SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2007

OR

¨ 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 291,620,256 shares of the registrant’s common stock, $.10 par value, outstanding as of August 6, 2007.

BJ SERVICES COMPANY

INDEX

PART I -   FINANCIAL INFORMATION:
Item 1. Financial Statements
	Consolidated Condensed Statement of Operations (Unaudited) – Three and Nine months ended June 30, 2007 and 2006	3
	Consolidated Condensed Statement of Financial Position (Unaudited) - June 30, 2007 and September 30, 2006	4
	Consolidated Statement of Stockholders’ Equity and Other Comprehensive Income (Unaudited) – Nine months ended June 30, 2007	5
	Consolidated Condensed Statement of Cash Flows (Unaudited) - Nine months ended June 30, 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		32
Item 4. Controls and Procedures		32
PART II - OTHER INFORMATION
Item 1. Legal Proceedings		33
Item 1A. Risk Factors		33
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		33
Item 3. Defaults upon Senior Securities		33
Item 4. Submission of Matters to a Vote of Security Holders		33
Item 5. Other Information		33
Item 6. Exhibits		34

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PART I

FINANCIAL INFORMATION

Item 1. Financial Statements

BJ SERVICES COMPANY

CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS (UNAUDITED)

(In thousands, except per share amounts)

	Three Months Ended June 30,						Nine Months Ended June 30,
	2007			2006			2007			2006
Revenue	$	1,152,518		$	1,116,906		$	3,523,096		$	3,151,885
Operating expenses:
Cost of sales and services		812,701			734,717			2,421,997			2,096,339
Research and engineering		17,146			16,665			49,004			47,392
Marketing		27,450			25,571			79,338			75,118
General and administrative		35,630			32,310			106,471			98,657
Loss on disposal of assets		1,764			764			1,946			2,620
Total operating expenses		894,691			810,027			2,658,756			2,320,126
Operating income		257,827			306,879			864,340			831,759
Interest expense		(8,994	)		(2,506	)		(26,261	)		(2,796	)
Interest income		581			3,456			1,405			10,347
Other income (expense)—net		(1,806	)		194			(5,679	)		398
Income before income taxes		247,608			308,023			833,805			839,708
Income tax expense		79,318			95,143			269,515			263,687
Net income	$	168,290		$	212,880		$	564,290		$	576,021
Earnings per share:
Basic	$	.57		$	.67		$	1.93		$	1.80
Diluted	$	.57		$	.67		$	1.90		$	1.77
Weighted average shares outstanding:
Basic		293,142			315,705			293,137			320,881
Diluted		296,407			319,502			296,383			324,765

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

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BJ SERVICES COMPANY

CONSOLIDATED CONDENSED STATEMENT OF FINANCIAL POSITION

(UNAUDITED)

(In thousands)

	June 30, 2007		September 30, 2006
ASSETS
Current assets:
Cash and cash equivalents	$	65,271	$	92,445
Receivables—net		910,367		927,027
Inventories—net:
Products		209,353		185,249
Work in process		36,256		27,308
Parts		218,972		143,347
Total inventories		464,581		355,904
Deferred income taxes		11,620		5,103
Prepaid expenses		89,600		36,311
Other current assets		50,254		42,070
Total current assets		1,591,693		1,458,860
Property—net		1,813,648		1,392,926
Deferred income taxes		25,890		29,557
Goodwill		963,933		928,297
Other assets		47,390		52,648
	$	4,442,554	$	3,862,288
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	462,281	$	435,040
Short-term borrowings		207,309		160,274
Current portion of long-term debt		250,000		—
Accrued employee compensation and benefits		104,831		131,725
Income and other taxes		75,894		85,872
Accrued insurance		27,324		21,965
Other accrued liabilities		120,921		113,060
Total current liabilities		1,248,560		947,936
Commitments and contingencies (Note 5)
Long-term debt		249,743		499,694
Deferred income taxes		84,762		66,584
Other long-term liabilities		204,451		201,134
Stockholders’ equity		2,655,038		2,146,940
	$	4,442,554	$	3,862,288

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

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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			Retained Earnings			Accumulated Other Comprehensive Income			Total
Balance, September 30, 2006	293,194		$	34,752	$	1,028,813		$	(1,433,808	)	$	2,494,350		$	22,833		$	2,146,940
Comprehensive income:
Net income												207,084
Other comprehensive income, net of tax:
Cumulative translation adjustments															(10,693	)
Comprehensive income																		196,391
Re-issuance of treasury stock for:
Stock options	149								3,952			(1,869	)					2,083
Stock purchase plan	488								12,916			(406	)					12,510
Director stock awards	43					(1,127	)		1,127									—
Stock based compensation						9,184												9,184
Tax benefit from exercise of options						471												471
Purchase of treasury stock	(669	)							(20,006	)								(20,006	)
Dividends declared												(13,472	)					(13,472	)
Balance, December 31, 2006	293,205		$	34,752	$	1,037,341		$	(1,435,819	)	$	2,685,687		$	12,140		$	2,334,101
Comprehensive income:
Net income												188,916
Other comprehensive income, net of tax:
Cumulative translation adjustments															2,150
Comprehensive income																		191,066
Re-issuance of treasury stock for:
Stock options	71								1,863			(797	)					1,066
Stock based compensation						8,529												8,529
Tax benefit from exercise of options						38												38
Dividends declared												(14,660	)					(14,660	)
Balance, March 31, 2007	293,276		$	34,752	$	1,045,908		$	(1,433,956	)	$	2,859,146		$	14,290		$	2,520,140
Comprehensive income:
Net income												168,290
Other comprehensive income, net of tax:
Cumulative translation adjustments															23,577
Comprehensive income																		191,867
Re-issuance of treasury stock for:
Bonus stock awards	28					(731	)		731									—
Stock options	156								4,114			(1,770	)					2,344
Stock based compensation						8,692												8,692
Tax benefit from exercise of options						1,232												1,232
Purchase of treasury stock	(1,896	)							(54,591	)								(54,591	)
Dividends declared												(14,646	)					(14,646	)
Balance, June 30, 2007	291,564		$	34,752	$	1,055,101		$	(1,483,702	)	$	3,011,020		$	37,867		$	2,655,038

