3	)		4.9		15.1		(9.2	)		5.9
Marketing-related		9.9		(6.0	)		3.9		5.7		(5.7	)		—
Customer-based		18.0		(4.9	)		13.1		13.6		(3.8	)		9.8
Other		0.3		(0.3	)		—		0.3		(0.3	)		—

Total amortizable intangible assets		294.3		(139.1	)		155.2		275.3		(124.1	)		151.2
Marketing-related intangible assets with indefinite useful lives		25.5		—			25.5		25.4		—			25.4

Total	$	319.8	$	(139.1	)	$	180.7	$	300.7	$	(124.1	)	$	176.6

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 estimated economic benefits of the intangible assets are consumed, which range from 15 to 30 years.

Amortization expense for intangible assets included in net income for the three and nine months ended September 30, 2008 was $5.2 million and $15.3 million, respectively, and is estimated to be $20.4 million for the year 2008. Estimated amortization expense for each of the subsequent five fiscal years is expected to be as follows: 2009 – $19.9 million; 2010 – $16.5 million; 2011 – $14.8 million; 2012 – $13.4 million; and 2013 – $13.1 million.

NOTE 9. FAIR VALUE OF CERTAIN FINANCIAL ASSETS AND LIABILITIES

On January 1, 2008, we adopted the methods of fair value as described in SFAS 157 to value certain of our financial assets and liabilities. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the reporting date. The statement establishes consistency and comparability by providing a fair value 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).

SFAS 157 requires the use of observable market inputs (quoted market prices) when measuring fair value whenever possible and requires a Level 1 quoted price be used to measure fair value whenever possible.

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

Financial assets and liabilities included in our financial statements and measured at fair value as of September 30, 2008 are classified based on the valuation technique level in the table below:


			Fair Value Measurement at September 30, 2008
Description	Total		Level 1		Level 2		Level 3

Assets:
Auction rate securities	$	28.1	$	—	$	—	$	28.1
Non-qualified defined contribution plan assets		124.4		124.4		—		—

Total assets at fair value	$	152.5	$	124.4	$	—	$	28.1


Liabilities:

Non-qualified defined contribution plan liabilities	$	124.4	$	124.4	$	—	$	—

Auction Rate Securities

Our auction rate securities (“ARS”) have been designated as “available-for-sale” securities. As of September 30, 2008, our ARS investments, which consist of credit linked notes, carried split ratings ranging from AAA to A-, as provided by Standard & Poor’s and Fitch rating agencies. These notes 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. Our ARS investments do not include any mortgage-backed securities. Since September 2007, we have been unable to sell our ARS investments because of unsuccessful auctions. As a result of the unsuccessful auctions and the downgrade in credit quality, the interest rate for each certificate resets every 28 days at one month LIBOR plus a spread determined by each certificate’s lowest assigned rating.

We utilized Level 3 inputs to estimate the fair value of our ARS investments based on the underlying structure of each security and their collateral values, including assessments of counterparty credit quality, default risk underlying the security, expected cash flows, discount rates and overall capital market liquidity. Based on this analysis, we estimate the fair value of our ARS investments to be $28.1 million as of September 30, 2008. The fair value of the securities at September 30, 2008, did not change from the beginning of the quarterly period. The valuation of our ARS investments is subject to uncertainties that are difficult to predict and require significant judgment. The fair value of our ARS investments could change significantly in the future based on various factors including changes to credit ratings of the securities as well as to the underlying assets supporting those securities, rates of default of the underlying assets, underlying collateral value, discount rates and counterparty risk. 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 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 1 inputs at the reporting date and were based on quoted market prices from various major stock exchanges.

Nonfinancial Assets and Liabilities

In November 2007, the FASB placed a one year deferral for the implementation of SFAS 157 for nonfinancial assets and liabilities. Accordingly, we will adopt the methods of fair value described in SFAS 157 for nonfinancial assets and liabilities on January 1, 2009. We have not yet determined the impact, if any, on our consolidated condensed financial statements for these nonfinancial assets and liabilities, which include, but are not limited to, goodwill, assets held for sale and asset retirement obligations.

NOTE 10. FINANCIAL INSTRUMENTS

Foreign Currency Forward Contracts

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

Krone and the Brazilian Real. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of September 30, 2008 for contracts with similar terms and maturity dates, we recorded a gain of $0.9 million to adjust these foreign currency forward contracts to their fair market value. This gain offsets designated foreign exchange losses resulting from the underlying exposures and is included in marketing, general and administrative expenses in our consolidated condensed statement of operations.

NOTE 11. INDEBTEDNESS

On March 3, 2008, we initiated a commercial paper program (the “Program”) under which we may issue from time to time unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time of $500.0 million. On April 2, 2008, we increased the Program to an aggregate of $1.0 billion. The proceeds of the Program are used for general corporate purposes, including working capital, capital expenditures, acquisitions and share repurchases. Commercial paper issued under the Program is scheduled to mature within approximately 270 days of issuance. The commercial paper is not redeemable prior to maturity and will not be subject to voluntary prepayment. At September 30, 2008, we had $557.5 million outstanding in commercial paper at a weighted average interest rate of 2.03%.

On April 1, 2008, we entered into a credit agreement (the “2008 Credit Agreement”) for a committed $500.0 million revolving credit facility that expires in March 2009. The 2008 Credit Agreement contains certain covenants, which, among other things, require the maintenance of a funded indebtedness to total capitalization ratio (a defined formula per the agreement) of less than or equal to 0.60, 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 2008 Credit Agreement may be accelerated. Such events of default include payment defaults to lenders under the 2008 Credit Agreement, covenant defaults and other customary defaults.

At September 30, 2008, we had $1,535.7 million of credit facilities with commercial banks, of which $1.0 billion are committed revolving credit facilities, which includes the 2008 Credit Agreement. The committed facilities expire on July 7, 2012 ($500.0 million), unless extended, and on March 31, 2009 ($500.0 million). There were no direct borrowings under the facilities during the nine months ended September 30, 2008; however, to the extent we have outstanding commercial paper, our ability to borrow under the facilities is reduced.

At September 30, 2008, we have short-term borrowings and current portion of long-term debt of $1,089.1 million. When applicable, based on our liquidity and other requirements, we classify short-term borrowings and current portion of long-term debt as long-term to the extent of our long-term committed facility that expires in 2012 because we have the ability under this facility and the intent to maintain these obligations for longer than one year. Accordingly, we have classified $500.0 million as long-term debt and $589.1 million as short-term debt at September 30, 2008.

On October 28, 2008, we sold $500.0 million of 6.50% Senior Notes that will mature November 15, 2013, and $750.0 million of 7.50% Senior Notes that will mature November 15, 2018. See “Note 17. Subsequent Event” for a more detailed description of the issuance of the notes.

NOTE 12. 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. We report results for our product-line focused divisions under two segments: the Drilling and Evaluation segment and the Completion and Production segment. We have aggregated the divisions within each segment because they have similar economic characteristics and because the long-term financial performance of these divisions 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 results of each segment are evaluated regularly by our chief operating decision maker in deciding how to allocate resources and in assessing performance.

•

The Drilling and Evaluation segment consists of the Baker Hughes Drilling Fluids (drilling fluids), Hughes Christensen (oilfield drill bits), INTEQ (drilling, measurement-while-drilling and logging-while-drilling) and Baker Atlas (wireline formation evaluation and wireline completion services) divisions and also includes GCA and GMI, our newly acquired reservoir consulting firms. 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 Baker Oil Tools (workover, fishing and completion equipment), Baker Petrolite (oilfield specialty chemicals), Centrilift (electric submersible pumps and progressing cavity pumps) divisions, the ProductionQuest (production optimization and permanent monitoring) business unit, and 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, and interest and dividend income. The “Corporate and Other” segment loss includes corporate expenses, interest expense, interest and dividend income and certain gains and losses not allocated to the segments. During the fourth quarter of 2007, we started allocating certain expenses, previously reported in “Corporate and Other” to the Drilling and Evaluation and Completion and Production segments. These expenses consist of administrative operations support costs that are more closely related to operating activities. The impact of this allocation was a reduction to “Corporate and Other” segment loss of $4.2 million for the three months ended September 30, 2007 and $10.6 million for the nine months ended September 30, 2007. All prior periods have been reclassified to conform to this new presentation.


