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 March 31, 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 160,899,954 shares of the registrant’s common stock, $.10 par value, outstanding as of May 11, 2004.

BJ SERVICES COMPANY

INDEX


PART I - FINANCIAL INFORMATION:

Item 1. Financial Statements

Consolidated Condensed Statement of Operations (Unaudited) - Three and Six months ended March 31, 2004 and 2003		3

Consolidated Condensed Statement of Financial Position (Unaudited) - March 31, 2004 and September 30, 2003		4

Consolidated Statement of Stockholders’ Equity (Unaudited) – Six months ended March 31, 2004		5

Consolidated Condensed Statement of Cash Flows (Unaudited) - Three and Six months ended March 31, 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		19

Item 3. Quantitative and Qualitative Disclosures About Market Risk		32

Item 4. Controls and Procedures		33

PART II - OTHER INFORMATION		34

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 March 31,						Six Months Ended March 31,
	2004			2003			2004			2003
Revenue	$	647,060		$	534,580		$	1,247,859		$	1,007,704
Operating expenses:
Cost of sales and services		484,106			415,031			941,836			790,764
Research and engineering		11,828			10,365			22,333			19,679
Marketing		20,133			18,345			39,430			35,474
General and administrative		20,027			18,947			37,908			35,322
(Gain)/Loss on disposal of assets		550			(331	)		928			269

Total operating expenses		536,644			462,357			1,042,435			881,508

Operating income		110,416			72,223			205,424			126,196
Interest expense		(4,144	)		(3,741	)		(8,346	)		(7,742	)
Interest income		898			344			1,718			863
Other expense - net		(100	)		(2,444	)		(596	)		(3,350	)

Income before income taxes		107,070			66,382			198,200			115,967
Income tax expense		33,806			21,574			63,424			37,689

Net income	$	73,264		$	44,808		$	134,776		$	78,278

Earnings per share:
Basic	$	.46		$	.28		$	.85		$	.50
Diluted	$	.45		$	.28		$	.83		$	.49

Weighted average shares outstanding:
Basic		159,474			157,813			159,165			157,692
Diluted		163,229			160,985			162,583			160,833

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)


	March 31, 2004		September 30, 2003
ASSETS

Current assets:
Cash and cash equivalents	$	387,934	$	277,666
Receivables - net		520,801		469,656
Inventories:
Products		114,049		109,383
Work in process		2,107		2,048
Parts		52,945		51,137

Total inventories		169,101		162,568
Deferred income taxes		—		718
Other current assets		38,195		31,100

Total current assets		1,116,031		941,708
Property - net		865,192		850,340
Deferred income taxes		60,912		66,877
Goodwill		885,810		879,710
Other assets		44,236		47,322

	$	2,972,181	$	2,785,957

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	231,308	$	220,031
Short-term borrowings		12,315		5,888
Accrued employee compensation and benefits		65,241		69,205
Income and other taxes		81,275		82,192
Accrued insurance		16,572		14,772
Other accrued liabilities		78,893		78,573

Total current liabilities		485,604		470,661
Commitments and contingencies (Note 6)
Long-term debt		496,128		493,754
Deferred income taxes		6,881		7,475
Other long-term liabilities		152,294		163,435
Stockholders’ equity		1,831,274		1,650,632

	$	2,972,181	$	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	$	968,518		$	(294,186	)	$	(5,793	)	$	1,148,418		$	(3,059	)	$	1,831,274

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)


	Six Months Ended March 31,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	134,776		$	78,278
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		61,962			57,992
Deferred income taxes		16,504			10,532
Minority interest		1,313			2,655
Amortization of unearned compensation		1,480			554
(Gain)/Loss on long-lived assets		928			269
Changes in:
Receivables		(51,529	)		(76,260	)
Inventories		(6,753	)		(3,909	)
Prepaid expenses		(9,532	)		(7,360	)
Accounts payable		11,852			19,682
Other current assets and liabilities		(6,548	)		5,537
Other - net		12,665			12,234

Net cash provided by operating activities		167,118			100,204

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(83,401	)		(70,915	)
Proceeds from disposal of assets		537			938
Acquisitions of businesses, net of cash acquired		(15,242	)		—

