BJ Services 10Q 2007 Q4 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 December 31, 2007

¨	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.)


4601 Westway Park Boulevard, Houston, Texas		77041
(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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

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

There were 292,938,808 shares of the registrant’s common stock, $.10 par value, outstanding as of February 6, 2008.

BJ SERVICES COMPANY

INDEX


PART I – FINANCIAL INFORMATION:

Item 1. Financial Statements

Consolidated Condensed Statement of Operations (Unaudited) – Three months ended December 31, 2007 and 2006		3

Consolidated Condensed Statement of Financial Position (Unaudited) – December 31, 2007 and September 30, 2007		4

Consolidated Statement of Stockholders’ Equity and Other Comprehensive Income (Unaudited) – Three months ended December 31, 2007		5

Consolidated Condensed Statement of Cash Flows (Unaudited) – Three months ended December 31, 2007 and 2006		6

Notes to Unaudited Consolidated Condensed Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18

Item 3. Quantitative and Qualitative Disclosures About Market Risk		29

Item 4. Controls and Procedures		30

PART II – OTHER INFORMATION

Item 1. Legal Proceedings		31

Item 1A. Risk Factors		31

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		31

Item 3. Defaults upon Senior Securities		31

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

Item 5. Other Information		31

Item 6. Exhibits		32

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 December 31,
	2007			2006
Revenue	$	1,285,065		$	1,183,940
Operating expenses:
Cost of sales and services		950,450			788,635
Research and engineering		17,198			15,694
Marketing		28,832			25,813
General and administrative		36,630			37,207
(Gain)/loss on disposal of assets		(626	)		265

Total operating expenses		1,032,484			867,614

Operating income		252,581			316,326
Interest expense		(7,862	)		(8,779	)
Interest income		474			320
Other expense - net		(2,711	)		(2,076	)

Income before income taxes		242,482			305,791
Income tax expense		70,298			98,707

Net income	$	172,184		$	207,084

Earnings per share:
Basic	$	.59		$	.71
Diluted	$	.58		$	.70

Weighted-average shares outstanding:
Basic		292,627			293,024
Diluted		295,284			296,477

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)


	December 31, 2007		September 30, 2007
ASSETS

Current assets:
Cash and cash equivalents	$	53,618	$	58,199
Receivables - net		1,042,957		1,022,847
Inventories - net:
Products		238,078		226,666
Work in process		29,502		37,460
Parts		217,859		221,811

Total inventories		485,439		485,937
Deferred income taxes		26,550		19,994
Prepaid expenses		48,286		72,033
Other current assets		42,396		44,762

Total current assets		1,699,246		1,703,772

Property - net		2,080,260		1,965,719
Deferred income taxes		36,523		30,471
Goodwill		964,518		963,937
Investments and other assets		50,989		51,313

	$	4,831,536	$	4,715,212


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	483,785	$	530,029
Short-term borrowings		124,548		171,268
Current portion of long-term debt		250,000		250,000
Accrued employee compensation and benefits		118,308		124,231
Income and other taxes		120,554		89,111
Accrued insurance		26,200		26,284
Other accrued liabilities		111,609		122,265

Total current liabilities		1,235,004		1,313,188

Long-term debt		249,776		249,760
Deferred income taxes		98,243		95,485
Other long-term liabilities		214,939		205,381
Commitments and contingencies (Note 5)
Stockholders’ equity		3,033,574		2,851,398

	$	4,831,536	$	4,715,212

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 Shares Outstanding	Common Stock		Capital In Excess of Par			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income		Total
Balance, September 30, 2007	291,736	$	34,752	$	1,060,115		$	(1,479,035	)	$	3,183,922		$	51,644	$	2,851,398

Adoption of FIN 48 (Note 6)											(8,115	)				(8,115	)
Comprehensive income:
Net income											172,184
Other comprehensive income, net of tax:
Cumulative translation adjustments														4,557
Comprehensive income																176,741
Re-issuance of treasury stock for:
Stock purchase plan	648							17,202			(2,564	)				14,638
Stock options	497							13,056			(10,980	)				2,076
Other stock awards	96				(2,552	)		2,552								—
Stock based compensation					8,464											8,464
Tax benefit from exercise of options					3,021											3,021
Dividends declared											(14,649	)				(14,649	)

Balance, December 31, 2007	292,977	$	34,752	$	1,069,048		$	(1,446,225	)	$	3,319,798		$	56,201	$	3,033,574

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)


	Three Months Ended December 31,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	172,184		$	207,084
Adjustments to reconcile net income to cash provided by operating activities:
Minority interest expense		3,069			2,482
(Gain)/loss on disposal of assets		(626	)		265
Depreciation and amortization		62,766			45,705
Excess tax benefits from stock based compensation		(3,081	)		(453	)
Deferred income tax (benefit)/expense		(8,299	)		1,004
Changes in:
Receivables		(21,917	)		18,348
Inventories		45			(28,922	)
Prepaid expenses		23,727			(401	)
Other current assets		2,523			2,848
Accounts payable		(45,471	)		(19,444	)
Accrued employee compensation and benefits		(5,923	)		(36,650	)
Current income tax		37,549			55,417
Other current liabilities		(16,849	)		14,981
Other - net		4,058			8,829

Net cash provided by operating activities		203,755			271,093

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(161,797	)		(146,861	)
Proceeds from disposal of assets		3,827			1,150
Acquisitions of businesses, net of cash received		—			(10,695	)

Net cash used in investing activities		(157,970	)		(156,406	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of short-term borrowings, net		(46,720	)		(115,248	)
Dividends paid to shareholders		(14,584	)		(14,660	)
Purchase of treasury stock		—			(20,006	)
Excess tax benefits from stock based compensation		3,081			453
Proceeds from exercise of stock options and stock purchase plan		6,965			6,673

Net cash used in financing activities		(51,258	)		(142,788	)

Effect of exchange rate changes on cash		892			(1,819	)

Decrease in cash and cash equivalents		(4,581	)		(29,920	)
Cash and cash equivalents at beginning of period		58,199			92,445

Cash and cash equivalents at end of period	$	53,618		$	62,525

Cash Paid for Interest and Taxes:
Interest	$	13,535		$	13,017
Taxes		15,074			41,810

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 our opinion, 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 our financial position and statement of stockholders’ equity as of December 31, 2007, and our results of operations and cash flows for each of the three-month periods ended December 31, 2007 and 2006. The consolidated condensed statement of financial position at September 30, 2007 is derived from the September 30, 2007 audited consolidated financial statements. Although we believe 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-month period ended December 31, 2007 are not necessarily indicative of the results to be expected for the full year.