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

*Revenues*
Three months ended September 30, 2008	$	1,558.1	$	1,451.4	$	3,009.5	$	0.1		$	3,009.6
Three months ended September 30, 2007		1,356.0		1,321.8		2,677.8		(0.2	)		2,677.6

Nine months ended September 30, 2008	$	4,476.1	$	4,201.3	$	8,677.4	$	0.1		$	8,677.5
Nine months ended September 30, 2007		3,923.2		3,764.7		7,687.9		—			7,687.9

*Segment profit (loss)*
Three months ended September 30, 2008	$	346.6	$	322.8	$	669.4	$	(79.8	)	$	589.6
Three months ended September 30, 2007		357.1		287.2		644.3		(67.9	)		576.4

Nine months ended September 30, 2008	$	1,062.9	$	908.5	$	1,971.4	$	(261.7	)	$	1,709.7
Nine months ended September 30, 2007		1,048.8		797.4		1,846.2		(182.9	)		1,663.3

*Total assets*
As of September 30, 2008	$	5,365.1	$	4,524.5	$	9,889.6	$	1,118.0		$	11,007.6
As of December 31, 2007		4,720.4		4,095.9		8,816.3		1,040.3			9,856.6

The following table presents the details of the segment profit (loss) for “Corporate and Other”:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007

Corporate and other expenses	$	(69.2	)	$	(61.7	)	$	(196.7	)	$	(165.9	)
Litigation settlement		—			—			(62.0	)		—
Gain on sale of product line		—			—			28.2			—
Interest expense		(20.5	)		(16.7	)		(53.3	)		(49.7	)
Interest and dividend income		9.9			10.5			22.1			32.7

Total	$	(79.8	)	$	(67.9	)	$	(261.7	)	$	(182.9	)

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

NOTE 13. 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.

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


													Other Postretirement
	U.S. Pension Benefits						Non-U.S. Pension Benefits						Benefits
	2008			2007			2008			2007			2008		2007

Service cost	$	7.6		$	7.9		$	0.7		$	0.7		$	2.1	$	1.9
Interest cost		4.3			3.9			4.4			4.4			2.3		2.2
Expected return on plan assets		(9.6	)		(8.6	)		(5.5	)		(4.8	)		—		—
Amortization of prior service cost		0.1			0.2			—			—			0.3		0.3
Amortization of net loss		0.1			0.1			0.3			0.7			—		—

Net periodic benefit cost/(income)	$	2.5		$	3.5		$	(0.1	)	$	1.0		$	4.7	$	4.4

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


													Other Postretirement
	U.S. Pension Benefits						Non-U.S. Pension Benefits						Benefits
	2008			2007			2008			2007			2008		2007

Service cost	$	22.8		$	23.7		$	2.1		$	2.1		$	6.3	$	5.7
Interest cost		12.9			11.7			13.2			13.2			6.9		6.6
Expected return on plan assets		(28.8	)		(25.8	)		(16.5	)		(14.4	)		—		—
Amortization of prior service cost		0.3			0.6			—			—			0.9		0.9
Amortization of net loss		0.3			0.3			0.9			2.1			—		—

Net periodic benefit cost	$	7.5		$	10.5		$	(0.3	)	$	3.0		$	14.1	$	13.2

NOTE 14. GUARANTEES

In the normal course of business with customers, vendors and others, we have entered into off-balance sheet arrangements, such as surety bonds, performance letters of credit and other bank issued guarantees, which totaled approximately $639.9 million at September 30, 2008. None of the off-balance sheet arrangements either has, or is likely to have, a material effect on our consolidated condensed financial statements.

We sell certain products with a product warranty that provides that customers can return a defective product during a specified warranty period following the purchase in exchange for a replacement product, repair at no cost to the customer or the issuance of a credit to the customer. We accrue amounts for estimated warranty claims based upon current and historical product sales data, warranty costs incurred and any other related information known to us.

The changes in the aggregate product warranty liabilities for the nine months ended September 30, 2008 are as follows:



Balance as of December 31, 2007	$	14.8
Claims paid or settled		(8.1	)
Additional warranties issued		3.9
Revisions in estimates of previously issued warranties		(0.3	)
Other		(0.3	)

Balance as of September 30, 2008	$	10.0

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

NOTE 15. 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					Nine Months Ended
	September 30,					September 30,
	2008			2007		2008			2007

Net income	$	428.9		$	389.1	$	1,203.2		$	1,113.4
Other comprehensive income (loss):
Foreign currency translation adjustments during the period		(101.3	)		38.4		(81.4	)		79.5
Pension and other postretirement benefits		5.0			0.1		2.9			(0.5	)
Unrealized loss on available-for-sale securities		—			—		(7.5	)		—

Total comprehensive income	$	332.6		$	427.6	$	1,117.2		$	1,192.4

Total accumulated other comprehensive loss consisted of the following:


	September 30,			December 31,
	2008			2007

Foreign currency translation adjustments	$	(69.5	)	$	11.9
Pension and other postretirement benefits		(53.2	)		(56.1	)
Unrealized loss on available-for-sale securities		(7.5	)		—

Total accumulated other comprehensive loss	$	(130.2	)	$	(44.2	)

NOTE 16. LITIGATION

We are involved in litigation or proceedings that have arisen in our 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 March 29, 2002, we announced that we had been advised that the SEC and the Department Of Justice (“DOJ”) were conducting investigations into allegations of violations of law relating to Nigeria and other related matters. The SEC issued a formal order of investigation into possible violations of provisions under the Foreign Corrupt Practices Act (“FCPA”) regarding antibribery, books and records and internal controls. In connection with the investigations, the SEC issued subpoenas seeking information about our operations in Angola (subpoena dated August 6, 2003) and Kazakhstan (subpoenas dated August 6, 2003 and April 22, 2005) as part of its ongoing investigation. We provided documents to and cooperated fully with the SEC and DOJ. In addition, we conducted internal investigations into these matters. Our internal investigations identified issues regarding the propriety of certain payments and apparent deficiencies in our books and records and internal controls with respect to certain operations in Angola, Kazakhstan and Nigeria, as well as potential liabilities to government authorities in Nigeria. Evidence obtained during the course of the investigations was provided to the SEC and DOJ.

On April 26, 2007, the United States District Court, Southern District of Texas, Houston Division (the “Court”) unsealed a three-count criminal information that had been filed against us as part of the execution of a Deferred Prosecution Agreement (the “DPA”) between us and the DOJ. The three counts arise out of payments made to an agent in connection with a project in Kazakhstan and include conspiracy to violate the 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 relate to our operations in Kazakhstan during the period from 2000 to 2003. Although we did not plead guilty to that information, we face prosecution under that information, and possibly under other charges as well, if we fail to comply with the terms of the DPA. Those terms include, for the two-year term of the DPA, full cooperation with the government; compliance with all federal criminal law, including but not limited to the FCPA; and adoption of a Compliance Code containing specific provisions intended to prevent violations of the FCPA. The DPA also requires us to retain an independent monitor for a term of three years to assess and make recommendations about our compliance policies and procedures and our implementation of those procedures. Provided that we comply with the DPA, the DOJ has agreed not to prosecute us for violations of the FCPA based

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

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 the same date, 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 (the “SEC Order”) against us in the Court. The SEC Complaint and the SEC 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 SEC Complaint, and also consented to the entry of the SEC Order. The SEC Complaint alleges 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 SEC’s cease and desist order of September 12, 2001. The SEC Order became effective on May 1, 2007, which is the date it was confirmed by the Court. The SEC 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, $44.1 million ($11 million in criminal penalties, $10 million in civil penalties, $19.9 million in disgorgement of profits and $3.2 million in pre-judgment interest) to settle these investigations. In the fourth quarter of 2006, we recorded a financial charge for the potential settlement.

