BJ SERVICES CO - 10-Q Quarterly Report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2004

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

For the Transition Period From to .

Commission file number 1-10570

BJ SERVICES COMPANY

(Exact name of registrant as specified in its charter)


Delaware		63-0084140
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5500 Northwest Central Drive, Houston, Texas		77092
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (713) 462-4239

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12 b-2. of the Exchange Act.) YES x NO ¨

There were 161,508,419 shares of the registrant’s common stock, $.10 par value, outstanding as of August 10, 2004.

BJ SERVICES COMPANY

INDEX


		Page
PART I - FINANCIAL INFORMATION:

Item 1. Financial Statements

	Consolidated Condensed Statement of Operations (Unaudited) - Three and Nine months ended June 30, 2004 and 2003	3

	Consolidated Condensed Statement of Financial Position (Unaudited) - June 30, 2004 and September 30, 2003	4

	Consolidated Statement of Stockholders’ Equity (Unaudited) – Nine months ended June 30, 2004	5

	Consolidated Condensed Statement of Cash Flows (Unaudited) - Nine months ended June 30, 2004 and 2003	6

	Notes to Unaudited Consolidated Condensed Financial Statements	7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		20

Item 3. Quantitative and Qualitative Disclosures About Market Risk		33

Item 4. Controls and Procedures		34

PART II - OTHER INFORMATION		35

PART I

FINANCIAL INFORMATION

Item 1. Financial Statements

BJ SERVICES COMPANY

CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS (UNAUDITED)

(In thousands, except per share amounts)


	Three Months Ended June 30,						Nine Months Ended June 30,
	2004			2003			2004			2003
Revenue	$	658,662		$	546,576		$	1,906,521		$	1,554,280
Operating expenses:
Cost of sales and services		498,484			423,210			1,440,320			1,213,974
Research and engineering		11,923			10,606			34,256			30,285
Marketing		20,788			18,976			60,218			54,450
General and administrative		20,133			17,634			58,041			52,956
Loss on disposal of assets		1,117			329			2,045			598

Total operating expenses		552,445			470,755			1,594,880			1,352,263

Operating income		106,217			75,821			311,641			202,017
Interest expense		(3,975	)		(3,982	)		(12,321	)		(11,724	)
Interest income		1,279			442			2,997			1,305
Other income/(expense) - net		83,604			(275	)		83,008			(3,625	)

Income before income taxes		187,125			72,006			385,325			187,973
Income tax expense		57,838			22,462			121,262			60,151

Net income	$	129,287		$	49,544		$	264,063		$	127,822

Earnings per share:
Basic	$	.80		$	.31		$	1.65		$	.81
Diluted	$	.79		$	.31		$	1.62		$	.79

Weighted average shares outstanding:
Basic		160,882			158,097			159,735			157,827
Diluted		163,915			161,770			163,034			161,162

The accompanying notes are an integral part of these consolidated condensed financial statements

BJ SERVICES COMPANY

CONSOLIDATED CONDENSED STATEMENT OF FINANCIAL POSITION

(UNAUDITED)

(In thousands)


	June 30, 2004		September 30, 2003
	June 30, 2004		September 30, 2003
ASSETS

Current assets:
Cash and cash equivalents	$	307,170	$	277,666
Short-term investments		229,774		—
Receivables - net		526,974		469,656
Inventories:
Products		120,652		109,383
Work in process		2,173		2,048
Parts		51,540		51,137

Total inventories		174,365		162,568
Deferred income taxes		8,066		718
Other current assets		34,232		31,100

Total current assets		1,280,581		941,708
Property - net		884,717		850,340
Deferred income taxes		36,286		66,877
Goodwill		885,816		879,710
Other assets		42,077		47,322

	$	3,129,477	$	2,785,957

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	227,353	$	220,031
Short-term borrowings		1,526		5,888
Current portion of long-term debt		18,399		—
Accrued employee compensation and benefits		67,818		69,205
Income and other taxes		107,983		82,192
Accrued insurance		17,001		14,772
Other accrued liabilities		78,272		78,573

Total current liabilities		518,352		470,661
Commitments and contingencies (Note 7)
Long-term debt		478,924		493,754
Deferred income taxes		15,482		7,475
Other long-term liabilities		151,951		163,435
Stockholders’ equity		1,964,768		1,650,632

	$	3,129,477	$	2,785,957

The accompanying notes are an integral part of these consolidated condensed financial statements

BJ SERVICES COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (UNAUDITED)

(In thousands)


	Common Stock Shares	Common Stock		Capital In Excess of Par			Treasury Stock			Unearned Compensation			Retained Earnings			Accumulated Other Comprehensive Income			Total
Balance, September 30, 2003	158,306	$	17,376	$	964,348		$	(348,277	)	$	—		$	1,026,832		$	(9,647	)	$	1,650,632
Comprehensive income:
Net income														61,513
Other comprehensive income, net of tax:
Cumulative translation adjustments																	6,916
Forward foreign exchange contracts																	368
Total comprehensive income																				68,797
Reissuance of treasury stock for:
Stock option plan	45							1,020						(48	)					972
Stock purchase plan	495							11,157						(217	)					10,940
Stock incentive plan	95				(3,103	)		2,144						898						(61	)
Stock incentive plan grant					7,273						(7,273	)
Recognition of unearned compensation											606									606

Balance, December 31, 2003	158,941	$	17,376	$	968,518		$	(333,956	)	$	(6,667	)	$	1,088,978		$	(2,363	)	$	1,731,886

Comprehensive income:
Net income														73,264
Other comprehensive income, net of tax:
Cumulative translation adjustments																	(549	)
Forward foreign exchange contracts																	(147	)
Total comprehensive income																				72,568
Reissuance of treasury stock for:
Stock option plan	1,703							38,162						(12,216	)					25,946
Revaluation of awards-stock incentive plan					1,608						(1,608	)
Recognition of unearned compensation											874									874

Balance, March 31, 2004	160,644	$	17,376	$	970,126		$	(295,794	)	$	(7,401	)	$	1,150,026		$	(3,059	)	$	1,831,274

Comprehensive income:
Net income														129,287
Other comprehensive income, net of tax:
Cumulative translation adjustments																	(3,382	)
Forward foreign exchange contracts																	(156	)
Total comprehensive income																				125,749
Reissuance of treasury stock for:
Stock option plan	449							10,110						(3,139	)					6,971
Revaluation of awards-stock incentive plan					521						(521	)
Recognition of unearned compensation											774									774

Balance, June 30, 2004	161,093	$	17,376	$	970,647		$	(285,684	)	$	(7,148	)	$	1,276,174		$	(6,597	)	$	1,964,768

The accompanying notes are an integral part of these consolidated condensed financial statements

BJ SERVICES COMPANY

CONSOLIDATED CONDENSED STATEMENT OF CASH FLOWS (UNAUDITED)

(In thousands)


	Nine Months Ended June 30,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	264,063		$	127,822
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		93,908			89,886
Deferred income taxes		48,885			21,036
Minority interest		2,000			3,967
Amortization of unearned compensation		2,254			831
Loss on long-lived assets		2,045			598
Changes in:
Receivables		(56,551	)		(92,659	)
Inventories		(11,799	)		(4,098	)
Prepaid expenses		(5,154	)		(2,911	)
Accounts payable		7,319			17,309
Other current assets and liabilities		10,693			41,602
Other - net		17,484			5,903

Net cash provided by operating activities		375,147			209,286

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(139,329	)		(121,382	)
Proceeds from disposal of assets		927			3,607
Purchase of U.S. Treasury securities		(229,774	)		—
Acquisitions of businesses, net of cash acquired		(15,242	)		—

Net cash used for investing activities		(383,418	)		(117,775	)

CASH FLOWS FROM FINANCING ACTIVITIES:
(Repayments)/Proceeds from short-term borrowings, net		(4,362	)		465
Debt issuance costs		(1,042	)		—
Proceeds from exercise of stock options and stock purchase plan		43,521			14,479

Net cash provided by financing activities		38,117			14,944

Effect of exchange rate changes on cash		(342	)		2,226

Increase in cash and cash equivalents		29,504			108,681
Cash and cash equivalents at beginning of period		277,666			84,727

Cash and cash equivalents at end of period	$	307,170		$	193,408

Cash Paid for Interest and Taxes:
Interest	$	5,180		$	5,302
Taxes		63,440			16,959

The accompanying notes are an integral part of these consolidated condensed financial statements

BJ SERVICES COMPANY

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 1 General

In the opinion of management, the unaudited consolidated condensed financial statements of BJ Services Company (the “Company”) include all adjustments (consisting solely of normal recurring adjustments) necessary for a fair presentation of its financial position and statement of stockholders’ equity as of June 30, 2004, its results of operations for the three and nine-month periods ended June 30, 2004 and 2003 and cash flows for the nine-month periods ending June 30, 2004 and 2003. The consolidated condensed statement of financial position at September 30, 2003 is derived from the September 30, 2003 audited consolidated financial statements. Although management believes the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. The results of operations for the three and nine-month periods ended June 30, 2004 and cash flows for the nine-month periods ended June 30, 2004, are not necessarily indicative of the results to be expected for the full year.

