Patterson-UTI Energy (PTEN) 10-Q 2007 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, 2007
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	(I.R.S. Employer
incorporation or organization)	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.

157,190,147 shares of common stock, $0.01 par value, as of August 2, 2007

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

			Page
PART I — FINANCIAL INFORMATION
	ITEM 1.	Financial Statements
		Unaudited consolidated balance sheets		1
		Unaudited consolidated statements of income		2
		Unaudited consolidated statement of changes in stockholders’ equity		3
		Unaudited consolidated statements of changes in cash flows		4
		Notes to unaudited consolidated financial statements		5
	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		13
	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk		21
	ITEM 4.	Controls and Procedures		21
Forward Looking Statements and Cautionary Statements for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995				22
PART II — OTHER INFORMATION
	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		23
	ITEM 4.	Submission of Matters to a Vote of Security Holders		23
	ITEM 5.	Other Information		24
	ITEM 6.	Exhibits		24
Signatures				25
Second Amended and Restated Bylaws
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 Pursuant to 18 U.S.C. Section 1350

PART I — FINANCIAL INFORMATION

ITEM 1.   Financial Statements

The following unaudited 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

CONSOLIDATED BALANCE SHEETS

(unaudited, in thousands, except share data)

	June 30,			December 31,
	2007			2006
ASSETS
Current assets:
Cash and cash equivalents	$	27,475		$	13,385
Accounts receivable, net of allowance for doubtful accounts of $8,438 at June 30, 2007 and $7,484 at December 31, 2006		393,448			484,106
Accrued federal and state income taxes receivable		—			5,448
Inventory		42,664			43,947
Deferred tax assets, net		36,504			48,868
Deposits on equipment purchase contracts		4,741			24,746
Embezzlement recovery receivable		42,500			—
Other		38,998			32,170
Total current assets		586,330			652,670
Property and equipment, net		1,688,868			1,435,804
Goodwill		96,198			99,056
Other		5,484			4,973
Total assets	$	2,376,880		$	2,192,503
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	190,129		$	138,372
Accrued revenue distributions		18,161			15,359
Other		13,099			18,424
Accrued federal and state income taxes payable		831			—
Accrued expenses		123,874			145,463
Total current liabilities		346,094			317,618
Borrowings under line of credit		15,000			120,000
Deferred tax liabilities, net		208,382			187,960
Other		4,560			4,459
Total liabilities		574,036			630,037
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 177,312,704 and 176,656,401 issued and 157,182,797 and 156,542,512 outstanding at June 30, 2007 and December 31, 2006, respectively		1,773			1,766
Additional paid-in capital		691,472			681,069
Retained earnings		1,570,507			1,346,542
Accumulated other comprehensive income		14,808			8,390
Treasury stock, at cost, 20,129,907 and 20,113,889 shares at June 30, 2007 and December 31, 2006, respectively		(475,716	)		(475,301	)
Total stockholders’ equity		1,802,844			1,562,466
Total liabilities and stockholders’ equity	$	2,376,880		$	2,192,503

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

1

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(unaudited, in thousands, except per share amounts)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Operating revenues:
Contract drilling	$	419,191		$	530,349		$	886,689		$	1,039,053
Pressure pumping		51,592			36,010			90,176			67,338
Drilling and completion fluids		39,667			59,877			70,427			109,058
Oil and natural gas		12,108			10,577			22,367			19,097
		522,558			636,813			1,069,659			1,234,546
Operating costs and expenses:
Contract drilling		228,297			235,902			474,451			469,676
Pressure pumping		25,777			17,935			46,928			35,585
Drilling and completion fluids		32,628			46,049			58,019			84,235
Oil and natural gas		2,461			5,364			5,739			8,019
Depreciation, depletion and impairment		59,947			47,481			115,878			91,030
Selling, general and administrative		16,322			12,840			30,991			25,651
Embezzlement costs (recoveries)		(41,935	)		673			(41,935	)		4,453
(Gain) loss on disposal of assets		(16,475	)		870			(16,273	)		—
Other operating expenses		400			786			1,000			1,385
		307,422			367,900			674,798			720,034
Operating income		215,136			268,913			394,861			514,512
Other income (expense):
Interest income		457			2,280			826			4,631
Interest expense		(831	)		(55	)		(1,594	)		(113	)
Other		109			59			203			143
		(265	)		2,284			(565	)		4,661
Income before income taxes and cumulative effect of change in accounting principle		214,871			271,197			394,296			519,173
Income tax expense:
Current		56,350			98,394			109,783			182,325
Deferred		18,970			1,113			29,161			6,589
		75,320			99,507			138,944			188,914
Income before cumulative effect of change in accounting principle		139,551			171,690			255,352			330,259
Cumulative effect of change in accounting principle, net of related income tax expense of $398		—			—			—			687
Net income	$	139,551		$	171,690		$	255,352		$	330,946
Income before cumulative effect of change in accounting principle:
Basic	$	0.90		$	1.02		$	1.64		$	1.94
Diluted	$	0.88		$	1.00		$	1.62		$	1.91
Net income per common share:
Basic	$	0.90		$	1.02		$	1.64		$	1.94
Diluted	$	0.88		$	1.00		$	1.62		$	1.91
Weighted average number of common shares outstanding:
Basic		155,527			168,894			155,457			170,351
Diluted		157,912			171,522			157,580			172,949

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

2

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(unaudited, in thousands)

