PATTERSON UTI ENERGY INC - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


[x]		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


		For the quarterly period ended June 30, 2004


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


P. O. BOX 1416, 4510 LAMESA HIGHWAY, SNYDER, TEXAS,		79550
(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 [x]		No [ ]

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


Yes [x]		No [ ]

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

166,888,659 shares of common stock, $0.01 par value, as of August 9, 2004

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,
	2004			2003
ASSETS
Current assets:
Cash and cash equivalents	$	63,353		$	100,483
Accounts receivable, net of allowance for doubtful accounts of $2,959 at June 30, 2004 and $2,133 at December 31, 2003		183,505			156,345
Federal and state income taxes receivable, net		—			12,667
Inventory		15,025			15,206
Deferred tax assets		21,645			16,449
Other		9,819			6,910

Total current assets		293,347			308,060
Property and equipment, at cost, net		785,153			693,631
Goodwill		101,360			51,179
Investment in equity securities		—			19,771
Other		13,914			2,686

Total assets	$	1,193,774		$	1,075,327

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	45,180		$	41,093
Accrued revenue distributions		11,863			8,545
Other		5,165			6,743
Accrued federal income taxes payable		4,301			—
Accrued expenses		51,658			52,066

Total current liabilities		118,167			108,447
Deferred tax liabilities		149,747			142,517
Other		4,906			3,822

Total liabilities		272,820			254,786

Commitments and contingencies		—			—
Stockholders’ equity:
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued		—			—
Common stock, par value $.01; authorized 200,000,000 shares at December 31, 2003 and 300,000,000 shares at June 30, 2004 with 169,971,598 (affected by a two-for-one stock split) and 82,483,148 issued and 166,858,502 (affected by a two-for-one stock split) and 80,976,600 outstanding at June 30, 2004 and December 31, 2003, respectively		1,700			825
Additional paid-in capital		579,314			506,018
Deferred compensation		(6,488	)		—
Retained earnings		354,522			318,419
Accumulated other comprehensive income		5,043			6,934
Treasury stock, at cost, 3,113,096 shares (affected by a two-for-one stock split) and 1,506,548 shares at June 30, 2004 and December 31, 2003, respectively		(13,137	)		(11,655	)

Total stockholders’ equity		920,954			820,541

Total liabilities and stockholders’ equity	$	1,193,774		$	1,075,327

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share amounts)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2004			2003			2004			2003
Operating revenues:
Drilling	$	188,222		$	163,951		$	367,397		$	299,532
Pressure pumping		14,577			9,800			28,827			18,311
Drilling and completion fluids		23,424			16,003			41,563			31,851
Oil and natural gas		8,287			5,870			15,502			11,169

		234,510			195,624			453,289			360,863

Operating costs and expenses:
Drilling		134,387			124,309			262,378			230,737
Pressure pumping		8,328			5,800			16,416			10,806
Drilling and completion fluids		19,837			13,922			35,476			28,303
Oil and natural gas		2,768			1,292			4,336			2,371
Depreciation, depletion, amortization and impairment		30,451			24,973			57,734			49,109
General and administrative		7,910			6,813			14,708			13,707
Bad debt expense		217			82			307			162
Other		(187	)		(720	)		(1,375	)		(3,329	)

		203,711			176,471			389,980			331,866

Operating income		30,799			19,153			63,309			28,997

Other income (expense):
Interest income		204			285			455			545
Interest expense		(54	)		(76	)		(130	)		(148	)
Other		172			319			257			1,660

		322			528			582			2,057

Income before income taxes and cumulative effect of change in accounting principle		31,121			19,681			63,891			31,054

Income tax expense (benefit):
Current		14,655			10,642			19,204			13,762
Deferred		(3,141	)		(3,163	)		4,398			(1,961	)

		11,514			7,479			23,602			11,801

Income before cumulative effect of change in accounting principle		19,607			12,202			40,289			19,253
Cumulative effect of change in accounting principle, net of related income tax benefit of approximately $287		—			—			—			(469	)

Net income	$	19,607		$	12,202		$	40,289		$	18,784

Net income per common share:
Basic:
Income before cumulative effect of change in accounting principle	$	0.12		$	0.08		$	0.24		$	0.12

Cumulative effect of change in accounting principle	$	—		$	—		$	—		$	—

Net income	$	0.12		$	0.08		$	0.24		$	0.12

Diluted:
Income before cumulative effect of change in accounting principle	$	0.12		$	0.07		$	0.24		$	0.12

Cumulative effect of change in accounting principle	$	—		$	—		$	—		$	—

Net income	$	0.12		$	0.07		$	0.24		$	0.11

Weighted average number of common shares outstanding:
Basic		166,681			161,058			165,211			160,694

Diluted		169,062			164,914			168,005			164,218

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY (Unaudited)

(in thousands)


	Common Stock												Accumulated
	Number				Additional								other
	of				paid-in		Deferred			Retained			comprehensive			Treasury
	shares		Amount		capital		compensation			earnings			income			stock			Total
Balance, December 31, 2003		82,483	$	825	$	506,018	$	—		$	318,419		$	6,934		$	(11,655	)	$	820,541
Issuance of common stock		1,388		14		49,462		—			—			—			—			49,476
Issuance of restricted stock		195		2		6,749		(6,751	)		—			—			—			—
Amortization of deferred compensation expense		—		—		—		263			—			—			—			263
Exercise of stock options		920		9		8,689		—			—			—			—			8,698
Tax benefit related to exercise of stock options		—		—		8,396		—			—			—			—			8,396
Foreign currency translation adjustment		—		—		—		—			—			(1,891	)		—			(1,891	)
Purchase of treasury stock		—		—		—		—			—			—			(1,482	)		(1,482	)
Payment of cash dividend (See Note 13)		—		—		—		—			(3,336	)		—			—			(3,336	)
Effect of two-for-one stock split (See Note 13)		84,986		850		—		—			(850	)		—			—			—
Net income		—		—		—		—			40,289			—			—			40,289

Balance, June 30, 2004		169,972	$	1,700	$	579,314	$	(6,488	)	$	354,522		$	5,043		$	(13,137	)	$	920,954

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS (Unaudited)

(in thousands)


	Six Months Ended
	June 30,
	2004			2003
Cash flows from operating activities:
Net income	$	40,289		$	18,784
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and impairment		57,734			49,109
Dry holes and abandonments		815			—
Provision for bad debts		307			162
Deferred income tax expense (benefit)		4,398			(1,961	)
Tax benefit related to exercise of stock options		8,396			5,992
Amortization of deferred compensation		263			—
Gain on sale of property and equipment		(1,375	)		(877	)
Cumulative effect of change in accounting principle, net of tax		—			(469	)
Changes in operating assets and liabilities, net of acquired assets and liabilities assumed:
Accounts receivable		(21,969	)		(36,457	)
Federal and state income taxes		16,953			25,708
Inventory and other current assets		(2,206	)		359
Accounts payable		4,445			7,427
Accrued expenses		(13,333	)		9,852
Other liabilities		(4,033	)		840