Net cash used for investing activities		(98,106	)		(69,977	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from short-term borrowings, net		6,427			(1,119	)
Proceeds from exercise of stock options and stock purchase plan		33,946			6,725

Net cash provided by financing activities		40,373			5,606

Effect of exchange rate changes on cash		883			1,482

Increase in cash and cash equivalents		110,268			37,315
Cash and cash equivalents at beginning of period		277,666			84,727

Cash and cash equivalents at end of period	$	387,934		$	122,042

Cash Paid for Interest and Taxes:
Interest	$	4,035		$	4,158
Taxes		54,635			16,669

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 March 31, 2004, and its results of operations and cash flows for each of the three and six-month periods ended March 31, 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 and cash flows for the three and six-month periods ended March 31, 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 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 March 31,				Six Months Ended March 31,
	2004		2003		2004		2003
Net income	$	73,264	$	44,808	$	134,776	$	78,278
Weighted-average common shares outstanding		159,474		157,813		159,165		157,692

Basic earnings per share	$	.46	$	.28	$	.85	$	.50


	Three Months Ended March 31,				Six Months Ended March 31,
	2004		2003		2004		2003
Weighted-average common and dilutive potential common shares outstanding:
Weighted-average common shares outstanding		159,474		157,813		159,165		157,692
Assumed exercise of stock options⁽¹⁾		3,755		3,172		3,418		3,141

		163,229		160,985		162,583		160,833

Diluted earnings per share	$	.45	$	.28	$	.83	$	.49

⁽¹⁾	For the three and six months ended March 31, 2004 no options were antidilutive. For the three and six months ended March 31, 2003, 410 thousand and 315 thousand stock options were excluded from the computation of diluted earnings per share due to their antidilutive effect, respectively.

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 March 31,						Six Months Ended March 31,
	2004			2003			2004			2003
Net income, as reported	$	73,264		$	44,808		$	134,776		$	78,278
Add: total stock-based employee compensation expense included in reported net income, net of tax		874			277			1,480			554
Less: total stock-based employee compensation expense determined under SFAS 123 for all awards, net of tax		(1,430	)		(738	)		(14,399	)		(14,757	)

Net income, pro forma	$	72,708		$	44,347		$	121,857		$	64,075

Earnings per share:
Basic, as reported	$	.46		$	.28		$	.85		$	.50

Basic, pro forma	$	.46		$	.28		$	.77		$	.41

Diluted, as reported	$	.45		$	.28		$	.83		$	.49

Diluted, pro forma	$	.45		$	.28		$	.75		$	.40

Note 4 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.

Business Segments


	U.S./Mexico Pressure Pumping		International Pressure Pumping		Other Oilfield Services		Corporate			Total
	(in thousands)
Three Months Ended March 31, 2004
Revenues	$	297,556	$	248,766	$	100,441	$	297		$	647,060
Operating income (loss)		74,206		39,160		8,561		(11,511	)		110,416

Three Months Ended March 31, 2003
Revenues	$	232,156	$	217,671	$	84,757	$	(4	)	$	534,580
Operating income (loss)		38,480		34,152		10,030		(10,439	)		72,223

Six Months Ended March 31, 2004
Revenues	$	581,998	$	469,975	$	195,348	$	538		$	1,247,859
Operating income (loss)		140,413		64,359		20,222		(19,570	)		205,424
Identifiable assets		861,657		1,078,981		507,410		524,133			2,972,181

Six Months Ended March 31, 2003
Revenues	$	444,138	$	396,551	$	167,047	$	(32	)	$	1,007,704
Operating income (loss)		71,582		53,395		19,644		(18,425	)		126,196
Identifiable assets		801,130		1,058,927		459,848		249,014			2,568,919

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


	Three Months Ended March 31,						Six Months Ended March 31,
	2004			2003			2004			2003
Total operating profit for Reportable segments	$	110,416		$	72,223		$	205,424		$	126,196
Interest expense		(4,144	)		(3,741	)		(8,346	)		(7,742	)
Interest income		898			344			1,718			863
Other expense – net		(100	)		(2,444	)		(596	)		(3,350	)

Income before income taxes	$	107,070		$	66,382		$	198,200		$	115,967

Note 5 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 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 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 6 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 acquisition 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

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 for which are offered under the “Mudzyme” 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 Mudzyme 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 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 recently 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 has filed an appeal with the Court of Appeals for the Federal Circuit. Briefs have been submitted by the parties and oral argument at the Court of Appeals is scheduled for June 10, 2004.

