BJ Services 10-Q 2009 Q2 Quarterly report

UNITED STATES

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, 2009

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)

(713) 462-4239

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    YES  ¨    NO  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

There were 292,123,066 shares of the registrant’s common stock, $0.10 par value, outstanding as of August 5, 2009.

BJ SERVICES COMPANY

INDEX

PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Statement of Operations (Unaudited) – Three and nine months ended June 30, 2009 and 2008	3
	Condensed Consolidated Statement of Financial Position – June 30, 2009 (Unaudited) and September 30, 2008	4
	Condensed Consolidated Statement of Stockholders’ Equity and Other Comprehensive Income (Unaudited) – Nine months ended June 30, 2009	5
	Condensed Consolidated Statement of Cash Flows (Unaudited) – Nine months ended June 30, 2009 and 2008	6
	Notes to Unaudited Condensed Consolidated 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	34
Item 4.	Controls and Procedures	34
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3.	Defaults upon Senior Securities	34
Item 4.	Submission of Matters to a Vote of Security Holders	34
Item 5.	Other Information	34
Item 6.	Exhibits	35

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PART I

FINANCIAL INFORMATION

Item 1. Financial Statements

BJ SERVICES COMPANY

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (UNAUDITED)

(In thousands, except per share amounts)

	Three Months Ended June 30,						Nine Months Ended June 30,
	2009			2008			2009			2008
Revenue	$	786,920		$	1,328,228		$	3,273,169		$	3,896,495
Operating expenses:
Cost of sales and services		741,457			1,032,375			2,750,232			2,986,932
Research and engineering		15,922			18,563			50,137			54,674
Marketing		25,933			29,400			83,462			89,996
General and administrative		36,225			40,401			119,485			118,683
Loss on disposal of assets, net		9,706			631			12,111			243
Pension settlement		—			—			21,695			—
Total operating expenses		829,243			1,121,370			3,037,122			3,250,528
Operating income (loss)		(42,323	)		206,858			236,047			645,967
Interest expense		(7,075	)		(6,596	)		(20,566	)		(21,407	)
Interest income		334			554			1,197			1,384
Other expense, net		(4,650	)		(3,189	)		(4,118	)		(4,847	)
Income (loss) before income taxes		(53,714	)		197,627			212,560			621,097
Income tax expense (benefit)		(21,378	)		55,844			52,670			179,827
Net income (loss)	$	(32,336	)	$	141,783		$	159,890		$	441,270
Earnings (loss) per share:
Basic	$	(0.11	)	$	0.48		$	0.55		$	1.50
Diluted	$	(0.11	)	$	0.48		$	0.54		$	1.49
Weighted-average shares outstanding:
Basic		292,087			293,892			292,278			293,253
Diluted		292,087			296,357			293,400			295,586

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

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BJ SERVICES COMPANY

CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION

(In thousands)

	June 30, 2009		September 30, 2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	231,280	$	150,254
Receivables, net		762,518		1,151,236
Inventories, net:
Products		292,020		291,857
Work in process		11,982		22,418
Parts		186,483		193,600
Total inventories		490,485		507,875
Deferred income taxes		32,163		28,097
Prepaid expenses		75,235		83,065
Other current assets		40,223		40,623
Total current assets		1,631,904		1,961,150
Property, net		2,366,253		2,312,949
Deferred income taxes		16,496		20,859
Goodwill		977,844		975,451
Investments and other assets		53,609		51,499
Total assets	$	5,046,106	$	5,321,908
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	297,719	$	554,615
Short-term borrowings		21,508		57,610
Accrued employee compensation and benefits		115,777		148,451
Income and other taxes		54,036		86,549
Other accrued liabilities		164,552		172,995
Total current liabilities		653,592		1,020,220
Long-term debt		498,865		498,730
Deferred income taxes		166,453		153,923
Accrued pension and postretirement benefits		100,948		127,065
Other long-term liabilities		94,014		80,163
Commitments and contingencies
Stockholders’ equity		3,532,234		3,441,807
Total liabilities and stockholders’ equity	$	5,046,106	$	5,321,908

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

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BJ SERVICES COMPANY

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

AND OTHER COMPREHENSIVE INCOME (UNAUDITED)

(In thousands)

	Common Shares Outstanding		Common Stock		Capital In Excess of Par			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance, September 30, 2008	294,232		$	34,752	$	1,100,977		$	(1,411,739	)	$	3,677,258		$	40,559		$	3,441,807
Comprehensive income:
Net income	—			—		—			—			159,890			—
Other comprehensive income, net of tax:
Cumulative translation adjustments	—			—		—			—			—			(47,772	)
Pension settlement	—			—		—			—			—			10,083
Changes in defined benefit and other postretirement plans	—			—		—			—			—			16,748
Comprehensive income																		138,949
Dividends declared	—			—		—			—			(43,810	)		—			(43,810	)
Treasury stock purchase	(3,467	)		—		—			(44,190	)		—			—			(44,190	)
Re-issuance of treasury stock for:
Stock purchase plan	769			—		—			19,630			(7,474	)		—			12,156
Stock options	417			—		—			18,008			(17,163	)		—			845
Other stock awards	163			—		(4,144	)		4,144			—			—			—
Stock-based compensation	—			—		26,254			—			—			—			26,254
Tax benefit from exercise of options	—			—		223			—			—			—			223
Balance, June 30, 2009	292,114		$	34,752	$	1,123,310		$	(1,414,147	)	$	3,768,701		$	19,618		$	3,532,234

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

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BJ SERVICES COMPANY

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)

(In thousands)

	Nine Months Ended June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	159,890		$	441,270
Adjustments to reconcile net income to cash provided by operating activities:
Pension settlement		21,695			—
Depreciation and amortization		221,821			195,198
Minority interest expense		8,348			6,761
Loss on disposal/impairment of assets, net		12,111			243
Reserve for obsolescence and excess inventory		13,330			10,364
Stock-based compensation expense		29,710			25,745
Excess tax benefits from stock-based compensation		(1,038	)		(14,436	)
Deferred income tax expense		15,153			3,557
Changes in:
Receivables		397,597			(29,635	)
Inventories		6,099			(524	)
Prepaid expenses		8,902			14,272
Other current assets		(7,299	)		5,074
Accounts payable		(261,819	)		(69,056	)
Accrued employee compensation and benefits		(45,450	)		16,345
Current income tax		(19,588	)		12,628
Other current liabilities		(25,029	)		2,551
Other, net		(28,991	)		(34,332	)
Net cash provided by operating activities		505,442			586,025
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(314,392	)		(433,638	)
Proceeds from disposal of assets		4,352			10,342
Acquisition of businesses, net of cash received		—			(54,400	)
Net cash used in investing activities		(310,040	)		(477,696	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		—			248,858
Repayment of long-term debt		—			(250,000	)
Proceeds (repayments) of short-term borrowings, net		13,898			(118,734	)
Borrowing (repayments) under committed credit facility		(50,000	)		50,000
Dividends paid to stockholders		(43,914	)		(43,916	)
Purchase of treasury stock		(44,190	)		(2,089	)
Excess tax benefits from stock-based compensation		1,038			14,436
Net proceeds from exercise of stock options and stock purchase plan		13,621			24,983
Distributions to minority interest partners		(2,535	)		(4,342	)
Debt issuance costs		—			(1,976	)
Net cash used in financing activities		(112,082	)		(82,780	)
Effect of exchange rate changes on cash		(2,294	)		(1,209	)
Increase in cash and cash equivalents		81,026			24,340
Cash and cash equivalents at beginning of period		150,254			58,199
Cash and cash equivalents at end of period	$	231,280		$	82,539
Cash Paid for Interest and Taxes:
Interest, net of capitalized interest of $4,981 and $5,606	$	25,628		$	28,484
Taxes		38,038			142,786

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

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BJ SERVICES COMPANY

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 General

In our opinion, the unaudited condensed consolidated 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 as of June 30, 2009, our results of operations for the three and nine-month periods ended June 30, 2009 and 2008, our statement of stockholders’ equity and other comprehensive income for the nine-month period ended June 30, 2009, and our cash flows for the nine-month periods ended June 30, 2009 and 2008. The condensed consolidated statement of financial position at September 30, 2008 is derived from the September 30, 2008 audited consolidated financial statements. Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. The results of operations and cash flows for the nine-month period ended June 30, 2009 are not necessarily indicative of the results to be expected for the full year.

We have evaluated subsequent events through August 7, 2009, the date of issuance of the condensed consolidated financial statements.

Certain prior period amounts have been reclassified in the accompanying condensed consolidated financial statements to conform to the current year presentation.

