Edgar Filing: PATTERSON UTI ENERGY INC

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q/A

(Amendment No. 1)


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 incorporation or organization)		(I.R.S. Employer Identification No.)

4510 Lamesa Highway, Snyder, Texas 79549

(Address of principal executive offices) (Zip Code)

(325) 574-6300

(Registrant’s telephone number, including area code)

N/ A

(Former name, former address and former fiscal year,

if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ Accelerated filer o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

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

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

Explanatory Note			3
PART I — Financial Information

Item 1.	Financial Statements
	Unaudited condensed consolidated balance sheets		5
	Unaudited condensed consolidated statements of income		6
	Unaudited condensed consolidated statement of changes in stockholders’ equity		7
	Unaudited condensed consolidated statements of changes in cash flows		8
	Notes to unaudited condensed consolidated financial statements		9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		21

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		31

Item 4.	Controls and Procedures		31
Forward Looking Statements and Cautionary Statements for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995			33

PART II — Other Information

Item 6.	Exhibits		34
Signatures			35
Certification of CEO Pursuant to Rule 13a-14(a)/15d-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)-15d-14(a)
Certification of CEO & CFO Pursuant to 18 USC Section 1350

PART I — FINANCIAL INFORMATION

Explanatory Note

This Amendment No. 1 on Form 10-Q/ A (“Form 10-Q/ A”) to our previously filed Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2005, initially filed with the United States Securities and Exchange Commission (“SEC”) on October 28, 2005 (“Original Filing”), reflects a restatement of our unaudited interim condensed consolidated financial statements as discussed in Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements. Previously issued financial statements are being restated to properly reflect losses incurred as a result of an embezzlement whereby payments were made to or for the benefit of Jonathan D. Nelson (“Nelson”), our former Chief Financial Officer (“CFO”), that had been reflected in previously issued financial statements as payments for assets and services that were not received by the Company. Previously issued financial statements are also being restated for the effects of the correction of other errors that are immaterial both individually and in the aggregate. These other adjustments relate primarily to previously reported property and equipment balances that resulted from our review of our property and equipment records and the underlying physical assets in connection with investigation of the embezzlement.

The total amount embezzled was approximately $77.5 million in cash, excluding any tax effects, beginning with the year ended December 31, 1998 through November 3, 2005 as follows (in thousands):


From 1998 to December 31, 2004		$	58,961
From January 1, 2005 to September 30, 2005			12,193

	Total through September 30, 2005		71,154
From October 1, 2005 to November 3, 2005 (net of $1,500 repayment)			6,350

	Total embezzlement	$	77,504

On November 16, 2005 the SEC obtained a freeze order on Nelson’s assets (including assets held by entities controlled by him) and a Receiver was appointed to collect those assets. The Company understands that the Receiver will ultimately liquidate the assets and propose a plan to distribute the proceeds. While the Company believes it has a claim for at least the full amount embezzled, other creditors have or may assert claims on the assets held by the Receiver. As a result, recovery by the Company from the Receiver is uncertain as to timing and amount, if any. Recoveries, if any, will be recognized when they are considered collectable.

The effects of the embezzlement on the Company’s financial position follow (in thousands):


	September 30,			December 31,
Decrease in Amounts Previously Reported	2005			2004

Assets	$	(66,952	)	$	(56,133	)
Liabilities(1)		(24,836	)		(20,848	)

Retained Earnings & Stockholders’ Equity	$	(42,116	)	$	(35,285	)


(1)	Consists of increases in Federal and state income taxes payable of $2.6 million and $1.3 million at September 30, 2005 and December 31, 2004, respectively and decreases in deferred tax liabilities of $27.4 million and $22.2 million at September 30, 2005 and December 31, 2004, respectively.

