Form 10-Q

10-Q 1 d10q.htm FORM 10-Q Form 10-Q

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, 2006

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

For the Transition Period From to .

Commission file number 1-10570

BJ SERVICES COMPANY

(Exact name of registrant as specified in its charter)

Delaware

63-0084140

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)


4601 Westway Park Boulevard, Houston, Texas		77041
(Address of principal executive offices)		(Zip Code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

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

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

There were 293,235,042 shares of the registrant’s common stock, $.10 par value, outstanding as of February 6, 2007.

BJ SERVICES COMPANY

INDEX


PART I - FINANCIAL INFORMATION:

	Item 1. Financial Statements

	Consolidated Condensed Statement of Operations (Unaudited) - Three months ended December 31, 2006 and 2005	3

	Consolidated Condensed Statement of Financial Position (Unaudited) - December 31, 2006 and September 30, 2006	4

	Consolidated Statement of Stockholders’ Equity and Other Comprehensive Income (Unaudited) - Three months ended December 31, 2006	5

	Consolidated Condensed Statement of Cash Flows (Unaudited) - Three months ended December 31, 2006 and 2005	6

	Notes to Unaudited Consolidated Condensed Financial Statements	7

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	19

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	32

	Item 4. Controls and Procedures	32

PART II - OTHER INFORMATION

	Item 1. Legal Proceedings	33

	Item 1A. Risk Factors	33

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	33

	Item 3. Defaults upon Senior Securities	33

	Item 4. Submission of Matters to a Vote of Security Holders	33

	Item 5. Other Information	33

	Item 6. Exhibits	34

PART I

FINANCIAL INFORMATION

Item 1.

Financial Statements

BJ SERVICES COMPANY

CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS (UNAUDITED)

(In thousands, except per share amounts)


	Three Months Ended December 31,
	2006			2005
Revenue	$	1,183,940		$	956,161
Operating expenses:
Cost of sales and services		788,635			649,266
Research and engineering		15,694			15,153
Marketing		25,813			24,592
General and administrative		37,207			37,591
Loss on disposal of assets		265			8

Total operating expenses		867,614			726,610

Operating income		316,326			229,551
Interest expense		(8,779	)		(135	)
Interest income		320			3,390
Other (expense) income - net		(2,076	)		952

Income before income taxes		305,791			233,758
Income tax expense		98,707			74,101

Net income	$	207,084		$	159,657

Earnings per share:
Basic	$	.71		$	.49
Diluted	$	.70		$	.48

Weighted-average shares outstanding:
Basic		293,024			323,903
Diluted		296,477			329,596

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

BJ SERVICES COMPANY

CONSOLIDATED CONDENSED STATEMENT OF FINANCIAL POSITION

(UNAUDITED)

(In thousands)


	December 31, 2006		September 30, 2006
	December 31, 2006		September 30, 2006
ASSETS

Current assets:
Cash and cash equivalents	$	62,525	$	92,445
Receivables - net		915,271		927,027
Inventories - net:
Products		192,150		185,249
Work in process		28,088		27,308
Parts		166,093		143,347

Total inventories		386,331		355,904
Deferred income taxes		6,378		5,103
Prepaid expenses		36,784		36,311
Other current assets		39,504		42,070

Total current assets		1,446,793		1,458,860

Property - net		1,493,095		1,392,926
Deferred income taxes		27,753		29,557
Goodwill		933,310		928,297
Other assets		51,617		52,648

	$	3,952,568	$	3,862,288

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	417,992	$	435,040
Short-term borrowings		45,026		160,274
Accrued employee compensation and benefits		95,075		131,725
Income and other taxes		141,747		85,872
Accrued insurance		21,305		21,965
Other accrued liabilities		128,317		113,060

Total current liabilities		849,462		947,936

Commitments and contingencies (Note 6)
Long-term debt		499,711		499,694
Deferred income taxes		67,683		66,584
Other long-term liabilities		201,611		201,134
Stockholders’ equity		2,334,101		2,146,940

	$	3,952,568	$	3,862,288

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

BJ SERVICES COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND

OTHER COMPREHENSIVE INCOME (UNAUDITED)

(In thousands)


	Common Stock Shares		Common Stock		Capital In Excess of Par			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income			Total
Balance, September 30, 2006	293,194		$	34,752	$	1,028,813		$	(1,433,808	)	$	2,494,350		$	22,833		$	2,146,940

Comprehensive income:
Net income												207,084
Other comprehensive income, net of tax:
Cumulative translation adjustments															(10,693	)
Comprehensive income																		196,391
Re-issuance of treasury stock for:
Stock options	149								3,952			(1,869	)					2,083
Stock purchase plan	488								12,916			(406	)					12,510
Director stock awards	43					(1,127	)		1,127									—
Stock based compensation						9,184												9,184
Tax benefit of stock options exercised						471												471
Purchase of treasury stock	(669	)							(20,006	)								(20,006	)
Dividends declared												(13,472	)					(13,472	)

Balance, December 31, 2006	293,205		$	34,752	$	1,037,341		$	(1,435,819	)	$	2,685,687		$	12,140		$	2,334,101

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

BJ SERVICES COMPANY

CONSOLIDATED CONDENSED STATEMENT OF CASH FLOWS (UNAUDITED)

(In thousands)


	Three Months Ended December 31,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	207,084		$	159,657
Adjustments to reconcile net income to cash provided by operating activities:
Minority interest		2,482			771
Loss on disposal of assets		265			8
Depreciation and amortization		45,705			38,185
Excess tax benefits from stock based compensation		(453	)		(983	)
Deferred income tax expense		1,004			8,108
Changes in:
Receivables		18,348			(34,129	)
Inventories		(28,922	)		(15,943	)
Prepaid expenses		(401	)		(15,447	)
Other current assets		2,848			(7,304	)
Accounts payable		(19,444	)		(20,815	)
Accrued employee compensation and benefits		(36,650	)		(21,849	)
Current income tax		55,417			46,789
Other current liabilities		14,981			24,910
Other - net		8,829			11,909

Net cash provided by operating activities		271,093			173,867

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(146,861	)		(81,860	)
Proceeds from disposal of assets		1,150			3,511
Acquisitions of businesses, net of cash		(10,695	)		—

Net cash used in investing activities		(156,406	)		(78,349	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of short-term borrowings, net		(115,248	)		(115	)
Dividends paid to shareholders		(14,660	)		(16,177	)
Purchase of treasury stock		(20,006	)		(18,954	)
Excess tax benefits from stock based compensation		453			983
Proceeds from exercise of stock options and stock purchase plan		6,673			8,605

Net cash used in financing activities		(142,788	)		(25,658	)

Effect of exchange rate changes on cash		(1,819	)		55

(Decrease)/Increase in cash and cash equivalents		(29,920	)		69,915
Cash and cash equivalents at beginning of period		92,445			356,508

Cash and cash equivalents at end of period	$	62,525		$	426,423

Cash Paid for Interest and Taxes:
Interest	$	13,017		$	128
Taxes		41,810			18,156

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

BJ SERVICES COMPANY

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 1 General

In our opinion, the unaudited consolidated condensed financial statements of BJ Services Company (the “Company”) include all adjustments (consisting solely of normal recurring adjustments) necessary for a fair presentation of its financial position and statement of stockholders’ equity as of December 31, 2006, and its results of operations and cash flows for each of the three-month periods ended December 31, 2006 and 2005. The consolidated condensed statement of financial position at September 30, 2006 is derived from the September 30, 2006 audited consolidated financial statements. Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. The results of operations and cash flows for the three-month period ended December 31, 2006 are not necessarily indicative of the results to be expected for the full year.

