BJ Services 10-Q 2009 Q1 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 March 31, 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  þ    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  þ	Accelerated filer  ¨	Non-accelerated filer  ¨	Smaller reporting company  ¨
		(Do not check if a 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  þ

There were 292,071,483 shares of the registrant’s common stock, $0.10 par value, outstanding as of April 30, 2009.

BJ SERVICES COMPANY

INDEX

PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements
Condensed Consolidated Statement of Operations (Unaudited) – Three and six months ended March  31, 2009 and 2008		3
Condensed Consolidated Statement of Financial Position (Unaudited) – March 31, 2009 and September 30, 2008		4
Condensed Consolidated Statement of Stockholders’ Equity and Other Comprehensive Income (Unaudited) – Six months ended March 31, 2009		5
Condensed Consolidated Statement of Cash Flows (Unaudited) – Six months ended March  31, 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	16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31
Item 4.	Controls and Procedures	31
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	31
Item 1A.	Risk Factors	31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 3.	Defaults upon Senior Securities	31
Item 4.	Submission of Matters to a Vote of Security Holders	31
Item 5.	Other Information	32
Item 6.	Exhibits	32

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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 March 31,						Six Months Ended March 31,
	2009			2008			2009			2008
Revenue	$	1,054,607		$	1,283,202		$	2,486,249		$	2,568,267
Operating expenses:
Cost of sales and services		909,543			1,004,107			2,008,775			1,954,557
Pension settlement		—			—			21,695			—
Research and engineering		17,095			18,913			34,215			36,111
Marketing		26,784			31,764			57,529			60,596
General and administrative		40,839			41,652			83,260			78,282
Loss (gain) on disposal of assets, net		2,377			238			2,405			(388	)
Total operating expenses		996,638			1,096,674			2,207,879			2,129,158
Operating income		57,969			186,528			278,370			439,109
Interest expense		(7,410	)		(6,949	)		(13,491	)		(14,811	)
Interest income		348			356			863			830
Other income (expense), net		(920	)		1,053			532			(1,658	)
Income before income taxes		49,987			180,988			266,274			423,470
Income tax expense		6,999			53,685			74,048			123,983
Net income	$	42,988		$	127,303		$	192,226		$	299,487
Earnings per share:
Basic	$	0.15		$	0.43		$	0.66		$	1.02
Diluted	$	0.15		$	0.43		$	0.65		$	1.01
Weighted-average shares outstanding:
Basic		292,054			293,245			292,373			292,934
Diluted		293,447			295,285			293,572			295,182

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

(UNAUDITED)

(In thousands)

	March 31, 2009		September 30, 2008
ASSETS
Current assets:
Cash and cash equivalents	$	244,814	$	150,254
Receivables, net		931,453		1,151,236
Inventories, net:
Products		299,826		291,857
Work in process		17,016		22,418
Parts		201,456		193,600
Total inventories		518,298		507,875
Deferred income taxes		29,887		28,097
Prepaid expenses		71,095		83,065
Other current assets		36,281		40,623
Total current assets		1,831,828		1,961,150
Property, net		2,356,394		2,312,949
Deferred income taxes		19,189		20,859
Goodwill		977,845		975,451
Investments and other assets		51,581		51,499
Total assets	$	5,236,837	$	5,321,908
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	413,544	$	554,615
Short-term borrowings		63,511		57,610
Accrued employee compensation and benefits		119,022		148,451
Income and other taxes		63,909		86,549
Other accrued liabilities		178,981		172,995
Total current liabilities		838,967		1,020,220
Long-term debt		498,820		498,730
Deferred income taxes		166,120		153,923
Other long-term liabilities		193,081		207,228
Commitments and contingencies
Stockholders’ equity		3,539,849		3,441,807
Total liabilities and stockholders’ equity	$	5,236,837	$	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	—			—		—			—			192,226			—
Other comprehensive income, net of tax:
Cumulative translation adjustments	—			—		—			—			—			(75,528	)
Pension settlement, net of tax	—			—		—			—			—			10,083
Changes in defined benefit and other postretirement plans	—			—		—			—			—			13,958
Comprehensive income																		140,739
Dividends declared	—			—		—			—			(29,205	)		—			(29,205	)
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	377			—		—			16,785			(16,051	)		—			734
Other stock awards	151			—		(3,834	)		3,834			—			—			—
Stock based compensation	—			—		17,592			—			—			—			17,592
Tax benefit from exercise of options	—			—		216			—			—			—			216
Balance, March 31, 2009	292,062		$	34,752	$	1,114,951		$	(1,415,680	)	$	3,816,754		$	(10,928	)	$	3,539,849

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)