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 $4.6 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 will record an estimated gain of $56 million, after taxes, reflecting receipt of this sum, net of legal fees and litigation costs.

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

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 $3.1 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.

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 $31.8 million and $33.9 million as of March 31, 2004 and September 30, 2003, respectively. 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 $1.8 and $16.0 million as of March 31, 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 March 31, 2004 (in thousands):


Other Commercial Commitments	Total Amounts Committed		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	$	36,617	$	36,605	$	—	$	—	$	12
Bank Guarantees and Performance Bonds		153,369		44,626		96,223		5,990		6,530

Total Other Commercial Commitments	$	189,986	$	81,231	$	96,223	$	5,990	$	6,542

Note 7 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 March 31,						Six Months Ended March 31,
	2004			2003			2004			2003
Interest cost on projected benefit obligation	$	950		$	975		$	1,901		$	1,951
Expected return on plan assets		(1,002	)		(950	)		(2,005	)		(1,901	)
Net amortization and deferral		157			621			314			1,242

Net pension cost	$	105		$	646		$	210		$	1,292

In fiscal 2004, the Company will have a minimum pension funding requirement of $3.7 million for the U.S. plan. This is expected to be funded by cash flows from operating activities. Contributions were not required in fiscal 2003 or in the six months ended March 31, 2004.

Foreign Defined Benefit Pension Plans


	Three Months Ended March 31,						Six Months Ended March 31,
	2004			2003			2004			2003
Service cost for benefits earned	$	986		$	913		$	1,844		$	1,819
Interest cost on projected benefit obligation		1,476			1,102			2,232			2,189
Expected return on plan assets		(1,337	)		(982	)		(1,990	)		(1,958	)

Recognized actuarial loss		42			17			35			36
Net amortization and deferral		385			351			704			704

Net pension cost	$	1,552		$	1,401		$	2,825		$	2,790

In fiscal 2004, the Company will have a minimum pension funding requirement of $5.2 million for the foreign plans. This is expected to be funded by cash flows from operating activities. Contributions in the amount of $2 million were made during the six months ended March 31, 2004.

Postretirement Benefit Plan


	Three Months Ended March 31,				Six Months Ended March 31,
	2004		2003		2004		2003
Service cost for benefits attributed to service during the period	$	729	$	633	$	1,458	$	1,266
Interest cost on accumulated postretirement benefit obligation		597		552		1,194		1,104
Amortization of cumulative unrecognized net loss				12				24

Net periodic postretirement benefit cost	$	1,326	$	1,197	$	2,652	$	2,394

Note 8 New Accounting Standards

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 GAAP 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 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.

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 March 31,				Six Months Ended March 31,
	2004		2003		2004		2003
Rig Count: ⁽¹⁾
U.S.		1,118		901		1,114		874
International⁽²⁾		1,325		1,237		1,262		1,137
Commodity Prices (average):
Crude Oil (WTI)	$	35.23	$	34.02	$	33.21	$	31.11
Natural Gas (Henry Hub)	$	5.64	$	6.42	$	5.37	$	5.36

⁽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 107 and 82 for the three-month period ended March 31, 2004 and 2003, respectively, and 107 and 79 for the six-month period ended March 31, 2003 and 2004, respectively.

For the three-month period ended March 31, 2004, the active U.S. rig count averaged 1,118 rigs, a 24% increase in activity compared to the same period in fiscal 2003. The Company’s management estimates that the average U.S. rig count for the third quarter of fiscal 2004 will average between 1,150 to 1,160 and for the forth quarter of fiscal 2004, to average between 1,175 and 1,200.