Certain amounts for fiscal 2006 have been reclassified in the accompanying consolidated condensed financial statements to conform to the current year presentation.

Note 2 Earnings Per Share (“EPS”)

Basic EPS excludes dilution and is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted EPS is based on the weighted-average number of shares outstanding during each period and the assumed exercise of dilutive instruments (stock options, the stock purchase plan, the stock incentive awards, bonus stock, and the 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,
	2006		2005
Net income	$	207,084	$	159,657
Weighted-average common shares outstanding		293,024		323,903

Basic earnings per share	$	.71	$	.49


	Three Months Ended December 31,
	2006		2005
Weighted-average common and dilutive potential common shares outstanding:
Weighted-average common shares outstanding		293,024		323,903
Assumed exercise of stock options ⁽¹⁾		3,453		5,693
Weighted-average dilutive shares outstanding		296,477		329,596

Diluted earnings per share	$	.70	$	.48

⁽¹⁾

For the three months ended December 31, 2006, 2.5 million stock options were excluded from the computation of diluted earnings per share due to their antidilutive effect. There were no stock options excluded from the computation of diluted earnings per share due to their antidilutive effect for the three months ended December 31, 2005.

Note 3 Segment Information

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

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

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

The International Pressure Pumping segment has five operating segments. Similar to U.S./Mexico Pressure Pumping, it includes cementing and stimulation services. These services are provided to customers in more than 50 countries in the major international oil and natural gas producing areas of Latin America, Europe and Africa, Asia Pacific, Russia and the Middle East. The operating segments have been aggregated into one reportable segment because they have similar economic characteristics, offer the same type of services, have similar production processes and use the same methods to provide their services. They also serve the same or similar customers, which include major multi-national, independent and national or state-owned oil companies.

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

The accounting policies of the segments are the same as those described in the summary of significant accounting policies in Note 2 of the Notes to the Consolidated Financial Statements included in our annual report on Form 10-K for the fiscal year ended September 30, 2006. Operating segment performance is evaluated based on operating income. Intersegment sales and transfers are not material.

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


	U.S./Mexico Pressure Pumping		Canada Pressure Pumping		International Pressure Pumping		Oilfield Services Group		Corporate			Total
	(in thousands)
Three Months Ended December 31, 2006
Revenue	$	640,826	$	111,664	$	252,056	$	179,394	$	—		$	1,183,940
Operating income (loss)		252,557		13,407		40,338		32,698		(22,674	)		316,326
Identifiable assets		1,297,008		475,636		1,082,945		732,277		364,702			3,952,568

Three Months Ended December 31, 2005
Revenue	$	497,294	$	124,265	$	191,729	$	142,873	$	—		$	956,161
Operating income (loss)		175,479		31,767		25,623		25,153		(28,471	)		229,551
Identifiable assets		1,101,186		380,748		864,985		594,981		639,435			3,581,335

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


	Three Months Ended December 31,
	2006			2005
Total operating profit for reportable segments	$	316,326		$	229,551
Interest expense		(8,779	)		(135	)
Interest income		320			3,390
Other (expense)/income – net		(2,076	)		952

Income before income taxes	$	305,791		$	233,758

Note 4 Acquisitions

On November 3, 2006, we completed the acquisition of Profile International Ltd. (“Profile”) for a total purchase price of $2.4 million,which resulted in $2.1 million of goodwill. Profile, located in

Newcastle, England, provides caliper inspection tools for pipeline integrity assessment to markets worldwide. This business complements our pipeline inspection business in the Oilfield Services Group.

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

We are in the process of completing our review and determination of the fair values of the assets acquired. Accordingly, allocation of the purchase price is subject to revision based on final determination of the asset values. The pro forma financial information for these acquisitions is not included as they were not material to the Company.

Note 5 Employee Stock Plans

Our 1995 Incentive Plan, 1997 Incentive Plan, 2000 Incentive Plan and 2003 Incentive Plan (the “Plans”) provide for the granting of stock based compensation to officers, key employees and non-employee directors. Our 1999 Employee Stock Purchase Plan (the “Purchase Plan”) allows all employees to purchase shares of our Common Stock at 85% of market value on the first or last business day, whichever is lower, of the twelve-month plan period beginning each October. Purchases are limited to 10% of an employee’s regular salary. The following grants were made on November 15, 2006. Stock based compensation for the three months ended December 31, 2006 was $10.3 million. We expect fiscal year 2007 stock based compensation expense to be $39.4 million.

Stock Options: Officers, key employees, and non-employee directors were granted stock options and compensation expense for the grant was determined under SFAS 123(R) for the three months ended December 31, 2006 and was calculated using the Black-Scholes option pricing model with the following assumptions:


November 15, 2006 Grant	Officer			Non-officer
Expected life of grant (years)		4.8			3.7
Interest rate		4.6	%		4.6	%
Volatility		37.0	%		33.4	%
Dividend yield		0.6	%		0.6	%
Weighted-average fair value per share at grant date	$	12.08		$	9.84
Assumed forfeiture rate		3.17	%		3.17	%
Total shares granted		813,641			888,309

We recorded $5.5 million of compensation expense in the first quarter of fiscal 2007 related to options. We expect to record compensation expense of approximately $19.7 million for stock options in fiscal 2007.

Bonus Stock: Certain officers were granted bonus stock awards. The bonus stock will be distributed in four equal installments at the end of each calendar quarter of 2007 subject to the Company’s earnings per share for each quarter exceeding the prior year quarter. The award is considered an equity award with a performance condition under SFAS 123(R). As such, no compensation cost will be recognized if the performance condition is not satisfied. In addition to the bonus stock, each officer will receive cash equal to his or her tax liability on the bonus stock they receive. The cash portion of the award is considered a liability award and we recognize compensation expense for the cash award ratably over the performance period. The cash award is re-valued quarterly in accordance with SFAS 123(R). Based on current projections, we expect to record compensation expense of approximately $4.5 million for officer bonus stock awards in fiscal 2007.

Stock Awards: In addition to stock options, officers and non-employee directors were granted an award of our common stock with no exercise price (“restricted stock”). Restricted Stock awards vest over a three year period. Compensation expense is recorded over the required service period, which is generally the vesting period. Issuances of the officer stock awards are subject to the Company earning a profit at the end of each fiscal year. In addition to the award of stock, each officer will also receive cash equal to his or her tax liability on the awards they receive, if any, at the end of the performance period. Officer stock awards and the related cash award are accounted for similar to bonus stock awards. The Company expects to record compensation expense of approximately $2.5 million for stock awards in fiscal 2007.

Stock Incentive Awards: Each officer was granted performance units. In addition to the award of Units, each officer will also receive cash equal to his or her tax liability on the Units they receive, if any, at the end of the performance period.