	Six Months Ended March 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	192,226		$	299,487
Adjustments to reconcile net income to cash provided by operating activities:
Pension settlement		21,695			—
Depreciation and amortization		148,005			127,666
Minority interest expense		4,627			2,944
Loss (gain) on disposal of assets, net		2,405			(388	)
Stock-based compensation expense		18,588			16,493
Excess tax benefits from stock-based compensation		(1,038	)		(12,566	)
Deferred income tax (benefit) expense		9,293			(8,300	)
Changes in:
Receivables		234,852			(29,841	)
Inventories		(6,963	)		1,995
Prepaid expenses		13,431			(1,047	)
Other current assets		(4,762	)		6,539
Accounts payable		(149,428	)		(33,848	)
Accrued employee compensation and benefits		(38,502	)		10,890
Current income tax		(8,135	)		6,127
Other current liabilities		(9,664	)		(7,108	)
Other, net		(31,060	)		(29,391	)
Net cash provided by operating activities		395,570			349,652
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(238,261	)		(311,786	)
Proceeds from disposal of assets		2,003			12,293
Net cash used in investing activities		(236,258	)		(299,493	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds (repayments) of short-term borrowings, net		5,901			(55,169	)
Dividends paid to shareholders		(29,311	)		(29,233	)
Purchase of treasury stock		(44,190	)		(2,089	)
Excess tax benefits from stock-based compensation		1,038			12,566
Net proceeds from exercise of stock options and stock purchase plan		9,807			16,369
Distributions to minority interest partners		(1,905	)		(3,829	)
Net cash used in financing activities		(58,660	)		(61,385	)
Effect of exchange rate changes on cash		(6,092	)		(3,325	)
Increase (decrease) in cash and cash equivalents		94,560			(14,551	)
Cash and cash equivalents at beginning of period		150,254			58,199
Cash and cash equivalents at end of period	$	244,814		$	43,648
Cash Paid for Interest and Taxes:
Interest, net of capitalized interest of $3,317 and $3,986	$	12,530		$	14,403
Taxes		37,566			100,696

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 March 31, 2009, our results of operations for the three and six-month periods ended March 31, 2009 and 2008, our statement of stockholders’ equity and other comprehensive income for the six-month period ended March 31, 2009, and our cash flows for the six-month periods ended March 31, 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 six-month period ended March 31, 2009 are not necessarily indicative of the results to be expected for the full year.

Note 2 Earnings Per Share

Basic earnings per share exclude dilution and are computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted earnings 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 per share for the periods presented (in thousands, except per share amounts):

	Three Months Ended March 31,				Six Months Ended March 31,
	2009		2008		2009		2008
Net income	$	42,988	$	127,303	$	192,226	$	299,487
Weighted-average common shares outstanding		292,054		293,245		292,373		292,934
Basic earnings per share	$	0.15	$	0.43	$	0.66	$	1.02
Weighted-average common and dilutive potential common shares outstanding:
Weighted-average common shares outstanding		292,054		293,245		292,373		292,934
Assumed exercise of dilutive instruments(1)		1,393		2,040		1,199		2,248
Weighted-average dilutive shares outstanding		293,447		295,285		293,572		295,182
Diluted earnings per share	$	0.15	$	0.43	$	0.65	$	1.01

⁽¹⁾ For the three and six-months ended March 31, 2009, 11.6 million and 12.6 million stock options, respectively, were excluded from the computation of diluted earnings per share due to their antidilutive effect. For the three and six-months ended March 31, 2008, 5.7 million and 3.0 million stock options, respectively, were excluded from the computation of diluted earnings per share due to their antidilutive effect.

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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 of services, have similar production processes and use the same methods to provide their services. They also serve the same or similar customers, which include major multi-national, independent and national or state-owned oil companies.

The Oilfield Services Group 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 other oilfield services, serve same or similar customers and some of the operating segments share resources.

The accounting policies of the segments are the same as those described in the summary of significant accounting policies in Note 2 of the Notes to the Consolidated Financial Statements included in our annual report on Form 10-K for the fiscal year ended September 30, 2008. Operating segment performance is evaluated based on operating income. Intersegment sales and transfers are not material.

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Summarized financial information concerning our segments is shown in the following table (in thousands):

	U.S./Mexico Pressure Pumping(1)		Canada Pressure Pumping		International Pressure Pumping		Oilfield Services Group		Corporate(2)			Total
Three Months Ended March 31, 2009
Revenue	$	475,576	$	95,371	$	276,664	$	206,996	$	—		$	1,054,607
Operating income (loss)		25,680		5,916		21,585		20,460		(15,672	)		57,969
Three Months Ended March 31, 2008
Revenue	$	635,870	$	138,790	$	292,120	$	216,422	$	—		$	1,283,202
Operating income (loss)		125,130		14,481		34,714		39,155		(26,952	)		186,528
Six Months Ended March 31, 2009
Revenue	$	1,197,122	$	227,181	$	605,632	$	456,314	$	—		$	2,486,249
Operating income (loss)		177,565		34,759		67,144		61,655		(62,753	)		278,370
Identifiable assets		1,643,293		481,001		1,510,871		966,456		635,216			5,236,837
Six Months Ended March 31, 2008
Revenue	$	1,290,012	$	260,136	$	580,632	$	437,487	$	—		$	2,568,267
Operating income (loss)		305,218		31,473		70,639		81,122		(49,343	)		439,109
Identifiable assets		1,619,231		535,962		1,377,151		961,710		436,767			4,930,821

(1) The “U.S./Mexico Pressure Pumping” results for the three and six months ended March 31, 2009 include an $8.2 million non-cash charge, $6.1 million of which was recorded in depreciation expense, related to excess or idle fixed assets.

