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, 2005

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
(Address of principal executive offices)       (Zip Code)

(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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes þ       No o

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

171,706,441 shares of common stock, $0.01 par value, as of July 28, 2005

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

PART I — Financial Information	Page
ITEM 1. Financial Statements
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		16
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		24
ITEM 4. Controls and Procedures		24
Forward Looking Statements and Cautionary Statements for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995		25
PART II — Other Information
ITEM 4. Submission of Matters to a Vote of Security Holders		26
ITEM 6. Exhibits		26
Signatures		28
Certification of CEO Pursuant to Rule 13a-14(a)15d-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)15d-14(a)
Certification of CEO & 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 (Unaudited)
(in thousands, except share data)

	June 30,			December 31,
	2005			2004
ASSETS
Current assets:
Cash and cash equivalents	$	70,077		$	112,371
Accounts receivable, net of allowance for doubtful accounts of $2,859 at June 30, 2005 and $1,909 at December 31, 2004		298,802			214,097
Inventory		21,920			17,738
Deferred tax assets, net		17,919			15,991
Other		28,401			26,836
Total current assets		437,119			387,033
Property and equipment, at cost, net		973,938			828,875
Goodwill		101,326			101,326
Other		5,135			5,677
Total assets	$	1,517,518		$	1,322,911
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	58,717		$	54,553
Accrued revenue distributions		11,388			11,297
Other		3,816			2,309
Accrued federal and state income taxes payable		10,278			2,754
Accrued expenses		85,280			79,163
Total current liabilities		169,479			150,076
Deferred tax liabilities, net		169,809			162,040
Other		4,351			3,256
Total liabilities		343,639			315,372
Commitments and contingencies		—			—
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 174,734,503 and 171,625,841 issued and 171,621,407 and 168,512,745 outstanding at June 30, 2005 and December 31, 2004, respectively		1,748			1,716
Additional paid-in capital		651,615			597,280
Deferred compensation		(12,095	)		(5,420	)
Retained earnings		539,365			415,489
Accumulated other comprehensive income		6,383			11,611
Treasury stock, at cost, 3,113,096 shares respectively		(13,137	)		(13,137	)
Total stockholders’ equity		1,173,879			1,007,539
Total liabilities and stockholders’ equity	$	1,517,518		$	1,322,911

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 (Unaudited)
(in thousands, except per share amounts)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
Operating revenues:
Contract drilling	$	329,503		$	188,222		$	624,892		$	367,397
Pressure pumping		22,025			14,577			38,718			28,827
Drilling and completion fluids		29,587			23,424			58,993			41,563
Oil and natural gas		8,807			8,287			17,912			15,502
		389,922			234,510			740,515			453,289
Operating costs and expenses:
Contract drilling		180,185			134,387			355,651			262,378
Pressure pumping		12,622			8,328			22,986			16,416
Drilling and completion fluids		23,846			19,837			47,795			35,476
Oil and natural gas		2,418			2,768			4,588			4,336
Depreciation, depletion and impairment		36,959			30,451			71,359			57,734
Selling, general and administrative		9,925			7,910			19,604			14,708
Bad debt expense		143			217			366			307
Other		1,408			(187	)		1,498			(1,375	)
		267,506			203,711			523,847			389,980
Operating income		122,416			30,799			216,668			63,309
Other income (expense):
Interest income		634			204			1,067			455
Interest expense		(57	)		(54	)		(123	)		(130	)
Other		16			172			20			257
		593			322			964			582
Income before income taxes		123,009			31,121			217,632			63,891
Income tax expense (benefit):
Current		44,983			14,655			78,079			19,204
Deferred		361			(3,141	)		2,140			4,398
		45,344			11,514			80,219			23,602
Net income	$	77,665		$	19,607		$	137,413		$	40,289
Net income per common share:
Basic	$	0.46		$	0.12		$	0.81		$	0.24
Diluted	$	0.45		$	0.12		$	0.80		$	0.24
Weighted average number of common shares outstanding:
Basic		169,992			166,681			169,378			165,211
Diluted		173,162			169,062			172,648			168,005

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 (Unaudited)
(in thousands)

	Common Stock														Accumulated other
						Additional			Deferred			Retained			comprehensive
	Number of shares			Amount		paid-in capital			compensation			earnings			income			Treasury stock			Total
Balance, December 31, 2004		171,626		$	1,716	$	597,280		$	(5,420	)	$	415,489		$	11,611		$	(13,137	)	$	1,007,539
Issuance of restricted stock		301			3		7,911			(7,914	)		—			—			—			—
Amortization of deferred compensation expense		—			—		—			1,108			—			—			—			1,108
Forfeitures of restricted shares		(9	)		—		(131	)		131			—			—			—			—
Exercise of stock options		2,816			29		29,285			—			—			—			—			29,314
Tax benefit related to exercise of stock options		—			—		17,270			—			—			—			—			17,270
Foreign currency translation adjustment, net of tax of $3.7 million		—			—		—			—			—			(5,228	)		—			(5,228	)
Payment of cash dividend		—			—		—			—			(13,537	)		—			—			(13,537	)
Net income		—			—		—			—			137,413			—			—			137,413
Balance, June 30, 2005		174,734		$	1,748	$	651,615		$	(12,095	)	$	539,365		$	6,383		$	(13,137	)	$	1,173,879

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 (Unaudited)
(in thousands)