Under SFAS 123(R), we are recognizing compensation expense for grants of stock incentive awards based on the fair value at the date of the grant using a lattice model (Monte Carlo simulation). The fair value for awards granted during the three months ended December 31, 2006 and assumptions used to determine the fair value are listed below:

Fiscal

Year

Granted

Volatility

Dividend

Yield

Weighted

Average

Fair value

per share

2007

113,180

33.41%

0.61%

$31.95

We expect to record compensation expense of approximately $6.5 million for stock incentive awards in fiscal 2007.

Stock Purchase Plan: We have reserved a total of 774,911 shares for fiscal 2007 under the stock purchase plan. Compensation expense determined under SFAS 123(R) for the three months ended December 31, 2006 was calculated using the Black-Scholes option pricing model with the following assumptions:


	2006
Expected life (years)		1.0
Interest rate		4.9	%
Volatility		39.1	%
Dividend yield		0.7	%
Weighted-average fair value per share at grant date	$	8.81

We expect to record compensation expense of approximately $6.1 million for the Purchase Plan in fiscal 2007.

Note 6 Commitments and Contingencies

Litigation

We, through performance of our service operations, are sometimes named as a defendant in litigation, usually relating to claims for bodily injuries or property damage (including claims for well or reservoir damage). We maintain insurance coverage against such claims to the extent deemed prudent by management.

Further, through a series of acquisitions, we assumed responsibility for certain claims and proceedings made against the Western Company of North America, Nowsco Well Service Ltd., OSCA and other companies whose stock we acquired in connection with their businesses. Some, but not all, of such claims and proceedings will continue to be covered under insurance policies of our predecessors that were in place at the time of the acquisitions.

Although the outcome of the claims and proceedings against us (including Western, Nowsco and OSCA) cannot be predicted with certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on our financial position or results of operations for which it has not already provided.

Newfield Litigation

On April 4, 2002, a jury rendered a verdict adverse to OSCA in connection with litigation pending in the United States District Court for the Southern District of Texas (Houston). The lawsuit, filed by Newfield Exploration on September 29, 2000, arose out of a blowout that occurred in 1999 on an offshore well owned by Newfield. The jury determined that OSCA’s negligence caused or contributed to the blowout and that it was responsible for 86% of the damages suffered by Newfield. The total damage amount awarded to Newfield was $15.6 million (excluding pre- and post-judgment interest). The Court delayed entry of the final judgment in this case pending the completion of the related insurance coverage litigation filed by OSCA against certain of its insurers and its former insurance broker. The Court elected to conduct the trial of the insurance coverage issues based upon the briefs of the parties. In the interim, the related litigation filed by OSCA against its former insurance brokers for errors and omissions in connection with the policies at issue in this case has been stayed. On February 28, 2003, the Court issued its final judgment in connection with the Newfield claims, based upon the jury’s verdict. At the same time, the Court issued rulings adverse to OSCA in connection with its claim for insurance coverage. Motions for New Trial were denied by the Judge and the case was appealed to the U.S. Court of Appeals for the Fifth Circuit, both with regard to the liability case and the insurance coverage issues. The Fifth circuit issued its ruling on April 12, 2006 finding against OSCA on the liability issues, but ruling in OSCA’s favor on insurance coverage. Based on the Fifth Circuit’s opinion, we believe that over half of the judgment against OSCA is covered by an insurance policy issued by AISLIC (an AIG affiliate). AISLIC filed a Motion for Re-hearing with the Fifth Circuit, which was denied. The case has been remanded to the District Court (as of June 5, 2006) for further consideration of one exclusion contained in the AISLIC policy. Even if the interpretation of this exclusion is resolved in a manner that is adverse to OSCA, a majority of the judgment against OSCA will remain covered by the AISLIC policy. Upon remand, Newfield filed a motion to enforce its judgment against OSCA, which the court denied. Great Lakes Chemical Corporation, (which owned the majority of the outstanding shares of OSCA at the time of the acquisition) agreed to indemnify OSCA for 75% of any uninsured liability in excess of $3 million arising from the Newfield litigation. Taking this indemnity into account and without regard to the outcome of the insurance coverage dispute, our share of the verdict is approximately $5.5 million. We are fully reserved for our share of this liability.

Asbestos Litigation

In August 2004, certain predecessors of ours, along with numerous other defendants were named in four lawsuits filed in the Circuit Courts of Jones and Smith Counties in Mississippi. These four lawsuits included 118 individual plaintiffs alleging that they suffer various illnesses from exposure to asbestos and seeking damages. The lawsuits assert claims of unseaworthiness, negligence, and strict liability, all based upon the status of our predecessors as Jones Act employers. The plaintiffs were required to complete data sheets specifying the companies they were employed by and the asbestos-containing products to which they were allegedly exposed. Through this process, approximately 25 plaintiffs have identified us or our predecessors as

their employer. Amended lawsuits were filed by four individuals against us and the remainder of the original claims (114) were dismissed. Of these four lawsuits, three failed to name us as an employer or manufacturer of asbestos containing products so we were thereby dismissed. Subsequently an individual from one of these lawsuits brought his own action against us. As a result, we are currently named as an employer in two of the Mississippi lawsuits. It is possible that as many as 21 other claimants who identified us or our predecessors as their employer could file suit against we, 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 its 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. Some of the allegations involve claims that we are the successor to the Byron Jackson Company. To date, we have been successful in obtaining dismissals of such cases without any payment in settlements or judgments, although some remain pending at the present time. We intend to defend ourselves vigorously in all of these cases based on the information available to us at this time, we do not expect the outcome of these lawsuits, individually or collectively, to have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these lawsuits or additional similar lawsuits, if any, that may be filed.

Gene Ellison et al v FPC Disposal et al

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

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

This case has been settled, and our contribution to the settlement was not material.

Environmental

Federal, state and local laws and regulations govern our operation of underground fuel storage tanks. Rather than incur additional costs to restore and upgrade tanks as required by regulations, management opted to remove the existing tanks. We have completed the removal of these tanks and have remedial cleanups in progress related to the tank removals. In addition, we are conducting environmental investigations and remedial actions at current and former Company locations and, along with other companies, are currently named as a potentially responsible party at four waste disposal sites owned by third parties. An accrual of approximately $3.8 million has been established for such environmental matters, which is management’s best

estimate of our portion of future costs to be incurred. Insurance is also maintained for some environmental liabilities.

Lease and Other Long-Term Commitments

In 1999, we contributed certain pumping service equipment to a limited partnership. The equipment is used to provide services to our customers for which we pay a service fee over a period of at least 6 years, but not more than 13 years, at approximately $12 million annually. This is accounted for as an operating lease. We assessed the terms of this agreement and determined it was a variable interest entity as defined in FIN 46, Consolidation of Variable Interest Entities. However, we were not deemed to be the primary beneficiary, and therefore, consolidation was not required. The transaction resulted in a gain that is being deferred and amortized over 13 years. The balance of the deferred gain was $15.3 million and $16.1 million as of December 31, 2006 and September 30, 2006, respectively. The agreement permits substitution of equipment within the partnership as long as the implied fair value of the new property transferred in at the date of substitution equals or exceeds the implied fair value, as defined, of the current property in the partnership that is being replaced. In September 2010, we have the option, but not the obligation, to purchase the pumping service equipment for approximately $32 million. We currently have the intent to exercise this option.

