Patterson-UTI Energy (PTEN) 10-Q 2006 Q2 Quarterly report

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 June 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, SNYDER, TEXAS	79549 (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” inRule 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 inRule 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.

166,055,859 shares of common stock, $0.01 par value, as of July 31, 2006

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

			Page
PART I — FINANCIAL INFORMATION
	ITEM 1.	Financial Statements		3
		Unaudited condensed consolidated balance sheets		3
		Unaudited condensed consolidated statements of income		4
		Unaudited condensed consolidated statement of changes in stockholders’ equity		5
		Unaudited condensed consolidated statements of changes in cash flows		6
		Notes to unaudited condensed consolidated financial statements		7
	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		18
	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk		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				28
PART II — OTHER INFORMATION
	ITEM 5.	Other Information		29
	ITEM 6.	Exhibits		29
Signatures				30
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO & CFO Pursuant to Section 906

2

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

	June 30,			December 31,
	2006			2005
	(Unaudited)
	(In thousands, except
	share data)
ASSETS
Current assets:
Cash and cash equivalents	$	18,992		$	136,398
Accounts receivable, net of allowance for doubtful accounts of $3,337 at June 30, 2006 and $2,199 at December 31, 2005		507,850			422,002
Inventory		32,386			27,907
Deferred tax assets, net		27,740			26,382
Prepaid federal and state income taxes		1,983			—
Other		34,539			25,168
Total current assets		623,490			637,857
Property and equipment, at cost, net		1,214,789			1,053,845
Goodwill		99,056			99,056
Other		4,860			5,023
Total assets	$	1,942,195		$	1,795,781
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	123,511		$	113,226
Accrued revenue distributions		14,131			13,379
Other		7,855			5,294
Accrued federal and state income taxes payable		—			11,034
Accrued expenses		124,536			112,476
Total current liabilities		270,033			255,409
Deferred tax liabilities, net		179,122			169,188
Other		4,390			4,173
Total liabilities		453,545			428,770
Commitments and contingencies (see Note 9)
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 176,227,954 and 175,909,274 issued and 166,055,058 and 172,441,178 outstanding at June 30, 2006 and December 31, 2005, respectively		1,762			1,759
Additional paid-in capital		671,333			672,151
Deferred Compensation		—			(9,287	)
Retained earnings		1,029,740			719,113
Accumulated other comprehensive income		11,103			8,565
Treasury stock, at cost, 10,172,896 and 3,468,096 shares at June 30, 2006 and December 31, 2005, respectively		(225,288	)		(25,290	)
Total stockholders’ equity		1,488,650			1,367,011
Total liabilities and stockholders’ equity	$	1,942,195		$	1,795,781

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

3

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
	(Unaudited)						(Unaudited)
	(In thousands, except						(In thousands, except
	per share amounts)						per share amounts)
Operating revenues:
Contract drilling	$	530,349		$	329,503		$	1,039,053		$	624,892
Pressure pumping		36,010			22,025			67,338			38,718
Drilling and completion fluids		59,877			29,587			109,058			58,993
Oil and natural gas		10,577			8,807			19,097			17,912
		636,813			389,922			1,234,546			740,515
Operating costs and expenses:
Contract drilling		235,902			180,185			469,676			355,651
Pressure pumping		17,935			12,622			35,585			22,986
Drilling and completion fluids		46,049			23,846			84,235			47,795
Oil and natural gas		5,364			2,418			8,019			4,588
Depreciation, depletion and impairment		47,481			37,559			91,030			72,774
Selling, general and administrative		12,840			9,919			25,651			19,592
Bad debt expense		600			143			1,200			366
Embezzled funds and related expenses		673			5,156			4,453			6,762
Other operating expenses (includes gain or loss on disposal of assets)		1,056			1,423			185			1,517
		367,900			273,271			720,034			532,031
Operating income		268,913			116,651			514,512			208,484
Other income (expense):
Interest income		2,280			634			4,631			1,067
Interest expense		(55	)		(57	)		(113	)		(123	)
Other		59			16			143			20
		2,284			593			4,661			964
Income before income taxes and cumulative effect of change in accounting principle		271,197			117,244			519,173			209,448
Income tax expense (benefit):
Current		98,394			45,410			182,325			78,939
Deferred		1,113			(2,192	)		6,589			(1,737	)
		99,507			43,218			188,914			77,202
Income before cumulative effect of change in accounting principle		171,690			74,026			330,259			132,246
Cumulative effect of change in accounting principle, net of related income tax expense of $398		—			—			687			—
Net income	$	171,690		$	74,026		$	330,946		$	132,246
Income before cumulative effect of change in accounting principle:
Basic	$	1.02		$	0.44		$	1.94		$	0.78
										��
Diluted	$	1.00		$	0.43		$	1.91		$	0.77
Net income per common share:
Basic	$	1.02		$	0.44		$	1.94		$	0.78
Diluted	$	1.00		$	0.43		$	1.91		$	0.77
Weighted average number of common shares outstanding:
Basic		168,894			169,992			170,351			169,378
Diluted		171,522			173,162			172,949			172,648