(2) The “Corporate” column includes corporate expenses and assets not allocated to the operating segments. The six months ended March 31, 2009 includes a $21.7 million pension settlement charge (discussed in Note 6).

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

	Three Months Ended March 31,						Six Months Ended March 31,
	2009			2008			2009			2008
Total operating income for reportable segments	$	57,969		$	186,528		$	278,370		$	439,109
Interest expense		(7,410	)		(6,949	)		(13,491	)		(14,811	)
Interest income		348			356			863			830
Other income (expense), net		(920	)		1,053			532			(1,658	)
Income before income taxes	$	49,987		$	180,988		$	266,274		$	423,470

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

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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 for which it has not already provided.

Asbestos Litigation

In August 2004, certain predecessors of ours, along with numerous other defendants were named in four lawsuits filed in the Circuit Courts of Jones and Smith Counties in Mississippi. These four lawsuits included 118 individual plaintiffs alleging that they suffer various illnesses from exposure to asbestos and seeking damages. The lawsuits assert claims of unseaworthiness, negligence, and strict liability, all based upon the status of our predecessors as Jones Act employers. The plaintiffs were required to complete data sheets specifying the companies they were employed by and the asbestos-containing products to which they were allegedly exposed. Through this process, approximately 25 plaintiffs have identified us or our predecessors as their employer. Amended lawsuits were filed by four individuals against us and the remainder of the original claims (114) were dismissed. Of these four lawsuits, three failed to name us as an employer or manufacturer of asbestos-containing products so we were thereby dismissed. Subsequently an individual from one of these lawsuits brought his own action against us. As a result, we are currently named as 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.

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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.

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.

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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 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 March 31, 2009 and September 30, 2008, we had reserved approximately $4.0 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 therefore, consolidation was not required. The transaction resulted in a gain that is being deferred and amortized over 13 years. The balance of the deferred gain was $3.0 million and $4.2 million as of March 31, 2009 and September 30, 2008, respectively. The agreement permits substitution of equipment within the partnership as long as the implied fair value of the new property transferred in at the date of substitution equals or exceeds the implied fair value, as defined, of the current property in the partnership that is being replaced. As a result of such substitutions, the deferred gain was reduced by $0.7 million in the six-month period ended March 31, 2009. It is anticipated that substitution activity in the third quarter of fiscal 2009 will reduce the balance of the deferred gain to zero.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.

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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 March 31, 2009 (in thousands):

	Total Amounts Committed		Amount of commitment expiration per period
Other Commercial Commitments			Less than 1 Year		1–3 Years		4–5 Years		Over 5 Years
Standby letters of credit	$	33,995	$	33,995	$	—	$	—	$	—
Guarantees		214,524		94,889		62,712		46,897		10,026
Total other commercial commitments	$	248,519	$	128,884	$	62,712	$	46,897	$	10,026

Note 6 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 reduction 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 March 31,						Six Months Ended March 31,
	2009			2008			2009			2008
Service cost for benefits earned	$	1,654		$	1,680		$	3,308		$	3,360
Interest cost on projected benefit obligation		3,449			3,327			6,898			6,654
Expected return on plan assets		(2,829	)		(2,903	)		(5,658	)		(5,806	)
Recognized actuarial loss		615			604			1,230			1,208
Net amortization and deferral		—			(25	)		—			(50	)
Net pension cost	$	2,889		$	2,683		$	5,778		$	5,366

In fiscal 2009, we expect to contribute a total of $17.7 million to the defined benefit plans, which represents the legal or contractual minimum funding requirements and expected discretionary contributions. We have paid $6.5 million in contributions to defined benefit pension plans during the six months ended March 31, 2009. These contributions have been and are expected to be funded by cash flows from operating activities.

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

	Three Months Ended March 31,					Six Months Ended March 31,
	2009			2008		2009			2008
Service cost for benefits attributed to service during the period	$	—		$	1,033	$	865		$	2,066
Interest cost on accumulated postretirement benefit obligation		80			914		999			1,828
Net amortization and deferral		(1,458	)		—		(1,785	)		—
Net postretirement benefit cost (income)	$	(1,378	)	$	1,947	$	79		$	3,894

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 $0.6 million in postretirement contributions during the six months ended March 31, 2009.

Note 7 New Accounting Standards

In December 2008, the FASB issued FASB Staff Position 132 (R)-1Employer’s Disclosures about Postretirement Benefit Plan Assets (“FSP 132 (R)-1”). 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”). 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, and other U.S. generally accepted accounting principles. FSP 142-3 is effective for fiscal years beginning after December 15, 2008. We are currently in the process of evaluating the impact of FSP 142-3 on our financial statements.

In March 2008, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 161,Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS 161”). 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 statement of financial position, results of operations or cash flows.

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

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”), 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. We do not have significant noncontrolling interests in consolidated subsidiaries, and therefore, adoption of this standard is not expected to have a significant impact on our financial statements.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115 (“SFAS 159”). This Statement provides companies with an option to report selected financial assets and liabilities at fair value. Under SFAS 159, companies that elect the fair value option will report unrealized gains and losses in earnings at each subsequent reporting date. In addition, SFAS 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. The fair value option election is irrevocable, unless a new election date occurs. SFAS 159 is effective at the beginning of an entity’s first fiscal year beginning after November 15, 2007 and is to be applied prospectively, unless the entity elects early adoption. Consequently, we adopted SFAS 159 effective October 1, 2008 and elected not to apply the fair value option.

