PATTERSON UTI ENERGY INC - Quarter Report: 2008 June (Form 10-Q)

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2008

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from            to

Patterson-UTI Energy, Inc.

DELAWARE		75-2504748
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
450 GEARS ROAD, SUITE 500
HOUSTON, TEXAS		77067
(Address of principal executive offices)		(Zip Code)

(281) 765-7100
(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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act: (Check one)

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
				(Do not check if a smaller reporting company)

     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.

     156,635,799 shares of common stock, $0.01 par value, as of July 31, 2008

 

 

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements
Unaudited consolidated balance sheets			1
Unaudited consolidated statements of income			2
Unaudited consolidated statement of changes in stockholders’ equity			3
Unaudited consolidated statements of changes in cash flows			4
Notes to unaudited consolidated financial statements			5
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			12
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk			18
ITEM 4. Controls and Procedures			19
Forward Looking Statements and Cautionary Statements for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995			19
PART II — OTHER INFORMATION
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds			20
ITEM 4. Submission of Matters to a Vote of Security Holders			20
ITEM 6. Exhibits			21
Signature			22
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 and CFO pursuant to 18 USC Section 1350

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

     The following unaudited consolidated financial statements include all adjustments which are, in the opinion of management, necessary for a fair statement of the results for the interim periods presented.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(unaudited, in thousands, except share data)

		June 30,				December 31,
		2008				2007
ASSETS
Current assets:
Cash and cash equivalents		$	62,232			$	17,434
Accounts receivable, net of allowance for doubtful accounts of $10,162 at June 30, 2008 and $10,014 at December 31, 2007			391,652				373,279
Accrued Federal and state income taxes receivable			18,445				—
Inventory			39,888				44,416
Deferred tax assets, net			33,930				35,370
Other			63,512				52,286
Total current assets			609,659				522,785
Property and equipment, net			1,873,511				1,841,404
Goodwill			96,198				96,198
Other			4,589				4,812
Total assets		$	2,583,957			$	2,465,199
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	151,674			$	156,916
Accrued Federal and state income taxes payable			—				1,458
Accrued expenses			122,828				136,834
Total current liabilities			274,502				295,208
Borrowings under line of credit			—				50,000
Deferred tax liabilities, net			247,597				219,490
Other			5,569				4,471
Total liabilities			527,668				569,169
Commitments and contingencies (see Note 10)			—				—
Stockholders’ equity:
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued			—				—
Common stock, par value $.01; authorized 300,000,000 shares with 180,216,614 and 177,385,808 issued and 156,619,765 and 153,942,800 outstanding at June 30, 2008 and December 31, 2007, respectively			1,802				1,773
Additional paid-in capital			755,124				703,581
Retained earnings			1,831,947				1,716,620
Accumulated other comprehensive income			18,126				20,207
Treasury stock, at cost, 23,596,849 and 23,443,008 shares at June 30, 2008 and December 31, 2007, respectively			(550,710	)			(546,151	)
Total stockholders’ equity			2,056,289				1,896,030
Total liabilities and stockholders’ equity		$	2,583,957			$	2,465,199

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(unaudited, in thousands, except per share amounts)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Operating revenues:
Contract drilling		$	416,835			$	419,191			$	836,984			$	886,689
Pressure pumping			57,094				51,592				99,958				90,176
Drilling and completion fluids			38,745				39,667				71,295				70,427
Oil and natural gas			13,609				12,108				22,600				22,367
			526,283				522,558				1,030,837				1,069,659
Operating costs and expenses:
Contract drilling			251,381				228,297				495,748				474,451
Pressure pumping			32,506				25,777				61,011				46,928
Drilling and completion fluids			31,449				32,628				59,982				58,019
Oil and natural gas			3,529				2,461				5,596				5,739
Depreciation, depletion and impairment			65,673				59,947				129,399				115,878
Selling, general and administrative			17,747				16,322				34,743				30,991
Embezzlement costs (recoveries)			—				(41,935	)			—				(41,935	)
Gain on disposal of assets			(2,721	)			(16,475	)			(2,535	)			(16,273	)
Other operating expenses			300				400				600				1,000
			399,864				307,422				784,544				674,798
Operating income			126,419				215,136				246,293				394,861
Other income (expense):
Interest income			493				457				836				826
Interest expense			(63	)			(831	)			(340	)			(1,594	)
Other			353				109				737				203
			783				(265	)			1,233				(565	)
Income before income taxes			127,202				214,871				247,526				394,296
Income tax expense:
Current			29,229				56,350				57,941				109,783
Deferred			16,551				18,970				30,754				29,161
			45,780				75,320				88,695				138,944
Net income		$	81,422			$	139,551			$	158,831			$	255,352
Net income per common share:
Basic		$	0.53			$	0.90			$	1.04			$	1.64
Diluted		$	0.52			$	0.88			$	1.02			$	1.62
Weighted average number of common shares outstanding:
Basic			153,978				155,527				153,289				155,457
Diluted			156,437				157,912				155,766				157,580
Cash dividends per common share		$	0.16			$	0.12			$	0.28			$	0.20