We retained in 2007 and the SEC and DOJ approved an independent monitor to assess our FCPA compliance policies and procedures for the specified three-year period. During March 2008, the independent monitor provided us with his initial recommendations relating to our compliance policies and procedures, primarily in the areas of internal controls, internal audit, agent due diligence, customs, training, human resources, and related matters. Consistent with the monitor’s recommendations, we are continuing the comprehensive compliance activities we already have in place, enhancing and streamlining some of those activities, initiating additional activities and expediting the introduction of certain previously planned compliance related activities.

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 is pending in the Houston Division of the United States District Court for the Southern District of Texas. An estimate of the possible loss or range of loss in connection with this lawsuit cannot be made. However, we do not expect this lawsuit to have a material adverse effect on our consolidated condensed financial statements.

On May 12, 2006, Baker Hughes Oilfield Operations, Inc. (“BHOO”), a subsidiary of the Company, was named as a defendant in a lawsuit in the United States District Court, Eastern District of Texas brought by ReedHycalog against BHOO and other third parties arising out of alleged patent infringement relating to the sale of certain diamond drill bits utilizing certain types of polycrystalline diamond cutters sold by our Hughes Christensen division (the “ReedHycalog Claims”). On May 22, 2008, we reached an agreement for reciprocal licenses with ReedHycalog, now a division of National Oilwell Varco, Inc. regarding the ReedHycalog Claims and

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

related Baker Hughes counter-claims. As part of the agreement, the Company and ReedHycalog have agreed to a cross-license of the disputed technologies. As a result, in June 2008, the Company paid ReedHycalog $70.0 million in royalties for prior use of certain patented technologies, and ReedHycalog paid the Company $8.0 million in royalties for the license of certain Company patented technologies. The net pre-tax charge of $62.0 million for the settlement of this litigation is reflected in the consolidated condensed statement of operations for the nine months ended September 30, 2008. In addition, the Company will pay a minimum of $30.0 million in royalties for future use. Pursuant to the agreement, BHOO is dismissed from all claims and has released ReedHycalog from all counter-claims, in connection with the previously disclosed litigation.

NOTE 17. SUBSEQUENT EVENT

On October 28, 2008, we sold $500.0 million of 6.50% Senior Notes that will mature November 15, 2013, and $750.0 million of 7.50% Senior Notes that will mature November 15, 2018 (collectively, the “Notes”). We intend to use a portion of the net proceeds of the Notes to repay $325.0 million aggregate principal amount of our outstanding 6.25% notes, which mature on January 15, 2009, and $200.0 million aggregate principal amount of our outstanding 6.00% notes, which mature on February 15, 2009. We will use the remaining net proceeds from the offering for general corporate purposes, which could include repaying outstanding commercial paper and funding on-going operations, business acquisitions and repurchases of our common stock. Net proceeds from the offering were approximately $1,235.5 million after deducting the underwriting discounts and estimated expenses of the offering. Interest on the Notes is payable May 15 and November 15 of each year. The first interest payment will be made on May 15, 2009, and will consist of accrued interest from October 28, 2008. The Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to any future subordinated indebtedness; and effectively junior to our future secured indebtedness, if any, and to all existing and future indebtedness of our subsidiaries. We may redeem, at our option, all or part of the Notes at any time, at the applicable make-whole redemption prices plus accrued and unpaid interest to the date of redemption.

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, 2007 (“2007 Annual Report).

EXECUTIVE SUMMARY

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. We report our results under two segments – Drilling and Evaluation and Completion and Production – which are aligned by product line based upon the types of products and services provided to our customers and upon the business characteristics of the divisions during business cycles. In April 2008, we acquired two reservoir consulting firms – Gaffney, Cline & Associates (“GCA”) and GeoMechanics International (“GMI”). These firms provide consulting services related to reservoir engineering, technical and managerial advisory services and reservoir geomechanics and are included in the Drilling and Evaluation segment.

	•		The Drilling and Evaluation segment consists of the Baker Hughes Drilling Fluids (drilling fluids), Hughes Christensen (oilfield drill bits), INTEQ (drilling, measurement-while-drilling and logging-while-drilling) and Baker Atlas (wireline formation evaluation and wireline completion services) divisions and also includes GCA and GMI, our newly acquired reservoir consulting firms. 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.

	•		The Completion and Production segment consists of the Baker Oil Tools (workover, fishing and completion equipment), Baker Petrolite (oilfield specialty chemicals), Centrilift (electric submersible pumps and progressing cavity pumps) divisions, the ProductionQuest (production optimization and permanent monitoring) business unit, and 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 business operations of our divisions are organized around four primary geographic regions: North America; Latin America; Europe, Africa, Russia and the Caspian; and Middle East, Asia Pacific. Each region has a council comprised of regional vice presidents from each division and representatives from various functions as deemed necessary. The regional vice presidents report directly to each division president. Through this structure, we have placed our management close to our customers, improving our customer relationships and allowing us to react more quickly to local market conditions and needs.

We operate in over 90 countries around the world and our corporate headquarters are in Houston, Texas. We have significant manufacturing operations in various countries, including, but not limited to, the United States (Texas, Oklahoma and Louisiana), the U.K. (Aberdeen, East Kilbride and Belfast), Germany (Celle), and Venezuela (Maracaibo). As of September 30, 2008, we had approximately 38,300 employees. Approximately 57% of our employees work outside the U.S.

BUSINESS ENVIRONMENT

Our business environment and its corresponding operating results are significantly affected 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 risk-adjusted costs to find, develop, and produce reserves; and their forecasts of available cash from sales of oil and gas as well as access to debt and equity markets to fund their exploration and production spending. 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, declining oil prices, lower natural gas prices, and a weakening global economic outlook 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 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 mid-summer highs has also negatively impacted our customers’ operational cash flow, further challenging their ability to continue to operate at recent levels as well as their future spending for our products and services. Last, the economic slowdown is also negatively impacting the incremental demand for hydrocarbon products especially in OECD (“Organization for Economic Cooperation and Development”) countries.

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				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007

Oil prices ($/Bbl)	$	118.23	$	75.24	$	113.54	$	66.18
Natural gas prices ($/mmBtu)		9.06		6.18		9.71		6.96

Oil prices averaged $118.23/Bbl in the third quarter of 2008. Prices ranged from a high of $145.29/Bbl in early July to a quarter low of $91.15/Bbl in mid September. Subsequent to the end of the third quarter of 2008, oil prices dropped to the mid $60s/Bbl closing on October 24, 2008 at $63.15/Bbl. The decrease in oil prices reflects concerns about slowing worldwide demand. In its October 2008 Oil Market Report, the International Energy Agency (“IEA”) lowered its forecast for global oil demand in 2008 and 2009 due to weaker demand in OECD countries. Reflecting at least some of the changes in the global economic outlook, the IEA now expects global oil demand to increase 0.5% to 86.5 million barrels per day in 2008, up 0.4 million barrels per day from an estimated 86.1 million barrels per day in 2007.