The effects of the restatement due to the embezzlement and other adjustments on operating income as previously reported for the three and nine months ended September 30, 2005 and 2004, respectively, follow (in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,

Operating Income:	2005			2004			2005			2004

As previously reported	$	173,511		$	47,408		$	390,179		$	110,717
Adjustment for effects of embezzlement		(4,721	)		(4,642	)		(10,819	)		(13,125	)
Other adjustments		(1,344	)		(1,024	)		(3,430	)		(2,953	)

As restated	$	167,446		$	41,742		$	375,930		$	94,639

The effects of the restatement due to the embezzlement and other property and equipment adjustments on net income as previously reported for the three and nine months ended September 30, 2005 and 2004, respectively, follow (in thousands):


		Three Months Ended						Nine Months Ended
		September 30,						September 30,

		2005			2004			2005			2004

Net Income:
As previously reported		$	110,135		$	29,964		$	247,548		$	70,253

Adjustments:
	Embezzled funds expense		(5,431	)		(4,759	)		(12,193	)		(13,479	)
	Embezzled amounts previously expensed as depreciation and selling, general and administrative		710			117			1,374			354
	Other adjustments		(1,344	)		(1,024	)		(3,430	)		(2,953	)
	Tax benefits		2,235			2,100			5,252			5,946

	Net adjustment		(3,830	)		(3,566	)		(8,997	)		(10,132	)

Net income, as restated		$	106,305		$	26,398		$	238,551		$	60,121

Net income per common share:
Basic:
	As previously reported	$	0.64		$	0.18		$	1.46		$	0.42
	Adjustment for effects of embezzlement	$	(0.02	)	$	(0.02	)	$	(0.04	)	$	(0.05	)
	Other adjustments	$	—		$	—		$	(0.01	)	$	(0.01	)
	As restated	$	0.62		$	0.16		$	1.40		$	0.36
Diluted:
	As previously reported	$	0.63		$	0.18		$	1.43		$	0.42
	Adjustment for effects of embezzlement	$	(0.02	)	$	(0.02	)	$	(0.04	)	$	(0.05	)
	Other adjustments	$	—		$	—		$	(0.01	)	$	(0.01	)
	As restated	$	0.61		$	0.16		$	1.38		$	0.36

Except for the foregoing amended information, this Form 10-Q/A continues to speak as of the date of the Original Filing and the Company has not updated the disclosure contained herein to reflect events that occurred at a later date.


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)


				Restated (See Note 2)

				September 30,			December 31,
				2005			2004

				(In thousands, except share
				data)
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					980,456			765,019
Goodwill					99,056			99,056
Other					5,065			5,677

			Total assets	$	1,646,106		$	1,256,785


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable:
		Trade		$	99,964		$	54,553
		Accrued revenue distributions			14,379			11,297
		Other			2,956			2,309
	Accrued federal and state income taxes payable				33,618			4,231
	Accrued expenses				102,493			79,163

		Total current liabilities			253,410			151,553
Deferred tax liabilities, net					139,177			140,475
Other					4,122			3,256

			Total liabilities		396,709			295,284

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				591,822			373,712
	Accumulated other comprehensive income				8,669			7,350
	Treasury stock, at cost, 3,113,096 shares				(13,137	)		(13,137	)

			Total stockholders’ equity		1,249,397			961,501

			Total liabilities and stockholders’ equity	$	1,646,106		$	1,256,785

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)


		Restated (See Note 2)

		Three Months						Nine Months
		Ended September 30,						Ended September 30,

		2005			2004			2005			2004

		(In thousands, except per share amounts)
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		39,545			31,661			112,319			91,037
	Selling, general and administrative		10,565			8,303			30,157			22,999
	Bad debt expense		50			192			416			499
	Embezzled funds expense		5,431			4,759			12,193			13,479
	Other (including gain or loss on sale of assets)		657			(112	)		2,174			(1,425	)

			301,293			217,432			833,324			617,824

Operating income			167,446			41,742			375,930			94,639

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			168,353			41,956			377,801			95,435

Income tax expense (benefit):
	Current		66,574			12,023			145,513			31,298
	Deferred		(4,526	)		3,535			(6,263	)		4,016

			62,048			15,558			139,250			35,314

Net income		$	106,305		$	26,398		$	238,551		$	60,121

Net income per common share:
	Basic	$	0.62		$	0.16		$	1.40		$	0.36

	Diluted	$	0.61		$	0.16		$	1.38		$	0.36

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.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)