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

4

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		243			2		(2	)		—			—			—		—			—
Exercise of stock options		111			1		1,260			—			—			—		—			1,261
Tax benefit for stock option exercises		—			—		845			—			—			—		—			845
Stock based compensation, net of cumulative effect of change in accounting principle		—			—		6,366			—			—			—		—			6,366
Forfeitures of restricted shares		(35	)		—		—			—			—			—		—			—
Elimination of deferred compensation due to change in accounting principle		—			—		(9,287	)		9,287			—			—		—			—
Foreign currency translation adjustment, net of tax of $1,589		—			—		—			—			—			2,538		—			2,538
Payment of cash dividends		—			—		—			—			(20,319	)		—		—			(20,319	)
Purchases of treasury stock		—			—		—			—			—			—		(199,998	)		(199,998	)
Net income		—			—		—			—			330,946			—		—			330,946
Balance, June 30, 2006		176,228		$	1,762	$	671,333		$	—		$	1,029,740		$	11,103	$	(225,288	)	$	1,488,650

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

5

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS

	Six Months Ended
	June 30,
	2006			2005
	(Unaudited)
	(In thousands)
Cash flows from operating activities:
Net income	$	330,946		$	132,246
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and impairment		91,030			72,774
Dry holes and abandonments		3,101			—
Provision for bad debts		1,200			366
Deferred income tax expense (benefit)		6,987			(1,737	)
Tax benefit related to exercise of stock options		—			17,270
Stock based compensation expense		6,366			1,108
Gain on disposal of assets		—			(1,034	)
Changes in operating assets and liabilities, net of business acquired:
Accounts receivable		(86,185	)		(85,417	)
Inventory		(4,479	)		(4,182	)
Other assets		(9,176	)		(2,808	)
Accounts payable		10,862			14,481
Income taxes payable/receivable		(12,561	)		8,393
Accrued expenses		11,959			5,056
Other liabilities		2,778			2,602
Net cash provided by operating activities		352,828			159,118
Cash flows from investing activities:
Purchases of property and equipment		(256,747	)		(162,199	)
Acquisitions		—			(65,401	)
Proceeds from disposal of property and equipment		4,264			8,839
Change in other assets		—			1,766
Net cash used in investing activities		(252,483	)		(216,995	)
Cash flows from financing activities:
Purchases of treasury stock		(199,998	)		—
Dividends paid		(20,319	)		(13,537	)
Proceeds from exercise of stock options		1,261			29,314
Tax benefit related to exercise of stock options		845			—
Net cash provided by (used in) financing activities		(218,211	)		15,777
Effect of foreign exchange rate changes on cash		460			(194	)
Net increase (decrease) in cash and cash equivalents		(117,406	)		(42,294	)
Cash and cash equivalents at beginning of period		136,398			112,371
Cash and cash equivalents at end of period	$	18,992		$	70,077
Supplemental disclosure of cash flow information:
Net cash paid during the period for:
Interest expense	$	(113	)	$	(123	)
Income taxes	$	(184,501	)	$	(48,585	)

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

6

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 onForm 10-K for the year ended December 31, 2005.

