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, 2005

¨	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 161,915,771 shares of the registrant’s common stock, $.10 par value, outstanding as of May 5, 2005.

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, 2005 and 2004	3

	Consolidated Condensed Statement of Financial Position (Unaudited) - March 31, 2005 and September 30, 2004	4

	Consolidated Statement of Stockholders’ Equity and Other Comprehensive Income (Unaudited) – Six months ended March 31, 2005	5

	Consolidated Condensed Statement of Cash Flows (Unaudited) - Six months ended March 31, 2005 and 2004	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		34

Item 4. Controls and Procedures		35

PART II - OTHER INFORMATION		36

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,
	2005			2004			2005			2004
Revenue	$	795,863		$	647,060		$	1,533,645		$	1,247,859
Operating expenses:
Cost of sales and services		573,593			484,106			1,123,679			941,836
Research and engineering		13,083			11,828			25,545			22,333
Marketing		22,170			20,133			43,845			39,430
General and administrative		26,218			20,027			48,701			37,908
Loss on disposal of assets		392			550			1,330			928

Total operating expenses		635,456			536,644			1,243,100			1,042,435

Operating income		160,407			110,416			290,545			205,424
Interest expense		(3,790	)		(4,144	)		(7,758	)		(8,346	)
Interest income		3,609			898			6,572			1,718
Other income (expense) - net		(282	)		(100	)		9,319			(596	)

Income before income taxes		159,944			107,070			298,678			198,200
Income tax expense		50,390			33,806			94,091			63,424

Net income	$	109,554		$	73,264		$	204,587		$	134,776

Earnings per share:
Basic	$	.68		$	.46		$	1.26		$	.85
Diluted	$	.66		$	.45		$	1.24		$	.83

Weighted average shares outstanding:
Basic		162,300			159,474			162,358			159,165
Diluted		164,858			163,229			164,981			162,583

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, 2005		September 30, 2004
ASSETS

Current assets:
Cash and cash equivalents	$	653,875	$	424,725
Short-term investments		—		229,930
Receivables - net		625,068		544,946
Inventories:
Products		135,875		125,174
Work in process		4,248		2,656
Parts		71,658		55,040

Total inventories		211,781		182,870
Deferred income taxes		13,212		10,768
Other current assets		38,603		30,484

Total current assets		1,542,539		1,423,723
Property - net		983,161		913,713
Deferred income taxes		67,143		64,461
Goodwill		883,628		885,905
Other assets		45,216		42,872

	$	3,521,687	$	3,330,674

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	262,155	$	247,230
Short-term borrowings		933		3,754
Current portion of long-term debt		500,934		419,585
Accrued employee compensation and benefits		73,040		78,049
Income and other taxes		78,129		62,803
Accrued insurance		17,495		14,797
Other accrued liabilities		98,838		83,673

Total current liabilities		1,031,524		909,891
Long-term debt (Note 5)		—		78,936
Deferred income taxes		70,614		89,009
Other long-term liabilities		158,927		158,702
Commitments and contingencies (Note 7)
Stockholders’ equity		2,260,622		2,094,136

	$	3,521,687	$	3,330,674

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

BJ SERVICES COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND OTHER COMPREHENSIVE INCOME (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, 2004	161,869		$	17,376	$	994,724		$	(268,410	)	$	(6,961	)	$	1,358,315		$	(908	)	$	2,094,136
Comprehensive income:
Net income															95,033
Other comprehensive income, net of tax:
Cumulative translation adjustments																		4,715
Comprehensive income																					99,748
Reissuance of treasury stock for:
Stock options	252								5,539						(910	)					4,629
Stock purchase plan	418								9,523						2,628						12,151
Purchase of treasury stock	(88	)							(4,004	)											(4,004	)
Dividends declared															(12,996	)					(12,996	)
Stock performance plan grant						6,468						(6,468	)								—
Revaluation of stock performance awards						(957	)					957									—
Recognition of unearned compensation												982									982

Balance, December 31, 2004	162,451		$	17,376	$	1,000,235		$	(257,352	)	$	(11,490	)	$	1,442,070		$	3,807		$	2,194,646

Comprehensive income:
Net income															109,554
Other comprehensive income, net of tax:
Cumulative translation adjustments																		1,501
Comprehensive income																					111,055
Reissuance of treasury stock for:
Stock options	151								3,591						33						3,624
Purchase of treasury stock	(775	)							(37,862	)											(37,862	)
Dividends declared															(13,000	)					(13,000	)
Director stock plan issuance	5					(121	)		121												—
Revaluation of stock performance awards						1,882						(1,882	)								—
Recognition of unearned compensation												2,159									2,159


Balance, March 31, 2005	161,832		$	17,376	$	1,001,996		$	(291,502	)	$	(11,213	)	$	1,538,657		$	5,308		$	2,260,622

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,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	204,587		$	134,776
Adjustments to reconcile net income to cash provided by operating activities:
Minority interest		1,131			1,313
Amortization of unearned compensation		3,141			1,480
Loss on disposal of assets		1,330			928
Depreciation and amortization		65,230			61,962
Deferred income taxes		(23,886	)		16,504
Changes in:
Receivables		(82,417	)		(51,529	)
Inventories		(29,407	)		(6,753	)
Prepaid expenses		(10,304	)		(9,532	)
Accounts payable		16,184			11,852
Other current assets and liabilities		27,890			(6,548	)
Other - net		9,115			12,665

Net cash provided by operating activities		182,594			167,118

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(132,607	)		(83,401	)
Proceeds from disposal of assets		4,256			537
Proceeds from U.S. Treasury securities		229,930			—
Acquisitions of businesses, net of cash acquired		—			(15,242	)

Net cash provided by (used in) investing activities		101,579			(98,106	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds (Repayment) from short-term borrowings, net		(2,821	)		6,427
Dividends paid to shareholders		(25,931	)		—
Purchase of treasury stock		(41,866	)		—
Proceeds from exercise of stock options and stock purchase plan		15,154			33,946

Net cash provided by (used in) financing activities		(55,464	)		40,373

Effect of exchange rate changes on cash		441			883

Increase in cash and cash equivalents		229,150			110,268
Cash and cash equivalents at beginning of period		424,725			277,666

Cash and cash equivalents at end of period	$	653,875		$	387,934

Cash Paid for Interest and Taxes:
Interest	$	4,038		$	4,035
Taxes		98,489			54,635

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, 2005, and its results of operations and cash flows for each of the three and six-month periods ended March 31, 2005 and 2004. The consolidated condensed statement of financial position at September 30, 2004 is derived from the September 30, 2004 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, 2005 are not necessarily indicative of the results to be expected for the full year.

