Edgar Filing: PATTERSON UTI ENERGY INC

e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended September 30, 2006
or
o		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 0-22664

Patterson-UTI Energy, Inc.

(Exact name of registrant as specified in its charter)


DELAWARE		75-2504748
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

4510 LAMESA HIGHWAY,		79549
SNYDER, TEXAS		(Zip Code)
(Address of principal executive offices)

(325) 574-6300

(Registrant’s telephone number, including area code)

N/A

(Former name, former address and former fiscal year,

if changed since last report)

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

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 þ	Accelerated filer o	Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

158,890,535 shares of common stock, $0.01 par value, as of October 31, 2006

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

TABLE OF CONTENTS


		Page

PART I — FINANCIAL INFORMATION
ITEM 1.	Financial Statements
	Unaudited condensed consolidated balance sheets	2
	Unaudited condensed consolidated statements of income	3
	Unaudited condensed consolidated statement of changes in stockholders’ equity	4
	Unaudited condensed consolidated statements of changes in cash flows	5
	Notes to unaudited condensed consolidated financial statements	6
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	26
ITEM 4.	Controls and Procedures	27
Forward Looking Statements and Cautionary Statements for Purposes of the ‘‘Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995		27

PART II — OTHER INFORMATION
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	29
ITEM 4.	Submission of Matters to a Vote of Security Holders	29
ITEM 5.	Other Information	29
ITEM 6.	Exhibits	29
Signatures		31
Certification of CEO Pursuant to Rule 13a-14(a)/15d-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)/15d-14(a)
Certification of CEO and CFO Pursuant to 18 USC Section 1350

PART I — FINANCIAL INFORMATION


ITEM 1.	*Financial Statements*

The following unaudited condensed consolidated financial statements include all adjustments which, in the opinion of management, are necessary in order to make such financial statements not misleading.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30,			December 31,
	2006			2005
	(Unaudited)
	(In thousands, except
	share data)

ASSETS
Current assets:
Cash and cash equivalents	$	16,945		$	136,398
Accounts receivable, net of allowance for doubtful accounts of $6,288 at September 30, 2006 and $2,199 at December 31, 2005		511,001			422,002
Inventory		36,083			27,907
Deferred tax assets, net		44,528			26,382
Other		53,407			25,168

Total current assets		661,964			637,857
Property and equipment, at cost, net		1,328,795			1,053,845
Goodwill		99,056			99,056
Other		5,074			5,023

Total assets	$	2,094,889		$	1,795,781


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	152,573		$	113,226
Accrued revenue distributions		14,512			13,379
Other		6,654			5,294
Accrued federal and state income taxes payable		15,519			11,034
Accrued expenses		150,669			112,476

Total current liabilities		339,927			255,409
Borrowings under line of credit		65,000			—
Deferred tax liabilities, net		186,507			169,188
Other		4,426			4,173

Total liabilities		595,860			428,770

Commitments and contingencies (see Note 10)		—			—
Stockholders’ equity:
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued		—			—
Common stock, par value $.01; authorized 300,000,000 shares with 176,616,631 and 175,909,274 issued and 159,906,735 and 172,441,178 outstanding at September 30, 2006 and December 31, 2005, respectively		1,766			1,759
Additional paid-in capital		674,903			672,151
Deferred Compensation		—			(9,287	)
Retained earnings		1,202,744			719,113
Accumulated other comprehensive income		11,581			8,565
Treasury stock, at cost, 16,709,896 and 3,468,096 shares at September 30, 2006 and December 31, 2005, respectively		(391,965	)		(25,290	)

Total stockholders’ equity		1,499,029			1,367,011

Total liabilities and stockholders’ equity	$	2,094,889		$	1,795,781

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
	(Unaudited)						(Unaudited)
	(In thousands, except per share amounts)						(In thousands, except per share amounts)

Operating revenues:
Contract drilling	$	577,047		$	401,046		$	1,616,100		$	1,025,938
Pressure pumping		40,462			27,640			107,800			66,358
Drilling and completion fluids		46,163			29,819			155,221			88,812
Oil and natural gas		9,986			10,234			29,083			28,146

		673,658			468,739			1,908,204			1,209,254

Operating costs and expenses:
Contract drilling		267,345			202,956			737,021			558,607
Pressure pumping		20,960			15,662			56,545			38,648
Drilling and completion fluids		36,183			24,062			120,418			71,857
Oil and natural gas		3,222			2,365			11,241			6,953
Depreciation, depletion and impairment		49,215			39,545			140,245			112,319
Selling, general and administrative		13,777			10,565			39,428			30,157
Embezzlement costs, net of recoveries		(1,512	)		5,431			2,941			12,193
Other operating expenses		2,563			707			3,948			2,590

		391,753			301,293			1,111,787			833,324

Operating income		281,905			167,446			796,417			375,930

Other income (expense):
Interest income		948			944			5,579			2,011
Interest expense		(363	)		(56	)		(476	)		(179	)
Other		88			19			231			39

		673			907			5,334			1,871

Income before income taxes and cumulative effect of change in accounting principle		282,578			168,353			801,751			377,801

Income tax expense (benefit):
Current		106,151			66,574			288,476			145,513
Deferred		(9,563	)		(4,526	)		(2,974	)		(6,263	)

		96,588			62,048			285,502			139,250

Income before cumulative effect of change in accounting principle		185,990			106,305			516,249			238,551
Cumulative effect of change in accounting principle, net of related income tax expense of $398		—			—			687			—

Net income	$	185,990		$	106,305		$	516,936		$	238,551

Income before cumulative effect of change in accounting principle:
Basic	$	1.14		$	0.62		$	3.07		$	1.40

Diluted	$	1.12		$	0.61		$	3.03		$	1.38

Net income per common share:
Basic	$	1.14		$	0.62		$	3.08		$	1.40

Diluted	$	1.12		$	0.61		$	3.03		$	1.38

Weighted average number of common shares outstanding:
Basic		163,412			171,613			168,036			169,846

Diluted		165,742			174,587			170,339			173,211

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY


															Accumulated
	Common Stock					Additional									Other
	Number of					Paid-in			Deferred			Retained			Comprehensive		Treasury
	Shares			Amount		Capital			Compensation			Earnings			Income		Stock			Total
	(Unaudited)
	(In thousands)

Balance, December 31, 2005		175,909		$	1,759	$	672,151		$	(9,287	)	$	719,113		$	8,565	$	(25,290	)	$	1,367,011
Issuance of restricted stock		613			6		(6	)		—			—			—		—			—
Exercise of stock options		133			1		1,413			—			—			—		—			1,414
Tax benefit for stock option exercises		—			—		922			—			—			—		—			922
Stock based compensation, net of cumulative effect of change in accounting principle		—			—		9,710			—			—			—		—			9,710
Forfeitures of restricted shares		(39	)		—		—			—			—			—		—			—
Elimination of deferred compensation due to change in accounting principle		—			—		(9,287	)		9,287			—			—		—			—
Foreign currency translation adjustment, net of tax of $1,673		—			—		—			—			—			3,016		—			3,016
Payment of cash dividends		—			—		—			—			(33,305	)		—		—			(33,305	)
Purchases of treasury stock		—			—		—			—			—			—		(366,675	)		(366,675	)
Net income		—			—		—			—			516,936			—		—			516,936

Balance, September 30, 2006		176,616		$	1,766	$	674,903		$	—		$	1,202,744		$	11,581	$	(391,965	)	$	1,499,029

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS


	Nine Months Ended
	September 30,
	2006			2005
	(Unaudited)
	(In thousands)

Cash flows from operating activities:
Net income	$	516,936		$	238,551
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and impairment		140,245			112,319
Dry holes and abandonments		3,709			—
Provision for bad debts		4,200			416
Deferred income tax benefit		(2,576	)		(6,263	)
Tax benefit related to exercise of stock options		—			24,047
Stock based compensation expense		9,710			2,121
Gain on disposal of assets		(437	)		(1,253	)
Changes in operating assets and liabilities, net of business acquired:
Accounts receivable		(92,069	)		(148,825	)
Inventory and other current assets		(36,086	)		(4,044	)
Accounts payable		40,280			48,568
Income taxes payable/receivable		4,789			29,660
Accrued expenses		23,798			22,662
Other liabilities		1,613			1,513