	Six Months Ended
	June 30,
	2005			2004
Cash flows from operating activities:
Net income	$	137,413		$	40,289
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and impairment		71,359			57,734
Provision for bad debts		366			307
Deferred income tax expense		2,140			4,398
Tax benefit related to exercise of stock options		17,270			8,396
Amortization of deferred compensation expense		1,108			263
Gain on sale of assets		(1,053	)		(1,375	)
Changes in operating assets and liabilities, net of business acquired:
Accounts receivable		(85,417	)		(21,969	)
Income taxes receivable		—			16,953
Inventory and other current assets		(6,990	)		(2,206	)
Accounts payable		4,481			5,260
Income taxes payable		7,533			—
Accrued expenses		5,056			(13,333	)
Other liabilities		2,602			(4,033	)
Net cash provided by operating activities		155,868			90,684
Cash flows from investing activities:
Acquisitions, net of cash acquired		(65,401	)		(32,514	)
Purchases of property and equipment		(158,949	)		(89,723	)
Proceeds from sales of property and equipment		8,839			1,986
Restricted cash deposited to collateralize retained insurance losses		—			(11,316	)
Change in other assets		1,766			—
Net cash used in investing activities		(213,745	)		(131,567	)
Cash flows from financing activities:
Purchase of treasury stock		—			(1,482	)
Dividends paid		(13,537	)		(3,336	)
Proceeds from exercise of stock options		29,314			8,698
Net cash provided by financing activities		15,777			3,880
Effect of foreign exchange rate changes on cash		(194	)		(127	)
Net decrease in cash and cash equivalents		(42,294	)		(37,130	)
Cash and cash equivalents at beginning of period		112,371			100,483
Cash and cash equivalents at end of period	$	70,077		$	63,353
Supplemental disclosure of cash flow information:
Net cash received (paid) during the period for:
Interest expense	$	(123	)	$	(130	)
Income taxes	$	(48,585	)	$	8,000

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, 2004, as presented herein, was derived from the audited balance sheet of the Company. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004.

     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 4 of these Notes to Unaudited Condensed Consolidated Financial Statements).

7

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

1. Basis of Consolidation and Presentation — (continued)

     The Company provides a dual presentation of its earnings per share in its Unaudited Condensed Consolidated Statements of Income: Basic Earnings per Share (“Basic EPS”) and Diluted Earnings per 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 and the assumed exercise of dilutive instruments, including stock options and warrants, less the number of treasury shares assumed to be purchased with the exercise proceeds. For the three and six months ended June 30, 2005 and 2004, all potentially dilutive options and warrants 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, 2005 and 2004 as well as dividends per share paid for the three and six months ended June 30, 2005 (in thousands, except per share amounts).

	Three months ended				Six months ended
	June 30,				June 30,
	2005		2004		2005		2004
Net income	$	77,665	$	19,607	$	137,413	$	40,289
Weighted average common shares outstanding		169,992		166,681		169,378		165,211
Basic earnings per share	$	0.46	$	0.12	$	0.81	$	0.24
Weighted average common shares outstanding		169,992		166,681		169,378		165,211
Assumed exercise of stock options		3,170		2,381		3,270		2,794
Weighted average dilutive common shares outstanding		173,162		169,062		172,648		168,005
Diluted earnings per share	$	0.45	$	0.12	$	0.80	$	0.24
Cash dividends per share (a)	$	0.04	$	0.02	$	0.08	$	0.02

     (a) 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. During June 2004, a cash dividend of $3.3 million was paid on outstanding shares of 166,786,254.

     The results of operations for the three and six months ended June 30, 2005 are not necessarily indicative of the results to be expected for the full year.

     Certain reclassifications have been made to the 2004 consolidated financial statements in order for them to conform with the 2005 presentation.

2. Recent Acquisitions

     On January 15, 2005, the Company purchased land drilling assets from Key Energy Services, Inc. for $61.8 million. The assets included 25 active and 10 stacked land-based drilling rigs, related drilling equipment, yard facilities and a rig moving fleet consisting of approximately 45 trucks and 100 trailers. The transaction was accounted for as an acquisition of assets and the purchase price was allocated among the assets acquired based on their estimated fair market values.

     On June 17, 2005, the Company acquired one land-based drilling rig for $3.6 million. The transaction was accounted for as an acquisition of assets and the purchase price was allocated to the acquired drilling rig.

8

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

3. Stock-based Compensation

     During June 2005, the Company’s shareholders approved the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 Plan”). In addition, the Board of Directors adopted a resolution that no future grants would be made under any of the previously existing equity plans of the Company. The Company accounts for activity under the 2005 Plan and previous activity of other equity plans using the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees (“APB 25”), and related interpretations. During the second quarters of 2004 and 2005, the Company granted restricted shares of the Company's common stock (the “Restricted Shares”) to certain key employees under the Patterson-UTI Energy, Inc 1997 Long-Term Incentive Plan, as amended, and the 2005 Plan. As required by APB 25, the Restricted Shares were valued based upon the market price of the Company’s common stock on the date of the grant. The resulting value is being amortized over the vesting period of the stock. For the three and six months ended June 30, 2005, compensation expense of $399,000 and $700,000, net of $56,000 and $131,000 of forfeitures and of $233,000 and $408,000 of taxes, respectively, was included as a reduction in net income. Compensation expense of $165,000, net of $97,000 of taxes, was included as a reduction in net income for the three and six months ended June 30, 2004. Other than the Restricted Shares discussed above, no additional stock-based employee compensation expense is reflected in net income, as all options granted under the plans discussed above had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and net income per share if the Company had applied the fair value recognition provisions of Financial Accounting Standards Board Statement No. 123, Accounting for Stock-Based Compensation (“SFAS 123”), to stock-based employee compensation (in thousands, except per share amounts):