Certain amounts for fiscal 2004 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 options, the stock purchase plan and the 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 Company’s convertible senior notes issued April 24, 2002, as the Company called for the redemption of these notes on March 25, 2005 and had the intent and ability to fund the redemption with cash at March 31, 2005, and did so on April 25, 2005 (see Note 5).

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,
	2005		2004		2005		2004
Net income	$	109,554	$	73,264	$	204,587	$	134,776

Weighted-average common shares outstanding		162,300		159,474		162,358		159,165

Basic earnings per share	$	.68	$	.46	$	1.26	$	.85


	Three Months Ended March 31,				Six Months Ended March 31,
	2005		2004		2005		2004
Weighted-average common and dilutive potential common shares outstanding:
Weighted-average common shares outstanding		162,300		159,474		162,358		159,165
Assumed exercise of stock options⁽¹⁾		2,558		3,755		2,623		3,418

		164,858		163,229		164,981		162,583

Diluted earnings per share	$	.66	$	.45	$	1.24	$	.83

⁽¹⁾	For the three and six months ended March 31, 2005 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, 2004. Statement of Financial Accounting Standards 123, Accounting for Stock-Based Compensation (“SFAS 123”), 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,
	2005			2004			2005			2004
Net income, as reported	$	109,554		$	73,264		$	204,587		$	134,776
Add: total stock-based employee compensation expense included in reported net income, net of tax		2,159			874			3,141			1,480
Less: total stock-based employee compensation expense determined under SFAS 123 for all awards, net of tax ⁽¹⁾		(4,398	)		(4,424	)		(7,650	)		(8,181	)

Net income, pro forma	$	107,315		$	69,714		$	200,078		$	128,075

Earnings per share:
Basic, as reported	$	.68		$	.46		$	1.26		$	.85

Basic, pro forma	$	.66		$	.44		$	1.23		$	.80

Diluted, as reported	$	.66		$	.45		$	1.24		$	.83

Diluted, pro forma	$	.65		$	.43		$	1.21		$	.79

(1)

In October and November 2001, the Company granted approximately 100% more shares than is typically granted, and therefore only a minimal amount was issued in the subsequent year. Given the three-year vesting schedule of these awards, stock-based compensation expense was higher in fiscal 2002, 2003 and 2004.

As discussed in Note 10, in December 2004, the FASB issued SFAS No. 123-Revised 2004 (“SFAS 123(R)”), Share–Based Payment. This is a revision of SFAS 123 and supersedes APB No. 25, Accounting for Stock Issued to Employees. Under SFAS 123(R), the Company will be required to measure the cost of employee services received in exchange for stock based on the grant-date fair value (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award (usually the vesting period). This is effective for the first quarter of the first fiscal year beginning after June 15, 2005. The Company is currently in the process of evaluating the impact of SFAS 123(R) on its financial statements, including different option-pricing models, and will adopt SFAS 123(R) in the first quarter of fiscal 2006.

Note 4. Segment Information

The Company currently has thirteen operating segments for which separate financial information is available and that have separate management teams that are engaged in oilfield services. The results for these operating segments are evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assessing performance. The operating segments have been aggregated into three reportable segments: U.S./Mexico Pressure Pumping, International Pressure Pumping and Other Oilfield Services.

The U.S./Mexico Pressure Pumping segment has two operating segments and 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. These two operating segments have been aggregated into one reportable segment because they offer the same type of services, have similar economic characteristics, have similar production processes and use the same methods to provide their services.

The International Pressure Pumping segment has six operating segments. Similar to U.S./Mexico Pressure Pumping, it includes cementing and stimulation services (consisting of fracturing, acidizing, sand control, nitrogen, coiled tubing and service tool services). These services are provided to customers in more than 49 countries in the major international oil and natural gas producing areas of Canada, Latin America, Europe / Africa, Southeast Asia, the Middle East and Russia. The operating segments have been aggregated into one reportable segment because they have similar economic characteristics, offer the same type of services, have similar production processes and use the same methods to provide their services. They also serve the same or similar customers, which include major multi-national, independent and national or state-owned oil companies.

The Other Oilfield Services segment has five operating segments. These operating segments provide other oilfield services such as production chemicals, casing and tubular services, process and pipeline services, completion tools and completion fluids services in the U.S. and in select markets internationally. The operating segments have been aggregated into one reportable segment as they all provide other oilfield services, they serve the same or similar customers and some of the operating segments share resources.

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, 2004. 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, 2005

Revenues	$	389,373	$	284,678	$	121,611	$	201		$	795,863
Operating income (loss)		116,808		45,518		14,497		(16,416	)		160,407

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

Six Months Ended March 31, 2005

Revenues	$	764,826	$	530,823	$	237,632	$	364		$	1,533,645
Operating income (loss)		224,532		76,588		20,926		(31,501	)		290,545
Identifiable assets		972,633		1,139,041		562,889		847,124			3,521,687

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

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,
	2005			2004			2005			2004
Total operating profit for Reportable segments	$	160,407		$	110,416		$	290,545		$	205,424
Interest expense		(3,790	)		(4,144	)		(7,758	)		(8,346	)
Interest income		3,609			898			6,572			1,718
Other income (expense) – net		(282	)		(100	)		9,319			(596	)

Income before income taxes	$	159,944		$	107,070		$	298,678		$	198,200

Note 5. Debt

On March 31, 2005, the Company had $421.9 million of Convertible Senior Notes outstanding. On March 25, 2005 the Company had called for the redemption of all of these notes. On April 25, 2005, the Company paid $422.4 million in cash for the redemption.

The unsecured 7% Series B Notes in the amount of $78.9 million are due February 1, 2006 and as such, have been classified as current.