Natural gas prices averaged $9.06/mmBtu in the third quarter of 2008. Natural gas prices decreased from a quarter high of $13.28/mmBtu in early July to a low of $7.10/mmBtu at September quarter end. Subsequent to the end of the third quarter of 2008, gas prices dropped to close at $6.27/mmBtu on October 24, 2008. The decrease in natural gas prices reflects strong year-on-year production growth from development of onshore fields, mild weather and lower oil prices. The increase in production has more than offset the impact of moderate demand growth and lower imports of liquefied natural gas (“LNG”) in 2008 compared to 2007. In its October 2008 Short-term Energy and Winter Fuels Outlook, the U.S. Department of Energy’s Energy Information Administration (“EIA”) projected that U.S. marketed natural gas production would increase by 6.7% in 2008 compared to 2007. Reflecting at least some of the changes in the global economic outlook, the EIA expects U.S. total natural gas consumption to increase by 2.4% in 2008 compared to 2007.

Rig Counts

We have 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 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 cannot be readily obtained.

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, which may change from time to time and may vary from region to region, 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, a weekly or daily average of active rigs is taken. In those 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, or not 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				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007

U.S. – land and inland waters		1,910		1,717		1,806		1,683
U.S. – offshore		69		72		65		77
Canada		433		347		372		338

North America		2,412		2,136		2,243		2,098

Latin America		386		357		380		355
North Sea		47		50		44		50
Other Europe		54		29		52		28
Africa		64		67		66		65
Middle East		287		273		279		264
Asia Pacific		257		244		254		239

Outside North America		1,095		1,020		1,075		1,001

Worldwide		3,507		3,156		3,318		3,099

Third Quarter of 2008 Compared to the Third Quarter of 2007

In North America, the rig count increased 13%. The U.S. – land and inland waters rig count increased 11% due to the increase in drilling for both oil and natural gas. The U.S. – offshore rig count decreased 5% primarily due to the ongoing migration of rigs out of the Gulf of Mexico to more attractive international markets. The Canadian rig count was up 25% as higher average natural gas prices relative to the year-ago quarter provided improved economics for natural gas producers.

Outside North America, the rig count increased 7%. The rig count in Latin America increased 8% with activity increases in Brazil, Mexico and Argentina. The North Sea rig count decreased 6% due to lower activity in the U.K. sector. The rig count in Africa decreased 4% driven primarily by lower activity in Nigeria and Algeria. The Middle East rig count increased 5%, driven primarily by activity increases in Egypt and Oman. The rig count in the Asia Pacific region was up 6% primarily due to increased activity in Indonesia and Australia.

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. The discussions are based on our consolidated financial results, as individual segments do not contribute disproportionately to our revenues, profitability or cash requirements. 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 nine months ended September 30, 2008 and 2007, respectively.


	Three Months Ended September 30,
	2008				2007

Revenues	$	3,009.6	100.0	%	$	2,677.6	100.0	%
Cost of revenues		2,027.8	67	%		1,765.8	66	%
Research and engineering		103.2	3	%		94.2	4	%
Marketing, general and administrative		278.2	9	%		235.0	9	%


	Nine Months Ended September 30,
	2008				2007

Revenues	$	8,677.5	100.0	%	$	7,687.9	100.0	%
Cost of revenues		5,793.8	67	%		5,037.5	66	%
Research and engineering		311.9	4	%		278.4	4	%
Marketing, general and administrative		798.6	9	%		692.1	9	%

Revenues


	Three Months Ended
	September 30,					Increase
	2008		2007			(decrease)		% Change

Geographic Revenues:
North America	$	1,311.7	$	1,140.7		$	171.0		15	%
Latin America		285.1		240.3			44.8		19	%
Europe, Africa, Russia, and the Caspian		874.1		799.1			75.0		9	%
Middle East, Asia Pacific		538.6		497.7			40.9		8	%

Oilfield Operations revenues		3,009.5		2,677.8			331.7		12	%
Other revenue		0.1		(0.2	)		0.3		—

Total revenues	$	3,009.6	$	2,677.6		$	332.0		12	%


	Nine Months Ended
	September 30,				Increase
	2008		2007		(decrease)		% Change

Geographic Revenues:
North America	$	3,767.1	$	3,307.6	$	459.5		14	%
Latin America		786.2		663.1		123.1		19	%
Europe, Africa, Russia, and the Caspian		2,541.9		2,273.3		268.6		12	%
Middle East, Asia Pacific		1,582.2		1,443.9		138.3		10	%

Oilfield Operations revenues		8,677.4		7,687.9		989.5		13	%
Other revenue		0.1		—		0.1		—

Total revenues	$	8,677.5	$	7,687.9	$	989.6		13	%

Third Quarter of 2008 Compared to the Third Quarter of 2007

Revenues for the three months ended September 30, 2008 increased 12% compared with the three months ended September 30, 2007, primarily due to increases in activity in certain geographic areas as evidenced by an 11% increase in the worldwide rig count and to a lesser degree price improvement and net changes in market share in selected product lines and geographic areas. These increases were partially offset by the impact of hurricanes in the Gulf of Mexico.

North America

Revenues in North America, which accounted for 44% of total revenues, increased 15% for the three months ended September 30, 2008 compared with the three months ended September 30, 2007, despite the unfavorable impact on our U.S. offshore revenues of approximately $55.0 million from hurricane-related disruptions in 2008. The improvement in North America revenue was led by our Completion and Production segment and directional drilling. Revenues from our U.S. land and inland waters operations increased 25% compared to an 11% increase in the rig count due to the increase in drilling for both oil and natural gas. U.S. offshore revenues decreased 14% compared to a 5% decrease in the U.S. offshore rig count. The U.S. offshore rig count continues to decline due to the ongoing migration of rigs out of the Gulf of Mexico to more attractive international markets. Canada revenues increased 12% compared to a 25% increase in the rig count as increases in natural gas prices provided improved economics for natural gas producers.

Outside North America

Revenues outside North America, which accounted for 56% of total revenues, increased 10% for the three months ended September 30, 2008 compared with the three months ended September 30, 2007. This increase reflected the improvement in international drilling activity, as evidenced by the 7% increase in the rig count outside North America.

Latin America revenues increased 19% compared to an 8% increase in the rig count. The improved revenue in Latin America was led by directional systems in Brazil and Colombia; completion systems in Mexico and Venezuela; and drill bits in several countries. In Colombia, we began work on our first integrated operations contract in that country.

Europe, Africa, Russia and the Caspian (“EARC”) revenues increased 9% compared with the third quarter of 2007. The improved revenue in the region was led by all product lines in Norway, drilling and evaluation in Libya, and completion systems and wireline in

Kazakhstan. In the third quarter of 2008, we were awarded over $800.0 million in contract awards for future work, including a $450.0 million award for multiple product lines for BP Norway.

Activity in the Middle East, Asia Pacific (“MEAP”) region continued to expand, reflected by an 8% increase in revenues. Middle East revenues increased 15% compared to a 5% increase in the rig count and Asia Pacific revenues were up 3% compared to a 5% increase in the rig count. The improvement in revenues from the region was led by our Drilling and Evaluation segment in Saudi Arabia and India, the Completion and Production segment in Egypt and sales of various other product lines in Oman, Pakistan, Yemen, Brunei, Malaysia, Singapore and Vietnam. In the third quarter of 2008, we were awarded several contracts for future work, including the artificial lift and completion systems for the Manifa project in Saudi Arabia; drilling fluids and completion systems for Cairn in India; a significant wireline award for ONGC India; and oilfield chemicals in Qatar.