Certain amounts for fiscal 2003 have been reclassified in the accompanying consolidated condensed financial statements to conform to the current year presentation.

Note 2 Earnings Per Share (“EPS”)

Basic EPS excludes dilution and is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted EPS is based on the weighted-average number of common shares outstanding during each period and the assumed exercise of dilutive instruments (stock option plans, stock purchase plan, and stock incentive plan) less the number of treasury shares assumed to be purchased with the exercise proceeds using the average market price of the Company’s common stock for each of the periods presented. No dilutive effect has been included for the convertible senior notes issued April 24, 2002 (see Note 5 of the Notes to the Consolidated Financial Statements included in the Company’s annual report on Form 10-K for the fiscal year ending September 30, 2003) because the Company currently has the ability and intent to settle the conversion price in cash.

The following table presents information necessary to calculate earnings per share for the periods presented (in thousands, except per share amounts):


	Three Months Ended June 30,				Nine Months Ended June 30,
	2004		2003		2004		2003
Net income	$	129,287	$	49,544	$	264,063	$	127,822

Weighted-average common shares outstanding		160,882		158,097		159,735		157,827

Basic earnings per share	$	.80	$	.31	$	1.65	$	.81


	Three Months Ended June 30,				Nine Months Ended June 30,
	2004		2003		2004		2003
Weighted-average common and dilutive potential common shares outstanding:
Weighted-average common shares outstanding		160,882		158,097		159,735		157,827
Assumed exercise of stock options⁽¹⁾		3,033		3,673		3,299		3,335

		163,915		161,770		163,034		161,162

Diluted earnings per share	$	.79	$	.31	$	1.62	$	.79

⁽¹⁾	For the three and nine months ended June 30, 2003 and 2004 no options were antidilutive.

Note 3 Employee Stock Plans

The Company has an Employee Stock Purchase Plan and several Incentive Plans that provide for the issuance of stock options and other awards of the Company’s common stock, which are described more fully in Note 13 of the Notes to the Consolidated Financial Statements included in the Company’s annual report on Form 10-K for the fiscal year ended September 30, 2003. Statement of Financial Accounting Standards (“SFAS”) 123, Accounting for Stock-Based Compensation, encourages, but does not require, companies to record compensation cost for employee stock-based compensation plans at fair value as determined by generally recognized option pricing models such as the Black-Scholes model or a binomial model. Because of the inexact and subjective nature of deriving stock option values using these methods, the Company has adopted the disclosure-only provisions of SFAS 123 and continues to account for stock-based compensation as it has in the past using the intrinsic value method prescribed in Accounting Principles Board (“APB”) 25, Accounting for Stock Issued to Employees. Accordingly, no compensation expense has been recognized in the consolidated condensed statement of operations for the Company’s Employee Stock Purchase Plan and the incentive plans. In December 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS No.148, Accounting for Stock-Based Compensation-

Transition and Disclosure, an amendment of FASB Statement No. 123, Accounting for Stock-Based Compensation. This statement requires pro forma disclosures on an interim basis as if the Company had applied the fair value recognition provisions of SFAS 123.

The following pro forma table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS 123 to the Company’s Employee Stock Purchase Plan and the incentive plans (in thousands, except per share amounts):


	Three Months Ended June 30,						Nine Months Ended June 30,
	2004			2003			2004			2003
Net income, as reported	$	129,287		$	49,544		$	264,063		$	127,822
Add: total stock-based employee compensation expense included in reported net income, net of tax		774			277			2,254			831
Less: total stock-based employee compensation expense determined under SFAS 123 for all awards, net of tax		(1,575	)		(955	)		(16,061	)		(15,712	)

Net income, pro forma	$	128,486		$	48,866		$	250,256		$	112,941

Earnings per share:
Basic, as reported	$	.80		$	.31		$	1.65		$	.81
Basic, pro forma	$	.80		$	.31		$	1.57		$	.72
Diluted, as reported	$	.79		$	.31		$	1.62		$	.79
Diluted, pro forma	$	.78		$	.30		$	1.53		$	.70

Note 4 Debt and Bank Credit Facilities

In June 2004, the Company replaced its then existing credit facility with a revolving credit facility (the “Revolving Credit Facility”) that permits borrowings up to $400 million in principal amount. The Revolving Credit Facility includes a $50 million sublimit for the issuance of standby letters of credit and a $20 million sublimit for swingline loans. Swingline loans have short-term maturities and the remaining amounts outstanding under the Revolving Credit Facility become due and payable in June 2009. Interest on outstanding borrowings is charged based on prevailing market rates. The Company is charged various fees in connection with the Revolving Credit Facility, including a commitment fee based on the average daily unused portion of the commitment. In addition, the Revolving Credit Facility charges a utilization fee on all outstanding loans and letters of credit while the usage of the Revolving Credit Facility exceeds 33%. There were no outstanding borrowings under the Revolving Credit Facility at June 30, 2004.

Holders of the Company’s convertible senior notes can require the Company to repurchase the notes in April 2005. The Company has the option to pay the repurchase price in cash or stock. Currently, the Company has the ability and intent to finance the purchase of the convertible senior notes on a long-term basis under the Revolving Credit Facility and therefore, continues to classify $400.0 million of the $418.4 million outstanding as of June 30, 2004 as long-term debt on the consolidated condensed statement of financial position. For further information on the convertible senior notes, see Note 5 in the Company’s Form 10-K for the fiscal year ending September 30, 2003.

Note 5 Segment Information

The Company has three reportable segments: U.S./Mexico Pressure Pumping, International Pressure Pumping and Other Oilfield Services. The U.S./Mexico Pressure Pumping segment includes cementing services and stimulation services (consisting of fracturing, acidizing, sand control, nitrogen, coiled tubing and service tool services) provided throughout the United States and Mexico, both offshore and onshore. The International Pressure Pumping segment also includes cementing and stimulation services provided to customers in more than 50 countries in the major international oil and natural gas producing areas of Latin America, Europe, Russia, Africa, Asia, Canada, China and the Middle East. The Other Oilfield Services segment consists of production chemicals, casing and tubular services, process and pipeline services and completion tools and completion fluids services in the U.S. and in select markets internationally.

The accounting policies of the segments are the same as those described in the summary of significant accounting policies in Note 2 of the Notes to the Consolidated Financial Statements included in the Company’s annual report on Form 10-K for the fiscal year ended September 30, 2003. Operating segment performance is evaluated based on operating income. Intersegment sales and transfers are not material.

Summarized financial information concerning the Company’s segments is shown in the following table. The “Corporate” column includes corporate expenses not allocated to the operating segments.


		U.S./Mexico Pressure Pumping		International Pressure Pumping		Other Oilfield Services		Corporate			Total
	(in thousands)
Three Months Ended June 30, 2004

Revenues		$	341,692	$	192,469	$	124,283	$	218		$	658,662
Operating income (loss)			94,582		4,271		16,981		(9,617	)		106,217

Three Months Ended June 30, 2003

Revenues		$	268,225	$	182,420	$	95,976	$	(45	)	$	546,576
Operating income (loss)			62,829		11,314		13,916		(12,238	)		75,821

Nine Months Ended June 30, 2004

Revenues		$	923,690	$	662,444	$	319,631	$	756		$	1,906,521
Operating income (loss)			234,995		68,630		37,191		(29,175	)		311,641
Identifiable assets			882,892		1,046,675		533,766		666,144			3,129,477

Nine Months Ended June 30, 2003

Revenues		$	712,363	$	578,971	$	263,023	$	(77	)	$	1,554,280
Operating income (loss)			134,411		64,709		33,449		(30,552	)		202,017
Identifiable assets			842,436		1,072,188		482,327		272,772			2,669,723

A reconciliation from the segment information to consolidated income before income taxes is set forth below (in thousands):


	Three Months Ended June 30,						Nine Months Ended June 30,
	2004			2003			2004			2003
Total operating profit for Reportable segments	$	106,217		$	75,821		$	311,641		$	202,017
Interest expense		(3,975	)		(3,982	)		(12,321	)		(11,724	)
Interest income		1,279			442			2,997			1,305
Other income/(expense) – net		83,604			(275	)		83,008			(3,625	)

Income before income taxes	$	187,125		$	72,006		$	385,325		$	187,973

Note 6 Acquisitions

On November 26, 2003, the Company completed the acquisition of Cajun Tubular Services, Inc. (“Cajun”) for a total purchase price of $8.1 million (net of cash). Cajun, located in Lafayette, Louisiana, provides tubular running, testing and torque monitoring services to the Gulf of Mexico market. This business complements the Company’s casing and tubular services business in the Other Oilfield Services segment.