Note 6. Acquisitions and Goodwill

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 acquisition was accounted for using the purchase method of accounting.

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. This acquisition was accounted for using the purchase method of accounting.

The Company has completed its review and determination of the fair values of the assets acquired in Cajun and Petro-Drive, which resulted in total goodwill of $6.2 million. The pro forma financial information for these acquisitions is not included, as they were not material to the Company.

During the quarter ended March 31, 2005, goodwill was reduced by $2.3 million due to the utilization of tax attributes that were acquired in prior acquisitions. The contingency related to these acquired tax attributes has been resolved, and so the benefit of these attributes represents a reduction of the amount of goodwill originally recorded in the acquisition.

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. Further, 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., OSCA and other companies whose stock we acquired 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.

Halliburton – Python Litigation

On June 27, 2002, Halliburton Energy Services, Inc. filed suit against the Company 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 the Company (under the trade name “Python”) and Weatherford infringe two of its patents for a tool constructed of composite material. The lawsuit was 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 the Company 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. On July 6, 2004, Halliburton submitted both of its patents for re-examination to the U.S. Patent Office, seeking to re-affirm the validity of its patents. The Company has filed its own request for re-examination of the patents. The lawsuit pending in the Northern District of Texas was dismissed on November 16, 2004, at the request of Halliburton. The dismissal was “without prejudice,” meaning that Halliburton has the right to re-file this lawsuit and may do so depending on the outcome of the re-examination process referenced above. The Company has filed a motion with the Court requesting that the Court reinstate the case solely for the purpose of conducting a Markman hearing to construe the construction of the claims in the Halliburton patent. Irrespective of the outcome of the pending motion or the patent re-examination, the Company does not expect the outcome of this matter to have a material adverse effect on its financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this matter or future lawsuits, if any, that may be filed.

Newfield Litigation

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. Oral argument was held on April 4, 2005, and the parties are awaiting a ruling. Great Lakes Chemical Corporation, which formerly owned the majority of the outstanding shares of OSCA, has agreed to indemnify the Company 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 $5.6 million. The Company is fully reserved for its share of this liability.

Asbestos Litigation

In August 2004, certain predecessors of the Company were named as defendants in four lawsuits filed in the Circuit Courts of Jones and Smith Counties in Mississippi. These four lawsuits include 118 individual plaintiffs alleging that they suffer various illnesses from exposure to asbestos. The lawsuits assert claims of unseaworthiness, negligence, and strict liability, all based upon the status of the Company’s predecessors as Jones Act employers. These cases include numerous defendants and, in general, the defendants are all alleged to have manufactured, distributed or utilized products containing asbestos. No discovery has been conducted to date, and the Company has not been provided with sufficient information to determine the number of plaintiffs who claim to have been exposed to asbestos while employed by the Company, the capacity in which they were employed, nor their medical condition. Accordingly, the Company is unable to estimate its potential exposure to these lawsuits. The Company and its predecessors in the past maintained insurance which it believes will be available to address any liability arising from these claims. The Company intends to defend itself vigorously and, based on the information available to the Company at this time, the Company does not expect the outcome of these lawsuits to have a material adverse effect on its financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these lawsuits or additional similar lawsuits, if any, that may be filed.

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 waste disposal sites owned by third parties. An accrual of approximately $2.7 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.

Lease and Other Long-Term Commitments

In December 1999, the Company contributed certain pumping service equipment to a limited partnership. The Company owns a 1% interest in the 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 and is included in “Obligations under equipment financing arrangements” in the Contractual Obligations section below. The Company assessed the terms of this agreement and determined it was a variable interest entity as defined in FIN 46, Consolidation of Variable Interest Entities. However, the Company was not deemed to be the primary beneficiary, and therefore, consolidation was not required. The transaction resulted in a gain that is being deferred and amortized over 13 years. The balance of the deferred gain was $24.8 million and $26.6 million as of March 31, 2005 and September 30, 2004, 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 April 2005 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 $1.1 million. 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 Company owns a 1% interest in the 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, of approximately $10 million annually. This is accounted for as an operating lease and is included in “Obligations under equipment financing arrangements” in the Contractual Obligations section below. The Company assessed the terms of this agreement and determined it was a variable interest entity as defined in FIN 46, Consolidation of Variable Interest Entities. However, the Company was not deemed to be the primary beneficiary, and therefore, consolidation was not required. The transaction resulted in a gain that is being deferred and amortized over 12 years. The balance of the deferred gain was $0.3 million and $0.4 million as of March 31, 2005 and September 30, 2004, 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 June 2009, the Company has the option, but not the obligation, to purchase the pumping service equipment for approximately $27 million.

Contractual Obligations

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 the 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, 2005 (in thousands):


	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	$	28,856	$	28,852	$	4	$	—	$	—
Guarantees		192,355		154,131		23,147		8,848		6,229

Total Other Commercial Commitments	$	221,211	$	182,983	$	23,151	$	8,848	$	6,229

Note 8. Supplemental Financial Information

Other income (expense), net for the three and six months ended March 31, 2005 is summarized as follows (in thousands):


	Three Months Ended						Six Months Ended
	2005			2004			2005			2004
Minority interest	$	(725	)	$	(427	)	$	(1,131	)	$	(1,313	)
Non-operating net foreign exchange loss		(186	)		(73	)		(337	)		(251	)
Recovery of misappropriated funds		—			—			9,020			—
Other income, net		629			400			1,767			968

Other income (expense), net	$	(282	)	$	(100	)	$	9,319		$	(596	)

In October 2004 the Company received a report from a whistleblower alleging that its Asia Pacific Region Controller had misappropriated Company funds in fiscal 2001. The Company began an internal investigation into the misappropriation and whether other inappropriate actions occurred in the Region. The Region Controller admitted to multiple misappropriations totaling approximately $9.0 million during a 30-month period ended April 2002. The misappropriations of approximately $9.0 million were repaid to the company and the Region Controller’s employment was terminated. Although unauthorized, the misappropriations were an expense of the Company in the form of theft that were recorded in the Consolidated Statement of Operations in periods prior to April 2002. The $9.0 million repayment represents a gain contingency and was reflected in Other Income in the Consolidated Condensed Statement of Operations for the quarter ended December 31, 2004 in accordance with SFAS 5, Accounting for Contingencies.