First Nine Months of 2008 Compared to the First Nine Months of 2007

Revenues for the nine months ended September 30, 2008 increased 13% compared with the nine months ended September 30, 2007 driven primarily by both activity increases, as evidenced by a 7% increase in the worldwide rig count, and price improvement and to a lesser degree net changes in market share partially offset by the impact of hurricanes in the Gulf of Mexico in 2008. Revenues in North America increased 14% as they were positively impacted by the increased activity from land rigs drilling for oil and natural gas in the U.S., driven by investment in drilling for oil and natural gas prospects. Revenues outside North America increased 12% reflecting increased activity in all three regions. Latin America revenues increased 19%; EARC revenues increased 12% and MEAP revenues increased 10%.

Cost of Revenues

Cost of revenues for the three months ended September 30, 2008 increased 15% compared with the three months ended September 30, 2007. Cost of revenues as a percentage of consolidated revenues was 67% and 66% for the three months ended September 30, 2008 and 2007, respectively. Cost of revenues for the nine months ended September 30, 2008 increased 15% compared with the nine months ended September 30, 2007. Cost of revenues as a percentage of consolidated revenues was 67% and 66% for the nine months ended September 30, 2008 and 2007, respectively. The increase in cost of revenues as a percentage of consolidated revenues resulted primarily from a change in the geographic and product mix from the sale of our products and services and higher raw material and labor costs which were not fully offset by pricing increases.

Research and Engineering

Research and engineering expenses increased 10% in the three months ended September 30, 2008 compared with the three months ended September 30, 2007 and increased 12% in the nine months ended September 30, 2008 compared with the nine months ended September 30, 2007. The increase reflects our continued commitment 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 18% in the three months ended September 30, 2008 compared with the three months ended September 30, 2007 and increased 15% in the nine months ended September 30, 2008 compared with the nine months ended September 30, 2007. The increase corresponds with increased activity and resulted primarily from higher employee related costs including compensation, training and benefits, higher marketing expenses as a result of increased activity, and an increase in legal, tax and other compliance-related expenses partially offset by higher foreign exchange gains.

Litigation Settlement

In connection with the settlement of litigation with ReedHycalog, in June 2008, the Company paid ReedHycalog $70.0 million in royalties for prior use of certain patented technologies, and ReedHycalog paid the Company $8.0 million in royalties for the license of certain Company patented technologies. The net pre-tax charge of $62.0 million for the settlement of this litigation is reflected in the consolidated condensed statement of operations for the nine months ended September 30, 2008.

Interest Expense, and Interest and Dividend Income

Interest expense increased $3.8 million and $3.6 million in the three and nine months ended September 30, 2008, respectively, compared with the three and nine months ended September 30, 2007. The increase is due primarily to higher average total debt levels. Interest and dividend income decreased $0.6 million and $10.6 million in the three and nine months ended September 30, 2008,

respectively, compared with the three and nine months ended September 30, 2007. These decreases were primarily due to lower interest rates on our short-term investments in 2008 compared to 2007.

Income Taxes

Our effective tax rate in the third quarter of 2008 is 27.3%, 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 and the expiration of statute of limitations in various taxing jurisdictions, offset by state income taxes. The tax rate for the year 2008 is expected to be between 30.0% and 30.5%.

Our effective tax rate in the third quarter of 2007 was 32.5%, which was lower than the U.S. statutory income tax rate of 35% due to lower rates of tax on certain international operations offset by state income taxes.

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 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, declining oil prices, lower natural gas prices, and a weakening global economic outlook 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 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 mid-summer highs has also negatively impacted our customers’ operational cash flow, further challenging their ability to continue to operate at recent levels, as well as their future spending for our products and services. Last, the economic slowdown is also negatively impacting the incremental demand for hydrocarbon products especially in OECD countries.

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. We base our energy price forecasts on 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 IEA and the Monthly Oil Market Report published by the Organization for Petroleum Exporting Countries (“OPEC”). These reports are revised monthly to reflect changes in the overall business environment. We base our outlook for production spending primarily on energy price forecasts and forecasts of expected oil and natural gas production levels.

Our outlook for activity outside of North America is heavily influenced by our expectations for oil prices and our outlook for activity in North America is heavily influenced by our expectations for North American natural gas prices.

Expectations for Oil Prices – Demand for oil is expected to increase between 330,000 and 800,000 barrels per day in 2008 compared to 2007. The change in non-OPEC supply in 2008 compared to 2007 is expected to be in a range between a decline of 200,000 and an increase of 400,000 barrels per day. The gap between increased demand and non-OPEC supply is expected to be met with increased OPEC supply and changes in oil inventories. Inventories and spare productive capacity, which buffer oil markets from supply disruptions, are expected to remain relatively low reflecting the continuing tight balance between supply and demand.

In its October 2008 STEO, the DOE forecasted oil prices to average $106/Bbl in 2008 and $107/Bbl in 2009. Subsequent to the end of the third quarter of 2008, oil prices dropped to the mid $60s/Bbl closing on October 24, 2008 at $63.15/Bbl.

We believe that many of our customers had based their capital spending plans on oil forecasts that are similar to the IEA’s forecast. Most of our customers’ projects are expected to result in attractive economic returns at current prices. However, we believe that our customers are revising their current budgets to account for lower energy prices and reduced cash flow and that these revisions will impact their future spending plans.

The risks to oil prices falling significantly from current levels include (1) a deeper or longer than expected recession in the U.S., and/or OECD; (2) slower than expected economic growth in China, India, developing Asia or the Middle East regions; (3) any other significant disruption to worldwide demand; (4) reduced geo-political tensions; (5) poor OPEC quota discipline; or (6) other factors that result in spare productive capacity and higher oil inventory levels or decreased demand. If oil prices rise significantly (above $100/Bbl) there is a risk that the high energy price environment could destroy demand and significantly slow economic growth. This risk is higher for the economies that are most closely tied to the U.S. Dollar. The primary risk of oil prices increasing significantly are a supply disruption in a major oil exporting country including Iran, Saudi Arabia, Iraq, Venezuela, Nigeria or Norway and continued weakening of the U.S. Dollar.

Expectations for North America Natural Gas Prices – In its October 2008 STEO, the DOE forecasted that U.S. natural gas demand would increase 2.4% in 2008 compared to 2007. The demand for U.S. natural gas is expected to be met by production from fields in the U.S., pipeline imports from Canada, and imports of LNG with natural gas storage buffering demand and supply. At current U.S. drilling activity levels, additions of new supply have more than offset production declines and U.S. supply is expected to increase 6.7% in 2008 compared to 2007. Canadian imports are expected to decrease as a result of lower activity levels in Canada over the past two years and increased demand within Canada. LNG imports are dependent on global demand for LNG with the U.S. playing the role of the market of last resort, accepting gas into storage if it is not needed in other international markets. As a result of increasing worldwide demand for LNG cargoes, particularly in the Asia Pacific region and Europe, U.S. imports of LNG in 2008 are expected to decline by more than 50% compared to 2007 levels. In its October 2008 STEO, the DOE forecasted that U.S. natural gas prices are expected to average approximately $9.71/mmBtu in 2008. Subsequent to the end of the third quarter of 2008, gas prices dropped to close at $6.27/mmBtu on October 24, 2008.

We believe that our customers’ forecasts are similar to the DOE’s. Prices are expected to remain volatile through 2008 with weather-driven demand, imports of Canadian gas, LNG imports and production from lower 48 gas fields playing significant roles in determining price volatility. Variations in the supply demand balance will be reflected in gas storage levels. Based on industry data regarding production decline rates, we believe that a significant reduction in drilling activity in the U.S. or Canada would result in decreased production within one or two quarters helping to rebalance supply and demand quickly.

Industry Activity and Customer Spending – Based upon our discussions with major customers, review of published industry reports and our outlook for oil and natural gas prices described above, our outlook for drilling activity, as measured by the Baker Hughes rig count and anticipated customer spending trends are as follows:

	•		Outside North America – Customer spending, primarily directed at developing oil supplies, is expected to increase approximately 15% to 20% in 2008 compared with 2007. Drilling activity outside of North America is expected to increase approximately 8% to 10% in 2008 compared with 2007. Our expectations for spending could decrease if there are disruptions in key oil and natural gas production markets.