	Three months ended						Six months ended
	June 30,						June 30,
	2005			2004			2005			2004
Net income, as reported	$	77,665		$	19,607		$	137,413		$	40,289
Add: Stock-based employee compensation expense recorded, net of forfeitures and taxes		399			165			700			165
Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects		(2,811	)		(3,187	)		(5,358	)		(6,161	)
Pro-forma net income	$	75,253		$	16,585		$	132,755		$	34,293
Net income per common share:
Basic, as reported	$	0.46		$	0.12		$	0.81		$	0.24
Basic, pro-forma	$	0.44		$	0.10		$	0.78		$	0.21
Diluted, as reported	$	0.45		$	0.12		$	0.80		$	0.24
Diluted, pro-forma	$	0.44		$	0.10		$	0.77		$	0.20

9

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

4. 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, 2005 and 2004 (in thousands):

	Three months ended						Six months ended
	June 30,						June 30,
	2005			2004			2005			2004
Net income	$	77,665		$	19,607		$	137,413		$	40,289
Other comprehensive income (expense):
Foreign currency translation adjustment related to our Canadian operations		(631	)		(1,424	)		(1,162	)		(1,891	)
Cumulative tax effect (1)		(4,066	)		—			(4,066	)		—
Comprehensive income, net of tax	$	72,968		$	18,183		$	132,185		$	38,398

(1) Amount represents the cumulative impact of deferred taxes on foreign currency translation adjustments for the Canadian operations.

5. Property and Equipment

     Property and equipment consisted of the following at June 30, 2005 and December 31, 2004 (in thousands):

	June 30,			December 31,
	2005			2004
Drilling rigs and related equipment	$	1,389,535		$	1,217,497
Other equipment		102,697			83,683
Oil and natural gas properties		77,869			82,711
Buildings		15,404			13,008
Land		5,573			3,949
		1,591,078			1,400,848
Less accumulated depreciation and depletion		(617,140	)		(571,973	)
	$	973,938		$	828,875

10

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

6. 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,
	2005			2004			2005			2004
Revenues:
Contract drilling (a)	$	330,027		$	189,691		$	626,604		$	370,016
Pressure pumping		22,025			14,577			38,718			28,827
Drilling and completion fluids (b)		29,726			23,507			59,152			41,671
Oil and natural gas		8,807			8,287			17,912			15,502
Total segment revenues		390,585			236,062			742,386			456,016
Elimination of intercompany revenues (a)(b)		663			1,552			1,871			2,727
Total revenues	$	389,922		$	234,510		$	740,515		$	453,289
Income before income taxes:
Contract drilling	$	116,333		$	28,507		$	206,035		$	55,595
Pressure pumping		5,533			3,364			8,088			6,588
Drilling and completion fluids		2,793			1,166			5,495			1,388
Oil and natural gas		3,106			767			6,434			3,543
		127,765			33,804			226,052			67,114
Corporate and other		(5,349	)		(3,005	)		(9,384	)		(3,805	)
Interest income		634			204			1,067			455
Interest expense		(57	)		(54	)		(123	)		(130	)
Other		16			172			20			257
Income before income taxes	$	123,009		$	31,121		$	217,632		$	63,891

	June 30,		December 31,
	2005		2004
Identifiable assets:
Contract drilling	$	1,258,738	$	1,044,147
Pressure pumping		72,580		62,866
Drilling and completion fluids		41,738		38,196
Oil and natural gas		72,172		66,734
		1,445,228		1,211,943
Corporate and other (c)		72,290		110,968
Total assets	$	1,517,518	$	1,322,911

(a)	Includes contract drilling intercompany revenues of approximately $524,000 and $1.5 million for the three months ended June 30, 2005 and 2004, respectively, and approximately $1.7 million and $2.6 million for the six months ended June 30, 2005 and 2004, respectively.
(b)	Includes drilling and completion fluids intercompany revenues of approximately $139,000 and $83,000 for the three months ended June 30, 2005 and 2004, respectively, and approximately $159,000 and $108,000 for the six months ended June 30, 2005 and 2004, respectively.
(c)	Corporate assets primarily include cash on hand managed by the parent corporation and certain deferred federal income tax assets.

11

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

7. Recently Issued Accounting Standards

     The Financial Accounting Standards Board (“FASB”) issued Staff Position Financial Accounting Standard 19-1, Accounting for Suspended Well Costs (“FAS19-1”), in April 2005. FAS 19-1 provides guidance on accounting for exploratory well costs for entities that use the successful efforts method of accounting as described in Statement of Financial Accounting Standard No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, (“SFAS 19”). Exploration activities are frequently performed in more remote areas, to greater depths, and in more complex geological formations than the exploration activities that occurred when SFAS 19 was issued in 1977. These changes in exploration activities have resulted in an increased frequency of exploratory wells that successfully find reserves that cannot be recognized as proved when drilling is completed and a lengthened evaluation period for determining whether the reserves qualify as proved. The FASB staff believes that exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project and SFAS 19 is amended to clarify this position. The Company intends to adopt these accounting and disclosure requirements prospectively to existing and newly capitalized exploratory well costs in the third quarter of 2005 and does not expect a significant impact on financial position or results of operations.

     The FASB issued Staff Position FIN46(R)-5, Implicit Variable Interests Under FASB Interpretation No. 46 (revised December 2003), in March 2005. It addresses whether a reporting enterprise should consider whether it holds an implicit variable interest in a variable interest entity (“VIE”) or potential VIE when specific conditions exist. The Company does not expect any impact on its financial position or results of operations as a result of its adoption of FIN 46(R)-5 in the second quarter of 2005.

     The FASB issued Staff Position FIN 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143, in March 2005. The Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. The statement clarifies the term “conditional asset retirement obligation” as used in FASB 143. The Company believes that it is already in compliance with the statement and does not expect any impact on financial position or results of operations when adopted.