On December 2, 2003, the Company acquired the assets and business of Petro-Drive, a division of Grant Prideco, Inc., for a total purchase price of $7 million. Petro-Drive, located in Lafayette, Louisiana, is a leading provider of hydraulic and diesel hammer services to the Gulf of Mexico market and select markets internationally. This business complements the Company’s casing and tubular services business in the Other Oilfield Services segment.

The Company is in the process of completing its review and determination of the fair values of the assets acquired. Accordingly, allocation of the purchase price is subject to revision based on final determination of the asset values. The pro forma financial information for these acquisitions is not included as they were not material to the Company.

Note 7 Commitments and Contingencies

Litigation

The Company, through performance of its service operations, is sometimes named as a defendant in litigation, usually relating to claims for bodily injuries or property damage (including claims for well or reservoir damage). The Company maintains insurance coverage against such claims to the extent deemed prudent by management. The Company believes that there are no existing claims that are likely to have a material adverse effect on the Company’s financial position or results of operations for which it has not already provided.

Through a series of acquisitions, the Company assumed responsibility for certain claims and proceedings made against the Western Company of North America, Nowsco Well Service Ltd. and OSCA in connection with their businesses. Some, but not all, of such claims and proceedings will continue to be covered under insurance policies of the Company’s predecessors that were in place at the time of the acquisitions. Although the outcome of the claims and proceedings against the Company (including Western, Nowsco and OSCA) cannot be predicted with certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on the Company’s financial position or results of operations for which it has not already provided.

Chevron Phillips Litigation

method for using enzymes to decompose used drilling mud. Although BJ has its own patents for remediating damage resulting from drill-in fluids (as opposed to drilling muds) in oil and gas formations (products and services which are offered under the registered “MUDZYMES” trademark), the Company approached Phillips for a license of the ‘477 patent. BJ was advised that Phillips had licensed this patent on an exclusive basis to Geo-Microbial Technologies, Inc. (“GMT”), a company co-owned by a former Phillips employee who is one of the inventors on the ‘477 patent, and that BJ should deal with GMT in obtaining a sublicense. BJ entered into a five year sublicense agreement with GMT in 1997.

Early in 2000, Phillips advised BJ that Phillips had reportedly terminated the license agreement between Phillips and GMT for GMT’s non-payment of royalties and that BJ’s sublicense had also been terminated. Even though BJ believes that its sublicense with GMT was not properly terminated and BJ’s MUDZYMES treatments may not be covered by the ‘477 patent, in 2000, BJ stopped offering its enzyme product for use on drilling mud and drill-in fluids in the U.S. Nevertheless, Chevron Phillips is claiming that the use of enzymes in fracturing fluids and other applications in the oil and gas industry falls under the ‘477 patent. Further, even though their patent is valid only in the United States, Chevron Phillips is requesting that the court award it damages for BJ’s use of enzymes in foreign countries on the theory that oil produced from wells treated with enzymes is being imported into the United States.

The Company disputes Chevron Phillips’ interpretation of the ‘477 patent and its theory of damages, and has vigorously defended itself against the allegations. On November 25^th and 26^th of 2002, the Court conducted a hearing regarding the scope and the interpretation of the claims in the ‘477 patent. Following the hearing, the Court issued a ruling on March 16, 2003, which we believe interprets the ‘477 patent in a manner that is consistent with BJ’s position. Based on this ruling, BJ filed a Motion for Summary Judgment seeking a determination that fracturing fluids with enzymes do not come within the scope of the ‘477 patent. The Court granted this Motion on July 2, 2003. Subsequently, BJ filed a Motion for Summary Judgment relating to the use of MUDZYMES treatment outside of the United States. On September 22, 2003, the Court granted the Company’s Motion and dismissed this portion of the Chevron Phillips’ case. Chevron Phillips has filed a Notice of Appeal with the Court of Appeals for the Federal Circuit. Although the earlier rulings from the District Court have been favorable to the Company’s position, they could be overturned on appeal. Given the scope of these claims, the possibility of very costly litigation and even a substantial adverse verdict still exists. However, the Company does not presently believe it is likely that the results of this litigation will have a material adverse impact on the Company’s financial position or results of operations.

Halliburton – Python Litigation

temporary restraining order and a preliminary injunction against both Weatherford and BJ to prevent either company from selling competing tools. On March 4, 2003, the District Court issued its opinion denying Halliburton’s requests. The Court denied Halliburton’s Motion to reconsider and Halliburton filed an appeal with the Court of Appeals for the Federal Circuit. Oral argument took place on June 10, 2004 and on June 14, 2004, the Court of Appeals issued its ruling affirming the District Court’s opinion. Halliburton has recently submitted both of its patents for re-examination to the U.S. Patent Office, seeking to re-affirm the validity of their patents. Halliburton has filed a motion to stay the litigation pending re-examination by the Patent Office.

The Company believes that the current design of the Python plug offered by BJ does not infringe any of the valid claims in the two Halliburton patents. The Company also believes that certain claims in the Halliburton patents are invalid based upon prior art demonstrated in products offered well before Halliburton filed for its patents. BJ’s revenue from the sale of its Python tools since the inception of this product in the summer of 2001 is approximately $4.8 million. The Company believes that it has no liability for infringement of the Halliburton patents. Moreover, even if the patents are found to be enforceable and the Company is found to have infringed them, the Company does not believe it is likely that the results of this litigation will have a material adverse impact on the Company’s financial position or the results of operations.

Halliburton – Vistar Litigation

On March 17, 2000, BJ Services Company filed a lawsuit against Halliburton Energy Services in the United States District Court for the Southern District of Texas (Houston). In the lawsuit, BJ alleged that a well fracturing fluid system used by Halliburton infringes a patent issued to BJ in January 2000 for a method of well fracturing referred to by BJ as “Vistar^®”. This case was tried in March and April of 2002. The jury reached a verdict in favor of BJ on April 12, 2002. The jury determined that BJ’s patent was valid and that Halliburton’s competing fluid system, Phoenix, infringed the BJ patent. The District Court entered a judgment for $101.1 million and a permanent injunction preventing Halliburton from using its Phoenix system. On August 6, 2003, a three-judge panel of the Court of Appeals for the Federal Circuit in Washington, D.C. unanimously affirmed the judgment in BJ’s favor. On October 17, 2003, the Federal Circuit denied Halliburton’s request for a re-hearing. Halliburton filed a Petition for Writ of Certiorari with the U.S. Supreme Court on January 15, 2004. On April 5, 2004 the Supreme Court notified the parties that it would not hear Halliburton’s appeal. On April 14, 2004, Halliburton transferred the sum of $106.4 million to BJ, representing full payment of the original judgment, certain court costs, and interest accrued through that date. For its quarter ending June 30, 2004, the Company has recorded a gain of $86 million ($106 million in award), and $56 million after taxes in “Other income/(expense) – net” in the Consolidated Condensed Statement of Operations, reflecting receipt of this sum.

Newfield Litigation

Exploration. The jury determined that OSCA’s negligence caused or contributed to the blowout and that it was responsible for 86% of the damages suffered by Newfield. The total damage amount awarded to Newfield was $15.5 million (excluding pre- and post-judgement interest). The Court delayed entry of the final judgment in this case pending the completion of the related insurance coverage litigation filed by OSCA against certain of its insurers and its former insurance broker. The Court elected to conduct the trial of the insurance coverage issues based upon the briefs of the parties. In the interim, the related litigation filed by OSCA against its former insurance brokers for errors and omissions in connection with the policies at issue in this case has been stayed. On February 28, 2003, the Court issued its Final Judgement in connection with the Newfield claims, based upon the jury’s verdict. The total amount of the verdict against OSCA is $15.6 million, inclusive of interest. At the same time, the Court issued its ruling on the related insurance dispute finding that OSCA’s coverage for this loss is limited to $3.8 million. Motions for New Trial have been denied by the Judge and the case is now on appeal to the U.S. Court of Appeals for the Fifth Circuit, both with regard to the liability case and the insurance coverage issues. Great Lakes Chemical Corporation, which formerly owned the majority of the outstanding shares of OSCA, has agreed to indemnify BJ for 75% of any uninsured liability in excess of $3 million arising from the Newfield litigation. Taking this indemnity into account, the Company’s share of the uninsured portion of the verdict is approximately $5.7 million. The Company is fully reserved for its share of this liability.