Net cash provided by operating activities		614,112			319,472

Cash flows from investing activities:
Purchases of property and equipment		(423,422	)		(262,723	)
Acquisitions, net of cash received		—			(73,577	)
Proceeds from disposal of property and equipment		7,983			12,502
Change in other assets		—			1,766

Net cash used in investing activities		(415,439	)		(322,032	)

Cash flows from financing activities:
Purchases of treasury stock		(352,393	)		—
Dividends paid		(33,305	)		(20,441	)
Proceeds from exercise of stock options		1,414			42,299
Tax benefit related to exercise of stock options		922			—
Proceeds from borrowings under line of credit		65,000			—
Debt issuance costs		(341	)		—

Net cash provided by (used in) financing activities		(318,703	)		21,858

Effect of foreign exchange rate changes on cash		577			(458	)

Net increase (decrease) in cash and cash equivalents		(119,453	)		18,840
Cash and cash equivalents at beginning of period		136,398			112,371

Cash and cash equivalents at end of period	$	16,945		$	131,211

Supplemental disclosure of cash flow information:
Net cash paid during the period for:
Interest expense	$	476		$	179
Income taxes	$	272,541		$	85,824

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


1.	Basis of Consolidation and Presentation

The interim condensed consolidated financial statements include the accounts of Patterson-UTI Energy, Inc. (the “Company”) and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.

The interim condensed consolidated financial statements have been prepared by management of the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to such rules and regulations, although the Company believes the disclosures included herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments which are of a normal recurring nature considered necessary for presentation of the information have been included. The Unaudited Condensed Consolidated Balance Sheet as of December 31, 2005, as presented herein, was derived from the audited balance sheet of the Company. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005.

The Company’s former Chief Financial Officer (“former CFO”) has pleaded guilty to criminal charges and has been sentenced and is serving a term of imprisonment arising out of his embezzlement of funds totaling approximately $77.5 million from the Company over a period of more than five years, ending November 3, 2005. The accompanying prior periods were previously restated to reflect the effects of the embezzlement in the periods of occurrence. Continuing professional and other costs related to the embezzlement are being recognized as operating costs when incurred. In the three months ended September 30, 2006, the Company recovered $2.0 million from its insurance carrier related to the embezzlement loss.

The U.S. dollar is the functional currency for all of the Company’s operations except for its Canadian operations, which use the Canadian dollar as their functional currency. The effects of exchange rate changes are reflected in accumulated other comprehensive income, which is a separate component of stockholders’ equity (see Note 3 of these Notes to Unaudited Condensed Consolidated Financial Statements).

The Company provides a dual presentation of its net income per common share in its Unaudited Condensed Consolidated Statements of Income: Basic net income per common share (“Basic EPS”) and diluted net income per common share (“Diluted EPS”). Basic EPS excludes dilution and is computed by dividing net income by the weighted average number of common shares outstanding. Diluted EPS is based on the weighted-average number of common shares outstanding plus the impact of dilutive instruments, including stock options, warrants and restricted shares using the treasury stock method. For the three and nine months ended September 30, 2006, options to purchase 800,000 shares of common stock were excluded from the calculation of Diluted EPS as their inclusion would have been anti-dilutive. For the three and nine months ended September 30, 2005, all potentially dilutive instruments were included in the calculation of Diluted EPS. The following table presents information necessary to calculate net income per share for the three and nine months ended September 30, 2006 and 2005 as well as cash

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

dividends per share paid during the three and nine months ended September 30, 2006 and 2005 (in thousands, except per share amounts):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005

Net income	$	185,990	$	106,305	$	516,936	$	238,551
Weighted average number of common shares outstanding		163,412		171,613		168,036		169,846

Basic net income per common share	$	1.14	$	0.62	$	3.08	$	1.40

Weighted average number of common shares outstanding		163,412		171,613		168,036		169,846
Dilutive effect of stock options and restricted shares		2,330		2,974		2,303		3,365

Weighted average number of diluted common shares outstanding		165,742		174,587		170,339		173,211

Diluted net income per common share	$	1.12	$	0.61	$	3.03	$	1.38

Cash dividends per common share(a)	$	0.08	$	0.04	$	0.20	$	0.12


(a)		During March 2006, June 2006 and September 2006, cash dividends of $6.9 million, $13.4 million and $13.0 million, respectively, were paid on outstanding shares of 172,654,128, 167,660,960 and 162,800,466, respectively. During March 2005, June 2005 and September 2005, cash dividends of $6.7 million, $6.8 million and $6.9 million, respectively, were paid on outstanding shares of 168,679,334 , 169,741,460 and 172,591,361, respectively.

The results of operations for the three and nine months ended September 30, 2006 are not necessarily indicative of the results to be expected for the full year.


2.	Stock-based Compensation

The Company adopted Financial Accounting Standards Board (“FASB”) Statement No. 123 (revised 2004), Share-Based Payment (“FAS 123(R)”), on January 1, 2006 and recognizes the cost of share-based payments under the fair-value-based method. The Company uses share-based payments to compensate employees and non-employee directors. All awards have been equity instruments in the form of stock options or restricted stock awards and include only service conditions. The Company issues shares of common stock when vested stock option awards are exercised and when restricted stock awards are granted. As a result of the initial adoption of FAS 123(R), the Company recognized income due to the cumulative effect of this change in accounting principle of $687,000, net of taxes of $398,000, related to previously expensed amortization of unvested restricted stock grants. For the three months ended September 30, 2006, the Company recognized $3.3 million in stock-based compensation expense and a related income tax benefit of $1.1 million. For the nine months ended September 30, 2006, the Company recognized $10.8 million in stock-based compensation expense and a related income tax benefit of $3.5 million and recognized a benefit in the form of a cumulative effect of change in accounting principle associated with the adoption of FAS 123(R) of $687,000, net of the related tax expense of $398,000.

During 2005, the Company’s shareholders approved the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 Plan”) and the Board of Directors adopted a resolution that no future grants would

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

be made under any of the Company’s six other previously existing plans. The Company’s share-based compensation plans at September 30, 2006 follow:


			Options &
	Shares		Restricted		Shares
	Authorized		Shares		Available
Plan Name	for Grant		Outstanding		for Grant

Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan		6,250,000		1,546,952		4,127,961
Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan, as amended (“1997 Plan”)		—		5,097,985		—
Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (“2001 Plan”)		—		771,977		—
Amended and Restated Non-Employee Director Stock Option Plan of Patterson-UTI Energy, Inc. (“Non-Employee Director Plan”)		—		180,000		—
Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee Stock Option Plan (“1996 Plan”)		—		95,800		—
Patterson-UTI Energy, Inc., 1993 Incentive Stock Plan, as amended (“1993 Plan”)		—		125,800		—

A summary of the 2005 Plan follows:


	•	The Compensation Committee of the Board of Directors administers the plan.

	•	All employees including officers and directors are eligible for awards.

	•	The Compensation Committee determines the vesting schedule for awards. Awards typically vest over 1 year for non-employee directors and 3 to 4 years for employees.

	•	The Compensation Committee sets the term of awards and no option term can exceed 10 years.

	•	All options granted under the plan are granted with an exercise price equal to or greater than the fair market value of the Company’s common stock at the time the option is granted.

	•	The plan provides for awards of incentive stock options, non-incentive stock options, tandem and freestanding stock appreciation rights, restricted stock awards, other stock unit awards, performance share awards, performance unit awards and dividend equivalents. As of September 30, 2006, only non-incentive stock options and restricted stock awards had been granted under the plan.

Options granted under the 1997 Plan vest over three or five years as dictated by the Compensation Committee. These options typically had terms of ten years. All options were granted with an exercise price equal to the fair market value of the related common stock at the time of grant. Restricted Stock Awards granted under the 1997 Plan vest over four years.

Options granted under the 2001 Plan vest over five years as dictated by the Compensation Committee. These options had terms of ten years. All options were granted with an exercise price equal to the fair market value of the Company’s common stock at the time of grant. Restricted Stock Awards granted under the 2001 Plan vest over four years.