     The FASB issued Statement of Financial Accounting Standard No. 123 (revised 2004), Share-Based Payment (“SFAS 123(R)”), in December 2004; it replaces SFAS 123, and supersedes APB 25. Under SFAS 123(R), companies would have been required to implement the standard as of the beginning of the first interim reporting period that begins after June 15, 2005. However, in April 2005, the SEC announced the adoption of an Amendment to Rule 4-01(a) of Regulation S-X regarding the compliance date for SFAS 123(R) that amends the compliance dates and allows companies to implement SFAS 123(R) beginning with the first annual reporting period beginning on or after June 15, 2005. The Company intends to adopt SFAS 123(R) in its fiscal year beginning January 1, 2006.

     The Company currently uses the intrinsic value method to value stock options, and accordingly, no compensation expense has been recognized for stock options since the Company grants stock options with exercise prices equal to the Company’s common stock market price on the date of the grant. SFAS 123(R) requires the expensing of all stock-based compensation, including stock options and restricted shares, using the fair value method. The Company intends to expense stock options using the Modified Prospective Transition method as described in SFAS 123(R). This method will require expense to be recognized for stock options over their respective remaining vesting periods. No expense will be recognized for stock options vested in periods prior to the adoption of SFAS 123(R). The Company is evaluating the impact of its adoption of SFAS 123(R) on its results of operations and financial position. Adoption is not expected to have a material effect on the Company’s financial position or results of operations.

     The FASB issued Statement of Financial Accounting Standard No. 151, Inventory Costs — an amendment of ARB No. 43, Chapter 4 (“SFAS 151”). SFAS 151 is effective, and will be adopted, for inventory costs incurred

12

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

7. Recently Issued Accounting Standards — (continued)

during fiscal years beginning after June 15, 2005 and is to be applied prospectively. SFAS 151 amends the guidance in ARB No. 43, Chapter 4, Inventory Pricing, to require current period recognition of abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Adoption is not expected to have a material effect on the Company’s financial position or results of operations.

     The FASB issued Statement of Financial Accounting Standard No. 153, Exchanges of Nonmonetary Assets — an amendment of APB Opinion No. 29 (“SFAS 153”). SFAS 153 is effective, and will be adopted, for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005 and is to be applied prospectively. SFAS 153 eliminates the exception for fair value treatment of nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Adoption is not expected to have a material effect on the Company’s financial position or results of operations.

     The FASB issued Statement of Financial Accounting Standards No. 154, Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3 (“SFAS 154”). SFAS 154 is effective, and will be adopted, for accounting changes made in fiscal years beginning after December 15, 2005 and is to be applied retrospectively. SFAS 154 requires that retroactive application of a change in accounting principle be limited to the direct effects of the change. Adoption is not expected to have a material effect on the Company’s financial position or results of operations.

8. Goodwill

     Goodwill is evaluated to determine if the fair value of an asset has decreased below its carrying value. At December 31, 2004 the Company performed its annual goodwill evaluation and determined no adjustment to impair goodwill was necessary. Goodwill as of June 30, 2005 and December 31, 2004 are as follows (in thousands):

	June 30,		December 31,
	2005		2004
Drilling:
Goodwill at beginning of year	$	91,362	$	41,215
Changes to goodwill		—		50,147
Goodwill at end of period		91,362		91,362
Drilling and completion fluids:
Goodwill at beginning of year	$	9,964	$	9,964
Changes to goodwill		—		—
Goodwill at end of period		9,964		9,964
Total goodwill	$	101,326	$	101,326

13

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

9. Accrued Expenses

     Accrued expenses consisted of the following at June 30, 2005 and December 31, 2004 (in thousands):

	June 30,		December 31,
	2005		2004
Salaries, wages, payroll taxes and benefits.	$	23,865	$	21,245
Workers’ compensation liability		38,099		38,677
Sales, use and other taxes		6,258		5,863
Insurance, other than workers’ compensation.		9,817		7,061
Other		7,241		6,317
	$	85,280	$	79,163

10. 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, 2005 and 2004 (in thousands):

	2005			2004
Balance at beginning of year	$	2,358		$	1,163
Liabilities incurred*		19			1,113
Liabilities settled		(511	)		(70	)
Accretion expense		37			15
Asset retirement obligation at end of period.	$	1,903		$	2,221

     * The 2004 amount includes $1,091 of liabilities assumed in the acquisition of TMBR/Sharp Drilling, Inc. (“TMBR”).

11. Commitments, Contingencies and Other Matters

     The Company maintains letters of credit in the aggregate amount of approximately $56 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.

     We are also party to various legal proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our financial condition.

14

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

12. Stockholders’ Equity

     On February 16, 2005 and April 27, 2005, the Company’s Board of Directors approved cash dividends on its common stock in the amount of $0.04 per share. The dividends of approximately $6.7 million and $6.8 million were paid on March 4, 2005 and June 1, 2005, respectively. 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.

     During the second quarters of 2004 and 2005, the Company granted restricted shares of the Company's common stock to certain key employees under the Patterson-UTI Energy, Inc 1997 Long-Term Incentive Plan, as amended, and the 2005 Plan. As required by APB Opinion No. 25, the Restricted Shares were valued based upon the market price of the Company’s common stock on the date of the grant. The resulting value is being amortized over the vesting period of the stock. For the three and six months ended June 30, 2005, compensation expense of $399,000 and $700,000, net of $56,000 and $131,000 of forfeitures and of $233,000 and $408,000 of taxes, respectively, was included as a reduction in net income. Compensation expense of $165,000, net of $97,000 taxes, was included as a reduction in net income for the three and six months ended June 30, 2004.

13. Subsequent Event

     On July 27, 2005, the Company’s Board of Directors approved a quarterly cash dividend of $0.04 on each outstanding share of its common stock. The dividend is to be paid on September 1, 2005 to holders of record as of August 16, 2005.