Note 2 Earnings (Loss) Per Share and Comprehensive Income

Basic earnings (loss) per share exclude dilution and are computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted earnings (loss) per share are based on the weighted-average number of shares outstanding during each period and the assumed exercise of dilutive instruments (stock options, employee stock purchase plan, stock incentive awards, bonus stock and director 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 (loss) per share for the periods presented (in thousands, except per share amounts):

	Three Months Ended June 30,					Nine Months Ended June 30,
	2009			2008		2009		2008
Net income (loss)	$	(32,336	)	$	141,783	$	159,890	$	441,270
Weighted-average common shares outstanding		292,087			293,892		292,278		293,253
Basic earnings (loss) per share	$	(0.11	)	$	0.48	$	0.55	$	1.50
Weighted-average common and dilutive potential common shares outstanding:
Weighted-average common shares outstanding		292,087			293,892		292,278		293,253
Assumed exercise of dilutive instruments(1)		—			2,465		1,122		2,333
Weighted-average dilutive shares outstanding		292,087			296,357		293,400		295,586
Diluted earnings (loss) per share	$	(0.11	)	$	0.48	$	0.54	$	1.49

⁽¹⁾ For the three months ended June 30, 2009, 1.6 million potential common shares were excluded from the computation of diluted loss per share due to their antidilutive affect. These shares represent a combination of stock options, employee stock purchase plan shares, stock incentive awards, bonus stock and director stock awards. For the three and nine months ended June 30, 2009, 11.3 million and

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11.5 million stock options, respectively, were excluded from the computation of diluted earnings (loss) per share due to their antidilutive effect as calculated using the treasury stock method. For the three and nine months ended June 30, 2008, 3.0 million stock options were excluded from the computation of diluted earnings per share due to their antidilutive effect.

The following table summarizes comprehensive income for the periods presented (in thousands):

	Three Months Ended June 30,					Nine Months Ended June 30,
	2009			2008		2009			2008
Net income (loss)	$	(32,336	)	$	141,783	$	159,890		$	441,270
Cumulative translation adjustments		27,756			4,636		(47,772	)		(5,831	)
Pension settlement		—			—		16,040			—
Changes in defined benefit and other postretirement plans		4,448			—		26,689			(9,277	)
Deferred tax benefit (expense)		(1,658	)		—		(15,898	)		3,445
Comprehensive income (loss)	$	(1,790	)	$	146,419	$	138,949		$	429,607

Accumulated other comprehensive income (loss) consisted of the following (in thousands):

	Pension and Other Postretirement Plan Adjustments			Cumulative Translation Adjustment			Total
Balance at September 30, 2008	$	(36,609	)	$	77,168		$	40,559
Changes		26,831			(47,772	)		(20,941	)
Balance at June 30, 2009	$	(9,778	)	$	29,396		$	19,618

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. We revised our internal management reporting structure in fiscal 2009, moving our U.S. service tool business, which previously had been reported within the U.S./Mexico Pressure Pumping segment, into the completion tools division of our Oilfield Services Group. All periods presented have been recast to conform to the new reporting structure.

The U.S./Mexico Pressure Pumping segment has two operating segments that provide cementing services and stimulation services (consisting of fracturing, acidizing, sand control, nitrogen and coiled tubing services) throughout the United States and Mexico. These two operating segments have been aggregated into one reportable segment because they offer the same type of services, have similar economic characteristics, have similar production processes and use the same methods to provide their services.

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

The International Pressure Pumping segment has five operating segments. Similar to U.S./Mexico and Canada Pressure Pumping, it provides 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 Europe / Africa, the Middle East, Asia Pacific, Russia and Latin America. These operating segments have been aggregated into one reportable segment because they have similar economic characteristics, offer the same type

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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. Business activities in our Russia operating segment are expected to conclude during the fourth quarter of fiscal 2009 and results are expected to be reclassified to discontinued operations during that quarter.

The Oilfield Services Group segment has five operating segments. These operating segments provide oilfield services such as casing and tubular services, process and pipeline services, chemical services, completion tools and completion fluids services in the United States and in select markets internationally. These operating segments have been aggregated into one reportable segment as they all provide oilfield services other than pressure pumping, serve same or similar customers and some of the operating segments share resources.

The accounting policies of the segments are the same as those described in the summary of significant accounting policies in Note 2 of the Notes to the Consolidated Financial Statements included in our annual report on Form 10-K for the fiscal year ended September 30, 2008. 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 (in thousands):

	U.S./Mexico Pressure Pumping			Canada Pressure Pumping			International Pressure Pumping		Oilfield Services Group		Corporate(1)			Total
Three Months Ended June 30, 2009
Revenue	$	314,012		$	23,259		$	264,753	$	184,896	$	—		$	786,920
Operating income (loss)		(38,540	)		(15,633	)		24,473		10,935		(23,558	)		(42,323	)
Three Months Ended June 30, 2008
Revenue	$	698,131		$	48,636		$	316,922	$	264,539	$	—		$	1,328,228
Operating income (loss)		144,677			(16,595	)		45,235		51,813		(18,272	)		206,858
Nine Months Ended June 30, 2009
Revenue	$	1,511,134		$	250,440		$	870,385	$	641,210	$	—		$	3,273,169
Operating income (loss)		139,025			19,126			91,617		72,590		(86,311	)		236,047
Identifiable assets		1,586,977			424,936			1,483,231		1,048,138		502,824			5,046,106
Nine Months Ended June 30, 2008
Revenue	$	1,988,143		$	308,772		$	897,554	$	702,026	$	—		$	3,896,495
Operating income (loss)		449,895			14,878			115,874		132,935		(67,615	)		645,967
Identifiable assets		1,662,129			482,768			1,400,952		1,060,957		456,482			5,063,288

(1) The “Corporate” column includes corporate expenses and assets not allocated to the operating segments. The nine months ended June 30, 2009 includes a $21.7 million pension settlement charge (discussed in Note 7).

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

	Three Months Ended June 30,						Nine Months Ended June 30,
	2009			2008			2009			2008
Total operating income (loss) for reportable segments	$	(42,323	)	$	206,858		$	236,047		$	645,967
Interest expense		(7,075	)		(6,596	)		(20,566	)		(21,407	)
Interest income		334			554			1,197			1,384
Other income (expense), net		(4,650	)		(3,189	)		(4,118	)		(4,847	)
Income (loss) before income taxes	$	(53,714	)	$	197,627		$	212,560		$	621,097

As a result of the reduction in demand for our services and products caused by the recent global economic downturn, we identified a list of cementing and stimulation equipment used in our Pressure Pumping business that was not economical to repair or maintain in the current market environment. We impaired such equipment to write it down to scrap or salvage value, recording non-cash, pre-tax impairment charges totaling $5.7 million in the U.S. Pressure Pumping segment and $1.5 million in the Middle East region of the International Pressure Pumping segment in the third fiscal quarter of 2009. These charges, totaling $7.2 million, are included in the loss on disposal of assets on the consolidated statement of operations.

Note 4 Acquisitions

On May 21, 2008, we acquired all of the outstanding shares of Innicor Subsurface Technologies Inc. (“Innicor”) for a purchase price of $54.4 million, including transaction costs, which resulted in an increase of $36.5 million in total current assets, $14.5 million in property and equipment, $0.6 million in intangible assets, $11.3 million in current liabilities, $3.1 million in long-term liabilities and $17.2 million of goodwill. Innicor designs, manufactures and provides tools and equipment utilized in the completion and production phases of oil and gas well development in Canada and select international markets. This business complements our completion tools business in the Oilfield Services Group. Pro forma financial information for this acquisition is not included as it is not material to our financial statements.

Note 5 Commitments and Contingencies

Litigation

Through performance of our service operations, we are sometimes named as a defendant in litigation, usually relating to claims for personal injury or property damage (including claims for well or reservoir damage, and damage to pipelines or process facilities). 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 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, results of operations or cash flows.

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

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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 a Jones Act 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 sites. 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 successor cases without any payment in settlements or judgments, although some remain pending at the present time. We intend to defend ourselves vigorously in all of these cases based on the information available to us at this time. We do not expect the outcome of these lawsuits, individually or collectively, to have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these lawsuits or additional similar lawsuits, if any, that may be filed.

Halliburton – Python Litigation

On December 21, 2007, Halliburton Energy Services, Inc. (“Halliburton”) re-filed a prior suit against us and another oilfield services company for patent infringement in connection with drillable bridge plug tools. These tools are used to isolate portions of a well for stimulation work, after which the plugs are milled out using coiled tubing or a workover rig. Halliburton claims that our tools (offered under the trade name “Python”) and tools offered by the other company infringe various patents for a tool constructed of composite material. The lawsuit was filed in the United States District Court for the Northern District of Texas (Dallas). This lawsuit arises from litigation filed in 2003 by Halliburton regarding the patents at issue. The earlier case was dismissed without prejudice when Halliburton sought a re-examination of the patents by the United States Patent and Trademark Office on July 6, 2004. The parties have filed briefs with the Court arguing their positions on the construction of the coverage of Halliburton’s patent. We expect that the Court will either issue a ruling or schedule a hearing on these issues within the next few months. We do not expect the outcome of this matter to have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this matter or future lawsuits, if any, that may be filed.

Halliburton – OptiFrac Litigation

In December 2008, Halliburton filed a lawsuit against us in the Eastern District of Texas (Marshall) and another lawsuit in Toronto, Canada against us and another oilfield services company for patent infringement. In both suits, Halliburton claims that our coiled tubing perforating system (“OptiFrac”) infringes various patents for a coiled tubing fracturing system marketed by Halliburton. We are in the process of analyzing the methods, claims and causes of action alleged by Halliburton in the suits. We do not expect the outcome of these matters 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 matters or future lawsuits, if any, that may be filed.