												Accumulated
	Common Stock					Additional						Other
	Number of					Paid-in			Retained			Comprehensive		Treasury
	Shares			Amount		Capital			Earnings			Income		Stock			Total
Balance, December 31, 2006		176,656		$	1,766	$	681,069		$	1,346,542		$	8,390	$	(475,301	)	$	1,562,466
Issuance of restricted stock		576			6		(6	)		—			—		—			—
Exercise of stock options		109			1		933			—			—		—			934
Stock based compensation		—			—		8,416			—			—		—			8,416
Tax benefit for stock based compensation		—			—		1,060			—			—		—			1,060
Forfeitures of restricted shares		(28	)		—		—			—			—		—			—
Foreign currency translation adjustment, net of tax of $3,625		—			—		—			—			6,418		—			6,418
Payment of cash dividends		—			—		—			(31,387	)		—		—			(31,387	)
Purchase of treasury stock		—			—		—			—			—		(415	)		(415	)
Net income		—			—		—			255,352			—		—			255,352
Balance, June 30, 2007		177,313		$	1,773	$	691,472		$	1,570,507		$	14,808	$	(475,716	)	$	1,802,844

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

3

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS

(unaudited, in thousands)

	Six Months Ended
	June 30,
	2007			2006
Cash flows from operating activities:
Net income	$	255,352		$	330,946
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and impairment		115,878			91,030
Dry holes and abandonments		786			3,101
Provision for bad debts		1,000			1,200
Deferred income tax expense		29,161			6,987
Stock based compensation expense		8,416			6,366
Gain on disposal of assets		(16,273	)		—
Changes in operating assets and liabilities:
Accounts receivable		90,703			(86,185	)
Embezzlement recovery receivable		(42,500	)		—
Inventory and other current assets		14,352			(13,655	)
Accounts payable		6,876			10,862
Income taxes payable/receivable		6,427			(12,561	)
Accrued expenses		(18,864	)		11,959
Other liabilities		(4,730	)		2,778
Net cash provided by operating activities		446,584			352,828
Cash flows from investing activities:
Purchases of property and equipment		(325,592	)		(256,747	)
Proceeds from disposal of property and equipment		26,803			4,264
Net cash used in investing activities		(298,789	)		(252,483	)
Cash flows from financing activities:
Purchases of treasury stock		(415	)		(199,998	)
Dividends paid		(31,387	)		(20,319	)
Proceeds from exercise of stock options		934			1,261
Tax benefit related to stock-based compensation		1,060			845
Proceeds from borrowings under line of credit		82,500			—
Repayment of borrowings under line of credit		(187,500	)		—
Net cash used in financing activities		(134,808	)		(218,211	)
Effect of foreign exchange rate changes on cash		1,103			460
Net increase (decrease) in cash and cash equivalents		14,090			(117,406	)
Cash and cash equivalents at beginning of period		13,385			136,398
Cash and cash equivalents at end of period	$	27,475		$	18,992
Supplemental disclosure of cash flow information:
Net cash paid during the period for:
Interest expense	$	1,194		$	113
Income taxes	$	96,759		$	184,501

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

4

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1.   Basis of Consolidation and Presentation

The interim unaudited 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 Company has no controlling financial interests in any entity that is not a wholly-owned subsidiary which would require consolidation.

The interim 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 Consolidated Balance Sheet as of December 31, 2006, as presented herein, was derived from the audited balance sheet of the Company. These unaudited 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, 2006.

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 Consolidated Financial Statements).

The Company provides a dual presentation of its net income per common share in its Unaudited 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 unrestricted common shares outstanding during the period. 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. The following table presents information necessary to calculate net income per share for the three and six months ended June 30, 2007 and 2006 as well as cash dividends per share paid and potentially dilutive securities excluded from the weighted average number of diluted common shares outstanding, as their inclusion would have been anti-dilutive during the three and six months ended June 30, 2007 and 2006 (in thousands, except per share amounts):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
Net income	$	139,551	$	171,690	$	255,352	$	330,946
Weighted average number of unrestricted common shares outstanding		155,527		168,894		155,457		170,351
Basic net income per common share	$	0.90	$	1.02	$	1.64	$	1.94
Weighted average number of unrestricted common shares outstanding		155,527		168,894		155,457		170,351
Dilutive effect of stock options and restricted shares		2,385		2,628		2,123		2,598
Weighted average number of diluted common shares outstanding		157,912		171,522		157,580		172,949
Diluted net income per common share	$	0.88	$	1.00	$	1.62	$	1.91
Cash dividends paid per common share	$	0.12	$	0.08	$	0.20	$	0.12
Potentially dilutive securities excluded as anti-dilutive		1,785		—		2,435		—

5

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The results of operations for the six months ended June 30, 2007 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. 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) in 2006, 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.

Stock Options.  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). 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 six month periods ended June 30, 2007 and 2006 follow:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2007			2006		2007			2006
Volatility		36.36	%		N/A		36.38	%		26.95	%
Expected term (in years)		4.00			N/A		4.00			4.00
Dividend yield		2.00	%		N/A		1.96	%		0.47	%
Risk-free interest rate		4.56	%		N/A		4.56	%		4.30	%

Stock option activity from January 1, 2007 to June 30, 2007 follows:

				Weighted-
				Average
	Underlying			Exercise
	Shares			Price
Outstanding at January 1, 2007		6,575,096		$	16.18
Granted		1,035,000		$	23.94
Exercised		(108,578	)	$	8.60
Forfeited		(1,333	)	$	14.64
Expired		—		$	—
Cancelled		—		$	—
Outstanding at June 30, 2007		7,500,185		$	17.36
Exercisable at June 30, 2007		5,547,051		$	14.48

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

6

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

nonvested restricted shares. Additionally, certain restricted stock awards contain performance conditions related to the Company’s net income.