Net cash provided by operating activities		90,684			78,469

Cash flows from investing activities:
Acquisitions, net of cash acquired		(32,514	)		(32,783	)
Purchases of property and equipment		(89,723	)		(51,182	)
Proceeds from sales of property and equipment		1,986			1,859
Restricted cash deposited to collateralize retained insurance losses		(11,316	)		—
Change in other assets		—			(1,304	)

Net cash used in investing activities		(131,567	)		(83,410	)

Cash flows from financing activities:
Purchase of treasury stock		(1,482	)		—
Dividends paid		(3,336	)		—
Proceeds from exercise of stock options and warrants		8,698			9,488

Net cash provided by financing activities		3,880			9,488

Net increase (decrease) in cash and cash equivalents		(37,003	)		4,547
Foreign currency translation adjustment		(127	)		755
Cash and cash equivalents at beginning of period		100,483			82,154

Cash and cash equivalents at end of period	$	63,353		$	87,456

Supplemental disclosure of cash flow information:
Net cash received (paid) during the period for:
Interest	$	(130	)	$	(145	)
Income taxes	$	8,000		$	18,530

Non-Cash investing and financing activities:

In February 2004, the Company completed its merger with TMBR/Sharp Drilling, Inc. (“TMBR”) in which one of its wholly-owned subsidiaries acquired 100% of the remaining outstanding shares of TMBR for a net cash payment of approximately $32.5 million ($40.4 million paid to TMBR shareholders less $7.9 million in cash acquired in the transaction) and the issuance of 2.78 million shares of the Company’s common stock valued at $17.82 per share, adjusted to reflect the two-for-one stock split in the form of a stock dividend on June 20, 2004. The assets of TMBR included 18 land-based drilling rigs and related equipment, shop facilities, equipment yards and their oil and natural gas properties. The transaction was accounted for as a business combination and the purchase price was allocated among the assets acquired and liabilities assumed based on their estimated fair market values (See Note 2).

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Consolidation and Presentation

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

The interim condensed consolidated financial statements have been prepared by management of the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles 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 (consisting of only normal recurring accruals) considered necessary for presentation of the information have been included. The unaudited condensed consolidated balance sheet as of December 31, 2003, 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, 2003, as amended.

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 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).

The Company provides a dual presentation of its earnings per share in its Condensed Consolidated Statements of Income: Basic Earnings per Share (“Basic EPS”) and Diluted Earnings per Share (“Diluted EPS”). Basic EPS is computed using the weighted average number of shares outstanding during the periods presented. Diluted EPS includes common stock equivalents, generally stock options and warrants which are dilutive to earnings per share. For the three months ended June 30, 2004 and 2003, dilutive securities included in the calculation of Diluted EPS were 2.4 million shares and 3.9 million shares, respectively. For the six months ended June 30, 2004 and 2003, dilutive securities included in the calculation of Diluted EPS were 2.8 million shares and 3.5 million shares, respectively. For the three and six months ended June 30, 2004, there were 540,000 potentially dilutive options and warrants which were excluded from the calculation of Diluted EPS as their exercise price was greater than the average market price for the period. For the six months ended June 30, 2003, there were 30,000 potentially dilutive options and warrants which were excluded from the calculation of Diluted EPS as their exercise price was greater than the average market price for the period.

On April 28, 2004, the Company’s Board of Directors authorized a two-for-one stock split in the form of a stock dividend which was distributed on June 30, 2004 to holders of record on June 14, 2004. At June 30, 2004, an adjustment was made to reclassify an amount from retained earnings to common stock to account for the par value of the common stock issued as a stock dividend. This adjustment had no overall effect on equity. The June 30, 2003 balance sheet was not restated as a result of this transaction; however, historical earnings per share amounts included in the statements of income and elsewhere in this report have been restated as if the two-for-one stock split had occurred on January 1, 2003.

The results of operations for the three and six months ended June 30, 2004 are not necessarily indicative of the results to be expected for the full year.

Certain reclassifications have been made to the 2003 consolidated financial statements in order for them to conform with the 2004 presentation.

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

2. Recent Acquisitions

On February 11, 2004, the Company completed its merger with TMBR/Sharp Drilling, Inc. (“TMBR”), a Texas corporation, in which one of its wholly-owned subsidiaries acquired 100 % of the remaining outstanding shares of TMBR. Operations of TMBR subsequent to February 11, 2004, are included in the Company’s consolidated financial statements. The transaction was accounted for as a business combination and the purchase price was allocated among the assets acquired and liabilities assumed based on their estimated fair market values. The assets of TMBR included 18 land-based drilling rigs and related equipment, shop facilities, equipment yards and their oil and natural gas properties.

The purchase price was calculated as follows (in thousands, except per share data and exchange ratio):


Cash of $9.09 per share for the 4,447 TMBR shares outstanding at February 11, 2004, excluding the 1,059 TMBR shares owned by Patterson-UTI	$	40,423
Patterson-UTI shares issued at $17.82 per share (4,447 TMBR shares X ..624332 exchange ratio X $17.82) (post stock-split)		49,476
1,059 TMBR shares previously acquired by the Company		19,771
Acquisition costs		12,511
Less: Cash acquired		(7,909	)

Total purchase price	$	114,270

The purchase price was allocated among assets acquired and liabilities assumed based on their estimated fair market values as follows (in thousands):


Current assets	$	6,287
Fixed assets		62,534
Other long term assets		172
Deferred tax assets		11,216
Goodwill		50,181
Current liabilities		(6,382	)
Other long term liabilities		(677	)
Deferred tax liability		(9,061	)

Total purchase allocation	$	114,270

The purchase price allocation is based on preliminary estimates, including estimates of federal tax contingencies, which are subject to change once additional information becomes available. Changes to these estimates could result in changes to the purchase price allocation.

The Company acquired TMBR to increase its productive asset base in the Permian Basin, which is one of the most active land drilling regions in the U.S. TMBR was well established in the contract drilling industry and maintained favorable customer relationships. Goodwill was recognized in the transaction as a result of these factors.