The Company is continuing to investigate whether additional funds were misappropriated beyond the $9 million identified to date and to investigate other possible inappropriate actions. To date, additional misappropriations of at least $0.9 million have been identified. As the Company continues its investigation, further adjustments may be recorded in the Consolidated Statements of Operations, but no material adjustments are known at this time.

In October 2004, the Company also received whistleblower allegations that illegal payments to foreign officials were made in the Asia Pacific Region. The Audit Committee of the Board of Directors engaged independent counsel to conduct a separate investigation to determine whether any such illegal payments were made. That investigation, which is continuing, has found information indicating that illegal payments to government officials in the Asia Pacific Region aggregating in excess of $1.5 million may have been made over several years.

Note 9. 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, 2004. 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,
	2005			2004			2005			2004
Interest cost on projected benefit obligation	$	957		$	950		$	1,914		$	1,901

Expected return on plan assets		(1,336	)		(1,002	)		(2,672	)		(2,005	)
Net amortization and deferral		147			157			294			314

Net pension cost	$	(232	)	$	105		$	(464	)	$	210

For fiscal 2005, the Company has a minimum pension funding requirement of $1.1 million for the U.S. plan, which was completely funded in the three months ended December 31, 2004. This contribution was funded by cash flows from operating activities.

Foreign Defined Benefit Pension Plans


	Three Months Ended March 31,						Six Months Ended March 31,
	2005			2004			2005			2004
Service cost for benefits earned	$	1,669		$	986		$	3,338		$	1,844

Interest cost on projected benefit obligation		1,918			1,476			3,836			2,232
Expected return on plan assets		(2,194	)		(1,337	)		(4,388	)		(1,990	)

Recognized actuarial loss		532			42			1,064			35
Net amortization and deferral		4			385			8			704

Net pension cost	$	1,929		$	1,552		$	3,858		$	2,825

In fiscal 2005, the Company will have a minimum pension funding requirement of $7.9 million for the foreign plans. Contributions in the amount of $4.3 million were made during the six months ended March 31, 2005. These contributions have been and are expected to be funded by cash flows from operating activities.

Postretirement Benefit Plan


	Three Months Ended March 31,				Six Months Ended March 31,
	2005		2004		2005		2004
Service cost for benefits attributed to service during the period	$	824	$	729	$	1,648	$	1,458
Interest cost on accumulated postretirement benefit obligation		658		597		1,316		1,194

Net periodic postretirement benefit cost	$	1,482	$	1,326	$	2,964	$	2,652

Note 10. New Accounting Standards

In December 2004, the FASB issued SFAS No. 123-Revised 2004 (“SFAS 123(R)”), Share–Based Payment. This is a revision of SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS 123”), and supersedes APB No. 25, Accounting for Stock Issued to Employees. As noted in our employee stock-based compensation accounting policy described in our Annual Report on Form 10-K for the period ended September 30, 2004, the Company does not record compensation expense for stock-based compensation. Under SFAS 123(R), the Company will be required to measure the cost of employee services received in exchange for stock based on the grant-date fair value (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award (usually the vesting period). The fair value will be estimated using an option-pricing model. Excess tax benefits, as defined in SFAS 123(R), will be recognized as an addition to paid-in capital. This is effective the quarter of the first fiscal year beginning after June 15, 2005. The Company is currently in the process of evaluating the impact of SFAS 123(R) on its financial statements, including different option-pricing models, and will adopt SFAS 123(R) in the first quarter of fiscal 2006. The pro forma table in Note 3 illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS 123.

In October 2004, the American Jobs Creation Act of 2004 (the “Act”) was signed into law. The Act contains new provisions that may impact the Company’s U.S. income tax liability in future years. The Act provides a deduction for income from qualified domestic production activities, which will be phased in from 2005 through 2010. Under the guidance in FASB Staff Position No. 109-1, Application of FASB Statement No. 109, “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004, the deduction will be treated as a “special deduction” as described in FASB Statement No. 109. As such, the special deduction has no effect on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the period in which the deduction is claimed on our tax return.

The Act also creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85 percent dividends received deduction for

certain dividends from controlled foreign corporations. The deduction is subject to a number of limitations and, as of today, uncertainty remains as to how to interpret numerous provisions in the Act. As such, we are not yet in a position to decide on whether, and to what extent, we might repatriate foreign earnings that have not yet been remitted to the U.S. Nevertheless, the Company believes that any associated tax liability would be fully offset by foreign tax credits.

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 oil and natural gas 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. See “Business” included in our Annual Report on Form 10-K for the period ended September 30, 2004 for more information on these operations.

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.

Asia Pacific Investigation

In October 2004 the Company received a report from a whistleblower alleging that its Asia Pacific Region Controller had misappropriated Company funds in fiscal 2001. The Company began an internal investigation into the misappropriation and whether other inappropriate actions occurred in the Region. The Region Controller admitted to multiple misappropriations totaling approximately $9.0 million during a 30-month period ended April 2002. The misappropriations of approximately $9.0 million were repaid to the Company and the Region Controller’s employment was terminated. Although unauthorized, the misappropriations were an expense of the Company in the form of theft that were recorded in the Consolidated Statement of Operations in periods prior to April 2002. The $9.0 million repayment represents a gain contingency and was reflected in Other Income in the Consolidated Condensed Statement of Operations for the quarter ended December 31, 2004 in accordance with SFAS 5, Accounting for Contingencies.

The Company is continuing to investigate whether additional funds were misappropriated beyond the $9 million identified to date and investigate other possible inappropriate actions. To date, additional misappropriations of at least $0.9 million have been identified. Although unauthorized, the additional $0.9 million of misappropriations were an expense of the Company in the form of theft that were recorded in the Consolidated Statement of Operations in periods prior to April 2002. As the Company continues its investigation, further adjustments may be recorded in the Consolidated Statements of Operations, but no material adjustments are known at this time.

In October 2004, the Company also received whistleblower allegations that illegal payments to foreign officials were made in the Asia Pacific Region. The Audit Committee of the

Board of Directors engaged independent counsel to conduct a separate investigation to determine whether any such illegal payments were made. That investigation, which is continuing, has found information indicating that illegal payments to government officials in the Asia Pacific Region aggregating in excess of $1.5 million may have been made over several years.