Restricted stock activity from January 1, 2007 to June 30, 2007 follows:

				Weighted
				Average
				Grant Date
	Shares			Fair Value
Nonvested at January 1, 2007		1,188,200		$	25.92
Granted		576,150		$	24.71
Vested		(181,925	)	$	19.00
Forfeited		(28,425	)	$	24.68
Nonvested at June 30, 2007		1,554,000		$	26.31

3.   Comprehensive Income

The following table illustrates the Company’s comprehensive income including the effects of foreign currency translation adjustments for the three and six months ended June 30, 2007 and 2006 (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
Net income	$	139,551	$	171,690	$	255,352	$	330,946
Other comprehensive income:
Foreign currency translation adjustment related to Canadian operations, net of tax		5,770		2,703		6,418		2,538
Comprehensive income, net of tax	$	145,321	$	174,393	$	261,770	$	333,484

4.   Property and Equipment

Property and equipment consisted of the following at June 30, 2007 and December 31, 2006 (in thousands):

	June 30,			December 31,
	2007			2006
Equipment	$	2,485,203		$	2,135,567
Oil and natural gas properties		80,174			85,143
Buildings		37,217			30,987
Land		10,117			7,507
		2,612,711			2,259,204
Less accumulated depreciation and depletion		(923,843	)		(823,400	)
Property and equipment, net	$	1,688,868		$	1,435,804

7

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

5.   Business Segments

The Company’s 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 operating decision maker 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,
	2007			2006			2007			2006
Revenues:
Contract drilling(a)	$	420,285		$	531,904		$	888,624		$	1,041,668
Pressure pumping		51,592			36,010			90,176			67,338
Drilling and completion fluids(b)		39,702			60,098			70,583			109,322
Oil and natural gas		12,108			10,577			22,367			19,097
Total segment revenues		523,687			638,589			1,071,750			1,237,425
Elimination of intercompany revenues(a)(b)		1,129			1,776			2,091			2,879
Total revenues	$	522,558		$	636,813		$	1,069,659		$	1,234,546
Income before income taxes:
Contract drilling	$	137,712		$	252,446		$	309,417		$	487,053
Pressure pumping		17,599			12,593			27,840			21,099
Drilling and completion fluids		3,906			10,562			6,182			18,480
Oil and natural gas		5,116			472			7,729			3,701
		164,333			276,073			351,168			530,333
Corporate and other		(7,607	)		(5,617	)		(14,515	)		(11,368	)
Embezzlement (costs) recoveries(c)		41,935			(673	)		41,935			(4,453	)
Gain (loss) on disposal of assets(d)		16,475			(870	)		16,273			—
Interest income		457			2,280			826			4,631
Interest expense		(831	)		(55	)		(1,594	)		(113	)
Other		109			59			203			143
Income before income taxes and cumulative effect of change in accounting principle	$	214,871		$	271,197		$	394,296		$	519,173

8

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	June 30,		December 31,
	2007		2006
Identifiable assets:
Contract drilling	$	1,984,381	$	1,849,923
Pressure pumping		147,581		111,787
Drilling and completion fluids		105,166		106,032
Oil and natural gas		62,856		65,443
		2,299,984		2,133,185
Corporate and other(e)		76,896		59,318
Total assets	$	2,376,880	$	2,192,503

(a)	Includes contract drilling intercompany revenues of approximately $1.1 million and $1.6 million for the three months ended June 30, 2007 and 2006, respectively. Includes contract drilling intercompany revenues of approximately $1.9 million and $2.6 million for the six months ended June 30, 2007 and 2006, respectively.
(b)	Includes drilling and completion fluids intercompany revenues of approximately $35,000 and $221,000 for the three months ended June 30, 2007 and 2006, respectively. Includes drilling and completion fluids intercompany revenues of approximately $156,000 and $264,000 for the six months ended June 30, 2007 and 2006, 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 from the Company. The Company expects to recover approximately $42.5 million in assets that have been seized from the former CFO and companies that he controlled by a court-appointed receiver. Embezzlement (costs) recoveries includes the recognition of this recovery, net of professional and other costs incurred as a result of the embezzlement.
(d)	Gains or losses associated with the disposal of assets relate to decisions of the executive management group regarding corporate strategy. Accordingly, the related gains or losses have been separately presented and excluded from the results of specific segments.
(e)	Corporate assets primarily include cash, embezzlement recovery receivable and certain deferred federal income tax assets.

9

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2006 the Company performed its annual goodwill evaluation and determined no adjustment to impair goodwill was necessary. Goodwill as of June 30, 2007 is as follows (in thousands):

	June 30,
	2007
Contract Drilling:
Goodwill at beginning of year	$	89,092
Changes to goodwill		(2,858	)
Goodwill at end of period		86,234
Drilling and completion fluids:
Goodwill at beginning of year		9,964
Changes to goodwill		—
Goodwill at end of period		9,964
Total goodwill	$	96,198

In connection with the implementation of FIN 48 as of January 1, 2007 as discussed in Note 12 of these Unaudited Consolidated Financial Statements, the Company determined that a tax reserve which had been established in connection with a business acquisition should be reduced. This reserve had originally been established in connection with the allocation of the purchase price in the transaction and was reflected as an increase in goodwill. The $2.9 million reduction of this reserve was reflected as a reduction to goodwill upon the adoption of FIN 48.