The option price to purchase the equipment under the partnership depends in part on the fair market value of the equipment held by the partnership at the time the option is exercised as well as other factors specified in the agreement.

In 1997, we contributed certain pumping service equipment to a limited partnership, 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 8 years, but not more than 13 years, at approximately $10 million annually. This is accounted for as an operating lease. We assessed the terms of this agreement and determined it was a variable interest entity as defined in FIN 46, Consolidation of Variable Interest Entities. However, we were not deemed to be the primary beneficiary, and therefore, consolidation was not required. Subsequent to December 31, 2006, we agreed to purchase the remaining partnership interest for approximately $48 million, and as a result acquired the partnership equipment. The acquisition of the partnership controlling interest will be accounted for as an asset purchase.

Other Commercial Commitments

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

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

following table summarizes our other commercial commitments as of December 31, 2006 (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	$	39,673	$	35,017	$	4,656	$	—	$	—
Guarantees		133,578		80,136		25,755		13,399		14,288

Total Other Commercial Commitments	$	173,251	$	115,153	$	30,411	$	13,399	$	14,288

Note 7 Supplemental Financial Information

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


	Three Months Ended December 31,
	2006			2005
Minority interest	$	(2,482	)	$	(771	)
Non-operating net foreign exchange loss		(335	)		(145	)
Recovery of misappropriated funds		—			2,790
Other, net		741			(922	)

Other (expense) income, net	$	(2,076	)	$	952

In October 2004, the Company received a report from a whistleblower alleging that its Asia Pacific Region Controller had misappropriated Company funds in fiscal 2001. The Company began an internal investigation into the misappropriation and whether other inappropriate actions occurred in the Region. The Region Controller admitted to multiple misappropriations totaling approximately $9.0 million during a 30-month period ended April 2002. The misappropriations of approximately $9.0 million were repaid to the Company and the Region Controller’s employment was terminated. The misappropriations were an expense of the Company in the form of theft that were recorded in the Consolidated Statement of Operations in periods prior to April 2002. The $9.0 million repayment represents a gain contingency and was reflected in Other Income in the Consolidated Condensed Statement of Operations for the quarter ended December 31, 2004 in accordance with SFAS 5, Accounting for Contingencies.

The Company is continuing to investigate whether additional funds were misappropriated beyond the $9.0 million originally identified. The Company has identified an additional $1.7 million that it believes was misappropriated by the former Region Controller. The additional $1.7 million of likely misappropriations were expenses of the Company that were recorded in the Consolidated Statement of Operations in periods prior to April 2002. It is possible that additional information could emerge resulting in further adjustments in the Consolidated Statements of Operations, but no material adjustments are known at this time.

In October 2004, the Company also received whistleblower allegations that illegal payments to foreign officials had been made in the Asia Pacific Region. The Audit Committee of the Board of Directors engaged independent counsel to conduct a separate investigation to determine whether any such illegal payments were made. The investigation found information indicating a significant likelihood that payments, made by the Company to an entity in the Asia Pacific Region with which the Company has certain contractual relationships, were then used to make payments to government officials in the Asia Pacific Region. This information included information indicating that certain employees of the Company in the Asia Pacific Region believed that the funds paid to the entity would be used to make payments to government officials. The payments, which may have been illegal, aggregated approximately $2.6 million and were made from fiscal 1999 through 2004.

Thereafter, in December 2005, the Company received a payment of approximately $2.8 million from the entity referenced above. The entity said that the funds represented the $2.6 million of funds described above, plus an interest amount, and that the $2.6 million had been misappropriated for the benefit of certain of that entity’s employees and was not used to make payments to government officials. The Audit Committee’s investigation was not able to verify this claim. The $2.8 million payment represents a gain contingency and was reflected in Other Income in the Consolidated Condensed Statement of Operations for the quarter ended December 31, 2005 in accordance with SFAS 5, Accounting for Contingencies.

The Company and the Audit Committee also investigated a large volume of other payments made by the Company during the period of fiscal 1998 through 2004 in the Asia Pacific Region. With respect to approximately $10 million of these payments, the investigations to date either have not been able to establish the legitimacy of the transactions reflected in the underlying documents or have not been able to resolve questions about the adequacy of the underlying documents to support the accounting entries. These payments may have been proper, but due to circumstances surrounding the payments, the investigations have not been able to determine whether theft, illegal payments or other improprieties may have been involved. The payments have been previously expensed, and therefore the Company believes that no additional expense is required to be recorded for such payments.

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

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

The DOJ, SEC and other authorities have a broad range of civil and criminal sanctions under the U.S. Foreign Corrupt Practices Act and other laws, which they may seek to impose against corporations and individuals in appropriate circumstances including, but not limited to, injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs. Such agencies and authorities have entered into agreements with, and obtained a range of sanctions against, several public corporations and individuals arising from allegations of improper payments and deficiencies in books and records and internal controls, whereby civil and criminal penalties were imposed, including in some cases multi-million dollar fines and other sanctions. We are in discussions with the DOJ and SEC regarding certain of the matters described above. It is not possible to accurately predict at this time when any of these matters will be resolved. Based on current information, we cannot predict the outcome of such investigations, whether we will reach resolution through such discussions or what, if any, actions may be taken by the DOJ, SEC or other authorities or the effect the foregoing may have on our consolidated financial statements.

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

managers at each of our five regional bases worldwide, to document, enhance, and test our control processes.

Note 8 Employee Benefit Plans

We have a U.S. Defined Benefit Plan, Foreign Defined Benefit Plans, and a Postretirement Benefit Plan, which are described in more detail in Note 9 of the Notes to the Consolidated Financial Statements included in our annual report on Form 10-K for the fiscal year ended September 30, 2006. Below is the amount of net periodic benefit costs recognized under our Foreign Defined Benefit Plans (in thousands). Information for our U.S. Defined Benefit Plan net periodic benefit costs is not been presented as it is not material to the Company.

Defined Benefit Plans


	Three Months Ended December 31,
	Non-U.S.
	2006			2005
Service cost for benefits earned	$	1,604		$	1,269
Interest cost on projected benefit obligation		2,507			2,114
Expected return on plan assets		(2,341	)		(2,029	)
Recognized actuarial loss		760			543
Net amortization and deferral		(349	)		31

Net pension (income) cost	$	2,181		$	1,928

In September 2006, we entered into an agreement to settle our obligation with respect to the U.S. defined benefit plan. Plan assets of approximately $72 million, plus our contribution of $1.5 million, were used to purchase an insurance contract that will be used to fund the benefits and settle the plan. The proposed settlement requires approval from the Pension Benefit Guaranty Corporation and the Internal Revenue Service to relieve us of primary responsibility for the pension benefit obligation. Once regulatory approval is obtained, which is expected in fiscal 2007, we will expense approximately $23.3 million of prepaid pension cost. As a result of these actions, we have reclassified the pension asset and recorded the payment for the annuity as current assets.