Options granted under the Non-Employee Director Plan vest on the first anniversary of the option grant. Non-Employee Director Plan options have five year terms. All options were granted with an exercise price equal to the fair market value of the related common stock at the time of grant.

Options granted under the 1996 plan vested over one, four and five years as dictated by the Compensation Committee. These options had terms of five or ten years as dictated by the Compensation Committee. All options were granted with an exercise price equal to the fair market value of the Company’s common stock at the time of grant.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Options granted under the 1993 Plan typically had terms of 10 years and vested over five years in 20% increments beginning at the end of the first year. All options were granted with an exercise price equal to the fair market value of the Company’s common stock at the time of grant.

Stock Options. The Company accounted for all stock options under the intrinsic value method prior to January 1, 2006. Accordingly, no compensation expense was recognized in prior periods for stock options because they had no intrinsic value when granted as exercise prices were equal to the grant date market value of the related common stock. The Modified Prospective Application (“MPA”) method is being applied to transition from the intrinsic value method to the fair-value-based method for stock options. The effects of the application of the MPA method follow:


	•	Previously reported amounts and disclosures are not affected.

	•	Compensation cost, net of estimated forfeitures for the unvested portion of awards outstanding at January 1, 2006, is recognized under the fair-value-based method as the awards vest. Compensation cost is based on the grant-date fair value of stock options as calculated for the Company’s previously reported pro forma disclosures under FASB Statement No. 123, Accounting for Stock-Based Compensation (“FAS 123”).

	•	The fair-value based method is applied to new awards and to awards outstanding at January 1, 2006 that are modified, repurchased or cancelled after that date, if any.

The Company estimates grant date fair values of stock options using the Black-Scholes-Merton valuation model (“Black-Scholes”), except for stock options granted prior to 1996 that are not subject to FAS 123(R) and were not subject to FAS 123 pro forma disclosures. Volatility assumptions are based on the historic volatility of the Company’s common stock over the most recent period equal to the expected term of the options as of the date the options were granted. The expected term assumptions are based on the Company’s experience with respect to employee stock option activity. Dividend yield assumptions are based on the expected dividends at the time the options were granted. The risk-free interest rate assumptions are determined by reference to United States Treasury yields. Weighted-average assumptions used to estimate grant date fair values for stock options granted in the three and nine month periods ended September 30, 2006 and 2005 follow:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006			2005		2006			2005

Volatility		33.59	%		N/A		33.18	%		26.95	%
Expected term (in years)		4.00			N/A		4.00			4.00
Dividend yield		1.14	%		N/A		1.09	%		0.65	%
Risk-free interest rate		4.91	%		N/A		4.87	%		3.84	%

No stock options were granted during the three months ended September 30, 2005.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Stock option activity from January 1, 2006 to September 30, 2006 follows:


						September 30,
						2006
						Weighted-
				Weighted-		Average		Aggregate
				Average		Remaining		Intrinsic
	Underlying			Exercise		Contractual		Value
	Shares			Price		Term (Yrs)		($000’s)

Outstanding at January 1, 2006		6,338,043		$	14.37
Granted		800,000		$	28.54
Exercised		(133,309	)	$	10.61
Forfeited		(15,800	)	$	11.65
Expired		(5,587	)	$	7.62
Cancelled(a)		(360,833	)	$	14.83

Outstanding at September 30, 2006		6,622,514		$	16.15		6.43	$	54,756

Exercisable at September 30, 2006		5,322,080		$	13.76		5.78	$	53,452


(a)		Represents vested stock options held by the former CFO which were cancelled by the Company’s Board of Directors.

The weighted-average grant-date fair value of stock options granted and the aggregate intrinsic value of stock options exercised during the three and nine month periods ended September 30, 2006 and 2005 follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005

Weighted-average grant-date fair value of stock options granted	$	8.58	$	N/A	$	8.62	$	6.33
Aggregate intrinsic value of stock options exercised ($000’s)	$	417	$	28,118	$	2,759	$	69,315

As of September 30, 2006, options to purchase 1,300,434 shares were outstanding and not vested. Of these non-vested options, approximately 1,273,000 are expected to ultimately vest. Additional information as of September 30, 2006 with respect to these options that are expected to vest follows:


Aggregate intrinsic value	$	1.3 million
Weighted-average remaining contractual term		9.07 years
Weighted-average remaining expected term		3.08 years
Weighted-average remaining vesting period		2.14 years
Unrecognized compensation cost	$	9.3 million

Restricted Stock. Under all restricted stock awards to date, shares were issued when granted, nonvested shares are subject to forfeiture for failure to fulfill service conditions and nonforfeitable dividends are paid on nonvested restricted shares. Restricted stock awards prior to January 1, 2006 were valued at the grant date market value of the underlying common stock, recognized as contra equity deferred compensation and amortized to expense under the “graded-vesting” method. Implementation of FAS 123(R) did not change the accounting for the Company’s nonvested stock awards, except as follows:


	•	Prior to January 1, 2006, forfeitures were recognized as they occurred;

	•	From January 1, 2006 forward, forfeitures are estimated in the determination of periodic compensation cost; and

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	•	Contra equity deferred compensation was reversed against paid-in-capital at January 1, 2006 and compensation expense is recognized as attributed to each period.

The Company uses the “graded-vesting” attribution method to determine periodic compensation cost from restricted stock awards.

Restricted stock activity from January 1, 2006 to September 30, 2006 follows:


				Weighted
				Average
				Grant Date
	Shares			Fair Value

Nonvested at January 1, 2006		623,150		$	21.44
Granted		613,400		$	30.46
Vested		(1,198	)	$	14.73
Forfeited		(39,352	)	$	26.15

Nonvested at September 30, 2006		1,196,000		$	25.92

As of September 30, 2006, approximately 949,000 shares of nonvested restricted stock outstanding are expected to vest. Additional information as of September 30, 2006 with respect to these shares that are expected to vest follows:


Aggregate intrinsic value	$	22.6 million
Weighted-average remaining vesting period		2.76 years
Unrecognized compensation cost	$	16.5 million

Dividends on Equity Awards. Nonforfeitable dividends paid on equity awards are recognized as follows:


	•	Dividends are recognized as reductions of retained earnings for the portion of equity awards expected to vest.

	•	Dividends are recognized as additional compensation cost for the portion of equity awards that are not expected to vest or that ultimately do not vest.

Vesting expectations, in regard to these dividend payments, correspond with forfeiture rate assumptions used to recognize compensation cost. Accordingly, when the Company adjusts forfeiture rate assumptions or when actual forfeitures are ultimately recognized, related dividends are reflected as additional compensation expense as opposed to being charged directly to retained earnings.

Prior Period Pro Forma Disclosures. Prior to January 1, 2006, the Company accounted for share-based compensation under the intrinsic value method. Other than the restricted stock discussed above, no additional share-based compensation expense was reflected in prior period earnings since the exercise price was equal to the grant-date market value of the underlying common stock for all stock options granted prior to January 1, 2006. The effect

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

of share-based compensation, as if the Company had applied the fair-value-based method proscribed by FAS 123, on net income and earnings per share for prior periods presented follows (in thousands, except per share amounts):


	Three Months Ended			Nine Months Ended
	September 30,			September 30,
	2005			2005

Net income, as reported	$	106,305		$	238,551
Add back: Share-based employee compensation cost, net of related tax effects, included in net income as reported		639			1,339
Deduct: Share-based employee compensation cost, net of related tax effects, that would have been included in net income if the fair-value-based method had been applied to all awards		(3,426	)		(9,484	)

Pro-forma net income	$	103,518		$	230,406

Net income per common share:
Basic, as reported	$	0.62		$	1.40

Basic, pro-forma	$	0.60		$	1.36

Diluted, as reported	$	0.61		$	1.38

Diluted, pro-forma	$	0.59		$	1.33


3.	Comprehensive Income

The following table illustrates the Company’s comprehensive income including the effects of foreign currency translation adjustments for the three and nine months ended September 30, 2006 and 2005 (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005

Net income	$	185,990	$	106,305	$	516,936	$	238,551
Other comprehensive income:
Foreign currency translation adjustment related to our Canadian operations, net of tax		478		2,286		3,016		1,319

Comprehensive income, net of tax	$	186,468	$	108,591	$	519,952	$	239,870


4.	Property and Equipment

Property and equipment consisted of the following at September 30, 2006 and December 31, 2005 (in thousands):


	September 30,			December 31,
	2006			2005

Equipment	$	2,021,601		$	1,633,911
Oil and natural gas properties		86,143			79,079
Buildings		29,052			22,490
Land		6,104			5,611

		2,142,900			1,741,091
Less accumulated depreciation and depletion		(814,105	)		(687,246	)

Property and equipment, at cost, net	$	1,328,795		$	1,053,845

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


5.	Business Segments

Our revenues, operating profits and identifiable assets are primarily attributable to four business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services, (iii) drilling and completion fluid services to operators in the oil and natural gas industry, and (iv) the exploration, development, acquisition and production of oil and natural gas. Each of these segments represents a distinct type of business based upon the type and nature of services and products offered. These segments have separate management teams which report to the Company’s chief executive officer and have distinct and identifiable revenues and expenses. Separate financial data for each of our four business segments is provided below (in thousands).