Environmental

Federal, state and local laws and regulations govern the Company’s operation of underground fuel storage tanks. Rather than incur additional costs to restore and upgrade tanks as required by regulations, management has opted to remove the existing tanks. The Company has completed the removal of these tanks and has remedial cleanups in progress related to the tank removals. In addition, the Company is conducting environmental investigations and remedial actions at current and former company locations and, along with other companies, is currently named as a potentially responsible party at four third-party owned waste disposal sites. An accrual of approximately $3.0 million has been established for such environmental matters, which is management’s best estimate of the Company’s portion of future costs to be incurred. Insurance is also maintained for environmental liabilities in amounts which the Company’s management believes are reasonable based on its knowledge of potential exposures.

The Company was notified on May 19, 2003, that misdemeanor criminal charges had been filed against it in connection with the illegal disposal of allegedly hazardous waste from its facility in Ardmore, Oklahoma. The Company’s investigation of this incident concluded that a former employee at the facility, a product handler, had removed and improperly disposed of drums from the facility in September of 2001, without instructions from, or the knowledge of the management at this location. The product handler provided a written statement to the investigating authorities in which he admitted having disposed of the drums without instructions from anyone at the Company and that he knew that his actions were prohibited under law. The criminal proceedings have been dismissed and the Company entered into a Consent Order (a civil proceeding) regarding this matter on March 24, 2004 with the State of Oklahoma, Department of Environmental Quality. A fine of $50,000 was assessed, $25,000 of which has been paid in

cash. BJ expects to receive credit for the balance of the fine by performing cementing services for the Oklahoma Department of Environmental Quality. The Company is also required to pay drum disposal costs of $5,770.

Lease and Other Long-Term Commitments

In December 1999, the Company contributed certain pumping service equipment to a limited partnership. The equipment is used to provide services to the Company’s customers for which the Company pays a service fee over a period of at least six years, but not more than 13 years, at approximately $12 million annually. This is accounted for as an operating lease. The Company owns a 1% interest in the limited partnership. The transaction resulted in a gain that is being deferred and amortized over 13 years. The balance of the deferred gain was $30.8 million and $33.9 million as of June 30, 2004 and September 30, 2003, respectively. The agreement permits substitution of equipment within the partnership as long as the implied fair value of the new property transferred in at the date of substitution equals or exceeds the implied fair value, as defined, of the current property in the partnership that is being replaced. In September 2010, the Company has the option, but not the obligation, to purchase the pumping service equipment for approximately $32 million.

In 1997, the Company contributed certain pumping service equipment to a limited partnership. The equipment is used to provide services to the Company’s customers for which the Company pays a service fee over a period of at least eight years, but not more than 13 years at approximately $10 million annually. This is accounted for as an operating lease. The Company owns a 1% interest in the limited partnership. The transaction resulted in a gain that is being deferred and amortized over 12 years. The balance of the deferred gain was $1.7 and $16.0 million as of June 30, 2004 and September 30, 2003, respectively. The agreement permits substitution of equipment within the partnership as long as the implied fair value of the new property transferred in at the date of substitution equals or exceeds the implied fair value, as defined, of the current property in the partnership that is being replaced. The Company received partnership approval in October 2003 to substitute certain pumping service equipment and has accounted for it as an exchange of like-kind assets with no earnings impact since the earnings process has not yet culminated. As a result of the substitutions, the deferred gain was reduced by $14.1 million during the quarter ended December 31, 2003. In June 2009, the Company has the option, but not the obligation, to purchase the pumping service equipment for approximately $27 million.

Guarantees

The Company routinely issues Parent Company Guarantees (“PCG’s”) in connection with service contracts entered into by the Company’s subsidiaries. The issuance of these PCG’s is frequently a condition of the bidding process imposed by the Company’s customers for work in countries outside of North America. The PCG’s typically provide that the Company guarantees the performance of the services by the Company’s local subsidiary. The term of these PCG’s varies with length of the service contract.

The Company arranges for the issuance of a variety of bank guarantees, performance bonds and standby letters of credit. The vast majority of these are issued in connection with contracts the Company, or a subsidiary, has entered into with its customers. The customer has the right to call on the bank guarantee, performance bond or standby letter of credit in the event that the Company, or the subsidiary, defaults in the performance of the services. These instruments are required as a condition to the Company, or the subsidiary, being awarded the contract, and are typically released upon completion of the contract. The balance of these instruments are predominantly standby letters of credit issued in connection with a variety of the Company’s financial obligations, such as in support of fronted insurance programs, claims administration funding, certain employee benefit plans and temporary importation bonds. The following table summarizes the Company’s other commercial commitments as of June 30, 2004 (in thousands):


			Amount of commitment expiration per period
Other Commercial Commitments	Total Amounts Committed		Less than 1 Year		1–3 Years		4–5 Years		Over 5 Years
Standby Letters of Credit	$	25,754	$	25,750	$	4	$	—	$	—
Bank Guarantees and Performance Bonds		157,966		46,900		99,475		6,288		5,303

Total Other Commercial Commitments	$	183,720	$	72,650	$	99,479	$	6,288	$	5,303

Note 8 Employee Benefit Plans

The Company has a U.S. Benefit Plan, Foreign Benefit Plans, and a Postretirement Benefit Plan, which are described in more detail in Note 9 of the Notes to the Consolidated Financial Statements included in the Company’s annual report on Form 10-K for the fiscal year ended September 30, 2003. Below is the amount of net periodic benefit costs recognized under each plan (in thousands):

U.S. Defined Benefit Pension Plan


	Three Months Ended June 30,						Nine Months Ended June 30,
	2004			2003			2004			2003
Interest cost on projected benefit obligation	$	950		$	975		$	2,850		$	2,925
Expected return on plan assets		(1,002	)		(950	)		(3,006	)		(2,850	)
Net amortization and deferral		157			621			471			1,863

Net pension cost	$	105		$	646		$	315		$	1,938

For fiscal 2004, the Company has a minimum pension funding requirement of $4.9 million for the U.S. plan, of which $1.1 million was funded in the nine months ended June 30, 2004. During the fourth quarter of fiscal 2004, the Company will pay an additional $3.8 million pursuant to the minimum pension funding requirement and make a discretionary contribution of $9 million to the U.S. Plan. These contributions have been and are expected to be funded by cash flows from operating activities. Contributions were not required in fiscal 2003.

Foreign Defined Benefit Pension Plans


	Three Months Ended June 30,						Nine Months Ended June 30,
	2004			2003			2004			2003
Service cost for benefits earned	$	973		$	922		$	2,938		$	2,765
Interest cost on projected benefit obligation		1,457			1,116			4,399			3,347
Expected return on plan assets		(1,320	)		(995	)		(3,985	)		(2,985	)
Recognized actuarial loss		42			18			127			55
Net amortization and deferral		378			352			1,145			1,056

Net pension cost	$	1,530		$	1,413		$	4,624		$	4,238

In fiscal 2004, the Company will have a minimum pension funding requirement of $5.2 million for the foreign plans. Contributions in the amount of $4.7 million were made during the nine months ended June 30, 2004. These contributions have been and are expected to be funded by cash flows from operating activities.

Postretirement Benefit Plan


	Three Months Ended June 30,				Nine Months Ended June 30,
	2004		2003		2004		2003
Service cost for benefits attributed to service during the period	$	729	$	633	$	2,187	$	1,899
Interest cost on accumulated postretirement benefit obligation		597		552		1,791		1,656
Amortization of cumulative unrecognized net loss				12				36

Net periodic postretirement benefit cost	$	1,326	$	1,197	$	3,978	$	3,591

Note 9 Short-Term Investments

Highly liquid investments with maturities of one year or less at the time of purchase are classified as short-term investments. At June 30, 2004, $229.8 million was invested in U.S. treasury bills and notes. The Company accounts for these short-term investments in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities. These short-term investments are being held to maturity and are recorded at amortized cost.

Note 10 New Accounting Standards

be required to segregate plan assets by category, such as debt, equity and real estate, and to provide certain expected rates of return and other informational disclosures. SFAS 132R also requires companies to disclose various elements of pension and postretirement benefit costs in interim-period financial statements for quarters beginning after December 15, 2003 (see Note 8 above). Since SFAS 132R only revises disclosure requirements, it will not have an impact on the Company’s financial position or results of operations.

