Patterson-UTI Energy (PTEN) 10-Q 2005 Q3 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 September 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	(I.R.S. Employer Identification No.)
incorporation or organization)

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.

Yesþ       Noo

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yesþ       Noo

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

172,801,959 shares of common stock, $0.01 par value, as of October 26, 2005

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

			Page
PART I — Financial Information
	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		15
	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 6.	Exhibits		26
Signatures				27
Certification of CEO Pursuant to Rule 13a-14(a)/Rule 15d-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)/Rule 15d-14(a)
Certification of CEO and 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)

	September 30,			December 31,
	2005			2004
ASSETS
Current assets:
Cash and cash equivalents	$	131,211		$	112,371
Accounts receivable, net of allowance for doubtful accounts of $2,431 at September 30, 2005 and $1,909 at December 31, 2004		362,976			214,097
Inventory		20,916			17,738
Deferred tax assets, net		19,688			15,991
Other		26,738			26,836
Total current assets		561,529			387,033
Property and equipment, at cost, net	��	1,048,561			828,875
Goodwill		101,326			101,326
Other		5,065			5,677
Total assets	$	1,716,481		$	1,322,911
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	89,964		$	54,553
Accrued revenue distributions		14,379			11,297
Other		2,956			2,309
Accrued federal and state income taxes payable		30,854			2,754
Accrued expenses		102,493			79,163
Total current liabilities		240,646			150,076
Deferred tax liabilities, net		171,542			162,040
Other		4,122			3,256
Total liabilities		416,310			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 175,791,288 and 171,625,841 issued and 172,678,192 and 168,512,745 outstanding at September 30, 2005 and December 31, 2004, respectively		1,758			1,716
Additional paid-in capital		671,303			597,280
Deferred compensation		(11,018	)		(5,420	)
Retained earnings		642,596			415,489
Accumulated other comprehensive income		8,669			11,611
Treasury stock, at cost, 3,113,096 shares		(13,137	)		(13,137	)
Total stockholders’ equity		1,300,171			1,007,539
Total liabilities and stockholders’ equity	$	1,716,481		$	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						Nine months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Operating revenues:
Contract drilling	$	401,046		$	206,454		$	1,025,938		$	573,851
Pressure pumping		27,640			19,663			66,358			48,490
Drilling and completion fluids		29,819			23,455			88,812			65,018
Oil and natural gas		10,234			9,602			28,146			25,104
		468,739			259,174			1,209,254			712,463
Operating costs and expenses:
Contract drilling		202,956			140,608			558,607			402,986
Pressure pumping		15,662			10,455			38,648			26,871
Drilling and completion fluids		24,062			19,851			71,857			55,327
Oil and natural gas		2,365			1,715			6,953			6,051
Depreciation, depletion and impairment		39,216			30,789			110,575			88,523
Selling, general and administrative		10,571			8,309			30,175			23,017
Bad debt expense		50			192			416			499
Other		346			(153	)		1,844			(1,528	)
		295,228			211,766			819,075			601,746
Operating income		173,511			47,408			390,179			110,717
Other income (expense):
Interest income		944			233			2,011			688
Interest expense		(56	)		(75	)		(179	)		(205	)
Other		19			56			39			313
		907			214			1,871			796
Income before income taxes		174,418			47,622			392,050			111,513
Income tax expense (benefit):
Current		66,147			11,996			144,226			31,200
Deferred		(1,864	)		5,662			276			10,060
		64,283			17,658			144,502			41,260
Net income	$	110,135		$	29,964		$	247,548		$	70,253
Net income per common share:
Basic	$	0.64		$	0.18		$	1.46		$	0.42
Diluted	$	0.63		$	0.18		$	1.43		$	0.42
Weighted average number of common shares outstanding:
Basic		171,613			167,006			169,846			165,744
Diluted		174,587			169,664			173,211			168,795

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)