	Common Stock														Accumulated
						Additional									Other
	Number					Paid-In			Deferred			Retained			Comprehensive			Treasury
	of Shares			Amount		Capital			Compensation			Earnings			Income			Stock			Total

	(In thousands)
December 31, 2004, as previously reported		171,626		$	1,716	$	597,280		$	(5,420	)	$	415,489		$	11,611		$	(13,137	)	$	1,007,539
Adjustment for effects of embezzlement (net of applicable income tax benefit of $20,848)		—			—		—			—			(35,285	)		—			—			(35,285	)
Other adjustments (net of applicable income tax benefit of $3,501) (See Note 2)		—			—		—			—			(6,492	)		(4,261	)		—			(10,753	)

December 31, 2004, as restated		171,626			1,716		597,280			(5,420	)		373,712			7,350			(13,137	)		961,501
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 $749, as restated		—			—		—			—			—			1,319			—			1,319
Payment of cash dividend		—			—		—			—			(20,441	)		—			—			(20,441	)
Net income, as restated		—			—		—			—			238,551			—			—			238,551

September 30, 2005, as restated		175,791		$	1,758	$	671,303		$	(11,018	)	$	591,822		$	8,669		$	(13,137	)	$	1,249,397

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)


					Restated (See Note 2)

					Nine Months
					Ended September 30,

					2005			2004

					(In thousands)
Cash flows from operating activities:
	Net income				$	238,551		$	60,121
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and impairment				112,319			91,037
		Provision for bad debts				416			499
		Deferred income tax expense				(6,263	)		4,016
		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				(1,253	)		(1,425	)
			Changes in operating assets and liabilities, net of business acquired:
				Accounts receivable		(148,825	)		(34,480	)
				Income taxes receivable		—			21,923
				Inventory and other current assets		(4,044	)		(6,997	)
				Accounts payable		48,568			2,820
				Income taxes payable		29,660			—
				Accrued expenses		22,662			(5,416	)
				Other liabilities		1,513			(6,729	)

			Net cash provided by operating activities			319,472			132,800

Cash flows from investing activities:
	Acquisitions, net of cash acquired					(73,577	)		(30,387	)
	Purchases of property and equipment					(262,723	)		(125,501	)
	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			(322,032	)		(164,573	)

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.

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 Company’s former Chief Financial Officer (“CFO”), Jonathan D. Nelson (“Nelson”), perpetrated an embezzlement over a period of more than five years. The accompanying interim unaudited condensed consolidated financial statements have been restated to reflect the effects of losses incurred as a result of the embezzlement in the periods of occurrence. Payments related to the embezzlement previously capitalized as property and equipment and goodwill acquired, and the related depreciation and other amounts expensed have been reversed from the Company’s accounting records. Embezzled payments have been recognized as expense in the periods they were embezzled. The cumulative effects of the embezzlement prior to 2004, have been recognized as a reduction of retained earnings. The accompanying interim unaudited condensed consolidated financial statements have also been restated for the effects of the correction of other errors that are immaterial both individually and in the aggregate (See Note 2).

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/A 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 5 of these Notes to Unaudited Condensed Consolidated Financial Statements).

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS — (Continued)

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).


	Restated (See Note 2)

	Three Months				Nine Months
	Ended September 30,				Ended September 30,

	2005		2004		2005		2004

Net income	$	106,305	$	26,398	$	238,551	$	60,121
Weighted average common shares outstanding		171,613		167,006		169,846		165,744

Basic earnings per share	$	0.62	$	0.16	$	1.40	$	0.36

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	$	0.61	$	0.16	$	1.38	$	0.36

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.	Embezzlement and Restatements

On November 3, 2005, the Company announced the resignation of its CFO, Jonathan D. Nelson. On November 10, 2005, the Company announced that, based on information received by Company senior management on November 9, 2005, the Audit Committee of the Company’s Board of Directors began an investigation into an embezzlement from the Company by Nelson.

Most of the embezzled funds result from Nelson causing the wiring of Company funds aggregating approximately $72.3 million, to, or for the benefit of, entities owned and controlled by him. Nelson was originally able to initiate these wire transfers by requesting the wire transfers himself in telephone calls to one of the Company’s banks. After changes to the Company’s internal controls and procedures in 2004, Nelson initiated the wire transfers through instructions to one his subordinates and by the creation of fraudulent invoices containing forged senior management approvals. This false documentation was created by our former CFO to conceal the true nature of these transactions from the Company and its independent registered public accountants.