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, stock incentive awards, bonus stock and stock awards) less the number of treasury shares assumed to be purchased with the exercise proceeds using the average market price of our common stock for each of the periods presented.

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


	Three Months Ended December 31,
	2007		2006
Net income	$	172,184	$	207,084
Weighted-average common shares outstanding		292,627		293,024

Basic earnings per share	$	.59	$	.71

Weighted-average common and dilutive potential common shares outstanding:
Weighted-average common shares outstanding		292,627		293,024
Assumed exercise of dilutive instruments⁽¹⁾		2,657		3,453

Weighted-average dilutive shares outstanding		295,284		296,477

Diluted earnings per share	$	.58	$	.70

⁽¹⁾	For the three months ended December 31, 2007 and 2006, 3.1 million and 2.5 million stock options, respectively, were excluded from the computation of diluted earnings per share due to their antidilutive effect.

Note 3 Segment Information

We currently have 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 four reportable segments: U.S./Mexico Pressure Pumping, Canada Pressure Pumping, International Pressure Pumping, and the Oilfield Services Group.

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 Canada Pressure Pumping segment has one operating segment. Like U.S./Mexico Pressure Pumping, it includes cementing and stimulation services. These services are provided to customers in major oil and natural gas producing areas of Canada.

The International Pressure Pumping segment has five operating segments. Similar to U.S./Mexico and Canada Pressure Pumping, it includes cementing and stimulation services. These services are provided to customers in more than 50 countries in the major international oil and natural gas producing areas of Latin America, Europe and Africa, Asia Pacific, Russia and the Middle East. These 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 Oilfield Services segment has five operating segments. These operating segments provide other oilfield services such as chemical services, casing and tubular services, process and pipeline services, completion tools and completion fluids services in the U.S. and in select markets internationally. These operating segments have been aggregated into one reportable segment as they all provide other oilfield services, serve 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 our annual report on Form 10-K for the fiscal year ended September 30, 2007. Operating segment performance is evaluated based on operating income. Intersegment sales and transfers are not material.

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


	U.S./Mexico Pressure Pumping		Canada Pressure Pumping		International Pressure Pumping		Oilfield Services Group		Corporate			Total
	(in thousands)
Three Months Ended December 31, 2007
Revenue	$	662,551	$	121,346	$	288,512	$	212,656	$	—		$	1,285,065
Operating income (loss)		182,022		16,992		35,925		40,033		(22,391	)		252,581

Identifiable assets		1,606,734		546,694		1,359,646		919,659		398,803			4,831,536

Three Months Ended December 31, 2006
Revenue	$	640,826	$	111,664	$	252,056	$	179,394	$	—		$	1,183,940
Operating income (loss)		252,557		13,407		40,373		32,698		(22,709	)		316,326
Identifiable assets		1,297,008		475,636		1,082,945		732,277		364,702			3,952,568

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


	Three Months Ended December 31,
	2007			2006
Total operating income for reportable segments	$	252,581		$	316,326
Interest expense		(7,862	)		(8,779	)
Interest income		474			320
Other expense – net		(2,711	)		(2,076	)

Income before income taxes	$	242,482		$	305,791

Note 4 Acquisitions

On June 30, 2007, we completed the acquisition of substantially all of the capillary tubing assets of Allis-Chalmers for a total purchase price of $16.3 million, which resulted in $12.3 million of goodwill. The assets are used for the installation and service of capillary injection systems primarily in the U.S. and Mexico. The assets complement our Dyna-Coil acquisition which occurred in the fourth quarter of fiscal 2006 and will enhance our chemical services operation in the Oilfield Services Group.

On March 1, 2007 we acquired Aberdeen-based Norson Services Ltd, (“Norson”), a division of Norson Group Ltd. In a related transaction completed on the same day, we purchased substantially all of the assets of Norson Group’s United States subsidiary Norson Services LLC. The total purchase price paid for both acquisitions was $28.9 million, including legal fees, which resulted in an increase of $7.3 million in total current assets, $5.8 million in property and equipment, $1.9 million in intangible assets, $6.5 million in current liabilities and $20.4 million of goodwill. The acquisition strengthens our service capabilities with the addition of Norson’s hydraulic and electrical umbilical testing services and the services provided by the Norson’s subsea units, which include remote pigging and flooding, subsea hydro testing and subsea data logging. This business complements our process and pipeline business in the Oilfield Services Group.

We are in the process of completing our review and determination of the fair values of the assets acquired from Allis-Chalmers. Accordingly, allocation of the purchase price is subject to revision based on final determination of the asset values. Pro forma financial information for these acquisitions is not included as they were not material individually or in aggregate to our financial statements.

Note 5 Commitments and Contingencies

Litigation

We, through performance of our service operations, are sometimes named as a defendant in litigation, usually relating to claims for personal injury or property damage (including claims for well or reservoir damage). We maintain insurance coverage against such claims to the extent deemed prudent by management. Further, through a series of acquisitions, we 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 our predecessors that were in place at the time of the acquisitions.

Although the outcome of the claims and proceedings against us (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 our financial position or results of operations for which it has not already provided.

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 $15.6 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 was stayed. On February 28, 2003, the Court issued its final judgment in connection with the Newfield claims, based upon the jury’s verdict. At the same time, the Court issued rulings adverse to OSCA in connection with its claim for insurance coverage. Motions for New Trial were denied by the Judge and the case was appealed to the U.S. Court of Appeals for the Fifth Circuit, both with regard to the liability case and the insurance coverage issues. The Fifth Circuit issued its ruling on April 12, 2006, finding against OSCA on the liability issues, but ruling in OSCA’s favor on insurance coverage. AISLIC filed a Motion for Re-hearing with the Fifth Circuit, which was denied. The case was remanded to the District Court in June 2006 for further consideration of one exclusion contained in the AISLIC policy. The District Court recently ruled that AISLIC owes an additional $4.3 million as the insurance policy covers portions of the damages incurred in the case. To date, approximately 50% of the judgment against OSCA has already been paid by AISLIC, due to the ruling by the Fifth Circuit. Upon remand, Newfield filed a motion to enforce its judgment against OSCA, which the court denied. Great Lakes Chemical Corporation, (which owned the majority of the outstanding shares of

OSCA at the time of the acquisition) agreed to indemnify OSCA for 75% of any uninsured liability in excess of $3 million arising from the Newfield litigation. Taking this indemnity into account and without regard to the outcome of the insurance coverage dispute, our share of the verdict is approximately $5.3 million. We are fully reserved for our share of this liability.