In January 2003, the FASB issued FASB Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities.” FIN 46 clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. In December 2003, the FASB issued FIN 46(R) which revised certain provisions in the original interpretation and permitted multiple effective dates based upon the nature and formation date of the variable interest entity. Adoption of the provisions of FIN 46 did not have a material impact on the Company’s financial position or results of operations.

Note 11 Subsequent Event

On July 22, 2004, the Company announced the initiation of a regular quarterly cash dividend and declared a dividend of $.08 per common share, payable October 15, 2004 to stockholders of record at the close of business on September 15, 2004.

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

Business

The Company is engaged in providing pressure pumping services and other oilfield services to the petroleum industry worldwide. Services are provided through three segments: U.S./Mexico Pressure Pumping, International Pressure Pumping, and Other Oilfield Services.

The U.S./Mexico and International Pressure Pumping segments provide stimulation and cementing services to the petroleum industry throughout the world. Stimulation services are designed to improve the flow of oil and natural gas from producing formations. Cementing services consists of pumping a cement slurry into a well between the casing and the wellbore to isolate fluids that might otherwise damage the casing and/or affect productivity, or that could migrate to different zones, primarily during the drilling and completion phase of a well.

The Other Oilfield Services segment consists of production chemical services, casing and tubular services, process and pipeline services and completion tools and completion fluids services in the U.S. and select markets internationally.

Market Conditions

The Company’s worldwide operations are primarily driven by the number of oil and natural gas wells being drilled, the depth and drilling conditions of such wells, the number of well completions and the level of workover activity. Drilling activity, in turn, is largely dependent on the price of crude oil and natural gas. These market factors often lead to volatility in the Company’s revenue and profitability, especially in the United States and Canada, where the Company historically has generated in excess of 50% of its revenue. Historical market conditions are reflected in the table below:


	Three Months Ended June 30,						Nine Months Ended June 30,
	2004		2003		Change		2004		2003		Change
Rig Count: ⁽¹⁾
U.S.		1,164		1,028	13	%		1,130		925	22	%
International⁽²⁾		1,040		967	8	%		1,188		1,080	10	%
Commodity Prices (average):
Crude Oil (WTI)	$	38.34	$	29.02			$	34.92	$	30.41
Natural Gas (Henry Hub)	$	6.11	$	5.64			$	5.61	$	5.45

⁽¹⁾	Estimate of drilling activity as measured by average active drilling rigs based on Baker Hughes Incorporated rig count information.

⁽²⁾	Includes Mexico rig count of 113 and 84 for the three-month period ended June 30, 2004 and 2003, respectively, and 109 and 81 for the nine-month period ended June 30, 2004 and 2003, respectively.

During the June 2004 quarter, drilling activity in the U.S. remained strong, increasing 13% over the same period in fiscal 2003. The Company’s management estimates that the average U.S. rig count for the fourth quarter of fiscal 2004 will average between 1,210 and 1,225.

Canadian drilling activity averaged 202 and 379 active drilling rigs for the three and nine months ended June 30, 2004, respectively. The average drilling activity level during the three months ended June 30, 2004 is consistent with the same period in the prior year, but has increased 16% for the nine months ended June 30, 2004 over the same period in the prior year. The Canadian drilling market is currently recovering from spring break-up which is the period during which heavy drilling and other equipment is not permitted to travel on the roads. Accordingly, the Company anticipates Canadian revenue to increase 5% to 10% during the quarter ending September 30, 2004, compared to the same period in prior year.

Drilling activity outside North America has historically been less volatile than the U.S. and Canadian drilling activity, considering the average international drilling activity as a whole. During the three months ended June 30, 2004, active international drilling rigs (excluding Canada) averaged 838 rigs, an increase of 10% in activity compared to the same period in fiscal 2003. The Company expects international drilling activity outside of Canada to remain relatively flat for fiscal 2004 compared to fiscal 2003.

Acquisitions

Results of Operations

The following table sets forth selected key operating statistics reflecting the Company’s financial results (in millions):


	Three Months Ended June 30,								Nine Months Ended June 30,
	2004			2003			Change		2004			2003			Change
Consolidated revenue	$	658.7		$	546.6		21	%	$	1,906.5		$	1,554.3		23	%
Revenue by business segment:
U.S./Mexico Pressure Pumping		341.7			268.2		27	%		923.7			712.4		30	%
International Pressure Pumping		192.5			182.4		6	%		662.4			579.0		14	%
Other Oilfield Services		124.3			96.0		29	%		319.6			263.0		22	%
Corporate		.2			—					.8			(0.1	)

Consolidated operating income	$	106.2		$	75.8		40	%	$	311.6		$	202.0		54	%
Operating income/(loss) by business segment:
U.S./Mexico Pressure Pumping		94.6			62.8		51	%		235.0			134.4		75	%
International Pressure Pumping		4.3			11.3		-62	%		68.6			64.7		6	%
Other Oilfield Services		17.0			13.9		22	%		37.2			33.4		11	%
Corporate		(9.6	)		(12.2	)				(29.2	)		(30.6	)

Consolidated Revenue and Operating Income: Increased drilling activity for the U.S. and Mexico, pricing improvement in the U.S. and improved revenue from all service lines in the Other Oilfield Services segment are the primary reasons for the increase in revenue for the three months ended June 30, 2004, compared to the same period in 2003. Increased activity, international growth and acquisitions are the primary reasons for the increase in the Other Oilfield Services segment. Operating income also benefited from the increased revenue described above, but was partially offset by decreased margins in Norway, Colombia and Africa. For the three months ended June 30, 2004, consolidated operating income margins improved to 16.1% from 14.0% reported in the same period in prior year.

For the nine month period ended June 30, 2004, increased drilling activity in the U.S. and Canada is the primary reason for the increase in our revenue and operating income compared to the same period in prior year. For the nine months ended June 30, 2004, operating income margins improved to 16.3% from 13.0% reported in the same period prior year.

See below discussion on individual segments for further revenue and operating income variance details.

U.S./Mexico Pressure Pumping Segment

Results for the three-month period ended June 30, 2004 and 2003

The increase in revenue is primarily a result of a combined U.S. and Mexico increase in drilling activity of 15% over the same period last year, the Company’s geographic expansion into Poza Rica (Mexico) and improved pricing in the U.S. As of June 30, 2004, approximately 50% of our customers were on the new U.S. price book implemented on May 1, 2004.

The increase in operating income was primarily due to the increases in revenue described above, coupled with labor and equipment efficiency gains. Labor efficiencies were achieved by maintaining a stable employee base and increasing their utilization on jobs. The headcount for the three-month period ended June 30, 2004 increased 7% compared to the same period last year with revenue increasing 27%. Equipment efficiencies were achieved through utilization of newer and more efficient equipment. Also, as activity increases, the utilization rate of equipment increases.

Results for the nine-month period ended June 30, 2004 and 2003

The increase in revenue is primarily a result of a combined U.S. and Mexico increase in drilling activity of 23% over the same period last year, the Company’s geographic expansion into Poza Rica (Mexico) and improved pricing in the U.S. As of June 30, 2004, approximately 50% of our customers were on the new U.S. price book implemented on May 1, 2004.

The increase in operating income was primarily due to the increases in revenue described above, coupled with labor and equipment efficiency gains noted previously. The headcount for the nine-month period ended June 30, 2004 increased 6% compared to the same period last year with revenue increasing 30%.

Outlook

During the fourth quarter of fiscal 2004, the Company estimates U.S. rig activity will average between 1,210 and 1,225. In determining forecasted rig activity, management reviews proprietary projected rig count data provided by a third party and has discussions with customers regarding their expectations for upcoming service requirements. Management analyzes the data obtained and an internal rig count projection is determined. Under normal circumstances and depending on the geographic mix and types of services provided, an increase in rig count will usually result in an increase in the Company’s revenue.

The Company has issued a price book increase for its U.S. pressure pumping operations. The increase averages 7% above its current price book in the U.S. and was effective May 1, 2004. The degree of customer acceptance of the price book increase will depend on activity levels and competitive pressures.

International Pressure Pumping Segment

Results for the three-month period ended June 30, 2004 and 2003

Canadian operations were the primary reason for the increase in revenue. Canadian revenue increased 22% with drilling activity flat. Excluding the benefit of a 5% gain in the Canadian exchange rate against the U.S. dollar, the increase in revenue is due to a different job mix (higher stimulation activity and coiled tubing work – unrelated to rig count) and a 100% realization of the 5% price book increase implemented in July 2003. Russia revenue increased 53% from increased stimulation activity. Activity increases in India improved revenue there by 169%. These increases in revenue were partially offset by decreased revenue in Norway, Colombia, and Africa. In Norway and Colombia, major customers have curtailed their drilling programs and primarily as a result of this, Norway’s revenue declined 33% and revenue in Colombia decreased 53%. Revenue from Africa was down 51%, primarily as a result of a customer’s activity reduction in Nigeria.