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

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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, 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 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 March 31,						Six Months Ended March 31,
	2009		% Change		2008		2009		% Change		2008
Rig Count:(1)
U.S.		1,326	-25	%		1,770		1,612	-9	%		1,780
Canada		329	-35	%		508		369	-15	%		432
International(2)		1,025	-2	%		1,046		1,058	3	%		1,032
Commodity Prices (average):
Crude Oil (West Texas Intermediate)	$	42.96	-56	%	$	97.94	$	50.70	-46	%	$	94.31
Natural Gas (Henry Hub)	$	4.57	-47	%	$	8.65	$	5.50	-30	%	$	7.82

(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 96 for the three-month periods ended March 31, 2009 and 2008, respectively, and 117 and 95 for the six-month periods ended March 31, 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 10 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 few months, tightening and uncertainty in the credit markets, and the global economic slowdown, drilling rig activity in the U.S. has continued its rapid decline from 2,031 rigs at September 12, 2008 to 945 at May 1, 2009, and we expect to see further reductions in U.S. drilling activity throughout fiscal 2009 compared to 2008. The magnitude and duration of reduction 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 10 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 decline throughout fiscal 2009 compared to 2008.

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 (“IOC’s”) and national oil companies (“NOC’s”) which tend to have different objectives and more operating stability than the typical independent producer in North America. During the last 10 years, the lowest annual international rig count, excluding Canada 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, with current prices approximately 70% 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, particularly in the U.S. market.

We expect average U.S. drilling rig activity to further decline to the 800-850 rig range by the end of June 2009, averaging roughly 30% below the second fiscal quarter average. Thereafter, we expect U.S. rig activity to continue to decline in the fiscal fourth quarter to the 700 rig range and stabilize at this level until natural gas supply and demand are more in balance. We anticipate that service and product pricing pressures

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will continue in most U.S. and Canadian markets as a result of the decline in drilling activity and competitive pressure driven by underutilized equipment capacity in the industry. We have undertaken a number of cost reduction measures to keep our cost structure in line with current business activity, including personnel reductions, a global wage freeze, reduced capital spending plans, supplier negotiations and working capital initiatives. We can make no assurances that these cost reductions will offset the impact of reductions in drilling activity or customer pricing.

We expect drilling activity in Canada to continue to decline from current levels heading into the third quarter, as the spring break-up period continues in the Canadian market, resulting in sequential revenue decline of over 50%. We expect revenues from International Pressure Pumping Services to be slightly lower in the fiscal third quarter when compared to the second quarter, but expect operating income in that segment to improve as a result of increased sales in higher margin businesses and due to cost reduction measures put into place in the second quarter.

We expect revenue and operating income improvement in the Oilfield Services Group as a result of several new contracts and international sales orders expected to ship during the upcoming quarter.

Results of Operations

Consolidated

	Three Months Ended March 31,						Six Months Ended March 31,
(dollars in millions)	2009		% Change		2008		2009		% Change		2008
Revenue	$	1,054.6	-18	%	$	1,283.2	$	2,486.2	-3	%	$	2,568.3
Operating income	$	58.0	-69	%	$	186.5	$	278.4	-37	%	$	439.1
Worldwide rig count(1)		2,680	-19	%		3,324		3,039	-6	%		3,244

(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 March 31, 2009 and 2008

All of our reportable segments were adversely impacted by a reduction in demand for oil and natural gas during the second fiscal quarter of 2009. Lower drilling activity and intense price competition for our services and products, especially in North America, drove our revenues to lower levels over the same quarter of the prior year.

Revenue for the three months ended March 31, 2009 decreased 18% when compared to the same period in the prior year and consolidated operating income for the period decreased 69%, primarily as the 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 income was a charge of $4.2 million in the International Pressure Pumping segment related to a denied value added tax refund claim, severance costs of $6.2 million and an $8.2 million non-cash charge related to excess or idle fixed assets in the U.S., partially offset by the reversal of $12.3 million in employee cash incentive accruals. For the three months ended March 31, 2009, consolidated operating income margins decreased to 5.5% from 14.5% reported in the same period of the prior fiscal year.

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Results for the six months ended March 31, 2009 and 2008

Our International Pumping Services and Oilfield Services segments experienced revenue growth for the first half of fiscal 2009 despite the impact of the global economic downturn. The integration of businesses acquired within the Oilfield Services Group in recent years and the procurement of new contracts in our International Pressure Pumping operations contributed to the higher revenue in these segments when compared to the same period of fiscal 2008. Lower drilling activity and intense price competition for our services and products in North America negatively impacted revenues in those segments for the six months ended March 31, 2009 compared to the same period of 2008.

Revenue for the six months ended March 31, 2009 decreased 3% when compared to the same period in the prior year and consolidated operating income for the period decreased 37%, primarily as the result of decreased demand and intense price competition for our products and services in the North America pressure pumping markets. Results for the six months ended March 31, 2009 also included a non-cash charge of $21.7 million, which represented 0.9% of revenue for the period, related to the settlement of a U.S. defined benefit pension plan. For the six months ended March 31, 2009, consolidated operating income margins decreased to 11.2% from 17.1% reported in the same period of the prior fiscal year.

