BAKER HUGHES a GE 10Q 2005 Q3 Quarterly report

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, 2005


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 (IRS Employer Identification No.)

3900 Essex Lane, Suite 1200, Houston, Texas
(Address of principal executive offices)
77027
(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. YESþ NOo

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b–2 of the Exchange Act). YESþ NOo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Exchange Act). YESo NOþ

As of October 26, 2005, the registrant has outstanding 341,844,192 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 – Three months and nine months ended September 30, 2005 and 2004		2

	Consolidated Condensed Balance Sheets – September 30, 2005 and December 31, 2004		3

	Consolidated Condensed Statements of Cash Flows – Nine months ended September 30, 2005 and 2004		4

	Notes to Consolidated Condensed Financial Statements		5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		15

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		29

Item 4.	Controls and Procedures		29

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings		29

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

Item 3.	Defaults Upon Senior Securities		31

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

Item 5.	Other Information		31

Item 6.	Exhibits		32

Signatures			33
Supplemental Retirement Plan
Offer Letter from Chad C. Deaton
Amendment to 2002 Director & Officer Long-Term Incentive Plan
Compensation Table for Directors
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certification of CEO & CFO Pursuant to Rule 13a-14(b)
News Release

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,
	2005			2004			2005			2004

Revenues	$	1,793.3		$	1,538.1		$	5,219.4		$	4,424.7

Costs and expenses:
Cost of revenues		1,225.5			1,103.8			3,606.6			3,190.1
Selling, general and administrative		257.0			229.7			731.5			675.9

Total		1,482.5			1,333.5			4,338.1			3,866.0


Operating income		310.8			204.6			881.3			558.7
Equity in income of affiliates		27.5			10.0			66.2			22.4
Interest expense		(18.8	)		(16.9	)		(54.1	)		(62.1	)
Interest income		4.9			0.1			10.1			1.0


Income from continuing operations before income taxes		324.4			197.8			903.5			520.0
Income taxes		(102.5	)		(60.5	)		(283.0	)		(171.6	)


Income from continuing operations		221.9			137.3			620.5			348.4
Income from discontinued operations, net of tax		—			0.2			—			0.6

Net income	$	221.9		$	137.5		$	620.5		$	349.0


Basic earnings per share:
Income from continuing operations	$	0.65		$	0.41		$	1.83		$	1.05
Income from discontinued operations		—			—			—			—

Net income	$	0.65		$	0.41		$	1.83		$	1.05


Diluted earnings per share:
Income from continuing operations	$	0.65		$	0.41		$	1.82		$	1.04
Income from discontinued operations		—			—			—			—

Net income	$	0.65		$	0.41		$	1.82		$	1.04


Cash dividends per share	$	0.115		$	0.115		$	0.345		$	0.345

See accompanying notes to consolidated condensed financial statements.

Baker Hughes Incorporated

Consolidated Condensed Balance Sheets
(In millions)


	September 30,			December 31,
	2005			2004
	(Unaudited)			(Audited)

ASSETS

Current assets:
Cash and cash equivalents	$	742.1		$	319.0
Accounts receivable, net		1,526.3			1,356.1
Inventories		1,145.1			1,035.2
Deferred income taxes		191.9			199.7
Other current assets		48.2			56.6
\
Total current assets		3,653.6			2,966.6

Investments in affiliates		665.5			678.1
Property, net		1,318.4			1,334.1
Goodwill		1,323.5			1,267.0
Intangible assets, net		147.4			155.1
Other assets		394.7			420.4

Total assets	$	7,503.1		$	6,821.3


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	509.0		$	454.3
Short—term borrowings and current portion of long—term debt		19.5			76.0
Accrued employee compensation		379.5			368.8
Income taxes		107.7			104.8
Other accrued liabilities		250.6			226.3

Total current liabilities		1,266.3			1,230.2

Long—term debt		1,079.1			1,086.3
Deferred income taxes and other tax liabilities		232.4			231.9
Pensions and postretirement benefit obligations		312.4			308.3
Other liabilities		72.5			69.2

Stockholders’ equity:
Common stock		341.8			336.6
Capital in excess of par value		3,321.4			3,127.8
Retained earnings		1,049.6			545.9
Accumulated other comprehensive loss		(159.8	)		(109.8	)
Unearned compensation		(12.6	)		(5.1	)

Total stockholders’ equity		4,540.4			3,895.4

Total liabilities and stockholders’ equity	$	7,503.1		$	6,821.3

See accompanying notes to consolidated condensed financial statements.

Baker Hughes Incorporated

Consolidated Condensed Statements of Cash Flows
(In millions)
(Unaudited)


	Nine Months Ended
	September 30,
	2005			2004

Cash flows from operating activities:
Income from continuing operations	$	620.5		$	348.4
Adjustments to reconcile income from continuing operations to net cash flows from operating activities:
Depreciation and amortization		283.4			276.0
Amortization of net deferred gains on derivatives		(4.5	)		(6.2	)
Amortization of unearned compensation		5.9			—
Provision for deferred income taxes		27.3			28.7
Gain on disposal of assets		(33.1	)		(32.1	)
Equity in income of affiliates		(66.2	)		(22.4	)
Changes in:
Accounts receivable		(172.2	)		(111.2	)
Inventories		(124.1	)		(42.1	)
Accounts payable		53.0			34.6
Accrued employee compensation and other current liabilities		42.6			41.8
Other		19.3			2.6

Net cash flows from operating activities		651.9			518.1


Cash flows from investing activities:
Expenditures for capital assets		(319.2	)		(242.3	)
Investments in affiliates		—			(7.1	)
Net proceeds from sale of business and interest in affiliate		3.7			59.2
Distribution from WesternGeco		15.0			—
Receipt of true—up payment related to WesternGeco		13.0			—
Proceeds from disposal of assets		68.1			81.8
Other		—			(5.6	)
—
Net cash flows from continuing operations		(219.4	)		(114.0	)
Net cash flows from discontinued operations		—			(0.4	)
—
Net cash flows from investing activities		(219.4	)		(114.4	)


Cash flows from financing activities:
Net repayments of commercial paper and other short—term debt		(59.5	)		(6.5	)
Repayment of indebtedness		—			(350.0	)
Payment to terminate interest rate swap agreement		(5.5	)		—
Proceeds from issuance of common stock		178.1			75.2
Dividends		(116.8	)		(114.9	)

Net cash flows from financing activities		(3.7	)		(396.2	)


Effect of foreign exchange rate changes on cash		(5.7	)		0.9

Increase in cash and cash equivalents		423.1			8.4
Cash and cash equivalents, beginning of period		319.0			98.4

Cash and cash equivalents, end of period	$	742.1		$	106.8


Income taxes paid	$	221.7		$	105.4
Interest paid	$	73.4		$	87.5

See accompanying notes to consolidated condensed financial statements.

Baker Hughes Incorporated

Notes to 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 to the oil and natural gas industry on a worldwide basis and provide products and services for drilling, formation evaluation, completion and production of oil and natural gas wells.

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 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, 2004. 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.

Certain reclassifications have been made to the prior year’s consolidated condensed financial statements to conform with the current period presentation.

NOTE 2. STOCK–BASED COMPENSATION

As allowed under Statement of Financial Accounting Standards (“SFAS”) No. 123,Accounting for Stock–Based Compensation, we have elected to account for our stock–based compensation using the intrinsic value method of accounting in accordance with Accounting Principles Board Opinion No. 25 (“APB No. 25”),Accounting for Stock Issued to Employees. Under this method, compensation expense is to be recognized for the difference between the quoted market price of the stock at the measurement date less the amount, if any, the employee is required to pay for the stock. Our reported net income does not include any compensation expense associated with stock option awards because the exercise prices of our stock option awards equal the market prices of the underlying stock when granted. Our reported net income does include compensation expense associated with restricted stock awards.

In December 2004, the Financial Accounting Standards Board (“FASB”) issued the revised SFAS No. 123,Share–Based Payment(“SFAS No. 123(R)”). SFAS No. 123(R) is a revision of SFAS No. 123 and supersedes APB No. 25. SFAS No. 123(R) requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant–date fair value of the award. That cost will be recognized over the period in which an employee is required to provide service in exchange for the award. SFAS No. 123(R) also requires a public entity to initially measure the cost of employee services rendered in exchange for an award of liability instruments at its current fair value. The fair value of that award is to be remeasured subsequently at each reporting date through the settlement date. Changes in the fair value during the required service period are to be recognized as compensation cost over that period. We are currently in the process of evaluating different option pricing models and the impact of SFAS No. 123(R) on our consolidated condensed financial statements. In accordance with guidance issued by the SEC that delayed the effective date of SFAS No. 123(R), we intend to adopt SFAS No. 123(R) on January 1, 2006.

SFAS No. 123(R) clarified the accounting in SFAS No. 123 related to estimating the service period for employees that are or become retirement eligible during the vesting period, requiring that the recognition of compensation expense for these employees be accelerated. This impacts the timing of expense recognition, but not the total expense to be recognized over the vesting period. In the first quarter of 2005, we adopted this new methodology on a prospective basis. The cumulative effect of this clarification is $11.8 million, net of tax, which is included in our pro forma disclosure for stock–based compensation below for the nine months ended September 30, 2005.

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

If we had recognized compensation expense as if the fair value based method had been applied to all awards, our pro forma net income, earnings per share (“EPS”) and stock–based compensation cost would have been as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004

Net income, as reported	$	221.9		$	137.5		$	620.5		$	349.0
Add: Stock–based compensation for restricted stock awards included in reported net income, net of tax		1.7			0.7			4.6			1.1
Deduct: Stock–based compensation determined under the fair value method, net of tax		(7.5	)		(5.5	)		(30.2	)		(15.5	)

Pro forma net income	$	216.1		$	132.7		$	594.9		$	334.6


Basic EPS
As reported	$	0.65		$	0.41		$	1.83		$	1.05
Pro forma		0.63			0.40			1.76			1.00
Diluted EPS
As reported	$	0.65		$	0.41		$	1.82		$	1.04
Pro forma		0.63			0.39			1.75			1.00

These pro forma calculations may not be indicative of future amounts since additional awards in future years are anticipated.