															Accumulated
	Common Stock					Additional									other
	Number					paid-in			Deferred			Retained			comprehensive			Treasury
	of shares			Amount		capital			compensation			earnings			income			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		305			3		8,040			(8,043	)		—			—			—			—
Amortization of deferred compensation expense		—			—		—			2,121			—			—			—			2,121
Forfeitures of restricted shares		(17	)		—		(324	)		324			—			—			—			—
Exercise of stock options		3,877			39		42,260			—			—			—			—			42,299
Tax benefit related to exercise of stock options		—			—		24,047			—			—			—			—			24,047
Foreign currency translation adjustment, net of tax of $5.0 million		—			—		—			—			—			(2,942	)		—			(2,942	)
Payment of cash dividend		—			—		—			—			(20,441	)		—			—			(20,441	)
Net income		—			—		—			—			247,548			—			—			247,548
Balance, September 30, 2005		175,791		$	1,758	$	671,303		$	(11,018	)	$	642,596		$	8,669		$	(13,137	)	$	1,300,171

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)

	Nine months Ended
	September 30,
	2005			2004
Cash flows from operating activities:
Net income	$	247,548		$	70,253
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and impairment		110,575			88,523
Provision for bad debts		416			499
Deferred income tax expense		276			10,060
Tax benefit related to exercise of stock options		24,047			6,682
Amortization of deferred compensation expense		2,121			749
Gain on sale of assets		(1,583	)		(1,528	)
Changes in operating assets and liabilities, net of business acquired:
Accounts receivable		(148,825	)		(34,480	)
Income taxes receivable		—			21,825
Inventory and other current assets		(4,044	)		(6,997	)
Accounts payable		38,568			2,820
Income taxes payable		28,373			—
Accrued expenses		22,662			(5,416	)
Other liabilities		1,513			(6,729	)
Net cash provided by operating activities		321,647			146,261
Cash flows from investing activities:
Acquisitions, net of cash acquired		(73,577	)		(32,514	)
Purchases of property and equipment		(264,898	)		(136,835	)
Proceeds from sales of property and equipment		12,502			2,631
Restricted cash deposited to collateralize retained insurance losses		—			(11,316	)
Change in other assets		1,766			—
Net cash used in investing activities		(324,207	)		(178,034	)
Cash flows from financing activities:
Purchase of treasury stock		—			(1,482	)
Dividends paid		(20,441	)		(6,674	)
Proceeds from exercise of stock options		42,299			9,293
Net cash provided by financing activities		21,858			1,137
Effect of foreign exchange rate changes on cash		(458	)		(81	)
Net increase (decrease) in cash and cash equivalents		18,840			(30,717	)
Cash and cash equivalents at beginning of period		112,371			100,483
Cash and cash equivalents at end of period	$	131,211		$	69,766
Supplemental disclosure of cash flow information:
Net cash paid during the period for:
Interest expense	$	179		$	205
Income taxes	$	85,824		$	500

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, warrants and restricted shares, less the number of treasury shares assumed to be purchased with the exercise proceeds. For the three and nine months ended September 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 nine months ended September 30, 2005 and 2004 as well as cash dividends per share paid during the three and nine months ended September 30, 2005 and 2004 (in thousands, except per share amounts).

	Three months ended				Nine months ended
	September 30,				September 30,
	2005		2004		2005		2004
Net income	$	110,135	$	29,964	$	247,548	$	70,253
Weighted average common shares outstanding		171,613		167,006		169,846		165,744
Basic earnings per share	$	0.64	$	0.18	$	1.46	$	0.42
Weighted average common shares outstanding		171,613		167,006		169,846		165,744
Dilutive effect of stock options and restricted shares		2,974		2,658		3,365		3,051
Weighted average dilutive common shares outstanding		174,587		169,664		173,211		168,795
Diluted earnings per share	$	0.63	$	0.18	$	1.43	$	0.42
Cash dividends per share (a)	$	0.04	$	0.02	$	0.12	$	0.04

(a) During March, June and September of 2005, cash dividends of $6.7 million, $6.8 million and $6.9 million, respectively, were paid on outstanding shares of 168,679,334, 169,741,460 and 172,591,361, respectively. During June and September of 2004, cash dividends of $3.3 million were paid on outstanding shares of 166,786,254 and 166,988,651, respectively.

     The results of operations for the three and nine months ended September 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.

     On September 29, 2005, the Company acquired five land-based drilling rigs and related drilling equipment for $8.2 million. 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.