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

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BJ SERVICES COMPANY

CONSOLIDATED CONDENSED STATEMENT OF CASH FLOWS (UNAUDITED)

(In thousands)

	Nine Months Ended June 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	564,290		$	576,021
Adjustments to reconcile net income to cash provided by operating activities:
Minority interest		7,562			1,765
Loss on disposal of assets		1,946			2,620
Depreciation and amortization		151,105			120,492
Excess tax benefits from stock based compensation		(1,441	)		(3,382	)
Deferred income taxes		11,987			(1,139	)
Changes in:
Receivables		20,511			(154,770	)
Inventories		(106,980	)		(75,760	)
Prepaid expenses		(53,381	)		(18,542	)
Other current assets		(1,918	)		(15,186	)
Accounts payable		29,635			65,638
Accrued employee compensation and benefits		(26,894	)		8,093
Current income tax		(16,341	)		41,201
Other current liabilities		17,597			34,378
Other—net		19,825			22,060
Net cash provided by operating activities		617,503			603,489
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(546,505	)		(323,249	)
Proceeds from disposal of assets		8,415			6,431
Acquisitions of businesses, net of cash received		(55,373	)		9,232
Net cash used in investing activities		(593,463	)		(307,586	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from short-term borrowings, net		47,035			100,257
Proceeds from long-term borrowings		—			499,673
Debt issuance costs		—			(2,179	)
Repayments of long-term borrowings		—			(79,000	)
Dividends paid to shareholders		(43,990	)		(48,415	)
Purchase of treasury stock		(74,597	)		(768,525	)
Excess tax benefits from stock based compensation		1,441			3,382
Proceeds from exercise of stock options and stock purchase plan		19,037			25,052
Net cash used in financing activities		(51,074	)		(269,755	)
Effect of exchange rate changes on cash		(140	)		211
(Decrease)/increase in cash and cash equivalents		(27,174	)		26,359
Cash and cash equivalents at beginning of period		92,445			356,508
Cash and cash equivalents at end of period	$	65,271		$	382,867
Cash Paid for Interest and Taxes:
Interest	$	38,436		$	370
Taxes		305,398			220,400

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

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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 June 30, 2007, and our results of operations for the three and nine-month periods ended June 30, 2007 and 2006 and cash flows for the nine-month periods ended June 30, 2007 and 2006. The consolidated condensed statement of financial position at September 30, 2006 is derived from the September 30, 2006 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 for the three and nine-month periods ended June 30, 2007 and cash flows for the nine-month periods ended June 30, 2007 are not necessarily indicative of the results to be expected for the full year.

Certain amounts for fiscal 2006 have been reclassified in the accompanying consolidated condensed financial statements to conform to the current year presentation. Such reclassifications do not affect our results of operations.

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 June 30,				Nine Months Ended June 30,
	2007		2006		2007		2006
Net income	$	168,290	$	212,880	$	564,290	$	576,021
Weighted-average common shares outstanding		293,142		315,705		293,137		320,881
Basic earnings per share	$	.57	$	.67	$	1.93	$	1.80

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	Three Months Ended June 30,				Nine Months Ended June 30,
	2007		2006		2007		2006
Weighted-average common and dilutive potential common shares outstanding:
Weighted-average common shares outstanding		293,142		315,705		293,137		320,881
Assumed exercise of stock based compensation(1)		3,265		3,797		3,246		3,884
		296,407		319,502		296,383		324,765
Diluted earnings per share	$	.57	$	.67	$	1.90	$	1.77

⁽¹⁾ For the three and nine months ended June 30, 2007, 3.1 million and 2.9 million stock options, respectively, were excluded from the computation of diluted earnings per share due to their antidilutive effect. There were no stock options excluded from the computation of diluted earnings per share due to their antidilutive effect for the three and nine months ended June 30, 2006.

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.

U.S./Mexico Pressure Pumping 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 similar types of services, have similar economic characteristics, have similar production processes and use the same methods to provide their services.

Canada Pressure Pumping 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.

International Pressure Pumping has five operating segments. Similar to U.S./Mexico 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. The operating segments have been aggregated into one reportable segment because they have similar economic characteristics, offer similar types 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 Group 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, serve same or similar customers and some of the operating segments share resources.

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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, 2006. 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 June 30, 2007
Revenue	$	646,719	$	35,169		$	277,314	$	193,316	$	—		$	1,152,518
Operating income (loss)		215,449		(21,610	)		42,643		41,800		(20,455	)		257,827
Three Months Ended June 30, 2006
Revenue	$	644,070	$	66,939		$	233,735	$	172,162	$	—		$	1,116,906
Operating income (loss)		260,618		(2,203	)		38,153		39,389		(29,078	)		306,879
Nine Months Ended June 30, 2007
Revenue	$	1,920,901	$	268,709		$	779,741	$	553,745	$	—		$	3,523,096
Operating income (loss)		688,346		10,607			112,066		111,172		(57,851	)		864,340
Identifiable assets		1,379,294		467,681			1,262,324		853,168		480,087			4,442,554
Nine Months Ended June 30, 2006
Revenue	$	1,708,260	$	342,954		$	629,337	$	471,334	$	—		$	3,151,885
Operating income (loss)		651,466		69,199			91,218		96,464		(76,588	)		831,759
Identifiable assets		1,223,528		409,919			945,041		627,342		720,439			3,926,269

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

	Three Months Ended June 30,						Nine Months Ended June 30,
	2007			2006			2007			2006
Total operating income for reportable segments	$	257,827		$	306,879		$	864,340		$	831,759
Interest expense		(8,994	)		(2,506	)		(26,261	)		(2,796	)
Interest income		581			3,456			1,405			10,347
Other income (expense) – net		(1,806	)		194			(5,679	)		398
Income before income taxes	$	247,608		$	308,023		$	833,805		$	839,708

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 $11.0 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 production chemical services operation in the Oilfield Services Group.