7.   Accrued Expenses

Accrued expenses consisted of the following at June 30, 2007 and December 31, 2006 (in thousands):

	June 30,		December 31,
	2007		2006
Salaries, wages, payroll taxes and benefits	$	27,633	$	42,751
Workers’ compensation liability		65,281		67,615
Sales, use and other taxes		9,489		11,043
Insurance, other than workers’ compensation		15,927		13,328
Other		5,544		10,726
Accrued expenses	$	123,874	$	145,463

10

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

8.   Asset Retirement Obligation

Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” 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 the Company’s asset retirement obligations during the six months ended June 30, 2007 and 2006 (in thousands):

	2007			2006
Balance at beginning of year	$	1,829		$	1,725
Liabilities incurred		151			63
Liabilities settled		(632	)		(45	)
Accretion expense		31			27
Revision in estimated cash flows		289			—
Asset retirement obligation at end of period	$	1,668		$	1,770

9.   Borrowings Under Line of Credit

The Company entered into a five-year unsecured revolving line of credit (“LOC”) in December 2004. On August 2, 2006, the Company amended the LOC and increased the borrowing capacity to $375 million. Interest is paid on outstanding LOC balances at a floating rate ranging from LIBOR plus 0.625% to 1.0% or the prime rate. Any outstanding borrowings must be repaid at maturity on December 16, 2009. This arrangement includes various fees, including a commitment fee on the average daily unused amount (0.15% at June 30, 2007). There are customary restrictions and covenants associated with the LOC. Financial covenants provide for a maximum debt to capitalization ratio and a minimum interest coverage ratio. The Company does not expect that the restrictions and covenants will impact its ability to operate or react to opportunities that might arise. As of June 30, 2007, the Company had $15.0 million in borrowings outstanding under the LOC and $60.3 million in letters of credit were outstanding. As a result, the Company had available borrowing capacity of approximately $300 million at June 30, 2007. The weighted average interest rate on outstanding borrowings at June 30, 2007 was 8.25%.

10.   Commitments, Contingencies and Other Matters

Commitments —The Company maintains letters of credit in the aggregate amount of $60.3 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 are typically renewed annually. No amounts have been drawn under the letters of credit.

As of June 30, 2007, the Company has signed non-cancelable commitments to purchase approximately $175 million of equipment. This amount excludes $4.7 million and $24.7 million at June 30, 2007 and December 31, 2006, respectively, related to deposits that have been paid pursuant to agreements that were entered into to purchase rig components to be used in the construction of 15 new land drilling rigs. These payments are presented as Deposits on equipment purchase contracts in the Company’s unaudited consolidated balance sheets.

Contingencies —A receiver was appointed to take control of and liquidate the assets of the Company’s former CFO in connection with his embezzlement of Company funds. In May 2007, the court approved a plan of distribution of the assets that had been recovered by the receiver. The Company expects to recover approximately $42.5 million pursuant to the approved plan and has recognized this recovery in the Company’s unaudited consolidated statement of income in the second quarter of 2007, net of additional professional fees associated with the embezzlement. Cash payments from the receiver of approximately $39.1 million were received in July 2007, with the remaining $3.4 million of the recovery consisting of notes receivable, investments and other assets that will be transferred to the Company.

11

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company is party to various 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, results of operations or cash flows.

11.   Stockholders’ Equity

Cash Dividends —The Company has paid cash dividends during the six months ended June 30, 2007 as follows:

	Per Share		Total
			(In thousands)
Paid on March 30, 2007 to shareholders of record as of March 15, 2007	$	0.08	$	12,527
Paid on June 29, 2007 to shareholders of record as of June 14, 2007		0.12		18,860
Total cash dividends	$	0.20	$	31,387

On August 1, 2007, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.12 per share to be paid on September 28, 2007 to holders of record as of September 12, 2007. 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.

The Company purchased 16,018 shares of treasury stock during the six months ended June 30, 2007. Shares were purchased from employees at fair market value upon the vesting of restricted stock to provide the respective employees with the funds necessary to satisfy their respective tax withholding obligations. The total purchase price for these shares was approximately $415,000.

On August 1, 2007, the Company’s Board of Directors approved a stock buyback program, authorizing purchases of up to $250 million of the Company’s common stock in open market or privately negotiated transactions.

12.   Income Taxes

The Company adopted FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109(“FIN 48”) on January 1, 2007. 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. As a result of the adoption of FIN 48 the Company reduced a reserve for an uncertain tax position with respect to a business combination that had originally been recorded as goodwill (see Note 6). The impact of adjustments to reserves with respect to other uncertain tax positions was not material. In connection with the adoption of FIN 48, the Company established a policy to account for interest and penalties with respect to income taxes as operating expenses. As of June 30, 2007, the years ended December 31, 2003 through 2006 are open for examination by U.S. taxing authorities. As of June 30, 2007, the years ended December 31, 2000 through 2006 are open for examination by Canadian taxing authorities.

13.   Recently Issued Accounting Standards

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 beginning in the quarter ending March 31, 2008. The application of FAS 157 is not expected to have a material impact to the Company.