As discussed in our Annual Report on Form 10-K for the period ended September 30, 2004, the misappropriations and related accounting adjustments were possible because of certain internal control operating deficiencies. During fiscal 2002, the Company implemented policy changes worldwide for disbursements. In March 2005, the Company assigned a new Controller, an Assistant Controller and several new accountants to the Asia Pacific region. In addition, we have put in place Control and Process Improvement Managers at each of our five regional bases world-wide to document, enhance and test our control processes. The Company has also made several enhancements to its accounting policies and procedures. The Company is still in the process of reviewing its control policies and procedures and may make further enhancements.

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 for the three and six months ended March 31:


	Three Months Ended						Six Months Ended
	2005		% Change		2004		2005		% Change		2004
Rig Count: ⁽¹⁾
U.S.		1,279	14	%		1,118		1,264	13	%		1,114
International⁽²⁾		1,397	5	%		1,325		1,340	6	%		1,262
Commodity Prices (average):
Crude Oil (West Texas Intermediate)	$	49.83	41	%	$	35.23	$	49.06	48	%	$	33.21
Natural Gas (Henry Hub)	$	6.44	14	%	$	5.64	$	6.41	20	%	$	5.37

(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 114 and 107 for the three-month period ended March 31, 2005 and 2004, respectively, and 111 and 107 for the six-month period ended March 31, 2005 and 2004, respectively.

U.S. Rig Count

Demand for the Company’s pressure pumping services in the U.S. is primarily driven by oil and natural gas drilling activity, which tends to be extremely volatile, depending on the current and anticipated prices of crude oil and natural gas. During the last 10 years, the lowest annual U.S. rig count averaged 601 in fiscal 1999 and the highest annual U.S. rig count averaged 1,172 in fiscal 2001. The Company’s management estimates that the average U.S. rig count for

fiscal 2005 will be approximately 13% higher than the average rig count in fiscal 2004 of 1,155. 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.

International Rig Count

Many countries in which we operate are subject to political, social and economic risks which may cause volatility within any given country. However, the Company’s international revenue is less volatile because we operate in approximately 49 countries, which provides some balance of risk. Due to the significant investment and complexity of international projects, management believes drilling decisions relating to such projects tend to be evaluated and monitored with a longer-term perspective with regard to oil and natural gas pricing. Additionally, the international market is dominated by major oil companies and national oil companies which tend to have different objectives and more operating stability than the typical independent producer in North America. During the last 10 years, the lowest annual international rig count (including Canada) averaged 828 in fiscal 1999 and the highest annual international rig count averaged 1,184 in fiscal 2004. During the three and six months ended March 31, 2005, active international drilling rigs (excluding Canada) averaged 876 and 869, respectively, compared to 797 and 794 rigs for the three months and six months ended March 31, 2004, respectively. Based on the Company’s current information and assumptions, the Company expects international revenue outside of Canada to increase 10% for fiscal 2005 compared to fiscal 2004.

Canadian drilling activity averaged 521 and 470 active drilling rigs for the three and six months ended March 31, 2005, respectively, compared to 528 and 468 rigs for the three and six months ended March 31, 2004, respectively. Based on the Company’s current information and assumptions, the Company anticipates Canadian revenue to increase 15% to 20% during fiscal 2005, over fiscal 2004.

Acquisitions

On November 26, 2003, the Company completed the acquisition of Cajun Tubular Services, Inc. (“Cajun”) for a total purchase price of $8.3 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 has completed its review and determination of the fair values of the assets acquired in Cajun and Petro-Drive which resulted in total goodwill of $6.2 million. The pro forma financial information for these acquisitions is not included, as they were not material to the Company.

Results of Operations

The following table sets forth selected key operating statistics reflecting the Company’s financial results for the three and six months ended March 31 (in millions):


	Three Months Ended								Six Months Ended
	2005			% Change		2004			2005			% Change		2004
Consolidated revenue	$	795.9		23	%	$	647.1		$	1,533.6		23	%	$	1,247.9
Revenue by segment:
U.S./Mexico Pressure Pumping		389.4		31	%		297.6			764.8		31	%		582.0
International Pressure Pumping		284.7		14	%		248.8			530.8		13	%		470.0
Other Oilfield Services		121.6		21	%		100.4			237.6		22	%		195.3
Corporate		.2					.3			.4					.5

Consolidated operating income	$	160.4		45	%	$	110.4		$	290.5		41	%	$	205.4
Operating income by segment:
U.S./Mexico Pressure Pumping		116.8		57	%		74.2			224.5		60	%		140.4
International Pressure Pumping		45.5		16	%		39.2			76.6		19	%		64.4
Other Oilfield Services		14.5		69	%		8.6			20.9		3	%		20.2
Corporate		(16.4	)				(11.5	)		(31.5	)				(19.6	)

Consolidated Revenue and Operating Income: For the three month period ended March 31, 2005 revenue increased, primarily due to higher U.S. drilling activity and pricing improvement in the U.S. and Canada. Operating income also benefited from U.S. drilling increases and U.S. pricing improvements, as operating income increased compared to the same period in the prior year.

For the six months ended March 31, 2005, U.S. drilling increases and U.S. and Canadian pricing improvements, coupled with activity improvements in the Middle East, increased revenue. Operating income also benefited from the increased revenue described above, but was hindered by a reduction in market activity for the Company’s stimulation vessel in the North Sea.

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

U.S./Mexico Pressure Pumping Segment

Results for the three- month periods ended March 31, 2005 and 2004

U.S./Mexico revenue increased as a result of a 14% increase in U.S. drilling activity

compared to the same period in the prior year and improved pricing in the U.S. The benefits contributed by U.S. activity and pricing were reduced by declines in activity in Poza Rica, Mexico. Our primary customer in Mexico experienced permitting problems in Poza Rica during the second quarter of fiscal 2005, causing a 36% reduction in our Mexico revenue compared to the same period in the prior year.