Although revenue increased during the third fiscal quarter of 2004 for this segment, operating income declined. As described above, the curtailment of high margin work in Norway and Colombia adversely affected our operating income in those countries. Operating income in Africa declined for the reasons discussed above. Cost reductions have been initiated to accommodate current activity levels. While the weakening U.S. dollar increased Canadian revenue, it had minimal impact on operating income as most of our expenses are denominated in Canadian dollars. Operating income also declined in Canada primarily as a result of maintaining our current headcount levels through the spring break-up period. Management anticipates the resumption of high activity levels in Canada, and expects to need the additional headcount. The Company also had a decline in operating profit from its stimulation vessel in the North Sea. The customer that contracted for the vessel shut down operations in the North Sea for two months during the quarter ended June 30, 2004, and since there are significant fixed costs associated with operating the stimulation vessel, there was a decline in operating profit. These declines were somewhat offset by increased operating income in India and Russia, for the reasons described above.

Results for the nine-month period ended June 30, 2004 and 2003

Canadian operations were the primary reason for the increase in revenue. Canadian revenue increased 51% compared to the same period in the prior year, with drilling activity up 16%. The Canadian increase in revenue is attributed to activity related gains of 30%, price improvement of 3% and favorable foreign exchange translation of 18%. In addition, Russia revenue increased 24% from increased stimulation activity. Due to a contract award in the last half of fiscal 2003, the Company’s stimulation vessel in the North Sea also contributed to our increase in revenue over first nine months in fiscal 2003. These increases in revenue were partially offset by decreased revenue in Saudi Arabia, Norway and Colombia. There was no fracturing activity in Saudi Arabia during the first four months of fiscal 2004. In Norway and Colombia, major customers have curtailed their drilling programs and, primarily as a result, Norway revenue declined 31%, and revenue in Colombia decreased 34%.

While the weakening U.S. dollar increased Canadian revenue, it had minimal impact on operating income as most of our expenses are denominated in Canadian dollars. The increase in operating income is primarily due to the activity increases in Canada, which also resulted in improved labor utilization efficiencies. Labor efficiencies were achieved by increasing revenue generated per employee, compared to the same period in fiscal 2003. This was partially offset by the decreased margins in Saudi Arabia, Colombia and Norway as a result of the decline in activity described above.

Outlook

Compared to levels experienced during the third fiscal quarter of fiscal 2004, the Company expects international drilling activity outside of Canada to remain relatively flat for the fourth fiscal quarter. As the Canadian market recovers from spring break-up in the fourth fiscal quarter of 2004, the Company anticipates Canadian revenue to increase 5% to 10% during the quarter ending September 30, 2004, compared to the same period in prior year.

The Company has issued a price book increase for its Canadian pressure pumping operations. The increase averages 5% above the former price book in Canada and was effective August 1, 2004. The degree of customer acceptance of the price book increase will depend on activity levels and competitive pressures.

Other Oilfield Services Segment

Results for the three-month period ended June 30, 2004 and 2003

Excluding the impact of the Cajun and Petro-Drive acquisitions, revenue would have increased 25%. The increase in revenue for this segment was primarily attributable to the process and pipeline services. Due to the high oil prices experienced in the prior year, many refineries deferred their maintenance shut-downs last year, and as a result, process and pipeline services did not perform as many inspections last year in what has been seasonally the best quarter. Revenue from each service line within Other Oilfield Services increased during the quarter. The increase in the completion tools business line was primarily achieved through customer activity improvement in the Gulf of Mexico area. International expansion is the reason for the increase in our revenue for the completion fluids and tubular business lines.

Excluding the impact of the Cajun and Petro-Drive acquisitions, operating income would have increased 20%. The increase is primarily attributable to completion tools, completion fluids and process and pipeline businesses for the reasons described above.

Results for the nine-month period ended June 30, 2004 and 2003

Excluding the impact of the Cajun and Petro-Drive acquisitions, revenue would have increased 18% for the same reasons discussed above.

Excluding the impact of the Cajun and Petro-Drive acquisitions, operating income would have increased 9%. The increase is primarily attributable to completion tools and tubular business lines for the reasons described above. The process and pipeline service business had a very strong June 30, 2004 quarter, which made up for the lower average margins experienced in the March 31, 2004 quarter. In our completion fluids business, while revenue increased in Norway, this increased activity was in lower margin product sales compared to the prior year.

Outlook

Due to seasonality, the revenue for the Other Oilfield Services segment is expected to decline by approximately 10% for the fourth fiscal quarter of 2004. The third fiscal quarter is typically process and pipeline’s most active quarter and as such, revenue for the process and pipeline business is projected to decline in the fourth fiscal quarter. Revenue for the remainder of this segment is expected to increase modestly for the fourth fiscal quarter of 2004 over the same period of fiscal 2003, primarily attributable to expanded markets for the casing and tubular, completion tools and completion fluids businesses.

Other Operating Expenses

Research and engineering, marketing and general and administrative expenses increased 11.9% and 10.8% for the three and nine-month periods ending June 30, 2004, respectively, versus the same periods in the prior year. As a percent of revenue, each of these expenses were consistent with the same periods of the prior year. The following table sets forth the Company’s other operating expenses as a percentage of revenue:


	Three Months Ended June 30,				Nine Months Ended June 30,
	2004		2003		2004		2003
Research and engineering	1.8	%	1.9	%	1.8	%	1.9	%
Marketing expense	3.2	%	3.5	%	3.2	%	3.5	%
General and administrative expense	3.1	%	3.2	%	3.0	%	3.4	%

Tax Expense

The effective tax rate was 30.9% during the June 30, 2004 quarter, down from 32% experienced in the first six months of fiscal 2004. This is primarily due to business tax credits that were realized during the third fiscal quarter of 2004. The tax rate for fiscal 2004 is expected to be 31.5%.

Financial

Position and Liquidity

Financial Position

The Company’s working capital increased $291.2 million at June 30, 2004 compared to September 30, 2003, primarily as a result of the increase in cash and cash equivalents, short-term investments and accounts receivable, partially offset by an increase in income and other taxes. Cash and cash equivalents, plus short-term investments, increased $259.3 million since September 30, 2003 as a result of positive cash flow from operations, proceeds from the exercise of stock options and the Halliburton award of $86.4 million (net of legal fees). Receivables increased $56.6 million primarily as a result of an increase in U.S. revenue. The increase in income and other taxes is due to the provision of income tax associated with the Halliburton award. During the first nine months, significant cash payments included capital expenditures of $139.3 million, annual prepayment of insurance premiums and the distribution of annual incentives to employees for fiscal 2003.

Liquidity and Capital Resources

Cash flow from operations is expected to be our primary source of liquidity in 2004. Our sources of liquidity also include cash and cash equivalents of $307.2 million at June 30, 2004, short-term investments in U.S. treasury securities of $229.8 million, and the below financing facilities (in millions):


Financing Facility	Expiration	Borrowings at June 30, 2004		Available at June 30, 2004
Revolving Credit Facility	June 2009		None	$	400.0
Discretionary	Various times within the next 12 months	$	1.5		92.4

outstanding loans and letters of credit while the usage of the Revolving Credit Facility exceeds 33%. There were no outstanding borrowings under the Revolving Credit Facility at June 30, 2004.

The Revolving Credit Facility includes various customary covenants and other provisions including the maintenance of certain profitability and solvency ratios, none of which materially restrict the Company’s activities. The Company is currently in compliance with all covenants imposed by the terms of its indebtedness.

In addition to the Revolving Credit Facility, the Company had $93.9 million in various unsecured, discretionary lines of credit at June 30, 2004, which expire at various dates within the next 12 months. There are no requirements for commitment fees or compensating balances in connection with these lines of credit, and interest on borrowings is based on prevailing market rates. There was $1.5 million and $5.9 million in outstanding borrowings under these lines of credit at June 30, 2004 and September 30, 2003, respectively.

Management believes that cash flow from operations combined with cash and cash equivalents, short-term investments, the Revolving Credit Facility, and other discretionary credit facilities, provide the Company with sufficient capital resources and liquidity to manage its routine operations, meet debt service obligations, fund projected capital expenditures, repurchase common stock, pay a regular quarterly dividend and support the development of our short-term and long-term operating strategies. If the discretionary lines of credit are not renewed, or if borrowings under these lines of credit otherwise become unavailable, the Company expects to refinance this debt by arranging additional committed bank facilities or through other long-term borrowing alternatives.