Nelson also instructed certain former employees, who worked under his supervision, to alter management reports related to property and equipment expenditures and created fictitious property and equipment approval forms with forged signatures.

On December 22, 2005, upon recommendation of Company management and the Audit Committee of its Board of Directors, the Company announced that based on the results to date of its ongoing internal investigation into the facts and circumstances surrounding the embezzlement by Nelson, the Company would restate its previously issued financial statements and amend its previously issued Annual Report on Form 10-K for the year ended December 31, 2004 and Quarterly Reports on Form 10-Q for the periods ended March 31,

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS — (Continued)

June 30 and September 30, 2005. These restatements reflect losses incurred as a result of payments made to or for the benefit of Nelson that had been recognized in the Company’s accounting records and previously issued financial statements as payments for assets and services that were not received by the Company.

The total amount embezzled was approximately $77.5 million in cash, excluding any tax effects, beginning with the year ended December 31, 1998 through November 3, 2005 as follows (in thousands):


From 1998 to December 31, 2004		$	58,961
From January 1, 2005 to September 30, 2005			12,193

	Total through September 30, 2005		71,154
From October 1, 2005 to November 3, 2005 (net of $1,500 repayment)			6,350

	Total embezzlement	$	77,504

The Company promptly advised the United States Securities and Exchange Commission (“SEC”) when it became aware of the embezzlement. The SEC promptly obtained a freeze order on Nelson’s assets (including assets held by entities controlled by him) and a Receiver was appointed to collect those assets. The United States Attorney for the Northern District of Texas obtained an indictment against Nelson and investigation of this matter continues.

The Company understands that the Receiver will ultimately liquidate the assets and propose a plan to distribute the proceeds. While the Company believes it has a claim for at least the full amount embezzled, other creditors have or may assert claims on the assets held by the Receiver. As a result, recovery by the Company from the Receiver is uncertain as to timing and amount, if any. Recoveries, if any, will be recognized when they are considered collectable.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS — (Continued)

The accompanying unaudited condensed consolidated financial statements have been restated to provide for, net of related tax effects, (1) the effects of losses incurred as a result of the former CFO’s embezzlement and (2) the effects of the correction of other errors that are immaterial both individually and in the aggregate. These other adjustments relate primarily to previously reported property and equipment balances that resulted from our review of the Company’s property and equipment records and the underlying physical assets in connection with the investigation of the embezzlement as well as the tax effects of our foreign currency translation adjustment. The effects of the embezzlement and other adjustments on the Company’s financial position follow (in thousands):


						Effect of			Effect of
			Previously			Adjustment for			Other
			Reported			Embezzlement			Adjustments			Restated

September 30, 2005:
	Property and equipment:
		At cost	$	1,701,246		$	(67,386	)	$	1,626		$	1,635,486
		Accumulated depreciation		(652,685	)		2,704			(5,049	)		(655,030	)
		Net		1,048,561			(64,682	)		(3,423	)		980,456
	Goodwill			101,326			(2,270	)		—			99,056
	Total assets			1,716,481			(66,952	)		(3,423	)		1,646,106
	Accounts payable, trade			89,964			—			10,000			99,964
	Federal and state income taxes payable			30,854			2,603			161			33,618
	Deferred tax liabilities, net			171,542			(27,439	)		(4,926	)		139,177
	Liabilities			416,310			(24,836	)		5,235			396,709
	Retained earnings			642,596			(42,116	)		(8,658	)		591,822
	Stockholders’ equity			1,300,171			(42,116	)		(8,658	)		1,249,397
December 31, 2004:
	Property and equipment:
		At cost		1,400,848			(55,211	)		(6,866	)		1,338,771
		Accumulated depreciation		(571,973	)		1,348			(3,127	)		(573,752	)
		Net		828,875			(53,863	)		(9,993	)		765,019
	Goodwill			101,326			(2,270	)		—			99,056
	Total assets			1,322,911			(56,133	)		(9,993	)		1,256,785
	Federal and state income taxes payable			2,754			1,311			166			4,231
	Deferred tax liabilities, net			162,040			(22,159	)		594			140,475
	Liabilities			315,372			(20,848	)		760			295,284
	Retained earnings			415,489			(35,285	)		(6,492	)		373,712
	Accumulated other comprehensive income			11,611			—			(4,261	)		7,350
	Stockholders’ equity			1,007,539			(35,285	)		(10,753	)		961,501