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Investigations Regarding Misappropriation and Possible Illegal Payments

In October 2004, we received a report from a whistleblower alleging that our Asia Pacific Region Controller had misappropriated Company funds and that illegal payments had been made to government officials in that region. Management and the Audit Committee of the Board of Directors conducted investigations of these allegations, as well as questions that later arose whether illegal payments had been made elsewhere.

As a result of the theft investigation, the Region Controller admitted to multiple misappropriations and returned certain amounts to the Company. His employment was terminated in 2004.

In addition, the Audit Committee’s investigation found information indicating a significant likelihood that payments, made by us to an entity in the Asia Pacific Region with which we have a contractual relationship, were then used to make payments to government officials in the region. The information also indicated that certain of our employees in the region believed that the payments by us would be used in that way. The payments, which may have been illegal, aggregated approximately $2.9 million and were made over a period of several years. The investigation also identified certain other payments as to which the legitimacy of the transactions reflected in the underlying documents could not be established or as to which questions about the adequacy of the underlying documents could not be resolved. We have voluntarily disclosed information found in the investigations to the U.S. Department of Justice (“DOJ”) and U.S. Securities and Exchange Commission (“SEC”) and have engaged in discussions with these authorities in connection with their review of the matter. We cannot predict whether further investigative efforts may be required or initiated by the authorities.

In May 2007, the former Region Controller pled guilty to one count of theft in Singapore. In June 2007, we filed a civil lawsuit against him seeking to recover any additional misappropriated funds and seeking an accounting of disbursements that could not be explained following the investigation. In July 2008, we reached a settlement of this litigation with the former Region Controller and he made a payment to us.

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 in appropriate circumstances. Recent civil and criminal settlements with a number of public corporations and individuals have included multi-million dollar fines, disgorgement, injunctive relief, guilty pleas, deferred prosecution agreements and other sanctions, including requirements that corporations retain a monitor to oversee compliance with the FCPA. We cannot predict 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.

Environmental

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. At June 30, 2009 and September 30, 2008, we had reserves of approximately $3.8 million and $4.6 million, respectively, for such environmental matters. This represents 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 Financial Accounting Standards Board (“FASB”) Interpretation No. 46(R),Consolidation of Variable Interest Entities. However, we were not deemed to be the primary beneficiary, and

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therefore, consolidation was not required. The transaction resulted in a gain that is being deferred and amortized over the partnership term. The partnership 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. Substitution activity during the partnership term has reduced the balance of the deferred gain to zero at June 30, 2009, compared to $4.2 million as of September 30, 2008. In 2010, we have the option, but not the obligation, to purchase the pumping service equipment in the limited partnership for approximately $46 million. We currently intend to exercise this option. The option price to purchase the equipment under the partnership depends in part on the fair market value of the equipment held by the partnership at the time the option is exercised, as well as other factors specified in the agreement.

Contractual Obligations

We routinely issue Parent Company Guarantees (“PCGs”) in connection with service contracts or performance obligations 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 subsidiaries, 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 subsidiaries, 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. We have also issued standby letters of credit 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, 2009 (in thousands):

			Amount of commitment expiration per period
Other Commercial Commitments	Total Amounts Committed		Less than 1 Year		1–3 Years		3–5 Years		Over 5 Years
Standby letters of credit	$	34,177	$	34,177	$	—	$	—	$	—
Guarantees		236,791		128,648		61,275		40,748		6,120
Total other commercial commitments	$	270,968	$	162,825	$	61,275	$	40,748	$	6,120

Note 6 Financial Instruments

The carrying amount of cash and cash equivalents, receivables, accounts payable, and short-term borrowings approximates fair value because of the short maturities of those instruments. Periodically, we borrow funds denominated in foreign currencies, which exposes us to market risk associated with exchange rate fluctuations. There were $21.5 million and $7.6 million of short-term borrowings denominated in foreign currencies at June 30, 2009 and September 30, 2008, respectively.

Fair value of our long-term debt, calculated based on quoted prices in active markets for our debt securities, at June 30, 2009 and September 30, 2008 was as follows (in thousands):

	June 30, 2009				September 30, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
5.75% Senior Notes due 2011	$	249,874	$	255,000	$	249,825	$	255,225
6% Senior Notes due 2018		248,991		242,163		248,905		250,300
Total long-term debt	$	498,865	$	497,163	$	498,730	$	505,525

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Note 7 Employee Benefit Plans

We have defined benefit pension plans and a postretirement benefit plan covering certain employees, which are described in more detail in Note 9 of the Notes to Consolidated Financial Statements included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008.

In September 2006, we entered into an agreement with an insurance company to settle our obligation with respect to the U.S. defined benefit plan. Plan assets of approximately $72 million were used to purchase an insurance contract to fund the benefits and settle the plan. In December 2008, we received approval from the Pension Benefit Guaranty Corporation and the Internal Revenue Service and were relieved of primary responsibility for the pension benefit obligation. Consequently, we recorded a non-cash pre-tax charge of $21.7 million in connection with the settlement in the first fiscal quarter of 2009. This charge resulted in a $5.7 million reduction in prepaid pension cost and a $16.0 million increase in accumulated other comprehensive income, with a tax effect of $5.9 million.

Below is the amount of net periodic benefit costs recognized under our foreign defined benefit plans (in thousands):

	Three Months Ended June 30,						Nine Months Ended June 30,
	2009			2008			2009			2008
Service cost for benefits earned	$	1,654		$	1,680		$	4,962		$	5,040
Interest cost on projected benefit obligation		3,449			3,327			10,347			9,981
Expected return on plan assets		(2,829	)		(2,903	)		(8,487	)		(8,709	)
Recognized actuarial loss		615			604			1,845			1,812
Net amortization and deferral		—			(25	)		—			(75	)
Net pension cost	$	2,889		$	2,683		$	8,667		$	8,049

In fiscal 2009, we expect to contribute a total of $12.8 million to the defined benefit plans, which represents the legal or contractual minimum funding requirements and expected discretionary contributions. We have paid $9.6 million in contributions to defined benefit pension plans during the nine months ended June 30, 2009. These contributions have been and are expected to be funded by cash flows from operating activities.

Below is the amount of net periodic benefit costs recognized under our postretirement benefit plan (in thousands).

	Three Months Ended June 30,					Nine Months Ended June 30,
	2009			2008		2009			2008
Service cost for benefits attributed to service during the period	$	172		$	1,033	$	1,037		$	3,099
Interest cost on accumulated postretirement benefit obligation		248			914		1,247			2,742
Net amortization and deferral		(1,232	)		—		(3,017	)		—
Net postretirement benefit cost (income)	$	(812	)	$	1,947	$	(733	)	$	5,841

We expect to contribute a total of $1.6 million to the postretirement benefit plan in fiscal 2009, which represents the anticipated cost of participant claims. We have made $1.2 million in postretirement contributions during the nine months ended June 30, 2009.

Note 8 New Accounting Standards

In June 2009, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 168,Codification and the Hierarchy of Generally Accepted Accounting Principles (“GAAP”) (“SFAS 168”) (FASB Accounting Standard Codification (“ASC”) 105-10) establishing

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an authoritative United States GAAP superseding all pre-existing accounting standards and literature. SFAS 168 is effective for financial statements issued for interim and annual periods after September 15, 2009. In response, we will change the accounting literature references contained in our SEC filings subsequent to that date without material impact on our financial statements.

In June 2009, the FASB issued SFAS No. 167,Amendments to FASB Interpretation (“FIN”) No. 46(R) (“SFAS 167”) which addresses the addition of qualified special purpose entities into the scope of FIN46(R) as the concept of these entities was eliminated by SFAS 166. This statement also modifies the analysis by which a controlling interest of a variable interest entity is determined thereby requiring the controlling interest to consolidate the variable interest entity. A controlling interest exists if a party to a variable interest entity has both (i) the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance and (ii) the obligation to absorb losses of or receive benefits from the entity that could be potentially significant to the variable interest entity. This statement could impact the way we account for our limited partnership discussed in Note 5 underLease and Other Long-Term Commitments. SFAS 167 becomes effective as of the beginning of the first annual reporting period beginning after November 15, 2009 and should be applied prospectively for interim and annual periods during that period going forward. We will adopt the provisions of SFAS 167 on October 1, 2010, and have not yet determined the impact, if any, on our consolidated financial statements.

In June 2009, the FASB issued SFAS No. 166,Accounting for Transfers of Financial Assets (“SFAS 166”) which eliminates the concept of a qualified special purpose entity and enhances guidance related to derecognition of transferred assets. SFAS 166 becomes effective as of the beginning of the first annual reporting period beginning after November 15, 2009 and should be applied prospectively for interim and annual periods during that period going forward. We will adopt the provisions of SFAS 166 on October 1, 2010, and have not yet determined the impact, if any, on our consolidated financial statements.

On June 30, 2009, we adopted FASB Staff Position (“FSP”) 107-1 and Accounting Principles Board (“APB”) 28-1,Interim Disclosures about Fair Value of Financial Instruments, which amends SFAS No. 107 and requires publicly-traded companies to disclose the fair value of financial instruments in their interim financial statements. See Note 6.

In May 2009, the FASB issued SFAS No. 165,Subsequent Events(“SFAS 165”) (FASB ASC 855-10). The objective of this statement is to establish general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This standard is effective for reporting periods ending after June 15, 2009. We adopted this standard in our June 30, 2009 condensed consolidated financial statements.