At June 30, 2004 and September 30, 2003, the Company had issued and outstanding $78.9 million of unsecured 7% Series B Notes due in 2006, net of discount.

On April 24, 2002, the Company sold convertible senior notes with a face value at maturity of $516.4 million (gross proceeds of $408.4 million). The notes are unsecured senior obligations that rank equally in right of payment with all of the Company’s existing and future senior unsecured indebtedness. The Company used the aggregate net proceeds of $400.1 million to fund a substantial portion of the purchase price of its acquisition of OSCA, which closed on May 31, 2002, and for general corporate purposes. There was $418.4 million and $414.9 million outstanding under the convertible senior notes at June 30, 2004 and September 30, 2003, respectively.

The notes will mature in 2022 and cannot be called by the Company for three years after issuance. If the Company exercises its right to call the notes, the redemption price must be paid in cash. Holders of the notes can require the Company to repurchase the notes on the third, fifth, tenth and fifteenth anniversaries of the issuance. The first such anniversary will occur during the third fiscal quarter of 2005. Currently, the Company has the ability and intent to finance the purchase of convertible senior notes on a long-term basis under the Revolving Credit Facility and therefore, has continued to classify $400.0 million of the $418.4 million outstanding as of

June 30, 2004 as long-term debt on the consolidated condensed statement of financial position. The Company has the option to pay the repurchase price in cash or stock. The issue price of the notes was $790.76 for each $1,000 in face value, which represents an annual yield to maturity of 1.625%. Of this 1.625% yield to maturity, 0.50% per year on the issue price will be paid semi-annually in cash for the life of the security.

The notes are convertible into BJ Services common stock at an initial rate of 14.9616 shares for each $1,000 face amount note. This rate results in an initial conversion price of $52.85 per share (based on the purchaser’s original issue discount) and represents a premium of 45% over the April 18, 2002 closing sale price of the Company’s common stock on the New York Stock Exchange of $36.45 per share. The Company has the option to settle notes that are surrendered for conversion using cash. Generally, except upon the occurrence of specified events, including a credit rating downgrade to below investment grade, holders of the notes are not entitled to exercise their conversion rights until the Company’s stock price is greater than a specified percentage (beginning at 120% and declining to 110% at the maturity of the notes) of the accreted conversion price per share. At June 30, 2004, the accreted conversion price per share would have been $54.02.

Capital Expenditures

The Company currently expects that 2004 capital expenditures will be between $200 million and $210 million, compared to $167 million spent in 2003. The 2004 capital expenditure program is expected to consist primarily of spending for the enhancement of the Company’s existing pressure pumping equipment, continued investment in the U.S. fracturing fleet recapitalization initiative and stimulation expansion internationally. The Company has determined it will expand its current U.S. fleet recapitalization initiative. The actual amount of 2004 capital expenditures will depend primarily on maintenance requirements and expansion opportunities and is expected to be funded by cash flows from operating activities.

Other Sources and Uses of Cash

On April, 14, 2004, the Company received approximately $86 million, net of legal costs, from Halliburton Energy Services ($56 million after tax), representing the full payment for the judgment awarded the Company for patent infringement litigation that was initiated in 2002 (see Note 7 to the Consolidated Condensed Financial Statements).

During fiscal 2004, due to the poor market performance of the pension plan investments in fiscal 2001 and 2002, the Company will have a minimum pension funding requirement of $10.1 million, and plans to make a discretionary contribution of an additional $9 million. Contributions of $5.8 million were made during the nine months ended June 30, 2004. These contributions have been and are expected to be funded by cash flows from operating activities.

Off Balance Sheet Transactions

Accounting Pronouncements

In December 2003, the FASB issued an exposure draft amending FASB Statement No. 128 (“SFAS 128”), Earnings per Share. The exposure draft would amend the computational guidance of SFAS 128. When applying the treasury stock method for year-to-date diluted earnings per share (EPS), SFAS 128 requires that the number of incremental shares included in the denominator be determined by computing a year-to-date weighted average of the number of incremental shares included in each quarterly diluted EPS computation. Under this proposed Statement, the number of incremental shares included in year-to-date diluted EPS would be computed using the average market price of common shares for the year-to-date period. The proposed Statement also would eliminate the provisions of SFAS 128 that allow an entity to

rebut the presumption that contracts with the option of settling in either cash or stock will be settled in cash. In addition, the proposed Statement would require that shares to be issued upon conversion of a mandatorily convertible security be included in the computation of basic EPS from the date that conversion becomes mandatory. Under the current SFAS 128, we have excluded the convertible senior notes from our diluted EPS calculation as we have the ability and intent to settle the obligation with cash instead of stock. If implemented as proposed, we would be required to include the convertible senior notes in the diluted EPS calculation, which could have a material effect on our diluted EPS. The provisions of the final Statement could differ from this disclosure; as a result, the actual application of any final Statement could result in different effects than discussed.

In December 2003, the FASB issued FASB Statement No. 132-Revised 2003 (“SFAS 132R”), Employers’ Disclosures about Pensions and Other Postretirement Benefits. This standard increases the existing disclosure requirements by requiring more details about pension plan assets, benefit obligations, cash flows, benefit costs and related information. Companies will be required to segregate plan assets by category, such as debt, equity and real estate, and to provide certain expected rates of return and other informational disclosures. SFAS 132R also requires companies to disclose various elements of pension and postretirement benefit costs in interim-period financial statements for quarters beginning after December 15, 2003 (see Note 7). Since SFAS 132R only revises disclosure requirements, it will not have an impact on the Company’s financial position or results of operations.

Critical Accounting Policies

For an accounting policy to be deemed critical, the accounting policy must first include an estimate that requires a company to make assumptions about matters that are highly uncertain at the time the accounting estimate is made. Second, different estimates that the company reasonably could have used for the accounting estimate in the current period, or changes in the accounting estimate that are reasonably likely to occur from period to period, must have a material impact on the presentation of the company’s financial condition or results of operations. Estimates and assumptions about future events and their effects cannot be predicted with certainty. The Company bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating

environment changes. There have been no material changes or developments in our evaluation of the accounting estimates and the underlying assumptions or methodologies that we believe to be Critical Accounting Policies disclosed in our Form 10-K for the fiscal year ending September 30, 2003.

Forward Looking Statements

This document contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities Exchange Act of 1934 concerning, among other things, the Company’s prospects, expected revenues, expenses and profits, developments and business strategies for its operations, all of which are subject to certain risks, uncertainties and assumptions. These forward-looking statements are identified by their use of terms and phrases such as “expect,” “estimate,” “project,” “believe,” “achievable,” “anticipate” and similar terms and phrases. These statements are based on certain assumptions and analyses made by the Company in light of its experience and its perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such statements are subject to:

•

fluctuating prices of crude oil and natural gas,

•

conditions in the oil and natural gas industry, including drilling activity,

•

reduction in prices or demand for our products and services,

•

general global economic and business conditions,

•

international political instability, security conditions, and hostilities,

•

the Company’s ability to expand its products and services (including those it acquires) into new geographic markets,

•

our ability to generate technological advances and compete on the basis of advanced technology,

•

risks from operating hazards such as fire, explosion, blowouts and oil spills,

•

unexpected litigation for which insurance and customer agreements do not provide protection,

•

changes in currency exchange rates,

•

weather conditions that affect conditions in the oil and natural gas industry,

•

the business opportunities that may be presented to and pursued by the Company,

•

competition and consolidation in the Company’s business, and

•

changes in law or regulations and other factors, many of which are beyond the control of the Company.

If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual results may vary materially from those expected, estimated or projected. Other than as required under securities laws, the Company does not assume a duty to update these forward looking statements. This list of risk factors is not intended to be comprehensive. See “Risk Factors” included elsewhere in the Company’s Form 10-K for the fiscal year ending September 30, 2003.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The table below provides information about the Company’s market sensitive financial instruments and constitutes a “forward-looking statement.” The Company’s major market risk exposure is to foreign currency fluctuations internationally and changing interest rates, primarily in the United States, Canada and Europe. The Company’s policy is to manage interest rates through use of a combination of fixed and floating rate debt. If the floating rates were to increase by 10% from June 30, 2004 rates, the Company’s combined interest expense to third parties would increase by approximately $636 each month in which such increase continued. At June 30, 2004, the Company had issued fixed-rate debt of $497.3 million. These instruments are fixed-rate and, therefore, do not expose the Company to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by $19.6 million if interest rates were to decline by 10% from their rates at June 30, 2004.