The Company’s former Chief Financial Officer (“former CFO”) has pleaded guilty to criminal charges arising out of his embezzlement of funds totalling 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.

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 six months ended June 30, 2006 and 2005, all potentially dilutive instruments were included in the calculation of Diluted EPS. The following table presents information necessary to calculate earnings per share for the three and six months ended June 30, 2006 and 2005 as well as cash

7

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Net income	$	171,690	$	74,026	$	330,946	$	132,246
Weighted average number of common shares outstanding		168,894		169,992		170,351		169,378
Basic net income per common share	$	1.02	$	0.44	$	1.94	$	0.78
Weighted average number of common shares outstanding		168,894		169,992		170,351		169,378
Dilutive effect of stock options and restricted shares		2,628		3,170		2,598		3,270
Weighted average number of diluted common shares outstanding		171,522		173,162		172,949		172,648
Diluted net income per common share	$	1.00	$	0.43	$	1.91	$	0.77
Cash dividends per common share(a)	$	0.08	$	0.04	$	0.12	$	0.08

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

The results of operations for the three and six months ended June 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 thefair-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 June 30, 2006, the Company recognized $3.5 million in stock-based compensation expense and a related income tax benefit of $1.3 million. For the six months ended June 30, 2006, the Company recognized $7.4 million in stock-based compensation expense and a related income tax benefit of $2.7 million.

8

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 be made under any of the Company’s six other previously existing plans. The Company’s share-based compensation plans at June 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		430,950		5,462,795
Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan, as amended (“1997 Plan”)		—		5,098,985		—
Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (“2001 Plan”)		—		784,404		—
Amended and Restated Non-Employee Director Stock Option Plan of Patterson-UTI Energy, Inc. (“Non-Employee Director Plan”)		—		180,000		—
1997 Stock Option Plan of DSI Industries, Inc. (“DSI Plan”)		—		536		—
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”)		—		136,400		—

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 June 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.

9

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Options granted under the DSI plan typically vested at a rate of 33% per year with ten 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.

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 thefair-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 thefair-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. Weighted-average assumptions used to estimate grant date fair values for stock options granted in the three and six month periods ended June 30, 2006 and 2005 follow:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2006		2005			2006			2005
Volatility		N/A		26.95	%		26.95	%		26.95	%
Expected term (in years)		N/A		4.00			4.00			4.00
Divided yield		N/A		0.65	%		0.47	%		0.65	%
Risk-free interest rate		N/A		3.84	%		4.30	%		3.84	%

No stock options were granted during the three months ended June 30, 2006.

10

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

						June 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		50,000		$	34.24
Exercised		(110,832	)	$	11.38
Forfeited		(14,717	)	$	11.83
Expired		(5,584	)	$	7.62
Cancelled(a)		(360,833	)	$	14.83
Outstanding at June 30, 2006		5,896,077		$	14.58		6.24	$	81,231
Exercisable at June 30, 2006		5,172,793		$	13.65		6.00	$	75,840

(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 six month periods ended June 30, 2006 and 2005 follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Weighted-average grant-date fair value of stock options granted	$	N/A	$	6.33	$	9.23	$	6.33
Aggregate intrinsic value of stock options exercised ($000’s)	$	2,342	$	33,510	$	2,342	$	47,450

As of June 30, 2006, options to purchase 723,284 shares were outstanding and not vested. Of these non-vested options, approximately 714,000 are expected to ultimately vest. Additional information as of June 30, 2006 with respect to these options that are expected to vest follows:

Aggregate intrinsic value	$	5.3	million
Weighted-average remaining contractual term		7.96	years
Weighted-average remaining expected term		2.05	years
Weighted-average remaining vesting period		1.31	years
Unrecognized compensation cost	$	5.0	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

11

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

•  Contra equity deferred compensation was reversed againstpaid-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 June 30, 2006 follows:

				Weighted
				Average
				Grant Date
	Shares			Fair Value
Nonvested at January 1, 2006		623,150		$	21.44
Granted		242,900		$	35.63
Vested		—		$	—
Forfeited		(35,052	)	$	26.39
Nonvested at June 30, 2006		830,998		$	25.38

As of June 30, 2006, approximately 627,000 shares of nonvested restricted stock outstanding are expected to vest. Additional information as of June 30, 2006 with respect to these shares that are expected to vest follows:

Aggregate intrinsic value	$	17.8	million
Weighted-average remaining vesting period		2.0	years
Unrecognized compensation cost	$	10.8	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.

12

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 of share-based compensation, as if the Company had applied thefair-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			Six Months Ended
	June 30,			June 30,
	2005			2005
Net income, as reported	$	74,026		$	132,246
Add back: Share-based employee compensation cost, net of related tax effects, included in net income as reported		399			700
Deduct: Share-based employee compensation cost, net of related tax effects, that would have been included in net income if thefair-value-based method had been applied to all awards		(2,811	)		(5,358	)
Pro-forma net income	$	71,614		$	127,588
Net income per common share:
Basic, as reported	$	0.44		$	0.78
Basic, pro-forma	$	0.42		$	0.75
Diluted, as reported	$	0.43		$	0.77
Diluted, pro-forma	$	0.41		$	0.74

3.   Comprehensive Income (Expense)

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2006		2005			2006		2005
Net income	$	171,690	$	74,026		$	330,946	$	132,246
Other comprehensive income (expense):
Foreign currency translation adjustment related to our Canadian operations, net of tax		2,703		(631	)		2,538		(967	)
Comprehensive income, net of tax	$	174,393	$	73,395		$	333,484	$	131,279

13

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

4.   Property and Equipment

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

	June 30,			December 31,
	2006			2005
Equipment	$	1,870,243		$	1,633,911
Oil and natural gas properties		82,857			79,079
Buildings		25,752			22,490
Land		5,542			5,611
		1,984,394			1,741,091
Less accumulated depreciation and depletion		(769,605	)		(687,246	)
Property and equipment, at cost, net	$	1,214,789		$	1,053,845

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						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Revenues:
Contract drilling(a)	$	531,904		$	330,027		$	1,041,668		$	626,604
Pressure pumping		36,010			22,025			67,338			38,718
Drilling and completion fluids(b)		60,098			29,726			109,322			59,152
Oil and natural gas		10,577			8,807			19,097			17,912
Total segment revenues		638,589			390,585			1,237,425			742,386
Elimination of intercompany revenues (a)(b)		1,776			663			2,879			1,871
Total revenues	$	636,813		$	389,922		$	1,234,546		$	740,515
Income before income taxes:
Contract drilling	$	252,446		$	115,729		$	487,053		$	204,612
Pressure pumping		12,593			5,533			21,099			8,088
Drilling and completion fluids		10,562			2,803			18,480			5,515
Oil and natural gas		472			3,106			3,701			6,434
		276,073			127,171			530,333			224,649
Corporate and other		(6,487	)		(2,812	)		(11,368	)		(6,851	)
Other operating expenses		—			(2,552	)		—			(2,552	)
Embezzled funds and related expenses(c)		(673	)		(5,156	)		(4,453	)		(6,762	)
Interest income		2,280			634			4,631			1,067
Interest expense		(55	)		(57	)		(113	)		(123	)
Other		59			16			143			20
Income before income taxes and cumulative effect of change in accounting principle	$	271,197		$	117,244		$	519,173		$	209,448

14

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	June 30,		December 31,
	2006		2005
Identifiable assets:
Contract drilling	$	1,648,906	$	1,421,779
Pressure pumping		94,635		72,536
Drilling and completion fluids		129,680		90,904
Oil and natural gas		60,122		60,785
		1,933,343		1,646,004
Corporate and other(d)		8,852		149,777
Total assets	$	1,942,195	$	1,795,781