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005

Revenues:
Contract drilling(a)	$	578,653		$	401,626		$	1,620,322		$	1,028,230
Pressure pumping		40,462			27,640			107,800			66,358
Drilling and completion fluids(b)		46,317			29,842			155,639			88,994
Oil and natural gas		9,986			10,234			29,083			28,146

Total segment revenues		675,418			469,342			1,912,844			1,211,728
Elimination of intercompany revenues(a)(b)		(1,760	)		(603	)		(4,640	)		(2,474	)

Total revenues	$	673,658		$	468,739		$	1,908,204		$	1,209,254

Income before income taxes:
Contract drilling	$	264,924		$	163,109		$	751,977		$	367,721
Pressure pumping		13,493			7,691			34,592			15,779
Drilling and completion fluids		6,558			2,746			25,038			8,261
Oil and natural gas		3,276			4,098			6,977			10,532

		288,251			177,644			818,584			402,293
Corporate and other		(5,295	)		(4,060	)		(15,278	)		(11,580	)
Other operating expenses		(2,563	)		(707	)		(3,948	)		(2,590	)
Embezzlement costs, net of recoveries(c)		1,512			(5,431	)		(2,941	)		(12,193	)
Interest income		948			944			5,579			2,011
Interest expense		(363	)		(56	)		(476	)		(179	)
Other		88			19			231			39

Income before income taxes and cumulative effect of change in accounting principle	$	282,578		$	168,353		$	801,751		$	377,801

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	September 30,		December 31,
	2006		2005

Identifiable assets:
Contract drilling	$	1,787,241	$	1,421,779
Pressure pumping		100,721		72,536
Drilling and completion fluids		104,076		90,904
Oil and natural gas		62,786		60,785

		2,054,824		1,646,004
Corporate and other(d)		40,065		149,777

Total assets	$	2,094,889	$	1,795,781


(a)		Includes contract drilling intercompany revenues of approximately $1.6 million and $580,000 for the three months ended September 30, 2006 and 2005, respectively, and approximately $4.2 million and $2.3 million for the nine months ended September 30, 2006 and 2005, respectively.

(b)		Includes drilling and completion fluids intercompany revenues of approximately $154,000 and $23,000 for the three months ended September 30, 2006 and 2005, respectively, and approximately $418,000 and $182,000 for the nine months ended September 30, 2006 and 2005, respectively .

(c)		The Company’s former CFO has pleaded guilty to criminal charges and has been sentenced and is serving a term of imprisonment arising out of his embezzlement of funds totaling approximately $77.5 million from the Company over a period of more than five years, ending November 3, 2005. Embezzlement costs, net of recoveries include embezzled funds and other costs incurred as a result of the embezzlement. In the three months ended September 30, 2006, the Company recovered $2.0 million from its insurance carrier related to the embezzlement loss.

(d)		Corporate assets primarily include cash on hand managed by the parent corporation and certain deferred federal income tax assets.


6.	Goodwill

Goodwill is evaluated at least annually to determine if the fair value of recorded goodwill has decreased below its carrying value. At December 31, 2005 the Company performed its annual goodwill evaluation and determined no adjustment to impair goodwill was necessary. Goodwill as of September 30, 2006 and December 31, 2005 is as follows (in thousands):


	September 30,		December 31,
	2006		2005

Contract Drilling:
Goodwill at beginning of period	$	89,092	$	89,092
Changes to goodwill		—		—

Goodwill at end of period		89,092		89,092

Drilling and completion fluids:
Goodwill at beginning of period	$	9,964	$	9,964
Changes to goodwill		—		—

Goodwill at end of period		9,964		9,964

Total goodwill	$	99,056	$	99,056

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


7.	Accrued Expenses

Accrued expenses consisted of the following at September 30, 2006 and December 31, 2005 (in thousands):


	September 30,		December 31,
	2006		2005

Workers’ compensation liability	$	62,737	$	47,107
Salaries, wages, payroll taxes and benefits		38,074		33,816
Sales, use and other taxes		11,647		9,484
Insurance, other than workers’ compensation		13,734		11,365
Other		24,477		10,704

Accrued expenses	$	150,669	$	112,476


8.	Asset Retirement Obligation

Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS No. 143”), requires that the Company record a liability for the estimated costs to be incurred in connection with the abandonment of oil and natural gas properties in the future. The following table describes the changes to our asset retirement obligations during the nine months ended September 30, 2006 and 2005 (in thousands):


	September 30,			September 30,
	2006			2005

Balance at beginning of year	$	1,725		$	2,358
Liabilities incurred		83			61
Liabilities settled		(48	)		(801	)
Accretion expense		41			55

Asset retirement obligation at end of period	$	1,801		$	1,673


9.	Borrowings Under Line of Credit

As of September 30, 2006, borrowings of $65.0 million have been advanced under the LOC. The weighted average interest rate on borrowings outstanding at September 30, 2006 was 8.25%.


10.	Commitments, Contingencies and Other Matters

The Company maintains letters of credit in the aggregate amount of approximately $60 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire at various times during each calendar year. No amounts have been drawn under the letters of credit.

As of September 30, 2006, the Company has remaining non-cancelable commitments to purchase $240 million of equipment through 2007.

A receiver has been appointed to identify the assets of our former CFO in connection with his embezzlement of Company funds. The receiver is liquidating the assets and will propose a plan to distribute the proceeds. While the Company believes it has a claim for at least the full amount of funds embezzled from the Company, other creditors have asserted or may assert claims with respect to the assets held by the receiver.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In December 2005, two derivative actions were filed in Texas state court in Scurry County, Texas, and in May 2006, a derivative action was filed in federal court in Lubbock, Texas, in each case, against the directors of the Company, alleging that the directors breached their fiduciary duties to the Company as a result of alleged failure to timely discover the embezzlement. The Board of Directors formed a special litigation committee to review and inquire about these allegations and recommend the Company’s response, if any. Further legal proceedings in these suits were stayed pending completion of the work of the special litigation committee. Settlement negotiations are taking place. The lawsuits seek recovery on behalf of and for the Company and do not seek recovery from the Company.

The Company is party to various other legal proceedings arising in the normal course of its business. The Company does not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on its financial condition.


11.	Stockholders’ Equity

On March 2, 2006, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.04 per share. The cash dividend of approximately $6.9 million was paid on March 30, 2006 to holders of record on March 15, 2006. On April 26, 2006, the Company’s Board of Directors approved an increase in its quarterly cash dividend from $0.04 to $0.08 on each outstanding share of its common stock. This dividend of approximately $13.4 million was paid on June 30, 2006 to holders of record on June 15, 2006. On August 2, 2006, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.08 per share. This dividend of approximately $13.0 million was paid on September 29, 2006 to holders of record on September 14, 2006. The amount and timing of all future dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of the Company’s credit facilities and other factors.

On March 27, 2006, the Company’s Board of Directors increased the Company’s previously authorized stock buyback program to allow for future purchases of up to $200 million of the Company’s outstanding common stock. During the second quarter of 2006, the Company completed the authorized buyback with the purchase of 6,704,800 shares of its common stock at a cost of approximately $200 million. On August 2, 2006, the Company’s Board of Directors again increased the Company’s previously authorized stock buyback program to allow for future purchases of up to $250 million of the Company’s outstanding common stock. During the three months ended September 30, 2006, the Company purchased 6,537,000 shares of its common stock at a cost of approximately $167 million. As of September 30, 2006, the Company is authorized to purchase approximately $83 million of the Company’s outstanding common stock under the stock buyback program. Shares purchased under the stock buyback program have been accounted for as treasury stock.