Asbestos Litigation

In August 2004, certain predecessors of ours, along with numerous other defendants were named in four lawsuits filed in the Circuit Courts of Jones and Smith Counties in Mississippi. These four lawsuits included 118 individual plaintiffs alleging that they suffer various illnesses from exposure to asbestos and seeking damages. The lawsuits assert claims of unseaworthiness, negligence, and strict liability, all based upon the status of our predecessors as Jones Act employers. The plaintiffs were required to complete data sheets specifying the companies they were employed by and the asbestos-containing products to which they were allegedly exposed. Through this process, approximately 25 plaintiffs have identified us or our predecessors as their employer. Amended lawsuits were filed by four individuals against us and the remainder of the original claims (114) were dismissed. Of these four lawsuits, three failed to name us as an employer or manufacturer of asbestos containing products so we were thereby dismissed. Subsequently an individual from one of these lawsuits brought his own action against us. As a result, we are currently named as an employer in two of the Mississippi lawsuits. It is possible that as many as 21 other claimants who identified us or our predecessors as their employer could file suit against us, but they have not done so at this time. Only minimal medical information regarding the alleged asbestos-related disease suffered by the plaintiffs in the two lawsuits has been provided. Accordingly, we are unable to estimate our potential exposure to these lawsuits. We and our predecessors in the past maintained insurance which may be available to respond to these claims. In addition to the Jones Act cases, we have been named in a small number of additional asbestos cases. The allegations in these cases vary, but generally include claims that we provided some unspecified product or service which contained or utilized asbestos or that an employee was exposed to asbestos at one of our facilities or customer job site. Some of the allegations involve claims that we are the successor to the Byron Jackson Company. To date, we have been successful in obtaining dismissals of such cases without any payment in settlements or judgments, although some remain pending at the present time. We intend to defend ourselves vigorously in all of these cases based on the information available to us at this time. We do not expect the outcome of these lawsuits, individually or collectively, to have a material adverse effect on our 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.

Halliburton – Python Litigation

On December 21, 2007, Halliburton Energy Services, Inc. re-filed a prior suit against us 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 Weatherford and us (under the trade name “Python”) infringe various 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). This lawsuit arises from litigation filed in 2003 by Halliburton regarding the patents at issue. The earlier case was dismissed without prejudice when Halliburton sought a re-examination of the patents by the United States Patent and Trademark Office on July 6, 2004. We do not expect the outcome of this matter to have a material adverse effect on our 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.

Environmental

Federal, state and local laws and regulations govern our operation of underground fuel storage tanks. Rather than incur additional costs to restore and upgrade tanks, management opted to remove the existing tanks, beginning in 1989. We have remedial cleanups in progress related to the tank removals. In addition, we are conducting environmental investigations and remedial actions at current and former Company locations and, along with other companies, are currently named as a potentially responsible party at five waste disposal sites owned by third parties. An accrual of approximately $4.0 million has been established for such environmental matters, which is management’s best estimate of our portion of future costs to be incurred. Insurance is also maintained for some environmental liabilities.

Lease and Other Long-Term Commitments

In 1999, we contributed certain pumping service equipment to a limited partnership, in which we own a 1% interest. The equipment is used to provide services to our customers for which we pay 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. We assessed the terms of this agreement and determined it was a variable interest entity as defined in FIN 46(R), Consolidation of Variable Interest Entities. However, we were 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 $8.3 million and $9.0 million as of December 31, 2007 and September 30, 2007, respectively. The agreement permits substitution of equipment within the partnership as long as the implied fair value of the new property transferred in at the date of substitution equals or exceeds the implied fair value, as defined, of the current property in the partnership that is being replaced. In September 2010, we have the option, but not the obligation, to purchase the pumping service equipment for approximately $32 million. We currently intend to exercise this option. The option price to purchase the equipment under the partnership depends in part on the fair market value of the equipment held by the partnership at the time the option is exercised, as well as other factors specified in the agreement.

Other Commercial Commitments

We routinely issue Parent Company Guarantees (“PCGs”) in connection with service contracts entered into by our subsidiaries. The issuance of these PCGs is frequently a condition of the bidding process imposed by our customers for work in countries outside of North America. The PCGs typically provide that we guarantee the performance of the services by our local subsidiary. The term of these PCGs varies with the length of the service contract. To date, the parent company has not been called upon to perform under any of these PCGs.

We arrange 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 we, or our subsidiary, have entered into with customers. The customer has the right to call on the bank guarantee, performance bond or standby letter of credit in the event that we, or our subsidiary, default in the performance of services. These instruments are required as a condition to 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 our 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 our other commercial commitments as of December 31, 2007 (in thousands):


			Amount of commitment expiration per period
Other Commercial Commitments	Total Amounts Committed		Less than 1 Year		1–3 Years		4–5 Years		Over 5 Years
Standby Letters of Credit	$	42,028	$	37,220	$	4,808	$	—	$	—
Guarantees		187,782		72,418		67,589		15,550		32,225

Total Other Commercial Commitments	$	229,810	$	109,638	$	72,397	$	15,550	$	32,225

Investigations Regarding Misappropriation and Possible Illegal Payments

In October 2004, we received a report from a whistleblower alleging that our Asia Pacific Region Controller had misappropriated Company funds in fiscal 2001. We 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 us and the Region Controller’s employment was terminated. The former Region Controller pled guilty to one count of theft in Singapore and received a 21 month prison sentence there on May 7, 2007.

We are continuing to investigate whether additional funds were misappropriated beyond the $9.0 million originally identified. We have identified an additional $1.7 million that we believe was misappropriated by the former Region Controller. It is possible that additional information could emerge resulting in further adjustments in the Consolidated Statements of Operations, but no material adjustments are known at this time. In June 2007, we filed a civil lawsuit against the former Region Controller seeking to recover any additional misappropriated funds and seeking an accounting of disbursements that could not be explained following the investigation.

In October 2004, we also received whistleblower allegations that illegal payments to foreign officials had been 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. The investigation found information indicating a significant likelihood that payments, made by us to an entity in the Asia Pacific Region with which we have certain contractual relationships, were then used to make payments to government officials in the Asia Pacific Region. This information included information indicating that certain of our employees in the Asia Pacific Region believed that the funds paid to the entity would be used to make payments to government officials. The payments, which may have been illegal, aggregated approximately $2.6 million and were made from fiscal 1999 through 2004.