NOTE 3. DISCONTINUED OPERATIONS

In September 2004, we completed the sale of Baker Hughes Mining Tools (“BHMT”), a product line group within the Drilling and Evaluation segment that manufactured rotary drill bits used in the mining industry. We received proceeds of $32.0 million, which were subject to post–closing adjustments to the purchase price. We recorded a gain on the sale of $0.5 million, net of tax of $3.8 million, which consisted of a gain on the disposal of $7.1 million offset by a loss of $6.6 million related to the recognition of the cumulative foreign currency translation adjustments into earnings. During the fourth quarter of 2004, we made a net payment of $0.5 million to the buyer in settlement of the final purchase price adjustments. The adjustments were the result of changes in the value of assets sold to and liabilities assumed by the buyer between the date the initial sales price was negotiated and the closing of the sale.

In January 2004, we completed the sale of BIRD Machine (“BIRD”), the remaining division of the former Process segment, and received $5.6 million in proceeds, which were subject to post–closing adjustments to the purchase price, and retained certain accounts receivable, inventories and other assets. During the second quarter of 2004, we made a net payment of $6.8 million to the buyer in settlement of the final purchase price adjustments. The adjustments were the result of changes in the value of assets sold to and liabilities assumed by the buyer between the date the initial sales price was negotiated and the closing of the sale.

Our consolidated condensed financial statements have been reclassified for all prior periods to reflect these operations as discontinued.

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

Summarized financial information from discontinued operations is as follows:


	Three Months Ended			Nine Months Ended
	September 30,			September 30,
	2004			2004

Revenues:
BHMT	$	8.0		$	29.4
BIRD		—			1.6

Total	$	8.0		$	31.0


Income (loss) before income taxes:
BHMT	$	(0.7	)	$	0.9
BIRD		0.1			(0.2	)

Total		(0.6	)		0.7

Income taxes:
BHMT		0.3			(0.2	)
BIRD		—			0.1

Total		0.3			(0.1	)

Income (loss) before gain (loss) on disposal:
BHMT		(0.4	)		0.7
BIRD		0.1			(0.1	)

Total		(0.3	)		0.6

Gain (loss) on disposal:
BHMT		0.5			0.5
BIRD		—			(0.5	)
—
Total		0.5			—
-
Income from discontinued operations	$	0.2		$	0.6

NOTE 4. 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,
	2005			2004			2005			2004

Net income	$	221.9		$	137.5		$	620.5		$	349.0
Other comprehensive income (loss):
Foreign currency translation adjustments:
Translation adjustments during the period		(0.6	)		10.4			(49.9	)		(9.9	)
Reclassifications included in net income due to sale of BHMT		—			6.6			—			6.6
Net change in derivative instruments		5.3			(1.1	)		(0.1	)		(1.0	)

Total comprehensive income	$	226.6		$	153.4		$	570.5		$	344.7

Total accumulated other comprehensive loss consisted of the following:


	September 30,			December 31,
	2005			2004

Foreign currency translation adjustments	$	(102.3	)	$	(52.4	)
Pension adjustment		(57.3	)		(57.3	)
Net loss on derivative instruments		(0.2	)		(0.1	)

Total accumulated other comprehensive loss	$	(159.8	)	$	(109.8	)

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

NOTE 5. EARNINGS 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,
	2005		2004		2005		2004

Weighted average common shares outstanding for basic EPS		340.5		334.1		338.8		333.2
Effect of dilutive securities — stock plans		2.4		1.8		2.1		1.7

Adjusted weighted average common shares outstanding for diluted EPS		342.9		335.9		340.9		334.9


Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than average market price for the period		—		3.5		0.7		5.1

NOTE 6. INVENTORIES

Inventories are comprised of the following:


	September 30,		December 31,
	2005		2004

Finished goods	$	932.6	$	869.5
Work in process		131.3		107.6
Raw materials		81.2		58.1

Total	$	1,145.1	$	1,035.2

NOTE 7. INVESTMENTS IN AFFILIATES

We have investments in affiliates that are accounted for using the equity method of accounting. The most significant of these affiliates is WesternGeco, a seismic venture in which we own 30% and Schlumberger Limited (“Schlumberger”) owns 70%. Summarized unaudited operating results for WesternGeco are as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004

Revenues	$	436.1	$	300.6	$	1,197.4	$	905.3
Operating income		90.8		31.5		210.6		78.4
Net income		69.5		29.1		176.2		64.9

The summarized unaudited financial position of WesternGeco is as follows:


	September 30,		December 31,
	2005		2004

Current assets	$	916.4	$	713.7
Noncurrent assets		1,061.4		1,147.9

Total assets	$	1,977.8	$	1,861.6


Current liabilities	$	456.3	$	402.2
Noncurrent liabilities		82.0		100.7
Stockholders’ equity		1,439.5		1,358.7

Total liabilities and stockholders’ equity	$	1,977.8	$	1,861.6

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

In conjunction with the formation of WesternGeco in November 2000, we entered into an agreement with Schlumberger whereby a cash true–up payment was to be made by either of the parties based on a formula comparing the ratio of the net present value of sales revenue from each party’s contributed multiclient seismic data libraries during the four–year period ending November 30, 2004 and the ratio of the net book value of those libraries as of November 30, 2000. The maximum payment that either party would be required to make as a result of this adjustment was $100.0 million. In August 2005, we received $13.3 million from Schlumberger related to the true–up payment. We recorded $13.0 million as a reduction in the carrying value of our investment in WesternGeco and $0.3 million as interest income. The income tax effect of $3.3 million related to this payment is included in our provision for income taxes for the three months and nine months ended September 30, 2005.

On or after December 1, 2005, either party to the WesternGeco Master Formation Agreement may offer to sell its entire interest in the venture to the other party at a cash purchase price per percentage interest specified in an offer notice. If the offer to sell is not accepted, the offering party will be obligated to purchase and the other party will be obligated to sell its entire interest at the same price per percentage interest as the price specified in the offer notice.

In the third quarter of 2005, we received a distribution of $15.0 million from WesternGeco which was recorded as a reduction in the carrying value of our investment.

In 2003, we acquired a 50% interest in the QuantX Wellbore Instrumentation venture (“QuantX”). Through August 2005, we accounted for our ownership in QuantX using the equity method of accounting. In August 2005, we exercised our right to acquire the remaining 50% interest in QuantX. The purchase price for the remaining 50% interest will be calculated based on the provisions of the QuantX Master Formation Agreement. We estimate that the purchase price of the remaining 50% interest will be approximately $25 million. As of September 1, 2005, we are now required to consolidate QuantX’s accounts and have discontinued using the equity method of accounting. We have recorded approximately $56.0 million of goodwill and $1.6 million of intangible assets. The purchase price was allocated based on the estimated fair value of the assets acquired and liabilities assumed. Pro forma results of operations have not been presented because the effect of this acquisition was not material to our consolidated condensed financial statements. We expect to close this transaction in the fourth quarter of 2005.

In February 2004, we completed the sale of our minority interest in Petreco International, a venture we entered into in 2001, for $35.8 million, of which $7.4 million was held in escrow pending the outcome of potential indemnification obligations pursuant to the sales agreement. In May 2005, we received $3.7 million from the release of a portion of the amount held in escrow. The remainder is expected to be released to us in February 2006 subject to the indemnity obligations under the sales agreement. We recognized a gain on the sale of $1.3 million, net of tax of $1.5 million.

NOTE 8. PROPERTY

Property is comprised of the following:


	September 30,			December 31,
	2005			2004

Land	$	40.0		$	40.8
Buildings and improvements		608.0			618.1
Machinery and equipment		1,994.4			1,960.6
Rental tools and equipment		1,146.6			1,097.5

Total property		3,789.0			3,717.0
Accumulated depreciation		(2,470.6	)		(2,382.9	)

Property – net	$	1,318.4		$	1,334.1

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

NOTE 9. GOODWILL AND INTANGIBLE ASSETS

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


	Drilling		Completion
	and Evaluation		and Production			Total

Balance as of December 31, 2004	$	902.9	$	364.1		$	1,267.0
Goodwill from acquisition during the period		—		56.0			56.0
Translation adjustments and other		0.9		(0.4	)		0.5

Balance as of September 30, 2005	$	903.8	$	419.7		$	1,323.5

Intangible assets are comprised of the following:


	September 30, 2005							December 31, 2004
	Gross							Gross
	Carrying		Accumulated					Carrying		Accumulated
	Amount		Amortization			Net		Amount		Amortization			Net

Technology based	$	192.9	$	(67.9	)	$	125.0	$	190.2	$	(58.8	)	$	131.4
Contract based		11.0		(6.1	)		4.9		11.0		(4.8	)		6.2
Marketing related		6.1		(5.5	)		0.6		6.1		(5.6	)		0.5
Customer based		0.6		(0.3	)		0.3		0.6		(0.2	)		0.4
Other		1.1		(0.7	)		0.4		1.2		(0.8	)		0.4

Total amortizable intangible assets		211.7		(80.5	)		131.2		209.1		(70.2	)		138.9
Marketing related intangible asset with an indefinite useful life		16.2		—			16.2		16.2		—			16.2

Total	$	227.9	$	(80.5	)	$	147.4	$	225.3	$	(70.2	)	$	155.1

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

Amortization expense for intangible assets for the three months and nine months ended September 30, 2005 was $3.8 million and $11.4 million, respectively, and is estimated to be $15.8 million for 2005. Estimated amortization expense for each of the subsequent five fiscal years is expected to be within the range of $8.5 million to $14.7 million.

NOTE 10. FINANCIAL INSTRUMENTS

Interest Rate Swap Agreement

In April 2004, we entered into an interest rate swap agreement for a notional amount of $325.0 million associated with our 6.25% Notes due January 2009. The agreement was designated and qualified as a fair value hedging instrument. Due to our outlook for interest rates, we terminated the interest rate swap agreement in June 2005 which required us to make a payment of $5.5 million. This amount was deferred and is being amortized as an increase to interest expense over the remaining life of the underlying debt security.

Foreign Currency Forward Contracts

At September 30, 2005, we had entered into several foreign currency forward contracts with notional amounts aggregating $76.8 million to hedge exposure to currency fluctuations in various foreign currencies. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of September 30, 2005 for contracts with similar terms and maturity dates, we recorded a loss of $2.4 million to adjust these foreign currency forward contracts to their fair market value. This loss offsets designated foreign exchange gains resulting from the underlying exposures and is included in selling, general and administrative expense in our consolidated condensed statement of operations.