In February 2007, the FASB issued Statement No. 159,The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115(“FAS 159”). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value. FAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007 and will be effective for the Company beginning in the quarter ending March 31, 2008. The application of FAS 159 is not expected to have a material impact to the Company.

12

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, 2007 and 2006, our operating revenues consisted of the following (dollars in thousands):

	Three Months Ended June 30,								Six Months Ended June 30,
	2007				2006				2007				2006
Contract drilling	$	419,191	80	%	$	530,349	83	%	$	886,689	83	%	$	1,039,053	84	%
Pressure pumping		51,592	10			36,010	6			90,176	8			67,338	5
Drilling and completion fluids		39,667	8			59,877	9			70,427	7			109,058	9
Oil and natural gas		12,108	2			10,577	2			22,367	2			19,097	2
	$	522,558	100	%	$	636,813	100	%	$	1,069,659	100	%	$	1,234,546	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, Pennsylvania 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.

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 2007, our average number of rigs operating was 237 per day compared to 255 in the first quarter of 2007 and 295 in the second quarter of 2006. Our average revenue per operating day decreased to $19,410 in the second quarter of 2007 from $20,350 in the first quarter of 2007 and $19,780 in the second quarter of 2006. Our consolidated net income for the second quarter of 2007 decreased by $32.1 million or 19% as compared to the second quarter of 2006. Included in consolidated net income for the second quarter of 2007 was a pre-tax gain of approximately $41.9 million associated with the expected recovery of embezzled funds and approximately $16.4 million in net pre-tax gains from the sale of certain oil and natural gas properties and the disposal of certain other assets. Excluding the above-mentioned gains, our consolidated net income for the second quarter of 2007 would have been approximately $102 million, which is a decrease of approximately $70.1 million or 41% as compared to the second quarter of 2006. This decrease was primarily due to our contract drilling segment experiencing an increase in the average costs per operating day, a decrease in the average revenue per operating day and a decrease in the average number of rigs operating in the second quarter of 2007 as compared to the second quarter of 2006.

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 a decrease in the number of rigs operating and 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, 2006.

We believe that the liquidity presented in our balance sheet as of June 30, 2007, which includes approximately $240 million in working capital (including $27.5 million in cash) and $300 million available under a $375 million line of credit, provides us with the ability to pursue acquisition opportunities, expand into new regions, make improvements to our assets, pay cash dividends and survive downturns in our industry.

13

Commitments and Contingencies — The Company maintains letters of credit in the aggregate amount of $60.3 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, 2007, we have remaining non-cancelable commitments to purchase approximately $175 million of equipment.

A receiver has been appointed to take control of and liquidate the assets of our former CFO in connection with his embezzlement of Company funds. In May 2007, the court approved a plan of distribution of the assets that had been recovered by the receiver. We expect to recover approximately $42.5 million pursuant to the approved plan and have recognized this recovery in our unaudited consolidated statement of income in the second quarter of 2007, net of additional professional fees associated with the embezzlement. Cash payments from the receiver of approximately $39.1 million were received in July 2007, with the remaining $3.4 million of the recovery consisting of notes receivable, investments and other assets that are expected to be transferred to us.

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, Pennsylvania and Western Canada. We have approximately 345 currently marketable land-based 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 high 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

•  construction of new 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, 2006.

14

Liquidity and Capital Resources

As of June 30, 2007, we had working capital of approximately $240 million including cash and cash equivalents of $27.5 million. For the six months ended June 30, 2007, our significant sources of cash flow included:

•  $447 million provided by operations,

•  $26.8 million in proceeds from disposal of property and equipment, and

•  $2.0 million from the exercise of stock options and related tax benefits associated with stock-based compensation.

We used $31.4 million to pay dividends on the Company’s common stock, $105 million to repay borrowings under our line of credit and $326 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.

As of June 30, 2007, we had $15.0 million in borrowings outstanding under our $375 million revolving line of credit and $60.3 million in letters of credit were outstanding such that we had available borrowing capacity of approximately $300 million at June 30, 2007.

We paid cash dividends during the six months ended June 30, 2007 as follows:

	Per Share		Total
			(In thousands)
Paid on March 30, 2007 to shareholders of record as of March 15, 2007	$	0.08	$	12,527
Paid on June 29, 2007 to shareholders of record as of June 14, 2007		0.12		18,860
Total cash dividends	$	0.20	$	31,387

On August 1, 2007, our Board of Directors approved a cash dividend on our common stock in the amount of $0.12 per share to be paid on September 28, 2007 to holders of record as of September 12, 2007. 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 our credit facilities and other factors.

On August 1, 2007, our Board of Directors approved a stock buyback program, authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions.

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.

15

Results of Operations

The following tables summarize operations by business segment for the three months ended June 30, 2007 and 2006:

Contract Drilling	2007		2006		% Change
	(Dollars in thousands)
Revenues	$	419,191	$	530,349		(21.0	)%
Direct operating costs	$	228,297	$	235,902		(3.2	)%
Selling, general and administrative	$	1,400	$	1,733		(19.2	)%
Depreciation	$	51,782	$	40,268		28.6	%
Operating income	$	137,712	$	252,446		(45.4	)%
Operating days		21,597		26,810		(19.4	)%
Average revenue per operating day	$	19.41	$	19.78		(1.9	)%
Average direct operating costs per operating day	$	10.57	$	8.80		20.1	%
Average rigs operating		237		295		(19.7	)%
Capital expenditures	$	129,913	$	124,909		4.0	%

Demand for our contract drilling services is dependent upon the prevailing prices for natural gas. The average market price of natural gas fell from $8.98 per Mcf in 2005 to $6.94 per Mcf in 2006. This decrease resulted in our customers reducing their drilling activities beginning in the fourth quarter of 2006 and continuing into 2007. As a result of the decrease in drilling activities by our customers, our average rigs operating declined to 237 in the second quarter of 2007 compared to 255 in the first quarter of 2007 and 295 in the second quarter of 2006.