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

2. Recent Acquisitions — (continued)

The following represents pro-forma unaudited financial information as if the merger had been completed on January 1, 2003 (in thousands, except per share amounts):


	Three months		Six months ended
	ended June 30,		June 30,
	2003		2004		2003
Revenue	$	207,757	$	457,876	$	383,019
Income before cumulative effect of change in accounting principle		12,921		39,990		19,615
Net income		12,921		39,990		19,146
Earnings per share:
Basic	$	0.08	$	0.24	$	0.12

Diluted	$	0.08	$	0.24	$	0.12

Since the merger was completed on February 11, 2004, and the results of TMBR have been included subsequent to that date, no pro-forma information for the three months ended June 30, 2004 is necessary.

3. Stock-based Compensation

At June 30, 2004, the Company had seven stock-based employee compensation plans, of which three were active. The Company accounts for those plans under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. During the second quarter of 2004, 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. 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. Compensation expense of $165,000, net of tax, was included 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 cost 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,” to stock-based employee compensation (in thousands, except per share amounts):


	Three months ended						Six months ended
	June 30,						June 30,
	2004			2003			2004			2003
Net income, as reported	$	19,607		$	12,202		$	40,289		$	18,784
Add: Stock-based employee compensation expense recorded		263			—			263			—
Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects		(3,450	)		(2,739	)		(6,424	)		(5,040	)

Pro-forma net income	$	16,420		$	9,463		$	34,128		$	13,744

Net income per common share:
Basic, as reported	$	0.12		$	0.08		$	0.24		$	0.12

Basic, pro-forma	$	0.10		$	0.06		$	0.21		$	0.09

Diluted, as reported	$	0.12		$	0.07		$	0.24		$	0.11

Diluted, pro-forma	$	0.10		$	0.06		$	0.20		$	0.08

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

5. Business Segments

Our revenues, operating profits and identifiable assets are primarily attributable to four business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services and (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,
	2004			2003			2004			2003
Operating revenues:
Drilling	$	188,222		$	163,951		$	367,397		$	299,532
Pressure pumping		14,577			9,800			28,827			18,311
Drilling and completion fluids		23,424			16,003			41,563			31,851
Oil and natural gas		8,287			5,870			15,502			11,169

Total operating revenues	$	234,510		$	195,624		$	453,289		$	360,863

Operating income:
Drilling	$	28,507		$	17,571		$	55,595		$	25,083
Pressure pumping		3,364			1,897			6,588			3,082
Drilling and completion fluids		1,166			(263	)		1,388			(1,157	)
Oil and natural gas		767			1,811			3,543			3,486

		33,804			21,016			67,114			30,494
Corporate and other (a)		(3,005	)		(1,863	)		(3,805	)		(1,497	)

Operating income	$	30,799		$	19,153		$	63,309		$	28,997


	June 30,		December 31,
	2004		2003
Identifiable assets:
Drilling	$	912,260	$	801,109
Pressure Pumping		53,855		46,763
Drilling and completion fluids		33,570		30,860
Oil and natural gas		63,717		33,494
Corporate and other (b)		130,372		163,101

	$	1,193,774	$	1,075,327

(a)		Corporate and other relates to decisions of the executive management group regarding corporate strategy, credit risk, loss contingencies and restructuring activities. Due to the non-operating nature of these decisions, the related income and expenses have been separately presented and excluded from the results of specific segments. These income and expense items primarily relate to the Drilling segment.

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

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

6. Recently Issued Accounting Standards

The Financial Accounting Standards Board issued Interpretation No. 46R, “Consolidation of Variable Interest Entities” (“FIN 46R”) which addresses the consolidation of variable interest entities (“VIEs”) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise that has the majority of the risks or rewards associated with the VIE. The Company believes it has no material interests in VIEs that require disclosure or consolidation under FIN 46R.

7. Goodwill

In accordance with Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” goodwill is evaluated to determine if fair value of the asset has decreased below its carrying value. At December 31, 2003, we performed the annual goodwill evaluation and determined no adjustment to impair goodwill was necessary. With respect to our drilling and completion fluids business, the determination that no impairment existed as of December 31, 2003, was based on our expectations of improvement in the results of operations for that business segment. If the expected improvement in results does not continue to occur, all or part of the goodwill of approximately $10 million associated with that business segment may be determined to be impaired. Goodwill as of June 30, 2004 and December 31, 2003 are as follows (in thousands):


	June 30,		December 31,
	2004		2003
Drilling:
Goodwill at beginning of period	$	41,215	$	41,215
Goodwill in TMBR		50,181		—

Goodwill at end of period		91,396		41,215

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

Total goodwill	$	101,360	$	51,179

8. Restricted Cash

During the second quarter of 2004, the Company entered into an agreement with its workers’ compensation insurance carrier to place restrictions on approximately $11.3 million in cash which is to be used as collateral for losses which may become payable under the terms of the underlying insurance contracts. The agreement restricts the Company from using the cash in operations for an indefinite period; however, the agreement does allow the Company to replace the cash with another form of collateral (such as a letter of credit) acceptable to the insurance carrier. The restricted cash is included in other long-term assets at June 30, 2004.

9. Investment in Equity Securities

During 2002, the Company acquired approximately 19.5% of the outstanding shares of TMBR. Accordingly, the Company accounted for its investment using a method other than the equity method. On February 11, 2004, the Company acquired 100% of the remaining outstanding shares of TMBR. Accordingly, the Company was required to retroactively account for its investment using the equity method of accounting. Therefore, the Company has restated its prior period financial statements to reflect the equity method of accounting for its investment in TMBR for all prior periods.

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

9. Investment in Equity Securities – (continued)

The following table presents the restated balances as of December 31, 2003 and for the three and six months ended June 30, 2003 using the equity method of accounting for its investment in TMBR (in thousands):


	As Previously		As
	Reported		Restated
Balance Sheet as of December 31, 2003:
Investment in equity securities	$	20,274	$	19,771
Accumulated other comprehensive income		8,554		6,934
Deferred tax liability		143,490		142,517
Retained earnings		316,329		318,419


	Three months ended						Six months ended
	June 30, 2003						June 30, 2003
	As						As
	Previously			As			Previously			As
	Reported			Restated			Reported			Restated
Comprehensive Income
Comprehensive income		17,341			16,372			26,094			25,855
Income Statement
Other income		77			319			85			1,660
Deferred income tax expense		(3,255	)		(3,163	)		(2,560	)		(1,961	)
Net income		12,052			12,202			17,808			18,784
Net income per common share:
Basic	$	0.07		$	0.08		$	0.11		$	0.12

Diluted	$	0.07		$	0.07		$	0.11		$	0.11

10. Accrued Expenses

Accrued expenses consisted of the following at June 30, 2004, and December 31, 2003 (in thousands):


	June 30,		December 31,
	2004		2003
Salaries, wages, payroll taxes and benefits.	$	13,254	$	15,740
Workers’ compensation liability		22,569		22,859
Contingent liabilities		5,194		2,335
Sales, use and other taxes		5,961		5,796
Insurance, other than workers’ compensation		1,458		1,848
Restructuring and merger related costs		1,000		1,000
Other		2,222		2,488

	$	51,658	$	52,066

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

11. Asset Retirement Obligation

The FASB issued Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), in June 2001. SFAS No. 143 requires that, beginning in 2003, we record a liability for the estimated costs to be incurred in connection with the abandonment of oil and natural gas properties in the future. We recorded a liability of approximately $1.1 million in the first quarter of 2003 upon initial adoption of SFAS No. 143. The following table describes the changes to our asset retirement obligations during the first six months of 2004 (in thousands):


Balance at December 31, 2003	$	1,163
Liabilities incurred*		1,209
Liabilities settled		(121	)
Accretion expense		33

Balance at June 30, 2004	$	2,284

* Includes $1,091 related to TMBR acquisition.