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS — (Continued)

The effects of the embezzlement and other adjustments on the Company’s results of operations and cash flows follow (in thousands, except per share amounts):


				Three Months Ended September 30,

							Effect of			Effect of
				Previously			Adjustment for			Other
				Reported			Embezzlement			Adjustments			Restated

2005:
	Depreciation, depletion and impairment			$	39,216		$	(704	)	$	1,033		$	39,545
	Selling, general and administrative				10,571			(6	)		—			10,565
	Other (including gain or loss on sale of assets)				346			—			311			657
	Embezzled funds expense				—			5,431			—			5,431
	Operating income				173,511			(4,721	)		(1,344	)		167,446
	Income before income taxes				174,418			(4,721	)		(1,344	)		168,353
	Income tax expense				64,283			(1,740	)		(495	)		62,048
	Net income				110,135			(2,981	)		(849	)		106,305
		Per common share:
			Basic		0.64			(0.02	)		—			0.62
			Diluted		0.63			(0.02	)		—			0.61
	Net cash provided by (used in):
		Operating activities			165,779			(5,425	)		—			160,354
		Investing activities			(110,462	)		5,425			—			(105,037	)
	Purchases of property and equipment				105,949			(5,425	)		—			100,524
2004:
	Depreciation, depletion and impairment			$	30,789		$	(111	)	$	983		$	31,661
	Selling, general and administrative				8,309			(6	)		—			8,303
	Other (including gain or loss on sale of assets)				(153	)		—			41			(112	)
	Embezzled funds expense				—			4,759			—			4,759
	Operating income				47,408			(4,642	)		(1,024	)		41,742
	Income before income taxes				47,622			(4,642	)		(1,024	)		41,956
	Income tax expense				17,658			(1,721	)		(379	)		15,558
	Net income				29,964			(2,921	)		(645	)		26,398
		Per common share:
			Basic		0.18			(0.02	)		—			0.16
			Diluted		0.18			(0.02	)		—			0.16
	Net cash provided by (used in):
		Operating activities			55,577			(4,753	)		—			50,824
		Investing activities			(46,467	)		4,753			—			(41,714	)
	Purchases of property and equipment				47,112			(4,753	)		—			42,359

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS — (Continued)


				Nine Months Ended September 30,

							Effect of			Effect of
				Previously			Adjustment for			Other
				Reported			Embezzlement			Adjustments			Restated

				(In thousands, except per share amounts)
2005:
	Depreciation, depletion and impairment			$	110,575		$	(1,356	)	$	3,100		$	112,319
	Selling, general and administrative				30,175			(18	)		—			30,157
	Other (including gain or loss on sale of assets)				1,844			—			330			2,174
	Embezzled funds expense				—			12,193			—			12,193
	Operating income				390,179			(10,819	)		(3,430	)		375,930
	Income before income taxes				392,050			(10,819	)		(3,430	)		377,801
	Income tax expense				144,502			(3,988	)		(1,264	)		139,250
	Net income				247,548			(6,831	)		(2,166	)		238,551
		Per common share:
			Basic		1.46			(0.04	)		(0.01	)		1.40
			Diluted		1.43			(0.04	)		(0.01	)		1.38
	Net cash provided by (used in):
		Operating activities			321,647			(12,175	)		10,000			319,472
		Investing activities			(324,207	)		12,175			(10,000	)		(322,032	)
	Purchases of property & equipment				264,898			(12,175	)		10,000			262,723
2004:
	Depreciation, depletion and impairment			$	88,523		$	(336	)	$	2,850		$	91,037
	Selling, general and administrative				23,017			(18	)		—			22,999
	Other (including gain or loss on sale of assets)				(1,528	)		—			103			(1,425	)
	Embezzled funds expense				—			13,479			—			13,479
	Operating income				110,717			(13,125	)		(2,953	)		94,639
	Income before income taxes				111,513			(13,125	)		(2,953	)		95,435
	Income tax expense				41,260			(4,854	)		(1,092	)		35,314
	Net income				70,253			(8,271	)		(1,861	)		60,121
		Per common share:
			Basic		0.42			(0.05	)		(0.01	)		0.36
			Diluted		0.42			(0.05	)		(0.01	)		0.36
	Net cash provided by (used in):
		Operating activities			146,261			(13,461	)		—			132,800
		Investing activities			(178,034	)		13,461			—			(164,573	)
		Acquisitions			32,514			(2,127	)		—			30,387
	Purchases of property & equipment				136,835			(11,334	)		—			125,501