Revenues in the second quarter of 2007 decreased as compared to the second quarter of 2006 as a result of the decreased number of operating days in 2007 and a decrease of approximately $370 in the average revenue per operating day. The increase in average direct operating costs per day of approximately $1,770 resulted primarily from increased compensation costs and an increase in the cost of maintenance for our drilling rigs, partially caused by costs relating to the deactivating of drilling rigs. Selling, general and administrative expense decreased primarily as a result of the transfer of administrative staff to our corporate segment. Significant capital expenditures have been incurred to activate additional drilling rigs, to modify and upgrade our 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 the capital expenditures discussed above.

Pressure Pumping	2007		2006		% Change
	(Dollars in thousands)
Revenues	$	51,592	$	36,010		43.3	%
Direct operating costs	$	25,777	$	17,935		43.7	%
Selling, general and administrative	$	4,808	$	3,152		52.5	%
Depreciation	$	3,408	$	2,330		46.3	%
Operating income	$	17,599	$	12,593		39.8	%
Total jobs		3,573		3,017		18.4	%
Average revenue per job	$	14.44	$	11.94		20.9	%
Average direct operating costs per job	$	7.21	$	5.94		21.4	%
Capital expenditures	$	14,206	$	10,652		33.4	%

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 costs per job. The increase in jobs was attributable to increased demand for our services and increased operating capacity. 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 primarily as a result of additional expenses to support the expanding operations of the pressure pumping segment. Significant capital expenditures

16

have been incurred to add capacity, expand our areas of operation and modify and upgrade existing equipment. The increase in depreciation expense was a result of the capital expenditures discussed above.

Drilling and Completion Fluids	2007		2006		% Change
	(Dollars in thousands)
Revenues	$	39,667	$	59,877		(33.8	)%
Direct operating costs	$	32,628	$	46,049		(29.1	)%
Selling, general and administrative	$	2,436	$	2,592		(6.0	)%
Depreciation	$	697	$	674		3.4	%
Operating income	$	3,906	$	10,562		(63.0	)%
Total jobs		434		532		(18.4	)%
Average revenue per job	$	91.40	$	112.55		(18.8	)%
Average direct operating costs per job	$	75.18	$	86.56		(13.1	)%
Capital expenditures	$	1,023	$	979		4.5	%

Revenues and direct operating costs decreased primarily as a result of decreases 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 decreased primarily as a result of a decrease in the number of large jobs offshore in the Gulf of Mexico.

Oil and Natural Gas Production and Exploration	2007		2006		% Change
	(Dollars in thousands, except sales prices)
Revenues	$	12,108	$	10,577		14.5	%
Direct operating costs	$	2,461	$	5,364		(54.1	)%
Selling, general and administrative	$	674	$	728		(7.4	)%
Depreciation, depletion and impairment	$	3,857	$	4,013		(3.9	)%
Operating income	$	5,116	$	472		983.9	%
Capital expenditures	$	4,619	$	5,856		(21.1	)%
Average net daily oil production (Bbls)		1,107		1,076		2.9	%
Average net daily gas production (Mcf)		6,444		5,109		26.1	%
Average oil sales price (per Bbl)	$	63.04	$	67.26		(6.3	)%
Average natural gas sales price (per Mcf)	$	7.84	$	6.78		15.6	%

Revenues increased primarily due to an increase in the net daily production of natural gas and an increase in the average sales price of natural gas. Average net daily oil and natural gas production increased primarily due to the completion of wells subsequent to the second quarter of 2006, partially offset by production declines in existing wells and by the sale of certain properties in 2007. The decrease in direct operating costs is primarily due to a decrease of approximately $3.0 million in costs associated with the abandonment of exploratory wells. Depreciation, depletion and impairment expense in the second quarter of 2007 includes approximately $534,000 incurred to impair certain oil and natural gas properties compared to approximately $1.3 million incurred to impair certain oil and natural gas properties in the second quarter of 2006.

Corporate and Other	2007			2006		% Change
	(Dollars in thousands)
Selling, general and administrative	$	7,004		$	4,635		51.1	%
Depreciation	$	203		$	196		3.6	%
Other operating expenses	$	400		$	786		(49.1	)%
(Gain) loss on disposal of assets	$	(16,475	)	$	870		N/A	%
Embezzlement costs (recoveries)	$	(41,935	)	$	673		N/A	%
Interest income	$	457		$	2,280		(80.0	)%
Interest expense	$	831		$	55		N/A	%
Other income	$	109		$	59		84.7	%
Capital expenditures	$	—		$	135		(100.0	)%

17

Selling, general and administrative expense increased primarily as a result of compensation expense related to transfers of administrative staff to our corporate segment as well as increases in stock-based compensation expense and professional fees. In the second quarter of 2007 we sold certain oil and natural gas properties resulting in a gain of $20.3 million. This gain was reduced by approximately $3.8 million in losses associated with the disposal of other assets. Gains and losses on the disposal of assets are considered as part of our corporate activities due to the fact that such transactions relate to decisions of the executive management group regarding corporate strategy. Embezzlement costs (recoveries) in the second quarter of 2007 includes an expected recovery of $42.5 million, reduced by approximately $600,000 in additional professional and other costs incurred as a result of the embezzlement. Embezzlement costs (recoveries) in the second quarter of 2006 include professional and other costs incurred as a result of the embezzlement. Interest income decreased due to the decrease in cash available to invest. During 2006, we repurchased $450 million of our common stock. Interest expense in 2007 increased primarily due to higher average borrowings that were outstanding under our line of credit during the second quarter of 2007.