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 March 31, 2004, active international drilling rigs (excluding Canada) averaged 797 rigs, an increase of 7% in activity compared to the same period in fiscal 2003. Canadian drilling activity also increased during the three months ended March 31, 2004 averaging 528 active drilling rigs, up 7% from the same period of fiscal year 2003. The Company expects international drilling activity outside of Canada to remain relatively flat for fiscal 2004 compared to fiscal 2003. We expect a normal spring break-up in Canada during our third fiscal quarter of 2004, resulting in a 55-60% decline in drilling activity from the average rig count of 528 for the quarter ended March 31, 2004. Spring break-up is the period during which heavy equipment is not permitted on the roads which results in lower drilling activity.

Acquisitions

Results of Operations

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


	Three Months Ended March 31,						Six Months Ended March 31,
	2004			2003			2004			2003
Consolidated revenue	$	647.1		$	534.6		$	1,247.9		$	1,007.7
Revenue by business segment:
U.S./Mexico Pressure Pumping		297.6			232.2			582.0			444.1
International Pressure Pumping		248.8			217.7			470.0			396.6
Other Oilfield Services		100.4			84.8			195.3			167.0
Corporate		.3			—			.5			—

Consolidated operating income	$	110.4		$	72.2		$	205.4		$	126.2
Operating income by business segment:
U.S./Mexico Pressure Pumping		74.2			38.5			140.4			71.6
International Pressure Pumping		39.2			34.2			64.4			53.4
Other Oilfield Services		8.6			10.0			20.2			19.6
Corporate		(11.5	)		(10.4	)		(19.6	)		(18.4	)

Consolidated Revenue and Operating Income: For the three month period ended March 31, 2004, consolidated revenue increased 21%, compared to the prior year’s second quarter, with U.S./Mexico Pressure Pumping revenue increasing 28%, International Pressure Pumping increasing 14% and Other Oilfield Services increasing 18%. Increased drilling activity in the U.S. and Canada is the primary reason for the increase in our pressure pumping segments. Increased activity, international growth and acquisitions are the primary reasons for the increase in the Other Oilfield Services segment. For the three months ended March 31, 2004, operating income margins improved to 17.1% from 13.5% reported in the prior year’s second quarter, due primarily to increased margins from the Company’s U.S./Mexico and Canadian operations.

For the six month period ended March 31, 2004, consolidated revenue increased 24%, compared to the same period of the prior year, with U.S./Mexico Pressure Pumping revenue increasing 31%, International Pressure Pumping increasing 19% and Other Oilfield Services increasing 17%. Increased drilling activity in the U.S. and Canada is the primary reason for the increase in our pressure pumping segments. Additional projects, international growth, and acquisitions are the primary reasons for the increase in the Other Oilfield Services segment. For the six months ended March 31, 2004, operating income margins improved to 16.5% from 12.5% reported in the same period prior year, due primarily to increased margins from the Company’s U.S./Mexico and Canadian operations.

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 March 31, 2004 and 2003

Revenue was $297.6 million, an increase of $65.4 million, or 28% compared to the second quarter of the prior fiscal year. This is primarily a result of a combined U.S. and Mexico increase in drilling activity of 25% over the same period last year. The Company’s geographic expansion into Poza Rica (Mexico) also contributed to the increase in revenue. Pricing in the U.S. market improved approximately 2.5%.

Operating income for the Company’s U.S./Mexico pressure pumping segment was $74.2 million, an increase of $35.7 million, or 93% from the same period of the prior year. The increase in operating income was primarily due to increases in drilling activity and 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 March 31, 2004 increased 6% compared to the same period last year with revenue increasing $65.4 million, or 28%. Equipment efficiencies were achieved through utilization of newer, more efficient and more modern equipment. As activity increases, the utilization rate of equipment increases.

Results for the six-month period ended March 31, 2004 and 2003

Revenue was $582.0 million, an increase of $137.9 million, or 31% compared to the same period of the prior fiscal year. This is primarily a result of a combined U.S. and Mexico increase in drilling activity of 28% over the same period last year. The Company’s geographic expansion into Poza Rica (Mexico) also contributed to the increase in revenue. Pricing in the U.S. market improved approximately 1.5%.

Operating income for the Company’s U.S./Mexico pressure pumping segment was $140.4 million, an increase of $68.8 million, or 96% from the same period of the prior year. The increase in operating income was primarily due to increases in drilling activity and labor and equipment efficiency gains noted previously. The headcount for the six-month period ended March 31, 2004 increased 5% compared to the same period last year with revenue increasing $137.9 million, or 31%.