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

At September 30, 2005, we had also entered into several foreign currency forward contracts with notional amounts aggregating $214.4 million to hedge exposure to currency fluctuations in various foreign currencies. These foreign currency forward contracts do not qualify for hedge accounting. Based on quoted market prices as of September 30, 2005 for contracts with similar terms and maturity dates, we recorded a loss of $7.5 million to adjust these foreign currency forward contracts to their fair market value. This loss is included in revenues ($3.2 million) and cost of revenues ($4.3 million) in our consolidated condensed statement of operations.

NOTE 11. SEGMENT AND RELATED INFORMATION

During the first quarter of 2005, we reorganized our operating divisions into two separate groups: the Drilling and Evaluation group, which consists of the Baker Atlas, Baker Hughes Drilling Fluids, Hughes Christensen and INTEQ divisions, and the Completion and Production group, which consists of the Baker Oil Tools, Baker Petrolite and Centrilift divisions. The Completion and Production group also includes Luna Energy, L.L.C. and QuantX. The reorganization was done to align product lines based on the types of products and services provided to our customers, to provide additional focus on our product lines and technology and to be able to more effectively serve our customers.

Accordingly, beginning with the first quarter of 2005, we are reporting our results under three segments: Drilling and Evaluation, Completion and Production and WesternGeco. Divisions in the Drilling and Evaluation segment generally provide services and products used directly in the drilling and formation evaluation of oil and natural gas wells. Divisions in the Completion and Production segment provide services and products used to complete wells, rework existing wells and enhance or initiate production from new wells.

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 include 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. All prior period segment information has been restated to reflect these changes.

The performance of our segments is evaluated based on segment profit (loss), which is defined as income from continuing operations before income taxes and interest income and expense. Summarized financial information is shown in the following table. The “Corporate and Other” column includes corporate—related items, results of insignificant operations and, as it relates to segment profit (loss), income and expense not allocated to the segments.


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

*Revenues*
Three months ended September 30, 2005	$	915.0	$	878.3			$	1,793.3	$	—		$	1,793.3
Three months ended September 30, 2004		764.8		772.3				1,537.1		1.0			1,538.1

Nine months ended September 30, 2005	$	2,648.0	$	2,570.1			$	5,218.1	$	1.3		$	5,219.4
Nine months ended September 30, 2004		2,168.4		2,253.9				4,422.3		2.4			4,424.7

*Segment profit (loss)*
Three months ended September 30, 2005	$	192.8	$	174.7	$	25.5	$	393.0	$	(68.6	)	$	324.4
Three months ended September 30, 2004		130.2		128.8		9.1		268.1		(70.3	)		197.8

Nine months ended September 30, 2005	$	528.6	$	504.0	$	63.3	$	1,095.9	$	(192.4	)	$	903.5
Nine months ended September 30, 2004		332.6		377.9		21.9		732.4		(212.4	)		520.0

*Total assets*
As of September 30, 2005	$	3,101.1	$	2,813.0	$	662.8	$	6,576.9	$	926.2		$	7,503.1
As of December 31, 2004		2,932.3		2,671.4		620.1		6,223.8		597.5			6,821.3

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

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004

Corporate expenses	$	(54.7	)	$	(53.5	)	$	(148.4	)	$	(151.3	)
Interest, net		(13.9	)		(16.8	)		(44.0	)		(61.1	)

Total	$	(68.6	)	$	(70.3	)	$	(192.4	)	$	(212.4	)

NOTE 12. EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

We have noncontributory defined benefit pension plans (“Pension Benefits”) covering various domestic and foreign employees. The components of net periodic benefit cost are as follows:


	U.S. Pension Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004

Service cost	$	5.7		$	5.1		$	17.1		$	15.4
Interest cost		3.0			2.7			8.9			8.0
Expected return on plan assets		(6.5	)		(5.1	)		(19.4	)		(15.3	)
Recognized actuarial loss		0.6			1.0			1.9			3.0

Net periodic benefit cost	$	2.8		$	3.7		$	8.5		$	11.1


	Non–U.S. Pension Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004

Service cost	$	0.5		$	0.5		$	1.7		$	1.4
Interest cost		3.4			3.4			10.5			10.1
Expected return on plan assets		(3.2	)		(2.3	)		(10.0	)		(6.8	)
Recognized actuarial loss		0.6			1.2			2.0			3.5

Net periodic benefit cost	$	1.3		$	2.8		$	4.2		$	8.2

Postretirement Welfare Benefits

We provide certain postretirement health care and life insurance benefits 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:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004

Service cost	$	1.5	$	1.3	$	4.6	$	4.1
Interest cost		2.5		2.4		7.3		7.3
Amortization of prior service cost		0.1		0.1		0.4		0.5
Recognized actuarial loss		0.5		0.2		1.5		0.8

Net periodic benefit cost	$	4.6	$	4.0	$	13.8	$	12.7

NOTE 13. GUARANTEES

In the normal course of business with customers, vendors and others, we have entered into off–balance sheet arrangements, such as letters of credit and other bank issued guarantees, for approximately $306.3 million at September 30, 2005. We have also guaranteed debt and other obligations of third parties with a maximum exposure of $2.3 million at September 30, 2005. None of the off–balance sheet arrangements either has, or is likely to have, a material effect on our consolidated condensed financial statements.

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

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, 2005 are as follows:


Balance as of December 31, 2004	$	16.6
Claims paid		(2.8	)
Additional warranties issued		2.8
Revisions in estimates for previously issued warranties		(1.6	)

Balance as of September 30, 2005	$	15.0

The product warranty liabilities as of September 30, 2005 and December 31, 2004 include $7.3 million and $7.6 million, respectively, related to the discontinued Process segment.

NOTE 14. NEW ACCOUNTING STANDARDS

In November 2004, the FASB issued SFAS No. 151,Inventory Costs – an Amendment of ARB No. 43, Chapter 4, which amends the guidance in ARB No. 43 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. SFAS No. 151 requires that these items be recognized as current period charges. In addition, SFAS No. 151 requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. SFAS No. 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. We do not expect the adoption to have a material effect on our consolidated condensed financial statements. We will adopt SFAS No. 151 on January 1, 2006.

In December 2004, the FASB issued SFAS No. 153,Exchanges of Nonmonetary Assets – an amendment of APB Opinion No. 29, to address the measurement of exchanges of nonmonetary assets. SFAS No. 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS No. 153 is effective for nonmonetary exchanges occurring after June 30, 2005. We adopted SFAS No. 153 on July 1, 2005.

In December 2004, the FASB issued FASB Staff Position No. 109–1 (“FSP 109–1”),Application of FASB Statement No. 109, “Accounting for Income Taxes” (“SFAS No. 109”) to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004, which provides guidance on the American Jobs Creation Act of 2004 (the “Act”). The Act provides a tax deduction for income from qualified domestic production activities. FSP 109–1 provides for the treatment of the deduction as a special deduction as described in SFAS No. 109. As such, the deduction will have no effect on existing deferred tax assets and liabilities. The impact of the deduction is to be reported in the period in which the deduction is claimed on our U.S. tax return. We do not expect that this deduction will have a material impact on our effective tax rate in future years. We adopted FSP 109–1 on January 1, 2005.

In December 2004, the FASB issued FASB Staff Position No. 109–2 (“FSP 109–2”),Accounting and Disclosure Guidance for the Foreign Repatriation Provision within the American Jobs Creation Act of 2004,which provides guidance under SFAS No. 109 with respect to recording the potential impact of the repatriation provisions of the Act on a company’s income tax expense and deferred tax liability. FSP 109–2 states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings for purposes of applying SFAS No. 109. We have decided not to elect to repatriate foreign earnings under the provisions in the Act. Accordingly, our consolidated condensed financial statements do not reflect a provision for taxes related to this election.

In March 2005, the FASB issued FASB Interpretation No. 47 (“FIN 47”),Accounting for Conditional Asset Retirement Obligations. FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143,Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. We are currently evaluating the provisions of FIN 47 and will adopt FIN 47 on December 31, 2005.

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

In May 2005, the FASB issued SFAS No. 154,Accounting Changes and Error Corrections. SFAS No. 154 replaces Accounting Principles Board Opinion No. 20 (“APB No. 20”),Accounting Changes, and SFAS No. 3,Reporting Accounting Changes in Interim Financial Statements, and changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS No. 154 requires retrospective application of changes in accounting principle to prior periods’ financial statements, unless it is impracticable to determine either the period–specific effects or the cumulative effect of the change. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We will adopt SFAS No. 154 on January 1, 2006.

NOTE 15. SUBSEQUENT EVENTS

On October 27, 2005, the Board of Directors authorized us to repurchase up to $455.5 million of common stock, which is in addition to the balance of $44.5 million remaining from the Board of Directors’ September 2002 authorization. We now have authorization to repurchase up to a total of $500.0 million of common stock. We did not repurchase any shares during the nine months ended September 30, 2005. We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. On October 27, 2005, the Board of Directors also authorized a dividend in the amount of $0.13 per share to be paid in the fourth quarter of 2005, representing an increase from prior dividends of $0.115 per share.

In October 2005, we received a distribution of $15.0 million from WesternGeco, which will be recorded as a reduction in the carrying value of our investment.

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, 2004.

EXECUTIVE SUMMARY

We are a leading provider of drilling, formation evaluation, completion and production products and services to the worldwide oil and natural gas industry. We compete as one of the three largest diversified oilfield services companies. Our product–line focused divisions are organized into two separate groups: the Drilling and Evaluation group and the Completion and Production group. The groups align product lines based on the types of products and services provided to our customers. We also own a 30% equity interest in WesternGeco, a seismic venture with Schlumberger Limited (“Schlumberger”). Accordingly, we report our results under three segments – Drilling and Evaluation, Completion and Production and WesternGeco:

	•		The Drilling and Evaluation segment consists of 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). The Drilling and Evaluation segment provides products and services used to drill oil and natural gas wells.

	•		The Completion and Production segment consists of Baker Oil Tools (workover, fishing and completion equipment), Baker Petrolite (oilfield specialty chemicals) and Centrilift (electric submersible pumps and progressing cavity pumps). The Completion and Production segment also includes Luna Energy, L.L.C. and QuantX Wellbore Instrumentation (“QuantX”). 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 WesternGeco segment consists of our equity interest in WesternGeco.