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 its 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 and the third quarter of 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 nine months ended September 30, 2005, compensation expense of $639,000 and $1.3 million, net of $29,000 and $160,000 of forfeitures and of $374,000 and $782,000 of taxes, respectively, was included as a reduction in net income. Compensation expense of $306,000 and $471,000, net of $180,000 and $278,000 of taxes, was included as a reduction in net income for the three and nine months ended September 30, 2004, respectively. 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						Nine months ended
	September 30,						September 30,
	2005			2004			2005			2004
Net income, as reported	$	110,135		$	29,964		$	247,548		$	70,253
Add: Stock-based employee compensation expense recorded, net of forfeitures and taxes		639			306			1,339			471
Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects		(3,426	)		(3,468	)		(9,484	)		(9,794	)
Pro-forma net income	$	107,348		$	26,802		$	239,403		$	60,930
Net income per common share:
Basic, as reported	$	0.64		$	0.18		$	1.46		$	0.42
Basic, pro-forma	$	0.63		$	0.16		$	1.41		$	0.37
Diluted, as reported	$	0.63		$	0.18		$	1.43		$	0.42
Diluted, pro-forma	$	0.62		$	0.16		$	1.40		$	0.36

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 nine months ended September 30, 2005 and 2004 (in thousands):

	Three months ended				Nine months ended
	September 30,				September 30,
	2005		2004		2005			2004
Net income	$	110,135	$	29,964	$	247,548		$	70,253
Other comprehensive income (expense):
Foreign currency translation adjustment related to our Canadian operations, net of tax		2,286		2,957		(2,942	)		1,066
Comprehensive income, net of tax	$	112,421	$	32,921	$	244,606		$	71,319

5. Property and Equipment

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

	September 30,			December 31,
	2005			2004
Drilling rigs and related equipment	$	1,494,878		$	1,217,497
Other equipment		107,663			83,683
Oil and natural gas properties		77,349			82,711
Buildings		15,770			13,008
Land		5,586			3,949
		1,701,246			1,400,848
Less accumulated depreciation and depletion		(652,685	)		(571,973	)
	$	1,048,561		$	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						Nine months ended
	September 30,						September 30,
	2005			2004			2005			2004
Revenues:
Contract drilling (a)	$	401,626		$	207,808		$	1,028,230		$	577,824
Pressure pumping		27,640			19,663			66,358			48,490
Drilling and completion fluids (b)		29,842			23,475			88,994			65,146
Oil and natural gas		10,234			9,602			28,146			25,104
Total segment revenues		469,342			260,548			1,211,728			716,564
Elimination of intercompany revenues (a)(b)		603			1,374			2,474			4,101
Total revenues	$	468,739		$	259,174		$	1,209,254		$	712,463
Income before income taxes:
Contract drilling	$	163,442		$	39,628		$	369,477		$	95,223
Pressure pumping		7,691			6,199			15,779			12,787
Drilling and completion fluids		2,536			1,100			8,031			2,488
Oil and natural gas		4,098			3,674			10,532			7,217
		177,767			50,601			403,819			117,715
Corporate and other		(4,256	)		(3,193	)		(13,640	)		(6,998	)
Interest income		944			233			2,011			688
Interest expense		(56	)		(75	)		(179	)		(205	)
Other		19			56			39			313
Income before income taxes	$	174,418		$	47,622		$	392,050		$	111,513

	September 30,		December 31,
	2005		2004
Identifiable assets:
Contract drilling	$	1,363,364	$	1,044,147
Pressure pumping		70,527		62,866
Drilling and completion fluids		75,289		38,196
Oil and natural gas		59,780		66,734
		1,568,960		1,211,943
Corporate and other (c)		147,521		110,968
Total assets	$	1,716,481	$	1,322,911

(a)	Includes contract drilling intercompany revenues of approximately $580,000 and $1.4 million for the three months ended September 30, 2005 and 2004, respectively, and approximately $2.3 million and $4.0 million for the nine months ended September 30, 2005 and 2004, respectively.
(b)	Includes drilling and completion fluids intercompany revenues of approximately $23,000 and $20,000 for the three months ended September 30, 2005 and 2004, respectively, and approximately $182,000 and $128,000 for the nine months ended September 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 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 its 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 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.