3.	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.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS — (Continued)

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.


4.	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):


		Restated (See Note 2)

		Three Months						Nine Months
		Ended September 30,						Ended September 30,

		2005			2004			2005			2004

Net income, as reported		$	106,305		$	26,398		$	238,551		$	60,121
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		$	103,518		$	23,236		$	230,406		$	50,798

Net income per common share:
	Basic, as reported	$	0.62		$	0.16		$	1.40		$	0.36

	Basic, pro-forma	$	0.60		$	0.14		$	1.36		$	0.31

	Diluted, as reported	$	0.61		$	0.16		$	1.38		$	0.36

	Diluted, pro-forma	$	0.60		$	0.14		$	1.34		$	0.30

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS — (Continued)


5.	Comprehensive Income

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):


		Restated (See Note 2)

		Three Months				Nine Months
		Ended September 30,				Ended September 30,

		2005		2004		2005		2004

Net income		$	106,305	$	26,398	$	238,551	$	60,121
Other comprehensive income (expense):
	Foreign currency translation adjustment related to our Canadian operations, net of tax		2,286		1,872		1,319		675

Comprehensive income, net of tax		$	108,591	$	28,270	$	239,870	$	60,796


6.	Property and Equipment

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


	Restated (See Note 2)

	September 30, 2005			December 31, 2004

Equipment	$	1,537,197		$	1,239,519
Oil and natural gas properties		77,349			82,711
Buildings		15,654			12,892
Land		5,286			3,649

		1,635,486			1,338,771
Less accumulated depreciation and depletion		(655,030	)		(573,752	)

	$	980,456		$	765,019


7.	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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS — (Continued)

identifiable revenues and expenses. Separate financial data for each of our four business segments is provided below (in thousands).


		Restated (See Note 2)

		Three Months						Nine Months
		Ended September 30,						Ended 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	$	163,109		$	38,752		$	367,721		$	92,697
	Pressure pumping		7,691			6,199			15,779			12,787
	Drilling and completion fluids		2,546			1,110			8,061			2,518
	Oil and natural gas		4,098			3,674			10,532			7,217

			177,444			49,735			402,093			115,219
	Corporate and other		(3,892	)		(3,234	)		(10,743	)		(7,101	)
	Other operating		(675	)		—			(3,227	)		—
	Embezzled funds expense(c)		(5,431	)		(4,759	)		(12,193	)		(13,479	)
	Interest income		944			233			2,011			688
	Interest expense		(56	)		(75	)		(179	)		(205	)
	Other		19			56			39			313

Income before income taxes		$	168,353		$	41,956		$	377,801		$	95,435


		Restated (See Note 2)

		September 30,		December 31,
		2005		2004

Identifiable assets:
	Contract drilling	$	1,301,286	$	961,873
	Pressure pumping		70,919		49,145
	Drilling and completion fluids		75,787		62,970
	Oil and natural gas		59,781		62,984

			1,507,773		1,136,972
	Corporate and other(d)		138,333		119,813

Total assets		$	1,646,106	$	1,256,785


(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.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS — (Continued)


(c)	The Company’s former CFO perpetrated an embezzlement over a period of more than five years. Embezzled funds expense includes adjustments to eliminate payments related to the embezzlement previously capitalized as property and equipment and goodwill acquired. The related depreciation and other amounts expensed have been reversed from the Company’s accounting records (See Note 2).