Thereafter, in December 2005, we received a payment of approximately $2.8 million from the entity referenced above. The entity said that the funds represented the $2.6 million of funds described above, plus an interest amount, and that the $2.6 million had been misappropriated for the benefit of certain of that entity’s employees and was not used to make payments to government officials. The Audit Committee’s investigation was not able to verify this claim.

During 2007, the investigation identified another payment of $300,000 made in a prior year to the same entity that may have been used to make illegal payments to government officials.

We and our Audit Committee also investigated a large volume of other payments made by us during the period of fiscal 1998 through 2004 in the Asia Pacific Region. With respect to approximately $10 million of these payments, the investigations to date either have not been able to establish the legitimacy of the

transactions reflected in the underlying documents or have not been able to resolve questions about the adequacy of the underlying documents to support the accounting entries. Some of these payments may have been proper, but the circumstances surrounding others suggest that theft, illegal payments or other improprieties may have been involved. The payments have been previously expensed, and therefore we believe that no additional expense is required to be recorded for such payments.

We have voluntarily disclosed information found in the special Audit Committee investigation, as well as related information from our theft investigation, to the U.S. Department of Justice (“DOJ”) and U.S. Securities and Exchange Commission (“SEC”) and have engaged in discussions with these authorities as they review the matter. We cannot predict whether further investigative efforts may be required or initiated by the authorities.

In connection with discussions regarding possible illegal payments in the Asia Pacific Region, U.S. government officials raised a question whether we had made illegal payments to a contractor or intermediary to obtain business in a country in Central Asia. The Audit Committee has investigated this question. We have voluntarily disclosed information found in the investigation to the DOJ and SEC and have engaged in discussions with these authorities as they review the matter.

The DOJ, SEC and other authorities have a broad range of civil and criminal sanctions under the U.S. Foreign Corrupt Practices Act (“FCPA”) and other laws, which they may seek to impose against corporations and individuals in appropriate circumstances including, but not limited to, injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs. Such agencies and authorities have entered into agreements with, and obtained a range of sanctions against, several public corporations and individuals arising from allegations of improper payments and deficiencies in books and records and internal controls, whereby civil and criminal penalties were imposed. Recent civil and criminal settlements have included multi-million dollar fines, deferred prosecution agreements, guilty pleas, and other sanctions, including the requirement that the corporation retain a monitor to oversee the corporation’s compliance with the FCPA. Furthermore, corporations that have entered into prior consent decrees regarding the FCPA are potentially subject to greater penalties. We entered into a consent decree with the SEC in 2004 following an investigation into improper payments in Argentina.

We have had discussions with the DOJ and SEC regarding certain of the matters described above. It is not possible to accurately predict at this time when any of these matters will be resolved. Based on current information, we cannot predict the outcome of such investigations, whether we will reach resolution through such discussions or what, if any, actions may be taken by the DOJ, SEC or other authorities or the effect the foregoing may have on our consolidated financial statements.

The misappropriations and related accounting adjustments in the Asia Pacific Region were possible because of certain internal control operating deficiencies. During fiscal 2002, we implemented policy changes worldwide for disbursements. Significant personnel changes were also made in the Asia Pacific Region. We assigned a new Region Manager and a new Region Controller, an Assistant Controller and replaced several accountants in the Asia Pacific region. We also took further disciplinary action against personnel in the Region. In addition, we put in place an Internal Control and Process Improvement function, led by an internal control manager at the corporate office and supported by managers at each of our five regional bases worldwide, to document, enhance, and test our control processes.

Note 6 Income Taxes

On October 1, 2007 we adopted FASB Interpretation No. 48 (“FIN 48”),Accounting for Uncertainty in Income Taxes. FIN 48 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, the tax benefit from an uncertain

tax position is to be recognized when it is more likely than not, based on the technical merits of the position, that the position will be sustained on examination by the taxing authorities. Additionally, the amount of the tax benefit to be recognized is the largest amount of benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim, and financial statement disclosures.

We adopted the provisions of FIN 48 on October 1, 2007. As a result of the implementation of FIN 48, we recognized a reduction of $8.1 million in the October 1, 2007 balance of retained earnings.

As of the date of adoption we have unrecognized tax benefits of $66.6 million, all of which, if recognized, would affect the effective tax rate in the period in which recognized. There has been no material change in this amount during the first fiscal quarter of 2008. It is reasonably possible that between $12.0 million and $16.0 million of unrecognized tax benefits could be realized in the next twelve months due to expiration of statutes of limitations and audit settlements for filing positions.

We recognize potential penalties and interest related to unrecognized tax benefits as a component of income tax expense. Interest and penalties that have been accrued as of the date of adoption is $11.3 million. There has been no material change in this amount during the first fiscal quarter of 2008.

We file tax returns in the United States and approximately fifty countries and are subject to audits periodically, none of which is expected to have a material impact on our financial statements. Due to the uncertainty and various stages of such audits, we are unable to make reasonably reliable estimates of the period of any cash settlement related to our FIN 48 liabilities or whether any material net cash settlement will be required. The United States and Canada are our major taxing jurisdictions since these jurisdictions have the highest projected tax liability for the current year. The earliest open tax year subject to examination is 2004 for the United States and 1999 for Canada.

Note 7 Employee Benefit Plans

We have a frozen U.S. Defined Benefit Plan, Foreign Defined Benefit Plans covering certain groups of employees, and a Postretirement Benefit Plan, all of which are described in more detail in Note 9 of the Notes to the Consolidated Financial Statements included in our annual report on Form 10-K for the fiscal year ended September 30, 2007. Below is the amount of net periodic benefit costs recognized under our Foreign Defined Benefit Plans (in thousands). Information for our U.S. Defined Benefit Plan net periodic benefit costs is not presented as it is not material.

Defined Benefit Plans


	Three Months Ended December 31,
	Non-U.S.
	2007			2006
Service cost for benefits earned	$	1,680		$	1,604
Interest cost on projected benefit obligation		3,327			2,507
Expected return on plan assets		(2,903	)		(2,341	)
Recognized actuarial loss		604			760
Net amortization and deferral		(25	)		(349	)

Net pension cost	$	2,683		$	2,181

In September 2006, we entered into an agreement to settle our obligation with respect to the U.S.

defined benefit plan. Plan assets of approximately $72 million, plus our contribution of $1.5 million, were used to purchase an insurance contract that is being used to fund the benefits and settle the plan. The proposed settlement requires approval from the Pension Benefit Guaranty Corporation and the Internal Revenue Service to relieve us of primary responsibility for the pension benefit obligation. Once regulatory approval is obtained, which is expected in fiscal 2008, we will expense approximately $23.3 million in connection with the settlement. This consists of $7 million of prepaid pension cost and $16 million of loss currently recognized in other comprehensive income. By relieving us of our obligation, the expense that would have otherwise been recognized over the remaining plan life will be accelerated to the period in which approval is received.