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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 $28.4 million, including legal fees, which resulted in $21.2 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.

On November 3, 2006, we completed the acquisition of Profile International Ltd. ("Profile") for a total purchase price of $2.4 million, which resulted in $2.1 million of goodwill. Profile, located in Newcastle, England, provides caliper inspection tools for pipeline integrity assessment to markets worldwide. This business complements our pipeline inspection business in the Oilfield Services Group.

On December 20, 2006, we purchased substantially all of the operating assets of Tekcor Technology, Ltd. ("Tekcor") for $8.3 million, which resulted in an increase of $4.5 million to total current assets and $3.8 million to technology based intangible assets. Tekcor provides specialty chemicals and related services to the oil and gas well drilling industry. Located in Houston, Texas, Tekcor services markets along the Texas and Louisiana Gulf Coast and is included in our completion fluids business in the Oilfield Services Group.

We have completed our purchase price allocation for the Profile and Tekcor acquisitions. However, we are still in the process of completing our review and determination of the fair values of the assets acquired from Allis-Chalmers and Norson. 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 bodily injuries 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

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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. Based on the Fifth Circuit’s opinion, we believe that over half of the judgment against OSCA is covered by an insurance policy issued by AISLIC (an AIG affiliate). 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. Even if the interpretation of this exclusion is resolved in a manner that is adverse to OSCA, approximately 50% of the judgment against OSCA has already been paid by AISLIC. 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 $5.4 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

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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.

Gene Ellison et al v FPC Disposal et al

On December 12, 2000, Gene and Marcia Ellison filed a lawsuit in State District Court of Canadian County, Oklahoma against us and about 120 other defendants, including Western and FPC Disposal, Inc., which owns and operates a commercial facility for the disposal of oil/gas well drilling fluids, cuttings and salt water located one-half mile from property owned by the Ellisons on which they conduct farming and ranching activities in Canadian County, Oklahoma. In their original Complaint, the Ellisons alleged that both we and Western sent flow-back water to the well for disposal and that the disposal activities polluted their water and therefore their property. In the original Complaint, the Ellisons sought actual and punitive damages in excess of $10 thousand for property damage, personal annoyance and endangerment of their comfort, health, tranquility and safety.

In April 2002, we filed a Motion for Summary Judgment, which was granted by the State District Court. The Plaintiffs appealed the motion for summary judgment. The Oklahoma Appeals Court reversed the Trial Court’s decision. We ultimately filed a Petition for Writ of Certiorari that was denied by the Oklahoma Supreme Court. The lawsuit was sent back to the trial court and the case proceeded. In late September 2006, the Plaintiffs quantified their actual damages in excess of $500 million, claiming under theories of remediation, unjust enrichment and lost profits. In addition, the Plaintiffs sought punitive damages against us of up to $51.8 million.

This case was settled in the first quarter of fiscal 2007, and our contribution to the settlement was not material.

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 $3.3 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, 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 $13.4 million and $16.1 million as of June 30, 2007 and September 30, 2006, respectively. The agreement permits substitution of

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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 have the intent 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.

In 1997, we contributed certain pumping service equipment to a limited partnership, in which we owned a 1% interest. The equipment was used to provide services to our customers for which we paid a service fee. On February 9, 2007, we purchased the remaining partnership interest for $47.8 million, and as a result acquired the partnership equipment. The acquisition of the partnership controlling interest was accounted for as an asset purchase.

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 June 30, 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	$	54,306	$	51,093	$	3,213	$	—	$	—
Guarantees		161,143		76,208		47,133		22,711		15,091
Total Other Commercial Commitments	$	215,449	$	127,301	$	50,346	$	22,711	$	15,091

Note 6 Supplemental Financial Information

Other income (expense), net is summarized as follows (in thousands):

	Three Months Ended June 30,						Nine Months Ended June 30,
	2007			2006			2007			2006
Minority interest	$	(2,633	)	$	(393	)	$	(7,562	)	$	(1,765	)
Non-operating net foreign exchange loss		(140	)		(647	)		(404	)		(1,357	)
Recovery of misappropriated funds		—			—			—			2,790
Other, net		967			1,234			2,287			730
Other income (expense), net	$	(1,806	)	$	194		$	(5,679	)	$	398

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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. 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. 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 $9.0 million originally identified. The Company has identified an additional $1.7 million that it believes was misappropriated by the former Region Controller. The additional $1.7 million of likely misappropriations were expenses of the Company that were recorded in the Consolidated Statement of Operations in periods prior to April 2002. 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. The Company recently 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, the Company 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 the Company to an entity in the Asia Pacific Region with which the Company has certain contractual relationships, were then used to make payments to government officials in the Asia Pacific Region. This information included information indicating that certain employees of the Company 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, the Company 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. The $2.8 million payment represents a gain contingency and was reflected in Other Income in the Consolidated Condensed Statement of Operations for the quarter ended December 31, 2005 in accordance with SFAS 5, Accounting for Contingencies.

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

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The Company and the Audit Committee also investigated a large volume of other payments made by the Company 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 the Company believes that no additional expense is required to be recorded for such payments.

The Company has voluntarily disclosed information found in the special Audit Committee investigation, as well as related information from the Company’s theft investigation, to the U.S. Department of Justice (“DOJ”) and U.S. Securities and Exchange Commission (“SEC”) and is engaged in ongoing discussions with these authorities as they review the matter. The Company 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 the Company 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. The Company has voluntarily disclosed information found in the investigation to the DOJ and SEC and is engaged in ongoing 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. The Company entered into a consent decree with the SEC in 2004 following an investigation into improper payments in Argentina.

We are in 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, the Company implemented policy changes worldwide for disbursements. Significant personnel changes were also made in the Asia Pacific Region. The Company has assigned a new Region Manager and a new Region Controller, an Assistant Controller and replaced several accountants in the Asia Pacific region. The Company also took further disciplinary action against personnel in the Region. In addition, we have 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.