Outlook

During the third quarter of fiscal 2004, we estimate rig activity in the U.S. to average 3-4% higher compared to levels experienced during the second quarter of fiscal 2004. 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 will average 7% above its current price book in the U.S. and is 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 March 31, 2004 and 2003

Revenue was $248.8 million, an increase of $31.1 million, or 14% from the same period in the prior year. Canadian revenue increased 39% with drilling activity up 7%. The Canadian increase in revenue is attributed to activity gains of 16%, price improvement of 5% and favorable foreign exchange translation of 18%. 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 quarter in fiscal 2003. In addition, activity increases in Venezuela contributed to the revenue increase, as the market conditions have recovered since the national strike, which negatively impacted revenue during the first six months of fiscal 2003. These increases in revenue were partially offset by decreased revenue in Saudi Arabia and Norway. There was no fracturing activity in Saudi Arabia during the first four months of fiscal 2004 and in Norway, there was a decline in rig activity and a decrease in coil tubing work from prior year.

Operating income was $39.2 million, an increase of $5.0 million, or 15% from the same period of the prior year. While the weakening U.S. dollar increased Canadian revenue, it had minimal impact on operating income as most of our expenses are also 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 maintaining a stable employee base and increasing their utilization on jobs. The headcount for the three-month period ended March 31, 2004 increased 10% compared to the same period last year with activity related revenue increasing 16%. The improved margins in Canada were partially offset by the decreased margins in Saudi Arabia as a result of the decline in activity described above.

Results for the six-month period ended March 31, 2004 and 2003

Revenue was $470.0 million, an increase of $73.4 million, or 19% from the same period in the prior year. Canadian revenue increased 59% compared to the same period in the prior year, with drilling activity up 21%. The Canadian increase in revenue is attributed to activity gains of 32%, price improvement of 5% and favorable foreign exchange translation of 22%. 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 six months in fiscal 2003. These increases in revenue were partially offset by decreased revenue in Saudi Arabia and Norway. There was no fracturing activity in Saudi Arabia during the first four months of fiscal 2004 and in Norway, there was a decline in rig activity and a decrease in coil tubing work from prior year.

Operating income was $64.4 million, an increase of $11.0 million, or 21% from the same period of the prior year. While the weakening U.S. dollar increased Canadian revenue, it had minimal impact on operating income as most of our expenses are also 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 as noted previously. The headcount for the six-month period ended March 31, 2004 increased 7% compared to the same period last year with activity related revenue increasing 21%. This was partially offset by the decreased margins in Saudi Arabia as a result of the decline in activity described above.

Outlook

Compared to levels experienced during the second fiscal quarter of fiscal 2004, the Company expects international drilling activity outside of Canada to remain relatively flat for the third fiscal quarter. We expect Canadian drilling activity to increase 15-20% during the third quarter of fiscal 2004 compared to the drilling activity in the third quarter of fiscal 2003. We expect a normal spring break-up in Canada (period during which heavy equipment is not permitted on the roads).

Other Oilfield Services Segment

Results for the three-month period ended March 31, 2004 and 2003

Revenue was $100.4 million, an increase of $15.6 million, or 18% when compared to the same period in fiscal 2003. Excluding the impact of the Cajun and Petro-Drive acquisitions, revenue would have increased 14%. Process and pipeline services and tubular services experienced increased project activity. Completion fluids revenue increased due to higher international activity, most notably in Norway.

Operating income for the Company’s Other Oilfield Services segment was $8.6 million, an decrease of $1.4 million, or 14% from the same period of the prior year. Excluding the impact of the Cajun and Petro-Drive acquisitions, operating income would have declined 19%. The decrease is attributable to project and customer mix in our process and pipeline services, completion tools and completion fluids businesses. For example, while revenue increased in our process and pipeline services division, the average margins for projects completed during the second fiscal quarter of 2004 were lower than those in the prior year. In our completion fluids business, while revenue increased in Norway, this activity was lower margin product sales compared to the prior year.