	•		North America – Customer spending in North America is expected to moderate in the fourth quarter of 2008 compared to the third quarter of 2008 as the restricted access to the credit markets and economic slowdown combined with lower gas prices drive customers to reduce spending to levels supported by internal cash flow. Drilling activity is expected to decrease 3% to 5% in the fourth quarter compared to the third quarter, and we expect to end the year with 1,800 to 1,840 rigs drilling. Drilling in Canada is expected to be comparable to last year’s fourth quarter.

For additional risk factors and cautions regarding forward-looking statements, see “Part II, Item 1A. Risk Factors” and the “Forward-Looking Statements” section in this Part I, Item 2, both contained herein. This list of risk factors is not intended to be all inclusive.

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, either positively or negatively, our expectation for oil and natural gas demand, oil and natural gas prices and drilling activity.

North America – In the fourth quarter of 2008, we expect customers to adjust their budgets to reflect their ability to access the credit markets, the impact of lower oil and gas prices on their free cash flow, and reduced expectations for economic growth. We expect many customers in North America to reduce their planned spending in the fourth quarter of 2008 relative to the third quarter of 2008.

Outside North America – In the fourth quarter of 2008, we expect revenues outside North America to increase 14% to 15% compared with the fourth quarter of 2007. In the second quarter of 2008, we were awarded more than $1.6 billion in project awards and extensions in Brazil and Mexico. We will incur incremental start up costs in the fourth quarter of 2008 as we invest to support these projects.

Other factors that could have a significant positive impact on profitability include: increasing prices for our products and services; lower than expected raw material and labor costs; and/or higher than planned activity. Conversely, less than expected price increases or 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 improve pricing is dependent on demand for our products and services and our competitors’ strategies of managing capacity. While the commercial introduction of new technology is an important factor in realizing pricing improvement, without capital discipline throughout the industry as a whole, meaningful improvements in our prices are not likely to be realized.

Our 2008 capital budget supports the continuation of the infrastructure expansion we began in late 2006 and early 2007. In 2007, we opened new or expanded facilities in many regions and/or countries including Latin America, the Middle East, and Russia. In addition, we opened the first phase of our Center for Technology Innovation in Houston, a research and engineering facility to design advanced completion systems for high pressure, high temperature hostile environments. In early 2008, we opened our new campus in Dubai which includes our Middle East and Asia Pacific region headquarters, a regional operations center, a regional manufacturing center and a center which expands our Eastern Hemisphere training capabilities. Capital expenditures are expected to be approximately $1.3 billion for 2008, including approximately $250.0 million to $300.0 million that we expect to spend on infrastructure, primarily outside of North America.

The execution of our 2008 business plan and the ability to meet our 2008 financial objectives are dependent on a number of factors. Key factors include: the strength of the oilfield services market outside North America and our ability to realize price increases commensurate with the value we provide to our customers and in excess of the increase in raw material and labor costs; our ability to meet our growth objectives in areas where the lack of transparency in the market makes operating under the Deferred Prosecution Agreement more difficult; the strength of the North America markets and our ability to maintain pricing in markets in which demand for oilfield services and industry capacity are more closely balanced. Other factors include, but are not limited to, our ability to: recruit, train and retain the skilled and diverse workforce necessary to meet our business needs; expand our business in areas that are growing rapidly with customers whose spending is expected to increase substantially, such as National Oil Companies, and in areas where we have market share opportunities (such as the Middle East, Russia and the Caspian area and India); manage raw material and component costs (especially steel alloys, chromium, copper, tungsten carbide, lead, nickel, titanium, beryllium, synthetic and natural diamonds, chemicals, barite and electronic components); continue to make ongoing improvements in the productivity of our manufacturing organization and manage our spending in the North America market depending on the relative strength or weakness of this market.

Compliance

In connection with our settlements with the DOJ and SEC, we retained an independent monitor to assess and make recommendations about our compliance policies and procedures. In response to the monitor’s initial recommendations, we are continuing our reduction of the use of commercial sales representatives (“CSRs”) and processing agents, including the reduction of customs agents. We are also enhancing 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 are adopting 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 are also instituting a program to ensure that each of our internal sponsors regularly reviews their CSRs, including a review with senior management.

In addition, we are reviewing and expanding 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 are working 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 are also creating 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 will be 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 are also working 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.

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 2007 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 nine months ended September 30, 2008, cash flows from operations were the principal sources of funding. We anticipate that cash flows from operations will be sufficient to fund our liquidity needs in 2008. At September 30, 2008, we had cash and cash equivalents of $1,127.0 million, $1.0 billion of committed revolving credit facilities and a commercial paper program that provides additional liquidity. See further discussion below under “Available Credit Facilities.” Additionally, on October 28, 2008, we sold $500.0 million of 6.50% Senior Notes that will mature November 15, 2013, and $750.0 million of 7.50% Senior Notes that will mature November 15, 2018. For additional information see Note 17 of the Notes to Unaudited Consolidated Condensed Financial Statements for a more detailed description of the issuance of the notes.

Our capital planning process is focused on utilizing our existing cash and cash flows generated from operations in ways that enhance the value of our company. During the nine months ended September 30, 2008, we used cash for a variety of activities including working capital needs, acquisition of businesses, payment of dividends, share repurchases and capital expenditures.

Cash Flows

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


	2008			2007

Operating activities	$	965.5		$	789.6
Investing activities		(748.3	)		(373.4	)
Financing activities		(136.2	)		(344.4	)

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 provided $965.5 million in the nine months ended September 30, 2008 compared with $789.6 million in the nine months ended September 30, 2007. This increase in cash flows of $175.9 million is primarily due to an increase in net income after adding back non cash items partially offset by the change in net operating assets and liabilities that used more cash in the nine months ended September 30, 2008 compared to the same period in 2007.

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

	•		An increase in accounts receivable in the nine months ended September 30, 2008 used $415.8 million in cash compared with using $257.6 million in cash in the nine months ended September 30, 2007. This increase was primarily due to the increase in revenues and an increase in the quarterly days sales outstanding of approximately four days.

	•		Inventory used $277.8 million in cash in the nine months ended September 30, 2008 compared with using $160.8 million in cash in the nine months ended September 30, 2007 due to activity increases.

	•		An increase in accounts payable in the nine months ended September 30, 2008 provided $141.5 million in cash compared with using $31.6 million in cash in the nine months ended September 30, 2007. This increase in accounts payable was primarily due to an increase in operating assets to support increased activity.

	•		Accrued employee compensation and other accrued liabilities provided $23.2 million in cash in the nine months ended September 30, 2008 compared with using $203.1 million in cash in the nine months ended September 30, 2007. The decrease was primarily due to payments made in the first nine months of 2007 that were greater than payments made in the first nine months of 2008 including payments related to employee bonuses, non income tax liabilities and the payment of $44.1 million related to the settlement of the investigations by the SEC and DOJ.

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 $839.4 million and $811.1 million for the nine months ended September 30, 2008 and 2007, 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 $141.6 million and $146.2 million for the nine months ended September 30, 2008 and 2007, 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. 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 $31.0 million.

During the nine months ended September 30, 2008, we paid an aggregate of $81.5 million for acquisition of businesses, the most significant of which were the acquisitions of GCA and GMI. In April 2008, we acquired GCA and GMI and paid cash of $71.7 million, including $3.5 million of direct transaction costs, and net of cash acquired of $5.2 million. As a result of these acquisitions, we recorded $42.9 million of goodwill and $18.9 million of intangible assets.