In December 2008, the FASB issued FASB Staff Position 132 (R)-1Employer’s Disclosures about Postretirement Benefit Plan Assets (“FSP 132 (R)-1”) (FASB ASC 715-20-65-2). FSP 132 (R)-1 amends FASB Statement No. 132 (revised 2003),Employers’ Disclosures about Pension and Other Postretirement Benefits, requiring the disclosure of major categories of plan assets, investment policies and strategies, fair value measurement of plan assets and significant concentration of credit risks related to defined benefit pension or other postretirement plans. FSP 132 (R)-1 is effective for fiscal years ending after December 15, 2009. We will adopt the new disclosure requirements of FSP 132 (R)-1 in fiscal 2010.

In April 2008, the FASB issued FSP 142-3,Determination of the Useful Life of Intangible Assets (“FSP 142-3”) (FASB ASC 350-30-65-1). FSP 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142,Goodwill and Other Intangible Assets (“SFAS 142”). The objective of FSP 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141(R),Business Combinations (FASB ASC 805-10,20,30,40,50,740), and other U.S. generally accepted accounting principles. FSP 142-3 is effective for the Company beginning October 1, 2009. We are currently in the process of evaluating the impact of FSP 142-3 on our financial statements.

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In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS 161”) (FASB ASC 815-10). SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under SFAS 133, and its related interpretations, and (3) how derivative instruments and related hedged items affect an entity's financial position, financial performance and cash flows. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008. Accordingly, we adopted SFAS 161 in the second quarter of fiscal 2009. We currently have no derivative financial instruments subject to accounting or disclosure under SFAS 133; therefore, the adoption of SFAS 161 had no effect on our consolidated statements of financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations (“SFAS 141(R)”), replacing SFAS No. 141,Business Combinations (“SFAS 141”) (FASB ASC 805-10,20,30,40,50,740). SFAS 141(R) retains the fundamental requirements in SFAS 141 that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS 141(R) defines the acquirer as the entity that obtains control of one or more businesses in the business combination and establishes the acquisition date as the date that the acquirer achieves control. SFAS 141(R) establishes principles and requirements for how the acquirer:

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

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

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

This statement is effective for business combinations occurring on or after the beginning of the first annual reporting period beginning after December 15, 2008. We will adopt SFAS 141(R) on October 1, 2009 for acquisitions beginning on or after that date.

In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements(“SFAS 160”) (FASB ASC810-10-65-1), amending previous guidance to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest and requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS 160 requires expanded disclosures in the consolidated financial statements that identify and distinguish between the interests of the parent’s owners and the interests of the noncontrolling owners of a subsidiary and shall be applied prospectively as of the beginning of the fiscal year in which initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. SFAS 160 is effective for fiscal years beginning after December 15, 2008 (our fiscal year beginning October 1, 2009). We do not have significant noncontrolling interests in consolidated subsidiaries.

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements (“SFAS 157”) (FASB ASC 820-10), effective for financial statements issued for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FSP 157-2 (FASB ASC 820-10-15-1A), delaying the effective date of SFAS

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157 for non-financial assets and liabilities to fiscal years beginning after November 15, 2008. 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. On October 1, 2008, we adopted without material impact on our consolidated financial statements the provisions of SFAS 157 related to financial assets and liabilities. We will adopt the provisions of SFAS 157 related to non-financial assets and liabilities on October 1, 2009, and have not yet determined the impact, if any, of these provisions of SFAS 157 on our consolidated financial statements.

In April 2009, the FASB issued FSP 157-4,Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, which provides additional guidance for estimating fair value in accordance with SFAS 157 when the volume and level of activity for the asset or liability have significantly decreased. This FSP emphasizes that even if there has been a significant decrease in the volume and level of activity for the asset or liability and regardless of the valuation technique(s) used, the objective of a fair value measurement remains the same. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction (that is, not a forced liquidation or distressed sale) between market participants under current market conditions. We adopted FSP 157-4 on June 30, 2009 and will apply it prospectively to all fair value measurements where appropriate.

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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 Pressure Pumping, Canada Pressure Pumping and International Pressure Pumping segments provide stimulation and cementing services to the petroleum industry throughout the world. Stimulation services are designed to improve the flow of oil and natural gas from producing formations. Cementing services consist of pumping 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 year ended September 30, 2008 for more information on these operations.

The Oilfield Services Group consists of casing and tubular services, process and pipeline services, chemical services, completion tools and completion fluids services in the United States and in select markets internationally.

Market Conditions

Our worldwide operations are primarily driven by the number of oil and natural gas wells being drilled, the depth and drilling conditions of such wells, the number of well completions and the level of workover activity. Drilling and workover activity, in turn, is largely dependent on the price of crude oil and natural gas and the volatility and expectations of future oil and natural gas prices. Our results of operations also depend heavily on the pricing we receive from our customers, which depends on activity levels, availability of equipment and other resources, and competitive pressures. 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,
	2009		% Change		2008		2009		% Change		2008
Rig Count:(1)
U.S.		936	-50	%		1,865		1,387	-23	%		1,808
Canada		91	-46	%		169		276	-20	%		344
International(2)		982	-9	%		1,084		1,032	-2	%		1,049
Commodity Prices (average):
Crude Oil (West Texas Intermediate)	$	59.52	-52	%	$	123.97	$	53.64	-49	%	$	104.19
Natural Gas (Henry Hub)	$	3.71	-67	%	$	11.38	$	4.90	-46	%	$	9.01

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

(2) Excludes Canada, and includes Mexico average rig count of 128 and 106 for the three-month periods ended June 30, 2009 and 2008, respectively, and 121 and 98 for the nine-month periods ended June 30, 2009 and 2008, respectively.

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U.S. Rig Count

Demand for our pressure pumping services in the United States is primarily driven by oil and natural gas drilling activity, which tends to be extremely volatile, depending on the current and anticipated prices of crude oil and natural gas. During the last 11 years, the lowest annual U.S. rig count averaged 601 in fiscal 1999 and the highest annual U.S. rig count averaged 1,851 in fiscal 2008.

With the retraction of oil and natural gas prices over the last several months, tightening and uncertainty in the credit markets, and the global economic slowdown, drilling rig activity in the United States has rapidly declined from peak levels of 2,031 rigs at September 12, 2008 to a recent low of 876 rigs at June 12, 2009, and was 948 rigs at July 31, 2009. We expect U.S. drilling activity to decline slightly during the final quarter of fiscal 2009 and we do not expect it to improve significantly during the first half of fiscal 2010. The duration of this depressed market activity is uncertain and will ultimately be influenced by a number of factors, including commodity prices, global demand for oil and natural gas, supplies and depletion rates of oil and natural gas reserves, and government policy with respect to the financial credit crisis.

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 United States, tends to be extremely volatile. During the last 11 years, the lowest annual rig count averaged 212 in fiscal 1999 and the highest annual rig count averaged 502 in fiscal 2006. Similar to activity in the United States, drilling rig activity in Canada has gradually declined since late September 2008, and is expected to continue to be lower than prior year levels into the first half of fiscal 2010. Rig counts in Canada typically encounter significant seasonal fluctuations, decreasing during the spring break-up period when travel restrictions are put in place to deter large vehicle movement during the winter thaw, thereby restricting access to well sites. The spring break-up period typically begins in late February or March and extends through May, significantly impacting our business during the third fiscal quarter.

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 helps to offset 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 international oil companies (“IOCs”) and national oil companies (“NOCs”) which tend to have different objectives and more operating stability than the typical independent producer in North America. During the last 11 years, the lowest annual international rig count, excluding Canada and including Mexico, averaged 616 in fiscal 1999 and the highest annual international rig count averaged 1,061 in fiscal 2008. International rig count has declined during fiscal 2009 compared to fiscal 2008, but at a much lower rate than North America.

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. The global economic slowdown has led to a steep decline in oil and natural gas prices, well below their historic highs in July 2008. These steep price declines have reduced cash flows of oil and gas producers and have led to significant reductions in planned drilling activity for the remainder of fiscal 2009 and into fiscal 2010, particularly in the U.S. and Canadian markets. The reduced drilling activity has led to reduction in demand and severe price competition for the services and products we provide.

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Drilling rig count in the United States has been relatively stable since mid-May, within a range of approximately 880-940 rigs. Over that period, the number of rigs drilling for natural gas has declined by roughly 60 rigs, while the number of rigs drilling for oil has increased by roughly 80 rigs. We expect U.S. gas drilling to continue to decline until natural gas supply and demand are more in balance, leading to increased natural gas prices. We expect rigs drilling for oil in the U.S. to stay at current levels or improve slightly in the near term, in response to changes in oil prices. Although we anticipate a slight sequential decrease in total U.S. rig count in our fiscal fourth quarter, we believe our profitability in the U.S./Mexico Pressure Pumping segment will improve slightly, as we realize the full benefit of the cost reduction measures we have put into place in recent months. Recent cost reductions have included personnel reductions, a global wage freeze, reduced capital spending plans, supplier negotiations and working capital initiatives. We can make no assurances that cost reductions will offset the impact of any reductions in drilling activity or customer pricing.