12.	Subsequent Events

On October 31, 2006, the Company’s Board of Directors approved a quarterly cash dividend of $0.08 on each outstanding share of its common stock. The dividend is to be paid on December 29, 2006 to holders of record as of December 14, 2006.


13.	Recently Issued Accounting Standards

In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006 and will be effective for the company as of January 1, 2007. The application of this standard is not expected to be material.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (“FAS 157”). FAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurement. FAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. FAS 157 will be effective for the Company in the quarter ending March 31, 2008. The application of FAS 157 is not expected to have a material impact to the Company.

In September 2006, the SEC staff issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (“SAB 108”). SAB 108 was issued in order to eliminate the diversity of practice surrounding how public companies quantify financial statement misstatements. Traditionally, there have been two widely-recognized methods for quantifying the effects of financial statement misstatements. The “roll-over” method focuses primarily on the impact of a misstatement on the income statement (including the reversing effect of prior year misstatements) but its use can lead to the accumulation of misstatements in the balance sheet. The “iron-curtain” method, on the other hand, focuses primarily on the effect of correcting the period-end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. The Company currently uses the iron-curtain method for quantifying identified financial statement misstatements. In SAB 108, the SEC staff established an approach that requires quantification of financial statement misstatements based on the effects of the misstatements on each of the company’s financial statements and the related financial statement disclosures. This model is commonly referred to as a “dual approach” because it requires quantification of errors under both the iron curtain and the roll-over methods. The Company will apply the provisions of SAB 108 in the quarter ending December 31, 2006 and the impact is not expected to be material.


ITEM 2.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*

Management Overview — We are a leading provider of contract services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and, to a lesser extent, we provide pressure pumping services and drilling and completion fluid services. In addition to the aforementioned contract services, we also engage in the development, exploration, acquisition and production of oil and natural gas. For the three and nine months ended September 30, 2006 and 2005, our operating revenues consisted of the following (dollars in thousands):


	Three Months Ended September 30,								Nine Months Ended September 30,
	2006				2005				2006				2005

Contract drilling	$	577,047	86	%	$	401,046	86	%	$	1,616,100	84	%	$	1,025,938	85	%
Pressure pumping		40,462	6			27,640	6			107,800	6			66,358	6
Drilling and completion fluids		46,163	7			29,819	6			155,221	8			88,812	7
Oil and natural gas		9,986	1			10,234	2			29,083	2			28,146	2

	$	673,658	100	%	$	468,739	100	%	$	1,908,204	100	%	$	1,209,254	100	%

We provide our contract services to oil and natural gas operators in many of the oil and natural gas producing regions of North America. Our contract drilling operations are focused in various regions of Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota and Western Canada while our pressure pumping services are focused primarily in the Appalachian Basin. Our drilling and completion fluids services are provided to operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. Our oil and natural gas operations are primarily focused in West and South Texas, Southeastern New Mexico, Utah and Mississippi.

We have been a leading consolidator of the land-based contract drilling industry over the past several years, increasing our drilling fleet to 403 rigs as of September 30, 2006. Based on publicly available information, we believe we are the second largest owner of land-based drilling rigs in North America.

The profitability of our business is most readily assessed by two primary indicators in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During the third quarter of 2006, our average number of rigs operating was 301 per day compared to 295 in the second quarter of 2006 and 283 in the third quarter of 2005. Our average revenue per operating day increased to $20,810 in the third quarter of 2006 from $19,780 in the second quarter of 2006 and $15,420 in the third quarter of 2005. Primarily due to these improvements, we experienced an increase of approximately $79.7 million, or 75%, in consolidated net income for the third quarter of 2006 as compared to the third quarter of 2005.

Our revenues, profitability and cash flows are highly dependent upon the market prices of oil and natural gas. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which results in increased demand for our contract services. Conversely, in periods of time when these commodity prices deteriorate, the demand for our contract services generally weakens and we experience downward pressure on pricing for our services. In addition, our operations are highly impacted by competition, the availability of excess equipment, labor issues and various other factors which are more fully described as “Risk Factors” included as Item 1A in our Annual Report on Form 10-K for the year ended December 31, 2005.

Management believes that the liquidity shown on our balance sheet as of September 30, 2006, which includes approximately $322 million in working capital (including $16.9 million in cash) and $250 million available under a $375 million line of credit ($65.0 million in borrowings are outstanding at September 30, 2006 and availability of $60.0 million is reserved for outstanding letters of credit), provides us with the ability to pursue acquisition opportunities, expand into new regions, make improvements to our assets, pay cash dividends, buy back the Company’s common stock and survive downturns in our industry.

Commitments and Contingencies — The Company maintains letters of credit in the aggregate amount of approximately $60.0 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire at various times during each calendar year. No amounts have been drawn under the letters of credit.

As of September 30, 2006, the Company has remaining non-cancelable commitments to purchase $240 million of equipment through 2007.

Trading and Investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits, money markets, and highly rated municipal and commercial bonds.

Description of Business — We conduct our contract drilling operations in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota and Western Canada. As of September 30, 2006, we owned 403 drilling rigs. We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. These services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. We provide drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. Drilling and completion fluids are used by oil and natural gas operators during the drilling process to control pressure when drilling oil and natural gas wells. We are also engaged in the development, exploration, acquisition and production of oil and natural gas. Our oil and natural gas operations are focused primarily in producing regions in West and South Texas, Southeastern New Mexico, Utah and Mississippi.

The North American land drilling industry has experienced periods of downturn in demand over the last decade. During these periods, there have been substantially more drilling rigs available than necessary to meet demand. As a result, drilling contractors have had difficulty sustaining profit margins during the downturn periods.

In addition to adverse effects that future declines in demand could have on us, ongoing factors which could adversely affect utilization rates and pricing, even in an environment of stronger oil and natural gas prices and increased drilling activity, include:


	•	movement of drilling rigs from region to region,

	•	reactivation of land-based drilling rigs, or

	•	new construction of drilling rigs.

We cannot predict either the future level of demand for our contract drilling services or future conditions in the oil and natural gas contract drilling business.

Critical Accounting Policies

In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. No changes in our critical accounting policies have occurred since the filing of the Company’s Annual Report on Form 10-K for the period ended December 31, 2005.

Liquidity and Capital Resources

As of September 30, 2006, we had working capital of approximately $322 million, including cash and cash equivalents of $16.9 million. For the nine months ended September 30, 2006, our significant sources of cash flow included:


	•	$614 million provided by operations,

	•	$65.0 million in proceeds from borrowings under our line of credit,

	•	$8.0 million in proceeds from disposal of property and equipment, and

	•	$2.3 million from the exercise of stock options and related tax benefits.

During the nine months ended September 30, 2006, we used $352 million to purchase shares of treasury stock, $33.3 million to pay dividends on the Company’s common stock and $423 million:


	•	to make capital expenditures for the betterment and refurbishment of our drilling rigs,

	•	to acquire and procure drilling equipment and facilities to support our drilling operations,

	•	to fund capital expenditures for our pressure pumping and drilling and completion fluids divisions, and

	•	to fund leasehold acquisition and exploration and development of oil and natural gas properties.

On August 2, 2006, the Company entered into an agreement to amend its $200 million unsecured revolving line of credit (“LOC”). In connection with this amendment, the borrowing capacity under this LOC was increased to $375 million. No significant changes were made to the terms of the LOC, including the interest to be paid on outstanding balances and financial covenants. As of September 30, 2006, we had borrowed $65.0 million under the LOC and $60.0 million in letters of credit were outstanding such that we had available borrowings of $250 million at September 30, 2006.