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Note 7 Employee Benefit Plans

We have a U.S. Defined Benefit Plan, Foreign Defined 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 our annual report on Form 10-K for the fiscal year ended September 30, 2006. 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

	Non-U.S.
	Three months ended June 30,						Nine months ended June 30,
	2007			2006			2007			2006
Service cost for benefits earned	$	1,604		$	1,269		$	4,812		$	3,807
Interest cost on projected benefit obligation		2,507			2,114			7,521			6,342
Expected return on plan assets		(2,341	)		(2,029	)		(7,023	)		(6,087	)
Recognized actuarial loss		760			543			2,280			1,629
Net amortization and deferral		(349	)		31			(1,047	)		93
Net pension cost	$	2,181		$	1,928		$	6,543		$	5,784

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 will be 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 early fiscal 2008, we will expense approximately $23.3 million of prepaid pension cost. As a result of these actions, we have reclassified the pension asset and recorded the payment for the annuity as current assets.

In fiscal 2007, we will have a minimum pension funding requirement of $8.1 million for the Non-U.S. defined benefit plans. In addition to the minimum pension funding requirement, we intend to contribute $7.6 million in discretionary contributions for our defined benefit plans. We have paid $2.2 million in discretionary contributions and $6.5 million in non-discretionary contributions during the nine months ended June 30, 2007. These contributions have been and are expected to be funded by cash flows from operating activities.

Postretirement Benefit Plan

	Three Months Ended June 30,				Nine Months Ended June 30,
	2007		2006		2007		2006
Service cost for benefits attributed to service during the period	$	993	$	867	$	2,979	$	2,601
Interest cost on accumulated postretirement benefit obligation		825		717		2,475		2,151
Net periodic postretirement benefit cost	$	1,818	$	1,584	$	5,454	$	4,752

We expect to contribute $1.3 million to the post retirement plan in fiscal 2007, which represents the anticipated claims. We have made $0.5 million in post retirement contributions during the nine months ended June 30, 2007.

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Note 8 New Accounting Standards

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. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R) (“SFAS 158”). This will require companies to recognize the over funded or under funded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in our statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. It also requires companies to measure the funded status of a plan as of the date of its year-end statement of financial position. Additionally, companies will need to:

a. Recognize the funded status of a benefit plan (measured as the difference between plan assets at fair value (with limited exceptions) and the benefit obligation) in our statement of financial position. For a pension plan, the benefit obligation is the projected benefit obligation; for any other postretirement benefit plan, such as a retiree health care plan, the benefit obligation is the accumulated postretirement benefit obligation.

b. Recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost.

c. Measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position.

d. Disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition asset or obligation.

Recognition of an asset or liability related to the funded status of a pension plan and disclosures are effective for fiscal years ending after December 15, 2006. We currently measure our defined benefit plan assets and obligations as of our fiscal year-end. Thus, this portion of SFAS 158 will not impact our financial statements. We are currently in the process of evaluating the impact on our financial statements from the other requirements of SFAS 158.

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.

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In July 2006, the FASB issued Interpretation No. 48 (“FIN 48”), Accounting for Uncertainty in Income Taxes, effective for fiscal years beginning after December 15, 2006. FIN 48 prescribes a recognition threshold and measurement attribute, as well as criteria for subsequently recognizing, derecognizing and measuring tax positions for financial statement purposes and requires companies to make disclosures about uncertain income tax positions, including a detailed roll forward of tax benefits taken that do not qualify for financial statement recognition. We are currently in the process of evaluating the impact of FIN 48 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 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 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, 2006 for more information on these operations.

The Oilfield Services Group consists of production chemical services, casing and tubular services, process and pipeline services, 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 work over activity. Drilling activity, in turn, is largely dependent on the price of crude oil and natural gas as well as storage levels of 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:

	Three Months Ended June 30,						Nine Months Ended June 30,
	2007		% Change		2006		2007		% Change		2006
Rig Count: (1)
U.S.		1,756	8	%		1,632		1,736	13	%		1,543
Canada		139	-50	%		277		370	-27	%		505
International(2)		1,003	10	%		913		979	10	%		893
Commodity Prices (average):
Crude Oil (West Texas Intermediate)	$	64.96	-8	%	$	70.47	$	60.99	-6	%	$	64.61
Natural Gas (Henry Hub)	$	7.53	15	%	$	6.54	$	7.14	-19	%	$	8.86

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

(2) Includes Mexico average rig count of 88 and 85 for the three-month periods ended June 30, 2007 and 2006, respectively, and 87 and 88 for the nine-month periods ended June 30, 2007 and 2006, respectively.

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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 1,587 in fiscal 2006. Based on the first three quarters of fiscal year 2007, the U.S. annual average rig count for fiscal year 2007 is expected to exceed the prior year average.

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. Based on the first three quarters of fiscal year 2007, the Canada annual average rig count for fiscal year 2007 is expected to be lower than the prior year average.

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, excluding Canada, averaged 616 in fiscal 1999 and the highest annual international rig count averaged 905 in fiscal 2006. Based on the first three quarters of fiscal year 2007, the international annual average rig count excluding Canada for fiscal year 2007 is expected to be higher than the prior year average.

Results of Operations

Consolidated

	Three Months Ended June 30,						Nine Months Ended June 30,
Consolidated (in millions)	2007		% Change		2006		2007		% Change		2006
Revenue	$	1,152.5	3	%	$	1,116.9	$	3,523.1	12	%	$	3,151.9
Operating income	$	257.8	-16	%	$	306.9	$	864.3	4	%	$	831.8
Worldwide rig count(1)		2,898	3	%		2,822		3,085	5	%		2,941

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

Results for the three-month periods ended June 30, 2007 and 2006

Consolidated revenue for the period increased as the result of increased market activity and growth in International Pressure Pumping and the Oilfield Services Group. International Pressure Pumping revenues increased 19% in the third quarter of fiscal 2007 compared to the same period in the prior year, while revenue from the Oilfield Services Group increased 12%. The increases provided by these segments were almost entirely offset by a 47% decline in revenue from Canada Pressure Pumping, caused by depressed market conditions.