During the nine months ended September 30, 2007, we purchased $2,520.7 million of and received proceeds of $2,812.2 million from maturing auction rate securities (“ARS”), which are variable-rate debt securities. While the underlying security has a long-term maturity, the interest rate is reset through Dutch auctions that are typically held every 7, 28 or 35 days. We discontinued additional investments in auction rate securities in September 2007.

At September 30, 2008 and at December 31, 2007, the fair value of the ARS investments held was $28.1 million and $35.6 million, respectively. The change of $7.5 million reflects a temporary impairment recorded as an unrealized loss in accumulated other comprehensive loss, a component of stockholders’ equity, in the three months ended June 30, 2008. Since September 2007, we have

been unable to sell our ARS investments because of unsuccessful auctions. As a result of the unsuccessful auctions and the downgrade in credit quality, the interest rate for each certificate resets every 28 days at one month LIBOR plus a spread determined by each certificate’s lowest assigned rating. Based on our ability to access our cash and cash equivalents, our expected operating cash flows, and our other sources of cash including our credit facilities with commercial banks, we do not anticipate that the lack of liquidity on these investments will affect our ability to operate our business. 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.

Financing Activities

We had net borrowings of commercial paper and other short-term debt of $547.2 million and $3.2 million in the nine months ended September 30, 2008 and 2007, respectively. Total debt outstanding at September 30, 2008 was $1,630.5 million, an increase of $545.7 million compared with December 31, 2007. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was 0.19 at September 30, 2008 and 0.15 at December 31, 2007. The increase in short-term debt was to fund expenses, capital expenditures and additional stock repurchases in the U.S. until cash can be cost effectively transferred to the U.S. from our international operations.

On October 28, 2008, we sold $500.0 million of 6.50% Senior Notes that will mature November 15, 2013, and $750.0 million of 7.50% Senior Notes that will mature November 15, 2018. For additional information see Note 17 of the Notes to Unaudited Consolidated Condensed Financial Statements for a more detailed description of the issuance of the notes.

We received proceeds of $51.4 million and $50.8 million in the nine months ended September 30, 2008 and 2007, 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. During the nine months ended September 30, 2008, we repurchased 8.8 million shares of our common stock at an average price of $69.22 per share for a total of $610.6 million. At September 30, 2008, we had authorization remaining to repurchase up to a total of $1.2 billion of our common stock.

We paid dividends of $126.6 million and $124.5 million in the nine months ended September 30, 2008 and 2007, respectively.

Available Credit Facilities

At September 30, 2008, we had $1,535.7 million of credit facilities with commercial banks, of which $500.0 million is a committed revolving credit facility (the “2005 Facility”), which expires on July 7, 2012, unless extended, and $500.0 million is a committed revolving credit facility which expires on March 31, 2009 (the “2008 Credit Agreement”). The 2005 Facility provides for a one-year extension, subject to the approval and acceptance by the lenders, among other conditions. In addition, the 2005 Facility contains a provision to allow for an increase of an additional $500.0 million, subject to the approval and acceptance by the lenders, among other conditions. The 2005 Facility contains certain covenants which, among other things, require the maintenance of a funded indebtedness to total capitalization ratio (a defined formula per the 2005 Facility) of less than or equal to 0.60, restrict certain merger transactions or the sale of all or substantially all of the assets of the company or a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the occurrence of certain events of default, our obligations under the 2005 Facility may be accelerated. Such events of default include payment defaults to lenders under the 2005 Facility, covenant defaults and other customary defaults.

The 2008 Credit Agreement, which we entered into on April 1, 2008, contains certain covenants, which, among other things, require the maintenance of a funded indebtedness to total capitalization ratio (a defined formula per the agreement) of less than or equal to 0.60, 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 2008 Credit Agreement may be accelerated. Such events of default include payment defaults to lenders under the 2008 Credit Agreement, covenant defaults and other customary defaults.

At September 30, 2008, we were in compliance with all of the covenants of both facilities. Additionally, there were no direct borrowings under either facility during the nine months ended September 30, 2008; however, to the extent we have outstanding commercial paper, our ability to borrow under these facilities is reduced.

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. We do not have any ratings triggers in the facilities that would accelerate the maturity of any borrowings under the 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.

Cash Requirements

In 2008, we believe existing cash, cash flows generated from operations and the cash proceeds from the sale of long-term notes in October 2008 will provide us with sufficient capital resources and liquidity to manage our working capital needs, meet contractual obligations including the repayment of our long-term debt maturities due in the first quarter of 2009, fund capital expenditures, pay dividends, repurchase common stock and support the development of our short-term and long-term operating strategies.

In 2008, we expect capital expenditures to be approximately $1.3 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.

In 2008, we expect to make interest payments of between $73.0 million and $75.0 million. This is based on our current expectations of debt levels during 2008. During the third quarter of 2008, we revised our estimate for income tax payments for 2008 and now we anticipate making income tax payments of between $690.0 million and $740.0 million in 2008.

On July 24, 2008, our Board of Directors authorized a program to repurchase up to $1.0 billion of our common stock (the “2008 Repurchase Program”) in addition to the existing stock repurchase authorization. As of September 30, 2008, we had authorization remaining to repurchase up to $1.2 billion in common stock. We may repurchase our common stock in the open market, in privately negotiated transactions or block transactions from time to time depending on market conditions, applicable legal requirements, our liquidity and other considerations. We may enter into Rule 10b5-1 plans to facilitate repurchases under the programs. A Rule 10b5-1 plan would generally permit us to repurchase the shares at any time when we might otherwise be prevented from doing so under certain securities laws. Shares repurchased under the programs will be retired. The programs do not require us to acquire any particular amounts of common stock and may be suspended or discontinued at any time.

On October 23, 2008, our Board of Directors authorized a dividend of $0.15 per share. We anticipate paying dividends of between $170.0 million and $175.0 million in 2008; however, our Board of Directors can change the dividend policy at anytime.

In 2008, we expect to contribute between $2.0 million and $3.0 million to our nonqualified U.S. pension plans and between $13.0 million and $15.0 million to the non-U.S. pension plans. We will also make benefit payments related to postretirement welfare plans of between $13.0 million and $15.0 million, and we estimate we will contribute between $142.0 million and $153.0 million to our defined contribution plans. We are currently evaluating the decline in the stock market and other assets held in our pension plans to determine the impact on any additional future funding requirements.

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. SFAS 157 was originally effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In November 2007, the FASB placed a one year deferral for the implementation of SFAS 157 for nonfinancial assets and liabilities; however, SFAS 157 is effective for fiscal years beginning after November 15, 2007 for financial assets and liabilities. We adopted all requirements of SFAS 157 on January 1, 2008, except as they relate to nonfinancial assets and liabilities, which will be adopted on January 1, 2009, as allowed under SFAS 157. See Note 9 of Notes to Unaudited Consolidated Condensed Financial Statements for further information on the impact of this standard to financial assets and liabilities. We have not yet determined the impact, if any, on our consolidated condensed financial statements for nonfinancial assets and liabilities.

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R) (“SFAS 158”). SFAS 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. Additionally, it requires an employer to measure the funded status of a plan as of the date of its year end statement of financial position, with limited exceptions. SFAS 158 is effective as of the end of the fiscal year ending after December 15, 2006; however, the requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year end statement of financial position is effective for fiscal years ending after December 15, 2008. We adopted all requirements of SFAS 158 on December 31, 2006, except for the funded status measurement date requirement, which will be adopted on December 31, 2008, as allowed under SFAS 158. We estimate the impact of moving our funded status measurement date from our current measurement date of October 1^st to December 31^st to be a reduction of approximately $1.6 million to beginning retained earnings which will be recorded in December 2008.