The increases in U.S. revenue described above coupled with labor efficiency gains contributed to an increase in operating income over the same period in the prior fiscal year. Labor efficiencies were achieved through an increase in activity without a proportional increase in headcount, thereby increasing employee utilization per job. In the U.S., average headcount increased 13% compared to the same period in the prior year, with revenue increasing 37%. Labor efficiencies are also being obtained through utilization of newer, more efficient and more modern equipment. The “Business” section in the September 30, 2004 Annual Report on Form 10-K provides further information on the U.S. fleet recapitalization initiative. In addition, the pricing improvement described above directly increased operating income without any associated cost. As with revenue, the increase in U.S. operating income was slightly offset by the decrease in our Mexico operations described above.

Results for the six- month periods ended March 31, 2005 and 2004

As discussed above, the revenue increase for the six months ended March 31, 2005 was a result of an increase in U.S. drilling activity of 13% compared to the same period in the prior year and improved pricing in the U.S. As with the three months ended March 31, 2005, declines in activity in Poza Rica, Mexico reduced revenue 25% for Mexico, which slightly offset the gains experienced in the U.S.

The increase in operating income from the same period in the prior year was primarily due to the same factors described previously. Similar to above, average headcount increased 13% compared to the same period in the prior year, with revenue increasing 31%.

Outlook

Compared to levels experienced during the quarter ended March 31, 2005, the Company expects average rig count for the U.S. to increase 5% and Mexico activity to increase 20% for the quarter ending June 30, 2005. U.S./Mexico revenue is expected to increase 25% by the end of fiscal 2005 compared to fiscal 2004, while Mexico revenue is expected to be down 15% from fiscal 2004. The Company also anticipates increasing average headcount 9% in the U.S. during fiscal 2005.

Effective May 1, 2005, the Company issued a price book increase for its U.S. pressure pumping operations. The increase averages 15% above the former U.S. price book. The degree of customer acceptance of the price book increase will depend on activity levels and competitive pressures; however, the Company anticipates that 75% of our customers will be on the new price book by December 31, 2005.

International Pressure Pumping Segment

Results for the three-month periods ended March 31, 2005 and 2004

Canadian and North Sea markets were the primary reasons for the increase in revenue. Canadian revenue increased 12% compared to the same period in the prior year, with drilling activity essentially flat. The Canadian increase in revenue is attributed to price improvement of 4% and favorable foreign exchange translation of 8%. The North Sea increase resulted from increased fracturing and coiled tubing activity in Norway and coiled tubing activity in the U.K. The increases in revenue from Norway and U.K. were partially offset by decreased activity of the North Sea stimulation vessel. Activity for the vessel was down approximately 52% during the quarter, as our primary customer continues to experience delays in its well delivery schedule. Middle East activity increases in India and Bangladesh also contributed to the increase in revenue.

Operating income increased as a result of the improved revenues in the North Sea and Middle East as described above. While the weakening U.S. dollar increased Canadian revenue, it had minimal impact on operating income as most of our expenses in Canada are denominated in Canadian dollars. These operating income increases were partially offset by lower activity levels with the Company’s stimulation vessel in the North Sea. Since there are significant fixed costs associated with operating the stimulation vessel, there was a decline in operating profit for the segment.

Results for the six-month periods ended March 31, 2005 and 2004

Canadian and Middle East operations are the primary factors for the revenue increase for the segment. North Sea activity gains in the U.K. and Norway were almost entirely offset by decreased stimulation vessel activity. Canadian revenue improved for the same reasons described above. Average drilling activity in the Middle East increased 13% compared to the same period in the prior year, enhancing revenue in India. In addition, stimulation activity, which was suspended in Saudi Arabia during the first four months of fiscal 2004, has resumed. Other countries that contributed to the revenue increase include Argentina and Russia. Revenue in Argentina was up 46% as a result of increased activity, while Russian revenue increased from the overall market increase. These increases in revenue were partially offset by Malaysia, where major customers have reduced their drilling programs, leading to a 36% revenue decline in Malaysia.

Operating income was impacted for the same reasons described above. In addition, there are significant fixed costs associated with operating the stimulation vessel in the North Sea, further hindering operating profit.

Outlook

As the market enters spring break up in Canada, the Company anticipates revenue in Canada to be down 60% compared to the quarter ended March 31, 2005. Spring break up is the

period during which heavy drilling and other equipment is not permitted to travel on the roads. Outside of Canada, the Company expects international pumping services revenue to be comparable to the quarter ended March 31, 2005.

Other Oilfield Services Segment

Results for the three-month periods ended March 31, 2005 and 2004

Revenue from each service line within Other Oilfield Services increased. Most of the revenue increase was from Completion Fluids, which increased 44%, and Process and Pipeline Services, which increased 22%. Completion Fluids’ increase was a result of an overall increase in product sales. The Process and Pipeline Services increase was due to activity increases.

All service lines showed improvement in operating margins, with Completion Fluids and Process and Pipeline Services being the main contributors for the same reasons as the revenue increases described above.

Results for the six-month periods ended March 31, 2005 and 2004

With the exception of Completion Tools, which experienced a 6% decrease in revenue, revenue from each service line within Other Oilfield Services increased. Most of the revenue increase was in Completion Fluids, which increased 70%, as a result of increased product sales in the U.S., Mexico and Norway. Completion Tools’ decrease was due to less deepwater activity in the Gulf of Mexico, primarily impacting the first fiscal quarter of 2005. This was slightly offset by new well screen sales.

Operating margins were consistent with the same period in the prior year. Operating profit improved for the reasons described above; however, there were additional costs during the period for worker’s compensation and write off of uncollectible receivables.

Outlook

We expect revenue from the Other Oilfield Services segment to increase 5% for the quarter ending June 30, 2005, compared to the quarter ended March 31, 2005. Revenue for the year ending September 30, 2005 are projected to be up 10-15% from the prior year, with Completion Fluids revenue increasing 30%.