12

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-
CONTINUED

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 September 30, 2005 and December 31, 2004 is as follows (in thousands):

	September 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

9. Accrued Expenses

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

	September 30,		December 31,
	2005		2004
Salaries, wages, payroll taxes and benefits	$	31,036	$	21,245
Workers’ compensation liability		42,277		38,677
Sales, use and other taxes		11,659		5,863
Insurance, other than workers’ compensation		9,542		7,061
Other		7,979		6,317
	$	102,493	$	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 nine months ended September 30, 2005 and 2004 (in thousands):

	2005			2004
Balance at beginning of year	$	2,358		$	1,163
Liabilities incurred*		61			1,242
Liabilities settled		(801	)		(144	)
Accretion expense		55			52
Asset retirement obligation at end of period	$	1,673		$	2,313

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

13

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-
CONTINUED

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.

     The Company has signed non-cancelable commitments to purchase $93.0 million of equipment to be received throughout 2006.

     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.

12. Stockholders’ Equity

     On February 16, 2005, April 27, 2005 and July 27, 2005, the Company’s Board of Directors approved cash dividends on its common stock in the amount of $0.04 per share. The cash dividends of approximately $6.7 million, $6.8 million and $6.9 million were paid on March 4, 2005, June 1, 2005 and September 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.

13. Subsequent Event

     On October 26, 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 December 1, 2005 to holders of record as of November 15, 2005.

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

     Management Overview— We are a leading provider of contract services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and, to a lesser extent, we provide pressure pumping services and drilling and completion fluid services. In addition to the aforementioned contract services, we also engage in the development, exploration, acquisition and production of oil and natural gas. For the three and nine months ended September 30, 2005 and 2004, our operating revenues consisted of the following (dollars in thousands):

	Three Months Ended								Nine months Ended
	September 30,								September 30,
	2005				2004				2005				2004
Contract drilling	$	401,046	86	%	$	206,454	80	%	$	1,025,938	85	%	$	573,851	81	%
Pressure pumping		27,640	6			19,663	7			66,358	6			48,490	7
Drilling and completion fluids		29,819	6			23,455	9			88,812	7			65,018	9
Oil and natural gas		10,234	2			9,602	4			28,146	2			25,104	3
	$	468,739	100	%	$	259,174	100	%	$	1,209,254	100	%	$	712,463	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 403 rigs as of September 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 third quarter of 2005, our average number of rigs operating increased to 283 from 265 in the second quarter of 2005 and 216 in the third quarter of 2004. Our average revenue per operating day increased to $15,410 in the third quarter of 2005 from $13,690 in the second quarter of 2005 and $10,400 in the third quarter of 2004. Primarily due to these improvements, we experienced an increase of approximately $80 million, or 268%, in consolidated net income for the third quarter of 2005 as compared to the third 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 September 30, 2005, which includes approximately $321 million in working capital (including $131 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.

15

     Commitments and Contingencies— 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.

     The Company has signed non-cancelable commitments to purchase $93.0 million of equipment to be received throughout 2006.

     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 September 30, 2005, we owned 403 drilling rigs. We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. These services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. We provide drilling fluids, completion fluids and related services to oil and natural gas operators 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 equipment¾ 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

16

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 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. There were no impairment charges to property and equipment during the nine months ended September 30, 2005 or 2004.

     Oil and natural gas properties¾ 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 $702,000 and $1.5 million for the three and nine months ended September 30, 2005, respectively, and $891,000 and $3.0 million for the three and nine months ended September 30, 2004, respectively, is included in depreciation, depletion and impairment in the accompanying financial statements.

     The Company adopted Staff Position Financial Accounting Standard 19-1,Accounting for Suspended Well Costs(“FAS 19-1”), on July 1, 2005. At that time, the Company evaluated exploration costs capitalized as wells-in-progress in accordance with FAS 19-1 and determined that no projects with capitalized costs were impaired.

     Changes in exploration costs capitalized as wells-in-progress, excluding costs capitalized and subsequently expensed in the same period, are provided below. Amounts for periods after June 30, 2005 reflect the requirements of FAS 19-1; prior period amounts reflect previous accounting policy (in thousands).