15

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, 2005 and 2004, our operating revenues consisted of the following (dollars in thousands):

	Three Months Ended								Six Months Ended
	June 30,								June 30,
	2005				2004				2005				2004
Contract drilling	$	329,503	84	%	$	188,222	80	%	$	624,892	84	%	$	367,397	81	%
Pressure pumping		22,025	6			14,577	6			38,718	5			28,827	6
Drilling and completion fluids		29,587	8			23,424	10			58,993	8			41,563	9
Oil and natural gas.		8,807	2			8,287	4			17,912	3			15,502	4
	$	389,922	100	%	$	234,510	100	%	$	740,515	100	%	$	453,289	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, 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 in Texas, Southeastern New Mexico, Oklahoma, the Gulf Coast region of Louisiana and the Gulf of Mexico. 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 397 rigs as of June 30, 2005. Based on publicly available information, we believe we are the second largest owner of land-based drilling rigs in North America. Growth by acquisition has been a corporate strategy intended to expand both revenues and profits.

     The profitability of our business is most readily assessed by two primary indicators: our average number of rigs operating and our average revenue per operating day. During the second quarter of 2005, our average number of rigs operating increased to 265 from 263 in the first quarter of 2005 and 203 in the second quarter of 2004. Our average revenue per operating day increased to $13,690 in the second quarter of 2005 from $12,490 in the first quarter of 2005 and $10,190 in the second quarter of 2004. Primarily due to these improvements, we experienced an increase of approximately $58 million, or 296%, in consolidated net income for the second quarter of 2005 as compared to the second quarter of 2004.

     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 in our “Forward Looking Statements and Cautionary Statements for Purposes of the ‘Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995” included in our Annual Report on Form 10-K for the year ended December 31, 2004, beginning on page 14.

     Management believes that the liquidity of our balance sheet as of June 30, 2005, which includes approximately $268 million in working capital (including $70 million in cash), no long-term debt and $144 million available under a $200 million line of credit (availability of $56 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 and survive downturns in our industry.

16

     Commitments and Contingencies — The Company has no commitments or contingencies which require disclosure in its financial statements other than letters of credit of approximately $56 million at June 30, 2005, maintained for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which may become payable under the terms of the underlying insurance contracts. No amounts have been drawn under the letters of credit.

     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, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota and Western Canada. As of June 30, 2005, we owned 397 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 in Texas, Southeastern New Mexico, Oklahoma, the Gulf Coast region of Louisiana and the Gulf of Mexico. 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. The following is a discussion of our critical accounting policies pertaining to property and equipment, oil and natural gas properties, goodwill, revenue recognition, and the use of estimates.

     Property and equipment ¾ Property and equipment, including betterments which extend the useful life of the asset, are stated at cost. Maintenance and repairs are charged to expense when incurred. We provide for the depreciation of our property and equipment using the straight-line method over their estimated useful lives. Our method of depreciation does not change when equipment becomes idle; we continue to depreciate idled equipment on a straight-line basis. No provision for salvage value is considered in determining depreciation of our property and equipment. We review our assets for impairment when events or changes in circumstances indicate that the carrying values of certain assets either exceed their respective fair values or may not be recovered over their estimated remaining useful lives. The cyclical nature of our industry has resulted in fluctuations in rig utilization over periods of time. Management believes that the contract drilling industry will continue to be cyclical and rig utilization will fluctuate. Based on management’s expectations of future trends we estimate future cash flows in our assessment of impairment assuming the following four-year industry cycle: one year projected with low utilization, one year

17

projected as a recovery period with improving utilization and the remaining two years projecting higher utilization. Provisions for asset impairment are charged to income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book value. Impairment charges are recorded based on discounted cash flows. Other than to our oil and natural gas properties, there were no impairment charges to property and equipment during the six months ended June 30, 2005 or 2004.

     Oil and natural gas properties ¾ Oil and natural gas properties are accounted for using the successful efforts method of accounting. Under the successful efforts method of accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are charged to expense when such determination is made. In accordance with SFAS 19, costs of exploratory wells are initially capitalized to wells in progress until the outcome of the drilling is known. We review wells in progress quarterly to determine the related reserve classification. If the reserve classification is uncertain after one year following the completion of drilling, we consider the costs of the well to be impaired and recognize the costs as expense. Geological and geophysical costs, including seismic costs and costs to carry and retain undeveloped properties, are charged to expense when incurred. The capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment, lease acquisition costs, and intangible development costs, are depreciated, depleted, and amortized on the units-of-production method, based on petroleum engineer estimates of proved oil and natural gas reserves of each respective field. We review our proved oil and natural gas properties for impairment when an event occurs such as downward revisions in reserve estimates or decreases in oil and natural gas prices. Proved properties are grouped by field and undiscounted cash flow estimates are provided by our reserve engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between its net book value and discounted cash flow. Unproved oil and natural gas properties are reviewed quarterly to determine impairment. Our intent to drill, lease expiration, and abandonment of area are considered. Assessment of impairment is made on a lease-by-lease basis. If an unproved property is determined to be impaired, then costs related to that property are expensed. Impairment expense of approximately $216,000 and $818,000 for the three and six months ended June 30, 2005, respectively, and $1.7 million and $2.2 million for the three and six months ended June 30, 2004, respectively, is included in depreciation, depletion and impairment in the accompanying financial statements.

     Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. As such, we assess impairment of our goodwill annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value.

     Revenue recognition ¾ Revenues are recognized when services are performed, except for revenues earned under turnkey contract drilling arrangements which are recognized using the completed contract method of accounting, as described below. We follow the percentage-of-completion method of accounting for footage contract drilling arrangements. Under the percentage-of-completion method, management estimates are relied upon in the determination of the total estimated expenses to be incurred drilling the well. Due to the nature of turnkey contract drilling arrangements and risks therein, we follow the completed contract method of accounting for such arrangements. Under this method, all drilling revenues and expenses related to a well in progress are deferred and recognized in the period the well is completed. Provisions for losses on incomplete or in-process wells are made when estimated total expenses are expected to exceed estimated total revenues.