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While revenue for the three months ended June 30, 2007 increased, consolidated operating income for the period decreased primarily as the result of U.S. pricing pressures and the depressed market conditions in Canada. Both our Canadian pressure pumping and process and pipeline operations had declines in operating income as a result of the market, which exhibited lower activity levels and lower prices that our customers were willing to pay for products and services. For the three months ended June 30, 2007, consolidated operating income margins decreased to 22% from 27% reported in the same period of the prior fiscal year.

Results for the nine-month periods ended June 30, 2007 and 2006

All of our reportable segments, except Canada, experienced an increase in revenue for the nine months ended June 30, 2007 when compared to the same period in the prior fiscal year. The increase primarily relates to higher activity in all major markets except Canada. Worldwide average active drilling rigs for fiscal 2007 year to date increased 5% compared to the same period in the prior year.

Consolidated operating income for the nine-months ended June 30, 2007 increased 4% compared to the same period in fiscal 2006 but was negatively impacted by a 85% decline in operating income from Canada. The fiscal 2007 year to date operating income margin was 25% compared to 26% in fiscal 2006.

U.S./Mexico Pressure Pumping

	Three Months Ended June 30,						Nine Months Ended June 30,
U.S./Mexico	2007		% Change		2006		2007		% Change		2006
Pressure Pumping (in millions)
Revenue	$	646.7	0	%	$	644.1	$	1,920.9	12	%	$	1,708.3
Operating income		215.4	-17	%		260.6		688.3	6	%		651.5
U.S. rig count(1)		1,756	8	%		1,632		1,736	13	%		1,543
Mexico rig count(1)		88	4	%		85		87	-1	%		88

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

Results for the three-month periods ended June 30, 2007 and 2006

U.S./Mexico revenue for the third quarter of fiscal 2007 was consistent with fiscal 2006 third quarter revenue. Revenue contributions from the Northeast and Mexico were offset by declines in revenue in the Pacific. Revenue from Mexico operations increased 42% as the result of expansion into the southern region of the country. Revenue improvement from increased U.S. activity levels were offset by declines in pricing as a result of competitive pressures.

Operating income margin decreased from 40% in the third quarter of fiscal 2006 to 33% during the third quarter of fiscal 2007, due to declines in U.S. pricing, increased material and labor costs, and higher depreciation expense.

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Results for the nine-month periods ended June 30, 2007 and 2006

U.S./Mexico revenue fiscal 2007 year to date increased compared to the same period in the prior year as the result of activity increases most notably in East Texas and the Permian Basin. The Mexico region also benefited from improved revenues attributable to the expansion of our business in southern Mexico. These increases were slightly offset by a decline in activity in the Pacific. The U.S./Mexico average active drilling rigs increased 13% for the nine months ended June 30, 2007. Revenue was also negatively impacted by pricing declines.

Operating income margin declined to 36% for the nine months ended June 30, 2007 compared to 38% for the same period in the prior fiscal year, primarily due to increased material and labor costs and increased depreciation expense.

Canada Pressure Pumping

	Three Months Ended June 30,								Nine Months Ended June 30,
Canada	2007			% Change		2006			2007		% Change		2006
Pressure Pumping (in millions)
Revenue	$	35.2		-47	%	$	66.9		$	268.7	-22	%	$	343.0
Operating income		(21.6	)	-882	%		(2.2	)		10.6	-85	%		69.2
Canadian rig count(1)		139		-50	%		277			370	-27	%		505

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

Results for the three-month periods ended June 30, 2007 and 2006

Lower activity levels influenced by lower natural gas prices and a longer Spring break up period in the Canadian market caused revenue for the three month period ended June 30, 2007 to decline compared to the same period in prior year. Spring break up is a period during which heavy drilling and other equipment is not permitted to travel on the roads. Average active drilling rigs decreased 50% for the third quarter of fiscal 2007 compared to the same periods in the prior year, with revenue exhibiting a corresponding decrease of 47%. The region has also experienced lower pricing for our products and services.

Operating income margin decreased to -61% for the three months ended June 30, 2007, from -3% during the same period in the prior year. Along with declining prices for our products and services, the region also had increased depreciation expense, material costs and labor costs in the third fiscal 2007 quarter compared to the same quarter of fiscal 2006.

Results for the nine-month periods ended June 30, 2007 and 2006

As with the three-months ended June 30, 2007, depressed market conditions in Canada have caused the revenue from this region to decrease. Both activity levels and pricing are lower in this region for the nine-months ended June 30, 2007 when compared to the same period in the prior year. In addition, operating income margin has declined from 20% for the nine months ended June 30, 2006 to 4% for the nine months ended June 30, 2007.

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International Pressure Pumping

	Three Months Ended June 30,						Nine Months Ended June 30,
International	2007		% Change		2006		2007		% Change		2006
Pressure Pumping (in millions)
Revenue	$	277.3	19	%	$	233.7	$	779.7	24	%	$	629.3
Operating income		42.6	12	%		38.2		112.1	23	%		91.2
International rig count, Excluding Mexico(1)		915	11	%		828		891	11	%		806

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

Results for the three-month periods ended June 30, 2007 and 2006

The following table summarizes the percentage change in revenue for each of the operating segments of International Pressure Pumping:

	% change in Revenue
Europe/Africa	36	%
Middle East	22	%
Asia Pacific	31	%
Russia	-29	%
Latin America	11	%

The revenue improvement in Europe/Africa was largely due to the acquisition of a controlling interest in our Algerian joint venture, (“BJSP”) in June 2006. Excluding BJSP, revenue for Europe/Africa increased 14%, benefiting from double digit revenue growth from most markets within the region as a result of increased activity. In addition, the region benefited from increased activity levels in the U.K. and expansion into Libya. Average active drilling rigs in Europe/Africa increased 7% during the three months ended June 30, 2007 compared to the same period in the prior fiscal year. These activity related increases were reduced somewhat by revenue declines in Norway due to the loss of a contract. Also, during the third quarter of fiscal 2007, we began to mobilize our vessel, the Vestfonn, to India, where it is expected to begin operations during the fourth quarter of fiscal 2007.