On March 2, 2006, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.04 per share. The dividend of approximately $6.9 million was paid on March 30, 2006. On April 26, 2006, the Company’s Board of Directors approved an increase in its quarterly cash dividend from $0.04 to $0.08 on each outstanding share of its common stock. This dividend of approximately $13.4 million was paid on June 30, 2006 to holders of record on June 15, 2006. On August 2, 2006, the Company’s Board of Directors approved a quarterly cash dividend of $0.08 on each outstanding share of its common stock. This dividend of approximately $13.0 million was paid on September 29, 2006 to holders of record as of September 14, 2006. On October 31, 2006, the Company’s Board of Directors approved a quarterly cash dividend of $0.08 on each outstanding share of its common stock. The dividend is to be paid on December 29, 2006 to holders of record as of December 14, 2006. The amount and timing of all future dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of the Company’s credit facilities and other factors.

On March 27, 2006, the Company’s Board of Directors increased the Company’s previously authorized stock buyback program to allow for future purchases of up to $200 million of the Company’s outstanding common stock. During the second quarter of 2006, the Company completed the authorized buyback with the purchase of 6,704,800 shares of its common stock at a cost of approximately $200 million. On August 2, 2006, the Company’s Board of Directors again increased the Company’s previously authorized stock buyback program to allow for future purchases of up to $250 million of the Company’s outstanding common stock. During the three months ended September 30, 2006, the Company purchased 6,537,000 shares of its common stock at a cost of approximately $167 million. As of September 30, 2006 the Company is authorized to purchase approximately $83 million of the Company’s outstanding common stock under the stock buyback program. Shares purchased under the stock buyback program have been accounted for as treasury stock.

We believe that the current level of cash and short-term investments, together with cash generated from operations, should be sufficient to meet our capital needs. From time to time, acquisition opportunities are evaluated. The timing, size or success of any acquisition and the associated capital commitments are unpredictable. Should opportunities for growth requiring capital arise, we believe we would be able to satisfy these needs through a combination of working capital, cash generated from operations, our existing credit facility and additional debt or equity financing. However, there can be no assurance that such capital would be available.

Results of Operations

Prior to the adoption of FAS 123(R) on January 1, 2006, the Company accounted for all stock options under the intrinsic value method. Accordingly, no compensation expense was recognized in prior periods for stock options because exercise prices were equal to the grant date market value of the related common stock. The modified prospective method was applied to transition from the intrinsic value method to the fair-value-based method for stock options (see Note 2 of these Notes to Unaudited Condensed Consolidated Financial Statements). The use of the modified prospective method does not result in adjustments to years prior to the adoption of FAS 123(R) which impact the comparability of certain items between 2006 and 2005. Incremental stock-based compensation in 2006 resulting from the adoption of FAS 123(R) is included in selling, general and administrative expenses in the statements of income.

The following tables summarize operations by business segment for the three months ended September 30, 2006 and 2005:


Contract Drilling	2006			2005			% Change
	(Dollars in thousands)

Revenues	$	577,047		$	401,046			43.9	%
Direct operating costs	$	267,345		$	202,956			31.7	%
Selling, general and administrative	$	1,817		$	1,286			41.3	%
Depreciation	$	42,961		$	33,695			27.5	%
Operating income	$	264,924		$	163,109			62.4	%
Operating days		27,725			26,015			6.6	%
Average revenue per operating day	$	20.81		$	15.42			35.0	%
Average direct operating costs per operating day	$	9.64		$	7.80			23.6	%
Number of owned rigs at end of period		403			403			0.0	%
Average number of rigs owned during period		403			398			1.3	%
Average rigs operating		301			283			6.4	%
Rig utilization percentage		75	%		71	%		5.6	%
Capital expenditures	$	152,879		$	90,114			69.7	%

Revenues and direct operating costs increased as a result of the increased number of operating days, as well as an increase in the average revenue and average direct operating costs per operating day. Operating days and average rigs operating increased primarily as a result of increased demand for our contract drilling services and the increase in the number of marketable rigs in our fleet due to our ongoing rig activation program. Average revenue per operating day increased as a result of increased demand and pricing for our drilling services. Average direct operating costs per operating day increased primarily as a result of increased compensation costs and an increase in the cost of maintenance for our rigs. Significant capital expenditures were incurred during the third quarter of 2006 to activate additional drilling rigs, to modify and upgrade our existing drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. The increase in depreciation expense was a result of significant capital expenditures.


Pressure Pumping	2006		2005		% Change
	(Dollars in thousands)

Revenues	$	40,462	$	27,640		46.4	%
Direct operating costs	$	20,960	$	15,662		33.8	%
Selling, general and administrative	$	3,450	$	2,464		40.0	%
Depreciation	$	2,559	$	1,823		40.4	%
Operating income	$	13,493	$	7,691		75.4	%
Total jobs		3,116		2,714		14.8	%
Average revenue per job	$	12.99	$	10.18		27.6	%
Average direct operating costs per job	$	6.73	$	5.77		16.6	%
Capital expenditures	$	7,692	$	5,865		31.2	%

Revenues and direct operating costs increased as a result of the increased number of jobs, as well as an increase in the average revenue and average direct operating cost per job. The increase in jobs was attributable to increased demand for our services and increased operating capacity which has been added in anticipation of that demand. Increased average revenue per job was due to increased pricing for our services and an increase in the number of larger jobs. Average direct operating costs per job increased as a result of increases in compensation and the cost of materials used in our operations as well as an increase in the number of larger jobs. Selling, general and administrative expense increased as a result of additional expenses which were necessary to support expanding the operations of the pressure pumping segment. Increased depreciation expense was largely due to the expansion of the pressure pumping segment through capital expenditures. Significant capital expenditures were incurred during the third quarter of 2006 to modify and upgrade existing equipment and to add additional equipment.


Drilling and Completion Fluids	2006		2005		% Change
	(Dollars in thousands)

Revenues	$	46,163	$	29,819		54.8	%
Direct operating costs	$	36,183	$	24,062		50.4	%
Selling, general and administrative	$	2,733	$	2,402		13.8	%
Depreciation	$	689	$	609		13.1	%
Operating income	$	6,558	$	2,746		138.8	%
Total jobs		550		485		13.4	%
Average revenue per job	$	83.93	$	61.48		36.5	%
Average direct operating costs per job	$	65.79	$	49.61		32.6	%
Capital expenditures	$	1,122	$	687		63.3	%

Revenues and direct operating costs increased as a result of increases in the average revenue and direct operating costs per job and in the number of total jobs. Average revenue and direct operating costs per job increased primarily as a result of an increase in large jobs in the Gulf of Mexico, as well as an increase in the average size of our smaller land-based jobs. Selling, general and administrative expense increased primarily due to increased incentive compensation resulting from higher profitability levels.


Oil and Natural Gas Production and Exploration	2006		2005		% Change
	(Dollars in thousands,
	except sales prices)

Revenues	$	9,986	$	10,234		(2.4	)%
Direct operating costs	$	3,222	$	2,365		36.2	%
Selling, general and administrative	$	684	$	545		25.5	%
Depreciation, depletion and impairment	$	2,804	$	3,226		(13.1	)%
Operating income	$	3,276	$	4,098		(20.1	)%
Capital expenditures	$	4,982	$	3,858		29.1	%
Average net daily oil production (Bbls)		961		869		10.6	%
Average net daily gas production (Mcf)		4,820		6,567		(26.6	)%
Average oil sales price (per Bbl)	$	68.66	$	60.42		13.6	%
Average natural gas sales price (per Mcf)	$	6.77	$	7.75		(12.6	)%

Revenues decreased due to a decrease in the net daily production and sales price of natural gas. Average net daily natural gas production decreased as a result of production declines and the sale of certain natural gas properties. Direct operating costs increased due primarily to approximately $608,000 in costs associated with the abandonment of an exploratory well. Depreciation, depletion and impairment expense includes approximately

$889,000 and $702,000 incurred during the three months ended September 30, 2006 and 2005, respectively, to impair certain oil and natural gas properties.