     In accordance with Emerging Issues Task Force Issue No. 00-14, we recognize reimbursements due from third parties for out-of-pocket expenses incurred as revenues and account for out-of-pocket expenses as direct costs.

     Use of estimates ¾ The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates.

18

     Key estimates used by management include:

• allowance for doubtful accounts,

• total expenses to be incurred on footage and turnkey drilling contracts,

• depreciation, depletion, and amortization,

• asset impairment,

• reserves for self-insured levels of insurance coverages, and

• fair values of assets and liabilities assumed in acquisitions.

Liquidity and Capital Resources

     As of June 30, 2005, we had working capital of approximately $267.6 million, including cash and cash equivalents of $70.1 million. For the six months ended June 30, 2005, our significant sources of cash flow included:

• $155.9 million provided by operations,

• $29.3 million from the exercise of stock options, and

• $8.8 million in proceeds from sales of property and equipment.

     We used $65.4 million to purchase land drilling assets from Key Energy Services, Inc. and one additional land-based drilling rig, $13.5 million to pay dividends on the Company’s common stock and $158.9 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.

     In January 2005, the Company purchased land drilling assets of Key Energy Services, Inc. for $61.8 million. The assets acquired included 25 active and 10 stacked land-based drilling rigs, related drilling equipment, yard facilities and a rig moving fleet consisting of approximately 45 trucks and 100 trailers. In June 2005, the Company acquired one land-based drilling rig for $3.6 million. The transactions were accounted for as acquisitions of assets and the respective purchase price was allocated among the assets acquired based on their estimated fair market values.

     On February 16, 2005 and April 27, 2005, the Company’s Board of Directors approved cash dividends on its common stock in the amount of $0.04 per share. The dividends of approximately $6.7 million and $6.8 million were paid on March 4, 2005 and June 1, 2005, respectively.

     On July 27, 2005, the Company’s Board of Directors approved a quarterly cash dividend of $0.04 on each outstanding share of its common stock to be paid on September 1, 2005 to holders of record as of August 16, 2005. 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.

     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.

19

Results of Operations

     The following tables summarize operations by business segment for the three months ended June 30, 2005 and 2004:

Contract Drilling	2005			2004			% Change
	(dollars in thousands)
Revenues	$	329,503		$	188,222			75.1	%
Direct operating costs	$	180,185		$	134,387			34.1	%
Selling, general and administrative	$	1,205		$	1,080			11.6	%
Depreciation	$	31,780		$	24,248			31.1	%
Operating income	$	116,333		$	28,507			308.1	%
Operating days		24,074			18,473			30.3	%
Average revenue per operating day	$	13.69		$	10.19			34.3	%
Average direct operating costs per operating day	$	7.48		$	7.27			2.9	%
Number of owned rigs at end of period		397			361			10.0	%
Average number of rigs owned during period		396			361			9.7	%
Average rigs operating		265			203			30.5	%
Rig utilization percentage		67	%		56	%		19.6	%
Capital expenditures	$	69,793		$	42,980			62.4	%

     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 as a result of increased demand for our contract drilling services and the acquisition of land drilling assets from Key Energy Services, Inc. in January 2005. Average revenue per operating day increased as a result of increased demand and pricing for our drilling services. Significant capital expenditures were incurred during the second quarter of 2005 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 the acquisition described above and capital expenditures in 2004 and 2005.

Pressure Pumping	2005		2004		% Change
	(dollars in thousands)
Revenues	$	22,025	$	14,577		51.1	%
Direct operating costs	$	12,622	$	8,328		51.6	%
Selling, general and administrative	$	2,192	$	1,664		31.7	%
Depreciation	$	1,678	$	1,221		37.4	%
Operating income	$	5,533	$	3,364		64.5	%
Total jobs		2,345		1,578		48.6	%
Average revenue per job	$	9.39	$	9.24		1.6	%
Average direct operating costs per job	$	5.38	$	5.28		1.9	%
Capital expenditures	$	7,075	$	4,782		48.0	%

     Revenues and direct operating costs for our pressure pumping operations increased primarily as a result of the increased number of jobs. The increase in jobs was largely attributable to increased demand for our services and increased operating capacity which was added in 2004 and the first six months of 2005. Selling, general and administrative expenses increased largely as a result of the expanding operations of the pressure pumping segment. Increased depreciation expense for the 2005 quarter was largely due to the expansion of the pressure pumping segment through capital expenditures during 2004 and 2005. Significant capital expenditures were incurred during the second quarter of 2005 to modify and upgrade existing equipment and to add additional equipment to the segment’s expanded operations to meet increased demand.

20

Drilling and Completion Fluids	2005		2004		% Change
	(dollars in thousands)
Revenues	$	29,587	$	23,424		26.3	%
Direct operating costs	$	23,846	$	19,837		20.2	%
Selling, general and administrative	$	2,367	$	1,875		26.2	%
Depreciation	$	581	$	546		6.4	%
Operating income	$	2,793	$	1,166		139.5	%
Total jobs		503		593		(15.2	)%
Average revenue per job	$	58.82	$	39.50		48.9	%
Average direct operating costs per job	$	47.41	$	33.45		41.7	%
Capital expenditures	$	766	$	416		84.1	%

     Revenues and direct operating costs increased during the second quarter of 2005 compared to the second quarter of 2004 as a result of an increase 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 the number of larger jobs in the Gulf of Mexico and a decrease in the number of smaller land-based jobs during the second quarter of 2005. Selling, general and administrative expense increased in 2005 primarily due to increased incentive compensation resulting from higher profitability levels.