In fiscal 2007, we will have a minimum pension funding requirement of $8.1 million for the defined benefit plans. In addition to the minimum pension funding requirement, we intend to contribute $7.6 million in discretionary contributions for our Defined Benefit Plans. We have paid $1.9 million in discretionary contributions and $2.9 million in non-discretionary contributions during the three months ended December 31, 2006. These contributions have been and are expected to be funded by cash flows from operating activities.

Postretirement Benefit Plan


	Three Months Ended December 31,
	2006		2005
Service cost for benefits attributed to service during the period	$	993	$	867
Interest cost on accumulated postretirement benefit obligation		825		717

Net periodic postretirement benefit cost	$	1,818	$	1,584

We expect to contribute $1.3 million to the post retirement plan in fiscal 2007, which represents the

anticipated claims.

Note 9 New Accounting Standards

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

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

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

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

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

Recognition of an asset or liability related to the funded status of a pension plan and disclosures are effective for fiscal years ending after December 15, 2006 and the required changes in the measurement date are effective for fiscal years ending after December 15, 2008. We currently measure our defined benefit plan assets and obligations as of our fiscal year-end. Thus, this portion of SFAS 158 will not impact our financial statements. We are currently in the process of evaluating the impact on our financial statements from the other requirements of SFAS 158.

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

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

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 consists of pumping a cement slurry into a well between the casing and the wellbore to isolate fluids that might otherwise damage the casing and/or affect productivity, or that could migrate to different zones, primarily during the drilling and completion phase of a well. See “Business” included in our Annual Report on Form 10-K for the period ended September 30, 2006 for more information on these operations.

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

Market Conditions

Our worldwide operations are primarily driven by the number of oil and natural gas wells being drilled, the depth and drilling conditions of such wells, the number of well completions and the level of workover activity. Drilling activity, in turn, is largely dependent on the price of crude oil and natural gas. These market factors often lead to volatility in our revenue and profitability, especially in the United States and Canada, where we have historically generated in excess of 50% of our revenue. Historical market conditions are reflected in the table below:


	For the three months ended
	December 31,
	2006		% Change		2005
Rig Count: ⁽¹⁾
U.S.		1,720	16	%		1,479
Canada		440	-23	%		572
International⁽²⁾		951	9	%		871
Commodity Prices (average):
Crude Oil (West Texas Intermediate)	$	59.99	0	%	$	60.02
Natural Gas (Henry Hub)	$	6.66	-46	%	$	12.33

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

(2)	Includes Mexico average rig count of 84 and 93 for the three-month periods ended December 31, 2006 and 2005, respectively.

U.S. Rig Count

Demand for our pressure pumping services in the U.S. is primarily driven by oil and natural gas drilling activity, which tends to be extremely volatile, depending on the current and anticipated prices of oil and natural gas. During the last 10 years, the lowest annual U.S. rig count averaged 601 in fiscal 1999 and the highest annual U.S. rig count averaged 1,587 in fiscal 2006.

Canadian Rig Count

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

International Rig Count

Many countries in which we operate are subject to political, social and economic risks which may cause volatility within any given country. However, our international revenue in total is less volatile because we operate in approximately 50 countries, which provides a reduction of exposure to any one country. Due to the significant investment and complexity of international projects, we believe drilling decisions relating to such projects tend to be evaluated and monitored with a longer-term perspective with regard to oil and natural gas pricing. Additionally, the international market is dominated by major oil companies and national oil companies which tend to have different objectives and more operating stability than the typical independent producer in North America. During the last 10 years, the lowest annual international rig count, excluding Canada, averaged 616 in fiscal 1999 and the highest annual international rig count averaged 905 in fiscal 2006.

Results of Operations

Consolidated


	Three Months Ended
	December 31,
Consolidated (in millions)	2006		% Change		2005
Revenue	$	1,183.9	24	%	$	956.2
Operating income		316.3	38	%		229.6

Worldwide rig count⁽¹⁾		3,111	6	%		2,922

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

Results for the three-month periods ended December 31, 2006 and 2005

Increased drilling activity and pricing improvements in the U.S. led to the increase in revenue for the first three months of fiscal 2006. Our International Pressure Pumping segment and Oilfield Services Group also contributed to the overall revenue increase as a result of increased activity. These increases were slightly offset by a decline in revenue from our Canada Pressure Pumping segment, which experienced lower activity levels during the three month period ended December 31, 2006.

As revenue increased, operating income also benefited. For three months ended December 31, 2006, consolidated operating income margins improved to 27% from 24% reported in fiscal 2005.

U.S./Mexico Pressure Pumping


	Three Months Ended December 31,
(in millions)	2006		% Change	2005
Revenue	$	640.8	29%	$	497.3
Operating income		252.6	44%		175.5

U.S. rig count⁽¹⁾		1,720	16%		1,479
Mexico rig count⁽¹⁾		84	-10%		93

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

Results for the three-month periods ended December 31, 2006 and 2005

Drilling activity increases and pricing improvements allowed substantially all of the operating regions within the U.S./Mexico Pressure Pumping segment to contribute to the revenue growth for the first fiscal quarter of 2007 when compared to the same period in the prior year.

Activity: Despite a 46% decline in the average price of natural gas, the U.S. average active drilling rig count for the three months ended December 31, 2006 was 16% higher compared to the same period in the prior fiscal year. This activity increase enabled the segment to achieve revenue improvement of 29%. In addition to the activity related revenue contributions from the U.S., our Mexico operating region showed a 30% increase in revenue during the period on a 10% decline in average active drilling rigs in Mexico. This was due to the award of a new contract in the region.

Price: Two U.S. price book increases, occurring in November 2005 and May 2006, complemented the U.S. activity increase to add further to the segment’s increase in revenue. As of December 31, 2006, approximately 55% of our revenue was generated on the May 2006 U.S. price book. The degree of customer acceptance of the price book increase depends on activity levels and competitive pressures.

While revenue increased 29% for the three months ended December 31, 2006 compared to the same period in the prior fiscal year, operating income increased 44%. Along with the increase in revenue, the pricing improvements described above led to the increased operating income for the first quarter of fiscal 2007.

Canada Pressure Pumping


	Three Months Ended December 31,
(in millions)	2006		% Change	2005
Revenue	$	111.7	-10%	$	124.3
Operating income		13.4	-58%		31.8

Canada rig count⁽¹⁾		440	-23%		572

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

Results for the three-month periods ended December 31, 2006 and 2005

Declining natural gas prices caused our customer base to reduce their spending levels in turn lowering activity levels and revenue for our Canada Pressure Pumping segment during the first quarter of fiscal 2007 compared to the same period in the prior fiscal year. These decreases were seen in the shallow gas and coalbed methane markets of Canada as well as in the foothill areas. A slight decrease in pricing also contributed to the lower revenue. Canadian average active drilling rigs for the three months ended December 31, 2006 fell 23%.

Operating income decreased 58% due to the decrease in revenue, increase in depreciation expense for new equipment that has been placed into service, higher labor costs resulting from an 18% increase in headcount, and higher material costs associated with a greater amount of coiled tubing jobs being completed.