We expect Canada Pressure Pumping results to improve significantly in the fourth fiscal quarter compared to the fiscal third quarter, as drilling activity increases coming out of the seasonal spring break-up period. We expect fiscal fourth quarter revenues from International Pressure Pumping Services to be in line with the fiscal third quarter, and we expect operating income in that segment to improve slightly due in part to cost reduction measures put into place during the second and third fiscal quarter.

We expect revenue and operating income improvement in the Oilfield Services Group as a result of several new contracts and international sales activity. The company has several relatively large international Completion Tools orders that it expects to complete during the fourth quarter.

Results of Operations

Consolidated

	Three Months Ended June 30,							Nine Months Ended June 30,
(dollars in millions)	2009			% Change		2008		2009		% Change		2008
Revenue	$	786.9		-41	%	$	1,328.2	$	3,273.2	-16	%	$	3,896.5
Operating income (loss)	$	(42.3	)	n/a		$	206.9	$	236.0	-63	%	$	646.0
Worldwide rig count(1)		2,009		-36	%		3,118		2,695	-16	%		3,202

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

Results for the three months ended June 30, 2009 and 2008

For the second consecutive quarter, all of our reportable segments were adversely impacted by lower drilling activity as commodity prices remained at depressed levels. Further decrease in demand for oil and natural gas continued to negatively impact drilling activity and sustained intense price competition for our services and products, especially in North America, driving our revenues to lower levels compared to the same quarter of the prior year.

Revenue for the three months ended June 30, 2009 decreased 41% when compared to the same period in the prior year, generating an operating loss of $42.3 million in the third fiscal quarter of 2009 compared to operating income of $206.9 million in the same quarter of the prior year, primarily as a result of decreased demand and intense price competition for our products and services in the U.S. and Canada pressure pumping markets. Also impacting operating results in the quarter were employee severance costs of $6.4 million, $7.2 million in non-cash impairment charges related to excess or idle fixed assets in the United States and the Middle East and $10.0 million of non-cash inventory write-downs, primarily representing reserves for slow-moving or excess inventory in the current environment, and inventory whose original cost exceeded current market value. For the three months ended June 30, 2009, operating income (loss) as a percentage of revenue decreased to (5.4)% from 15.6% reported in the same period of the prior fiscal year.

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Results for the nine months ended June 30, 2009 and 2008

For the nine months ended June 30, 2009, the impact of the global economic downturn and decreased demand for oil and natural gas combined with intense price competition in North America negatively affected each of our reporting segments compared to the same period of the prior year.

Revenue for the first nine months of fiscal 2009 decreased 16% when compared to the same period in fiscal 2008 and consolidated operating income for the period decreased 63%, primarily as the result of decreased demand and intense price competition for our products and services in the United States. Results for the nine months ended June 30, 2009 included a non-cash charge of $21.7 million related to the settlement of a U.S. defined benefit pension plan, employee severance costs of $12.7 million, $15.4 million in non-cash charges related to excess or idle fixed assets, and $10.0 million of non-cash inventory write-downs. These unusual charges during fiscal 2009 represented 1.8% of consolidated revenue. For the nine months ended June 30, 2009, consolidated operating income margins decreased to 7.2% from 16.6% reported in the same period of the prior fiscal year.

U.S./Mexico Pressure Pumping

	Three Months Ended June 30,							Nine Months Ended June 30,
(dollars in millions)	2009			% Change		2008		2009		% Change		2008
Revenue	$	314.0		-55	%	$	698.1	$	1,511.1	-24	%	$	1,988.1
Operating income (loss)	$	(38.5	)	n/a		$	144.7	$	139.0	-69	%	$	449.9
U.S. rig count(1)		936		-50	%		1,865		1,387	-23	%		1,808
Mexico rig count(1)		128		21	%		106		121	23	%		98
Total U.S./Mexico		1,064		-46	%		1,971		1,508	-21	%		1,906

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

Results for the three months ended June 30, 2009 and 2008

Our U.S./Mexico Pressure Pumping operations third fiscal quarter 2009 revenue declined 55% with average active drilling rigs for the U.S. and Mexico decreasing 46% during the same period. This decrease was attributable to lower fracturing and cementing activity in the United States, coupled with reductions in pricing for our services and products. Mexico revenues increased sequentially, due to increased activity both onshore and offshore.

Operating margin for U.S./Mexico Pressure Pumping decreased to a loss of (12.3)% in the third quarter from a positive operating margin of 20.7% in the same quarter last year. The lower operating margin was primarily attributable to lower drilling activity and lower pricing for our services and products, further impacted by $5.7 million of fixed asset impairment charges, $4.7 million in inventory charges and $2.6 million in employee severance costs in the third quarter.

Results for the nine months ended June 30, 2009 and 2008

Our U.S./Mexico Pressure Pumping operations first nine months of fiscal 2009 revenue declined 24% with average active drilling rigs for the U.S. and Mexico decreasing 21% when compared to the same period of fiscal 2008. This revenue decrease was primarily the result of lower pricing and decreased demand for our products and services within the U.S. market partially offset by increased activity in Mexico.

Operating income margin decreased from 22.6% in the first nine months of fiscal 2008 to 9.2% during the same period of 2009 as increased competition in the United States resulted in lower pricing for our

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products and services. The results for the nine months ended June 30, 2009 also include $13.9 million of non-cash charges related to excess or idle fixed assets, $4.7 million in inventory charges and $4.2 million in employee severance costs.

Canada Pressure Pumping

	Three Months Ended June 30,								Nine Months Ended June 30,
(dollars in millions)	2009			% Change		2008			2009		% Change		2008
Revenue	$	23.3		-52	%	$	48.6		$	250.4	-19	%	$	308.8
Operating income (loss)	$	(15.6	)	6	%	$	(16.6	)	$	19.1	29	%	$	14.9
Canadian rig count(1)		91		-46	%		169			276	-20	%		344

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

Results for the three months ended June 30, 2009 and 2008

Canadian Pressure Pumping revenue decreased $25.3 million, or 52%, for the third fiscal quarter of 2009 compared to the same period of fiscal 2008, primarily as a result of decreased cementing and fracturing activity, as well as lower pricing. Average drilling rig count in Canada was down 46% for the comparable quarters, as many operators were slower to resume drilling activities after spring break-up in fiscal 2009 due to adverse market conditions.

Operating loss for the third quarter of 2009 was $15.6 million, slightly improved from the $16.6 million loss in the same quarter in the previous year. The operating loss for the fiscal third quarter of 2009 was lower than in fiscal 2008, despite the significantly lower revenue, primarily as a result of lower material and fuel costs in fiscal 2009, and a more favorable job mix.

Results for the nine months ended June 30, 2009 and 2008

Canadian Pressure Pumping revenue decreased $58.3 million, or 19%, for the first nine months of fiscal 2009 compared to the same period of fiscal 2008. The weakening Canadian dollar compared to the U.S. dollar during the comparable periods accounts for approximately $51.3 million of this revenue decrease. In addition, decreased demand and recent lower pricing for our services and products negatively impacted revenue for the comparable periods. Average drilling rig count in Canada was down 20% for the comparable periods.

Operating income margin improved to 7.6% for the nine months ended June 30, 2009, from 4.8% during the same period in the prior year, as a result of a more favorable job mix and lower fuel costs in the current year compared to the prior year partially offset by $1.3 million in employee severance costs in fiscal 2009.

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International Pressure Pumping

	Three Months Ended June 30,						Nine Months Ended June 30,
(dollars in millions)	2009		% Change		2008		2009		% Change		2008
Revenue	$	264.8	-16	%	$	316.9	$	870.4	-3	%	$	897.6
Operating income	$	24.5	-46	%	$	45.2	$	91.6	-21	%	$	115.9
International rig count, excluding Mexico(1)		854	-13	%		978		911	-4	%		951

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

Results for the three months ended June 30, 2009 and 2008

The following table summarizes the percentage change in revenue for each of the operating segments within the International Pressure Pumping reportable segment, comparing the third fiscal quarter of 2009 with the comparable quarter of fiscal 2008:

	% Change in Revenue
Europe	-23	%
Middle East	-11	%
Asia Pacific	-5	%
Russia	-61	%
Latin America	-18	%

International Pressure Pumping revenue of $264.8 million in the third fiscal quarter of 2009 decreased 16% compared to the same period in the prior year, with our Russia and Europe operations experiencing the largest percentage decrease. International drilling rig activity decreased 13% over the same time period. The decline in Europe is primarily due to lower activity and lower pricing in the North Sea. The Middle East decrease was primarily the result of decreased activity and lower pricing in Saudi Arabia and Kazakhstan. Latin America was negatively impacted by industry-wide labor strikes in Argentina and decreased activity in Venezuela and other areas in the region. The Asia Pacific decrease reflects decreased activity levels in New Zealand and China, partially offset by increased activity in Malaysia and Vietnam.

Our activity in Russia decreased year-over-year as we continue to wind-down activity with our final remaining contract, which concluded in July 2009. As we exit the Russian pressure pumping market, we expect to reclassify our historical Russian operating results as discontinued operations during the fourth quarter of fiscal 2009.