	Period ending
	September 30,			December 31,
	2005			2004			2003
Wells-in-progress, January 1	$	3,860		$	1,166		$	108
Costs impaired upon adoption of FAS 19-1		—			—			—
Exploration costs incurred		2,401			4,903			1,312
Reductions:
Costs related to proved reserves transferred to completed wells		(3,525	)		(1,986	)		(254	)
Costs impaired		—			(223	)		—
Wells-in-progress, end of period	$	2,736		$	3,860		$	1,166

17

      The following table provides the length of time and amount of capitalized exploration costs which are classified as wells-in-progress for each of the respective periods (in thousands).

	Period ending
	September 30,		December 31,
Costs of wells-in-progress:	2005		2004		2003
For one year or less	$	2,736	$	3,860	$	1,166
For more than one year		—		—		—
End of period	$	2,736	$	3,860	$	1,166

     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 recognition¾ 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 estimates¾ 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.

     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 September 30, 2005, we had working capital of approximately $321 million, including cash and cash equivalents of $131 million. For the nine months ended September 30, 2005, our significant sources of cash flow included:

• $322 million provided by operations,

• $42 million from the exercise of stock options, and

• $13 million in proceeds from sales of property and equipment.

18

     We used $74 million to purchase land drilling assets from Key Energy Services, Inc. and six additional land-based drilling rigs, $20 million to pay dividends on the Company’s common stock and $265 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. In September 2005, the Company acquired five land-based drilling rigs and related drilling equipment for $8.2 million. The transactions were accounted for as acquisitions of assets and the purchase price was allocated among the assets acquired based on their estimated fair market values.

     On February 16, 2005, April 27, 2005 and July 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, $6.8 million and $6.9 million were paid on March 4, 2005, June 1, 2005 and September 1, 2005, respectively.

     On October 26, 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 December 1, 2005 to holders of record on November 15, 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 September 30, 2005 and 2004:

Contract Drilling	2005			2004			% Change
	(dollars in thousands)
Revenues	$	401,046		$	206,454			94.3	%
Direct operating costs	$	202,956		$	140,608			44.3	%
Selling, general and administrative	$	1,292		$	1,092			18.3	%
Depreciation	$	33,356		$	25,126			32.8	%
Operating income	$	163,442		$	39,628			312.4	%
Operating days		26,015			19,855			31.0	%
Average revenue per operating day	$	15.41		$	10.40			48.2	%
Average direct operating costs per operating day	$	7.80		$	7.08			10.2	%
Number of owned rigs at end of period		403			361			11.6	%
Average number of rigs owned during period		398			361			10.2	%
Average rigs operating		283			216			31.0	%
Rig utilization percentage		71	%		60	%		18.3	%
Capital expenditures	$	95,539		$	40,511			135.8	%

     Revenues and direct operating costs increased as a result of the increased number of operating days, as well as an increase in the average revenue and average direct operating costs per operating day. Operating days and average rigs operating increased primarily as a result of increased demand for our contract drilling services and the 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. Average direct operating costs per operating day increased primarily as a result of increased wage levels for field personnel. Significant capital expenditures were incurred during the third 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 acquisitions and capital expenditures in 2004 and 2005.

Pressure Pumping	2005		2004		% Change
	(dollars in thousands)
Revenues	$	27,640	$	19,663		40.6	%
Direct operating costs	$	15,662	$	10,455		49.8	%
Selling, general and administrative	$	2,464	$	1,725		42.8	%
Depreciation	$	1,823	$	1,284		42.0	%
Operating income	$	7,691	$	6,199		24.1	%
Total jobs		2,714		2,200		23.4	%
Average revenue per job	$	10.18	$	8.94		13.9	%
Average direct operating costs per job	$	5.77	$	4.75		21.5	%
Capital expenditures	$	5,865	$	3,508		67.2	%

     Revenues and direct operating costs increased as a result of the increased number of jobs, as well as an increase in the average revenue and average direct operating cost per job. The increase in jobs was attributable to increased demand for our services and increased operating capacity which was added in 2004 and 2005. 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 the cost of sand and other materials used in our operations as well as an increase in the number of larger jobs. Selling, general and administrative expenses increased primarily 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 third 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	$	29,819	$	23,455			27.1	%
Direct operating costs	$	24,062	$	19,851			21.2	%
Selling, general and administrative	$	2,402	$	1,965			22.2	%
Depreciation	$	619	$	539			14.8	%
Other expense from operations	$	200		—			N/A	%
Operating income	$	2,536	$	1,100			130.5	%
Total jobs		485		550			(11.8	)%
Average revenue per job	$	61.48	$	42.65			44.2	%
Average direct operating costs per job	$	49.61	$	36.09			37.5	%
Capital expenditures	$	687	$	354			94.1	%