During the third quarter of 2005, the Baker Hughes worldwide rig count continued to increase, as oil and natural gas companies around the world recognized the need to build productive capacity to meet the growing demand for hydrocarbons and to offset depletion of existing developed reserves. Oil and natural gas prices were at historic highs in the third quarter of 2005, reflecting continued strong demand, relatively low excess productive capacity, and disruptions in supply due to hurricanes in the Gulf of Mexico. We reported revenues of $1,793.3 million for the third quarter of 2005, a 16.6% increase compared with the third quarter of 2004, approximating the 18.6% increase in the worldwide average rig count for the third quarter of 2005 compared with the third quarter of 2004. In addition to the growth in our revenues from increased activity, our revenues were impacted by pricing improvements and changes in market share in certain product lines. Net income for the third quarter of 2005 was $221.9 million, a 61.4% increase compared with $137.5 million in the third quarter of 2004.

	•		In North America, our revenues for the third quarter of 2005 increased 20.8% compared with the third quarter of 2004, while the rig count increased 23.6% for the third quarter of 2005 compared with the third quarter of 2004, driven primarily by land–based drilling for natural gas. In the third quarter of 2005, hurricane–related disruptions negatively impacted our revenues from the U.S. offshore market by approximately $48 million.

	•		Latin American revenues increased 10.2% and the Latin American rig count increased 6.5% in the third quarter of 2005 compared with the third quarter of 2004.

	•		Europe, Africa and CIS revenues increased 12.6% in the third quarter of 2005 compared with the third quarter of 2004. Growth in revenues from Africa exceeded the increase in the rig count for Africa and growth in revenues from Europe was below the increase in the European rig count for the comparable periods.

	•		Middle East and Asia Pacific revenues were up 17.3% in the third quarter of 2005 compared with the third quarter of 2004. Growth in revenues from the Middle East exceeded the increase in the Middle Eastern rig count and growth in revenues from Asia Pacific was below the change in the rig count for Asia Pacific for the comparable periods.

The customers for our products and services include the super–major and major integrated oil and natural gas companies, independent oil and natural gas companies and state–owned national oil companies (“NOCs”). Our ability to compete in the oilfield services market is dependent on our ability to differentiate our product and service offerings by technology, service and the price paid for the value we deliver.

The primary driver of our business is our customers’ capital and operating expenditures dedicated to exploring and drilling for and developing and producing oil and natural gas. Our business is cyclical and is dependent upon our customers’ forecasts of future oil and natural gas prices, future economic growth and hydrocarbon demand and estimates of future oil and natural gas production. During the first nine months of 2005, our customers’ spending directed to both worldwide oil and North American oil and natural gas projects increased compared with the first nine months of 2004. The increase in spending was driven by the perceived multi–year requirement to find, develop and produce more hydrocarbons to meet the growth in demand, offset production declines, increase inventory levels and rebuild productive capacity. Additionally, the increase was supported by historically high oil and natural gas prices. Our customers’ spending on oil and gas projects is expected to continue to grow for the remainder of 2005 and in the near future.

Our ability to continue to execute our 2005 business plan and to meet our 2005 financial objectives is dependent on a number of factors. These factors include, but are not limited to, our ability to: manage increasing raw material and component costs (especially steel alloys, copper, carbide and chemicals); continue to make ongoing improvements in the productivity of our manufacturing organization; 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 NOCs), and in areas where we have market share opportunities (such as the Middle East); realize price increases commensurate with the value we provide to our customers and in excess of the increase in raw material and labor costs; and recover from the effects of recent hurricanes. For a full discussion of risk factors and forward–looking statements, please see the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry”, “Risk Factors Related to Our Business” and “Forward–Looking Statements” sections contained herein.

BUSINESS ENVIRONMENT

Our business environment and its corresponding operating results are significantly affected by the level of energy industry spending for the exploration and production (“E&P”) of oil and natural gas reserves. An indicator for this spending is the rig count because when drilling and workover rigs are active, many of the products and services provided by the oilfield services industry are required. Our products and services are used during the drilling and workover phases, during the completion of the oil and natural gas wells and during actual production of the hydrocarbons. This E&P spending by oil and natural gas companies is, in turn, influenced strongly by expectations about the supply and demand for oil and natural gas products and by current and expected prices for both oil and natural gas. Rig counts, therefore, generally reflect the relative strength and stability of energy prices.

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 and onshore China, because this information is extremely difficult to obtain.

Rigs in the U.S. are counted as active if, on the day the count is taken, the well being drilled has been started, 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. In general, rigs are counted as active if the well has been started but has not reached its target depth, even if there are extensive delays due to weather or other reasons. If the well has been started but not completed and the rig is expected to resume work in two weeks or less, the rig is counted as active during a weather delay. Rigs are not counted as active if the rig is lost or damaged or if drilling operations are expected to be suspended for more than two weeks.

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 other 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, are rigging up, are being used in non–drilling activities, including production testing, completion and workover, or are 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,
	2005		2004		2005		2004

U.S. — land and inland waters		1,330		1,133		1,254		1,075
U.S. — offshore		98		95		97		96
Canada		494		327		416		346

North America		1,922		1,555		1,767		1,517

Latin America		311		292		317		285
North Sea		45		34		41		40
Other Europe		29		28		28		30
Africa		49		49		50		48
Middle East		245		236		244		227
Asia Pacific		231		207		221		197

Outside North America		910		846		901		827

Worldwide		2,832		2,401		2,668		2,344


U.S. Workover Rigs		1,390		1,255		1,322		1,215

The U.S. — land and inland waters rig count increased 17.4% in the third quarter of 2005 compared with the third quarter of 2004 due to the increase in drilling for natural gas. The U.S. — offshore rig count increased 3.2% in the third quarter of 2005 compared with the third quarter of 2004; however, this increase does not fully reflect the magnitude of the activity disruptions caused by hurricanes in the Gulf of Mexico in the third quarter of 2005. The Canadian rig count increased 51.1% in the third quarter of 2005 compared with the third quarter of 2004 due to the increase in drilling for natural gas.

Outside North America, the rig count increased 7.6% in the third quarter of 2005 compared with the third quarter of 2004. The rig count in Latin America increased 6.5% in the third quarter of 2005 compared with the third quarter of 2004, driven primarily by activity increases in Venezuela, Colombia and Argentina. The North Sea rig count increased 32.4% in the third quarter of 2005 compared with the third quarter of 2004. The rig count in Africa was unchanged in the third quarter of 2005 compared with the third quarter of 2004. Activity in the Middle East continued to rise steadily, with a 3.8% increase in the rig count in the third quarter of 2005 compared with the third quarter of 2004 driven primarily by activity increases in Saudi Arabia and Yemen. The rig count in the Asia Pacific region was up 11.6% in the third quarter of 2005 compared with the third quarter of 2004 primarily due to activity increases in India and offshore China.

Oil and Natural Gas Prices

Generally, changes in the current price and expected future prices of oil or natural gas drive both customers’ expectations about their prospects from oil and natural gas sales and their expenditures to explore for or produce oil and natural gas. Accordingly, changes in these expenditures will normally result in increased or decreased demand for our products and services. Oil (Bloomberg West Texas Intermediate (WTI) Cushing Crude Oil Spot Price) and natural gas (Bloomberg 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,
	2005		2004		2005		2004

Oil prices ($/Bbl)	$	63.18	$	43.91	$	55.46	$	39.26
Natural gas prices ($/mmBtu) *		9.43		5.50		7.57		5.74


*		In late September 2005, Hurricane Rita damaged natural gas processing facilities in Henry, Louisiana (“Henry Hub”) and the New York Mercantile Exchange declaredforce majeureon its Henry Hub natural gas contracts. As a result, the average natural gas prices for the three months and nine months ended September 30, 2005 exclude those dates when there was insufficient activity to determine a spot price.

Oil traded between $54/Bbl and $61/Bbl in July 2005, hitting a low for the quarter of $54.93/Bbl in late July 2005. Oil then traded between $63/Bbl and $70/Bbl from the second week of August through the end of September, reaching a high for the quarter of $69.47/Bbl in early September, following Hurricane Katrina. Prices decreased after Hurricane Katrina with demand destruction and conservation driven by higher prices offsetting the disruption in supply and refining capacity, allowing prices to settle in the lower $60s/Bbl range. Inventories of crude and petroleum products increased in the first two months of the third quarter of 2005, but fell in September due to the disruptions from the hurricanes. While inventories remained at historically normal levels throughout the third quarter, the ongoing lack of excess productive capacity supported high prices. Worldwide demand for hydrocarbons was driven by worldwide economic growth, which was particularly strong in China and developing countries in Asia. Worldwide excess productive capacity remains at the lowest level in 30 years, with the excess capacity primarily in heavy and sour grades for which there is limited refining capacity. Disruptions, or the potential for disruptions, in oil supply are expected to result in oil prices remaining volatile throughout the balance of the year.

In July and August, high oil prices supported an increase in natural gas prices from $7/mmBtu to $8/mmBtu in early July to $9/mmBtu to $10/mmBtu in late August. However, since Hurricane Katrina made landfall in late August, natural gas has traded at a Btu–premium to oil, peaking at $14.50/mmBtu as Hurricane Rita made landfall in late September. Natural gas storage levels are expected to end the April to October injection season with more than 3Tcf in storage, but possibly the lowest beginning storage level since 2000. High prices in September reflected the competition between demand to fill storage for peak winter demand and the more immediate industrial demands.

Worldwide Oil and Natural Gas Industry Outlook

This section should be read in conjunction with the factors described in the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry,” “Risk Factors Related to Our Business” and “Forward–Looking Statements” sections 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.

Oil– Oil prices for the remainder of 2005 are expected to trade between $55/Bbl and $70/Bbl, with periodic spikes or troughs which may exceed this range. Strong worldwide economic growth and the lack of excess productive capacity are expected to support prices within this range. Growth in oil demand has slowed in 2005 compared with 2004, as worldwide economic growth and, in particular, economic growth in China, has moderated from the extraordinarily strong growth exhibited in 2004. At the beginning of October 2005, the International Energy Agency estimated that excess productive capacity was less than 3% of demand and that more than three–quarters of the excess capacity was in Saudi Arabia and Iraq. The ongoing lack of excess productive capacity will leave the energy markets susceptible to price volatility and the Organization of Petroleum Exporting Countries (“OPEC”) is unlikely to be able to increase production should there be any significant disruptions or threat of disruptions in oil supplies.