A charge of $469,000 (net of tax) was recorded as a cumulative effect of a change in accounting principle for the quarter ended March 31, 2003. The change relates to the cost associated with the future abandonment of oil and natural gas properties. There was no effect on diluted earnings per share as a result of the change in accounting principle for the three and six months ended June 30, 2003.

12. Commitments, Contingencies and Other Matters

During the second quarter of 2004, the Company entered into an agreement with its workers’ compensation insurance carrier to place restrictions on approximately $11.3 million in cash which is to be used as collateral for losses which may become payable under the terms of the underlying insurance contracts. The agreement restricts the Company from using the cash in operations for an indefinite period, however, the agreement does allow the Company to replace the cash with another form of collateral (such as a letter of credit) acceptable to the insurance carrier. The restricted cash is included in other long-term assets at June 30, 2004.

The Company maintains letters of credit in the aggregate amount of $38.0 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire at various times during each calendar year. No amounts have been drawn under the letters of credit.

Westfort Energy LTD and Westfort Energy (US) LTD f/k/a Canadian Delta, Inc. (“Westfort”), filed a lawsuit against two of the Company’s subsidiaries, Patterson Petroleum LP and Patterson Drilling Company LP, in the Circuit Court, Rankin County, Mississippi, Case No. 2002-18. The lawsuit relates to a letter agreement entered into in July 2000 between Patterson Petroleum LP and Westfort concerning the drilling of a daywork well in Mississippi (the “Well”). This lawsuit was filed by Westfort after Patterson Petroleum LP made demand on Westfort for payment of the contract drilling services. Westfort’s lawsuit has been dismissed without prejudice. In its lawsuit, Westfort alleged breach of contract, fraud, and negligence causes of action. Westfort sought alleged monetary damages, the return of shares of Westfort stock, unspecified damages from alleged lost profits, lost use of income stream, and additional operating expenses, along with alleged punitive damages to be determined by the jury, but not less than 25% of the Company’s net worth.

Patterson Petroleum LP, LLLP and Patterson-UTI Drilling Company LP, LLLP, subsidiaries of the Company, filed a lawsuit against Westfort to collect monies owed concerning the drilling of the Well and to foreclose the lien filed by the subsidiaries. The Westfort entities filed for bankruptcy in May 2003. The Westfort bankruptcies were dismissed with prejudice in April 2004. On June 30, 2004, the subsidiaries of the Company obtained an Agreed Judgment against Westfort for approximately $5.1 million, plus attorneys’ fees, post-judgment interest, recognition

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

12. Commitments, Contingencies and Other Matters – (continued)

of the lien, and order of sale. These amounts are not reflected in the Company’s consolidated financial statements for the period ended June 30, 2004 and other amounts which have been deemed uncollectible have been reserved.

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.

13. Stockholders’ Equity

On April 28, 2004, the Company’s Board of Directors authorized a two-for-one stock split in the form of a stock dividend which was distributed on June 30, 2004 to holders of record on June 14, 2004. At June 30, 2004, an adjustment was made to reclassify an amount from retained earnings to common stock to account for the par value of the common stock issued as a stock dividend. This adjustment had no overall effect on equity. The prior year balance sheet was not restated as a result of this transaction; however, historical earnings per share amounts included in the statements of income and elsewhere in this report have been restated as if the two-for-one stock split had occurred on January 1, 2003.

On April 28, 2004, the Company’s Board of Directors approved the initiation of a quarterly cash dividend on each share of the Company’s common stock. The first quarterly dividend in the amount of $0.02 per share, or approximately $3.3 million was paid to holders of record on May 17, 2004 and paid on June 2, 2004. The amount and timing of all dividend payments is, however, subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors.

On June 7, 2004, the Company’s Board of Directors authorized a stock buyback program for the purchase of up to $30 million of outstanding shares of the Company’s common stock. During the second quarter of 2004, the Company purchased 100,000 shares of its common stock in the open market for approximately $1.5 million. These shares are included in treasury stock at June 30, 2004.

During the second quarter of 2004, the Company granted the Restricted Shares to certain key employees under the Patterson-UTI Energy, Inc. 1997 Long-Term Incentive Plan, as amended. 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. Compensation expense of $165,000, net of tax, was included in net income for the three and six months ended June 30, 2004.

14. Subsequent Event

On June 28, 2004, the Company’s Board of Directors approved a cash dividend on each share of its common stock in the amount of $0.02 per share. The dividend is to be paid to holders of record on August 16, 2004 and paid on September 1, 2004.

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, 2004 and 2003, our operating revenues consisted of the following (dollars in thousands):


	Three Months Ended								Six Months Ended
	June 30,								June 30,
	2004				2003				2004				2003
Contract drilling	$	188,222	80	%	$	163,951	84	%	$	367,397	81	%	$	299,532	83	%
Pressure pumping		14,577	6			9,800	5			28,827	6			18,311	5
Drilling and completion fluids		23,424	10			16,003	8			41,563	9			31,851	9
Oil and natural gas		8,287	4			5,870	3			15,502	4			11,169	3

	$	234,510	100	%	$	195,624	100	%	$	453,289	100	%	$	360,863	100	%

We provide our contract services to oil and natural gas operators in North America. Our contract drilling operations are focused in various regions of Texas, New Mexico, Oklahoma, Louisiana, Mississippi, Colorado, Utah, Wyoming 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, New Mexico, Oklahoma, the Gulf Coast regions of Texas and Louisiana and the Gulf of Mexico. Our oil and natural gas operations are primarily focused in Texas, New Mexico and Mississippi.

We have been a leading consolidator of the domestic land-based contract drilling industry over the past several years increasing our drilling fleet to 361 rigs, which we believe is the second largest drilling fleet in North America. Growth by acquisition has been a corporate strategy intended to expand both revenues and market share.