     Revenues and direct operating costs increased 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 jobs completed in the Gulf of Mexico and a decrease in the number of smaller land-based jobs. Selling, general and administrative expense increased in 2005 primarily due to increased incentive compensation resulting from higher profitability levels. Other expense from operations in 2005 includes a charge of $200,000 representing the deductible portion of the Company’s insurance coverage for damage caused by the hurricanes in August and September 2005.

Oil and Natural Gas Production and Exploration	2005		2004		% Change
	(dollars in thousands, except sales prices)
Revenues	$	10,234	$	9,602		6.6	%
Direct operating costs	$	2,365	$	1,715		37.9	%
Selling, general and administrative	$	545	$	484		12.6	%
Depreciation, depletion and impairment	$	3,226	$	3,729		(13.5	)%
Operating income	$	4,098	$	3,674		11.5	%
Capital expenditures	$	3,858	$	2,739		40.9	%
Average net daily oil production (Bbls)		869		1,095		(20.6	)%
Average net daily gas production (Mcf)		6,567		8,203		(19.9	)%
Average oil sales price (per Bbl)	$	60.42	$	42.60		41.8	%
Average gas sales price (per Mcf)	$	7.75	$	6.13		26.4	%

     Revenues increased due to increased market prices for oil and natural gas. Average net daily oil and natural gas production decreased as a result of production declines and the sale of certain oil and natural gas properties during 2005. Depreciation, depletion and impairment expense includes approximately $702,000 and $891,000 of expenses incurred during the three months ended September 30, 2005 and 2004, respectively, to impair certain oil and natural gas properties. Depreciation and depletion further decreased in 2005 as a result of decreased oil and natural gas production.

Corporate and Other	2005		2004			% Change
	(in thousands)
Selling, general and administrative	$	3,868	$	3,043			27.1	%
Bad debt expense	$	50	$	192			(74.0	)%
Depreciation	$	192	$	111			73.0	%
Other (income) expense from operations	$	146	$	(153	)		N/A	%
Interest income	$	944	$	233			305.2	%
Interest expense	$	56	$	75			(25.3	)%
Other income (expense)	$	19	$	56			(66.1	)%

     Selling, general and administrative expenses increased primarily as a result of increased insurance costs, payroll taxes attributable to the exercise of employee stock options, compensation expense related to the issuance of restricted shares to certain key employees in the second quarter of 2005 and professional fees. Other (income) expense from operations in 2005 includes a charge of $675,000 to increase reserves related to the financial failure of a workers’ compensation insurance carrier used previously by the Company. This charge is partially offset by gains recognized on the sale of certain oil and natural gas properties and other equipment. Interest income increased as a result of higher cash balances and interest rates in 2005.

21

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

Contract Drilling	2005			2004			% Change
	(dollars in thousands)
Revenues	$	1,025,938		$	573,851			78.8	%
Direct operating costs	$	558,607		$	402,986			38.6	%
Selling, general and administrative	$	3,719		$	3,267			13.8	%
Depreciation and amortization	$	94,135		$	72,375			30.1	%
Operating income	$	369,477		$	95,223			288.0	%
Operating days		73,746			56,292			31.0	%
Average revenue per operating day	$	13.91		$	10.19			36.5	%
Average direct operating costs per operating day	$	7.57		$	7.16			5.7	%
Number of owned rigs at end of period		403			361			11.6	%
Average number of rigs owned during period		395			358			10.3	%
Average rigs operating		270			205			31.7	%
Rig utilization percentage		68	%		57	%		19.3	%
Capital expenditures	$	224,667		$	111,871			100.8	%

     Revenues and direct operating costs increased as a result of the increased number of operating days, as well as an increase in the average revenue and average direct operating costs per operating day. Operating days and average rigs operating increased primarily as a result of the 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 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 acquisitions and capital expenditures in 2004 and 2005.