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


8.	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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS — (Continued)

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.


9.	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):


					Restated (See Note 2)

					September 30,		December 31,
					2005		2004

Drilling:
	Goodwill at beginning of year				$	89,092	$	41,069
		Changes to goodwill				—		48,020
		Other				—		3

			Goodwill at end of period			89,092		89,092

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	$	99,056	$	99,056


10.	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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS — (Continued)


11.	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 liabilities assumed in the acquisition of TMBR/ Sharp Drilling, Inc. (“TMBR”).


12.	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.


13.	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.


14.	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.


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

This Quarterly Report on Form 10-Q/A for the three and nine months ended September 30, 2005 amends and restates the financial statements and related financial information for all periods presented herein. The determination to restate these financial statements and other information was made as a result of management’s identification of an embezzlement. Further information on the restatement can be found in Note 2 to unaudited condensed consolidated financial statements.

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 302.7%, 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/A for the year ended December 31, 2004, beginning on page 18.

Management believes that the liquidity of our balance sheet as of September 30, 2005, which includes approximately $308 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.

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.

Net income for the three months ended September 30, 2005 and 2004 includes embezzlement expense of approximately $5.4 million and $4.8 million, respectively. Net income for the nine months ended September 30, 2005 and 2004 includes embezzlement expense of approximately $12.2 million and $13.5 million, respectively. On November 16, 2005, the SEC obtained a freeze order on Nelson’s assets (including assets held by entities controlled by him) and a Receiver was appointed to collect those assets. The Company understands that the Receiver will ultimately liquidate the assets and propose a plan to distribute the proceeds. While the Company believes it has a claim for at least the full amount embezzled, other creditors have or may assert claims on the assets held by the Receiver. As a result, recovery by the Company from the Receiver is uncertain as to timing and amount, if any. Recoveries, if any, will be recognized when they are considered collectable.

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

					December 31,
		September 30,
		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

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

			December 31,
	September 30,
	2005		2004		2003

Costs of wells-in-progress:
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 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. We follow the percentage-of-completion method of accounting for footage contract drilling arrangements. Under the percentage-of-completion method, management estimates are relied upon in the determination of the total estimated expenses to be incurred drilling the well. Due to the nature of turnkey contract drilling arrangements and risks therein, we follow the completed contract method of accounting for such arrangements. Under this method, all drilling revenues and expenses related to a well in progress are deferred and recognized in the period the well is completed. Provisions for losses on incomplete or in-process wells are made when estimated total expenses are expected to exceed estimated total revenues.

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

Use of estimates — 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 $308 million, including cash and cash equivalents of $131 million. For the nine months ended September 30, 2005, our significant sources of cash flow included:


	•	$319 million provided by operations,

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

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

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 $263 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.

Results of Operations

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


	Restated (See Note 2)

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	$	1,286		$	1,086			18.4	%
Depreciation	$	33,695		$	26,008			29.6	%
Operating income	$	163,109		$	38,752			320.9	%
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	$	90,114		$	35,758			152.0	%

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


	Restated (See Note 2)

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	$	609	$	529		15.1	%
Other operating	$	200		—		N/A	%
Operating income	$	2,546	$	1,110		129.4	%
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.


	Restated (See Note 2)

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	%
Gain on sale of assets	$	218	$	112		N/A	%
Embezzled funds expense	$	5,431	$	4,759		14.1	%
Other	$	675	$	—		N/A	%
Interest income	$	944	$	233		305.2	%
Interest expense	$	56	$	75		(25.3	)%
Other income	$	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 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. Interest income increased as a result of higher cash balances and interest rates in 2005. Embezzled funds expense includes payments made to or for the benefit of Jonathan D. Nelson, our former CFO, for assets and services that were not received by the Company.

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


	Restated (See Note 2)

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	$	3,701		$	3,249			13.9	%
Depreciation and amortization	$	95,909		$	74,919			28.0	%
Operating income	$	367,721		$	92,697			296.7	%
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	$	222,492		$	100,537			121.3	%

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.