The following tables summarize operations by business segment for the six months ended June 30, 2007 and 2006:

Contract Drilling	2007		2006		% Change
	(Dollars in thousands)
Revenues	$	886,689	$	1,039,053		(14.7	)%
Direct operating costs	$	474,451	$	469,676		1.0	%
Selling, general and administrative	$	2,851	$	3,521		(19.0	)%
Depreciation	$	99,970	$	78,803		26.9	%
Operating income	$	309,417	$	487,053		(36.5	)%
Operating days		44,569		53,810		(17.1	)%
Average revenue per operating day	$	19.89	$	19.31		3.0	%
Average direct operating costs per operating day	$	10.65	$	8.73		22.0	%
Average rigs operating		246		297		(17.2	)%
Capital expenditures	$	283,189	$	224,286		26.3	%

Revenues in the first six months of 2007 decreased as compared to the first six months of 2006 as a result of the decreased number of operating days in 2007, partially offset by an increase of approximately $580 in the average revenue per operating day. Although the number of operating days decreased in 2007, direct operating costs increased due to an increase in average direct operating costs per operating day of approximately $1,920. The increase in average direct operating costs per day primarily resulted from increased compensation costs and an increase in the cost of maintenance for our drilling rigs, partially caused by costs relating to the deactivating of drilling rigs. Selling, general and administrative expense decreased primarily as a result of the transfer of administrative staff to our corporate segment. Significant capital expenditures have been incurred to activate additional drilling rigs, to modify and upgrade our 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 the capital expenditures discussed above.

Pressure Pumping	2007		2006		% Change
	(Dollars in thousands)
Revenues	$	90,176	$	67,338		33.9	%
Direct operating costs	$	46,928	$	35,585		31.9	%
Selling, general and administrative	$	8,876	$	6,138		44.6	%
Depreciation	$	6,532	$	4,516		44.6	%
Operating income	$	27,840	$	21,099		31.9	%
Total jobs		6,412		5,728		11.9	%
Average revenue per job	$	14.06	$	11.76		19.6	%
Average direct operating costs per job	$	7.32	$	6.21		17.9	%
Capital expenditures	$	30,631	$	19,679		55.7	%

18

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 costs per job. The increase in jobs was attributable to increased demand for our services and increased operating capacity. 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 primarily as a result of additional expenses to support the expanding operations of the pressure pumping segment. Significant capital expenditures have been incurred to add capacity, expand our areas of operation and modify and upgrade existing equipment. The increase in depreciation expense was a result of the capital expenditures discussed above.

Drilling and Completion Fluids	2007		2006		% Change
	(Dollars in thousands)
Revenues	$	70,427	$	109,058		(35.4	)%
Direct operating costs	$	58,019	$	84,235		(31.1	)%
Selling, general and administrative	$	4,833	$	5,032		(4.0	)%
Depreciation	$	1,393	$	1,311		6.3	%
Operating income	$	6,182	$	18,480		(66.5	)%
Total jobs		869		1,019		(14.7	)%
Average revenue per job	$	81.04	$	107.02		(24.3	)%
Average direct operating costs per job	$	66.77	$	82.66		(19.2	)%
Capital expenditures	$	2,121	$	1,930		9.9	%

Revenues and direct operating costs decreased primarily as a result of decreases 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 decreased primarily as a result of a decrease in the number of large jobs offshore in the Gulf of Mexico.

Oil and Natural Gas Production and Exploration	2007		2006		% Change
	(Dollars in thousands, except sales prices)
Revenues	$	22,367	$	19,097		17.1	%
Direct operating costs	$	5,739	$	8,019		(28.4	)%
Selling, general and administrative	$	1,322	$	1,366		(3.2	)%
Depreciation, depletion and impairment	$	7,577	$	6,011		26.1	%
Operating income	$	7,729	$	3,701		108.8	%
Capital expenditures	$	9,651	$	10,717		(9.9	)%
Average net daily oil production (Bbls)		1,104		935		18.1	%
Average net daily gas production (Mcf)		5,944		5,070		17.2	%
Average oil sales price (per Bbl)	$	59.69	$	64.98		(8.1	)%
Average natural gas sales price (per Mcf)	$	7.53	$	7.04		7.0	%

Revenues increased due to increases in the net daily production of oil and natural gas and an increase in the average sales price of natural gas which was partially offset by a reduction in the average sales price of oil. Average net daily oil and natural gas production increased primarily due to the completion of wells subsequent to the second quarter of 2006, partially offset by production declines in existing wells and by the sale of certain properties in 2007. Direct operating costs decreased due primarily to a decrease of approximately $2.3 million in costs associated with the abandonment of exploratory wells. Depreciation, depletion and impairment expense increased due to the increases in net daily production of oil and natural gas.