Revenue from the Middle East increased 22%, while average active drilling rigs increased 11% in the region. Revenue increases due to a large product sale in India and increased coil tubing activity in Saudi Arabia were slightly offset by lower revenue in Kazakhstan due to project delays.

In our Asia Pacific region revenue increased due to new contracts in Malaysia and activity increases in Australia and Indonesia. These increases were slightly offset by a decline in revenue in New Zealand due to non-repeat work in the prior year.

Our Latin American revenue increased largely due to an increase in fracturing activity in Brazil and Argentina and increased coil tubing work in Colombia. The average active drilling rig count in the region increased 9% during the third quarter of fiscal 2007 compared to the third quarter of fiscal 2006.

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Russian revenue declined for the three months ended June 30, 2007 compared to the same period in the prior fiscal year due to the sale of our workover rig business in the region in April 2007.

Operating income margins from our International Pressure Pumping operations decreased from 16% in the third quarter of fiscal 2006 to 15%, with Europe/Africa and Russia as the primary contributors to the lower operating income margin.

Results for the nine-month periods ended June 30, 2007 and 2006

The following table summarizes the percentage change in revenue for each of the operating segments of International Pressure Pumping:

	% change in Revenue
Europe/Africa	42	%
Middle East	20	%
Asia Pacific	27	%
Russia	-3	%
Latin America	19	%

All of our operating regions within International Pressure Pumping, except Russia, showed significant increases in revenue during the nine months ended June 30, 2007 compared to the same period in the prior year.

Europe/Africa showed improvement as the result of the BJSP acquisition, activity related revenue increases in the U.K and Netherlands, and expansion of operations into Libya. These increases were slightly offset by revenue declines in Norway due to the loss of a contract. The average active drilling rig count for the nine months ended increased 9% compared to the same period in the prior fiscal year. Excluding BJSP, revenue in the region increased 19%.

Despite a significant decline in revenue from the prior year’s non-repeat blowout work in Bangladesh, the Middle East showed improved revenues due to increased activity in India and increased coil tubing work in Saudi Arabia. The average active drilling rig count for the nine months ended increased 15% compared to the same period in the prior fiscal year.

The award of contracts in Malaysia and activity increases in Australia accounted for most of Asia Pacific’s revenue increase. This increase was offset by a decline in revenue from New Zealand due to non-repeat work in the prior fiscal year.

Our Latin American region had increased activity in Argentina, Colombia, and Brazil. The average active drilling rig count increased 11% in Latin America compared to the same period in the prior year. Our Russian revenue declined as the result of the divesture of our workover rig business in the region as well as decreased activity.

Operating income margin remained consistent at 14% during the nine months ended June 30, 2007 compared to the same period in the prior year. Margin contributions from the Asia Pacific and Latin America were offset by margin declines from the high margin non-repeat blowout work in Bangladesh in the prior fiscal year and declines in Norway activity.

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Oilfield Services Group

	Three Months Ended June 30,						Nine Months Ended June 30,
Oilfield Services Group (in millions)	2007		% Change		2006		2007		% Change		2006
Revenue	$	193.3	12	%	$	172.2	$	553.7	17	%	$	471.3
Operating income		41.8	6	%		39.4		111.2	15	%		96.5

Results for the three-month periods ended June 30, 2007 and 2006

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

	% Change in Revenue
Tubular Services	24	%
Process & Pipeline Services	5	%
Chemical Services	32	%
Completion Tools	54	%
Completion Fluids	-19	%

All of the Oilfield Services Group, except Completion Fluids, showed revenue improvement for the three months ended June 30, 2007 when compared to the same period in the prior fiscal year with Completion Tools and Chemical services being the major contributors. Improved revenue from Completion Tools was the result of increased deepwater activity in the U.S. and higher sand screen sales. Chemical Services, in turn, benefited from the acquisition of Dyna-Coil in the fourth quarter of fiscal 2006, which specializes in capillary injection systems and associated products. Excluding Dyna-Coil, Chemical Services revenue increased 5%. Our Process and Pipeline Services revenue improved primarily due to the acquisition of Norson Service Ltd during the second quarter of fiscal 2007, which provides subsea and pipeline commissioning and umbilical testing services. Excluding Norson, Process and Pipeline Services revenue decreased 2%, as it was impacted by lower Canadian market conditions. Our Tubular Services operations showed revenue improvement from international market expansion, while revenue from our Completion Fluids operations was lower due to lower domestic deepwater work in the current period as well as the closing of operations in the U.K. and Norway in the previous year.

Operating income margin for the Oilfield Services Group for the third quarter of fiscal 2007 was 22% compared to 23% in third quarter of fiscal 2006. The decline primarily relates to the lower levels of revenue from our Completion Fluids operations.

Results for the nine-month periods ended June 30, 2007 and 2006

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

	% Change in Revenue
Tubular Services	35	%
Process & Pipeline Services	9	%
Chemical Services	42	%
Completion Tools	29	%
Completion Fluids	-3	%

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As with the three months ended June 30, 2007, all of our operating segments, except Completion Fluids, showed revenue improvement for year to date fiscal 2007. Our Chemical Services and Tubular Services were the largest contributors to the revenue increase for the nine months ended June 30, 2007. Excluding the Dyna Coil acquisition, revenue for Chemical Services increased 15%, due to activity increases in the U.S. Our Tubular Services’ revenue for fiscal 2007 year to date increased largely due to international market expansion. Our Completion Tools revenue improvements was due to international growth as well as increased domestic deepwater activity, while revenue from our Completion Fluids operations declined for the same reasons stated for the three months ended June 30, 2007.

Fiscal 2007 year to date operating income margin for the Oilfield Services Group was 20%, consistent with the operating income margin reported in the first nine months of fiscal year 2006.

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 fourth quarter of fiscal 2007, we expect revenue from our U.S./Mexico Pressure Pumping operations to be flat to slightly down compared to our third quarter fiscal 2007 results due to continued pricing pressures in the U.S. Our Canadian Pressure Pumping operations are expected to improve as drilling activity improves from the third quarter Spring break up levels. We expect our International Pressure Pumping segment to increase modestly and our Oilfield Services Group is projected to achieve double digit revenue growth in the fourth quarter of fiscal 2007 compared to the third quarter of fiscal 2007.