	Restated (See Note 2)

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	$	1,730	$	1,623		6.6	%
Other operating	$	200		—		N/A	%
Operating income	$	8,061	$	2,518		220.1	%
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 prices)
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.


	Restated (See Note 2)

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	%
Gain on sale of assets	$	1,253	$	1,425		(12.1	)%
Embezzled funds expense	$	12,193	$	13,479		(9.5	)%
Other	$	3,227	$	—		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 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. Interest income increased as a result of higher cash balances and interest rates in 2005. Embezzled funds expense includes payments made to or for the benefit of Jonathan D. Nelson, our former CFO, for assets and services that were not received by the Company.

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.

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 and the value of our Canadian net assets will decline.


Item 4.	*Controls and Procedures*

Background to the Fraud and Restatement — In November 2005, the Company discovered that its former Chief Financial Officer, Jonathan D. Nelson (“Nelson”), had fraudulently diverted approximately $78 million in Company funds for his own benefit. Nelson’s fraudulent diversions began in 1998 and continued until the fourth quarter of 2005 when he resigned from the Company. The funds fraudulently diverted were recorded as payments for assets or services that were not actually received by the Company. The Audit Committee of the Board of Directors commenced an investigation into Nelson’s activities and retained independent counsel and independent forensic accountants to assist with the investigation.

On December 22, 2005, the Company announced that the Audit Committee of the Board of Directors of the Company had concluded that it was necessary to restate its previously reported consolidated financial statements for the years ended December 31, 2004, 2003 and 2002, and for the first three quarters of 2005 and all quarters in 2004 and 2003.

As discussed in Note 2 to the consolidated financial statements included within this Quarterly Report on Form 10-K/A for the quarterly period ended September 30, 2005, we have restated our previously issued financial statements.

Disclosure Controls and Procedures — We maintain disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act) designed to ensure that the information required to be disclosed in the reports that we file with the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief

Executive Officer (“CEO”) and current Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of our management, including our CEO and current CFO, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q/A.

At the time of the filing of our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2005, our CEO and former CFO concluded that our disclosure controls and procedures were effective as of September 30, 2005. Subsequent to that evaluation, our CEO and current CFO concluded that our disclosure controls and procedures were not effective at a reasonable level of assurance, as of September 30, 2005, because of material weaknesses. For a discussion of the material weakness, see Item 9A of our Annual Report on Form 10-K/A for the year ended December 31, 2004. Based upon the substantial work performed during the restatement process, management has concluded that the Company’s unaudited condensed consolidated financial statements for the periods covered by and included in this Quarterly Report on Form 10-Q/A are fairly stated in all material respects.

Changes in Internal Control Over Financial Reporting — Our management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f). With the participation of our CEO and CFO, our management evaluates any changes in our internal control over financial reporting that occurred during each fiscal quarter which have materially affected, or are reasonably likely to materially affect, such internal control. At the time of the filing of our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2005, our management, including our CEO and former CFO, concluded that there were no changes in our internal control over financial reporting that occurred during the fiscal quarter ended September 30, 2005, that have materially affected or were reasonably likely to materially affect our internal control over financial reporting.

Our CEO and current CFO have subsequently concluded that the material weaknesses described in Item 9A of our Annual Report on Form 10-K/A for the year ended December 31, 2004 existed as of September 30, 2005.

You can find more information about the investigation, the material weaknesses and the actions that we have taken and are planning to take to remediate the material weaknesses in Item 9A of our Annual Report on Form 10-K/A, for the year ended December 31, 2004.

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/A for the year ended December 31, 2004, beginning on page 18.

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.

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.
	99.1			Controls and Procedures (filed March 17, 2006 as Item 9A to the Company’s Annual Report on Form 10-K/A for the fiscal year ended December 31, 2004 and incorporated herein by reference).

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	PATTERSON-UTI ENERGY, INC.


	By:	/s/ Cloyce A. Talbott



	Cloyce A. Talbott
	(Principal Executive Officer)
	Chief Executive Officer


	By:	/s/ John E. Vollmer III



	John E. Vollmer III
	(Principal Accounting Officer)
	Senior Vice President — Corporate Development, Chief Financial Officer,
	Secretary and Treasurer

DATED: March 27, 2006

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