Other Expenses

Research and engineering and marketing expense: These expenses increased for three and six months ended March 31, 2004, compared to the same periods in the prior year. As a percent of revenue, each of these expenses was similar to the same periods of the prior year. The following table sets forth the Company’s other operating expenses as a percentage of revenue for

the three and six-month periods ended March 31:


	Three Months				Six Months Ended
	2005		2004		2005		2004
Research and engineering	1.6	%	1.8	%	1.7	%	1.8	%
Marketing expense	2.8	%	3.1	%	2.9	%	3.2	%
General and administrative expense	3.3	%	3.1	%	3.2	%	3.0	%

General and administrative expense: The increase in general and administrative expenses occurred during the second quarter of fiscal 2005 and relates mostly to legal costs associated with the ongoing investigation in our Asia Pacific Region (see “Asia Pacific Investigation” above). We expect general and administrative expenses to increase by approximately $4.0 million during the second half of fiscal 2005 as we continue to prepare for our first year under Section 404 of the Sarbanes-Oxley Act.

Interest Expense and Interest Income: Interest income increased for the three and six-month periods ended March 31, 2005 as a result of increases in cash and cash equivalents. As a result of the redemption of our Convertible Notes (see Note 5), we anticipate interest income and interest expense to decline considerably during the remainder of fiscal year 2005.

Other (Expense) Income, net: In the first quarter of fiscal 2005, the Company recorded a gain of $9.0 million relating to the recovery of misappropriated funds (see “Asia Pacific Investigation” above).

Liquidity and Capital Resources

Historical Cash Flow

The following table sets forth the historical cash flows for the six-month period ended March 31 (in millions):


	2005			2004
Cash flow from operations	$	182.6		$	167.1
Cash flow provided by / (used) in investing		101.6			(98.1	)
Cash flow provided by / (used) in financing		(55.4	)		40.4
Effect of exchange rate changes on cash		.4			.9

Change in cash and cash equivalents	$	229.2		$	110.3

The Company’s working capital decreased $2.8 million at March 31, 2005 compared to September 30, 2004, as a result of the debt balances classified as long term becoming current debt during the current fiscal quarter. Accounts receivable increased $82.4 million, inventory increased $29.4 million, and accounts payable increased $16.2, million primarily as a result of an increase in U.S. and Canadian activity.

The cash flow provided by investing was attributable to the Company’s investment in U.S. treasury notes maturing during the quarter in the amount of $229.9 million.

Cash flows used in financing were the result of repurchases of stock totaling $41.9 million and the payment of dividends in the amount of $25.9 million during the period.

Liquidity and Capital Resources

Cash flow from operations is expected to be our primary source of liquidity in fiscal 2005. Our sources of liquidity also include cash and cash equivalents of $653.9 million at March 31, 2005 and the available financing facilities listed below (in millions):


Financing Facility	Expiration	Borrowings at March 31, 2005		Available at March 31, 2005
Revolving Credit Facility	June 2009		None	$	400.0
Discretionary	Various times within the next 12 months	$	.9		44.4

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, totaling $0.1 million for the six months ended March 31, 2005. In addition, the Revolving Credit Facility charges a utilization fee on all outstanding loans and letters of credit when usage of the Revolving Credit Facility exceeds 33%, though there were no such charges in fiscal 2005 to date or fiscal 2004. There were no outstanding borrowings under the Revolving Credit Facility at March 31, 2005.

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 the Revolving Credit Facility.

In addition to the Revolving Credit Facility, the Company had $45.3 million in various unsecured, discretionary lines of credit at December 31, 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 $.9 million and $5.9 million in outstanding borrowings under these lines of credit at March 31, 2005 and September 30, 2004, respectively.

Management believes that cash flow from operations combined with cash and cash equivalents, 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 March 31, 2005 and September 30, 2004, the Company had issued and outstanding $78.9 million of unsecured 7% Series B Notes due February 1, 2006, net of discount, which are classified as current based on their maturity date.

On April 24, 2002 the Company sold Convertible Senior Notes due 2022 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 $422.0 million and $419.6 million outstanding under the convertible senior notes at March 31, 2005 and September 30, 2004, respectively. On March 25, 2005 the Company called for the redemption of all of its outstanding convertible senior notes. The redemption date was April 25, 2005 with an aggregate redemption price of $422.4 million. The redemption of the notes was funded with cash.

Cash Requirements

As described above, the Company redeemed the convertible senior notes in April 2005. The redemption was funded entirely with cash.

The Company anticipates capital expenditures to be approximately $290 million in fiscal 2005, compared to $201 million in fiscal 2004, $167 million in fiscal 2003 and $179 million in fiscal 2002. The 2005 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. fleet recapitalization initiative and stimulation expansion internationally. In 1998, the Company embarked on a program to replace its aging U.S. fracturing pump fleet with new, more efficient and higher horsepower pressure pumping equipment. During fiscal 2004, the Company expanded this U.S. fleet recapitalization initiative to include additional equipment, such as cementing, nitrogen and acidizing and will begin recapitalizing the pressure pumping equipment in Canada in fiscal 2005. The actual amount of fiscal 2005 capital expenditures will depend primarily on maintenance requirements and expansion opportunities.

In fiscal 2005, the Company’s minimum pension and postretirement funding requirements are anticipated to be approximately $9.0 million, and the Company has contributed $5.4 million during the six months ended March 31, 2005.

Due to the expiration of favorable tax provisions on depreciation and the usage of tax credits and other tax attributes in fiscal 2004, we expect an incremental increase in cash paid for income taxes of at least $45 million in fiscal 2005.

The Company anticipates paying cash dividends in the amount of $.08 per common share on a quarterly basis in fiscal 2005. Based on the shares outstanding on September 30, 2004, the aggregate annual amount would be $52.0 million. However, dividends are subject to the approval of the Company’s Board of Directors each quarter, and the Board has the ability to change the dividend policy at any time.

The Company expects that cash and cash equivalents and cash flow from operations will generate sufficient cash flow to fund all of the cash requirements described above.