(a)	Includes contract drilling intercompany revenues of approximately $1.6 million and $524,000 for the three months ended June 30, 2006 and 2005, respectively, and approximately $2.6 million and $1.7 million for the six months ended June 30, 2006 and 2005, respectively.
(b)	Includes drilling and completion fluids intercompany revenues of approximately $221,000 and $139,000 for the three months ended June 30, 2006 and 2005, respectively, and approximately $264,000 and $159,000 for the six months ended June 30, 2006 and 2005, respectively .
(c)	The Company’s former CFO has pleaded guilty to criminal charges arising out of his embezzlement of funds totalling approximately $77.5 million from the Company over a period of more than five years, ending November 3, 2005. Embezzled funds and related expenses include embezzled funds and other costs incurred as a result of the embezzlement.
(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 June 30, 2006 and December 31, 2005 is as follows (in thousands):

	June 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

15

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

7.   Accrued Expenses

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

	June 30,		December 31,
	2006		2005
Workers’ compensation liability	$	56,229	$	47,107
Salaries, wages, payroll taxes and benefits		34,049		33,816
Sales, use and other taxes		10,330		9,484
Insurance, other than workers’ compensation		13,253		11,365
Other		10,675		10,704
Accrued expenses	$	124,536	$	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 six months ended June 30, 2006 and 2005 (in thousands):

	June 30,			June 30,
	2006			2005
Balance at beginning of year	$	1,725		$	2,358
Liabilities incurred		63			19
Liabilities settled		(45	)		(511	)
Accretion expense		27			37
Asset retirement obligation at end of period	$	1,770		$	1,903

9.   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 June 30, 2006, the Company has signed non-cancelable commitments to purchase $66.3 million of equipment to be received throughout the remainder of 2006.

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.

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

16

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

suits have been stayed pending completion of the work of the special litigation committee. 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.

10.   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. 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. Shares purchased under the stock buyback program have been accounted for as treasury stock.

11.   Subsequent Events

As of June 30, 2006, the Company had completed the authorized buyback of its common stock under the plan that had been previously authorized by the Company’s Board of Directors. 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.

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.

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. The dividend is to be paid on September 29, 2006 to holders of record as of September 14, 2006.

12.   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 Company is in the process of evaluating the impact of the adoption of this standard.

17

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 six months ended June 30, 2006 and 2005, our operating revenues consisted of the following (dollars in thousands):

	Three Months Ended June 30,								Six Months Ended June 30,
	2006				2005				2006				2005
Contract drilling	$	530,349	83	%	$	329,503	84	%	$	1,039,053	84	%	$	624,892	84	%
Pressure pumping		36,010	6			22,025	6			67,338	5			38,718	5
Drilling and completion fluids		59,877	9			29,587	8			109,058	9			58,993	8
Oil and natural gas		10,577	2			8,807	2			19,097	2			17,912	3
	$	636,813	100	%	$	389,922	100	%	$	1,234,546	100	%	$	740,515	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 June 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 second quarter of 2006, our average number of rigs operating was 295 per day compared to 300 in the first quarter of 2006 and 265 in the second quarter of 2005. Our average revenue per operating day increased to $19,780 in the second quarter of 2006 from $18,840 in the first quarter of 2006 and $13,690 in the second quarter of 2005. Primarily due to these improvements, we experienced an increase of approximately $97.7 million, or 132%, in consolidated net income for the second quarter of 2006 as compared to the second 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 onForm 10-K for the year ended December 31, 2005, beginning on page 11.

Management believes that the liquidity of our balance sheet as of June 30, 2006, which includes approximately $353 million in working capital (including $19 million in cash), no long-term debt and $140 million available under a $200 million line of credit (availability of $60 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 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

18

letters of credit expire at various times during each calendar year. No amounts have been drawn under the letters of credit.

As of June 30, 2006, the Company has signed non-cancelable commitments to purchase $66.3 million of equipment to be received throughout the remainder of 2006.

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.