Results for the six-month period ended March 31, 2004 and 2003

Revenue was $195.3 million, an increase of $28.3 million, or 17% when compared to the same period in fiscal 2003. Excluding the impact of the Cajun and Petro-Drive acquisitions,

revenue would have increased 14%. Process and pipeline services and tubular services experienced increased project activity. Completion fluids revenue increased due to higher international activity, most notably in Norway.

Operating income for the Company’s Other Oilfield Services segment was $20.2 million, an increase of $0.6 million, or 3% from the same period of the prior year. Excluding the impact of the Cajun and Petro-Drive acquisitions, operating income would be consistent with prior year. The reason for the consistency in operating income even though revenue increased, is attributable to project and customer mix in our process and pipeline services, completion tools and completion fluids businesses. For example, while revenue increased in our process and pipeline services division, the average margins for projects completed during the second fiscal quarter of 2004 were lower than those in the prior year. In our completion fluids business, while revenue increased in Norway, this activity was lower margin product sales compared to the prior year.

Outlook

We expect revenue for this segment to increase modestly for the remainder of fiscal 2004 over fiscal 2003, primarily attributable to expanded markets for the tubular, completion tools and completion fluids businesses.

Other Operating Expenses

Research and engineering, marketing and general and administrative expenses increased 11.4% and 10.2% for the three and six-month periods ending March 31, 2004 versus the same period in the prior year. As a percent of revenue, each of these expenses were consistent with the same period of the prior year. We expect these expenses will increase slightly for the remainder of fiscal 2004 as a percentage of revenue, but will be slightly less than fiscal 2003 as a percentage of revenue. The following table sets forth the Company’s other operating expenses as a percentage of revenue:


	Three Months Ended March 31,				Six Months Ended March 31,
	2004		2003		2004		2003
Percentage of research and engineering expense to revenue	1.8	%	1.7	%	1.8	%	2.0	%
Percentage of marketing expense to revenue	3.1	%	3.2	%	3.2	%	3.5	%
Percentage of general and administrative expense to revenue	3.1	%	3.0	%	3.0	%	3.5	%

Financial Position and Liquidity

Financial Position

The Company’s working capital increased $159.4 million at March 31, 2004 compared to September 30, 2003, primarily as a result of the increase in cash and cash equivalents and accounts receivable. Cash and cash equivalents increased $110.3 million since September 30, 2003 as a result of positive cash flow from operations and proceeds from the exercise of stock options. Receivables increased $51.1 million as a result of an increase in activity. During the first six months, significant cash payments included an annual pre-payment for insurance of approximately $13 million and the distribution of annual incentives for fiscal 2003 of approximately $11 million.

Liquidity and Capital Resources

Cash flow from operations is expected to be our primary source of liquidity in 2004. Our sources of liquidity include cash of $387.9 million at March 31, 2004, cash flow from operations, and the below financing facilities (in millions):


Financing Facility	Expiration	Borrowings at March 31, 2004	Available at March 31, 2004
Committed Credit Facility	June 2004	None	$400.0
Discretionary	Various 2004	$12.3	81.6

The Company has in place a $400 million committed line of credit (“Committed Credit Facility”). The Committed Credit Facility consists of a $200 million, 364-day commitment that renews annually at the option of the lenders and a $200 million three-year commitment. The current Committed Credit Facility expires in June 2004 and the Company expects to replace this facility during the Company’s third fiscal quarter of 2004. There were no borrowings under the Committed Credit Facility during the quarter ended March 31, 2004.

In addition to the Committed Credit Facility, the Company had $93.9 million in various unsecured, discretionary lines of credit at March 31, 2004, which expire at various dates in 2004. 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 were $12.3 million and $5.9 million in outstanding borrowings under these lines of credit at March 31, 2004 and September 30, 2003, respectively.

Management believes that cash and cash equivalents, the Committed Credit Facility, combined with other discretionary credit facilities and cash flows from operations, provide the Company with sufficient capital resources and liquidity to manage its routine operations, meet debt service obligations and fund projected capital expenditures. 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 March 31, 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 were $417.2 million and $414.9 million outstanding under the convertible senior notes at March 31, 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. 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 March 31, 2004, the accreted conversion price per share would have been $53.87.

Capital Expenditures

The Company anticipates spending approximately $200 million in fiscal 2004, 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 made significant progress with the 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

As disclosed in Note 6 to the financial statements, on April, 14, 2004, the Company received approximately $86 million, net of 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.