Factors that could lead to prices at the lower end of our range include, but are not limited to: (1) a significant slowing of worldwide economic growth, particularly economic growth in China; (2) greater than planned growth in Russian oil exports; (3) any significant disruption to demand; or (4) other factors which result in excess productive capacity and higher oil inventories levels or decreased demand.

Factors that could lead to prices at the higher end of our range include but are not limited to: (1) more rapid than planned expansion of the worldwide economy, particularly the economy in China; (2) a significant slowing of exports from Russia and the inability of key exporting countries to produce additional crude; or (3) other factors which result in excess productive capacities remaining at low levels.

Factors that could lead to disruptions or the threat of disruptions in oil supply and volatility in oil prices include, but are not limited to: (1) terrorist attacks targeting oil production from Saudi Arabia or other key producers; (2) labor strikes in key oil producing areas such as Nigeria; (3) the potential for other military actions in the Middle East; and (4) adverse weather conditions, especially in the Gulf of Mexico. The potential for these and other events to cause volatility will be mitigated by the degree to which OPEC and, in particular, Saudi Arabia are able to increase excess productive capacity as well as the capability of the markets to refine and market products refined from crude oil.

Natural Gas –Natural gas prices for the remainder of 2005 are expected to remain volatile, trading between $7/mmBtu and $15/mmBtu. A significant factor for the markets this winter will be the pace of recovery of production of natural gas in the Gulf of Mexico following the disruptions from Hurricanes Katrina and Rita. Natural gas prices could trade at the top, or beyond the top, of this range if: (1) storage levels are relatively low at the beginning of the withdrawal season; (2) weather is colder than normal; (3) slower than expected restoration of hurricane damaged production facilities; or (4) the U.S. economy, particularly the industrial sector, exhibits greater than expected growth and continued levels of oilfield customer spending are not sufficient to support the production

growth required to meet the growth of natural gas demand. Natural gas prices could move to the bottom, or below the bottom, of this range if: (1) storage levels are relatively high at the beginning of the withdrawal season; (2) U.S. economic growth is weaker than expected; or (3) weather is milder than expected.

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, anticipated customer spending trends are as follows:

	•		North America – Spending in North America, primarily towards developing natural gas supplies, is expected to increase approximately 17% to 19% in 2005 compared with 2004.

	•		Outside North America – Customer spending, primarily directed at developing oil supplies, is expected to increase 14% to 16% in 2005 compared with 2004.

	•		Total spending is expected to increase 17% to 19% in 2005 compared with 2004.

Drilling Activity– Based upon our outlook for oil and natural gas prices and customer spending described above, our outlook for drilling activity, as measured by the Baker Hughes rig count, is as follows:

	•		The North American rig count is expected to increase approximately 10% to 12% in 2005 compared with 2004.

	•		Drilling activity outside of North America is expected to increase approximately 9% to 11% in 2005 compared with 2004.

Risk Factors Related to the Worldwide Oil and Natural Gas Industry

Our business is focused on providing products and services to the worldwide oil and natural gas industry; therefore, our risk factors are centered on those factors that impact, either positively or negatively, the markets for oil and natural gas. Key risk factors currently influencing the worldwide oil and natural gas markets are discussed below.

•		Excess productive capacity– the impact of supply and demand disruptions on oil prices and oil price volatility is tempered by the size and expected duration of the disruption relative to the excess productive capacity. Key measures include estimates of worldwide productive capacity and the quality of the capacity as compared with worldwide demand.

•		Supply disruptions –the loss of production, the inability to export and/or the delay of activity from key oil producing countries, including, but not limited to, Iraq, Saudi Arabia and other Middle Eastern countries, Nigeria, Norway, Russia and Venezuela, due to political instability, civil unrest, labor issues or military activity. In addition, adverse weather such as hurricanes could impact production facilities, causing supply disruptions.

•		Energy prices and price volatility –the impact of widely fluctuating commodity prices on the stability of the market and subsequent impact on customer spending. While current energy prices are important contributors to positive cash flow at E&P companies, expectations for future prices and price volatility are generally more important for determining future E&P spending. While higher commodity prices generally lead to higher levels of E&P spending, sustained high energy prices can be an impediment to economic growth.

•		Global economic growth –particularly the impact of the U.S. and Western European economies and the economic activity in Japan, China, South Korea and the developing areas of Asia where the correlation between economic growth and energy demand is strong. The strength of the U.S. economy and economic growth in developing countries in Asia, particularly China, will continue to be important in 2005. Key measures include U.S. and international economic output, global energy demand and forecasts of future demand by governments and private organizations.

•		Oil and natural gas storage inventory levels –an indicator of the balance between supply and demand. A key measure of U.S. natural gas inventories is the storage level reported weekly by the U.S. Department of Energy compared with historic levels. Key measures for oil inventories include U.S. inventory levels reported by the U.S. Department of Energy and the American Petroleum Institute and worldwide estimates reported by the International Energy Agency.

•		Production control –the degree to which individual OPEC nations and other large oil and natural gas producing countries, including, but not limited to, Mexico, Norway and Russia, are willing and able to control production and exports of oil, to decrease or increase supply and to support their targeted oil price while meeting their market share objectives. Key measures of production control include actual production levels compared with target or quota production levels, oil prices compared with

		targeted oil prices and changes in each country’s market share.

•		Ability to produce natural gas– the amount of natural gas that can be produced is a function of the number and productivity of new wells drilled, completed and connected to pipelines as well as the rate of production and resulting depletion of existing wells. Advanced technologies, such as horizontal drilling, improve total recovery but also result in a more rapid production decline. Key measures include government and private surveys of natural gas production, company reported production, estimates of reservoir depletion rates and drilling and completion activity.

•		Impact of energy prices and price volatility on demand for hydrocarbons– short–term price changes can result in companies switching to the most economic sources of fuel, prompting a temporary curtailment of demand, while long–term price changes can lead to permanent changes in demand. These changes in demand result in the oilfield services industry being cyclical in nature. Key indicators include hydrocarbon prices on a Btu equivalent basis and indicators of hydrocarbon demand, such as electricity generation or industrial production.

•		Access to prospects– the ability of oil and natural gas companies to develop economically attractive projects based on their expectations of future energy prices, required investments and resulting returns. Access to prospects may be limited because host governments do not allow access to the reserves or because another oil and natural gas company owns the rights to develop the prospect.

•		Weather –the impact of variations in temperatures as compared with normal weather patterns and the related effect on demand for oil and natural gas. A key measure of the impact of weather on energy demand is population–weighted heating and cooling degree days as reported by the U.S. Department of Energy and forecasts of warmer than normal or cooler than normal temperatures. Weather can also impact production, for example, in the North Sea, the Gulf of Mexico and Canada.

•		Access to capital– the ability of oil and natural gas companies to access the funds necessary to carry out their E&P plans. Access to capital is particularly important for smaller independent oil and natural gas companies. Key measures of access to capital include cash flow, interest rates, analysis of oil and natural gas company leverage and equity offering activity.

•		Technological progress –the design and application of new products that allow oil and natural gas companies to drill fewer wells and to drill, complete and produce wells faster, recover more hydrocarbons and/or lower costs. Key measures also include the overall level of research and engineering spending by oilfield services companies and the pace at which new technology is both introduced commercially and accepted by customers.

•		Pace of new investment –the investment by oil and natural gas companies in emerging markets and any impact it has on their spending in areas where they already have an established presence.

•		Maturity of the resource base –the growing necessity for increased levels of investment and activity to support production from an area the longer it is developed. Key measures include changes in undeveloped hydrocarbon reserves in mature areas like the North Sea, the U.S., Canada and Latin America.

•		Government regulations –the costs incurred by oil and natural gas companies to conform to and comply with government regulations, including environmental regulations, may limit the quantity of oil and natural gas that may be economically produced.

For additional risk factors and cautions regarding forward–looking statements, see the “Risk Factors Related to Our Business” and the “Forward–Looking Statements” sections contained herein. This list of risk factors is not intended to be all inclusive.

BUSINESS OUTLOOK

This section should be read in conjunction with the factors described in the “Risk Factors Related to Our Business,” “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” and “Forward–Looking Statements” sections 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.

In our outlook for 2005, we took into account the factors described herein. Revenues in 2005 should increase by 16% to 17% compared with 2004, in line with the expected increase in customer spending. We expect that the growth in our revenues will primarily be due to increased activity and pricing improvement. Our assumptions regarding overall growth in customer spending assume strong economic growth in the U.S. and China, resulting in an average annual oil price exceeding $55/Bbl. Our assumptions

regarding customer spending in North America assume strong economic growth in the U.S. and natural gas prices exceeding an annual average of $8/mmBtu.

In North America, we expect revenues to increase 17% to 19% in 2005 compared with 2004. We expect spending on land–based projects to continue to increase in 2005 driven by demand for natural gas, following the trend evident in 2004. We also expect offshore spending in the Gulf of Mexico to increase modestly in 2005 compared with 2004. The impact of Hurricanes Katrina and Rita will have a negative impact on spending in the Gulf of Mexico in the fourth quarter of 2005.

In 2005, we expect revenues outside North America to be between 55% and 60% of total revenues, and we expect these revenues to increase 14% to 16% in 2005 compared with 2004, continuing the multi–year trend of growth in customer spending. Spending on large projects by NOCs are expected to reflect established seasonality trends, which resulted in softer revenues in the first half of the year and revenues which are expected to be stronger in the second half. The Middle East, Africa and Latin America are expected to grow modestly in 2005 compared with 2004. Our expectations for spending and revenue growth could decrease if there are disruptions in key oil and natural gas production markets, such as Venezuela or Nigeria.

In the nine months ended September 30, 2005, WesternGeco contributed $63.3 million of equity in income of affiliates compared with $21.9 million of equity in income of affiliates in the nine months ended September 30, 2004. We expect the trend of improving operating results for WesternGeco to continue throughout 2005. Information regarding WesternGeco’s profitability in 2005 is based on information that WesternGeco has provided to us. Should this information not be accurate, our forecasts for profitability could be impacted, either positively or negatively.