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 2004, our average number of rigs operating increased to 203 (including an average of ten rigs acquired from TMBR) from 197 (including an average of five rigs acquired from TMBR) in the first quarter of 2004 and 195 in the second quarter of 2003. Our average revenue per operating day increased to $10,190 in the second quarter of 2004 from $9,970 in the first quarter of 2004 and $9,240 in the second quarter of 2003.

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. Our operations are also impacted by competition, the availability of excess equipment, labor shortages 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, 2003, as amended, beginning on page 15.

Management believes that the liquidity of our balance sheet as of June 30, 2004, which includes approximately $175 million in working capital (including $63 million in cash), no long term debt and $62 million available under our existing $100 million line of credit (availability of $38 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.

Commitments and Contingencies — During the second quarter of 2004, the Company entered into an agreement with its workers’ compensation insurance carrier to place restrictions on approximately $11.3 million in cash which is to be used as collateral for losses which may become payable under the terms of the underlying insurance contracts. The agreement restricts the Company from using the cash in operations for an indefinite period, however, the agreement does allow the Company to replace the cash with another form of collateral (such as a letter of credit) acceptable to the insurance carrier. The restricted cash is included in other long-term assets at June 30, 2004.

We have no other commitments or contingencies which require disclosure in our financial statements other than letters of credit totaling $38.0 million at June 30, 2004, 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 — As a leading provider of onshore contract drilling services, we currently own 361 land-based drilling rigs. Our pressure pumping services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. Our drilling and completion fluids services are used 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.

The contract drilling business experienced many downturns in demand over the last several years. During these periods, there have been substantially more drilling rigs available than necessary to meet demand in most operational and geographic segments of the North American land drilling industry. As a result, drilling contractors have had difficulty sustaining profit margins.

In addition to adverse effects that future declines in demand could have on the Company, 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, intangible assets, revenue recognition, and the use of estimates.

Property and equipment — 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 the 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, including intangible 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 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 six months ended June 30, 2004 or 2003.

Oil and natural gas properties — 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 determinations are made. In accordance with Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” (“SFAS No. 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. The Company reviews its 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. The Company’s 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 $1.7 million and $2.2 million for the three and six months ended June 30, 2004, respectively, is included in depreciation, depletion, amortization and impairment in the accompanying financial statements.

Intangible assets — Intangible assets consist of goodwill arising from business combinations. Intangible assets such as goodwill are considered to have indefinite useful economic lives and are not amortized until their lives are determined to be finite. 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. With respect to our drilling and completion fluids business, the determination that no impairment existed as of December 31, 2003, was based on our expectations of improvement in the results of operations for that business segment. If the expected improvement in results does not continue to occur, all or part of the goodwill of approximately $10 million associated with that business segment may be determined to be impaired.

Revenue recognition — 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. The Company follows 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, the Company follows the completed contract method of accounting for such arrangements. Under this method, all drilling advances and costs related to a well in progress are deferred and recognized as revenues and expenses in the period the well is completed. Provisions for losses on incomplete or in-process wells are made when estimated total costs are expected to exceed estimated total revenues.

In accordance with Emerging Issues Task Force Issue No. 00-14, the Company recognizes reimbursements received from third parties for out-of-pocket expenses incurred by the Company as revenues and accounts for out-of-pocket expenses as direct costs.

Use of estimates — The preparation of financial statements in conformity with generally accepted accounting principles 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.

Liquidity and Capital Resources

As of June 30, 2004, we had working capital of approximately $175.2 million, including cash and cash equivalents of $63 million. For the six months ended June 30, 2004, our significant sources of cash flow were approximately:

• $91 million provided by operations,

• $9 million from the exercise of stock options and warrants, and

• $2 million from the proceeds from sales of property and equipment.

We used approximately $33 million to acquire the remaining outstanding shares of TMBR and approximately $90 million:

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

• for the acquisition and procurement of 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.

Additionally, approximately $3.3 million was used to pay dividends on the Company’s common stock and approximately $1.5 million was used to buy back 100,000 shares (post stock-split) of the Company’s common stock pursuant to the stock buyback program authorized by the Company’s Board of Directors on June 7, 2004. Furthermore, restrictions on the Company’s use of approximately $11.3 million were put into place during the second quarter of 2004 as the Company pledged this cash as collateral for losses which could become payable under the terms of its workers’ compensation insurance contracts.

In February 2004, the Company completed its merger with TMBR in which one of the Company’s wholly-owned subsidiaries acquired 100% of the remaining outstanding shares of TMBR for a net cash payment of approximately $33 million ($40.4 million paid to TMBR shareholders less $7.9 million in cash acquired in the transaction) and the issuance of 2.78 million shares (post stock-split) of the Company’s common stock valued at $17.82 per share (post stock-split). The assets of TMBR included 18 land-based drilling rigs and related equipment, shop facilities, equipment yards and their oil and natural gas properties. The transaction was accounted for as a business combination and the purchase price was allocated among the assets acquired and liabilities assumed based on their estimated fair market values.

On April 28, 2004, the Company’s Board of Directors approved the initiation of a quarterly cash dividend on each share of the Company’s common stock. The first quarterly dividend in the amount of $0.02 per share (post stock-split), or approximately $3.3 million was paid to holders of record on May 17, 2004 and paid on June 2, 2004. On July 28, 2004, our Board of Directors approved a cash dividend of $0.02 per share on each share of our common stock to be paid on September 1, 2004 to holders of record on August 16, 2004. The amount and timing of all dividend payments is, however, subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions 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 reviewed. The timing, size or success of any acquisition and the associated capital commitments are unpredictable. Over the longer term, should further 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, and either debt or equity financing. However, there can be no assurance that such capital would be available.

Commitments, Contingencies and Other Matters

During the second quarter of 2004, the Company entered into an agreement with its workers’ compensation insurance carrier to place restrictions on approximately $11.3 million in cash which is to be used as collateral for losses which may become payable under the terms of the underlying insurance contracts. The agreement restricts the Company from using the cash in operations for an indefinite period, however, the agreement does allow the Company to replace the cash with another form of collateral (such as a letter of credit) acceptable to the insurance carrier. The restricted cash is included in other long-term assets at June 30, 2004.