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 have been stayed pending completion of the work of the special litigation committee. The lawsuits seek recovery on behalf of and for the Company and do not seek recovery from the Company.

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 June 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 onForm 10-K for the period ended December 31, 2005.

19

Liquidity and Capital Resources

As of June 30, 2006, we had working capital of approximately $353 million, including cash and cash equivalents of $19 million. For the six months ended June 30, 2006, our significant sources of cash flow included:

•  $353 million provided by operations,

•  $4.3 million in proceeds from sales of property and equipment, and

•  $2.1 million from the exercise of stock options and related tax benefits.

For the six months ended June 30, 2006, we used $200 million to purchase shares of treasury stock, $20.3 million to pay dividends on the Company’s common stock and $257 million:

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

•  to acquire and procure drilling equipment,

•  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.

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. The dividend is to be paid on September 29, 2006 to holders of record as of 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. Shares purchased under the stock buyback program have been accounted for as treasury stock. On August 2, 2006, the Company’s Board of Directors authorized a further increase in the size of this previously approved stock buyback program to allow for future purchases of up to $250 million of the Company’s outstanding common stock.

The table below sets forth the information with respect to purchases of our common stock made by or on our behalf during the quarter ended June 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)
April 1-30, 2006		1,250,000	$	32.75		1,250,000	$	159,065
May 1-31, 2006		2,925,000	$	30.34		2,925,000	$	70,329
June 1-30, 2006		2,529,800	$	27.80		2,529,800	$	—
Total		6,704,800	$	29.83		6,704,800	$	—

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

20

(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 may be made from time to time as, in the opinion of management, market conditions warrant, 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.

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 thefair-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 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.

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

Contract Drilling	2006			2005			% Change
	(Dollars in thousands)
Revenues	$	530,349		$	329,503			61.0	%
Direct operating costs	$	235,902		$	180,185			30.9	%
Selling, general and administrative	$	1,733		$	1,199			44.5	%
Depreciation	$	40,268		$	32,390			24.3	%
Operating income	$	252,446		$	115,729			118.1	%
Operating days		26,810			24,074			11.4	%
Average revenue per operating day	$	19.78		$	13.69			44.5	%
Average direct operating costs per operating day	$	8.80		$	7.48			17.6	%
Number of owned rigs at end of period		403			397			1.5	%
Average number of rigs owned during period		403			396			1.8	%
Average rigs operating		295			265			11.3	%
Rig utilization percentage		73	%		67	%		9.0	%
Capital expenditures	$	124,909		$	74,643			67.3	%

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

21

the cost of maintenance for our rigs. Significant capital expenditures were incurred during the second quarter of 2006 to activate additional drilling rigs to meet increased demand, 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	$	36,010	$	22,025		63.5	%
Direct operating costs	$	17,935	$	12,622		42.1	%
Selling, general and administrative	$	3,152	$	2,192		43.8	%
Depreciation	$	2,330	$	1,678		38.9	%
Operating income	$	12,593	$	5,533		127.6	%
Total jobs		3,017		2,345		28.7	%
Average revenue per job	$	11.94	$	9.39		27.2	%
Average direct operating costs per job	$	5.94	$	5.38		10.4	%
Capital expenditures	$	10,652	$	7,075		50.6	%

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 expenses increased as a result of additional expenses which were necessary to support expanding the operations of the pressure pumping segment. Increased depreciation expense for 2006 was largely due to the expansion of the pressure pumping segment through capital expenditures. Significant capital expenditures were incurred during the second 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	$	59,877	$	29,587		102.4	%
Direct operating costs	$	46,049	$	23,846		93.1	%
Selling, general and administrative	$	2,592	$	2,367		9.5	%
Depreciation	$	674	$	571		18.0	%
Operating income	$	10,562	$	2,803		276.8	%
Total jobs		532		503		5.8	%
Average revenue per job	$	112.55	$	58.82		91.3	%
Average direct operating costs per job	$	86.56	$	47.41		82.6	%
Capital expenditures	$	979	$	766		27.8	%

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.