Pressure Pumping	2005		2004		% Change
	(dollars in thousands)
Revenues	$	66,358	$	48,490		36.8	%
Direct operating costs	$	38,648	$	26,871		43.8	%
Selling, general and administrative	$	6,858	$	5,182		32.3	%
Depreciation	$	5,073	$	3,650		39.0	%
Operating income	$	15,779	$	12,787		23.4	%
Total jobs		6,968		5,466		27.5	%
Average revenue per job	$	9.52	$	8.87		7.3	%
Average direct operating costs per job	$	5.55	$	4.92		12.8	%
Capital expenditures	$	20,598	$	14,112		46.0	%

     Revenues and direct operating costs increased primarily as a result of the increased number of jobs. The increase in jobs was attributable to increased demand for our services and increased operating capacity which was added in 2004 and 2005. Selling, general and administrative expenses increased primarily 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 2005.

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Drilling and Completion Fluids	2005		2004		% Change
	(dollars in thousands)
Revenues	$	88,812	$	65,018		36.6	%
Direct operating costs	$	71,857	$	55,327		29.9	%
Selling, general and administrative	$	6,964	$	5,550		25.5	%
Depreciation and amortization	$	1,760	$	1,653		6.5	%
Other expense from operations	$	200		—		N/A	%
Operating income	$	8,031	$	2,488		222.8	%
Total jobs		1,515		1,661		(8.8	)%
Average revenue per job	$	58.62	$	39.14		49.8	%
Average direct operating costs per job	$	47.43	$	33.31		42.4	%
Capital expenditures	$	2,039	$	981		107.8	%

     Revenues and direct operating costs increased 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 jobs completed in the Gulf of Mexico and a decrease in the number of smaller land-based jobs. Selling, general and administrative expense increased primarily due to increased incentive compensation resulting from higher profitability levels. Other expense from operations includes a charge of $200,000 representing the deductible portion of the Company’s insurance coverage for damage caused by the hurricanes in August and September 2005.

Oil and Natural Gas Production and Exploration	2005		2004		% Change
	(dollars in thousands, except sales pries)
Revenues	$	28,146	$	25,104		12.1	%
Direct operating costs	$	6,953	$	6,051		14.9	%
Selling, general and administrative	$	1,598	$	1,324		20.7	%
Depreciation, depletion and impairment	$	9,063	$	10,512		(13.8	)%
Operating income	$	10,532	$	7,217		45.9	%
Capital expenditures	$	12,286	$	9,871		24.5	%
Average net daily oil production (Bbls)		854		1,065		(19.8	)%
Average net daily gas production (Mcf)		7,465		7,728		(3.4	)%
Average oil sales price (per Bbl)	$	52.92	$	38.37		37.9	%
Average gas sales price (per Mcf)	$	6.63	$	5.63		17.8	%

     Revenues increased primarily due to increased market prices for oil and natural gas. Average net daily oil and natural gas production decreased as a result of production declines and the sale of certain oil and natural gas properties during 2005. Depreciation, depletion and impairment expense includes approximately $1.5 million and $3.0 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	$	11,036	$	7,694			43.4	%
Bad debt expense	$	416	$	499			(16.6	)%
Depreciation and amortization	$	544	$	333			63.4	%
Other (income) expense from operations	$	1,644	$	(1,528	)		N/A	%
Interest income	$	2,011	$	688			192.3	%
Interest expense	$	179	$	205			(12.7	)%
Other income	$	39	$	313			(87.5	)%
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 2004 and 2005. Other (income) expense from operations in 2005 includes a charge of $3.2 million to increase reserves related to the financial failure of a worker’s compensation insurance carrier used previously by the Company. This charge is partially offset by gains recognized on the sale of certain oil and natural gas properties and other equipment. Interest income increased as a result of higher cash balances and interest rates in 2005.

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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 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 $7.78 in the third 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 283 in the third 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 September 30, 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

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

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

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

• Shortages of drill pipe and other drilling equipment;

• Labor shortages, primarily qualified drilling personnel;

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

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

• Environmental and other governmental regulation.

     For a more complete explanation of these various factors and others, see “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.

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PART II — OTHER INFORMATION

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).
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.

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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: October 28, 2005

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