Oil and Natural Gas Production and Exploration	2005		2004		% Change
	(dollars in thousands, except sales prices)
Revenues	$	8,807	$	8,287		6.3	%
Direct operating costs	$	2,418	$	2,768		(12.6	)%
Selling, general and administrative	$	552	$	427		29.3	%
Depreciation, depletion and impairment	$	2,731	$	4,325		(36.9	)%
Operating income	$	3,106	$	767		305.0	%
Capital expenditures	$	3,407	$	3,600		(5.4	)%
Average net daily oil production (Bbls)		795		1,171		(32.1	)%
Average net daily gas production (Mcf)		7,253		7,335		(1.1	)%
Average oil sales price (per Bbl)	$	51.52	$	37.94		35.8	%
Average gas sales price (per Mcf)	$	6.44	$	5.31		21.3	%

     Revenues increased in the second quarter of 2005 compared to the second quarter of 2004, due to increased market prices received for oil and natural gas. Average net daily oil production decreased as a result of production declines and the sale of certain oil and gas properties during the second quarter of 2005. Depreciation, depletion and impairment expense includes approximately $216,000 and $1.7 million of expenses incurred during the three months ended June 30, 2005 and 2004, respectively, to impair certain oil and natural gas properties.

Corporate and Other	2005		2004			% Change
	(in thousands)
Selling, general and administrative	$	3,609	$	2,864			26.0	%
Bad debt expense	$	143	$	217			(34.1	)%
Depreciation	$	189	$	111			70.3	%
Other (income) expense from operations	$	1,408	$	(187	)		N/A	%
Interest income	$	634	$	204			210.8	%
Interest expense	$	57	$	54			5.6	%
Other income	$	16	$	172			(90.7	)%
Capital expenditures	$	108	$	—			N/A	%

     Selling, general and administrative expenses increased primarily as a result of payroll taxes attributable to the exercise of employee stock options, increased professional fees, and additional compensation expense related to the issuance of restricted shares to certain key employees in the second quarters of 2004 and 2005. Other (income) expense from operations in 2005 includes a charge of $2.6 million to increase reserves related to the financial failure of a workers’ compensation insurance carrier used previously by the Company and this charge is partially offset by a gain recognized on the sale of certain oil and natural gas properties.

21

The following tables summarize operations by business segment for the six months ended June 30, 2005 and 2004:

Contract Drilling	2005			2004			% Change
	(dollars in thousands)
Revenues	$	624,892		$	367,397			70.1	%
Direct operating costs	$	355,651		$	262,378			35.5	%
Selling, general and administrative	$	2,427		$	2,175			11.6	%
Depreciation and amortization	$	60,779		$	47,249			28.6	%
Operating income	$	206,035		$	55,595			270.6	%
Operating days		47,731			36,437			31.0	%
Average revenue per operating day	$	13.09		$	10.08			29.9	%
Average direct operating costs per operating day	$	7.45		$	7.20			3.5	%
Number of owned rigs at end of period		397			361			10.0	%
Average number of rigs owned during period		393			357			10.1	%
Average rigs operating		264			200			32.0	%
Rig utilization percentage		67	%		56	%		19.6	%
Capital expenditures	$	129,128		$	71,360			81.0	%

     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 as a result of the increased demand for our contract drilling services, the acquisition of land drilling assets from Key Energy Services, Inc. in January 2005, and the acquisition of TMBR in February 2004. Average revenue per operating day increased as a result of increased demand and pricing for our drilling services. Significant capital expenditures were incurred during the first six months of 2005 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 the acquisitions described above and capital expenditures in 2004 and 2005.

Pressure Pumping	2005		2004		% Change
	(dollars in thousands)
Revenues	$	38,718	$	28,827		34.3	%
Direct operating costs	$	22,986	$	16,416		40.0	%
Selling, general and administrative	$	4,394	$	3,457		27.1	%
Depreciation	$	3,250	$	2,366		37.4	%
Operating income	$	8,088	$	6,588		22.8	%
Total jobs		4,254		3,266		30.3	%
Average revenue per job	$	9.10	$	8.83		3.1	%
Average direct operating costs per job	$	5.40	$	5.03		7.4	%
Capital expenditures	$	14,733	$	10,604		38.9	%

     Revenues and direct operating costs for our pressure pumping operations primarily increased as a result of the increased number of jobs. The increase in jobs was largely attributable to increased demand for our services and increased operating capacity which was added in 2004 and the first six months of 2005. Selling, general and administrative expenses increased largely as a result of the expanding operations of the pressure pumping segment. Increased depreciation expense in 2005 was largely due to the expansion of the pressure pumping segment through capital expenditures during 2004 and the first six months of 2005.

22

Drilling and Completion Fluids	2005		2004		% Change
	(dollars in thousands)
Revenues	$	58,993	$	41,563		41.9	%
Direct operating costs	$	47,795	$	35,476		34.7	%
Selling, general and administrative	$	4,562	$	3,585		27.3	%
Depreciation and amortization	$	1,141	$	1,114		2.4	%
Operating income	$	5,495	$	1,388		295.9	%
Total jobs		1,030		1,111		(7.3	)%
Average revenue per job	$	57.27	$	37.41		53.1	%
Average direct operating costs per job	$	46.40	$	31.93		45.3	%
Capital expenditures	$	1,352	$	627		115.6	%

     Revenues and direct operating costs increased during the first six months of 2005 compared to the first six months of 2004 as a result of an increase 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 the number of larger jobs in the Gulf of Mexico and a decrease in the number of smaller land-based jobs during 2005. Selling, general and administrative expense increased in 2005 primarily due to increased incentive compensation resulting from higher profitability levels.