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Oil and Natural Gas Production and Exploration	2006		2005		% Change
	(Dollars in thousands, except sales prices)
Revenues	$	10,577	$	8,807		20.1	%
Direct operating costs	$	5,364	$	2,418		121.8	%
Selling, general and administrative	$	728	$	552		31.9	%
Depreciation, depletion and impairment	$	4,013	$	2,731		46.9	%
Operating income	$	472	$	3,106		(84.8	)%
Capital expenditures	$	5,856	$	3,407		71.9	%
Average net daily oil production (Bbls)		1,076		795		35.3	%
Average net daily gas production (Mcf)		5,109		7,253		(29.6	)%
Average oil sales price (per Bbl)	$	67.26	$	51.52		30.6	%
Average gas sales price (per Mcf)	$	6.78	$	6.44		5.3	%

Revenues increased primarily due to an increase in the net daily production and sales price of oil. 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 an exploratory well in the second quarter of 2006. Depreciation, depletion and impairment expense includes approximately $1.3 million and $602,000 incurred during the three months ended June 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	$	4,635	$	3,609		28.4	%
Bad debt expense	$	600	$	143		319.6	%
Depreciation	$	196	$	189		3.7	%
Other operating expenses (includes gain or loss on disposal of assets)	$	1,056	$	1,423		(25.8	)%
Embezzled funds and related expenses	$	673	$	5,156		(86.9	)%
Interest income	$	2,280	$	634		259.6	%
Interest expense	$	55	$	57		(3.5	)%
Other income	$	59	$	16		268.8	%
Capital Expenditures	$	135	$	108		25.0	%

Selling, general and administrative expenses 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 $1.1 million in gains recognized on the sale of certain assets reduced by approximately $2.6 million in charges to increase reserves related to the financial failure of a workers’ compensation insurance carrier used previously by the Company. Other operating expenses in 2006 include losses associated with the disposal of certain assets. Interest income increased as a result of higher cash balances and improvements in interest rates in 2006. Embezzled funds and related expenses 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.

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

Contract Drilling	2006			2005			% Change
	(Dollars in thousands)
Revenues	$	1,039,053		$	624,892			66.3	%
Direct operating costs	$	469,676		$	355,651			32.1	%
Selling, general and administrative	$	3,521		$	2,415			45.8	%
Depreciation	$	78,803		$	62,214			26.7	%
Operating income	$	487,053		$	204,612			138.0	%
Operating days		53,810			47,731			12.7	%
Average revenue per operating day	$	19.31		$	13.09			47.5	%
Average direct operating costs per operating day	$	8.73		$	7.45			17.2	%
Number of owned rigs at end of period		403			397			1.5	%
Average number of rigs owned during period		403			393			2.5	%
Average rigs operating		297			264			12.5	%
Rig utilization percentage		74	%		67	%		10.4	%
Capital expenditures	$	224,286		$	132,378			69.4	%

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 first half of 2006 to activate additional drilling rigs to meet increased demand, 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	$	67,338	$	38,718		73.9	%
Direct operating costs	$	35,585	$	22,986		54.8	%
Selling, general and administrative	$	6,138	$	4,394		39.7	%
Depreciation	$	4,516	$	3,250		39.0	%
Operating income	$	21,099	$	8,088		160.9	%
Total jobs		5,728		4,254		34.6	%
Average revenue per job	$	11.76	$	9.10		29.2	%
Average direct operating costs per job	$	6.21	$	5.40		15.0	%
Capital expenditures	$	19,679	$	14,733		33.6	%

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 expenses increased as a result of additional expenses which were necessary to support expanding the operations of the pressure pumping segment. Increased depreciation expense for 2006 was largely due to the

24

expansion of the pressure pumping segment through capital expenditures. Significant capital expenditures were incurred during the first half of 2006 to modify and upgrade existing equipment and to add additional equipment.