Periodically, the Company borrows funds which are denominated in foreign currencies, which exposes the Company to market risk associated with exchange rate movements. There were no such borrowings denominated in foreign currencies at June 30, 2004. When the Company believes prudent, the Company enters into forward foreign exchange contracts to hedge the impact of foreign currency fluctuations. There was one forward foreign exchange contract outstanding as of June 30, 2004, in the amount of $2.3 million. This contract is being accounted for as cash flow hedges of future foreign currency denominated obligation. This contract will settle in August 2004. All items described are non-trading and are stated in U.S. dollars. The expected maturity dates and fair value of our market risk sensitive instruments are as follows (in thousands):


	Expected Maturity Dates											Fair Value June 30, 2004
	2004		2005	2006		2007	2008	Thereafter		Total		Fair Value June 30, 2004
SHORT-TERM BORROWINGS
Bank borrowings; U.S. $ denominated	$	1,526								$	1,526	$	1,526
Average variable interest rate – 5.00% at June 30, 2004

LONG-TERM BORROWINGS
7% Series B Notes – U.S. $ denominated
Fixed interest rate – 7%				$	78,924						78,924		83,495

1.625% Convertible Notes ⁽¹⁾
U.S. $ denominated
Fixed interest rate – 1.625%		18,399						$	400,000		418,399		436,522

FINANCIAL INSTRUMENTS
Forward foreign exchange contracts		65									65		65

Total	$	19,990	—	$	78,924	—	—	$	400,000	$	498,914	$	521,608

⁽¹⁾

The holders of the convertible notes can require the Company to repurchase the convertible notes in May 2005, 2007 and 2009. In the event the holders require the Company to repurchase the convertible notes, the Company expects the obligation to be paid with cash, or to refinance this debt on a long-term basis.

Item 4. Controls and Procedures

(a)

Evaluation of disclosure controls and procedures. Based on their evaluation of the Company’s disclosure controls and procedures as of the end of the period covered by this report, the Chief Executive Officer and Chief Financial Officer of the Company have concluded that the disclosure controls and procedures are effective in ensuring that the information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

(b)

Changes in internal control over financial reporting. There were no changes in the Company’s internal control over financial reporting that occurred during the Company’s most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II

OTHER INFORMATION

Item 1. Legal Proceedings

Litigation

Chevron Phillips Litigation

On July 10, 2002, Chevron Phillips Chemical Company (“Chevron Phillips”) filed a lawsuit against BJ Services Company (“BJ”) for patent infringement in the United States District Court for the Southern District of Texas (Corpus Christi). The lawsuit relates to a patent issued in 1992 to the Phillips Petroleum Company (“Phillips”). This patent (the ‘477 patent) relates to a method for using enzymes to decompose used drilling mud. Although BJ has its own patents for remediating damage resulting from drill-in fluids (as opposed to drilling muds) in oil and gas formations (products and services which are offered under the registered “MUDZYMES” trademark), the Company approached Phillips for a license of the ‘477 patent. BJ was advised that Phillips had licensed this patent on an exclusive basis to Geo-Microbial Technologies, Inc. (“GMT”), a company co-owned by a former Phillips employee who is one of the inventors on the ‘477 patent, and that BJ should deal with GMT in obtaining a sublicense. BJ entered into a five year sublicense agreement with GMT in 1997.

though their patent is valid only in the United States, Chevron Phillips is requesting that the court award it damages for BJ’s use of enzymes in foreign countries on the theory that oil produced from wells treated with enzymes is being imported into the United States.

The Company disputes Chevron Phillips’ interpretation of the ‘477 patent and its theory of damages, and has vigorously defended itself against the allegations. On November 25^th and 26^th of 2002, the Court conducted a hearing regarding the scope and the interpretation of the claims in the ‘477 patent. Following the hearing, the Court issued a ruling on March 16, 2003, which we believe interprets the ‘477 patent in a manner that is consistent with BJ’s position. Based on this ruling, BJ filed a Motion for Summary Judgment seeking a determination that fracturing fluids with enzymes do not come within the scope of the ‘477 patent. The Court granted this Motion on July 2, 2003. Subsequently, BJ filed a Motion for Summary Judgment relating to the use of MUDZYMES outside of the United States. On September 22, 2003, the Court granted the Company’s Motion and dismissed this portion of the Chevron Phillips’ case. Chevron Phillips has filed a Notice of Appeal with the Court of Appeals for the Federal Circuit. Although the earlier rulings from the District Court have been favorable to the Company’s position, they could be overturned on appeal. Given the scope of these claims, the possibility of very costly litigation and even a substantial adverse verdict still exists. However, the Company does not presently believe it is likely that the results of this litigation will have a material adverse impact on the Company’s financial position or results of operations.

Halliburton – Python Litigation

On June 27, 2002, Halliburton Energy Services, Inc. filed suit against BJ and Weatherford International, Inc. for patent infringement in connection with drillable bridge plug tools. These tools are used to isolate portions of a well for stimulation work, after which the plugs are milled out using coiled tubing or a workover rig. Halliburton claims that tools offered by BJ (under the trade name “Python”) and Weatherford infringe two of its patents for a tool constructed of composite material. The lawsuit has been filed in the United States District Court for the Northern District of Texas (Dallas). Halliburton requested that the District Court issue a temporary restraining order and a preliminary injunction against both Weatherford and BJ to prevent either company from selling competing tools. On March 4, 2003, the District Court issued its opinion denying Halliburton’s requests. The Court denied Halliburton’s Motion to reconsider and Halliburton filed an appeal with the Court of Appeals for the Federal Circuit. Oral argument took place on June 10, 2004 and on June 14, 2004, the Court of Appeals issued its ruling affirming the District Court’s opinion. Halliburton has recently submitted both of its patents for re-examination to the U.S. Patent Office, seeking to re-affirm the validity of their patents. Halliburton has filed a motion to stay the litigation pending re-examination by the Patent Office.

patents. Moreover, even if the patents are found to be enforceable and the Company is found to have infringed them, the Company does not believe it is likely that the results of this litigation will have a material adverse impact on the Company’s financial position or the results of operations.

Halliburton – Vistar Litigation

Newfield Litigation

On April 4, 2002, a jury rendered a verdict adverse to OSCA in connection with litigation pending in the United States District Court for the Southern District of Texas (Houston). The lawsuit arose out of a blowout that occurred in 1999 on an offshore well owned by Newfield Exploration. The jury determined that OSCA’s negligence caused or contributed to the blowout and that it was responsible for 86% of the damages suffered by Newfield. The total damage amount awarded to Newfield was $15.5 million (excluding pre- and post-judgement interest). The Court delayed entry of the final judgment in this case pending the completion of the related insurance coverage litigation filed by OSCA against certain of its insurers and its former insurance broker. The Court elected to conduct the trial of the insurance coverage issues based upon the briefs of the parties. In the interim, the related litigation filed by OSCA against its former insurance brokers for errors and omissions in connection with the policies at issue in this case has been stayed. On February 28, 2003, the Court issued its Final Judgement in connection with the Newfield claims, based upon the jury’s verdict. The total amount of the verdict against OSCA is $15.6 million, inclusive of interest. At the same time, the Court issued its ruling on the related insurance dispute finding that OSCA’s coverage for this loss is limited to $3.8 million. Motions for New Trial have been denied by the Judge and the case is now on appeal to the U.S. Court of Appeals for the Fifth Circuit, both with regard to the liability case and the insurance coverage issues. Great Lakes Chemical Corporation, which formerly owned the majority of the outstanding shares of OSCA, has agreed to indemnify BJ for 75% of any uninsured liability in

excess of $3 million arising from the Newfield litigation. Taking this indemnity into account, the Company’s share of the uninsured portion of the verdict is approximately $5.7 million. The Company is fully reserved for its share of this liability.

Environmental

Item	2. Changes in Securities and Use of Proceeds

None

Item	3. Defaults upon Senior Securities

None

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

None

Item 5. Other Information

None

Item 6. Exhibits and Reports on Form 8-K.

(a) Exhibits.


31.1		Section 302 certification for J. W. Stewart

31.2		Section 302 certification for T. M. Whichard

32.1		Section 906 certification furnished for J. W. Stewart

32.2		Section 906 certification furnished for T. M. Whichard

(b) Reports furnished on Form 8-K.

On April 27, 2004, the Company furnished a report on Form 8-K attaching a press release with respect to an announcement of the financial results for the quarter ended March 31, 2004, pursuant to Item 12 of Form 8-K.

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.


	BJ Services Company
	(Registrant)

Date: August 12, 2004	BY	\s\ J. W. Stewart
		J. W. Stewart
		Chairman of the Board

Date: August 12, 2004	BY	\s\ T. M. Whichard
		T. M. Whichard
		Chief Financial Officer

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