Off Balance Sheet Transactions

In December 1999, the Company contributed certain pumping service equipment to a limited partnership. The Company owns a 1% interest in the 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 and is included in “Obligations under equipment financing arrangements” in the Contractual Obligations section below. The Company assessed the terms of this agreement and determined it was a variable interest entity as defined in FIN 46, Consolidation of Variable Interest Entities. However, the Company was not deemed to be the primary beneficiary, and therefore, consolidation was not required. The transaction resulted in a gain that is being deferred and amortized over 13 years. The balance of the deferred gain was $24.8 million and $26.6 million as of March 31, 2005 and September 30, 2004, 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 April 2005 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 $1.1 million. In September 2010, the Company has the option, but not the obligation, to purchase the pumping service equipment for approximately $32 million.

deferred and amortized over 12 years. The balance of the deferred gain was $0.3 million and $0.4 million as of March 31, 2005 and September 30, 2004, 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 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 2004, the FASB issued SFAS No. 123-Revised 2004 (“SFAS No. 123(R)”), Share–Based Payment. This is a revision of SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB No. 25, Accounting for Stock Issued to Employees. In accordance with APB 25, the Company does not record compensation expense for stock-based compensation. Under SFAS 123(R), the Company will be required to measure the cost of employee services received in exchange for stock based on the grant-date fair value (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award (usually the vesting period). Employee stock purchase plans will not result in recognition of compensation cost if certain conditions are met. The cost will initially be measured based on its current fair value, which will be subsequently remeasured at each reporting date through the settlement date. Changes in fair value during the requisite service period will be recognized as compensation cost over that period. The fair value will be estimated using an option-pricing model. Excess tax benefits, as defined in SFAS 123(R), will be recognized as an addition to paid-in capital. This is effective for the first quarter of the first fiscal year beginning after June 15, 2005. The Company is currently in the process of evaluating the impact of SFAS No. 123(R) on its financial statements, including different option-pricing models, and will adopt SFAS 123(R) in the first quarter of fiscal 2006. However, based on the Black-Scholes option pricing model historically used for the disclosures in the stock-based compensation information, it is estimated that the Company will have an additional expense of approximately $14 million (after tax) in the consolidated statement of operations if the levels of stock-options granted in fiscal 2004 remain the same.

The Act also creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85 percent dividends received deduction for

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 ended September 30, 2004.

Forward Looking Statements

This document, including the sections labeled “Outlook,” 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 and level of acceptance of price book increases in our markets,

•

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,

•

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

•

adverse consequences that may be found in or result from our ongoing internal investigation, including potential financial consequences and governmental actions, proceedings, charges or penalties,

•

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 in the Company’s Form 10-K for the fiscal year ended September 30, 2004.

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. The Company’s interest rate risk has decreased due to the redemption of the convertible notes during April 2005. The Company’s remaining debt instruments do not present significant market risk to the Company.

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, 2005. When the Company believes prudent, the Company enters into forward foreign exchange contracts to hedge the impact of foreign currency fluctuations. There were no such forward foreign exchange contracts at March 31, 2005. The expected maturity dates and fair value of our market risk sensitive instruments are stated below (in thousands). All items described are non-trading and are stated in U.S. dollars.


	Expected Maturity Dates										Fair Value
	2005		2006		2007	2008	2009	Thereafter	Total		3/31/05
SHORT-TERM BORROWINGS

Bank borrowings; U.S. $ denominated Average variable interest rate – 6.75% at March 31, 2005	$	933							$	933	$	933

LONG-TERM BORROWINGS

7% Series B Notes-U.S. $ denominated Fixed interest rate – 7%				78,959						78,959		80,934

1.625% Convertible Notes U.S. denominated Fixed interest rate – 1.625%(1)		421,975								421,975		424,491

Total	$	422,908	$	78,959	—	—	—	—	$	501,867	$	506,358

(1)	As described in Note 5, these notes were redeemed on April 25, 2005.

Item 4. Controls and Procedures

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.

PART II

OTHER INFORMATION

Item 1. Legal Proceedings

Litigation

Halliburton – Python Litigation

not expect the outcome of this matter to have a material adverse effect on its financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this matter or future lawsuits, if any, that may be filed.

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, filed by Newfield Exploration on September 29, 2000, arose out of a blowout that occurred in 1999 on an offshore well owned by Newfield. 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-judgment 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. Oral argument was held on April 4, 2005, and the parties are awaiting a ruling. Great Lakes Chemical Corporation, which formerly owned the majority of the outstanding shares of OSCA, has agreed to indemnify the Company 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 $5.6 million. The Company is fully reserved for its share of this liability.

Asbestos Litigation

time, the Company does not expect the outcome of these lawsuits to have a material adverse effect on its financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these lawsuits or additional similar lawsuits, if any, that may be filed.

Environmental

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

(a) None

(b) None


Period	(a) Total Number of Shares Purchased	(b) Average Price paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽¹⁾	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
January 1– 31, 2005	0		0	0	$	247 million
February 1 – 28, 2005	256,700	$	46.94	256,700	$	235 million
March 1 – 31, 2005	518,300	$	49.80	518,300	$	209 million
TOTAL	775,000	$	48.83	775,000	$	209 million

⁽¹⁾

On December 19, 1997, the Company’s Board of Directors authorized a stock repurchase program of up to $150 million (subsequently increased to $300 million in May 1998, to $450 million in September 2000, to $600 million in July 2001 and again to $750 million in October 2001). Repurchases are made at the discretion of the Company’s management and the program will remain in effect until terminated by the Company’s Board of Directors.

Item 3. Defaults upon Senior Securities

None

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

The Company held its Annual Meeting of Stockholders on March 24, 2005. Proxies for the

Annual Meeting were solicited pursuant to Regulation 14A of the Securities Exchange Act of 1934. The Board of Directors nominated L. William Heiligbrodt, James L. Payne and J. W. Stewart for re-election at the Annual Meeting. There was no solicitation in opposition to these nominees, and the nominees were re-elected. The number of votes for and withheld with respect to the nominees were as follows:


Nominee	Votes For	Withheld
L. William Heiligbrodt	144,871,649	4,644,736
James L. Payne	147,957,298	1,559,086
J. W. Stewart	144,931,334	4,585,051

In addition, the following directors continued in office after the Annual Meeting: John R. Huff, Don D. Jordan, Michael E. Patrick and William H. White.

Item 5. Other Information

None

Item 6. 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

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 10, 2005	By:	/s/ J. W. Stewart
		J. W. Stewart
		Chairman of the Board, President
		and Chief Executive Officer

Date: May 10, 2005	By:	/s/ T. M. Whichard
		T. M. Whichard
		Vice President, Finance
		and Chief Financial Officer

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