In fiscal 2008, we expect to contribute $17.4 million to the defined benefit plans, which represents the legal or contractual minimum funding requirements and expected discretionary contributions. We have paid $0.8 million in non-discretionary contributions during the three months ended December 31, 2007. These contributions have been and are expected to be funded by cash flows from operating activities.

Postretirement Benefit Plan

Below is the amount of net periodic benefit costs recognized under our Postretirement Benefit Plan (in thousands).


	Three Months Ended December 31,
	2007		2006
Service cost for benefits attributed to service during the period	$	1,033	$	993
Interest cost on accumulated postretirement benefit obligation		914		825

Net postretirement benefit cost	$	1,947	$	1,818

We expect to contribute $1.6 million to the postretirement plan in fiscal 2008, which represents the anticipated claims. We have made $0.3 million in postretirement contributions during the three months ended December 31, 2007.

Note 8 New Accounting Standards

In December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations (“SFAS 141(R)”), replacing SFAS No. 141,Business Combinations(“SFAS 141”).SFAS 141 (R) retains the fundamental requirements in SFAS 141 that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS 141(R) defines the acquirer as the entity that obtains control of one or more businesses in the business combination and establishes the acquisition date as the date that the acquirer achieves control. SFAS 141(R) establishes principles and requirements for how the acquirer:

Recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree.

Recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase.

Determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.

This statement is effective for fiscal years beginning after December 15, 2008. We are currently in the process of evaluating the impact of SFAS 141(R) on our financial statements.

In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements(“SFAS 160”), amending ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest and requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS 160 requires expanded disclosures in the consolidated financial statements that identify and distinguish between the interests of the parent’s owners and the interests of the noncontrolling owners of a subsidiary and shall be applied prospectively as of the beginning of the fiscal year in which initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. SFAS 160 is effective for fiscal years beginning after December 15, 2008. We are currently in the process of evaluating the impact of SFAS 160 on our financial statements.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115(“SFAS 159”). This Statement provides companies with an option to report selected financial assets and liabilities at fair value. Under SFAS 159, companies that elect the fair value option will report unrealized gains and losses in earnings at each subsequent reporting date. In addition, SFAS 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. The fair value option election is irrevocable, unless a new election date occurs. SFAS 159 is effective the beginning of an entity’s first fiscal year beginning after November 15, 2007 and is to be applied prospectively, unless the entity elects early adoption. We are currently in the process of evaluating the impact of SFAS 159 on our financial statements, if we choose to elect this option.

In September 2006, the FASB issued SFAS No. 157 (“SFAS 157”),Fair Value Measurements, effective for financial statements issued for fiscal years beginning after November 15, 2007. SFAS 157 introduces a new definition of fair value, a fair value hierarchy (requiring market based assumptions be used, if available) and new disclosures of assets and liabilities measured at fair value based on their level in the hierarchy. We are currently in the process of evaluating the impact of SFAS 157 on our financial statements.

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Business

We are engaged in providing pressure pumping services and other oilfield services to the oil and natural gas industry worldwide. Services are provided through four business segments: U.S./Mexico Pressure Pumping, Canada Pressure Pumping, International Pressure Pumping and the Oilfield Services Group.

The U.S./Mexico, Canada Pressure Pumping 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 consist of pumping 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, 2007 for more information on these operations.

The Oilfield Services Group consists of 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

Our 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 our revenue and profitability, especially in the United States and Canada, where we have historically generated in excess of 50% of our revenue. Historical market conditions are reflected in the table below:


	For the three months ended December 31,
	2007		% Change		2006
Rig Count:⁽¹⁾
U.S.		1,790	4	%		1,720
Canada		356	-19	%		440
International⁽²⁾		1,018	7	%		951
Commodity Prices (average):
Crude Oil (West Texas Intermediate)	$	90.67	51	%	$	59.99
Natural Gas (Henry Hub)	$	6.99	5	%	$	6.66

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

⁽²⁾	Excludes Canada, and includes Mexico average rig count of 93 and 84 for the three-month periods ended December 31, 2007 and 2006, respectively.

U.S. Rig Count

Demand for our 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 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 1,749 in fiscal 2007.

Canadian Rig Count

The demand for our pressure pumping services in Canada is primarily driven by oil and natural gas drilling activity, and similar to the U.S., tends to be extremely volatile. During the last 10 years, the lowest annual rig count averaged 212 in fiscal 1999 and the highest annual rig count averaged 502 in fiscal 2006. The average annual rig count was 365 in fiscal year 2007.

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, our international revenue in total is less volatile because we operate in approximately 50 countries, which provides a reduction of exposure to any one country. Due to the significant investment and complexity of international projects, we believe 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 averaged 616 in fiscal 1999 and the highest annual international rig count averaged 989 in fiscal 2007.

Results of Operations

Consolidated


	Three Months Ended December 31,
	2007		% Change		2006
(dollars in millions)
Revenue	$	1,285.1	9	%	$	1,183.9
Operating income	$	252.6	-20	%	$	316.3

Worldwide rig count⁽¹⁾		3,164	2	%		3,111

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

All of our reportable segments made positive contributions to the consolidated revenue growth for the first fiscal quarter of 2008. The integration of businesses acquired within the Oilfield Services Group in recent years, the introduction of two stimulation vessels in our Middle East pressure pumping operations, and activity related improvements in almost all regions of our U.S./Mexico operations were significant providers to the growth.

While revenue for the three months ended December 31, 2007 increased, consolidated operating income for the period decreased, primarily as the result of price declines for our products and services in the U.S. pressure pumping market. For the three months ended December 31, 2007, consolidated operating income margins decreased to 20% from 27% reported in the same period of the prior fiscal year.