In 2005, we modified our long–term incentive program to provide a combination of both restricted stock and stock option awards. Restricted stock awards were granted in January and stock option awards were granted in January and July. As required under the current accounting rules, awards of restricted stock are expensed over the vesting period based on their fair value when granted. We plan to begin expensing the fair value of stock option awards and stock issued under the employee stock purchase plan in January 2006, when we intend to adopt the revised Statement of Financial Accounting Standards No. 123,Share–Based Payment(“SFAS No. 123(R)”). We are currently in the process of evaluating different option pricing models and the impact of SFAS No. 123(R) on our consolidated financial statements.

Based on the above forecasts, we believe that net income per diluted share in 2005 will be in the range of $2.52 to $2.54, which includes the impact of expensing restricted stock awards. Significant price increases, lower than expected raw material and labor costs, higher than planned activity or significantly better than expected results from WesternGeco could cause earnings per share to reach the upper end of this range. Conversely, less than expected price increases, higher than expected raw material and labor costs, lower than expected productivity or significantly worse than expected results at WesternGeco could result in earnings per share being at or below the bottom of this range. 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 pricing discipline throughout the industry as a whole, meaningful improvements in our prices are not likely to be realized. Additionally, significant changes in drilling activity outside our expectations could impact operating results positively or negatively.

We do business in approximately 90 countries including over one–half of the 35 countries having the lowest scores, which indicates high levels of corruption, in Transparency International’s Corruption Perception Index (“CPI”) survey for 2005. We devote significant resources to the development, maintenance and enforcement of our Business Code of Conduct policy, our Foreign Corrupt Practices Act (the “FCPA”) policy, our internal control processes and procedures and other compliance related policies. Notwithstanding the devotion of such resources, and in part as a consequence thereof, from time to time we discover or receive information alleging potential violations of laws and regulations, including the FCPA and our policies, processes and procedures. We conduct internal investigations of these potential violations and take appropriate action depending upon the outcome of the investigation. In addition, U.S. government agencies and authorities are conducting investigations into allegations of potential violations of laws.

We anticipate that the devotion of significant resources to compliance related issues, including the necessity for investigations, will continue to be an aspect of doing business in a number of the countries in which oil and natural gas exploration, development and production take place and in which we are requested to conduct operations. Compliance related issues could limit our ability to do business in these countries. In order to provide products and services in some of these countries, we may in the future utilize ventures with third parties, sell products to distributors or otherwise modify our business approach in order to improve our ability to conduct our business in accordance with laws and regulations and our Business Code of Conduct. In the third quarter of 2005, our independent foreign subsidiaries initiated a process to prohibit any business activity that directly or indirectly involves or facilitates transactions in Iran, Sudan or with their governments, including government–controlled companies operating outside of these countries.

Implementation of this process should be substantially complete by the end of 2006 and is not expected to have a material impact on our consolidated condensed financial statements.

Risk Factors Related to Our Business

Our expectations regarding our business outlook, including changes in revenue, pricing, capital spending and profitability, are only our forecasts regarding these matters. These forecasts may be substantially different from actual results, which are affected by the following risk factors and the timing of any of these risk factors:

•

Oil and gas market conditions– the level of petroleum industry E&P expenditures; drilling rig and oil and natural gas industry manpower and equipment availability; the price of, and the demand for, crude oil and natural gas; drilling activity; excess productive capacity; seasonal and other weather conditions that affect the demand for energy; severe weather conditions, such as hurricanes, that affect exploration and production activities; OPEC policy and the adherence by OPEC nations to their OPEC production quotas; war, military action, terrorist activities or extended period of international conflict, particularly involving the U.S., Middle East or other major petroleum–producing or consuming regions; civil unrest or security conditions where we operate; expropriation of assets by governmental action.

•

Pricing, market share and contract terms –our ability to implement and affect price increases for our products and services; the effect of the level and sources of our profitability on our tax rate; the ability of our competitors to capture market share; our ability to retain or increase our market share; changes in our strategic direction; the effect of industry capacity relative to demand for the markets in which we participate; our ability to negotiate acceptable terms and conditions with our customers, especially NOCs; our ability to manage warranty claims and improve performance and quality; our ability to effectively manage our commercial agents.

•

Costs and availability of resources– our ability to manage the rising costs and availability of sufficient raw materials and components (especially steel alloys, copper, carbide and chemicals); our ability to recruit, train and retain the skilled and diverse workforce necessary to meet our business needs; manufacturing capacity and subcontracting capacity at forecasted costs to meet our revenue goals; the availability of essential electronic components used in our products; the effect of competition, particularly our ability to introduce new technology on a forecasted schedule and at forecasted costs; potential impairment of long–lived assets; the accuracy of our estimates regarding our capital spending requirements; unanticipated changes in the levels of our capital expenditures; the need to replace any unanticipated losses in capital assets; the development of technology by us or our competitors that lowers overall finding and development costs; labor–related actions, including strikes, slowdowns and facility occupations.

•

Litigation and changes in laws or regulatory conditions– the potential for unexpected litigation or proceedings; the legislative, regulatory and business environment in the U.S. and other countries in which we operate; outcome of government and internal investigations and legal proceedings; new laws, regulations and policies that could have a significant impact on the future operations and conduct of all businesses; changes in export control laws or exchange control laws; additional restrictions on doing business in countries subject to sanctions; financial impact of exiting certain markets; changes in laws in Russia or other countries identified by management for immediate focus; changes in accounting standards; changes in tax laws or tax rates in the jurisdictions in which we operate; resolution of audits by various tax authorities; ability to fully utilize our tax loss carryforwards and tax credits.

•

Economic conditions –worldwide economic growth; the effect that high energy prices may have on worldwide economic growth and demand for hydrocarbons; foreign currency exchange fluctuations and changes in the capital markets in international locations where we operate; the condition of the capital and equity markets in general; our ability to estimate the size of and changes in the worldwide oil and natural gas industry.

•

Environmental matters– unexpected, adverse outcomes or material increases in liability with respect to environmental remediation sites where we have been named as a potentially responsible party; the discovery of new environmental remediation sites; changes in environmental regulations; the discharge of hazardous materials or hydrocarbons into the environment.

For additional risk factors and cautions regarding forward–looking statements, see the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” and “Forward–Looking Statements” sections contained herein. This list of risk factors is not intended to be all inclusive.

DISCONTINUED OPERATIONS

Our consolidated condensed financial statements have been reclassified for all prior periods to reflect these operations as discontinued. See Note 3 of the Notes to Consolidated Condensed Financial Statements for additional information regarding discontinued operations.

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.

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, 2005 and 2004, respectively.


	Three Months Ended September 30,
	2005				2004

Revenues	$	1,793.3	100.0	%	$	1,538.1	100.0	%
Cost of revenues		1,225.5	68.3			1,103.8	71.8
Selling, general and administrative		257.0	14.3			229.7	14.9


	Nine Months Ended September 30,
	2005				2004

Revenues	$	5,219.4	100.0	%	$	4,424.7	100.0	%
Cost of revenues		3,606.6	69.1			3,190.1	72.1
Selling, general and administrative		731.5	14.0			675.9	15.3

Revenues

Revenues for the three months ended September 30, 2005 increased 16.6% compared with the three months ended September 30, 2004, primarily due to increases in activity, as evidenced by an 18.6% increase in the worldwide rig count, pricing improvements and changes in market share in certain product lines. Revenues in North America, which accounted for 42.2% of total revenues, increased 20.8% for the three months ended September 30, 2005 compared with the three months ended September 30, 2004, despite the unfavorable impact on our U.S. offshore revenues of approximately $48 million from hurricane–related disruptions. This increase reflects increased activity in the U.S., as evidenced by the 23.6% increase in the North American rig count, with activity dominated by land–based gas–directed drilling. Revenues outside North America, which accounted for 57.8% of total revenues, increased 13.7% for the three months ended September 30, 2005 compared with the three months ended September 30, 2004. This increase reflects the improvement in international drilling activity, as evidenced by the 9.4% increase in the rig count outside North America, particularly in Latin America, the Middle East and Asia Pacific, coupled with pricing improvement in certain markets and product lines.

Revenues for the nine months ended September 30, 2005 increased 18.0% compared with the nine months ended September 30, 2004. Revenues were positively impacted by the increased activity from land rigs drilling for natural gas in the U.S. and Canada, driven by continued investment in drilling for natural gas prospects; increased activity in certain international markets, including the U.K. sector of the North Sea, Nigeria and Saudi Arabia; and pricing improvements in certain markets and product lines.

Cost of Revenues

Cost of revenues for the three months ended September 30, 2005 increased 11.0% compared with the three months ended September 30, 2004. Cost of revenues for the nine months ended September 30, 2005 increased 13.1% compared with the nine months ended September 30, 2004. Cost of revenues as a percentage of consolidated revenues was 68.3% and 71.8% for the three months ended September 30, 2005 and 2004, respectively. Cost of revenues as a percentage of consolidated revenues was 69.1% and 72.1% for the nine months ended September 30, 2005 and 2004, respectively. The decreases are primarily the result of pricing improvement in certain markets and product lines, higher utilization of our rental tool fleet and improved cost control measures, partially offset by increased material costs and higher employee expenses.

Selling, General and Administrative

Selling, general and administrative expenses increased 11.9% in the three months ended September 30, 2005 compared with the three months ended September 30, 2004 and increased 8.2% in the nine months ended September 30, 2005 compared with the nine months ended September 30, 2004. These increases are primarily due to higher marketing and employee expenses as a result of increased activity.

Equity in Income of Affiliates

Equity in income of affiliates increased $17.5 million in the three months ended September 30, 2005 compared with the three months ended September 30, 2004 and increased $43.8 million in the nine months ended September 30, 2005 compared with the nine months ended September 30, 2004. The increases are primarily due to the increase in equity in income of WesternGeco, our most significant equity method investment, as a result of improving conditions in the seismic market.

Interest Expense

Interest expense increased $1.9 million in the three months ended September 30, 2005 compared with the three months ended September 30, 2004. The increase was primarily due to the impact of the interest rate swap agreement that was in place during the third quarter of 2004 but was terminated in June 2005.