Other Expenses

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

	Three Months Ended June 30,				Nine Months Ended June 30,
	2007		2006		2007		2006
Research and engineering	$	17,146	$	16,665	$	49,004	$	47,392
Marketing expense		27,450		25,571		79,338		75,118
General and administrative expense		35,630		32,310		106,471		98,657

Three-month period ended June 30, 2007

Research and engineering expense: While research and engineering expense has increased for the three months ended June 30, 2007 compared to the same period in the prior fiscal year, as a percentage of revenue this expense has remained consistent.

Marketing expense: Fiscal year 2007 third quarter marketing expense increased primarily due to activity related increases in commissions in certain markets internationally as well as increased headcount to support market growth.

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General and administrative expense: General and administrative expense increased for the three months ended June 30, 2007 compared to the same periods in the prior fiscal year, primarily as the result of the consolidation of expense from our investment in BJSP, of which we acquired controlling interest in June 2006. The increase also relates to increased stock based compensation expense, offset by decreased compensation expense related to incentive accruals.

Nine-month period ended June 30, 2007

Research and engineering, marketing, and general and administrative expense: These expenses have increased for the nine months ended June 30, 2007, mostly as the result of increased headcount offset by lower incentive related compensation expense. However, as a percentage of revenue each of these expense categories have decreased.

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

	Three Months Ended June 30,						Nine Months Ended June 30,
	2007			2006			2007			2006
Interest expense	$	(8,994	)	$	(2,506	)	$	(26,261	)	$	(2,796	)
Interest income		581			3,456			1,405			10,347
Other income (expense) – net		(1,806	)		194			(5,679	)		398

Interest Expense and Interest Income: Interest expense increased $6.5 million and $23.5 million for the three and nine months ended June 30, 2007, respectively, compared to the same periods in the prior fiscal year as the result of higher average outstanding debt during the respective periods. In June 2006, we completed a public offering of $500.0 million aggregate principal amount of Senior Notes and at June 30, 2007 our debt balance was $707.1 million compared to $603.3 million at June 30, 2006. Interest income decreased $2.9 million and $8.9 million for the three and nine months ended June 30, 2007, respectively, compared to the same period in the prior fiscal year as a result of lower cash and cash equivalents. We expect fiscal year 2007 interest expense, net of interest income, to be approximately $35 million.

Other Income, net: Other income (expense), net is summarized as follows (in thousands):

	Three Months Ended June 30,						Nine Months Ended June 30,
	2007			2006			2007			2006
Minority interest	$	(2,633	)	$	(393	)	$	(7,562	)	$	(1,765	)
Non-operating net foreign exchange loss		(140	)		(647	)		(404	)		(1,357	)
Recovery of misappropriated funds		—			—			—			2,790
Other, net		967			1,234			2,287			730
Other income (expense), net	$	(1,806	)	$	194		$	(5,679	)	$	398

The increase in other income (expense), net for the three and nine months ended June 30, 2007 was primarily caused by an increase in minority interest expense, due to the acquisition of controlling interest in BJSP during the third quarter of fiscal 2006. Other income in the nine months ended June 30, 2006 primarily relates to amounts discussed below in “Investigations Regarding Misappropriation and Possible Illegal Payments.”

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Liquidity and Capital Resources

Historical Cash Flow

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

	Nine Months Ended June 30,
	2007			2006
Cash flow from operations	$	617.5		$	603.5
Cash flow used in investing		(593.5	)		(307.6	)
Cash flow used in financing		(51.1	)		(269.7	)
Effect of exchange rate changes on cash		(.1	)		.2
Change in cash and cash equivalents	$	(27.2	)	$	26.4

Higher revenue and profits for the U.S./Mexico Pressure Pumping, International Pressure Pumping, and Oilfield Services Group resulted in higher cash flow from operations. Working capital decreased $167.8 million as a result of a $250.0 million increase in the current portion of long term debt and $47.0 million increase in short-term borrowings, which were reduced by a $107.0 million increase in inventory as a result of activity and a $53.4 million increase in prepaid expenses, primarily related to tax payments.

The cash flow used in investing during the nine months ended June 30, 2007 was almost entirely due to $546.5 million of purchases of property, plant, and equipment, including $47.8 million paid to buy-out an equipment partnership established in 1997. We also paid $55.4 million, net of cash, for acquisitions.

Cash flows used in financing consisted of $47.0 million, net, in proceeds from short term borrowings, $74.6 million in repurchases of our common stock and a $44.0 million payment of dividends during the nine months ended June 30, 2007. We also received proceeds in the amount of $19.0 million for employee stock purchases and stock option exercises during the first three quarters of fiscal 2007.

Liquidity and Capital Resources

Cash flows from operations is expected to be our primary source of liquidity for the remainder of fiscal 2007. Our sources of liquidity also include cash and cash equivalents of $65.3 million at June 30, 2007 and the available financing facilities listed below (in millions):

Financing Facility	Expiration	Borrowings at June 30, 2007		Available at June 30, 2007
Revolving Credit Facility	June 2009	$	132.0	$	268.0
Discretionary	Various times within the next 12 months	$	75.3	$	87.4

On June 8, 2006, we completed a public offering of $500.0 million aggregate principal amount of Senior Notes, consisting of $250.0 million of floating rate Senior Notes due 2008, with an annual interest rate of three-month LIBOR plus 17 basis points, and $250.0 million of 5.75% Senior Notes due 2011. The net proceeds from the offering of approximately $497.1 million, after deducting underwriting discounts and commissions and expenses, were used primarily to repurchase outstanding shares of common stock and also repay indebtedness, fund capital expenditures and for other corporate purposes. As of June 30, 2007 and September 30, 2006, we had $250.0 million of the Senior Notes due 2008 issued and outstanding and $249.7 million, net of discount, of the 5.75% Senior Notes due 2011 issued and outstanding, respectively.