U.S./Mexico Pressure Pumping


	Three Months Ended December 31,
	2007		% Change		2006
(dollars in millions)
Revenue	$	662.6	3	%	$	640.8
Operating income		182.0	-28	%		252.6

U.S. rig count⁽¹⁾		1,790	4	%		1,720
Mexico rig count⁽¹⁾		93	11	%		84

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

Our U.S./Mexico Pressure Pumping operations first fiscal quarter 2008 revenue improved 3% with average active drilling rigs increasing 4% during the same period. The impact of lower prices for our products and services in the U.S. market was offset by a higher volume of jobs performed, allowing almost all regions to contribute to the revenue improvement. However, revenue from our Gulf Coast operations declined due to lower drilling activity in the region and revenue from our Rocky Mountain operations remained flat as a result of more weather-related job delays than in the prior year.

Operating income margin decreased from 39% in the first fiscal quarter 2007 to 27% during the first fiscal quarter 2008 as increased competition in the U.S. has resulted in lower pricing for our products and services. Increased material, fuel and labor costs also contributed to the margin decline.

Canada Pressure Pumping


	Three Months Ended December 31,
	2007		% Change		2006
(dollars in millions)
Revenue	$	121.3	9	%	$	111.7
Operating income		17.0	27	%		13.4

Canadian rig count⁽¹⁾		356	-19	%		440

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

The Canadian Pressure Pumping revenue increase for the first fiscal quarter of 2008 was entirely due to the strengthening of the Canadian dollar. Relative to the U.S. dollar, the Canadian dollar exchange rate increased 14% in the first fiscal quarter of 2008 compared to the same period in fiscal 2007, thereby increasing the U.S. dollar equivalent of revenues earned in Canada. On a Canadian dollar basis, revenue declined 15% due to lower drilling activity levels. Average active drilling rigs decreased 19% for the first fiscal quarter of 2008 compared to the same period in the prior year.

Operating income margin improved to 14% for the three months ended December 31, 2007, from 12% during the same period in the prior year, primarily as a result of cost reduction measures, including facility closures, asset redeployment and headcount reductions, that we implemented in the third and fourth fiscal quarters of 2007 in response to the weaker market conditions.

International Pressure Pumping


	Three Months Ended December 31,
	2007		% Change		2006
(dollars in millions)
Revenue	$	288.5	14	%	$	252.1
Operating income		35.9	-11	%		40.4

International rig count, excluding Mexico⁽¹⁾		925	7	%		867

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

The following table summarizes the percentage change in revenue for each of the operating segments within the International Pressure Pumping reportable segment, comparing the first fiscal quarter of 2008 with the comparable period of fiscal 2007:


	% change in Revenue
Europe/Africa	-10	%
Middle East	47	%
Asia Pacific	22	%
Russia	-32	%
Latin America	25	%

International Pressure Pumping revenue increased 14% in the first fiscal quarter of 2008 when compared to the same period in the prior year, with our Middle East and Latin American operations being the most significant contributors. The Middle East revenue growth was primarily due to the introduction of two stimulation vessels into the India market during the fourth fiscal quarter of 2007. One of the vessels operated in the North Sea prior to being transferred to India and as a result, revenue from our Europe/Africa region decreased from the same quarter last year.

Our Latin American revenue increased largely due to an increase in fracturing activity in Brazil and Argentina. The average active drilling rig count in the region increased 9% during the three months ended December 31, 2007, when compared to the same period in the prior year.

In our Asia Pacific region, revenue increased due to the start up of new projects in Australia and New Zealand as well as increased activity in China. The average active drilling rig count for the region increased 10% in the first fiscal quarter of 2008 when compared to the same period in fiscal 2007.

In Russia, declines in activity and redeployment of assets into other markets accounted for the decline in revenue.

Operating income margins from our International Pressure Pumping operations decreased from 16% in the first fiscal quarter of fiscal 2007 to 12% for the first fiscal quarter of 2008, with declines in revenue from our Europe/Africa and Russia operations being the primary contributors to the lower operating income margin. Unusually harsh weather conditions in a number of areas, costs associated with two offshore stimulation vessels being dry docked for a portion of the quarter, project delays and front-end project start-up costs in a number of international markets all contributed to the margin decline.

Oilfield Services Group


	Three Months Ended December 31,
	2007		% Change		2006
(dollars in millions)
Revenue	$	212.7	19	%	$	179.4
Operating income		40.0	22	%		32.7

The following table summarizes the percentage change in revenue for each of the operating segments within Oilfield Services Group:


	% Change in Revenue
Tubular Services	11	%
Process & Pipeline Services	51	%
Chemical Services	26	%
Completion Tools	23	%
Completion Fluids	-33	%

All of our operating segments, except Completion Fluids, showed improved revenues during the three months ended December 31, 2007, when compared to the same period in the prior year. Process and Pipeline Services revenue increased 51%, due to increased activity in our European and U.S. operations. Chemical Services also showed improved revenue largely due to increased capillary services activity. Completion Tools improved year over year due to continued expansion into international markets. The decline in revenue from Completion Fluids was primarily the result of lower U.S. deepwater activity and lower revenue in Mexico.

Operating income margin for the Oilfield Services Group for the first fiscal quarter of 2008 was 19% compared to 18% in first fiscal quarter of fiscal 2007. All of our operating segments, except Completion Fluids, contributed to the margin improvement.

Outlook

As stated under “Market Conditions” above, our 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. Our results of operations also depend heavily on the pricing we receive from our customers. The degree of pricing acceptance varies by customer and depends on activity levels and competitive pressures.

For the second fiscal quarter of 2008, we expect drilling activity to remain relatively flat in the U.S. market, and we expect pricing pressures to continue at least until the latter part of the year. We do expect continued high demand for our services in a number of areas, especially in gas shale areas in Arkansas, the Rockies and the Mid-Continent region, and we anticipate increased Gulf of Mexico activity particularly in the deep water area.

Canadian drilling activity is expected to increase in the second fiscal quarter as we enter the winter drilling season, and we expect our operating results to improve there compared to the first fiscal quarter.

We also anticipate increased revenue and improved margins in the International Pressure Pumping segment. Both the Blue Angel stimulation vessel in Brazil and the Vestfonn stimulation vessel in India have returned to work after being dry-docked for a portion of the first fiscal quarter. We have a number of new projects in our international pressure pumping operations that either have already begun or are scheduled to begin in the second fiscal quarter in Latin America, North Africa and China that we believe will help to improve international operating margins.

Our Oilfield Services group is projected to be up slightly in the second quarter as revenue growth from Completion Tools and Completion Fluids will be partially offset by continued seasonal decline in our Process and Pipeline Services business.