Interest expense decreased $8.0 million in the nine months ended September 30, 2005 compared with the nine months ended September 30, 2004. The decrease was primarily due to lower total debt levels partially offset by the impact of the interest rate swap agreement that was in place from April 2004 through June 2005. The lower total debt levels were a result of the repayment of $350.0 million of long–term debt in the second quarter of 2004.

Income Taxes

Our effective tax rates differ from the U.S. statutory income tax rate of 35% due to state income taxes, differing rates of tax on international operations and higher taxes associated with the WesternGeco venture. Additionally, our provision for income taxes for the nine months ended September 30, 2005 reflects a $10.6 million reduction related to the recording of a deferred tax asset for our supplemental retirement plan. The effective tax rate for the fourth quarter of 2005 is expected to be approximately 32.5% and for the year ending December 31, 2005 is expected to be approximately 31.5%.

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, 2005, cash flows from operations and proceeds from the issuance of common stock resulting from the exercise of stock options were the principal sources of funding. We anticipate that cash flows from operations will cover our liquidity needs in 2005. We also have a $500.0 million committed revolving credit facility that provides back–up liquidity in the event of an unanticipated significant demand on cash flows that could not be funded by operations.

Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of our company. During the nine months ended September 30, 2005, we used cash for a variety of activities including working capital needs,

repayment of short–term borrowings, payment of dividends and capital expenditures.

Cash Flows

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


	2005			2004

Operating activities	$	651.9		$	518.1
Investing activities		(219.4	)		(114.0	)
Financing activities		(3.7	)		(396.2	)

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

Operating Activities

Cash flows from operating activities of continuing operations provided $651.9 million in cash in the nine months ended September 30, 2005 compared with $518.1 million in cash in the nine months ended September 30, 2004. This increase was primarily due to an increase in income from continuing operations partially offset by an increase in working capital.

The underlying drivers of the changes in working capital are as follows:

	•		An increase in accounts receivable due to increased activity used $172.2 million in cash in the first nine months of 2005 compared with using $111.2 million in cash in the first nine months of 2004. This was due to an increase in revenues and an increase in days sales outstanding (defined as the average number of days our accounts receivable are outstanding) of approximately three days.

	•		A build up of inventory in anticipation of increased activity used $124.1 million in cash in the first nine months of 2005 compared with using $42.1 million in the first nine months of 2004.

	•		An increase in accounts payable provided $53.0 million in cash in the first nine months of 2005 compared with providing $34.6 million in cash in the first nine months of 2004 primarily due to increased activity.

	•		An increase in accrued employee compensation and other current liabilities provided $42.6 million in cash in the first nine months of 2005 compared with providing $41.8 million in cash in the first nine months of 2004.

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 $319.2 million and $242.3 million for the nine months ended September 30, 2005 and 2004, respectively. The majority of these expenditures were for rental tools and machinery and equipment, including wireline tools and equipment.

In the third quarter of 2005, we received a distribution of $15.0 million from WesternGeco, which was recorded as a reduction in the carrying value of our investment. We also received $13.3 million from Schlumberger related to the WesternGeco true–up payment, of which $13.0 million was recorded as a reduction in the carrying value of our investment and $0.3 million as interest income. In October 2005, we received an additional distribution of $15.0 million from WesternGeco, which will be recorded as a reduction in the carrying value of our investment.

In September 2004, we completed the sale of BHMT and received proceeds of $32.0 million, which are subject to post–closing adjustments to the purchase price. In January 2004, we completed the sale of BIRD and received $5.6 million in proceeds, which were subject to post–closing adjustments to the purchase price. In June 2004, we made a net payment of $6.8 million to the buyer in settlement of the final purchase price adjustments.

In February 2004, we completed the sale of our minority interest in Petreco International for $35.8 million, of which $7.4 million was held in escrow pending the outcome of potential indemnification obligations pursuant to the sales agreement. In May 2005, we

received $3.7 million from the release of a portion of the amount held in escrow. The remainder is expected to be released to us in February 2006 subject to the indemnity obligations under the sales agreement.

Proceeds from the disposal of assets were $68.1 million and $81.8 million for the nine months ended September 30, 2005 and 2004, 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.

Financing Activities

We had net repayments of commercial paper and other short–term debt of $59.5 million and $6.5 million in the nine months ended September 30, 2005 and 2004, respectively. In the second quarter of 2004, we repaid the $100.0 million 8.0% Notes due May 2004 and the $250.0 million 7.875% Notes due June 2004. These repayments were funded with cash on hand, cash flows from operations and the issuance of commercial paper.

Total debt outstanding at September 30, 2005 was $1,098.6 million, a decrease of $63.7 million compared with December 31, 2004. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was 0.19 at September 30, 2005 and 0.23 at December 31, 2004.

We received proceeds of $178.1 million and $75.2 million in the nine months ended September 30, 2005 and 2004, respectively, from the issuance of common stock from the exercise of stock options.

We paid dividends of $116.8 million and $114.9 million in the nine months ended September 30, 2005 and 2004, respectively.

Available Credit Facilities

At September 30, 2005, we had $915.6 million of credit facilities with commercial banks, of which $500.0 million is a committed revolving credit facility (the “facility”) that expires in July 2010. The facility provides for up to three one–year extensions, subject to the approval and acceptance by the lenders, among other conditions. In addition, the facility contains a provision to allow for an increase in the facility amount of an additional $500.0 million, subject to the approval and acceptance by the lenders, among other conditions. The facility contains certain covenants which, among other things, require the maintenance of a funded indebtedness to total capitalization ratio (a defined formula per the 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 facility may be accelerated. Such events of default include payment defaults to lenders under the facility, covenant defaults and other customary defaults. At September 30, 2005, we were in compliance with all of the facility covenants. There were no direct borrowings under the facility during the nine months ended September 30, 2005; however, to the extent we have outstanding commercial paper, our ability to borrow under the facility is reduced. At September 30, 2005, we had no outstanding commercial paper.

If market conditions were to change and revenues were to be significantly reduced or operating costs were to increase, our cash flows and liquidity could be reduced. Additionally, it could cause the rating agencies to lower our credit rating. We do not have any ratings triggers in the facility that would accelerate the maturity of any borrowings under the facility. However, a downgrade in our credit ratings could increase the cost of borrowings under the facility and could also limit or preclude our ability to issue commercial paper. Should this occur, we would seek alternative sources of funding, including borrowing under the facility.

We believe that our credit ratings and relationships with major commercial and investment banks would allow us to obtain interim financing over and above our existing credit facilities for any currently unforeseen significant needs or growth opportunities. We also believe that such interim financings could be funded with subsequent issuances of long–term debt or equity, if necessary.

Cash Requirements

In 2005, we believe operating cash flows will provide us with sufficient capital resources and liquidity to manage our working capital needs, meet contractual obligations, fund capital expenditures, pay dividends, repurchase common stock and support the development of our short–term and long–term operating strategies.

We currently expect that 2005 capital expenditures will be between $490 million and $510 million, excluding acquisitions. The expenditures are expected to be used primarily for normal, recurring items necessary to support the growth of our business and operations.

During the third quarter of 2005, we exercised our right to acquire the remaining 50% interest in QuantX. We estimate that the purchase price will be approximately $25 million, and we expect to close the transaction in the fourth quarter of 2005.

In 2005, we expect to make interest payments of approximately $80 million to $90 million. This is based on our current expectations of debt levels and interest rates during 2005.

In 2005, we estimate that we will contribute approximately $12 million to $19 million to our defined benefit pension plans and make benefit payments related to postretirement welfare plans of approximately $14 million to $16 million. We also estimate that we will contribute approximately $70 million to $80 million to our defined contribution plans.

During the third quarter of 2005, we revised our estimate for income tax payments for 2005 and now anticipate making income tax payments of approximately $285 million to $325 million.

We do not believe that there are any other material trends, demands, commitments, events or uncertainties that would have, or are reasonably likely to have, a material impact on our financial condition and liquidity. Other than previously discussed, we currently have no information that would create a reasonable likelihood that the reported levels of revenues and cash flows from operations in the nine months ended September 30, 2005 are not indicative of what we can expect in the near future.

RELATED PARTY TRANSACTIONS

NEW ACCOUNTING STANDARDS

In November 2004, the FASB issued SFAS No. 151,Inventory Costs – an Amendment of ARB No. 43, Chapter 4, which amends the guidance in ARB No. 43 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. SFAS No. 151 requires that these items be recognized as current period charges. In addition, SFAS No. 151 requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. SFAS No. 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. We do not expect the adoption to have a material impact on our consolidated condensed financial statements. We will adopt SFAS No. 151 on January 1, 2006.

measurement for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS No. 153 is effective for nonmonetary exchanges occurring after June 30, 2005. We adopted SFAS No. 153 on July 1, 2005.

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. We undertake no obligation to publicly update or revise any forward–looking statement. Our expectations regarding our business outlook, including changes in revenue, pricing, capital spending, profitability, 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.

These forecasts may be substantially different from actual results, which are affected by those risk factors and the timing of any of those risk factors identified in the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” and “Risk Factors Related to Our Business” sections contained herein, as well as the risk factors described in our Annual Report on Form 10–K for the year ended December 31, 2004 and those set forth from time to time in our filings with the Securities and Exchange Commission (“SEC”). These documents are available through the Company’s web site or through the SEC’s Electronic Data Gathering and Analysis Retrieval System (EDGAR) athttp://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 the Euro and the net asset or net liability position in a currency other than the functional currency.

Foreign Currency Forward Contracts

At September 30, 2005, we had entered into several foreign currency forward contracts with notional amounts aggregating $76.8 million to hedge exposure to currency fluctuations in various foreign currencies, including the British Pound Sterling, the Norwegian Krone, the Euro, the Canadian Dollar and the Brazilian Real. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of September 30, 2005 for contracts with similar terms and maturity dates, we recorded a loss of $2.4 million to adjust these foreign currency forward contracts to their fair market value. This loss offsets designated foreign exchange gains resulting from the underlying exposures and is included in selling, general and administrative expense in our consolidated condensed statement of operations.