Corporate and Other	2006			2005		% Change
	(In thousands)

Selling, general and administrative	$	5,093		$	3,868		31.7	%
Depreciation	$	202		$	192		5.2	%
Other operating expenses	$	2,563		$	707		262.5	%
Embezzlement costs, net of recoveries	$	(1,512	)	$	5,431		N/A	%
Interest income	$	948		$	944		0.4	%
Interest expense	$	363		$	56		548.2	%
Other income	$	88		$	19		363.2	%

Selling, general and administrative expense increased primarily as a result of compensation expense related to the adoption of a new accounting standard in 2006 requiring the expensing of stock options. Other operating expenses in 2005 include approximately $675,000 in charges to increase reserves related to the financial failure of a workers’ compensation insurance carrier used previously by the Company, approximately $200,000 related to losses incurred as a result of Hurricane Katrina and approximately $50,000 in bad debt expense reduced by approximately $218,000 in gains on the disposal of certain assets. Other operating expenses in 2006 include approximately $3.0 million in bad debt expense reduced by approximately $437,000 in gains associated with the disposal of certain assets. Embezzlement costs, net of recoveries in 2005 includes payments made to or for the benefit of Jonathan D. Nelson, our former CFO, for assets and services that were not received by the Company and in 2006 includes continuing professional and other costs related to the embezzlement, net of insurance proceeds of $2.0 million received in connection with the loss. Interest expense in 2006 increased due to borrowings under our line of credit during the third quarter of 2006.

The following tables summarize operations by business segment for the nine months ended September 30, 2006 and 2005:


Contract Drilling	2006			2005			% Change
	(Dollars in thousands)

Revenues	$	1,616,100		$	1,025,938			57.5	%
Direct operating costs	$	737,021		$	558,607			31.9	%
Selling, general and administrative	$	5,338		$	3,701			44.2	%
Depreciation	$	121,764		$	95,909			27.0	%
Operating income	$	751,977		$	367,721			104.5	%
Operating days		81,489			73,746			10.5	%
Average revenue per operating day	$	19.83		$	13.91			42.6	%
Average direct operating costs per operating day	$	9.04		$	7.57			19.4	%
Number of owned rigs at end of period		403			403			0.0	%
Average number of rigs owned during period		403			395			2.0	%
Average rigs operating		298			270			10.4	%
Rig utilization percentage		74	%		68	%		8.8	%
Capital expenditures	$	377,165		$	222,492			69.5	%

Revenues and direct operating costs increased as a result of the increased number of operating days, as well as an increase in the average revenue and average direct operating costs per operating day. Operating days and average rigs operating increased primarily as a result of increased demand for our contract drilling services and the increase in the number of marketable rigs in our fleet due to our ongoing rig activation program. Average revenue per operating day increased as a result of increased demand and pricing for our drilling services. Average direct operating costs per operating day increased primarily as a result of increased compensation costs and an increase in the cost of maintenance for our rigs. Selling, general and administrative expense increased due to additional personnel and other costs to support the increased level of activity in the contract drilling segment. Significant capital expenditures were incurred in 2006 to activate additional drilling rigs, to modify and upgrade our existing drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating

systems, rig hoisting systems and safety enhancement equipment. Increased depreciation expense was due to capital expenditures.


Pressure Pumping	2006		2005		% Change
	(Dollars in thousands)

Revenues	$	107,800	$	66,358		62.5	%
Direct operating costs	$	56,545	$	38,648		46.3	%
Selling, general and administrative	$	9,588	$	6,858		39.8	%
Depreciation	$	7,075	$	5,073		39.5	%
Operating income	$	34,592	$	15,779		119.2	%
Total jobs		8,844		6,968		26.9	%
Average revenue per job	$	12.19	$	9.52		28.0	%
Average direct operating costs per job	$	6.39	$	5.55		15.1	%
Capital expenditures	$	27,371	$	20,598		32.9	%

Revenues and direct operating costs increased as a result of the increased number of jobs, as well as an increase in the average revenue and average direct operating cost per job. The increase in jobs was attributable to increased demand for our services and increased operating capacity which has been added. Increased average revenue per job was due to increased pricing for our services and an increase in the number of larger jobs. Average direct operating costs per job increased as a result of increases in compensation and the cost of materials used in our operations as well as an increase in the number of larger jobs. Selling, general and administrative expense increased as a result of additional expenses which were necessary to support expanding the operations of the pressure pumping segment. Increased depreciation expense was largely due to the expansion of the pressure pumping segment through capital expenditures. Significant capital expenditures were incurred during 2006 to modify and upgrade existing equipment and to add additional equipment.


Drilling and Completion Fluids	2006		2005		% Change
	(Dollars in thousands)

Revenues	$	155,221	$	88,812		74.8	%
Direct operating costs	$	120,418	$	71,857		67.6	%
Selling, general and administrative	$	7,765	$	6,964		11.5	%
Depreciation	$	2,000	$	1,730		15.6	%
Operating income	$	25,038	$	8,261		203.1	%
Total jobs		1,569		1,515		3.6	%
Average revenue per job	$	98.93	$	58.62		68.8	%
Average direct operating costs per job	$	76.75	$	47.43		61.8	%
Capital expenditures	$	3,052	$	2,039		49.7	%

Revenues and direct operating costs increased primarily as a result of increases in the average revenue and direct operating costs per job. Average revenue and direct operating costs per job increased primarily as a result of an increase in large jobs in the Gulf of Mexico, as well as an increase in the average size of our smaller land-based

jobs. Selling, general and administrative expense increased in 2006 primarily due to increased incentive compensation resulting from higher profitability levels.


Oil and Natural Gas Production and Exploration	2006		2005		% Change
	(Dollars in thousands,
	except sales prices)

Revenues	$	29,083	$	28,146		3.3	%
Direct operating costs	$	11,241	$	6,953		61.7	%
Selling, general and administrative	$	2,050	$	1,598		28.3	%
Depreciation, depletion and impairment	$	8,815	$	9,063		(2.7	)%
Operating income	$	6,977	$	10,532		(33.8	)%
Capital expenditures	$	15,699	$	12,286		27.8	%
Average net daily oil production (Bbls)		944		854		10.5	%
Average net daily gas production (Mcf)		4,986		7,465		(33.2	)%
Average oil sales price (per Bbl)	$	66.24	$	52.92		25.2	%
Average natural gas sales price (per Mcf)	$	6.96	$	6.63		5.0	%

Revenues increased slightly due to an increase in the net daily production and sales price of oil which was offset by a decrease in the net daily production of natural gas. Average net daily natural gas production decreased as a result of production declines and the sale of certain natural gas properties during 2005. The increase in direct operating costs includes a charge of $3.1 million associated with the abandonment of exploratory wells in 2006. Depreciation, depletion and impairment expense includes approximately $2.2 million and $1.5 million incurred during the nine months ended September 30, 2006 and 2005, respectively, to impair certain oil and natural gas properties.


Corporate and Other	2006		2005		% Change
	(In thousands)

Selling, general and administrative	$	14,687	$	11,036		33.1	%
Depreciation	$	591	$	544		8.6	%
Other operating expenses	$	3,948	$	2,590		52.4	%
Embezzlement costs, net of recoveries	$	2,941	$	12,193		(75.9	)%
Interest income	$	5,579	$	2,011		177.4	%
Interest expense	$	476	$	179		165.9	%
Other income	$	231	$	39		492.3	%
Capital Expenditures	$	135	$	5,308		(97.5	)%

Selling, general and administrative expense increased primarily as a result of compensation expense related to the adoption of a new accounting standard in 2006 requiring the expensing of stock options. Other operating expenses in 2005 include approximately $1.3 million in gains recognized on the sale of certain oil and natural gas properties and other equipment reduced by approximately $3.2 million in charges to increase reserves related to the financial failure of a workers’ compensation insurance carrier used previously by the Company, approximately $200,000 related to losses incurred as a result of Hurricane Katrina and approximately $416,000 in bad debt expenses. Other operating expenses in 2006 include approximately $4.2 million in bad debt expense reduced by gains associated with the disposal of certain assets. Interest income increased as a result of higher cash balances and improvements in interest rates in 2006. Interest expense in 2006 increased due to borrowings under our line of credit during the third quarter of 2006. Embezzlement costs, net of recoveries in 2005 includes payments made to or for the benefit of Jonathan D. Nelson, our former CFO, for assets and services that were not received by the Company and in 2006 includes continuing professional and other costs related to the embezzlement, net of insurance proceeds of $2.0 million received in connection with the loss.

Recently Issued Accounting Standards

tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006 and will be effective for the Company as of January 1, 2007. The application of this standard is not expected to be material.