In 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 $8.9 million. This is expected to be funded by cash flows from operating activities. Contributions of $2 million were made during the six months ended March 31, 2004.

The Company’s total debt (net of cash) was 6.2% of its total capitalization (total capitalization equals the sum of debt, net of cash and stockholders’ equity) at March 31, 2004, compared to 11.9% at September 30, 2003. The Committed 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.

Off Balance Sheet Transactions

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 transaction resulted in a gain that is being deferred and amortized over 12 years. The balance of the deferred gain was $1.8 and $16.0 million as of March 31, 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.

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.

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 March 31, 2004 rates, the Company’s combined interest expense to third parties would increase by approximately $5,125 each month in which such increase continued. At March 31, 2004, the Company had issued fixed-rate debt of $496 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 $19.5 million if interest rates were to decline by 10% from their rates at March 31, 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 March 31, 2004. When the Company believes prudent, the Company enters into forward foreign exchange contracts to hedge the impact of foreign currency fluctuations. There were two forward foreign exchange contracts outstanding as of March 31, 2004, each in the amount of $2.3 million. These contracts are being accounted for as cash flow hedges of future foreign currency denominated obligations. Beginning in May 2004 and ending in August 2004, one contract will settle in each of the following two quarters. All items described are non-trading and are stated in U.S. dollars (in thousands).


	Expected Maturity Dates											Fair Value March 31, 2004
	2004		2005	2006		2007	2008	Thereafter		Total		Fair Value March 31, 2004
SHORT-TERM BORROWINGS
Bank borrowings; U.S. $ denominated	$	12,315								$	12,315	$	12,315
Average variable interest rate – 5.00% at March 31, 2004

LONG-TERM BORROWINGS
7% Series B Notes – U.S. $ denominated
Fixed interest rate – 7%				$	78,911						78,911		85,565

1.625% Convertible Notes ⁽¹⁾
U.S. $ denominated
Fixed interest rate – 1.625%								$	417,216		417,216		436,316

FINANCIAL INSTRUMENTS
Forward foreign exchange contracts	$	221									221		221

Total	$	12,536	—	$	78,911	—	—	$	417,216	$	508,663	$	534,417

⁽¹⁾

The holders of the convertible notes can require the Company to repurchase the convertible notes in May 2005 and 2007. 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 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

Through acquisition 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

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.

Halliburton – Python Litigation

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, the Supreme Court notified the parties that it would not hear Halliburton’s appeal. On April, 14, 2004, Halliburton wire 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 will record an estimated gain of $56 million, after taxes, reflecting receipt of this sum, net of legal fees and litigation costs.

Newfield Litigation

Environmental

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.

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

Company held its Annual Meeting of Stockholders on January 22, 2004 in Houston, Texas.

(a)

All nominated directors were elected. Directors elected at the Annual Meeting:


Class II Directors	Votes in Favor	Votes Withheld
Don D. Jordan	141,092,242	2,232,207
William H. White	141,014,307	2,310,142

There were no abstentions or broker non-votes.

(b)

Directors with terms of office continuing after the Annual Meeting:

Class I Directors

John R. Huff

Michael E. Patrick

Class III Directors

L. William Heiligbrodt

James L. Payne

J. W. Stewart

(c)

The stockholders voted in favor of the 2003 Incentive Plan:


Votes in Favor	Votes Against	Votes Abstained	Broker Non-Votes
112,903,098	14,269,594	1,312,402	14,839,355

(d)

The stockholders voted against the stockholder proposal on the Company’s operations in Burma:


Votes in Favor	Votes Against	Votes Abstained	Broker Non-Votes
5,836,011	108,765,710	13,882,371	14,840,357

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 January 20, 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 first quarter ended December 31, 2003, pursuant to Item 12 of Form 8-K.

On March 29, 2004, the Company furnished a report on Form 8-K announcing a price book increase for U.S. pressure pumping pursuant to Item 9 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: May 14, 2004	BY	/s/ J. W. Stewart
		J. W. Stewart
		Chairman of the Board

Date: May 14, 2004	BY	/s/ T. M. Whichard
		T. M. Whichard
		Chief Financial Officer

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