Operating income margins from our International Pressure Pumping operations decreased from 14.3% in the third quarter of fiscal 2008 to 9.2% in the third quarter of fiscal 2009. The decreased operating margin is largely attributable to a high fixed cost structure in Russia required to maintain operations on the single remaining contract in advance of exiting that market coupled with activity declines and pricing pressures in certain other international markets. Third quarter fiscal 2009 results also included $2.0 million of severance costs, $1.5 million of asset impairment charges and $1.4 million of inventory charges, representing 1.9% of revenues in the segment.

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Results for the nine months ended June 30, 2009 and 2008

The following table summarizes the percentage change in revenue for each of the operating segments within the International Pressure Pumping reportable segment, comparing the first nine months of fiscal 2009 with the comparable period of fiscal 2008:

	% Change in Revenue
Europe	-11	%
Middle East	-4	%
Asia Pacific	13	%
Russia	-39	%
Latin America	-2	%

International Pressure Pumping revenue of $870.4 million in the first nine months of fiscal 2009 decreased 3% compared to the same period in the prior year. Average international drilling rig activity declined 4% over the same time period. The increased revenue in Asia Pacific is largely attributable to increased activity in Malaysia and Thailand. The modest decline in Latin America revenue was the result of industry-wide labor strikes in Argentina, largely offset by activity-related increases in Brazil and Venezuela.

Revenues in Europe decreased largely as a result of unfavorable exchange rates primarily in the first quarter of fiscal 2009, which caused local currency billings to translate into fewer U.S. dollars, combined with lower activity and lower pricing in the North Sea. In the Middle East, the favorable impact of increased activity and new service contracts in North Africa was offset by lower rig activity in India, Kazakhstan and Saudi Arabia. Russia was negatively impacted by the completion of a significant service contract during the first quarter of 2009 and the wind-down activities described above.

Operating income margin from our International Pressure Pumping operations decreased from 12.9% in the first nine months of fiscal 2008 to 10.5% in the first nine months of fiscal 2009. The decreased operating margins are largely attributable to a high fixed cost structure in Russia required to maintain operations on the single remaining contract in advance of exiting that market, severance costs totaling $4.8 million associated with our initiative to align our workforce with current market conditions, a $4.2 million charge related to a denied value added tax refund claim in the Asia Pacific, $1.5 million of fixed asset impairment charges and $1.4 million of inventory charges.

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Oilfield Services Group

	Three Months Ended June 30,						Nine Months Ended June 30,
(dollars in millions)	2009		% Change		2008		2009		% Change		2008
Revenue	$	184.9	-30	%	$	264.5	$	641.2	-9	%	$	702.0
Operating income		10.9	-79	%		51.8		72.6	-45	%		132.9

Results for the three months ended June 30, 2009 and 2008

The following table summarizes the percentage change in revenue for each of the operating segments within the Oilfield Services Group, comparing the third fiscal quarter of 2009 with the comparable quarter of fiscal 2008:

	% Change in Revenue
Tubular Services	-25	%
Process & Pipeline Services	-28	%
Chemical Services	-21	%
Completion Tools	-34	%
Completion Fluids	-49	%

Revenues from our Oilfield Service Group decreased 30% to $184.9 million in the third quarter of fiscal 2009 compared to the same period in fiscal 2008, with the most significant percentage decreases from businesses most impacted by declines in U.S. Gulf of Mexico drilling activity and the seasonal spring break-up in Canada. Process & Pipeline Services revenues declined primarily due to the completion of certain large international projects between the two periods. Tubular Services revenues declined primarily due to lower service activity primarily in the Gulf of Mexico and Asia Pacific. Chemical Services and Completion Fluids revenues declined primarily as a result of decreased activity in the United States. Completion Tools revenues declined primarily due to lower sales both in the United States and internationally.

Operating income margin for the Oilfield Services Group for the third fiscal quarter of 2009 decreased to 5.9% compared to 19.6% in the third fiscal quarter of fiscal 2008, primarily as a result of the decreased activity described in the previous paragraph and start-up costs incurred in 2009 related to an offshore Completion Fluids project in Mexico.

Results for the nine months ended June 30, 2009 and 2008

The following table summarizes the percentage change in revenue for each of the operating segments within the Oilfield Services Group, comparing the first nine months of fiscal 2009 with the comparable period of fiscal 2008:

	% Change in Revenue
Tubular Services	-13	%
Process & Pipeline Services	-14	%
Chemical Services	-1	%
Completion Tools	1	%
Completion Fluids	-11	%

Revenues from our Oilfield Service Group decreased 9% to $641.2 million in the first nine months of fiscal 2009 compared to the same period in fiscal 2008. Tubular Services declined primarily as a result of lower service activity in the U.S. Gulf of Mexico and Asia Pacific. Process & Pipeline Services was negatively

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impacted by a combination of decreased activity in North America and the conclusion of certain large international projects in the prior year. Chemical Services showed only a modest decline as increased capillary work in the United States and internationally substantially offset the impact of lower activity in the United States. Completion Fluids decreased primarily as a result of large international project revenues in the prior year that did not repeat in the current year coupled with decreased activity in the United States. Completion Tools showed modest improvement due to the inclusion of the Innicor Subsurface Technologies business, which was acquired in May 2008, mostly offset by lower sales both in the United States and internationally.

Operating income margin for the Oilfield Services Group for the first nine months of fiscal 2009 decreased to 11.3% compared to 18.9% for the same period of fiscal 2008, primarily as a result of lower activity and, to a lesser extent, lower pricing and a difference in product / service mix.

Other Operating Expenses

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

	Three Months Ended June 30,				Nine Months Ended June 30,
	2009		2008		2009		2008
Research and engineering	$	15,922	$	18,563	$	50,137	$	54,674
Marketing		25,933		29,400		83,462		89,996
General and administrative		36,225		40,401		119,485		118,683
Loss on disposal of assets, net		9,706		631		12,111		243
Pension settlement		—		—		21,695		—

Research and engineering: Research and engineering expense decreased 14% and 8% comparing the three and nine months ended June 30, 2009 to the corresponding periods in the prior fiscal year, respectively, primarily as a result of cost reductions implemented during the 2009 periods in response to prevailing market conditions. As a percentage of revenue, this expense increased to 2.0% for the three months ended June 30, 2009 from 1.4% in the same period in the prior fiscal year and increased slightly to 1.5% from 1.4% as a percentage of revenue for the nine months ended June 30, 2009 compared to the same period of fiscal 2008. These increases as a percentage of revenue are primarily the result of the lower revenue base.

Marketing:Marketing expense decreased $3.5 million and $6.5 million for the three and nine months ended June 30, 2009, respectively, compared to the same periods in the prior fiscal year primarily as a result of cost reductions implemented during the 2009 in response to prevailing market conditions. As a percentage of revenue, marketing expense was 3.3% for the three months ended June 30, 2009 compared to 2.2% for the corresponding period in fiscal year 2008 and 2.5% for the nine months ended June 30, 2009 compared to 2.3% for the same period of fiscal 2008. These increases in marketing cost as a percentage of revenue are largely a function of the lower revenue base.

General and administrative:General and administrative expense decreased $4.2 million, or 10%, in the three months ended June 30, 2009 compared to the same period in fiscal 2008, and was relatively flat for the nine months ended June 30, 2009 compared to the same period in the prior year. The improvement for the three months ended June 30, 2009 was the result of cost reduction measures introduced in the second and third quarters of fiscal 2009. As a percentage of revenue, general and administrative expense increased from 3.0% in the third quarter fiscal 2008 to 4.6% for the same period of fiscal 2009 and from 3.0% for the nine months ended June 30, 2008 to 3.7% for the same period of fiscal 2009 primarily due to the impact of unfavorable pricing pressure on our revenue.

Loss on disposal of assets, net: Loss on disposal of assets, net of gains, increased significantly in fiscal 2009 compared to 2008, primarily as a result of non-cash fixed asset impairment charges totaling $7.2 million recorded in the third fiscal quarter of 2009. These charges related to certain cementing and stimulation equipment that was not economical to repair or maintain in the current market environment.

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Pension settlement: In September 2006, we entered into an agreement with an insurance company to settle our obligation with respect to the U.S. defined benefit pension plan. Plan assets of approximately $72 million were used to purchase an insurance contract to fund the benefits and settle the plan. In December 2008, we received approval from the Pension Benefit Guaranty Corporation and the Internal Revenue Service and were relieved of primary responsibility for the pension benefit obligation. Consequently, we recorded a non-cash pre-tax charge of $21.7 million in connection with the settlement in the first fiscal quarter of fiscal 2009.

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

	Three Months Ended June 30,						Nine Months Ended June 30,
	2009			2008			2009			2008
Interest expense	$	(7,057	)	$	(6,596	)	$	(20,566	)	$	(21,407	)
Interest income		334			554			1,197			1,384
Net interest expense	$	(6,723	)	$	(6,042	)	$	(19,369	)	$	(20,023	)

Interest expense increased $0.5 million in three months ended June 30, 2009 compared to the same period of fiscal 2008, primarily as a result of higher average interest rates on outstanding debt partially offset by lower average outstanding borrowings when comparing the respective periods. In June 2008, we refinanced $250 million of variable rate Senior Notes with $250 million of fixed rate 6% Senior Notes. Interest expense decreased $0.8 million in nine months ended June 30, 2009 compared to the same period of fiscal 2008, primarily as a result of lower average outstanding borrowings when comparing the respective periods. Outstanding debt balances decreased from $601.2 million at June 30, 2008 to $520.4 million at June 30, 2009. Interest income was fairly consistent with the same periods in the prior year, as higher average invested balances were offset by lower prevailing interest rates.