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In June 2004, we replaced our 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. 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 $0.3 million for the nine months ended June 30, 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 33%, though there were no material charges in fiscal 2007 to date or in fiscal 2006. There were $132.0 million and $160.0 million in outstanding borrowings under the Revolving Credit Facility at June 30, 2007 and September 30, 2006, respectively.

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 these covenants.

In addition to the Revolving Credit Facility, we had $162.7 million of unsecured, discretionary lines of credit at June 30, 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 $75.3 million and $0.3 million in outstanding borrowings under these lines of credit at June 30, 2007 and September 30, 2006, 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.

Cash Requirements

We anticipate capital expenditures to be approximately $725 million for fiscal 2007, which includes $48 million we paid in February to purchase the remaining interest in the 1997 equipment partnership as discussed in Off Balance Sheet Transactions below, compared to $460 million in fiscal 2006. The 2007 capital expenditure program has consisted 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. We have made significant progress adding new equipment. However, much of the older equipment still remains in operation due to the increases in market activity in the U.S. The actual amount of fiscal 2007 capital expenditures will depend primarily on maintenance requirements and expansion opportunities and our ability to execute our budgeted capital expenditures for the fourth quarter of fiscal 2007.

In fiscal 2007, our minimum pension and postretirement funding requirements are anticipated to be approximately $17.0 million. We have contributed $9.2 million during the nine months ended June 30, 2007.

We anticipate paying cash dividends in the amount of $.05 per common share on a quarterly basis in

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fiscal 2007. Based on the shares outstanding on September 30, 2006, the aggregate annual amount paid for dividends would be approximately $58.6 million. We have paid $44.0 million in dividends during the nine months ended June 30, 2007. 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.

As of June 30, 2007, we had $250.0 million of the Senior Notes due June 2008 issued and outstanding and $249.7 million of the 5.75% Senior Notes due 2011 issued and outstanding, net of discount. We expect cash paid for net interest expense (net of interest income) will be approximately $35 million, inclusive of borrowings under our credit facility, in fiscal 2007.

We expect an incremental increase to cash paid for income taxes to be approximately $52 million in fiscal 2007 compared to fiscal 2006, due to increased profitability.

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 are in discussions with the DOJ and SEC regarding our internal investigation and certain other matters described in Note 6 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. 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, 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 $13.4 million and $16.1 million as of June 30, 2007 and September 30, 2006, 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 have the intent 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.

In 1997, we contributed certain pumping service equipment to a limited partnership. The equipment is used to provide services to our customers for which we paid a service fee. On February 9, 2007, we purchased the remaining partnership interest for $47.8 million, and as a result acquired the partnership equipment. The acquisition of the partnership controlling interest was accounted for as an asset purchase.

Accounting Pronouncements

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.

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In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R) (“SFAS 158”). This will require companies to recognize the over funded or under funded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in our statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. It also requires companies to measure the funded status of a plan as of the date of our year-end statement of financial position. Additionally, companies will need to:

a. Recognize the funded status of a benefit plan (measured as the difference between plan assets at fair value (with limited exceptions) and the benefit obligation) in our statement of financial position. For a pension plan, the benefit obligation is the projected benefit obligation; for any other postretirement benefit plan, such as a retiree health care plan, the benefit obligation is the accumulated postretirement benefit obligation.

b. Recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost.

c. Measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position.

d. Disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition asset or obligation.

Recognition of an asset or liability related to the funded status of a pension plan and disclosures are effective for fiscal years ending after December 15, 2006. We currently measure our defined benefit plan assets and obligations as of our fiscal year-end. Thus, this portion of SFAS 158 will not impact our financial statements. We are currently in the process of evaluating the impact on our financial statements from the other requirements of SFAS 158.

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.

In July 2006, the FASB issued Interpretation No. 48 (“FIN 48”), Accounting for Uncertainty in Income Taxes, effective for fiscal years beginning after December 15, 2006. FIN 48 prescribes a recognition threshold and measurement attribute, as well as criteria for subsequently recognizing, derecognizing and measuring tax positions for financial statement purposes and requires companies to make disclosures about uncertain income tax positions, including a detailed rollforward of tax benefits taken that do not qualify for financial statement recognition. We are currently in the process of evaluating the impact of FIN 48 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

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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. 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, 2006.

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 revenues, 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 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 us in light of our experience and our 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, and declines in customer activity due to adverse local and regional conditions,

• our ability to expand our 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,

• 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 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 our Form 10-K for the fiscal year ended September 30, 2006.

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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 June 30, 2007 rates, our combined interest expense to third parties would increase by a total of $215 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 June 30, 2007 were $29.0 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 at June 30, 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.

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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 June 30, 2007 in our “Risk Factors” as discussed in our Form 10-K for the fiscal year ended September 30, 2006.

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

(a) None

(b) None

(c) Purchases of Equity Securities by the Issuer and Affiliated Purchasers

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
April 1 – 30, 2007	0				$	449.3 million
May 1 – 31, 2007	0				$	449.3 million
June 1 – 30, 2007	1,895,568	$	28.80	1,895,568	$	394.7 million
TOTAL	1,895,568			1,895,568	$	394.7 million

⁽¹⁾ On December 19, 1997, our Board of Directors authorized a stock repurchase program of up to $150 million (which was subsequently increased several times). Repurchases are made at the discretion of our management and the program will remain in effect until terminated by our Board of Directors. Since the Company began its share repurchase program in 1997, the Company has repurchased 84.9 million shares for $1.81 billion. The Company currently has remaining authorization from its Board of Directors to purchase up to an additional $394.7 million in stock.

Item 3. Defaults upon Senior Securities

None

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

None

Item 5. Other Information

None

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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: August 9, 2007	By:	/s/ J. W. Stewart
		J. W. Stewart
		Chairman of the Board, President and Chief Executive Officer
Date: August 9, 2007	By:	/s/ Jeffrey E. Smith
		Jeffrey E. Smith
		Senior Vice President - Finance and Chief Financial Officer

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