19

Corporate and Other	2007			2006		% Change
	(Dollars in thousands)
Selling, general and administrative	$	13,109		$	9,594		36.6	%
Depreciation	$	406		$	389		4.4	%
Other operating expenses	$	1,000		$	1,385		(27.8	)%
Gain on disposal of assets	$	(16,273	)	$	—		N/A	%
Embezzlement costs (recoveries)	$	(41,935	)	$	4,453		N/A	%
Interest income	$	826		$	4,631		(82.2	)%
Interest expense	$	1,594		$	113		N/A	%
Other income	$	203		$	143		42.0	%
Capital expenditures	$	—		$	135		(100.0	)%

Selling, general and administrative expense increased primarily as a result of compensation expense related to transfers of administrative staff to our corporate segment as well as increases in stock-based compensation expense and professional fees. In 2007 we sold certain oil and natural gas properties resulting in a gain of $20.3 million. This gain was reduced by approximately $4.1 million in losses associated with the disposal of other assets. Gains and losses on the disposal of assets are considered as part of our corporate activities due to the fact that such transactions relate to decisions of the executive management group regarding corporate strategy. Embezzlement costs (recoveries) in 2007 includes an expected recovery of $42.5 million reduced by approximately $600,000 in additional professional and other costs incurred as a result of the embezzlement. Embezzlement costs (recoveries) in 2006 include professional and other costs incurred as a result of the embezzlement. Interest income decreased due to the decrease in cash available to invest from 2006 to 2007. Interest expense in 2007 increased primarily due to higher average borrowings that were outstanding under our line of credit during 2007.

Recently Issued Accounting Standards

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 us beginning in the quarter ending March 31, 2008. The application of FAS 157 is not expected to have a material impact to us.

In February 2007, the FASB issued Statement No. 159,The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115(“FAS 159”). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value. FAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007 and will be effective for us beginning in the quarter ending March 31, 2008. The application of FAS 159 is not expected to have a material impact to us.

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. During 2006, the average market price of natural gas retreated from record highs that were set in 2005. The price dropped to an average of $6.94 per Mcf for the full year of 2006 compared to $8.98 per Mcf for the full year of 2005. This decrease resulted in our customers reducing their drilling activities beginning in the fourth quarter of 2006 and continuing into 2007. As a result of this decrease in drilling activities by our customers, our average rigs operating have declined to 237 in the second quarter of 2007 compared to 255 in the first quarter of 2007 and 290 in the fourth quarter of 2006. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. A significant

20

decrease in market prices for natural gas could result in a material decrease in demand for drilling rigs and reduction in our operation results.

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. This currency rate risk is not material to our results of operations or financial condition.

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, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2007.

Changes in Internal Control Over Financial Reporting — There were no changes in our internal control over financial reporting during our most recently completed fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting, as defined inRule 13a-15(f) under the Exchange Act.

21

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 Part I 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 onForm 10-K for the year ended December 31, 2006, beginning on page 10.

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.

22

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 us during the quarter ended June 30, 2007.

							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		thousands)(2)
April 1-30, 2007		—	$	—		—	$	—
May 1-31, 2007		—	$	—		—	$	—
June 1-30, 2007		16,018	$	25.95		—	$	—
Total		16,018	$	25.95		—	$	—

(1)	Represents shares purchased from employees on June 9, 2007 to provide the respective employees with the funds necessary to satisfy their tax withholding obligations with respect to the vesting of restricted shares on that date. The price paid per share represents the closing price of our common stock on June 8, 2007.
(2)	On August 1, 2007, our Board of Directors approved a stock buyback program authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions.

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

On June 7, 2007, the Company held its Annual Meeting of Stockholders. At the meeting, the stockholders voted on the following matters:

1. The election of seven persons to serve as directors of the Company.

2. Ratification of the appointment of PricewaterhouseCoopers LLP as the independent registered public accounting firm of the Company for the fiscal year ending December 31, 2007.

The seven nominees to the Board of Directors of the Company were elected at the meeting, and the other proposal received the affirmative vote required for approval. The voting results were as follows:

1. Election of Directors	Votes For		Votes Withheld
Mark S. Siegel		130,898,755		3,158,393
Cloyce A. Talbott		131,379,433		2,677,715
Kenneth N. Berns		126,257,416		7,799,732
Charles O. Buckner		133,306,445		750,703
Curtis W. Huff		133,273,715		783,433
Terry H. Hunt		128,661,402		5,395,746
Kenneth R. Peak		133,141,175		915,973

			Votes				Broker
	Votes For		Against		Abstentions		Non-votes
2. Ratification of PricewaterhouseCoopers LLP as the Company’s independent registered public accounting firm		133,664,121		276,006		117,021		0

23

ITEM 5.   Other Information

On August 1, 2007, the Board of Directors approved and adopted the Second Amended and Restated Bylaws of the Company, which amended the Amended and Restated Bylaws of the Company to provide that the Company may, in accordance with the General Corporation Law of the State of Delaware, issue both certificated and uncertificated shares of its stock. The Board of Directors approved the amendments in connection with recent rules promulgated by the Nasdaq Stock Market. A copy of the Second Amended and Restated Bylaws is attached hereto as Exhibit 3.3.

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	Second Amended and Restated Bylaws.
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.

24

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 and Treasurer

DATED: August 6, 2007

25