Drilling and Completion Fluids	2006		2005		% Change
	(Dollars in thousands)
Revenues	$	109,058	$	58,993		84.9	%
Direct operating costs	$	84,235	$	47,795		76.2	%
Selling, general and administrative	$	5,032	$	4,562		10.3	%
Depreciation	$	1,311	$	1,121		16.9	%
Operating income	$	18,480	$	5,515		235.1	%
Total jobs		1,019		1,030		(1.1	)%
Average revenue per job	$	107.02	$	57.27		86.9	%
Average direct operating costs per job	$	82.66	$	46.40		78.1	%
Capital expenditures	$	1,930	$	1,352		42.8	%

Revenues and direct operating costs increased 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	$	19,097	$	17,912		6.6	%
Direct operating costs	$	8,019	$	4,588		74.8	%
Selling, general and administrative	$	1,366	$	1,053		29.7	%
Depreciation, depletion and impairment	$	6,011	$	5,837		3.0	%
Operating income	$	3,701	$	6,434		(42.5	)%
Capital expenditures	$	10,717	$	8,428		27.2	%
Average net daily oil production (Bbls)		935		846		10.5	%
Average net daily gas production (Mcf)		5,070		7,922		(36.0	)%
Average oil sales price (per Bbl)	$	64.98	$	49.00		32.6	%
Average gas sales price (per Mcf)	$	7.04	$	6.16		14.3	%

Revenues increased primarily due to an increase in the net daily production and sales price of oil. 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 $3.1 million associated with the abandonment of an exploratory well in 2006. Depreciation, depletion and impairment expense includes approximately $1.3 million and $817,000 incurred during the six months ended June 30, 2006 and 2005, respectively, to impair certain oil and natural gas properties.

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Corporate and Other	2006		2005		% Change
	(In thousands)
Selling, general and administrative	$	9,594	$	7,168		33.8	%
Bad debt expense	$	1,200	$	366		227.9	%
Depreciation	$	389	$	352		10.5	%
Other operating expenses (includes gain or loss on disposal of assets)	$	185	$	1,517		(87.8	)%
Embezzled funds and related expenses	$	4,453	$	6,762		(34.1	)%
Interest income	$	4,631	$	1,067		334.0	%
Interest expense	$	113	$	123		(8.1	)%
Other income	$	143	$	20		615.0	%
Capital Expenditures	$	135	$	5,308		(97.5	)%

Selling, general and administrative expenses increased primarily as a result of compensation expense related to the adoption of a new accounting standard in the 2006 requiring the expensing of stock options. Other operating expenses in 2005 include approximately $1.0 million in gains recognized on the sale of certain oil and natural gas properties and other equipment reduced by approximately $2.6 million in charges to increase reserves related to the financial failure of a workers’ compensation insurance carrier used previously by the Company. Other operating expenses in 2006 include losses associated with the disposal of certain assets. Interest income increased as a result of higher cash balances and improvements in interest rates in 2006. Embezzled funds and related expenses 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.

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 $6.74 in the second 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 295 in the second 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 no exposure to interest rate market risk as we have no outstanding balance under our credit facility. Should we incur a balance in the future, we would have exposure associated with the floating rate of the interest charged on that balance. The revolving credit facility calls for periodic interest payments at a floating rate

26

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 LIBOR is not expected to be 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 inRules 13a-15(e) and15d-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 onForm 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 onForm 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 June 30, 2006. For a discussion of the material weaknesses, see Item 9A of our Annual Report onForm 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 ActRule 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 six 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 onForm 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 inRule 13a-15(f) under the Exchange Act.

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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 various factors and others, see “Risk Factors” included as Item 1A in our Annual Report onForm 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.

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PART II — OTHER INFORMATION

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 onForm 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 onForm 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 onForm 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference).
10	.1	Employment Agreement effective as of May 3, 2006, by and between Patterson-UTI Energy, Inc. and A. Glenn Patterson (filed May 5, 2006 as Exhibit 10.1 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended March 31, 2006 and incorporated herein by reference).
31	.1	Certification of Chief Executive Officer pursuant toRule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
31	.2	Certification of Chief Financial Officer pursuant toRule 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.

29

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)

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: August 4, 2006

30