U.S./Mexico Pressure Pumping

	Three Months Ended March 31,						Six Months Ended March 31,
(dollars in millions)	2009		% Change		2008		2009		% Change		2008
Revenue	$	475.6	-25	%	$	635.9	$	1,197.1	-7	%	$	1,290.0
Operating income	$	25.7	-79	%	$	125.1	$	177.6	-42	%	$	305.2
U.S. rig count(1)		1,326	-25	%		1,770		1,612	-9	%		1,780
Mexico rig count(1)		128	33	%		96		117	23	%		95

(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 March 31, 2009 and 2008

Our U.S./Mexico Pressure Pumping operations second fiscal quarter 2009 revenue declined 25% with average active drilling rigs for the U.S. and Mexico decreasing 22% during the same period. The impact of declining activity and intense price competition for our products and services throughout the U.S. market was partially offset by increased activity in Mexico.

Operating income margin decreased from 19.7% in the second fiscal quarter of 2008 to 5.4% during the second fiscal quarter of 2009 as rapidly declining activity in the U.S. resulted in lower pricing for our products and services. These results also include an $8.2 million non-cash charge related to excess or idle fixed assets.

Results for the six months ended March 31, 2009 and 2008

Our U.S./Mexico Pressure Pumping operations first half of fiscal 2009 revenue declined 7% with average active drilling rigs for the U.S. and Mexico decreasing 8% during the same period. This 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.

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Operating income margin decreased from 23.7% in the first half of fiscal 2008 to 14.8% during the same period of 2009 as increased competition in the U.S. resulted in lower pricing for our products and services. These results also include an $8.2 million non-cash charge related to excess or idle fixed assets.

Canada Pressure Pumping

	Three Months Ended March 31,						Six Months Ended March 31,
(dollars in millions)	2009		% Change		2008		2009		% Change		2008
Revenue	$	95.4	-31	%	$	138.8	$	227.2	-13	%	$	260.1
Operating income	$	5.9	-59	%	$	14.5	$	34.8	10	%	$	31.5
Canadian rig count(1)		329	-35	%		508		369	-15	%		432

(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 March 31, 2009 and 2008

Canadian Pressure Pumping revenue decreased $43.4 million, or 31%, for the second fiscal quarter of 2009 compared to the same period of fiscal 2008, $24.4 million of which was attributable to the weakening Canadian dollar compared to the U.S. dollar during the comparable periods. In addition, decreased demand and lower pricing for our services and products negatively impacted revenue for the comparable periods. Average drilling rig count in Canada was down 35% for the comparable quarters.

Operating income margin declined to 6.2% for the three months ended March 31, 2009, from 10.4% during the same period in the prior year, primarily as a result of lower drilling activity, competitive pricing pressures and reduced higher margin services related revenue.

Results for the six months ended March 31, 2009 and 2008

Canadian Pressure Pumping revenue decreased, $32.9 million, or 13%, for the first half 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 resulted in a $47.7 million revenue decrease, which was partially offset by improved pricing and increased activity in the first fiscal quarter of 2009 compared to the prior year period. Average drilling rig count in Canada was down 15% for the same periods.

Operating income margin improved to 15.3% for the six months ended March 31, 2009, from 12.1% 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 period when compared to the prior year period.

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International Pressure Pumping

	Three Months Ended March 31,						Six Months Ended March 31,
(dollars in millions)	2009		% Change		2008		2009		% Change		2008
Revenue	$	276.7	-5	%	$	292.1	$	605.6	4	%	$	580.6
Operating income	$	21.6	-38	%	$	34.7	$	67.1	-5	%	$	70.6
International rig count, excluding Mexico(1)		897	-6	%		950		941	—	%		938

(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 March 31, 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 second fiscal quarter of 2009 with the comparable period of fiscal 2008:

	% Change in Revenue
Europe/Africa	—	%
Middle East	-10	%
Asia Pacific	17	%
Russia	-55	%
Latin America	-5	%

International Pressure Pumping revenue of $276.7 million in the second fiscal quarter of 2009 decreased 5% compared to the same period in the prior year, with our Russia and the Middle East operations being the most significant contributors to the revenue decline. International drilling rig activity decreased 6% over the same time period. The revenue decrease in the Middle East was primarily the result of lower rig activity in Saudi Arabia, India and Kazakhstan. Russia was negatively impacted by the completion of a significant service contract during the first quarter of fiscal 2009. We have closed one base in Russia and continue to service a single service contract out of our one remaining base. Upon completion of that contract later in the fiscal year, we intend to orderly exit the Russian pressure pumping market.

Revenues in Europe/Africa were flat for the second fiscal quarter of 2009 compared to the same period of 2008 as increased activity in the Netherlands, Nigeria and Ghana was offset by lower activity in Norway. Revenue in our Asia Pacific operations improved in the second fiscal quarter of 2009 on increased project activity in Thailand, Malaysia and China when compared to the same period of 2008.

Operating income margins from our International Pressure Pumping operations decreased from 11.9% in the second quarter of fiscal 2008 to 7.8% in the second 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, severance costs totaling $2.6 million associated with our initiative to align our workforce with current market conditions and the $4.2 million charge related to a denied value added tax refund claim.

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Results for the six months ended March 31, 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 half of fiscal 2009 with the comparable period of fiscal 2008:

	% Change in Revenue
Europe/Africa	-3	%
Middle East	-1	%
Asia Pacific	23	%
Russia	-26	%
Latin America	7	%

International Pressure Pumping revenue of $605.6 million in the first six months of fiscal 2009 increased 4% compared to the same period in the prior year, with our Asia Pacific and Latin America operations being the most significant contributors. International drilling rig activity remained flat over the same time period. The increased revenue in Asia Pacific is largely attributable to new projects in China and increased activity in Malaysia and Thailand. Latin America benefited from activity-related increases in Brazil, Venezuela and Ecuador.

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. In the Middle East, the favorable impact of increased activity and new service contracts in North Africa and Oman was offset by lower rig activity in India and Saudi Arabia. Russia was negatively impacted by the completion of a significant service contract during the first quarter of 2009.

Operating income margin from our International Pressure Pumping operations decreased from 12.2% in the first six months of fiscal 2008 to 11.1% in the first six 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 $2.7 million associated with our initiative to align our workforce with current market conditions and the $4.2 million charge related to a denied value added tax refund claim.

Oilfield Services Group

	Three Months Ended March 31,						Six Months Ended March 31,
(dollars in millions)	2009		% Change		2008		2009		% Change		2008
Revenue	$	207.0	-4	%	$	216.4	$	456.3	4	%	$	437.5
Operating income	$	20.5	-48	%	$	39.2	$	61.7	-24	%	$	81.1

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Results for the three months ended March 31, 2009 and 2008

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

	% Change in Revenue
Tubular Services	-10	%
Process & Pipeline Services	-11	%
Chemical Services	6	%
Completion Tools	3	%
Completion Fluids	-3	%

Revenues from our Oilfield Service Group decreased 4% to $207.0 million in the second quarter of fiscal 2009 compared to the same period in fiscal 2008, with the most significant decreases from our Tubular Services and Process & Pipeline Services businesses. The decrease in Tubular Services revenue is primarily attributable to lower activity in most international markets and in the Gulf of Mexico. Process & Pipeline Services revenue decreased primarily as a result of the completion of a large international project and the activity decline in the U.S. and Canada markets. Chemical Services revenues increased primarily as a result of the expansion of capillary services into new markets and increased industrial service work.

Operating income margin for the Oilfield Services Group for the second fiscal quarter of 2009 decreased to 9.9% compared to 18.1% in the second fiscal quarter of fiscal 2008, primarily as a result of a large project-oriented Completion Tools product sale in the second fiscal quarter of 2008 that did not repeat, and lower activity in the U.S and certain international markets.

Results for the six months ended March 31, 2009 and 2008

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

	% Change in Revenue
Tubular Services	-6	%
Process & Pipeline Services	-6	%
Chemical Services	11	%
Completion Tools	20	%
Completion Fluids	18	%

Revenues from our Oilfield Service Group increased 4% to $456.3 million in the first half of fiscal 2009 compared to the same period in fiscal 2008, primarily as a result of increased revenue in the Completion Tools business. The increase in Completion Tools revenue is primarily attributable to the inclusion of the Innicor Subsurface Technologies business, which was acquired in May 2008.

Operating income margin for the Oilfield Services Group for the first six months of fiscal 2009 decreased to 13.5% compared to 18.5% for the same period of fiscal 2008, primarily as a result of lower tubular service activity, a difference in product / service mix and fewer high end jobs and decreased activity in Completion Tools.

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Other Operating Expenses

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

	Three Months Ended March 31,				Six Months Ended March 31,
	2009		2008		2009		2008
Pension settlement	$	—	$	—	$	21,695	$	—
Research and engineering		17,095		18,913		34,215		36,111
Marketing		26,784		31,764		57,529		60,596
General and administrative		40,839		41,652		83,260		78,282
Loss (gain) on disposal of assets, net		2,377		238		2,405		(388	)

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.

Research and engineering: Research and engineering expense decreased 10% and 5% comparing the three and six months ended March 31, 2009 to the corresponding periods in the prior fiscal year, respectively. As a percentage of revenue, this expense increased slightly to 1.6% for the three months ended March 31, 2009 from 1.5% in the same period in the prior fiscal year and remained flat as a percentage of revenue for the six months ended March 31, 2009 and 2008.

Marketing:Marketing expense decreased $5.0 million and $3.1 million for the three and six months ended March 31, 2009, respectively, compared to the same periods in the prior fiscal year. As a percentage of revenue, marketing expense was 2.3% for the six months ended March 31, 2009 compared to 2.4% for the corresponding period in fiscal 2008.

General and administrative:General and administrative expense decreased $0.8 million, or 2%, in the three months ended March 31, 2009 compared to the same period in fiscal 2008, and increased $5.0 million, or 6%, in six months ended March 31, 2009 compared to the same period in the prior year. These changes are due to the inclusion of the Innicor operations acquired in May 2008 and as a result of increased administrative costs to support operations in other new markets, partially offset by the impact of cost reduction measures we introduced during the second quarter of fiscal 2009. As a percentage of revenue, general and administrative expense increased from 3.2% in the second quarter fiscal 2008 to 3.9% for the same period of fiscal 2009 and from 3.0% for the six months ended March 31, 2008 to 3.3% for the same period 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 March 31,						Six Months Ended March 31,
	2009			2008			2009			2008
Interest expense	$	(7,410	)	$	(6,949	)	$	(13,491	)	$	(14,811	)
Interest income		348			356			863			830
Net interest expense	$	(7,062	)	$	(6,593	)	$	(12,628	)	$	(13,981	)

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Interest expense increased $0.5 million in three months ended March 31, 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 $1.3 million in six months ended March 31, 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 $615.9 million at March 31, 2008 to $562.3 million at March 31, 2009. Interest income was consistent with the same periods in the prior year, as higher average invested balances were offset by lower prevailing interest rates.

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

	Three Months Ended March 31,					Six Months Ended March 31,
	2009			2008		2009			2008
Minority interest	$	(1,448	)	$	125	$	(4,627	)	$	(2,944	)
Non-operating net foreign exchange loss		(98	)		172		406			533
Legal settlement		—			—		3,569			—
Other, net		626			756		1,184			753
Other income (expense), net	$	(920	)	$	1,053	$	532		$	(1,658	)

Other income (expense), net declined $2.0 million in the three-month period and improved $2.2 million in the six–month period ended March 31, 2009, compared to the corresponding periods of fiscal 2008. The increase in expense in the three-month period was attributable to increased minority interest expense in fiscal 2009, reflecting improved operating results from our international joint venture operations. The improvement in the six-month period was primarily a result of a legal settlement involving a commercial dispute, which was recorded in the first quarter of fiscal 2009, offset by increased minority interest expense.

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 31% as of December 31, 2008, to 28% as of March 31, 2009. Accordingly, we revised our year-to-date income tax expense to reflect these revised expectations. Because our pre-tax income during the second quarter of fiscal 2009 was considerably less than the pre-tax income we reported in the first quarter, this revision had a significant impact on our effective tax rate for the second quarter. Our effective tax rate decreased from 30% for the three months ended March 31, 2008 to 14% for the three months ended March 31, 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 fiscal year end tax rate of 28%.

Our effective tax rate decreased from 29% for the six months ended March 31, 2008 to 28% for the six months ended March 31, 2009, primarily due to the decline in estimated taxable income in our higher tax jurisdictions partially offset by the impact of a Canadian statutory tax rate decrease included in the prior year.

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Liquidity and Capital Resources

Historical Cash Flow

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

	Six Months Ended March 31,
	2009			2008
Cash flow from operations	$	395.6		$	349.6
Cash used in investing		(236.2	)		(299.5	)
Cash used in financing		(58.7	)		(61.4	)
Effect of exchange rate changes on cash		(6.1	)		(3.3	)
Change in cash and cash equivalents	$	94.6		$	(14.6	)

Cash flow from operations of $395.6 million for the six months ended March 31, 2009 increased $46.0 million, or 13%, compared to the same period in the prior year, primarily as a result of a reduction in investment in working capital between the two periods, partially offset by lower net income.

Cash used in investing activities decreased $63.3 million, or 21%, 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 decreased $2.7 million, or 4%, in fiscal 2009 compared to fiscal 2008. This change was primarily a result of short-term borrowings during the six months ended March 31, 2009 compared to repayments of short-term borrowings in the corresponding period of fiscal 2008 mostly offset by an increase in cash used to purchase treasury stock during the current fiscal year.

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 $244.8 million at March 31, 2009 and the available financing facilities listed below (in millions):

Financing Facility	Expiration	Borrowings at March 31, 2009		Available at March 31, 2009
Revolving Credit Facility	August 2012	$	—	$	400.0
Committed Credit Facility	May 2009		50.0		—
Discretionary	Various times within the next 12 months		13.5		8.3

As of March 31, 2009, the Company had $249.9 million of the 5.75% Senior Notes due 2011 and $248.9 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

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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 six months ended March 31, 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 six months ended March 31, 2009. There were no borrowings outstanding under the Revolving Credit Facility at March 31, 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 are no commitment fees required by this facility, and the interest rate is based on market rates on the dates that amounts are borrowed. On March 31, 2009, there were $50.0 million in outstanding borrowings under this credit facility. This facility will expire in May 2009. We expect to repay this facility when it becomes due with cash on hand.

In addition to the Revolving Credit Facility and the Committed Credit Facility, we had available $8.3 million of discretionary lines of credit at March 31, 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 was $13.5 million in outstanding borrowings under these lines of credit at March 31, 2009, primarily representing borrowings in foreign currencies. The weighted average interest rate on short-term borrowings outstanding under the Committed Credit Facility and the discretionary lines as of March 31, 2009 was 5.5%.

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 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, Revolving Credit Facility and Committed 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 $238.3 million of capital expenditures during the six months ended March 31, 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 by approximately $125 million from earlier estimates. We currently anticipate capital expenditures to be approximately $400-425 million in fiscal 2009. The actual amount of fiscal 2009 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 $19.3 million in fiscal 2009. We contributed $7.1 million to such plans during the six months ended March 31, 2009.

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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 six months ended March 31, 2009, we paid cash dividends totaling $29.3 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 March 31, 2009, we had $249.9 million of 5.75% Senior Notes due 2011, $248.9 million of 6% Senior Notes due 2018 issued and outstanding, net of discount, and $50.0 million outstanding on a Committed Credit Facility due May 2009. We expect to repay the amount outstanding under the Committed Credit Facility when it becomes due with cash on hand. We expect cash paid for interest expense to be approximately $32.0 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 amortized over 13 years. The balance of the deferred gain was $3.0 million and $4.2 million as of March 31, 2009 and September 30, 2008, respectively. The agreement permits substitution of equipment within the partnership as long as the implied fair value of the new property transferred in at the date of substitution equals or exceeds the implied fair value, as defined, of the current property in the partnership that is being replaced. As a result of such substitutions, the deferred gain was reduced by $0.7 million in the six-month period ended March 31, 2009. It is anticipated that substitution activity in the third quarter of fiscal 2009 will reduce the balance of the deferred gain to zero.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 December 2008, the FASB issued FASB Staff Position 132 (R)-1Employer’s Disclosures about Postretirement Benefit Plan Assets (“FSP 132 (R)-1”). 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.

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In April 2008, the FASB issued FSP 142-3,Determination of the Useful Life of Intangible Assets (“FSP 142-3”). 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, and other U.S. generally accepted accounting principles. FSP 142-3 is effective for fiscal years beginning after December 15, 2008. We are currently in the process of evaluating the impact of FSP 142-3 on our financial statements.

In March 2008, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 161,Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS 161”). 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 statement 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”).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 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”), 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

29

income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest and requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS 160 requires expanded disclosures in the consolidated financial statements that identify and distinguish between the interests of the parent’s owners and the interests of the noncontrolling owners of a subsidiary and shall be applied prospectively as of the beginning of the fiscal year in which initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. SFAS 160 is effective for fiscal years beginning after December 15, 2008. We do not have significant noncontrolling interests in consolidated subsidiaries, and therefore, adoption of this standard is not expected to have a significant impact on our financial statements.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115(“SFAS 159”). This Statement provides companies with an option to report selected financial assets and liabilities at fair value. Under SFAS 159, companies that elect the fair value option will report unrealized gains and losses in earnings at each subsequent reporting date. In addition, SFAS 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. The fair value option election is irrevocable, unless a new election date occurs. SFAS 159 is effective at the beginning of an entity’s first fiscal year beginning after November 15, 2007 and is to be applied prospectively, unless the entity elects early adoption. Consequently, we adopted SFAS 159 effective October 1, 2008 and elected not to apply the fair value option.

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

Forward Looking Statements

This document contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities Exchange Act of 1934 concerning, among other things, our prospects, expected revenue, expenses and profits, developments and business strategies for our operations, all of which are subject to certain risks, uncertainties and assumptions. These forward-looking statements are identified in statements described as “Outlook” and by their use of terms and phrases such as “expect,” “estimate,” “project,” “forecast,” “believe,” “achievable,” “anticipate,” “should” and similar terms and phrases. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances 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 six-month period ended March 31, 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. Based on their evaluation of our disclosure controls and procedures as of the end of the period covered by this report, the Chief Executive Officer and Chief Financial Officer of the Company have concluded that the disclosure controls and procedures are effective.

PART II

OTHER INFORMATION

Item 1. Legal Proceedings

The information regarding litigation and environmental matters described in Note 5 of the Notes to 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 six month period ended March 31, 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

The Company held its Annual Meeting of Stockholders on January 29, 2009. Proxies for the Annual Meeting were solicited pursuant to Regulation 14A of the Securities Exchange Act of 1934. The Board of Directors nominated John R. Huff and Michael E. Patrick for re-election as Class I directors at the Annual Meeting. There was no solicitation in opposition to these nominees, and the nominees were re-elected. The number of votes for and withheld with respect to the nominees were as follows:

Nominee	Votes For	Withheld
John R. Huff	228,800,421	39,868,333
Michael E. Patrick	228,955,321	39,713,433

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In addition, the following directors continued in office after the Annual Meeting: L. William Heiligbrodt, Don D. Jordan, James L. Payne, J.W. Stewart and William H. White.

The stockholders also approved amendments to the 2003 Incentive Plan and ratified the appointment of Deloitte & Touche LLP as the Company's independent auditor for the fiscal year 2009.

	Votes For	Votes Against	Abstain	Broker Non-Vote
2003 Incentive Plan Amendments	170,622,465	77,213,293	174,618	20,658,378
Ratification of Deloitte & Touche	263,883,460	4,753,080	32,213	N/A

Item 5. Other Information

None

Item 6. Exhibits

†*10.1	First Amendment effective March 19, 2009 to the Amended and Restated BJ Services Company 2003 Incentive Plan.
*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.

† Management contract or compensatory plan or arrangement.

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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: May 4, 2009	By:	/s/ J. W. Stewart
		J. W. Stewart
		Chairman of the Board, President
		and Chief Executive Officer
Date: May 4, 2009	By:	/s/ Jeffrey E. Smith
		Jeffrey E. Smith
		Executive Vice President - Finance
		and Chief Financial Officer

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