Results of Operations

The following tables summarize operations by business segment for the three months ended June 30, 2004 and 2003:


Contract Drilling	2004			2003			% Change
	(dollars in thousands)
Revenues	$	188,222		$	163,951			14.8	%
Direct operating costs	$	134,387		$	124,309			8.1	%
Selling, general, and administrative	$	1,080		$	1,094			(1.3	)%
Depreciation and amortization	$	24,248		$	20,977			15.6	%
Operating income	$	28,507		$	17,571			62.2	%
Operating days		18,473			17,742			4.1	%
Average revenue per operating day	$	10.19		$	9.24			10.3	%
Average direct operating costs per operating day	$	7.27		$	7.01			3.9	%
Number of owned rigs at end of period		361			340			6.2	%
Average number of rigs owned during period		361			334			8.1	%
Average rigs operating		203			195			4.1	%
Rig utilization percentage		56	%		58	%		(3.4	)%
Capital expenditures	$	42,980		$	27,400			56.9	%

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. Revenue per operating day increased as a result of increased pricing for our drilling services. Direct operating costs per operating day increased primarily as a result of field personnel pay increases implemented in late 2003. Significant capital expenditures were incurred during the second quarter of 2004 to modify and upgrade our existing drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating systems and various safety enhancement equipment. Increased depreciation expense was due to significant capital expenditures, including the acquisition of 19 drilling rigs and related equipment during 2003 and 18 drilling rigs and related equipment acquired during the first quarter of 2004.


Pressure Pumping	2004		2003		% Change
	(dollars in thousands)
Revenues	$	14,577	$	9,800		48.7	%
Direct operating costs	$	8,328	$	5,800		43.6	%
Selling, general, and administrative	$	1,664	$	1,245		33.7	%
Depreciation	$	1,221	$	858		42.3	%
Operating income	$	3,364	$	1,897		77.3	%
Total jobs		1,578		1,246		26.6	%
Average revenue per job	$	9.24	$	7.87		17.4	%
Average direct operating costs per job	$	5.28	$	4.65		13.5	%
Capital expenditures	$	4,782	$	2,406		98.8	%

Revenues and direct operating costs increased as a result of the increased number of jobs, as well as an increase in the average revenue and average direct operating costs per job. The increase in jobs in the quarter was largely due to the Company’s continued growth in the Appalachian regions of Kentucky, Tennessee and West Virginia. General and administrative expenses increased as a result of the expanding operations of the pressure pumping segment. Increased depreciation expense for the 2004 quarter was largely due to the expansion of the pressure pumping segment during 2003 and 2004 and related expenditures to acquire necessary equipment to facilitate the growth. Capital expenditures increased in 2004 compared to 2003 due to further expansion of services into Tennessee as well as equipment modifications and upgrades.


Drilling and Completion Fluids	2004		2003			% Change
	(dollars in thousands)
Revenues	$	23,424	$	16,003			46.4	%
Direct operating costs	$	19,837	$	13,922			42.5	%
Selling, general, and administrative	$	1,875	$	1,771			5.9	%
Depreciation and amortization	$	546	$	573			(4.7	)%
Operating income (loss)	$	1,166	$	(263	)		N/A	%
Total jobs		593		515			15.1	%
Average revenue per job	$	39.50	$	31.07			27.1	%
Average direct operating costs per job	$	33.45	$	27.03			23.8	%
Capital expenditures	$	416	$	146			184.9	%

Revenues and direct operating costs increased during the second quarter of 2004 compared to the second quarter of 2003 primarily as a result of the increased number of jobs, as well as an increase in the average revenue and average direct operating costs per job. Average revenue and direct operating costs per job increased as a result of an increase in the number of larger jobs in the Gulf of Mexico.


Oil and Natural Gas Production and Exploration	2004		2003		% Change
	(dollars in thousands, except sales pries)
Revenues	$	8,287	$	5,870		41.2	%
Direct operating costs	$	2,768	$	1,292		114.2	%
Selling, general, and administrative	$	427	$	350		22.0	%
Depreciation, depletion and impairment	$	4,325	$	2,417		78.9	%
Operating income	$	767	$	1,811		(57.6	)%
Capital expenditures	$	3,600	$	2,166		66.2	%
Average net daily oil production (Bbls)		1,171		797		46.9	%
Average net daily gas production (Mcf)		7,335		6,469		13.4	%
Average oil sales price (per Bbl)	$	37.94	$	29.27		29.6	%
Average gas sales price (per Mcf)	$	5.31	$	5.52		(3.8	)%

Oil and natural gas revenues and direct operating costs increased in the second quarter of 2004 compared to the second quarter of 2003, primarily due to the acquisition of the oil and natural gas properties acquired in the merger with TMBR during February 2004 and increased market prices received for oil during the second quarter of 2004. Direct operating costs further increased as a result of $815,000 of dry hole costs incurred during the 2004 quarter. Depreciation, depletion and impairment expense increased in 2004 primarily as a result of approximately $1.7 million of expenses incurred to impair certain oil and natural gas properties during the quarter.


Corporate and Other	2004		2003		% Change
	(in thousands)
Selling, general, and administrative	$	2,864	$	2,353		21.7	%
Bad debt expense	$	217	$	82		164.6	%
Depreciation and amortization	$	111	$	148		(25.0	)%
Other income from operations	$	187	$	720		(74.0	)%
Interest income	$	204	$	285		(28.4	)%
Interest expense	$	54	$	76		(28.9	)%
Other income	$	172	$	319		(46.1	)%

Selling, general and administrative expenses increased as a result of increased professional expenses and additional compensation expense of $263,000 related to the Company’s issuance of restricted shares to certain key employees of the Company. Bad debt expense increased in 2004 as management increased its allowance for uncollectible accounts.

The following tables summarize operations by business segment for the six months ended June 30, 2004 and 2003:


Contract Drilling	2004			2003			% Change
	(dollars in thousands)
Revenues	$	367,397		$	299,532			22.7	%
Direct operating costs	$	262,378		$	230,737			13.7	%
Selling, general, and administrative	$	2,175		$	2,229			(2.4	)%
Depreciation and amortization	$	47,249		$	41,483			13.9	%
Operating income	$	55,595		$	25,083			121.6	%
Operating days		36,437			33,611			8.4	%
Average revenue per operating day	$	10.08		$	8.91			13.1	%
Average direct operating costs per operating day	$	7.20		$	6.87			4.8	%
Number of owned rigs at end of period		361			340			6.2	%
Average number of rigs owned during period		357			331			7.9	%
Average rigs operating		200			186			7.5	%
Rig utilization percentage		56	%		56	%		—	%
Capital expenditures	$	71,360		$	40,939			74.3	%

Revenues and direct operating costs increased as a result of the increased number of operating days, as well as an increase in the average revenue and average direct operating costs per operating day. Revenue per operating day increased as a result of increased pricing for our drilling services. Direct operating costs per operating day increased primarily as a result of field personnel pay increases implemented in late 2003. Significant capital expenditures were incurred during the first six months of 2004 to modify and upgrade our existing drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating systems and various safety enhancement equipment. Increased depreciation expense was due to significant capital expenditures, including the acquisition of 19 drilling rigs and related equipment during 2003 and 18 drilling rigs and related equipment acquired during the first quarter of 2004.