Other Expenses

The following table sets forth our other operating expenses (in thousands):


	Three Months Ended December 31,
	2007		2006
Research and engineering	$	17,198	$	15,694
Marketing		28,832		25,813
General and administrative		36,630		37,207

Research and engineering: While research and engineering expense increased for the three months ended December 31, 2007 compared to the same period in the prior fiscal year, as a percentage of revenue this expense has remained consistent at 1.3%.

Marketing:While marketing expense increased for the three months ended December 31, 2007 compared to the same period in the prior fiscal year, as a percentage of revenue this expense has remained consistent at 2.2%.

General and administrative:General and administrative expense decreased $0.6 million, or 2%, in the first quarter of fiscal 2008 compared to the same period in fiscal 2007. As a percentage of revenue, general and administrative expense decreased from 3.1% to 2.9%.

The following table shows a comparison of interest expense, interest income, and other expense, net (in thousands):


	Three Months Ended December 31,
	2007			2006
Interest expense	$	(7,862	)	$	(8,779	)
Interest income		474			320
Other expense, net		(2,711	)		(2,076	)

Interest Expense and Interest Income:Interest expense decreased slightly with outstanding debt balances decreasing from $660.0 million at December 31, 2006 to $624.3 million at December 31, 2007. Interest income was consistent with the same period in the prior year. We expect fiscal year 2008 interest expense, net of interest income, to be approximately $25.0 million.

Other Expense, net:Other expense, net is primarily composed of minority interest expense of $3.1 million and $2.5 million for the three months ended December 31, 2007 and 2006, respectively.

Income Tax Expense

Our effective tax rate decreased from 32% for the three months ended December 31, 2006 to 29% for the three months ended December 31, 2007 primarily due to the effect of a rate decrease in Canada and an increase in the domestic production activity deduction in the U.S.

Liquidity and Capital Resources

Historical Cash Flow

The following table sets forth the historical cash flows (in millions):


	Three Months Ended December 31,
	2007			2006
Cash flow from operations	$	203.8		$	271.1
Cash flow used in investing		(158.0	)		(156.4	)
Cash flow used in financing		(51.3	)		(142.8	)
Effect of exchange rate changes on cash		.9			(1.8	)

Change in cash and cash equivalents	$	(4.6	)	$	(29.9	)

Lower profits caused by declines in U.S. pricing and increased material, fuel and labor costs for our U.S./Mexico Pressure Pumping segment resulted in lower cash flow from operations. Working capital increased $73.7 million. Significant uses of cash were a $45.5 million reduction in accounts payable due to lower capital spending for fiscal 2008 and a $21.9 million increase in accounts receivable primarily as a result of increased revenues. Prepaid expenses decreased $23.7 primarily related to the timing of income tax payments.

The cash flow used in investing during the three months ended December 31, 2007 was almost entirely due to $161.8 million of purchases of property, plant, and equipment.

Cash flows used in financing consisted of $46.7 million, net, in payments of short term borrowings and a $14.6 million payment of dividends during the three months ended December 31, 2007. We also received proceeds in the amount of $7.0 million from employee stock purchases and stock option exercises during the first fiscal quarter of 2008.

Liquidity and Capital Resources

Cash flows from operations are expected to be our primary source of liquidity for the remainder of fiscal 2008. Our sources of liquidity also include cash and cash equivalents of $53.6 million at December 31, 2007 and the available financing facilities listed below (in millions):


Financing Facility	Expiration	Borrowings at December 31, 2007		Available at December 31, 2007
Revolving Credit Facility	August 2012	$	80.0	$	320.0

Discretionary	Various times within the next 12 months	$	44.5	$	123.1

As of December 31, 2007, we had $250.0 million of Senior Notes due June 2008 issued and outstanding and $249.8 million, net of discount, of 5.75% Senior Notes due 2011 issued and outstanding.

In August 2007, we amended and restated our then existing revolving credit facility. The amended and restated revolving credit facility (the “Revolving Credit Facility”) permits borrowings of 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 August 2012. In addition, we have the right to request up to an additional $200 million over the permitted borrowings of $400 million, subject to the approval of our lenders at the time of the request. Depending on the amount of borrowings outstanding under this facility, the interest rate applicable to borrowings generally ranges from 30-40 basis points above LIBOR. We are 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 $48 thousand for the three months ended December 31, 2007. 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 62.5%, though there were no material fees for the three months ended December 31, 2007. There were $80.0 million and $147.0 million in outstanding borrowings under the Revolving Credit Facility at December 31, 2007 and September 30, 2007, respectively.

In addition to the Revolving Credit Facility, we had available $123.1 million of unsecured, discretionary lines of credit at December 31, 2007, which expire at the bank’s discretion. There are no requirements for commitment fees or compensating balances in connection with these lines of credit and interest is at prevailing market rates. There was $44.5 million and $24.3 million in outstanding borrowings under these lines of credit at December 31, 2007 and September 30, 2007, respectively.

Management believes that cash flows from operations combined with cash and cash equivalents, the Revolving Credit Facility and other discretionary credit facilities provide us with sufficient capital resources and liquidity to manage our 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, we expect to refinance this debt by arranging additional committed bank facilities or through other long-term borrowing alternatives.

The Senior Notes and Revolving Credit Facility include various customary covenants and other provisions, including the maintenance of certain profitability and solvency ratios, none of which materially restrict our activities. We are currently in compliance with all covenants imposed.

Cash Requirements

We anticipate capital expenditures to be approximately $640 million in fiscal 2008. We spent $161.8 million for capital expenditures during the three months ended December 31, 2007. The fiscal 2008 capital expenditure program consists primarily of capital for facilities, new pressure pumping equipment, new equipment for our Oilfield Services Group, and capital to extend the useful life of existing assets. In 1998, we embarked on a program to replace our aging U.S. fracturing pump fleet with new, more efficient and higher horsepower pressure pumping equipment. We have since expanded the U.S. fleet recapitalization initiative to include additional equipment, such as cementing, nitrogen and acidizing equipment and have made significant progress in adding new equipment. However, much of the older equipment still remains in operation due to the increases in market activity. We plan to continue adding new equipment to our fleet and the market activity level at the time the equipment is ready for use will determine if the new equipment will be used for expansion or used as replacement assets. At the end of fiscal 2007, approximately 20% of our U.S. fleet remained candidates for future replacement as part of our recapitalization initiative. The actual amount of fiscal 2008 capital expenditures will depend primarily on maintenance requirements and expansion opportunities and our ability to execute our budgeted capital expenditures.

In fiscal 2008, our minimum pension and postretirement funding requirements are anticipated to be approximately $19.0 million. We contributed $1.1 million during the three months ended December 31, 2007.