Volatility of Oil and Natural Gas Prices and its Impact on Operations

Our revenue, profitability, and rate of growth are substantially dependent upon prevailing prices for oil and natural gas, with respect to all of our operating segments. For many years, oil and natural gas prices and markets have been volatile. Prices are affected by market supply and demand factors as well as international military, political and economic conditions, and the ability of OPEC to set and maintain production and price targets. All of these factors are beyond our control. Natural gas prices fell from an average of $6.23 per Mcf in the first quarter of 2001 to an average of $2.51 per Mcf for the same period in 2002. During this same period, the average number of our rigs operating dropped by approximately 50%. The average market price of natural gas improved from $3.36 in 2002 to $6.77 in the third quarter of 2006, resulting in an increase in demand for our drilling services. Our average number of rigs operating increased from 126 in 2002 to 301 in the third quarter of 2006. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition and operations and ability to access sources of capital. A significant decrease in expected market prices for natural gas could result in a material decrease in demand for drilling rigs and reduction in our operation results.

The North American land drilling industry has experienced many downturns in demand over the last decade. During these periods, there have been substantially more drilling rigs available than necessary to meet demand. As a result, drilling contractors have had difficulty sustaining profit margins during the downturn periods.

Impact of Inflation

We believe that inflation will not have a significant near-term impact on our financial position.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

We currently have exposure to interest rate market risk associated with borrowings under our credit facility. The revolving credit facility calls for periodic interest payments at a floating rate ranging from LIBOR plus 0.625% to 1.0% or at the prime rate. The applicable rate above LIBOR is based upon our debt to capitalization ratio. Our exposure to interest rate risk due to changes in the prime rate or LIBOR is not material.

We conduct some business in Canadian dollars through our Canadian land-based drilling operations. The exchange rate between Canadian dollars and U.S. dollars has fluctuated during the last several years. If the value of

the Canadian dollar against the U.S. dollar weakens, revenues and earnings of our Canadian operations will be reduced and the value of our Canadian net assets will decline when they are translated to U.S. dollars.

ITEM 4. Controls and Procedures

Disclosure Controls and Procedures — We maintain disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) designed to ensure that the information required to be disclosed in the reports that we file with the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, and due to the material weaknesses in the Company’s internal control over financial reporting as reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005, our CEO and CFO concluded that our disclosure controls and procedures were not effective at a reasonable level of assurance, as of September 30, 2006. For a discussion of the material weaknesses, see Item 9A of our Annual Report on Form 10-K for the year ended December 31, 2005.

Changes in Internal Control Over Financial Reporting — Our management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f). With the participation of our CEO and CFO, our management evaluates any changes in our internal control over financial reporting that occurred during each fiscal quarter which have materially affected, or are reasonably likely to materially affect, such internal control. At December 31, 2005, the Company’s assessment of the effectiveness of its internal control over financial reporting concluded that material weaknesses in its control environment and controls over property and equipment existed. During the first nine months of 2006, the Company has implemented, or is in the process of implementing, remediation steps to address these material weaknesses. You can find more information about these material weaknesses and the actions that we have taken and are planning to take to remediate the material weaknesses in Item 9A of our Annual Report on Form 10-K for the year ended December 31, 2005.

There were no changes in the Company’s internal control over financial reporting during its most recently completed fiscal quarter that have materially affected or are reasonably likely to materially affect its internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act.

FORWARD LOOKING STATEMENTS AND CAUTIONARY STATEMENTS FOR PURPOSES OF
THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995

“Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in Item 2 of this Report contains forward-looking statements which are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. These statements include, without limitation, statements relating to: liquidity; financing of operations; continued volatility of oil and natural gas prices; source and sufficiency of funds required for immediate capital needs and additional rig acquisitions (if further opportunities arise); and other matters. The words “believes,” “plans,” “intends,” “expected,” “estimates” or “budgeted” and similar expressions identify forward-looking statements. The forward-looking statements are based on certain assumptions and analyses we make in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. We do not undertake to update, revise or correct any of the forward-looking information. Factors that could cause actual results to differ materially from our expectations expressed in the forward-looking statements include, but are not limited to, the following:


	•	Changes in prices and demand for oil and natural gas;

	•	Changes in demand for contract drilling, pressure pumping and drilling and completion fluids services;


	•	Shortages of drill pipe and other drilling equipment;

	•	Labor shortages, primarily qualified drilling personnel;

	•	Effects of competition from other drilling contractors and providers of pressure pumping and drilling and completion fluids services;

	•	Occurrence of operating hazards and uninsured losses inherent in our business operations; and

	•	Environmental and other governmental regulation.

For a more complete explanation of these factors and others, see “Risk Factors” included as Item 1A in our Annual Report on Form 10-K for the year ended December 31, 2005, beginning on page 11.

You are cautioned not to place undue reliance on any of our forward-looking statements, which speak only as of the date of this Report or, in the case of documents incorporated by reference, the date of those documents.

PART II — OTHER INFORMATION

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

The table below sets forth the information with respect to purchases of our common stock made by the Company during the quarter ended September 30, 2006.


							Approximate Dollar
					Total Number of		Value of Shares
					Shares (or Units)		That May yet be
					Purchased as Part		Purchased Under the
	Total		Average Price		of Publicly		Plans or
	Number of Shares		Paid per		Announced Plans		Programs (in
Period Covered	Purchased(1)		Share		or Programs(2)		thousands)(2)

July 1-31, 2006		—	$	—		—	$	—
August 1-31, 2006		2,887,000	$	27.16		2,887,000	$	171,587
September 1-30, 2006		3,650,000	$	24.18		3,650,000	$	83,324

Total		6,537,000	$	25.50		6,537,000	$	83,324


(1)		All of the reported shares were purchased in open-market transactions.

(2)		On June 7, 2004, our Board of Directors authorized a stock buyback program for the purchase of up to $30 million of our outstanding common stock, which repurchases could be made from time to time as, in the opinion of management, market conditions warranted, in the open market or in privately negotiated transactions. On March 27, 2006, our Board of Directors increased the stock buyback program to allow the future purchases of up to $200 million of our outstanding common stock. As of June 30, 2006, the purchases under this program had been completed, and on August 2, 2006, the Company’s Board of Directors authorized an increase in the size of the previously approved stock buyback program to allow for future purchases of up to $250 million of the Company’s outstanding common stock.


ITEM 4.	*Submission of Matters to a Vote of Security Holders*

On July 12, 2006, the Company held its Annual Meeting of Stockholders. At the meeting, the stockholders voted on the election of eight persons to serve as directors of the Company. The eight nominees to the Board of Directors of the Company were elected at the meeting. The number of votes cast for or withheld, were as follows:


	Votes For		Votes Withheld

Mark S. Siegel		147,055,845		4,169,682
Cloyce A. Talbott		148,290,667		2,934,860
Kenneth N. Berns		144,213,982		7,011,545
Robert C. Gist		144,100,153		7,125,374
Curtis W. Huff		148,128,445		3,097,082
Terry H. Hunt		149,970,941		1,254,586
Kenneth R. Peak		144,035,789		7,189,738
Nadine C. Smith		144,001,236		7,224,291


ITEM 5.	*Other Information*

None.


ITEM 6.	*Exhibits*

(a) Exhibits.

The following exhibits are filed herewith or incorporated by reference, as indicated:


3	.1	Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3	.2	Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3	.3	Amended and Restated Bylaws (filed March 19, 2002 as Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference).
10	.1	Commitment Increase and Joinder Agreement, dated as of August 2, 2006, by and among Patterson-UTI Energy, Inc., the guarantors party thereto, the lenders party thereto, and Bank of America, N.A. as Administrative Agent, L/C Issuer and Lender (filed August 21, 2006 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
31	.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
31	.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
32	.1	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

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

PATTERSON-UTI ENERGY, INC.


	By:	/s/ Cloyce A. Talbott

Cloyce A. Talbott

(Principal Executive Officer)

President & Chief Executive Officer


	By:	/s/ John E. Vollmer III

John E. Vollmer III

(Principal Financial and Accounting Officer)

Senior Vice President-Corporate Development,

Chief Financial Officer, Secretary and Treasurer

DATED: November 6, 2006

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