International Pressure Pumping


	Three Months Ended
	December 31,
(in millions)	2006		% Change	2005
Revenue	$	252.1	31 %	$	191.7
Operating income		40.3	57 %		25.6

International rig count, excluding Mexico⁽¹⁾		867	11 %		778

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

Results for the three-month periods ended December 31, 2006 and 2005

The following table summarizes the change in revenue for the three-month periods ended December 31, 2006 and 2005 for each of the operating segments of International Pressure Pumping:


		% change in Revenue
Europe/Africa		61 %
Middle East		10 %
Asia Pacific		48 %
Russia		5 %
Latin America		26 %

Revenue from our Europe/Africa operations increased 61% compared to the first fiscal quarter of 2005. A portion of this revenue increase was due to the acquisition of a controlling interest in our Algerian joint venture, Societe Algerienne de Stimulation de Puits Productures d’Hydrocarbures (“BJSP”), on June 25, 2006. As a result of the acquisition, we now consolidate the revenue from BJSP. Excluding BJSP, revenue for Europe/Africa would have increased 37%. In addition to BJSP, Europe/Africa revenue also benefited from activity improvements in Africa, including expansion of our business in Libya and an increase in revenue from our vessel operations.

Our Middle Eastern revenue increased 10% with a 19% increase in average active drilling rigs. Within the region, revenue increases in India, Kazakhstan, Saudi Arabia, and Oman were slightly offset by a decrease in revenue from Bangladesh due to non-repeat revenue from blow-out work that occurred in the three months ended December 31, 2005.

Although rig count decreased 3% during the first three months of fiscal 2007 compared to the same period in the prior year, activity increases in Australia, Thailand, and Indonesia and the award of a new contract in Malaysia contributed to the Asia Pacific region’s 48% increase in revenue.

Latin America revenue increased 26% for the three months ended December 31, 2006 compared to the same period in the prior year from overall activity increases. The average active drilling rig count increased 10% in Latin America, with all major markets within the region exhibiting double digit revenue improvements.

Our Russian revenue increased 5% for the first quarter of 2007 compared to first quarter of 2006 due to additional fracturing activity.

Operating income from our International Pressure Pumping operations increased 57% for the three months ended December 31, 2006, when compared to the same period in the prior fiscal year. The increase is almost entirely due to the increased revenue described above.

Oilfield Services Group


	Three Months Ended
	December 31,
(in millions)	2006		% Change	2005
Revenue	$	179.4	26 %	$	142.9
Operating income		32.7	30 %		25.2

Results for the three-month periods ended December 31, 2006 and 2005

The following table summarizes the change in revenue for the three-month periods ended December 31, 2006 and 2005 for each of the operating segments of Oilfield Services Group:


		% Change in Revenue
Tubular Services		46 %
Process & Pipeline Services		19 %
Chemical Services		60 %
Completion Tools		22 %
Completion Fluids		3 %

Increased revenue from Chemical Services, Tubular Services, and Process & Pipeline Services provided the majority of the revenue increase within Oilfield Services Group during the three months ended December 31, 2006 when compared to the same period in the prior year. Increased revenue from Chemical Services is mostly due to the acquisition of Dyna Coil that occurred in August 2006. Excluding Dyna Coil, revenue for Chemical Services would have increased 34%. Process & Pipeline Services revenue increased due to revenue increases in Europe/Africa as well as growth in the Middle East, while Tubular Services revenue benefited from overall activity increases. Our Completion Tools operating segment benefited from increased international activity.

Operating income margin for the Oilfield Services Group during the first quarter of fiscal 2007 remained at 18%, consistent with that seen in the first three months of fiscal 2006.

Outlook

As stated under “Market Conditions” above, our worldwide operations are primarily driven by the number of oil and natural gas wells being drilled, the depth and drilling conditions of such wells, the number of well completions and the level of workover activity. Drilling activity, in turn, is largely dependent on the price of crude oil and natural gas. The average price of natural gas declined 46% during the three months ended December 31, 2006 compared to the same period in prior year, while the price of crude oil has remained flat. As a result, drilling activity both in the U.S. and International markets during the first three months of fiscal 2007 have declined slightly from that seen in that last quarter of fiscal 2006.

Our results of operations also depend heavily on pricing. Fifty five percent of our U.S. revenue at December 31, 2006, was recorded using our most recently issued U.S. price book from May 2006. The degree of acceptance of the price book increase varies by customer and depends on activity levels and competitive pressures.

Given the levels of natural gas currently in storage, the volatility of natural gas prices, and the level of drilling activity in North America, our outlook will depend on the weather conditions for the remainder of winter. Warmer than normal winter weather conditions and the declining natural gas prices has caused our North America operations to have lower than earlier forecasted results. Despite this, we expect our Canada Pressure Pumping operations to improve in the second fiscal quarter of 2007 and expect modest improvement in our U.S./Mexico and International Pressure Pumping businesses during the second quarter of fiscal 2007.

Other Expenses

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


	Three Months Ended December 31,
	2006		2005
Research and engineering	$	15,694	$	15,153
Marketing expense		25,813		24,594
General and administrative expense		37,207		37,591

Research and engineering, marketing expense, and general and administrative expense: These expenses have increase slightly for three months ended December 31, 2006 compared to the same periods in the prior fiscal year. However, as a percent of revenue, each of these expenses has decreased. The majority of the increase for each of these expense categories relates to increased revenue.

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


	Three Months Ended December 31,
	2006			2005
Interest expense	$	(8,779	)	$	(135	)
Interest income		320			3,390
Other income (expense) – net		(2,076	)		952

Interest Expense and Interest Income: Interest expense increased $8.8 million for the three months ended December 31, 2006 compared to the same period in the prior year as the result of the Company completing a public offering of $500.0 million aggregate principal amount of Senior Notes in June 2006. The net proceeds from the offering of approximately $497.1 million, after deducting underwriting discounts and commissions and expenses, were used primarily to repurchase outstanding shares of common stock and also repay indebtedness, fund capital expenditures and for other corporate purposes. Interest income decreased $3.1 million over the same period as a result of a decrease in cash and cash equivalents caused by purchases of treasury shares made during the prior fiscal year. We expect fiscal year 2007 interest expense, net of interest income, to be approximately $29 million.

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


	Three Months Ended December 31,
	2006			2005
Minority interest	$	(2,482	)	$	(771	)
Non-operating net foreign exchange loss		(335	)		(145	)
Recovery of misappropriated funds		—			2,790
Other income (expense), net		741			(922	)

Other income (expense)	$	(2,076	)	$	952

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

Liquidity and Capital Resources

Historical Cash Flow

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


	Three Months Ended December 31,
	2006			2005
Cash flow from operations	$	271.1		$	173.9
Cash flow used in investing		(156.4	)		(78.3	)
Cash flow used in financing		(142.8	)		(25.7	)
Effect of exchange rate changes on cash		(1.8	)		—

Change in cash and cash equivalents	$	(29.9	)	$	69.9

Higher revenue and profits for the U.S., International Pressure Pumping, and Oilfield Services Group resulted in higher cash flow from operations. Working capital increased $86.4 million as a result of a $18.3 million decrease in accounts receivable and $55.4 million decrease in current income taxes.

The cash flow used in investing was almost entirely due to $146.9 million of purchases of property, plant, and equipment during the three months ended December 31, 2006. We also paid $10.7 million, net of cash, for acquisitions during the first quarter of fiscal 2007.