Pressure Pumping	2004		2003		% Change
	(dollars in thousands)
Revenues	$	28,827	$	18,311		57.4	%
Direct operating costs	$	16,416	$	10,806		51.9	%
Selling, general, and administrative	$	3,457	$	2,756		25.4	%
Depreciation	$	2,366	$	1,667		41.9	%
Operating income	$	6,588	$	3,082		113.8	%
Total jobs		3,266		2,307		41.6	%
Average revenue per job	$	8.83	$	7.94		11.2	%
Average direct operating costs per job	$	5.03	$	4.68		7.5	%
Capital expenditures	$	10,604	$	6,119		73.3	%


Drilling and Completion Fluids	2004		2003			% Change
	(dollars in thousands)
Revenues	$	41,563	$	31,851			30.5	%
Direct operating costs	$	35,476	$	28,303			25.3	%
Selling, general, and administrative	$	3,585	$	3,548			1.0	%
Depreciation and amortization	$	1,114	$	1,157			(3.7	)%
Operating income (loss)	$	1,388	$	(1,157	)		N/A	%
Total jobs		1,111		1,001			11.0	%
Average revenue per job	$	37.41	$	31.82			17.6	%
Average direct operating costs per job	$	31.93	$	28.27			12.9	%
Capital expenditures	$	627	$	277			126.4	%

Revenues and direct operating costs increased during the first six months of 2004 compared to the first six months of 2003 primarily as a result of the increased number of jobs, as well as an increase in the average revenue and average direct operating costs per job. Average revenue and direct operating costs per job increased as a result of an increase in the number of larger jobs in the Gulf of Mexico.


Oil and Natural Gas Production and Exploration	2004		2003		% Change
	(dollars in thousands, except sales pries)
Revenues	$	15,502	$	11,169		38.8	%
Direct operating costs	$	4,336	$	2,371		82.9	%
Selling, general, and administrative	$	840	$	732		14.8	%
Depreciation, depletion and impairment	$	6,783	$	4,580		48.1	%
Operating income	$	3,543	$	3,486		1.6	%
Capital expenditures	$	7,132	$	4,316		65.2	%
Average net daily oil production (Bbls)		1,050		776		35.3	%
Average net daily gas production (Mcf)		7,488		5,943		26.0	%
Average oil sales price (per Bbl)	$	36.14	$	31.36		15.2	%
Average gas sales price (per Mcf)	$	5.35	$	5.35		—	%

Oil and natural gas revenues and direct operating costs increased in the first six months of 2004 compared to the first six months of 2003, primarily due to the acquisition of the oil and natural gas properties acquired in the merger with TMBR during February 2004 and increased market prices received for oil during the first six months of 2004. Direct operating costs further increased as a result of $815,000 of dry hole costs incurred during the 2004 period. Depreciation, depletion and impairment expense increased in 2004 primarily as a result of approximately $2.2 million of expenses incurred to impair certain oil and natural gas properties.


Corporate and Other	2004		2003		% Change
	(in thousands)
Selling, general, and administrative	$	4,651	$	4,442		4.7	%
Bad debt expense	$	307	$	162		89.5	%
Depreciation and amortization	$	222	$	222		—	%
Other income from operations	$	1,375	$	3,329		(58.7	)%
Interest income	$	455	$	545		(16.5	)%
Interest expense	$	130	$	148		(12.2	)%
Other income	$	257	$	1,660		(84.5	)%

Bad debt expense increased as management increased its allowance for uncollectible accounts. Other income from operations in 2004 includes approximately $1.4 million from the sale of used equipment. In 2003, other income from operations includes a $2.5 million payment received as settlement for contract drilling services previously provided in Mexico by Norton Drilling Company Mexico, Inc., a wholly-owned subsidiary of the Company. The receivable had been reserved as uncollectible at the time of the Company’s acquisition of Norton Drilling Company Mexico, Inc. in 1999. Other income in 2003 includes approximately $1.6 million representing the

Company’s pro rata share of the net income of TMBR for that six month period, using the equity method of accounting.

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. Historically, oil and natural gas prices and markets have been volatile. Prices are affected by market supply and demand factors as well as actions of state and local agencies, the United States and foreign governments, and international cartels. 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 to $5.45 in 2003 compared to $3.36 in 2002, resulting in an increase in demand for our drilling services. Our average number of rigs operating increased to 188 in 2003 from 126 in 2002. During the second quarter of 2004, the average market price of natural gas was $5.55 per Mcf and our average number of rigs operating increased to 203 (including an average of ten rigs acquired from TMBR). 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.

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 significant exposure to interest rate market risk because 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 1.75 % to 2.75%. The applicable rate above LIBOR (1.75% at June 30, 2004) is based upon our trailing twelve-month EBITDA (earnings before interest expense, income taxes, and depreciation, depletion, and amortization expense). 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 over the last ten 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

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 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 Quarterly Report on Form 10-Q, 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 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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, 2003, as amended, beginning on page 15.

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

PART II — OTHER INFORMATION

ITEM 1. Legal Proceeding.

ITEM 2. Changes in Securities and Use of Proceeds.

The following table summarizes common stock purchased during the second quarter of 2004 (post stock-split):

(d) Maximum

Number (or

(c) Total Number

Approximate

of Shares

Dollar Value) of

Purchase as Part

Shares (of Units)

(a) Total Number

(b) Average Price

of Publicly

That May Yet Be

of Shares

Paid

Announced

Purchased Under the

Purchased

Per Share

Plans or Programs

Plans or Programs(1)

June 9, 2004

100,000

14.82

100,000

28,518,000

(1) On June 7, 2004, the Company’s Board of Directors authorized a stock buyback program for the purchase of up to $30 million of outstanding shares of the Company’s common stock.

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

On June 29, 2004, 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. An amendment to the Company’s Restated Certificate of Incorporation to increase the authorized shares of the Company’s common stock from 200,000,000 shares to 300,000,000 shares.

3. Re-approval of the criteria upon which performance objectives are currently based in the Company’s Amended and Restated 1997 Long-Term Incentive Plan (the “1997 Plan”).

4. An amendment to the 1997 Plan to increase the aggregate annual amount of cash that may be received as a performance award by a participant under the 1997 Plan and to amend the criteria upon which performance objectives are currently based in the 1997 Plan.

5. Ratification of the appointment of PricewaterhouseCoopers LLP as the independent accountants of the Company for the fiscal year ending December 31, 2004.