We paid cash dividends in the amount of $.05 per common share on a quarterly basis in fiscal 2007, totaling $58.6 million. We anticipate paying a quarterly dividend in fiscal 2008; however, dividends are subject to approval of our Board of Directors each quarter and the Board has the ability to change the dividend policy at any time. We paid $14.6 million in cash dividends during the three months ended December 31, 2007.

As of December 31, 2007, we had $250.0 million of Senior Notes due June 2008 issued and outstanding and $249.8 million of 5.75% Senior Notes due 2011 issued and outstanding, net of discount (collectively “the Notes”). We intend to redeem the $250.0 million Senior Notes due 2008 with existing cash and if necessary, through funds available from our Revolving Credit Facility. We expect cash paid for net interest expense (net of interest income) to be approximately $26.2 million in fiscal 2008.

On October 1, 2007, we adopted FIN 48, which addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. However, the timing of future cash flows associated with FIN 48 is uncertain and we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authority. Therefore, we excluded unrecognized tax benefits from our contractual obligations table.

We expect that cash and cash equivalents and cash flows from operations will generate sufficient cash flows to fund all of the cash requirements described above.

Investigations Regarding Misappropriation and Possible Illegal Payments

We have had discussions with the DOJ and SEC regarding our internal investigation and certain other matters described in Note 5 of our unaudited consolidated condensed financial statements. It is not possible to accurately predict at this time when any of these matters will be resolved. Based on current information, we cannot predict the outcome of such investigations, whether we will reach resolution through such discussions or what, if any, actions may be taken by the DOJ, SEC or other authorities or the effect the foregoing may have on our consolidated financial statements.

Off Balance Sheet Transactions

In 1999, we contributed certain pumping service equipment to a limited partnership, in which we own a 1% interest. The equipment is used to provide services to our customers for which we pay 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. We assessed the terms of this agreement and determined it was a variable interest entity as defined in FIN 46(R),Consolidation of Variable Interest Entities. However, we were 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 $8.3 million and $9.0 million as of December 31, 2007 and September 30, 2007, respectively. The agreement permits substitution of equipment within the partnership as long as the implied fair value of the new property transferred in at the date of substitution equals or exceeds the implied fair value, as defined, of the current property in the partnership that is being replaced. In September 2010, we have the option, but not the obligation, to purchase the pumping service equipment for approximately $32 million. We currently intend to exercise this option. The option price to purchase the equipment under the partnership depends in part on the fair market value of the equipment held by the partnership at the time the option is exercised as well as other factors specified in the agreement.

Accounting Pronouncements

Recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree

Recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase

Determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.

This statement is effective for fiscal years beginning after December 15, 2008. We are currently in the process of evaluating the impact of SFAS 141(R) on our financial statements.

in the consolidated financial statements that identify and distinguish between the interests of the parent’s owners and the interests of the noncontrolling owners of a subsidiary and shall be applied prospectively as of the beginning of the fiscal year in which initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. SFAS 160 is effective for fiscal years beginning after December 15, 2008. We are currently in the process of evaluating the impact of SFAS 160 on our financial statements.

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 we 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 our financial condition or results of operations. Estimates and assumptions about future events and their effects cannot be predicted with certainty. We base our 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 our operating environment changes. On October 1, 2007 we adopted the provisions of FIN 48. FIN 48 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN48, the tax benefit from an uncertain tax position is to be recognized when it is more likely than not, based on the technical merits of the position, that the position will be sustained on examination by the taxing authorities. Additionally, the amount of the tax benefit to be recognized is the largest amount of benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. There have been no other 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, 2007.

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, our prospects, expected revenue, expenses and profits, developments and business strategies for our operations, all of which are subject to certain risks, uncertainties and assumptions. These forward-looking statements are identified in statements described as “Outlook” and by their use of terms and phrases such as “expect,” “estimate,” “project,” “forecast,” “believe,” “achievable,” “anticipate”, “should” and similar terms and phrases. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe 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, hostilities, and declines in customer activity due to adverse local and regional conditions,

•

our ability to expand our products and services (including those we acquire) 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 internal investigations, including potential financial and business consequences and governmental actions, proceedings, charges or penalties,

•

changes in currency exchange rates,

•

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

•

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

•

competition and consolidation in our business,

•

changes in law or regulations and other factors, many of which are beyond our control, and

•

other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission.

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, we do 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 our Form 10-K for the fiscal year ended September 30, 2007.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Our major market risk exposure is to foreign currency fluctuations internationally and changing interest rates, primarily in the United States, Canada and Europe. Our 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 December 31, 2007 rates, our combined interest expense to third parties would increase by a total of $168 thousand each month in which such increase continued.

Periodically, the Company borrows funds which are denominated in foreign currencies, which exposes the Company to market risk associated with exchange rate movements. Total borrowings denominated in foreign currencies at December 31, 2007 were $43.0 million. When we believe prudent, we enter into forward foreign exchange contracts to hedge the impact of foreign currency fluctuations. There were no such forward foreign exchange contracts outstanding at December 31, 2007.

Item 4.

Controls and Procedures

Evaluation of disclosure controls and procedures. Based on their evaluation of our 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

The information regarding litigation and environmental matters described in Note 5 of the Notes to the Unaudited Consolidated Condensed Financial Statements included elsewhere in this Quarterly Report on Form 10-Q is incorporated herein by reference.

Item 1A.

Risk Factors

There have been no material changes during the period ended December 31, 2007 in our “Risk Factors” as discussed in our Form 10-K for the fiscal year ended September 30, 2007.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

(a)

None

(b)

None

(c)

None

Item 3.

Defaults upon Senior Securities

None

Item 4.

Submission of Matters to a Vote of Security Holders

None

Item 5.

Other Information

None

Item 6.

Exhibits


31.1		Section 302 certification for J. W. Stewart

31.2		Section 302 certification for Jeffrey E. Smith

32.1		Section 906 certification furnished for J. W. Stewart

32.2		Section 906 certification furnished for Jeffrey E. Smith

SIGNATURES

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


	BJ Services Company
		(Registrant)

Date: February 11, 2008	By:	/s/ J. W. Stewart
		J. W. Stewart
		Chairman of the Board, President and Chief Executive Officer

Date: February 11, 2008	By:	/s/ Jeffrey E. Smith
		Jeffrey E. Smith
		Senior Vice President - Finance and Chief Financial Officer

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BJ Services Inactive 10-Q2007 Q4 Quarterly report

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