Cash flows used in financing consisted of $115.2 million, net, repayment of short term borrowings, $20.0 million in repurchases of our stock and a $14.7 million payment of dividends during the three months ended December 31, 2006. We received proceeds in the amount of $6.7 million for employee stock purchases and stock option exercises during the first quarter of fiscal 2007.

Liquidity and Capital Resources

Cash flows from operations is expected to be our primary source of liquidity in fiscal 2007. Our

sources of liquidity also include cash and cash equivalents of $62.5 million at December 31, 2006 and the available financing facilities listed below (in millions):


Financing Facility	Expiration	Borrowings at December 31, 2006		Available at December 31, 2006
Revolving Credit Facility	June 2009	$	30.0	$	370.0
Discretionary	Various times within the next 12 months	$	15.1	$	122.1

On June 8, 2006, we completed a public offering of $500.0 million aggregate principal amount of Senior Notes, consisting of $250.0 million of floating rate Senior Notes due 2008, with an annual interest rate of three-month LIBOR plus 17 basis points, and $250.0 million of 5.75% Senior Notes due 2011. The net proceeds from the offering of approximately $497.1 million, after deducting underwriting discounts and commissions and expenses, were used primarily to repurchase outstanding shares of common stock and also repay indebtedness, fund capital expenditures and for other corporate purposes. As of December 31, 2006 and September 30, 2006, we had $250.0 million of the Senior Notes due 2008 issued and outstanding and $249.7 million, net of discount, of the 5.75% Senior Notes due 2011 issued and outstanding.

In June 2004, we replaced our then existing credit facility with a revolving credit facility (the “Revolving Credit Facility”) that permits borrowings up to $400 million in principal amount. The Revolving Credit Facility includes a $50 million sublimit for the issuance of standby letters of credit and a $20 million sublimit for swingline loans. Swingline loans have short-term maturities and the remaining amounts outstanding under the Revolving Credit Facility become due and payable in June 2009. Interest on outstanding borrowings is charged based on prevailing market rates. We are charged various fees in connection with the Revolving Credit Facility, including a commitment fee based on the average daily unused portion of the commitment, totaling $0.1 million for the three months ended December 31, 2006. In addition, the Revolving Credit Facility charges a utilization fee on all outstanding loans and letters of credit when usage of the Revolving Credit Facility exceeds 33%, though there were no material charges in fiscal 2007 to date or in fiscal 2006. There were $30.0 million and $160.0 million in outstanding borrowings under the Revolving Credit Facility at December 31, 2006 and September 30, 2006, respectively.

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

In addition to the Revolving Credit Facility, we had $137.2 million of unsecured, discretionary lines of credit at December 31, 2006, 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 $15.0 million and $0.3 million in outstanding borrowings under these lines of credit at December 31, 2006 and September 30, 2006, respectively.

Management believes that cash flows from operations combined with cash and cash equivalents, the Revolving Credit Facility and other discretionary credit facilities provide us with sufficient capital resources and liquidity to manage our routine operations, meet debt service obligations, fund projected capital expenditures, repurchase common stock, pay a regular quarterly dividend and support the development of our short-term and long-term operating strategies. If the discretionary lines of credit are not renewed, or if borrowings under these lines of credit otherwise become unavailable, we expect to refinance this debt by arranging additional committed bank facilities or through other long-term borrowing alternatives.

Cash Requirements

We anticipate capital expenditures to be $650 million in fiscal 2007, compared to $460 million in fiscal 2006. The 2007 capital expenditure program is expected to consist primarily of capital for facilities, new pressure pumping equipment, new equipment for our Oilfield Services Group, and capital to extend the useful life of existing assets. We have made significant progress adding new equipment. However, much of the older equipment still remains in operation due to the increases in market activity in the U.S. During fiscal 2004, we expanded our U.S. fleet recapitalization initiative to include additional equipment, such as cementing, nitrogen and acidizing equipment. Recapitalization of our pressure pumping equipment in Canada began in fiscal 2005. The actual amount of fiscal 2007 capital expenditures will depend primarily on maintenance requirements and expansion opportunities and our ability to execute our budgeted capital expenditures.

In fiscal 2007, our minimum pension and postretirement funding requirements are anticipated to be approximately $15.7 million and has contributed $4.8 million during the three months ended December 31, 2006.

We anticipate paying cash dividends in the amount of $.05 per common share on a quarterly basis in fiscal 2007. Based on the shares outstanding on September 30, 2006, the aggregate annual amount paid for dividends would be approximately $58.6 million. However, dividends are subject to approval of our Board of Directors each quarter, and the Board has the ability to change the dividend policy at any time.

As of December 31, 2006, we had $250.0 million of the Senior Notes due 2008 issued and outstanding and $249.7 million of the 5.75% Senior Notes due 2011 issued and outstanding, net of discount. We expect cash paid for net interest expense (net of interest income) will be approximately $29 million in fiscal 2007.

We expect an incremental increase to cash paid for income taxes to be approximately $135 million in fiscal 2007 compared to fiscal 2006, due to increased profitability.

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

Investigations Regarding Misappropriation and Possible Illegal Payments

Off Balance Sheet Transactions

In 1999, we contributed certain pumping service equipment to a limited partnership. The equipment is used to provide services to our customers for which we pay a service fee over a period of at least six years, but not more than 13 years, at approximately $12 million annually. This is accounted for as an operating lease. We assessed the terms of this agreement and determined it was a variable interest entity as defined in FIN 46, Consolidation of Variable Interest Entities. However, we were not deemed to be the primary beneficiary, and therefore, consolidation was not required. The transaction resulted in a gain that is being deferred and amortized over 13 years. The balance of the deferred gain was $15.3 million and $16.1 million as of December 31, 2006 and September 30, 2006, respectively. The agreement permits substitution of equipment within the partnership as long as the implied fair value of the new property transferred in at the date of substitution equals or exceeds the implied fair value, as defined, of the current property in the partnership that is being replaced. In September 2010, we have the option, but not the obligation, to purchase the pumping service equipment for approximately $32 million. We currently have the intent to exercise this option.

In 1997, we contributed certain pumping service equipment to a limited partnership. We own a 1% interest in the limited partnership. The equipment is used to provide services to our customers for which we pay a service fee over a period of at least eight years, but not more than 13 years, at approximately $10 million annually. This is accounted for as an operating lease. We assessed the terms of this agreement and determined it was a variable interest entity as defined in FIN 46, Consolidation of Variable Interest Entities. However, we were not deemed to be the primary beneficiary, and therefore, consolidation was not required. Subsequent to December 31, 2006, we agreed to purchase the remaining partnership interest for approximately $48 million, and as a result, acquired the partnership equipment. The acquisition of the partnership controlling interest will be accounted for as an asset purchase.

Accounting Pronouncements

comprehensive income of a business entity. It also requires companies to measure the funded status of a plan as of the date of our year-end statement of financial position. Additionally, companies will need to:

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

Recognition of an asset or liability related to the funded status of a pension plan and disclosures are effective for fiscal years ending after December 15, 2006 and the required changes in the measurement date are effective for fiscal years ending after December 15, 2008. We currently measure our defined benefit plan assets and obligations as of our fiscal year-end so, this portion of SFAS 158 will not impact our financial statements. We are currently in the process of evaluating the impact on our financial statements the other requirements of SFAS 158.