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		76,697,198		2,219,885
Cloyce A. Talbott		76,753,043		2,164,040
A. Glenn Patterson		76,705,317		2,211,766
Kenneth N. Berns		74,815,566		4,101,517
Robert C. Gist		75,112,777		3,804,306
Curtis W. Huff		76,500,309		2,416,774
Terry H. Hunt		76,494,465		2,422,618
Kenneth R. Peak		77,474,444		1,442,639
Nadine C. Smith		77,475,191		1,441,892


							Broker
	Votes For		Votes Against		Abstentions		Non-votes
2. Amendment to the Company’s Restated Certificate of Incorporation		76,257,778		2,314,558		344,747		0


							Broker
	Votes For		Votes Against		Abstentions		Non-votes
3. Approval of the criteria upon which performance objectives are currently based in the 1997 Plan		62,880,881		3,258,830		833,438		11,943,934


							Broker
	Votes For		Votes Against		Abstentions		Non-votes
4. Amendment to the 1997 Plan and approval of the criteria upon which performance objectives are currently based in the 1997 Plan		61,643,497		4,493,387		836,265		11,943,934


	Votes For		Votes Against		Abstentions		Broker Non-votes
5. Ratification of PricewaterhouseCoopers LLP as the Company’s Independent Accountants		76,864,634		1,739,274		313,175		0

ITEM 6. Exhibits and Reports on Form 8-K

(a) Exhibits.

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

3.1 Restated Certificate of Incorporation, as amended.*

3.2 Amendment to Restated Certificate of Incorporation.*

3.3 Amended and Restated Bylaws. ⁽²⁾

10.1 Restricted Stock Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Mark S. Siegel (Chairman of the Board and Director of Patterson-UTI Energy, Inc.) *

10.2 Restricted Stock Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (Chief Executive Officer and Director of Patterson-UTI Energy, Inc.)*

10.3 Restricted Stock Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and A. Glenn Patterson (President, Chief Operating Officer and Director of Patterson-UTI Energy, Inc.)*

10.4 Restricted Stock Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Kenneth N. Berns (Senior Vice President and Director of Patterson-UTI Energy, Inc.)*

10.5 Restricted Stock Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Jonathan D. Nelson (Vice President, Chief Financial Officer, Secretary and Treasurer of Patterson-UTI Energy, Inc.)*

10.6 Restricted Stock Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and John E. Vollmer III (Senior Vice President – Corporate Development of Patterson-UTI Energy, Inc.)*

10.7 Amendment to the Amended and Restated 1997 Long-Term Incentive Plan.*

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.*

*		Filed herewith.

(1)		Incorporated herein by reference to Item 6, “Exhibits and Reports on Form 8-K” to Form 10-Q for the quarterly period ended June 30, 2003.

(2)		Incorporated herein by reference to Item 14, “Exhibits, Financial Statement Schedules and Reports on Form 8-K” to Annual Report on Form 10-K for the fiscal year ended December 31, 2001.

(b) Reports on Form 8-K.

On June 7, 2004, the Company furnished a Current Report on Form 8-K, dated June 7, 2004, furnishing the Company’s public announcement relating to authorization by the Board of Directors of a stock buyback program for the purchase of up to $30 million of the Company’s outstanding common stock.

On April 29, 2004, the Company furnished a Current Report on Form 8-K, dated April 28, 2004, furnishing the Company’s public announcement of a quarterly cash dividend and declaration of a two-for-one stock split as well as its financial results for the quarter ended March 31, 2004, including the Condensed Consolidated Statements of Income and Additional Financial and Operating Data.


	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		16
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		25
ITEM 4. Controls and Procedures		25
Forward Looking Statements and Cautionary Statements for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995		26
PART II — Other Information
ITEM 1. Legal Proceeding		27
ITEM 2. Changes in Securities and Use of Proceeds		27
ITEM 4. Submission of Matters to a Vote of Security Holders		27
ITEM 6. Exhibits and Reports on Form 8-K		28
Signatures		30
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certification of CEO & CFO Pursuant to Section 906
Restated Certificate of Incorporation
Amendment to Restated Certificate of Incorporation
Restricted Stock Agreement - Mark S. Siegel
Restricted Stock Agreement - Cloyce A. Talbott
Restricted Stock Agreement - A. Glenn Patterson
Restricted Stock Agreement - Kenneth N. Berns
Restricted Stock Agreement - Jonathan D. Nelson
Restricted Stock Agreement - John E. Vollmer III
Amendment to the Amended and Restated 1997 Long-Term Incentive Plan
Certication of Chief Executive Officer
Certication of Chief Financial Officer
Certification of CEO and CFO Pursuant to Section 906


	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

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12.		Commitments, Contingencies and Other Matters – (continued)

		of the lien, and order of sale. These amounts are not reflected in the Company’s consolidated financial statements for the period ended June 30, 2004 and other amounts which have been deemed uncollectible have been reserved.

•		movement of drilling rigs from region to region,

•		reactivation of land-based drilling rigs, or

•		new construction of drilling rigs.

•		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.

•		$91 million provided by operations,

•		$9 million from the exercise of stock options and warrants, and

•		$2 million from the proceeds from sales of property and equipment.

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

•		for the acquisition and procurement of 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.

•		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.

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

2.		An amendment to the Company’s Restated Certificate of Incorporation to increase the authorized shares of the Company’s common stock from 200,000,000 shares to 300,000,000 shares.

3.		Re-approval of the criteria upon which performance objectives are currently based in the Company’s Amended and Restated 1997 Long-Term Incentive Plan (the “1997 Plan”).

4.		An amendment to the 1997 Plan to increase the aggregate annual amount of cash that may be received as a performance award by a participant under the 1997 Plan and to amend the criteria upon which performance objectives are currently based in the 1997 Plan.

5.		Ratification of the appointment of PricewaterhouseCoopers LLP as the independent accountants of the Company for the fiscal year ending December 31, 2004.

3.1		Restated Certificate of Incorporation, as amended.*

3.2		Amendment to Restated Certificate of Incorporation.*

3.3		Amended and Restated Bylaws. ⁽²⁾

10.1		Restricted Stock Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Mark S. Siegel (Chairman of the Board and Director of Patterson-UTI Energy, Inc.) *

10.2		Restricted Stock Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (Chief Executive Officer and Director of Patterson-UTI Energy, Inc.)*

10.3		Restricted Stock Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and A. Glenn Patterson (President, Chief Operating Officer and Director of Patterson-UTI Energy, Inc.)*

10.4		Restricted Stock Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Kenneth N. Berns (Senior Vice President and Director of Patterson-UTI Energy, Inc.)*

10.5		Restricted Stock Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Jonathan D. Nelson (Vice President, Chief Financial Officer, Secretary and Treasurer of Patterson-UTI Energy, Inc.)*

10.6		Restricted Stock Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and John E. Vollmer III (Senior Vice President – Corporate Development of Patterson-UTI Energy, Inc.)*

10.7		Amendment to the Amended and Restated 1997 Long-Term Incentive Plan.*

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.*