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,” “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, including changes in revenue, pricing, expenses, capital spending, backlogs, profitability, tax rates, strategies for our operations, impact of our common stock repurchases, oil and natural gas market conditions, market share and contract terms, costs and availability of resources, economic and regulatory conditions, and environmental matters are only our forecasts regarding these matters.

All of our forward-looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in “Part II, Item 1A. Risk Factors” section contained herein, as well as the risk factors described in our 2007 Annual Report, the Company’s Form 10-Q for the quarter ended March 31, 2008 and June 30, 2008, this filing and those set forth from time to time in our filings with the 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 September 30, 2008, we had entered into several foreign currency forward contracts with notional amounts aggregating $125.0 million to hedge exposure to currency fluctuations in various foreign currencies, including British Pound Sterling, Euro, Norwegian Krone and the Brazilian Real. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of September 30, 2008 for contracts with similar terms and maturity dates, we recorded a gain of $0.9 million to adjust these foreign currency forward contracts to their fair market value. This gain offsets designated foreign exchange losses resulting from the underlying exposures and is included in marketing, general and administrative expenses in our consolidated condensed statement of operations.

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 unlikely event that the counterparties fail to meet the terms of a foreign currency contract, our exposure is limited to the foreign currency rate differential.


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 September 30, 2008, our disclosure controls and procedures, as defined by Rule 13a-15(e) of the Exchange Act, are effective at a reasonable assurance level. There has been no change in our internal controls over financial reporting during the quarter ended September 30, 2008 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Disclosure controls and procedures are our controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act, such as this quarterly report, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

PART II. OTHER INFORMATION


ITEM 1.		LEGAL PROCEEDINGS

We are subject to a number of lawsuits, investigations and claims (some of which involve substantial amounts) arising out of the conduct of our business. See a further discussion of litigation matters in Note 16 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 2007 Annual Report for additional discussion of legal proceedings.

ITEM 1A. RISK FACTORS

As of the date of this filing, the Company and its operations continue to be subject to the risk factors previously disclosed in our “Risk Factors” in the 2007 Annual Report and the Form 10-Q for the period ended March 31, 2008 and the Form 10-Q for the period ended June 30, 2008, as well as the following risk factors:

Recent changes in the financial and credit markets may impact economic growth, and volatility of oil and natural gas prices can also impact our customers’ activity levels and spending for our products and services.

Based on a number of economic indicators, it appears that growth in global economic activity has slowed substantially. At the present time, the rate at which the global economy will slow has become increasingly uncertain. A slowing of global economic growth, and in particular in the U.S. or China, will likely reduce demand for oil and natural gas, increase spare productive capacity and result in lower prices and adversely impact the demand for our services.

Additionally, oil and natural gas prices have been extremely volatile and have declined substantially. On October 24, 2008, oil prices (West Texas Intermediate (WTI) Cushing Crude Oil Spot Price), closed at $63.15/Bbl, down from a high of $145.29/Bbl on July 3, 2008. Volatility in oil and natural gas prices can also impact our customers’ activity levels and spending for our products and services. While current energy prices are important contributors to positive cash flow for our customers, expectations about future prices and price volatility are generally more important for determining future spending levels. While higher oil and natural gas prices generally lead to increased spending by our customers, sustained high energy prices can be an impediment to economic growth, and can therefore negatively impact spending by our customers. Our customers also take into account the volatility of energy prices and other risk factors by requiring higher returns for individual projects if there is higher perceived risk. Any of these factors could affect the demand for oil and natural gas and could have a material adverse effect on our results of operations.

Many of our customers’ activity levels and spending for our products and services may be impacted by the current deterioration in the credit markets.

Many of our customers finance their exploration and development activities through cash flow from operations, the incurrence of debt or the issuance of equity. Recently, there has been a significant decline in the credit markets and the availability of credit. Additionally, many of our customers’ equity values have substantially declined. 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 result in a significant reduction in our customers’ spending for our products and services and may impact the ability of our customers to pay amounts owed to us. For example, a number of our customers have announced reduced capital expenditure budgets for the remainder of 2008 and 2009. This reduction in spending could have a material adverse effect on our operations.


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 September 30, 2008.

Issuer Purchases of Equity Securities


					Total Number of
					Shares						Maximum Number (or
					Purchased as						Approximate Dollar
	Total Number				Part of a Publicly				Total Number of		Value) of Shares that
	of Shares		Average Price		Announced		Average Price Paid		Shares Purchased		May Yet Be Purchased
Period	Purchased⁽¹⁾		Paid Per Share⁽¹⁾		Program⁽²⁾		Per Share⁽³⁾		in the Aggregate		Under the Program⁽⁴⁾

July 1-31, 2008		533	$	84.48		88,200	$	82.72		88,733		—
August 1-31, 2008		—		—		110,700		78.80		110,700		—
September 1-30, 2008		2,228		65.28		340,000		65.83		342,228		—

Total		2,761	$	68.99		538,900	$	71.26		541,661	$	1,213,341,883


⁽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⁾		Repurchases were made under Stock Purchase Plans with an agent that complied with the requirements of Rule 10b5-1 of the Exchange Act (the “Plans”) as well as open market purchases that complied with Rule 10b-18 of the Exchange Act. We entered into a Plan as of May 23, 2008 that ran from June 2, 2008 through July 24, 2008. We also entered into a Plan as of August 25, 2008 that ran from September 2, 2008 through October 23, 2008. Under the Plans, the agent repurchased a number of shares of our common stock determined under the terms of the Plans each trading day based on the trading price of the stock on that day. Shares were repurchased under the Plans by the agent at the prevailing market prices, in open market transactions which complied with Rule 10b-18 of the Exchange Act.

⁽³⁾		Average price paid includes commissions.

⁽⁴⁾		Our Board of Directors has authorized a program to repurchase our common stock from time to time. On July 24, 2008, our Board of Directors authorized a program to repurchase up to $1.0 billion of our common stock (the “2008 Repurchase Program”) in addition to the existing stock repurchase program. As of July 24, 2008, we had authorization remaining to repurchase approximately $1.246 billion of common stock, including the 2008 Repurchase Program. During the third quarter of 2008, we repurchased 538,900 shares of our common stock at an average price of $71.26 per share, for a total of $38.4 million with authorization remaining to repurchase up to a total of $1.2 billion of our common stock.


ITEM 3.		DEFAULTS UPON SENIOR SECURITIES

None.


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

None.


ITEM 5.		OTHER INFORMATION

The following event occurred subsequent to the period covered by this Form 10-Q and is reportable under Form 8-K:

Item 5.03 Amendments to Articles of Incorporation or Bylaws:

On October 23, 2008, the Board of Directors of the Company amended and restated the Company’s Bylaws to further clarify the (i) duties of the Inspectors of Election at annual and special meetings of stockholders; (ii) procedures for bringing business before an annual meeting, which included the advance notice of stockholder proposals required; and (iii) procedures for nominating directors. A copy of the Restated Bylaws are attached hereto and filed as Exhibit 3.2.


ITEM 6.		EXHIBITS

	3.2		Bylaws of Baker Hughes Incorporated restated as of October 23, 2008.

	4.1		Bylaws of Baker Hughes Incorporated restated as of October 23, 2008 (filed as Exhibit 3.2 to this Form 10-Q for the quarter ended September 30, 2008).

	31.1		Certification of Chad C. Deaton, Chief Executive Officer, dated October 29, 2008, 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 October 29, 2008, 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 October 29, 2008, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.

SIGNATURES

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


	BAKER HUGHES INCORPORATED (Registrant)
Date: October 29, 2008	By:	/s/PETER A. RAGAUSS
	Peter A. Ragauss
	Senior Vice President and Chief Financial Officer


Date: October 29, 2008	By:	/s/ALAN J. KEIFER
	Alan J. Keifer
	Vice President and Controller

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