Critical Accounting Policies

For an accounting policy to be deemed critical, the accounting policy must first include an estimate that requires a company to make assumptions about matters that are highly uncertain at the time the accounting estimate is made. Second, different estimates that we reasonably could have used for the accounting estimate in the current period, or changes in the accounting estimate that are reasonably likely to occur from period to period, must have a material impact on the presentation of our financial condition or results of operations. Estimates and assumptions about future events and their effects cannot be predicted with certainty. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. There have been no material changes or developments in our evaluation

of the accounting estimates and the underlying assumptions or methodologies that we believe to be Critical Accounting Policies disclosed in our Form 10-K for the fiscal year ended September 30, 2006.

Forward Looking Statements

This document contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities Exchange Act of 1934 concerning, among other things, our prospects, expected revenues, expenses and profits, developments and business strategies for our operations, all of which are subject to certain risks, uncertainties and assumptions. These forward-looking statements are identified by their use of terms and phrases such as “expect,” “estimate,” “project,” “believe,” “achievable,” “anticipate” and similar terms and phrases. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such statements are subject to:

•

fluctuating prices of crude oil and natural gas,

•

conditions in the oil and natural gas industry, including drilling activity,

•

reduction in prices or demand for our products and services, and level of acceptance of price book increases in our markets,

•

general global economic and business conditions,

•

international political instability, security conditions, and hostilities, and declines in customer activity due to adverse local and regional conditions,

•

our ability to expand our products and services (including those it acquires) into new geographic markets,

•

our ability to generate technological advances and compete on the basis of advanced technology,

•

risks from operating hazards such as fire, explosion, blowouts and oil spills,

•

litigation for which insurance and customer agreements do not provide protection,

•

adverse consequences that may be found in or result from our ongoing internal investigation, including potential financial consequences and governmental actions, proceedings, charges or penalties,

•

changes in currency exchange rates,

•

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

•

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

•

competition and consolidation in our business

•

changes in law or regulations and other factors, many of which are beyond our control and other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission

If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual results may vary materially from those expected, estimated or projected. Other than as required under securities laws, we does not assume a duty to update these forward looking statements. This list of risk factors is not intended to be comprehensive. See “Risk Factors” included in our Form 10-K for the fiscal year ended September 30, 2006.

I tem 3.

Quantitative and Qualitative Disclosures About Market Risk

Our major market risk exposure is to foreign currency fluctuations internationally and changing interest rates, primarily in the United States, Canada and Europe. Our policy is to manage interest rates through use of a combination of fixed and floating rate debt. If the floating rates were to increase by 10% from December 31, 2006 rates, our combined interest expense to third parties would increase by a total of $137 thousand each month in which such increase continued.

Periodically, the Company borrows funds which are denominated in foreign currencies, which exposes the Company to market risk associated with exchange rate movements. Total borrowings denominated in foreign currencies at December 31, 2006 was $15.0 million. When we believe prudent, we enter into forward foreign exchange contracts to hedge the impact of foreign currency fluctuations. There were no such forward foreign exchange contracts at December 31, 2006.

It em 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 we 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 6 of the Notes to the Unaudited Consolidated Condensed Financial Statements included elsewhere in this Quarterly Report on Form 10-Q is incorporated herein by reference.

Item 1A.

Risk Factors

There have been no material changes during the period ended December 31, 2006 in our “Risk Factors” as discussed our Form 10-K for the fiscal year ended September 30, 2006.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

(a)

None

(b)

None

(c)

Purchases of Equity Securities by the Issuer and Affiliated Purchasers


Period	(a) Total Number of Shares Purchased	(b) Average Price paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽¹⁾	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 – 31, 2006	668,889	$	29.91	668,889	$	449 million
November 1 – 30, 2006	0				$	449 million
December 1 – 31, 2006	0				$	449 million

TOTAL	668,889			668,889	$	449 million

⁽¹⁾

On December 19, 1997, our Board of Directors authorized a stock repurchase program of up to $150 million (which was subsequently increased several times). Repurchases are made at the discretion of our management and the program will remain in effect until terminated by our Board of Directors. Since the Company began its share repurchase program in 1997, the Company has repurchased 84.7 million shares for $1.75 billion. The Company currently has remaining authorization from its Board of Directors to purchase up to an additional $449.3 million in stock.

Item 3.

Defaults upon Senior Securities

None

Item 4.

Submission of Matters to a Vote of Security Holders

None

Item 5.

Other Information

None

Item 6.

Exhibits


3.1		Amended and Restated Bylaws of the Company (filed as Exhibit 3.1 to the Company’s 8-K filed December 13, 2006 and incorporated herein by reference)

10.1		Form of letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to executive officers during fiscal 2007 (filed as Exhibit 10.1 to the Company’s 8-K filed November 21, 2006 and incorporated herein by reference)

10.2		Form of amended letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to executive officers during fiscal 2007 (filed as Exhibit 10.1 to the Company’s 8-K filed December 13, 2006 and incorporated herein by reference)

10.3		Form of letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to directors during fiscal 2007 (filed as Exhibit 10.2 to the Company’s 8-K filed November 21, 2006 and incorporated herein by reference)

10.4		Form of amended letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to directors during fiscal 2007 (filed as Exhibit 10.2 to the Company’s 8-K filed December 13, 2006 and incorporated herein by reference)

10.5		BJ Services Company 2000 Incentive Plan - Form of Second Amendment to Terms and Conditions of Stock Options for Officers (filed as Exhibit 10.3 to the Company’s 8-K filed November 1, 2006 and incorporated herein by reference)

10.6		Eighth Amendment to the BJ Services Company 1997 Incentive Plan (filed as Exhibit 10.3 to the Company’s 8-K filed December 13, 2006 and incorporated herein by reference)

10.7		Fifth Amendment to the BJ Services Company 2000 Incentive Plan (filed as Exhibit 10.4 to the Company’s 8-K filed December 13, 2006 and incorporated herein by reference)

10.8		Second Amendment to the BJ Services Company 2003 Incentive Plan (filed as Exhibit10.5 to the Company’s 8-K filed December 13, 2006 and incorporated herein by reference)

10.9		Form of letter agreement setting forth terms and conditions of performance units awarded to executive officers during fiscal 2007 (filed herewith and corrects Exhibit 10.64 contained in the Company’s 10-K filed December 7, 2006 for the fiscal year ended September 30, 2006)

31.1		Section 302 certification for J. W. Stewart

31.2		Section 302 certification for Jeffrey E. Smith

32.1		Section 906 certification furnished for J. W. Stewart

32.2		Section 906 certification furnished for Jeffrey E. Smith

SIGNATURES

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


	BJ Services Company
	(Registrant)

Date: February 9, 2007	By:	/s/ J. W. Stewart
		J. W. Stewart
		Chairman of the Board, President and Chief Executive Officer


Date: February 9, 2007	By:	/s/ Jeffrey E. Smith
		Jeffrey E. Smith
		Vice President - Finance and Chief Financial Officer

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