Other expense, net:Other expense, net, was made up of the following (in thousands):

	Three Months Ended June 30,						Nine Months Ended June 30,
	2009			2008			2009			2008
Minority interest	$	(3,721	)	$	(3,817	)	$	(8,348	)	$	(6,761	)
Non-operating net foreign exchange gain (loss)		(973	)		(274	)		(567	)		259
Legal settlement		—			—			3,569			—
Other, net		44			902			1,228			1,655
Other expense, net	$	(4,650	)	$	(3,189	)	$	(4,118	)	$	(4,847	)

Other expense, net increased $1.5 million in the three-month period and improved $0.7 million in the nine–month period ended June 30, 2009, compared to the corresponding periods of fiscal 2008. The increase in expense in the three-month period was attributable to increased foreign exchange loss in fiscal 2009, due to volatility in currency markets, coupled with a decrease in other miscellaneous income. The improvement in the nine-month period was primarily a result of a legal settlement involving a commercial dispute, which was recorded in the first quarter of fiscal 2009, partially offset by increased minority interest expense. The increased minority interest expense reflects improved operating results from our international joint venture operations.

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Income Tax Expense

Primarily as a result of lower profit forecast for our North American operations, and the resulting change in the geographic mix of our expected pre-tax income for fiscal 2009, our expected effective tax rate for fiscal 2009 changed from 28% as of March 31, 2009, to 25% as of June 30, 2009. Accordingly, we revised our year-to-date income tax expense to reflect these revised expectations. Our effective tax rate decreased from 28% for the three months ended June 30, 2008 to a benefit of 40% for the three months ended June 30, 2009, primarily due to the adjustment in the current fiscal year quarter to align our year-to-date effective tax rate with our current anticipated full fiscal year tax rate of 25%.

Our effective tax rate decreased from 29% for the nine months ended June 30, 2008 to 25% for the nine months ended June 30, 2009, primarily due to the decline in current year estimated taxable income in our higher tax jurisdictions, partially offset by the impact of a Canadian statutory tax rate decrease reflected in the prior year.

Liquidity and Capital Resources

Historical Cash Flow

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

	Nine Months Ended June 30,
	2009			2008
Cash flow from operations	$	505.4		$	586.0
Cash used in investing		(310.0	)		(477.7	)
Cash used in financing		(112.1	)		(82.8	)
Effect of exchange rate changes on cash		(2.3	)		(1.2	)
Change in cash and cash equivalents	$	81.0		$	24.3

Cash flow from operations of $505.4 million for the nine months ended June 30, 2009 decreased $80.6 million, or 14%, compared to the same period in the prior year. Net income of $159.9 million in the first nine months of fiscal 2009 was $281.4 million lower than the same period in fiscal 2008, primarily as a result of the market downturn caused by lower demand for our services and products. Non-cash items included in net income, primarily including depreciation and amortization, stock-based compensation expense, pension settlement and net loss on disposal of assets, totaled $321.1 million for the first nine months of fiscal 2009, compared to $227.4 million for the same period in fiscal 2008. Finally, changes in working capital and other operating accounts generated cash of $24.4 million in the first nine months of fiscal 2009, compared to using cash of $82.7 million for the first nine months of fiscal 2008, primarily as a result of the decline in market activity which led to reductions in working capital.

Cash used in investing activities decreased $167.7 million, or 35%, in fiscal 2009 compared to fiscal 2008, as a result of a decrease in capital expenditures, primarily as a result of lower expansion capital needed due to lower demand for our products and services.

Cash used in financing activities increased $29.3 million, or 35%, in fiscal 2009 compared to fiscal 2008. This change was primarily a result of a treasury stock purchase of $44.2 million during current fiscal year partially offset by higher debt repayments during the nine months ended June 30, 2008 compared to the same period of 2009.

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Liquidity and Capital Resources

Cash flows from operations are expected to be our primary source of liquidity for the remainder of fiscal 2009. Our sources of liquidity also include cash and cash equivalents of $231.3 million at June 30, 2009 and the available financing facilities listed below (in millions):

Financing Facility	Expiration	Borrowings at June 30, 2009		Available at June 30, 2009
Revolving Credit Facility	August 2012	$	—	$	400.0
Discretionary	Various times within the next 12 months		21.5		16.6

As of June 30, 2009, the Company had $249.9 million of the 5.75% Senior Notes due 2011 and $249.0 million of the 6% Senior Notes due 2018 issued and outstanding, net of discount.

Our amended and restated revolving credit facility (the “Revolving Credit Facility”) permits borrowings of up to $400 million in principal amount. The Revolving Credit Facility includes a $50 million sublimit for the issuance of standby letters of credit and a $20 million sublimit for swingline loans. Swingline loans have short-term maturities and the remaining amounts outstanding under the Revolving Credit Facility become due and payable in August 2012. In addition, we have the right to request up to an additional $200 million over the permitted borrowings of $400 million, subject to the approval of our lenders at the time of the request. Depending on the amount of borrowings outstanding under this facility, the interest rate applicable to borrowings generally ranges from 30-40 basis points above LIBOR. We are charged various fees in connection with the Revolving Credit Facility, including a commitment fee based on the average daily unused portion of the commitment, totaling $0.2 million for the nine months ended June 30, 2009. In addition, the Revolving Credit Facility charges a utilization fee on all outstanding loans and letters of credit when usage of the Revolving Credit Facility exceeds 62.5%, although there were no material fees for the nine months ended June 30, 2009. There were no borrowings outstanding under the Revolving Credit Facility at June 30, 2009.

In May 2008, we entered into a Committed Credit Facility with a commercial bank to finance our acquisition of Innicor Subsurface Technologies Inc. There were no commitment fees required by this facility, and the interest rate was based on market rates on the dates that amounts were borrowed. This facility expired in May 2009 and was repaid with cash on hand.

In addition to the Revolving Credit Facility, we had available $16.6 million of discretionary lines of credit available at June 30, 2009, which expire at the bank’s discretion. These discretionary lines are unsecured. 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 were $21.5 million in outstanding borrowings under these lines of credit at June 30, 2009, representing borrowings in foreign currencies. The weighted average interest rate on short-term borrowings outstanding under these discretionary lines as of June 30, 2009 was 16.2%.

Many of our customers are currently experiencing reduced cash flows as a result of lower commodity prices, higher borrowing costs and reduced availability of credit in the current economic environment. If such conditions persist, we may experience increased delays or nonpayment of our accounts receivable, which could have a material adverse impact on our results of operations, cash flows and financial condition. We have experienced an increased delay in payment from one of our significant national oil company customers in Latin America.

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, pay a regular quarterly dividend and support the development of our short-term and long-term

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operating strategies. If the discretionary lines of credit are not renewed, or if borrowings under these lines of credit otherwise become unavailable, we expect to refinance this debt by arranging additional committed bank facilities or through other long-term borrowing alternatives.

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

Cash Requirements

We had $314.4 million of capital expenditures during the nine months ended June 30, 2009. In response to anticipated decline in demand for our services and products resulting from the global economic slowdown, we have reduced our planned capital expenditures for fiscal 2009 considerably. We currently anticipate capital expenditures in the fiscal fourth quarter of 2009 to be $100-125 million, and we expect capital expenditures in fiscal 2010 to be substantially lower than in fiscal 2009. The actual amount of fiscal 2009 and 2010 capital expenditures will depend primarily on maintenance requirements and market opportunities and our ability to execute our planned capital expenditures.

We expect our minimum pension and postretirement funding requirements to be approximately $14.4 million in fiscal 2009. We contributed $10.8 million to such plans during the nine months ended June 30, 2009.

We have paid cash dividends in the amount of $0.05 per common share each quarter since the fourth quarter of fiscal 2005. For the nine months ended June 30, 2009, we paid cash dividends totaling $43.9 million. We anticipate paying a quarterly cash dividend of $0.05 per common share for the remainder of fiscal 2009. However, dividends are subject to approval by our Board of Directors each quarter, and the Board has the ability to change the dividend policy at any time.

As of June 30, 2009, we had $249.9 million of 5.75% Senior Notes due 2011 and $249.0 million of 6% Senior Notes due 2018 issued and outstanding, net of discount. We expect cash paid for interest expense to be approximately $32 million in fiscal 2009.

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

Investigations Regarding Misappropriation and Possible Illegal Payments

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

Off Balance Sheet Transactions

In 1999, we contributed certain pumping service equipment to a limited partnership, in which we own a 1% interest. The equipment is used to provide services to our customers for which we pay a service fee over a period of at least six years, but not more than 13 years, at approximately $12 million annually. This is accounted for as an operating lease. We assessed the terms of this agreement and determined it was a variable interest entity as defined in Financial Accounting Standards Board (“FASB”) Interpretation No. 46(R),Consolidation of Variable Interest Entities. However, we were not deemed to be the primary beneficiary, and therefore, consolidation was not required. The transaction resulted in a gain that is being deferred and

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amortized over the partnership term. The partnership 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. Substitution activity during the partnership term has reduced the balance of the deferred gain to zero at June 30, 2009, compared to $4.2 million as of September 30, 2008. In 2010, we have the option, but not the obligation, to purchase the pumping service equipment in the limited partnership for approximately $46 million. We currently intend to exercise this option. The option price to purchase the equipment under the partnership depends in part on the fair market value of the equipment held by the partnership at the time the option is exercised, as well as other factors specified in the agreement.

Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 168,Codification and the Hierarchy of Generally Accepted Accounting Principles (“GAAP”) (“SFAS 168”) (FASB Accounting Standard Codification (“ASC”) 105-10) establishing an authoritative United States GAAP superseding all pre-existing accounting standards and literature. SFAS 168 is effective for financial statements issued for interim and annual periods after September 15, 2009. In response, we will change the accounting literature references contained in our SEC filings subsequent to that date without material impact on our financial statements.

In June 2009, the FASB issued SFAS No. 167,Amendments to FASB Interpretation (“FIN”) No. 46(R) (“SFAS 167”) which addresses the addition of qualified special purpose entities into the scope of FIN46(R) as the concept of these entities was eliminated by SFAS 166. This statement also modifies the analysis by which a controlling interest of a variable interest entity is determined thereby requiring the controlling interest to consolidate the variable interest entity. A controlling interest exists if a party to a variable interest entity has both (i) the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance and (ii) the obligation to absorb losses of or receive benefits from the entity that could be potentially significant to the variable interest entity. This statement could impact the way we account for our limited partnership discussed in Note 5 underLease and Other Long-Term Commitments. SFAS 167 becomes effective as of the beginning of the first annual reporting period beginning after November 15, 2009 and should be applied prospectively for interim and annual periods during that period going forward. We will adopt the provisions of SFAS 167 on October 1, 2010, and have not yet determined the impact, if any, on our consolidated financial statements.

In June 2009, the FASB issued SFAS No. 166,Accounting for Transfers of Financial Assets (“SFAS 166”) which eliminates the concept of a qualified special purpose entity and enhances guidance related to derecognition of transferred assets. SFAS 166 becomes effective as of the beginning of the first annual reporting period beginning after November 15, 2009 and should be applied prospectively for interim and annual periods during that period going forward. We will adopt the provisions of SFAS 166 on October 1, 2010, and have not yet determined the impact, if any, on our consolidated financial statements.

On June 30, 2009, we adopted FASB Staff Position (“FSP”) 107-1 and Accounting Principles Board (“APB”) 28-1,Interim Disclosures about Fair Value of Financial Instruments, which amends SFAS No. 107 and requires publicly-traded companies to disclose the fair value of financial instruments in their interim financial statements.

In May 2009, the FASB issued SFAS No. 165,Subsequent Events(“SFAS 165”) (FASB ASC 855-10). The objective of this statement is to establish general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This standard is effective for reporting periods ending after June 15, 2009. We adopted this standard in our June 30, 2009 condensed consolidated financial statements.

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In December 2008, the FASB issued FASB Staff Position 132 (R)-1Employer’s Disclosures about Postretirement Benefit Plan Assets (“FSP 132 (R)-1”) (FASB ASC 715-20-65-2). FSP 132 (R)-1 amends FASB Statement No. 132 (revised 2003),Employers’ Disclosures about Pension and Other Postretirement Benefits, requiring the disclosure of major categories of plan assets, investment policies and strategies, fair value measurement of plan assets and significant concentration of credit risks related to defined benefit pension or other postretirement plans. FSP 132 (R)-1 is effective for fiscal years ending after December 15, 2009. We will adopt the new disclosure requirements of FSP 132 (R)-1 in fiscal 2010.

In April 2008, the FASB issued FSP 142-3,Determination of the Useful Life of Intangible Assets (“FSP 142-3”) (FASB ASC 350-30-65-1). FSP 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142,Goodwill and Other Intangible Assets (“SFAS 142”). The objective of FSP 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141(R),Business Combinations (FASB ASC 805-10,20,30,40,50,740), and other U.S. generally accepted accounting principles. FSP 142-3 is effective for the Company beginning October 1, 2009. We are currently in the process of evaluating the impact of FSP 142-3 on our financial statements.

In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS 161”) (FASB ASC 815-10). SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under SFAS 133, and its related interpretations, and (3) how derivative instruments and related hedged items affect an entity's financial position, financial performance and cash flows. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008. Accordingly, we adopted SFAS 161 in the second quarter of fiscal 2009. We currently have no derivative financial instruments subject to accounting or disclosure under SFAS 133; therefore, the adoption of SFAS 161 had no effect on our consolidated statements of financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations (“SFAS 141(R)”), replacing SFAS No. 141,Business Combinations (“SFAS 141”) (FASB ASC 805-10,20,30,40,50,740). SFAS 141(R) retains the fundamental requirements in SFAS 141 that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS 141(R) defines the acquirer as the entity that obtains control of one or more businesses in the business combination and establishes the acquisition date as the date that the acquirer achieves control. SFAS 141(R) establishes principles and requirements for how the acquirer:

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

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

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

This statement is effective for business combinations occurring on or after the beginning of the first annual reporting period beginning after December 15, 2008. We will adopt SFAS 141(R) on October 1, 2009 for acquisitions beginning on or after that date.

In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements(“SFAS 160”) (FASB ASC810-10-65-1), amending previous guidance to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of

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a subsidiary. SFAS 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest and requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS 160 requires expanded disclosures in the consolidated financial statements that identify and distinguish between the interests of the parent’s owners and the interests of the noncontrolling owners of a subsidiary and shall be applied prospectively as of the beginning of the fiscal year in which initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. SFAS 160 is effective for fiscal years beginning after December 15, 2008 (our fiscal year beginning October 1, 2009). We do not have significant noncontrolling interests in consolidated subsidiaries.

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements (“SFAS 157”) (FASB ASC 820-10), effective for financial statements issued for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FSP 157-2 (FASB ASC 820-10-15-1A), delaying the effective date of SFAS 157 for non-financial assets and liabilities to fiscal years beginning after November 15, 2008. 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. On October 1, 2008, we adopted without material impact on our consolidated financial statements the provisions of SFAS 157 related to financial assets and liabilities. We will adopt the provisions of SFAS 157 related to non-financial assets and liabilities on October 1, 2009, and have not yet determined the impact, if any, of these provisions of SFAS 157 on our consolidated financial statements.

In April 2009, the FASB issued FSP 157-4,Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, which provides additional guidance for estimating fair value in accordance with SFAS 157 when the volume and level of activity for the asset or liability have significantly decreased. This FSP emphasizes that even if there has been a significant decrease in the volume and level of activity for the asset or liability and regardless of the valuation technique(s) used, the objective of a fair value measurement remains the same. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction (that is, not a forced liquidation or distressed sale) between market participants under current market conditions. We adopted FSP 157-4 on June 30, 2009 and will apply it prospectively to all fair value measurements where appropriate.

Forward Looking Statements

This document contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities Exchange Act of 1934 concerning, among other things, our prospects, expected revenue, expenses and profits, developments and business strategies for our operations, all of which are subject to certain risks, uncertainties and assumptions. These forward-looking statements include all statements other than historical fact, including those identified as “Outlook” and by the use of terms and phrases such as “expect,” “estimate,” “project,” “forecast,” “believe,” “achievable,” “anticipate,” “should” and similar terms and phrases that convey the uncertainty of future events or outcomes. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances but that may not prove to be accurate.

Such statements are subject to risks and uncertainties, including, but not limited to, general economic and business conditions; global economic growth and activity; oil and natural gas market conditions; political and economic uncertainty; and other risks and uncertainties described elsewhere in this Report and in our Annual Report on Form 10-K. 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. Forward-looking statements speak only as of the date they are made and, other than as required under securities laws, we do not assume a duty to update or revise these forward-looking statements.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk from foreign currency fluctuations internationally and from changing interest rates, primarily in the United States, Canada and Europe. A discussion of our primary market risk exposure is included in Part II, Item 7A of our Annual Report on Form 10-K the year ended September 30, 2008. No events or transactions have occurred during the nine-month period ended June 30, 2009, which would materially change the information disclosed in our Annual Report on Form 10-K with respect to market risk.

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. As of the end of the period covered by this quarterly report, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act of 1934, as amended (the “Exchange Act”). This evaluation was carried out under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of the Company. Based on their evaluation of our disclosure controls and procedures, as defined by Rule 13a-15(e) of the Exchange Act, these officers have concluded that as of the end of the period covered by this report, the disclosure controls and procedures are effective.

PART II

OTHER INFORMATION

Item 1. Legal Proceedings

The information regarding litigation and environmental matters described in Note 5 of the Notes to Unaudited Condensed Consolidated 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 nine-month period ended June 30, 2009 in our “Risk Factors” as discussed in our Form 10-K for the fiscal year ended September 30, 2008.

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

(a) None

(b) None

(c) None

Item 3. Defaults upon Senior Securities

None

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

None

Item 5. Other Information

None

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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.

* Filed herewith.

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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 7, 2009	By:	/s/ J. W. Stewart
		J. W. Stewart
		Chairman of the Board, President and Chief Executive Officer
Date: August 7, 2009	By:	/s/ Jeffrey E. Smith
		Jeffrey E. Smith
		Executive Vice President - Finance and Chief Financial Officer

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