At September 30, 2005, we had also entered into several foreign currency forward contracts with notional amounts aggregating $214.4 million to hedge exposure to currency fluctuations in various foreign currencies, including the British Pound Sterling, the Euro and the Canadian Dollar. These exposures arise when local currency operating expenses are not in balance with local currency revenue collections. These foreign currency forward contracts do not qualify for hedge accounting. Based on quoted market prices as of September 30, 2005 for contracts with similar terms and maturity dates, we recorded a loss of $7.5 million to adjust these foreign currency forward contracts to their fair market value. This loss is included in revenues ($3.2 million ) and cost of revenues ($4.3 million) 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

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 Securities 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, 2005, our disclosure controls and procedures are functioning effectively to provide reasonable assurance that the information required to be disclosed by us in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission (“SEC”) rules and forms. There has been no change in our internal controls over financial reporting during the quarter ended September 30, 2005 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

On March 29, 2002, we announced that we had been advised that the Securities and Exchange Commission (“SEC”) and the Department of Justice (“DOJ”) are conducting investigations into allegations of violations of law relating to Nigeria and other related matters. The SEC has issued a formal order of investigation into possible violations of provisions under the Foreign Corrupt Practices Act (“FCPA”) regarding anti–bribery, books and records and internal controls. The SEC has 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 are providing documents to and cooperating fully with the SEC and DOJ. The DOJ and the SEC have issued subpoenas to, or otherwise asked for interviews with, current and former employees in connection with the investigations regarding Nigeria, Angola and Kazakhstan. In addition, we have conducted internal investigations into these matters.

Our internal investigations have 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 Nigeria, Angola and Kazakhstan, as well as potential liabilities to governmental authorities in Nigeria. The investigation in Nigeria was substantially completed during the first quarter of 2003 and, based upon current information, we do not expect that any such potential liabilities will have a material adverse effect on our consolidated financial statements. The internal investigations in Angola and Kazakhstan were substantially completed in the third quarter of 2004. Evidence obtained during the course of the investigations has been provided to the SEC and DOJ.

The Department of Commerce, Department of the Navy and DOJ (the “U.S. agencies”) have investigated compliance with certain export licenses issued to Western Geophysical from 1994 through 2000 for export of seismic equipment leased by the People’s Republic of China. We acquired Western Geophysical in August 1998 and subsequently transferred related assets to WesternGeco in December 2000. WesternGeco continued to use the licenses until 2001. Under the WesternGeco Formation Agreement, we owe indemnity to WesternGeco for certain matters. We are cooperating fully with the U.S. agencies.

We have received a subpoena from a grand jury in the Southern District of New York regarding goods and services we delivered to Iraq from 1995 through 2003 during the United Nations Oil—for—Food Program. We have also received a request from the SEC to provide a written statement and certain information regarding our participation in that program. We have responded to both the subpoena and the request and may provide additional information and documents in the future. Other companies in the energy industry are believed to have received similar subpoenas and requests.

The U.S. agencies, the SEC and other authorities have a broad range of civil and criminal sanctions they may seek to impose against corporations and individuals in appropriate circumstances including, but not limited to, injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs. Such agencies and authorities have entered into agreements with, and obtained a range of sanctions against, several public corporations and individuals arising from allegations of improper payments and deficiencies in books and records and internal controls, whereby civil and criminal penalties were imposed, including in some cases multi—million dollar fines and other sanctions. We are in discussions with the U.S. agencies and the SEC regarding the resolution, including sanctions, associated with certain of the matters described above. It is not possible to accurately predict at this time when any of these matters will be resolved. Based on current information, we cannot predict the outcome of such investigations, whether we will reach resolution through such discussions or what, if any, actions may be taken by the U.S. agencies, the SEC or other authorities or the effect it may have on our consolidated condensed financial statements.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table contains information about our purchases of equity securities during the third quarter of 2005.

Issuer Purchases of Equity Securities


							Maximum Number
					Total Number		(or Approximate
					of Shares		Dollar Value) of
	Total Number		Average		Purchased as		Shares that May
	of Shares		Price Paid		Part of a Publicly		Yet Be Purchased
Period	Purchased¹		per Share¹		Announced Plan		Under the Plan²
July 1—31, 2005		7,465	$	56.59		—		—
August 1—31, 2005		363		56.54		—		—
September 1—30, 2005		25,639		59.19		—		—

Total		33,467	$	58.58		—		—


¹		Represents shares purchased from employees to pay the option exercise price related to stock—for—stock exchanges in option exercises under employee benefit plans.

²		On September 10, 2002, we announced a plan to repurchase from time to time up to $275 million of our outstanding common stock. No shares have been repurchased in 2005 under the plan. Under the plan, we have authorization remaining to repurchase up to $44.5 million in common stock. On October 27, 2005, we announced that the Board of Directors authorized us to repurchase up to an additional $455.5 million of its common stock from time to time. We now have authorization to repurchase up to a total of $500.0 million in common stock. The plan has no expiration date, but may be terminated by the Board of Directors at any time.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

Entry Into Material Definitive Agreements

The following events set forth in items a., b., c. and d. occurred subsequent to the quarterly period covered by this Form 10-Q and are reportable under Item 1.01 of Form 8-K:

On October 27, 2005, our Board of Directors adopted an amendment and restatement to the Baker Hughes Incorporated Supplemental Retirement Plan effective as of January 1, 2005 (the “Plan”). The changes were intended to make the Plan compliant with the rules and regulations issued in connection with the American Jobs Creation Act of 2004 and to extend a four percent matching contribution made by us under the Plan to all base pay and bonus pay received by a participant, except to the extent that the matching contributions were made to a participant’s 401(k) plan. A copy of the amendment and restatement of the Plan is attached hereto as Exhibit 10.1.

	b.		On October 26, 2005, the Compensation Committee of our Board of Directors confirmed that James R. Clark, President and Chief Operating Officer, would be granted five (5) years of credited service as of his first day of employment for determining his eligibility for retirement under our benefits and compensation programs. A copy of the October 26, 2005 letter from Mr. Chad C. Deaton, Chairman and Chief Executive Officer, and a copy of Mr. Clark’s offer letter dated February 15, 2001, is attached hereto as Exhibit 10.2.

	c.		On October 27, 2005, our Board of Directors adopted an amendment to our 2002 Director & Officer Long-Term Incentive Plan whereby vesting of stock options granted to directors would be specified in the Award Agreement setting forth the terms of a director option, provided that no option would vest or become exercisable earlier than the first anniversary of the date of grant of the director option. Prior to the amendment, the Plan provided for all stock options to vest one year after the date of grant. A copy of the Amendment is attached hereto as Exhibit 10.3.

	d.		On October 27, 2005, our Board of Directors approved the following compensation to be paid to our independent directors effective as of January 1,2006:


Annual Retainer:	$	60,000
Audit/Ethics Committee Chairman Annual Retainer:	$	20,000
Other Committee Chairman Annual Retainer:	$	15,000
Audit/Ethics Committee Members Retainer:	$	10,000
Other Committee Members Retainer (excluding Executive Committee):	$	5,000

Annual Non-Retainer Equity:	$	150,000	*

* $100,000 of restricted stock will be awarded each January of each year and $25,000 in stock options awarded in January and July of each year.

The shares of restricted stock and the stock options each vest one-third per year, beginning on the first anniversary of the awards subject to continued service as a director on each vesting date and other terms set forth in our 2002 Director & Officer Long-Term Incentive Plan. A copy of the updated compensation table for independent directors is attached hereto as Exhibit 10.4.

Other Events

	e.		On October 27, 2005, our Board of Directors authorized a dividend in the amount of $0.13 per share to be paid in the fourth quarter of 2005, representing an increase from prior dividends of $0.115 per share. A copy of the news release is attached hereto as Exhibit 99.1.

	f.		On October 27, 2005, our Board of Directors authorized an increase in our stock repurchase program up to an additional $455.5 million of our common stock from time to time. We now have authorization remaining to repurchase $500.0 million in stock. A copy of the news release is attached hereto as Exhibit 99.1.

	g.		On October 26, 2005, the SEC granted our voluntary application to withdraw our common stock from listing and registration on the Pacific Exchange, Inc., effective October 27, 2005. The common stock will continue to be listed on the New York Stock Exchange and the Swiss Exchanges.

ITEM 6. EXHIBITS

	10.1		Baker Hughes Incorporated Supplemental Retirement Plan, as amended and restated effective as of January 1, 2005.

	10.2		Letter dated October 26, 2005, to James R. Clark clarifying Mr. Clark’s employment terms.

	10.3		Amendment to 2002 Director & Officer Long-Term Incentive Plan, effective as of October 27, 2005.

	10.4		Compensation Table for Directors.

	31.1		Certification of Chad C. Deaton, Chief Executive Officer, dated October 28, 2005, pursuant to Rule 13a–14(a) of the Securities Exchange Act of 1934, as amended.

	31.2		Certification of G. Stephen Finley, Chief Financial Officer, dated October 28, 2005, 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 G. Stephen Finley, Chief Financial Officer, dated October 28, 2005, furnished pursuant to Rule 13a–14(b) of the Securities Exchange Act of 1934, as amended.

	99.1		News Release dated October 27, 2005.

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 28, 2005		By: /s/ G. STEPHEN FINLEY
		G. Stephen Finley Sr. Vice President – Finance and Administration and Chief Financial Officer

Date: October 28, 2005		By: /s/ ALAN J. KEIFER
		Alan J. Keifer Vice President and Controller

Index to Exhibits

10.1		Baker Hughes Incorporated Supplemental Retirement Plan, as amended and restated effective as of January 1, 2005.

10.2		Letter dated October 26, 2005, to James R. Clark clarifying Mr. Clark’s employment terms.

10.3		Amendment to 2002 Director & Officer Long-Term Incentive Plan, effective as of October 27, 2005.

10.4		Compensation Table for Directors.

31.1		Certification of Chad C. Deaton, Chief Executive Officer, dated October 28, 2005, pursuant to Rule 13a–14(a) of the Securities Exchange Act of 1934, as amended.

31.2		Certification of G. Stephen Finley, Chief Financial Officer, dated October 28, 2005, 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 G. Stephen Finley, Chief Financial Officer, dated October 28, 2005, furnished pursuant to Rule 13a–14(b) of the Securities Exchange Act of 1934, as amended.

99.1		News Release dated October 27, 2005.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Good

BAKER HUGHES a GE (BHI) 10-Q2005 Q3 Quarterly report

Content analysis

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents