BJ SERVICES CO - FORM 10-Q - February 8, 2010

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EXCEL - IDEA: XBRL DOCUMENT - BJ SERVICES CO	Financial_Report.xls
EX-32.2 - SECTION 906 CFO CERTIFICATION - BJ SERVICES CO	dex322.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - BJ SERVICES CO	dex312.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - BJ SERVICES CO	dex311.htm
EX-32.1 - SECTION 906 CEO CERTIFICATION - BJ SERVICES CO	dex321.htm

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 December 31, 2009

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

For the transition period from to .

Commission file number 1-10570

BJ SERVICES COMPANY

(Exact Name of Registrant as Specified in Its Charter)


Delaware		63-0084140
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

4601 Westway Park Boulevard, Houston, Texas		77041
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s telephone number, including area code: (713) 462-4239

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES x 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.

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

There were 293,716,155 shares of the registrant’s common stock, $0.10 par value, outstanding as of February 3, 2010.

BJ SERVICES COMPANY

INDEX



PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Condensed Consolidated Statement of Operations (Unaudited) – Three months ended December 31, 2009 and 2008		3

Condensed Consolidated Statement of Financial Position (Unaudited) – December 31, 2009 and September 30, 2009		4

Consolidated Statement of Stockholders’ Equity and Other Comprehensive Income (Unaudited) – Three months ended December 31, 2009		5

Condensed Consolidated Statement of Cash Flows (Unaudited) – Three months ended December 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		18

Item 3. Quantitative and Qualitative Disclosures About Market Risk		30

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		31

Item 6. Exhibits		32

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 December 31,
	2009			2008

Revenue	$	931,547		$	1,416,788
Operating expenses:
Cost of sales and services		860,674			1,083,934
Research and engineering		15,501			17,120
Marketing		24,570			30,693
General and administrative		42,188			41,988
Pension settlement		—			21,695
Loss (gain) on disposal of assets, net		(586	)		34

Total operating expenses		942,347			1,195,464


Operating income (loss)		(10,800	)		221,324

Interest expense		(7,079	)		(6,042	)
Interest income		7			515
Other income (expense), net		(1,620	)		1,709

Income (loss) from continuing operations before income taxes		(19,492	)		217,506
Income tax expense (benefit)		(11,091	)		67,043


Income (loss) from continuing operations		(8,401	)		150,463
Loss from discontinued operations, net of income tax benefit of $- and $6, respectively		(4,874	)		(1,225	)

Net income (loss)	$	(13,275	)	$	149,238


Basic earnings (loss) per share:
Income (loss) from continuing operations	$	(0.03	)	$	0.51
Loss from discontinued operations, net		(0.02	)		—

Net income (loss) per share	$	(0.05	)	$	0.51


Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	(0.03	)	$	0.51
Loss from discontinued operations, net		(0.02	)		—

Net income (loss) per share	$	(0.05	)	$	0.51


Weighted-average shares outstanding:
Basic		293,463			292,685
Diluted		293,463			293,910

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

BJ SERVICES COMPANY

CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION

(UNAUDITED)

(In thousands)


	December 31, 2009		September 30, 2009
ASSETS

Current assets:
Cash and cash equivalents	$	261,061	$	282,636
Receivables, net		822,336		786,063
Inventories, net:
Products		246,206		248,251
Work in process		12,261		11,786
Parts		178,143		183,496

Total inventories		436,610		443,533
Deferred income taxes		32,015		32,924
Prepaid expenses		160,015		129,662
Current assets of discontinued operations		6,943		7,618
Other current assets		35,598		36,003

Total current assets		1,754,578		1,718,439

Property, net		2,346,155		2,374,323
Deferred income taxes		23,889		22,039
Goodwill		977,941		977,941
Investments and other assets		56,184		54,181

Total assets	$	5,158,747	$	5,146,923


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	365,079	$	340,735
Short-term borrowings		10,799		7,202
Accrued employee compensation and benefits		108,641		123,944
Income and other taxes		63,481		62,538
Current liabilities of discontinued operations		222		1,121
Other accrued liabilities		164,598		183,372

Total current liabilities		712,820		718,912

Long-term debt		498,955		498,910
Deferred income taxes		209,275		204,502
Accrued pension and postretirement benefits		126,969		126,771
Other long-term liabilities		92,795		77,911
Commitments and contingencies
Stockholders’ equity		3,517,933		3,519,917

Total liabilities and stockholders’ equity	$	5,158,747	$	5,146,923

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

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		Total
Balance, September 30, 2009	292,155	$	34,752	$	1,130,646		$	(1,413,086	)	$	3,743,791		$	23,814	$	3,519,917
Comprehensive income:
Net loss	—		—		—			—			(13,275	)		—
Other comprehensive income, net of tax:
Cumulative translation adjustments	—		—		—			—			—			3,779
Comprehensive loss																(9,496	)
Dividends declared	—		—		—			—			(14,682	)		—		(14,682	)
Re-issuance of treasury stock for:
Stock options	140		—		—			3,599			(1,420	)		—		2,179
Stock purchase plan	949		—		—			24,238			(8,801	)		—		15,437
Other stock awards	398		—		(11,124	)		10,305			—			—		(819	)
Stock-based compensation	—		—		4,603			—			—			—		4,603
Tax benefit from exercise of options	—		—		794			—			—			—		794

Balance, December 31, 2009	293,642	$	34,752	$	1,124,919		$	(1,374,944	)	$	3,705,613		$	27,593	$	3,517,933

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

BJ SERVICES COMPANY

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)

(In thousands)


	Three Months Ended December 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from continuing operations	$	(8,401	)	$	150,463
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Depreciation and amortization		75,549			69,363
Pension settlement		—			21,695
Minority interest expense		2,845			3,179
(Gain) loss on disposal/impairment of assets, net		(586	)		34
Reserve for obsolescence and excess inventory		2,401			967
Stock-based compensation expense		5,491			8,383
Excess tax benefits from stock-based compensation		(52	)		(1,038	)
Deferred income tax (benefit) expense		(351	)		11,479
Changes in:
Receivables		(37,083	)		38,167
Inventories		4,182			(3,629	)
Prepaid expenses and other current assets		(30,065	)		5,569
Accounts payable		24,756			(50,811	)
Current income tax		4,201			(4,633	)
Other current liabilities		(16,453	)		(35,393	)
Other, net		(712	)		(13,880	)
Net cash provided by (used in) operating activities from discontinued operations		(8,524	)		692

Net cash provided by operating activities		17,198			200,607


CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(39,722	)		(117,124	)
Proceeds from disposal of assets		2,409			754
Net cash provided by investing activities from discontinued operations		3,426			150

Net cash used in investing activities		(33,887	)		(116,220	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds (repayments) of short-term borrowings, net		3,597			(3,028	)
Dividends paid to stockholders		(14,606	)		(14,709	)
Purchase of treasury stock		—			(44,190	)
Excess tax benefits from stock-based compensation		52			1,038
Net proceeds from exercise of stock options and stock purchase plan		5,690			5,634
Distributions to minority interest partners		—			(1,090	)

Net cash used in financing activities		(5,267	)		(56,345	)


Effect of exchange rate changes on cash		381			(4,929	)


Increase (decrease) in cash and cash equivalents		(21,575	)		23,113
Cash and cash equivalents at beginning of period, including $- and $452 related to discontinued operations		282,636			150,254

Cash and cash equivalents at end of period, including $- and $1,294 related to discontinued operations	$	261,061		$	173,367


Cash Paid for Interest and Taxes:
Interest, net of capitalized interest of $784 and $1,588	$	13,992		$	14,108
Taxes		11,424			18,845

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

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 December 31, 2009, our results of operations for the three-month periods ended December 31, 2009 and 2008, our statement of stockholders’ equity and other comprehensive income for the three-month period ended December 31, 2009, and our cash flows for the three-month periods ended December 31, 2009 and 2008. The condensed consolidated statement of financial position at September 30, 2009 is derived from the September 30, 2009 audited consolidated financial statements. Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. The results of operations and cash flows for the three-month period ended December 31, 2009 are not necessarily indicative of the results to be expected for the full year.

We have evaluated subsequent events through February 8, 2010, the date of issuance of the condensed consolidated financial statements.

Note 2 New Accounting Standards

In June 2009, the FASB issued an update to ASC 810, Consolidation – Variable Interest Entities, which addresses the addition of qualified special purpose entities into previous guidance as the concept of these entities was eliminated by ASC 860. This guidance also modifies the analysis by which a controlling interest of a variable interest entity is determined thereby requiring the controlling interest to consolidate the variable interest entity. This statement could impact the way we account for our limited partnership discussed in Note 7 under Lease and Other Long-Term Commitments. This guidance becomes effective as of the beginning of the first annual reporting period beginning after November 15, 2009 and should be applied prospectively for interim and annual periods during that period going forward. We will adopt the guidance on October 1, 2010, and have not yet determined the impact, if any, on our consolidated financial statements.

In June 2009, the FASB issued guidance under ASC 860 – Transfers and Servicing, which eliminates the concept of a qualified special purpose entity and enhances guidance related to derecognition of transferred assets. This guidance becomes effective as of the beginning of the first annual reporting period beginning after November 15, 2009 and should be applied prospectively for interim and annual periods during that period going forward. We will adopt this guidance on October 1, 2010, and have not yet determined the impact, if any, on our consolidated financial statements.

In December 2008, the FASB issued guidance under ASC 715, Compensation – Retirement Benefits – Defined Benefit Plans, requiring annual 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. This guidance is effective for fiscal years ending after December 15, 2009 and, accordingly, we intend to adopt it for annual reporting in fiscal 2010.

In April 2008, the FASB issued guidance contained in ASC 350, Intangibles – Goodwill and Others – General Intangibles Other than Goodwill, amending the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under previously existing literature. The objective of this guidance is to improve the consistency between the useful life of a recognized intangible asset under ASC 350 and the period of expected cash flows used to measure the fair value of the asset under ASC 805, Business Combinations. This guidance is effective for the Company beginning October 1, 2009, and did not have a significant impact on our consolidated financial statements.

BJ SERVICES COMPANY

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In December 2007, the FASB issued an update to ASC 805, Business Combinations, to establish principles and requirements for the recognition and measurement of assets, liabilities and goodwill, and requires that most transaction and restructuring costs related to the acquisition be expensed. This guidance is effective for business combinations occurring on or after the beginning of the first annual reporting period beginning after December 15, 2008. Consequently, we adopted this guidance on October 1, 2009 with no material impact on our consolidated financial statements.

In December 2007, the FASB issued guidance under ASC 810, Consolidation – Overall – Transition, amending previous guidance to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary in an effort to improve the relevance, comparability and transparency of the financial information that a reporting entity provides. We adopted this guidance effective October 1, 2009 with no change to our consolidated financial statements as amounts are immaterial.

In September 2006, the FASB issued guidance under ASC 820, Fair Value Measurements and Disclosures, section 10, defining fair value, outlining a fair value hierarchy (requiring market-based assumptions be used, if available) and setting disclosure requirements 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 ASC 820 related to financial assets and liabilities. We adopted the provisions of ASC 820 related to non-financial assets and liabilities on October 1, 2009 without material impact on our consolidated financial statements.

Note 3 Baker Hughes Merger Agreement

On August 30, 2009, the Company and Baker Hughes Incorporated (“Baker Hughes”) entered into an Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which the Company will merge with and into a wholly-owned subsidiary of Baker Hughes, and each share of Company common stock will be converted into the right to receive 0.40035 shares of Baker Hughes common stock and $2.69 in cash (the “Merger”). Completion of the Merger is subject to customary closing conditions, including (i) approval of the Merger by the stockholders of the Company, (ii) approval by the stockholders of Baker Hughes, including approval of the issuance of Baker Hughes common stock to Company stockholders in the merger, (iii) applicable regulatory approvals, including the termination or expiration of the applicable waiting period (and any extensions thereof) under the U.S. Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (iv) the effectiveness of a registration statement on Form S-4 relating to the Baker Hughes common stock to be issued in the Merger, and (v) other customary closing conditions.

Under the Merger Agreement, the Company agreed to conduct its business in the ordinary course while the Merger is pending, and to generally refrain from acquiring new businesses, incurring new indebtedness, repurchasing treasury shares, issuing new common stock or equity awards, or entering into new material contracts or commitments outside the normal course of business, without the consent of Baker Hughes. The Company incurred $3.1 million of costs related to the merger during the first fiscal quarter of 2010, which are included in general and administrative expense in the Corporate segment. Under certain circumstances, the Company or Baker Hughes may be required to pay a termination fee of $175 million to the other party if the Merger is not completed. When and if the Merger is approved or completed, certain contractual obligations of the Company will or may be triggered or accelerated under the “change of control” provisions of such contractual arrangements. Examples of such arrangements include stock-based compensation awards, severance and retirement plan agreements applicable to executive officers, directors and certain employees, and the equipment partnership described in Note 7.

BJ SERVICES COMPANY

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On October 14, 2009, Baker Hughes and the Company each received from the Antitrust Division of the U.S. Department of Justice a request for additional information and documentary material (a “second request”). Baker Hughes and the Company each substantially complied with the second request by December 22, 2009. Baker Hughes has agreed to work with the Antitrust Division to resolve any remaining issues and to not close the transaction prior to March 6, 2010 unless the Antitrust Division provides written notice that the transaction can close prior to that time. Baker Hughes and the Company have scheduled special meetings of stockholders on March 19, 2010, subject to adjournment or postponement, in connection with the Merger and expect to close the transaction in March 2010, subject to the closing conditions. However, the Company cannot predict with certainty when the Merger will be completed, because completion of the Merger is subject to conditions both within and beyond the Company’s control.

Note 4 Earnings Per Share and Comprehensive Income

Basic earnings per share excludes dilution and is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is 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 December 31,
	2009			2008
Income (loss) from continuing operations	$	(8,401	)	$	150,463
Loss from discontinued operations		(4,874	)		(1,225	)

Net income (loss)	$	(13,275	)	$	149,238


Weighted-average common shares outstanding		293,463			292,685

Basic earnings per share:
Income (loss) from continuing operations	$	(0.03	)	$	0.51
Loss from discontinued operations		(0.02	)		—

Net income (loss)	$	(0.05	)	$	0.51


Weighted-average common and dilutive potential common shares outstanding:
Weighted-average common shares outstanding		293,463			292,685
Assumed exercise of stock options		—			44
Assumed stock purchase plan grants		—			212
Assumed vesting of other stock awards		—			969

Weighted-average dilutive shares outstanding		293,463			293,910

Diluted earnings per share:
Income (loss) from continuing operations	$	(0.03	)	$	0.51
Loss from discontinued operations		(0.02	)		—

Net income (loss)	$	(0.05	)	$	0.51

⁽¹⁾	For the three months ended December 31, 2009 and 2008, 12.8 million and 12.7 million stock equivalents, respectively, were excluded from the computation of diluted earnings per share due to their antidilutive effect.

BJ SERVICES COMPANY

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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


	Pension and Other Postretirement Plan Adjustments			Cumulative Translation Adjustment		Total
Balance at September 30, 2009	$	(28,501	)	$	52,315	$	23,814
Changes		—			3,779		3,779

Balance at December 31, 2009	$	(28,501	)	$	56,094	$	27,593

Note 5 Segment Information

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

The U.S./Mexico Pressure Pumping segment has two operating segments 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 four 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, the Middle East, Asia Pacific 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. Our Russia pressure pumping unit, which was historically an operating segment within the International Pressure Pumping segment, was discontinued during 2009. Consequently, its operating results are excluded from the segment data tables below.

The Oilfield Services segment has five operating segments. These operating segments provide other oilfield services such as casing and tubular services, process and pipeline services, chemical services, completion tools and completion fluids services in the United States and in select markets internationally. These operating segments have been aggregated into one reportable segment as they all provide oilfield services other than pressure pumping, have similar economic characteristics, serve same or similar customers which primarily include major multi-national, independent and national or state-owned oil companies, 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 Consolidated Financial Statements included in our annual report on Form 10-K for the fiscal year ended September 30, 2009. We evaluate the performance of our segments based on operating income. Intersegment sales and transfers are not material.

BJ SERVICES COMPANY

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Summarized financial information concerning our segments is shown in the following table. The “Corporate” column includes assets and liabilities from discontinued operations, corporate expenses, including the $21.7 million pension settlement charge in first fiscal quarter of 2009 discussed in Note 8, and assets not allocated to the operating segments. Revenue by geographic location is determined based on the location in which services are rendered or products are sold.


	U.S./Mexico Pressure Pumping			Canada Pressure Pumping		International Pressure Pumping		Oilfield Services Group		Corporate⁽¹⁾			Total

Three Months Ended December 31, 2009
Revenue	$	384,876		$	82,313	$	283,867	$	180,491	$	—		$	931,547
Operating income (loss)		(16,933	)		4,498		26,520		4,215		(29,100	)		(10,800	)
Identifiable assets		1,573,338			448,794		1,501,260		1,006,005		629,350			5,158,747

Three Months Ended December 31, 2008
Revenue	$	721,546		$	131,810	$	314,114	$	249,318	$	—		$	1,416,788
Operating income (loss)		151,885			28,843		46,482		41,195		(47,081	)		221,324
Identifiable assets		1,762,107			480,365		1,442,814		983,027		654,178			5,322,491

(1)	The “Corporate” column includes a $21.7 million pension settlement charge for the three months ended December 31, 2008 (see Note 8).

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


	Three Months Ended December 31,
	2009			2008
Total operating income (loss) for reportable segments	$	(10,800	)	$	221,324
Interest expense		(7,079	)		(6,042	)
Interest income		7			515
Other income (expense), net		(1,620	)		1,709

Income (loss) from continuing operations before income taxes	$	(19,492	)	$	217,506

Note 6 Discontinued Operations

We classified the Russia pressure pumping unit, an operating segment within the International Pumping Services segment, as a discontinued operation in the fourth quarter of fiscal 2009. Accordingly, the assets and liabilities of this business, along with its results of operations, have been reclassified for all periods presented. As soon as our contractual obligations were fulfilled, we began the process of redeployment and liquidation of the assets associated with this business and other exit activities. In the fourth quarter of fiscal 2009, we recorded charges totaling $6.6 million in connection with these exit activities, including employee separation costs, fixed asset and inventory impairment charges, and freight costs to redeploy certain pressure pumping assets into other markets. During the first quarter of fiscal 2010 we recorded costs totaling $4.9 million associated with these exit activities and we expect to incur additional exit costs during fiscal 2010 in the range of $4-6 million as we complete the exit activities associated with our Russia pressure pumping business.

BJ SERVICES COMPANY

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Summarized operating results from discontinued operations are as follows:


	Three Months Ended December 31,
	2009			2008
	(in thousands)
Revenue	$	—		$	14,854
Loss before income taxes		(4,874	)		(1,219	)
Income tax expense		—			6

Loss from discontinued operations	$	(4,874	)	$	(1,225	)

Significant categories of assets and liabilities from discontinued operations are shown below:


	December 31, 2009		September 30, 2009
	(in thousands)
Total assets:
Inventories, net	$	3,098	$	2,910
Property, net		3,845		4,708

Total assets	$	6,943	$	7,618

Total liabilities:
Accrued liabilities	$	222	$	1,121

Total liabilities	$	222	$	1,121

Note 7 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.

Stockholder Lawsuits regarding Baker Hughes Merger

In connection with the pending Baker Hughes Merger, various lawsuits have been filed in the Court of Chancery of the State of Delaware (the “Delaware Lawsuits”) on behalf of the public stockholders of the Company, naming the Company, current members of the Company’s Board of Directors, and Baker Hughes as defendants. In the Delaware Lawsuits, the plaintiffs allege, among other things, that the Company’s Board of Directors violated various fiduciary duties in approving the Merger Agreement and that the Company and/or Baker Hughes aided and abetted such alleged violations. Among other remedies, the plaintiffs seek to enjoin the Merger.

BJ SERVICES COMPANY

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On September 25, 2009, the Delaware Chancery Court entered an order consolidating the Delaware Lawsuits into one class action, In re: BJ Services Company Shareholders Litigation, C.A. No. 4851-VCN. On October 6, 2009, the Delaware Chancery Court entered an order designating the law firm of Faruqi & Faruqi, LLP of New York, New York as lead counsel and Rosenthal, Monhait & Goddess, P.A. of Wilmington, Delaware as liaison counsel. On October 16, 2009, lead counsel for the plaintiffs filed an amended complaint in the Delaware Chancery Court which, among other things, adds Jeffrey E. Smith, the Company’s Executive Vice President and Chief Financial Officer, as a defendant, contains new factual allegations about the merger negotiations, and alleges the preliminary joint proxy/prospectus filed on October 14, 2009, with the U.S. Securities and Exchange Commission (the “SEC”) omits and misrepresents material information.

Various lawsuits have also been filed in the District Courts of Harris County, Texas (the “Texas Lawsuits”). The Texas Lawsuits make substantially the same allegations as were initially asserted in the Delaware Lawsuits, and seek the same relief. On October 9, 2009, the Harris County Court consolidated the Texas Lawsuits into one class action, Garden City Employees’ Retirement System, et al. v. BJ Services Company, et al., Cause No. 2009-57320, 80^th Judicial District of Harris County, Texas. On October 20, 2009, the Court of Appeals for the First District of Texas at Houston granted the defendants’ emergency motion to stay the Texas Lawsuits pending its decision on the defendants’ petition seeking a stay of the Texas Lawsuits pending adjudication of the Delaware Lawsuits, which were filed first. Oral arguments were held on December 15, 2009, in the Court of Appeals. To date, a ruling has not been issued from the Court of Appeals and the Texas Lawsuits remain stayed.

The Company believes that the Delaware Lawsuits and the Texas Lawsuits are without merit, and it intends to vigorously defend itself against them. The outcome of this litigation is uncertain, however, and we cannot currently predict the manner and timing of the resolution of the suits, the likelihood of the issuance of an injunction preventing the consummation of the Merger, or an estimate of a range of possible losses or any minimum loss that could result in the event of an adverse verdict in these suits. These suits could prevent or delay the completion of the Merger and result in substantial costs to the Company and Baker Hughes. We have recorded an amount for estimated legal defense costs under our applicable insurance policies. However, there can be no assurance as to the ultimate outcome of these lawsuits or the extent to which our applicable insurance policies will provide coverage for these claims.

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.

BJ SERVICES COMPANY

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Halliburton – Python Litigation

On December 21, 2007, Halliburton Energy Services, Inc. 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. At this point, discovery in both cases is just beginning. 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.

Customer Claim

On November 19, 2009, we received correspondence from a customer operating in the North Sea, claiming that the Company’s decision to move a stimulation vessel out of the North Sea market constituted a breach of contract. The customer alleges that it was forced to purchase well stimulation services from other providers at a higher cost than in the original agreement between the customer and the Company. The customer further alleges that it has incurred actual and estimated future damages of $40.4 million plus an undisclosed amount for production loss and/or production deferral. The customer has initiated a request for arbitration and we are responding accordingly. We believe that this claim is without merit, and we intend to vigorously defend ourselves in this matter based on the information available to us at this time. 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.

BJ SERVICES COMPANY

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 the SEC and have engaged in discussions with these authorities in connection with their review of the matter. We cannot predict whether further investigative efforts may be required or initiated by the authorities.

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

The DOJ, the 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, the 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 December 31, 2009 and September 30, 2009, we had reserved approximately $4.8 million and $5.0 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. The partnership agreement permits substitution of equipment within the partnership as long as the implied fair value of the new property transferred in at the date of substitution equals or exceeds the implied fair value, as defined, of the current property in the partnership that is being replaced. In 2010, we intend to exercise our option to purchase the pumping service equipment for approximately $46 million, $30.7 million of which is due and payable during our fiscal second quarter.

BJ SERVICES COMPANY

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Contractual Obligations

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

We arrange for the issuance of a variety of bank guarantees, performance bonds and standby letters of credit. The vast majority of these are issued in connection with contracts we, or our subsidiaries, have entered into with customers. The customer has the right to call on the bank guarantee, performance bond or standby letter of credit in the event that we, or our subsidiaries, default in the performance of services. These instruments are required as a condition to being awarded the contract, and are typically released upon completion of the contract. We have also issued standby letters of credit in connection with a variety of our financial obligations, such as in support of fronted insurance programs, claims administration funding, certain employee benefit plans and temporary importation bonds. The following table summarizes our other commercial commitments as of December 31, 2009 (in thousands):


			Amount of commitment expiration per period
Other Commercial Commitments	Total Amounts Committed		Less than 1 Year		1–3 Years		4–5 Years		Over 5 Years
Standby letters of credit	$	39,255	$	39,255	$	—	$	—	$	—
Guarantees		243,809		150,792		52,525		38,734		1,758

Total other commercial commitments	$	283,064	$	190,047	$	52,525	$	38,734	$	1,758

Note 8 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 10 of the Notes to Consolidated Financial Statements included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2009.

In September 2006, we entered into an agreement with an insurance company to settle our obligation with respect to our 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.

BJ SERVICES COMPANY

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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


	Three Months Ended December 31,
	2009			2008
Service cost for benefits earned	$	1,079		$	1,654
Interest cost on projected benefit obligation		2,896			3,449
Expected return on plan assets		(2,373	)		(2,829	)
Recognized actuarial loss		712			615

Net pension cost	$	2,314		$	2,889

In fiscal 2010, we expect to contribute a total of $13.7 million to the defined benefit plans, which represents the legal or contractual minimum funding requirements and expected discretionary contributions. We have paid $4.2 million in contributions to defined benefit pension plans during the three months ended December 31, 2009. These contributions have been and are expected to be funded by cash flows from operating activities.

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


	Three Months Ended December 31,
	2009			2008
Service cost for benefits attributed to service during the period	$	542		$	865
Interest cost on accumulated postretirement benefit obligation		394			919
Net amortization and deferral		(1,192	)		(327	)

Net postretirement benefit cost (income)	$	(256	)	$	1,457

We expect to contribute a total of $1.3 million to the postretirement benefit plan in fiscal 2010, which represents the anticipated cost of participant claims. We have made $0.2 million in postretirement contributions during the three months ended December 31, 2009.

Note 9 Financial Instruments

Our financial instruments include cash and short-term investments, accounts receivable, accounts payable and debt. Except as described below, the estimated fair value of such financial instruments at December 31, 2009 approximates their carrying value as reflected in our consolidated balance sheet.

The estimated fair value of total debt at December 31, 2009 was $535.0 million, which differs from the carrying amount of $509.8 million included in our condensed consolidated balance sheet. The fair value of our debt has been estimated based on quoted market prices as of December 31, 2009.

Note 10 Subsequent Events

In January 2010, the Venezuelan government devalued its bolivar currency. We anticipate that we will record a one-time currency exchange loss of less than $10 million during the fiscal second quarter in remeasuring our net bolivar-based assets and liabilities. This estimate is based on our net position as of December 31, 2009 and our current understanding of how the new two-rate structure will apply to our Venezuela operations.

Item 2.

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

Business

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

The U.S./Mexico Pressure Pumping, Canada Pressure Pumping and International Pressure Pumping segments provide stimulation and cementing services to the petroleum industry throughout the world. Stimulation services are designed to improve the flow of oil and natural gas from producing formations. Cementing services consist of pumping a cement slurry into a well between the casing and the wellbore to isolate fluids that might otherwise damage the casing and/or affect productivity, or that could migrate to different zones, primarily during the drilling and completion phase of a well. See “Business” included in our Annual Report on Form 10-K for the year ended September 30, 2009 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.

Baker Hughes Merger Agreement

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 summarized in the table below:


	For the three months ended
	December 31,
	2009		% Change		2008
Rig Count: ⁽¹⁾
U.S.		1,108	-42	%		1,898
Canada		278	-32	%		408
International⁽²⁾		1,011	-7	%		1,090
Commodity Prices (average):
Crude Oil (West Texas Intermediate)	$	76.08	30	%	$	58.45
Natural Gas (Henry Hub)	$	4.34	-33	%	$	6.43

(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 123 and 106 for the three-month periods ended December 31, 2009 and 2008, respectively.

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 841 in fiscal 2000 and the highest annual U.S. rig count averaged 1,851 in fiscal 2008.

With the retraction of oil and natural gas prices since their peak in July 2008, tightening and uncertainty in the credit markets, and the global economic slowdown, drilling rig activity in the United States has rapidly declined from peak levels of 2,031 rigs at September 12, 2008 to a recent low of 876 rigs at June 12, 2009, before gradually increasing over the last two fiscal quarters. U.S. rig count was 1,335 rigs at February 5, 2010. The near-term and longer range outlook for U.S. drilling activity is uncertain, and will ultimately be influenced by a number of factors, including commodity prices, global demand for oil and natural gas, production and depletion rates of oil and natural gas reserves, and government policy with respect to the financial credit crisis, energy and environmental issues, and other issues impacting our business.

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 255 in fiscal 2009 and the highest annual rig count averaged 502 in fiscal 2006. Similar to activity in the United States, drilling rig activity in Canada has declined significantly since late September 2008, although it has improved in recent months, primarily in response to higher oil prices and seasonal activity increases, and was 557 at February 5, 2010. Rig count in Canada typically encounters significant seasonal fluctuations, decreasing during the spring break-up period when snow and ice begin to melt and heavy equipment is not permitted on the roads, restricting access to well sites and, therefore, resulting in lower drilling activity. The spring break-up period typically begins in late February or March and extends through May.

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 oil companies and national oil companies which tend to have different objectives and more operating stability than the typical independent producer in North America. During the last 10 years, the lowest annual international rig count, excluding Canada and including Mexico, averaged 617 in fiscal 2000 and the highest annual international rig count averaged 1,061 in fiscal 2008. International rig count declined during fiscal 2009 but improved slightly during the first fiscal quarter of 2010.

In response to prevailing market conditions, we implemented a number of cost reduction measures during fiscal 2009 in the United States, Canada and certain markets outside of North America. Such measures include reducing personnel levels, managing our supply chain to reduce material costs, reducing capital spending and controlling our investment in working capital.

Outlook

As stated under “Market Conditions” above, our worldwide operations are primarily driven by the number of oil and natural gas wells being drilled, the depth and drilling conditions of such wells, the number of well completions and the level of workover activity. The global economic slowdown has led to a steep decline in oil and natural gas prices, well below their historic highs in July 2008. These steep price declines have reduced cash flows of oil and gas producers and have led to significant reductions in planned drilling activity continuing into fiscal 2010, particularly in the U.S. and Canadian markets. The reduced drilling activity has led to reduction in demand and severe price competition for the services and products we provide.

Drilling rig count in the United States increased slightly during the first fiscal quarter of 2010 to 1,108 rigs compared to 973 rigs during the fourth quarter of fiscal 2009. Over that period, the average number of rigs drilling for natural gas increased by roughly 50 rigs, or 7%, while the number of rigs drilling for oil has increased by roughly 90 rigs, or 31%. Nevertheless, drilling activity in the first fiscal quarter of 2010 was 42% below the comparable period of fiscal 2009. We expect U.S. gas drilling to gradually improve as natural gas supply and demand get more in balance, leading to increased natural gas prices. We expect rigs drilling for oil in the U.S. to stay at current levels or improve slightly in the near term, in response to changes in oil prices. We believe our profitability in the U.S./Mexico Pressure Pumping segment will improve slightly, as activity improves and as we realize the full benefit of the cost reduction measures we have put into place in fiscal 2009. Cost reductions have included personnel reductions, a global wage freeze, reduced capital spending plans, supplier negotiations and working capital initiatives.

We expect Canada Pressure Pumping results to improve slightly in the second fiscal quarter compared to the first fiscal quarter, on increased drilling activity and improved pricing. We expect fiscal second quarter revenue from International Pressure Pumping Services to be in line with the first fiscal quarter, but profitability will be negatively impacted by the Venezuelan currency devaluation discussed below. We expect operating results in our Oilfield Services group to improve significantly in the fiscal second quarter, primarily as a result of several expected large completion tool sales in the Gulf of Mexico and internationally.

Results of Operations

Consolidated


	Three Months Ended December 31,
	2009			% Change		2008
(dollars in millions)
Revenue	$	931.5		-34	%	$	1,416.8
Operating income (loss)		(10.8	)	-105	%		221.3
Operating income (loss) margin		(1.2	)%				15.6	%

Worldwide rig count⁽¹⁾		2,397		-29	%		3,396

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

Revenue was lower in all of our reportable segments for the first fiscal quarter of 2010 compared to the first fiscal quarter of 2009, primarily as a result of lower drilling activity caused by the global economic downturn and decreased demand for oil and gas, combined with intense price competition in North America.

Revenue for the three months ended December 31, 2009 decreased $485.2 million, or 34%, while consolidated operating income for the period decreased $232.1 million, or 105%, primarily as the result of decreased demand and lower pricing for our products and services , particularly in North America. Results for the three months ended December 31, 2008 included a non-cash charge of $21.7 million, which represented 1.5% of revenue for the quarter, related to the settlement of a frozen U.S. defined benefit pension plan. For the three months ended December 31, 2009, consolidated operating income margins decreased to (1.2)% from 15.6% reported in the same period of the prior fiscal year.

U.S./Mexico Pressure Pumping


	Three Months Ended December 31,
	2009			% Change		2008
(dollars in millions)
Revenue	$	384.9		-47	%	$	721.5
Operating income (loss)		(16.9	)	-111	%		151.9
Operating income (loss) margin		(4.4	)%				21.0	%

U.S. rig count⁽¹⁾		1,108		-42	%		1,898
Mexico rig count⁽¹⁾		123		16	%		106

Total U.S. / Mexico rig count		1,231		-39	%		2,004

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

Our U.S./Mexico Pressure Pumping operations first fiscal quarter 2010 revenue decreased 47% compared to the same period in fiscal 2009,with average active drilling rigs decreasing 39% during the same period. This decrease was attributable to lower fracturing and cementing activity in the United States, coupled with reductions in pricing for our services and products. Mexico revenue increased compared to the same fiscal quarter of the prior year, due to new projects and increased activity both onshore and offshore.

Operating margin for U.S./Mexico Pressure Pumping decreased from 21.0% in the first fiscal quarter of 2009 to (4.4)% during the first fiscal quarter of 2010 primarily as result of decreased demand and lower pricing for our products and services in the U.S., partially offset by cost reductions implemented during fiscal 2009.

Canada Pressure Pumping


	Three Months Ended December 31,
	2009			% Change		2008
(dollars in millions)
Revenue	$	82.3		-38	%	$	131.8
Operating income		4.5		-84	%		28.8
Operating income margin		5.5	%				21.9	%

Canadian rig count⁽¹⁾		278		-32	%		408

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

Canadian Pressure Pumping revenue decreased 38% for the first fiscal quarter of 2010 compared to the same period of fiscal 2009 with average active drilling rigs declining 32% during the same period. The lower revenue was primarily attributable to lower drilling activity and lower pricing for our services and products as a result of the lower demand.

Operating income margin declined to 5.5% for the three months ended December 31, 2009, from 21.9% during the same period in the prior year, primarily as a result of decreased activity and lower pricing, partially offset by cost reduction initiatives implemented during 2009 and more favorable job mix.

International Pressure Pumping


	Three Months Ended December 31,
	2009			% Change		2008
(dollars in millions)
Revenue	$	283.9		-10	%	$	314.1
Operating income		26.5		-43	%		46.5
Operating income margin		9.3	%				14.8	%

International rig count, excluding Mexico⁽¹⁾		888		-10	%		984

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

The following table summarizes the percentage change in revenue for each of the operating segments within the International Pressure Pumping reportable segment, comparing the first fiscal quarter of 2010 with the comparable period of fiscal 2009:


	% change in Revenue
Europe	32	%
Middle East	-21	%
Asia Pacific	-25	%
Latin America	-4	%

International Pressure Pumping revenue of $283.9 million in the first fiscal quarter of 2010 decreased 10% compared to the same period in the prior year, with our Middle East and Asia Pacific operations being the most significant contributors to the decline, primarily as a result of lower activity and lower pricing in certain markets. International drilling rig activity decreased 10% over the comparable period.

Revenue in Europe increased primarily as a result of high service activity in Norway, the Netherlands and continental Europe. Asia Pacific revenue was lower as a result of significantly lower activity in China, as well as lower activity in Malaysia, Thailand and Indonesia. Middle East revenue was lower, primarily as a result of lower activity and project delays in India, Kazakhstan, Saudi Arabia, Egypt and Libya. Latin America revenue was slightly lower as increased activity in Brazil and new contracts in Angola and Congo were offset by lower activity in Argentina, Venezuela and Peru.

Operating income margins from our International Pressure Pumping operations decreased from 14.8% in the first quarter of fiscal 2009 to 9.3% in the first quarter of fiscal 2010. The decreased operating margins are largely attributable to the activity-related revenue decrease in most international regions and lower pricing in certain markets.

Oilfield Services Group


	Three Months Ended December 31,
	2009			% Change		2008
(dollars in millions)
Revenue	$	180.5		-28	%	$	249.3
Operating income		4.2		-90	%		41.2
Operating income margin		2.3	%				16.5	%

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	-24	%
Process and Pipeline Services	-22	%
Chemical Services	-17	%
Completion Tools	-50	%
Completion Fluids	-25	%

Revenue from our Oilfield Service Group decreased 28% to $180.5 million in the first quarter of fiscal 2010 compared to the same period in fiscal 2009, with significant decreases from each operating segment. The decrease in Completion Tools and Completion Fluids were largely attributable to significantly lower activity in the U.S. Gulf of Mexico. In addition, the first quarter of fiscal 2009 included a large international sale of completion tools which did not repeat in fiscal 2010. Chemical Services revenue was lower due to the reduced drilling activity in the U.S. and Canada. Tubular Services revenue was lower as a result of lower activity in the Gulf of Mexico in addition to rig movement and delays in some international projects. Process and Pipeline Services revenue was lower due to lower activity and deferred customer spending in the Middle East and Asia Pacific markets.

Operating income margin for the Oilfield Services Group for the first fiscal quarter of 2010 decreased to 2.3% compared to 16.5% in first fiscal quarter of fiscal 2009, primarily as a result of the decreased activity described in the previous paragraph in addition to lower pricing in certain areas.

Other Operating Expenses

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


	Three Months Ended December 31,
	2009			2008
Research and engineering	$	15,501		$	17,120
Marketing		24,570			30,693
General and administrative		42,188			41,988
Pension settlement		—			21,695
Loss (gain) on disposal of assets, net		(586	)		34

Research and engineering: Research and engineering expense decreased $1.6 million, or 9%, to $15.5 million for the three months ended December 31, 2009 compared to the same period in the prior fiscal year, reflecting cost reductions implemented during fiscal 2009. As a percentage of revenue, this expense increased slightly from 1.2% in the fiscal 2009 first quarter to 1.7% in fiscal 2010 primarily as a result of the lower revenue base.

Marketing: Marketing expense decreased $6.1 million, or 20%, to $24.6 million for the three months ended December 31, 2009 compared to the same period in the prior fiscal year, primarily as a result of cost reduction measures put into place during fiscal 2009. As a percentage of revenue this expense increased slightly to 2.6% in the first quarter of fiscal 2010 compared to 2.2% in fiscal 2009 as a result of the lower revenue base.

General and administrative: General and administrative expense was essentially flat comparing the first quarter of fiscal 2010 compared to the same period in fiscal 2009. As a percentage of revenue, general and administrative expense increased in the first quarter from 3.0% in fiscal 2009 to 4.5% in fiscal 2010. General and administrative expenses in fiscal 2010 included $3.1 million of legal fees and other costs related to the Baker Hughes merger partially offset by cost reduction measures implemented in the second and third quarters of fiscal 2009.

Pension settlement: In September 2006, we entered into an agreement with an insurance company to settle our obligation with respect to a 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 2009 in our Corporate segment.

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


	Three Months Ended December 31,
	2009			2008
Interest expense	$	(7,079	)	$	(6,042	)
Interest income		7			515

Net interest expense	$	(7,072	)	$	(5,527	)

Interest expense increased $1.0 million in the first quarter of fiscal 2010 compared to the same period of fiscal 2009, primarily as a result of lower capitalized interest in the current fiscal year quarter partially offset by lower average outstanding borrowings when comparing the respective periods. Outstanding debt balances decreased from $553.4 million at December 31, 2008 to $509.8 million at December 31, 2009. Interest income was relatively low in both periods due to low rates of return on invested cash balances.

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


	Three Months Ended December 31,
	2009			2008
Minority Interest	$	(2,845	)	$	(3,179	)
Non-operating net foreign exchange loss		698			1,074
Legal settlement		—			3,569
Other, net		527			245

Other income (expense), net	$	(1,620	)	$	1,709

Other income (expense), net declined by $3.3 million in the first quarter of fiscal 2010 compared to the same period of fiscal 2009, primarily as a result of a favorable legal settlement in a commercial dispute in the first quarter of fiscal 2009.

Income Tax Expense (Benefit)

Our effective tax rate increased from 31% for the three months ended December 31, 2008 to 57% for the three months ended December 31, 2009, primarily as a result of pre-tax losses in relatively high-tax jurisdictions being benefited at a higher rate than taxes on income in relatively low tax jurisdictions.

Discontinued Operations

During the fourth quarter of fiscal 2009, we classified the Russia pressure pumping unit, an operating segment within the International Pumping Services segment, as a discontinued operation. Accordingly, the assets and liabilities of this business, along with its results of operations, have been reclassified for all periods presented. As soon as our contractual obligations were fulfilled, we began the process of redeployment and liquidation of the assets associated with this business and other exit activities. In the fourth quarter of fiscal 2009, we recorded charges totaling $6.6 million in connection with these exit activities, including employee separation costs, fixed asset and inventory impairment charges, and freight costs to redeploy certain pressure pumping assets into other markets. During the first quarter of fiscal 2010 we recorded costs totaling $4.9 million associated with these exit activities and we expect to incur additional exit costs during fiscal 2010 in the range of $4-6 million as we complete the exit activities associated with our Russia pressure pumping business.

Summarized operating results from discontinued operations are as follows:


	Three Months Ended December 30,
	2009			2008
	(in thousands)
Revenue	$	—		$	14,854
Loss before income taxes		(4,874	)		(1,219	)
Income tax expense		—			6

Loss from discontinued operations	$	(4,874	)	$	(1,225	)

Losses in the first fiscal quarter of fiscal 2010 primarily consist of $1.6 million of loss on the sale of equipment and inventory, $1.0 million of freight to redeploy certain equipment and other ongoing costs associated with discontinuing operating activities in the Russia pressure pumping market.

Liquidity and Capital Resources

Historical Cash Flow

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


	Three Months Ended December 31,
	2009			2008
Cash provided by operations	$	17.2		$	200.6
Cash used in investing		(33.9	)		(116.2	)
Cash used in financing		(5.3	)		(56.4	)
Effect of exchange rate changes on cash		0.4			(4.9	)

Change in cash and cash equivalents	$	(21.6	)	$	23.1

Cash flow from operations of $17.2 million for the three months ended December 31, 2009 decreased $183.4 million, or 91%, compared to the same period in the prior year. Income (loss) from continuing operations of $(8.4) million for the first three months of fiscal 2010 was $158.9 million lower than the same period of fiscal 2009, primarily as a result of the market downturn characterized by lower drilling activity, lower demand for our services and products and lower pricing. Non-cash items included in net income, primarily including depreciation and amortization, stock-based compensation expense, pension settlement and net (gain) loss on disposal of assets, totaled $85.3 million for the first three months of fiscal 2010, compared to $114.1 million for the same period in fiscal 2009. Finally, changes in working capital and other operating accounts used cash totaling $51.2 million in the first three months of fiscal 2010, compared to using cash of $64.6 million for the first three months of fiscal 2009.

Cash used in investing activities decreased $82.3 million, or 71%, in the first quarter of fiscal 2010 compared to fiscal 2009, as a result of a decrease in capital expenditures. Lower demand for our products and services resulted in lower expansion capital required to meet market conditions.

Cash used in financing activities decreased $51.1 million, or 91%, in fiscal 2010 compared to fiscal 2009, primarily as a result of treasury stock purchases of 3,466,500 shares of common stock for $44.2 million in the first quarter of fiscal 2009 that did not repeat in the same quarter of fiscal 2010. Cash used in financing activities in fiscal 2010 primarily include dividend payments to shareholders.

Liquidity and Capital Resources

Our cash and cash equivalents balance of $261.1 million at December 31, 2009 and cash flows from operations are expected to be our primary source of liquidity for the remainder of fiscal 2010. Our sources of liquidity also include the available financing facilities listed below (in millions):


Financing Facility	Expiration	Borrowings at December 31, 2009		Available at December 31, 2009
Revolving Credit Facility	August 2012	$	—	$	400.0
Discretionary	Various times within the next 12 months		10.8		17.8

As of December 31, 2009, the Company had $249.9 million of the 5.75% Senior Notes due 2011 and $249.1 million of the 6% Senior Notes due 2018 issued and outstanding, net of discount.

Our amended and restated revolving credit facility (the “Revolving Credit Facility”) permits borrowings of up to $400 million in principal amount. The Revolving Credit Facility includes a $50 million sublimit for the issuance of standby letters of credit and a $20 million sublimit for swingline loans. Swingline loans have short-term maturities and the remaining amounts outstanding under the Revolving Credit Facility become due and payable in August 2012. In addition, we have the right to request up to an additional $200 million over the permitted borrowings of $400 million, subject to the approval of our lenders at the time of the request. Depending on the amount of borrowings outstanding under this facility, the interest rate applicable to borrowings generally ranges from 30-40 basis points above LIBOR. We are charged various fees in connection with the Revolving Credit Facility, including a commitment fee based on the average daily unused portion of the commitment, totaling $0.1 million for the three months ended December 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 three months ended December 31, 2009. There were no borrowings under the Revolving Credit Facility at December 31, 2009, and pursuant to the Merger Agreement, there must be no borrowings outstanding under the Revolving Credit Facility on the completion date of the Merger.

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

In addition to the Revolving Credit Facility and the Committed Credit Facility, we had $28.6 million of unsecured discretionary lines of credit at December 31, 2009, which expire at the bank’s discretion. There are no requirements for commitment fees or compensating balances in connection with these lines of credit, and interest is at prevailing market rates. There was $10.8 million in outstanding borrowings under these lines of credit at December 31, 2009. The weighted average interest rate on short-term borrowings outstanding under the discretionary lines as of December 31, 2009 was 3.0%.

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

Cash Requirements

We had $39.7 million of capital expenditures during the three months ended December 31, 2009. We currently anticipate capital expenditures to be approximately $170-200 million in fiscal 2010. The actual amount of fiscal 2010 capital expenditures will depend primarily on maintenance requirements and market opportunities and our ability to execute our planned capital expenditures.

We expect our minimum pension and postretirement funding requirements to be approximately $15.0 million in fiscal 2010. We contributed $4.4 million to such plans during the three months ended December 31, 2009.

We have paid cash dividends in the amount of $0.05 per common share each quarter since the fourth quarter of fiscal 2005. For the three months ended December 31, 2009, we paid cash dividends totaling $14.6 million. We anticipate paying a quarterly cash dividend in fiscal 2010 until the Merger is completed; 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. We also expect to make a payment of $30.7 million in March 2010 as part of the option to purchase the pumping service equipment from our limited partnership. See Note 7 of our unaudited condensed consolidated financial statements.

As of December 31, 2009, we had $249.9 million of 5.75% Senior Notes due 2011 and $249.1 million of 6% Senior Notes due 2018 issued and outstanding, net of discount. We expect cash paid for interest expense to be approximately $30.0 million in fiscal 2010.

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 7 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

Accounting Pronouncements

In June 2009, the FASB issued an update to ASC 810, Consolidation – Variable Interest Entities, which addresses the addition of qualified special purpose entities into previous guidance as the concept of these entities was eliminated by ASC 860. This guidance also modifies the analysis by which a controlling interest of a variable interest entity is determined thereby requiring the controlling interest to consolidate the variable interest entity. This statement could impact the way we account for our limited partnership discussed in Note 7 under Lease and Other Long-Term Commitments. This guidance becomes effective as of the beginning of the first annual reporting period beginning after November 15, 2009 and should be applied prospectively for interim and annual periods during that period going forward. We will adopt this guidance on October 1, 2010, and have not yet determined the impact, if any, on our consolidated financial statements.

In April 2008, the FASB issued guidance contained in ASC 350, Intangibles – Goodwill and Others – General Intangibles Other than Goodwill, amending the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under previously existing literature. The objective of this guidance is to improve the consistency between the useful life of a recognized intangible asset under ASC 350 and the period of expected cash flows used to measure the fair value of the asset under ASC 805, Business Combinations. This guidance is effective for the Company beginning October 1, 2009, and is not expected to have a significant impact on our consolidated financial statements.

In December 2007, the FASB issued an update to ASC 805, Business Combinations, to establish principles and requirements for the recognition and measurement of assets, liabilities and goodwill, and requires that most transaction and restructuring costs related to the acquisition be expensed. This guidance is effective for business combinations occurring on or after the beginning of the first annual reporting period beginning after December 15, 2008. Consequently, we adopted this guidance on October 1, 2009 with no material impact 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 include all statements other than historical fact, including those identified as “Outlook” and by the use of terms and phrases such as “expect,” “estimate,” “project,” “forecast,” “believe,” “achievable,” “anticipate,” “should” and similar terms and phrases that convey the uncertainty of future events or outcomes. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances but that may not prove to be accurate.

Such statements are subject to risks and uncertainties, including, but not limited to, general economic and business conditions; global economic growth and activity; oil and natural gas market conditions; political and economic uncertainty; and other risks and uncertainties described elsewhere in this Report and in our Annual Report on Form 10-K. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual results may vary materially from those expected, estimated or projected. Forward-looking statements speak only as of the date they are made and, other than as required under securities laws, we do not assume a duty to update or revise these forward-looking statements.

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 for the year ended September 30, 2009. No events or transactions have occurred during the three-month period ended December 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. As of the end of the period covered by this quarterly report, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act of 1934, as amended (the “Exchange Act”). This evaluation was carried out under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of the Company. Based on their evaluation of our disclosure controls and procedures, as defined by Rule 13a-15(e) of the Exchange Act, these officers have concluded that as of the end of the period covered by this report, the disclosure controls and procedures are effective.

There has been no change in our internal controls over financial reporting during the quarter ended December 31, 2009 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II

OTHER INFORMATION

Item 1.

Legal Proceedings

The information regarding litigation and environmental matters described in Note 7 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 period ended December 31, 2009 in our “Risk Factors” as discussed in our Form 10-K for the fiscal year ended September 30, 2009.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

(a) None

(b) None

Item 3.

Defaults upon Senior Securities

None

Item 4.

Submission of Matters to a Vote of Security Holders

None

Item 5.

Other Information

None

Item 6.

Exhibits



*31.1		Section 302 certification for J. W. Stewart.

*31.2		Section 302 certification for Jeffrey E. Smith.

*32.1		Section 906 certification furnished for J. W. Stewart.

*32.2		Section 906 certification furnished for Jeffrey E. Smith.

**101.0		The following financial statements and accompanying notes from BJ Service Company’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2009, filed with the Securities and Exchange Commission on February 8, 2009,formatted in eXtensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statement of Operations for the three months ended December 31, 2009 and 2008; (ii) the Condensed Consolidated Statement of Financial Position as of December 31, 2009 and September 30, 2009; (iii) the Condensed Consolidated Statement of Stockholders’ Equity and Other Comprehensive Income for the three months ended December 31, 2009; and (iv) the Condensed Consolidated Statement of Cash Flows for the three months ended December 31, 2009 and 2008.

*	Filed herewith.

**	Furnished herewith.

SIGNATURES

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


	BJ Services Company
	(Registrant)

Date: February 8, 2010	By:	/s/ J. W. Stewart
		J. W. Stewart
		Chairman of the Board, President and Chief Executive Officer

Date: February 8, 2010	By:	/s/ Jeffrey E. Smith
		Jeffrey E. Smith
		Executive Vice President - Finance and Chief Financial Officer

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