Oil and Natural Gas Production and Exploration	2005		2004		% Change
	(dollars in thousands, except sales pries)
Revenues	$	17,912	$	15,502		15.5	%
Direct operating costs	$	4,588	$	4,336		5.8	%
Selling, general and administrative	$	1,053	$	840		25.4	%
Depreciation, depletion and impairment	$	5,837	$	6,783		(13.9	)%
Operating income	$	6,434	$	3,543		81.6	%
Capital expenditures	$	8,428	$	7,132		18.2	%
Average net daily oil production (Bbls)		846		1,050		(19.4	)%
Average net daily gas production (Mcf)		7,922		7,488		5.8	%
Average oil sales price (per Bbl)	$	49.00	$	36.14		35.6	%
Average gas sales price (per Mcf)	$	6.16	$	5.35		15.1	%

     Revenues increased in 2005 compared to 2004, primarily due to increased market prices received for oil and natural gas. Depreciation, depletion and impairment expense includes approximately $817,000 and $2.2 million of expenses incurred during 2005 and 2004, respectively, to impair certain oil and natural gas properties.

Corporate and Other	2005		2004			% Change
	(in thousands)
Selling, general and administrative	$	7,168	$	4,651			54.1	%
Bad debt expense	$	366	$	307			19.2	%
Depreciation and amortization	$	352	$	222			58.6	%
Other (income) expense from operations	$	1,498	$	(1,375	)		N/A	%
Interest income	$	1,067	$	455			134.5	%
Interest expense	$	123	$	130			(5.4	)%
Other income	$	20	$	257			(92.2	)%
Capital expenditures	$	5,308	$	—			N/A	%

     Selling, general and administrative expenses increased primarily as a result of payroll taxes attributable to the exercise of employee stock options, increased professional fees, and additional compensation expense related to the issuance of restricted shares to certain key employees in the second quarters of 2004 and 2005. Other (income) expense from operations in 2005 includes a charge of $2.6 million to increase reserves related to the financial failure of a worker’s compensation insurance carrier used previously by the Company.

23

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

     Our revenue, profitability, and future 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 $5.45 in 2003 to $5.95 in 2004 and $6.94 in the second quarter of 2005, resulting in an increase in demand for our drilling services. Our average number of rigs operating increased from 126 in 2002 to 188 in 2003 to 211 in 2004 and 265 in the second quarter of 2005. 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.

     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.

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 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 when they are translated to U.S. dollars. Also, the value of our Canadian net assets in U.S. dollars may decline.

ITEM 4. Controls and Procedures

     Disclosure Controls and Procedures. As of the end of the period covered by this Quarterly Report on Form 10-Q, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934) was evaluated by our management, with the participation of our Chief Executive Officer, Cloyce A. Talbott (principal executive officer), and our Vice President, Chief Financial Officer, Secretary and Treasurer, Jonathan D. Nelson (principal financial and accounting officer). Messrs. Talbott and Nelson have concluded that our disclosure controls and procedures are effective, as of the end of the period covered by this Report, to help ensure that information we are required to disclose in reports that we file with the SEC is accumulated and communicated to management and recorded, processed, summarized and reported within the time periods prescribed by the SEC.

     There were no changes in our internal control over financial reporting that occurred during our last fiscal quarter ended June 30, 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

24

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 “Forward Looking Statements and Cautionary Statements for Purposes of the ‘Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995” included in our Annual Report on Form 10-K for the year ended December 31, 2004, beginning on page 14.

     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.

25

PART II — OTHER INFORMATION

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

     On June 15, 2005, the Company held its Annual Meeting of Stockholders. At the meeting, the stockholders voted on the following matters:

1.	The election of nine persons to serve as directors of the Company.
2.	Approval of the adoption of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 Plan”).
3.	Ratification of the appointment of PricewaterhouseCoopers LLP as the independent accountants of the Company for the fiscal year ending December 31, 2005.

     The nine nominees to the Board of Directors of the Company were elected at the meeting, and the other proposals received the affirmative vote required for approval. The number of votes cast for, against or withheld, as well as the number of abstentions and broker non-votes, were as follows:

		Votes For		Votes Withheld
1.	Election of Directors
	Mark S. Siegel		155,764,040		2,664,759
	Cloyce A. Talbott		155,762,955		2,665,844
	A. Glenn Patterson		155,763,338		2,665,461
	Kenneth N. Berns		151,630,010		6,798,789
	Robert C. Gist		152,198,666		6,230,133
	Curtis W. Huff		157,004,971		1,423,828
	Terry H. Hunt		157,003,923		1,424,876
	Kenneth R. Peak		157,072,419		1,356,380
	Nadine C. Smith		157,070,786		1,358,013

								Broker
		Votes For		Votes Against		Abstentions		Non-votes
2.	Approval of the 2005 Plan		126,619,156		10,728,710		1,651,308		19,429,625

								Broker
		Votes For		Votes Against		Abstentions		Non-votes
3.	Ratification of PricewaterhouseCoope rs LLP as the Company’s Independent Accountants		156,358,655		1,945,384		124,760		0

ITEM 6. Exhibits

	(a) Exhibits.
	The following exhibits are filed herewith or incorporated by reference, as indicated:
3.1	Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3.2	Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3.3	Amended and Restated Bylaws (filed March 19, 2002 as Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference).

26

10.1	Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, including Form of Executive Officer Restricted Stock Award Agreement, Form of Executive Officer Stock Option Agreement, Form of Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee Director Stock Option Agreement (incorporated by reference to Exhibit 10.1 to Patterson-UTI Energy, Inc.’s Current Report on Form 8-K, dated June 15, 2005, as filed with the SEC on June 21, 2005).*
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
32.1	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Management Contract or Compensatory Plan.

27

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/ Jonathan D. Nelson
		Jonathan D. Nelson (Principal Accounting Officer) Vice President, Chief Financial Officer, Secretary and Treasurer
DATED: July 28, 2005

28