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
(unaudited, in thousands)

																		Accumulated
		Common Stock								Additional								Other
		Number of								Paid-in				Retained				Comprehensive				Treasury
		Shares				Amount				Capital				Earnings				Income				Stock				Total
Balance, December 31, 2007			177,386			$	1,773			$	703,581			$	1,716,620			$	20,207			$	(546,151	)		$	1,896,030
Issuance of restricted stock			577				6				(6	)			—				—				—				—
Forfeitures of restricted shares			(30	)			—				—				—				—				—				—
Exercise of stock options			2,284				23				25,344				—				—				—				25,367
Stock-based compensation			—				—				10,137				—				—				—				10,137
Tax benefit related to stock-based compensation			—				—				16,068				—				—				—				16,068
Foreign currency translation adjustment, net of tax of $1,206			—				—				—				—				(2,081	)			—				(2,081	)
Payment of cash dividends			—				—				—				(43,504	)			—				—				(43,504	)
Purchase of treasury stock			—				—				—				—				—				(4,559	)			(4,559	)
Net income			—				—				—				158,831				—				—				158,831
Balance, June 30, 2008			180,217			$	1,802			$	755,124			$	1,831,947			$	18,126			$	(550,710	)		$	2,056,289

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS
(unaudited, in thousands)

		Six Months Ended
		June 30,
		2008				2007
Cash flows from operating activities:
Net income		$	158,831			$	255,352
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and impairment			129,399				115,878
Provision for bad debts			600				1,000
Dry holes and abandonments			600				786
Deferred income tax expense			30,754				29,161
Stock-based compensation expense			10,137				8,416
Gain on disposal of assets			(2,535	)			(16,273	)
Changes in operating assets and liabilities:
Accounts receivable			(19,609	)			90,703
Embezzlement recovery receivable			—				(42,500	)
Income taxes receivable/payable			(19,923	)			6,427
Inventory and other current assets			(2,912	)			14,352
Accounts payable			14,929				6,876
Accrued expenses			(13,960	)			(18,864	)
Other liabilities			(13,035	)			(4,730	)
Net cash provided by operating activities			273,276				446,584
Cash flows from investing activities:
Purchases of property and equipment			(176,162	)			(325,592	)
Proceeds from disposal of assets			4,429				26,803
Net cash used in investing activities			(171,733	)			(298,789	)
Cash flows from financing activities:
Purchases of treasury stock			(4,559	)			(415	)
Dividends paid			(43,504	)			(31,387	)
Tax benefit related to stock-based compensation			16,068				1,060
Proceeds from borrowings under line of credit			—				82,500
Repayment of borrowings under line of credit			(50,000	)			(187,500	)
Proceeds from exercise of stock options			25,367				934
Net cash used in financing activities			(56,628	)			(134,808	)
Effect of foreign exchange rate changes on cash			(117	)			1,103
Net increase in cash and cash equivalents			44,798				14,090
Cash and cash equivalents at beginning of period			17,434				13,385
Cash and cash equivalents at end of period		$	62,232			$	27,475
Supplemental disclosure of cash flow information:
Net cash paid during the period for:
Interest expense		$	444			$	1,194
Income taxes		$	60,025			$	96,759

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Consolidation and Presentation

     The interim unaudited consolidated financial statements include the accounts of Patterson-UTI Energy, Inc. (the “Company”) and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. The Company has no controlling financial interests in any entity that is not a wholly-owned subsidiary and which would require consolidation.

     The interim consolidated financial statements have been prepared by management of the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to such rules and regulations, although the Company believes the disclosures included either on the face of the financial statements or herein are sufficient to make the information presented not misleading. In the opinion of management, all adjustments which are of a normal recurring nature considered necessary for a fair statement of the information in conformity with accounting principles generally accepted in the United States have been included. The Unaudited Consolidated Balance Sheet as of December 31, 2007, as presented herein, was derived from the audited balance sheet of the Company, but does not include all disclosures required by accounting principles generally accepted in the United States of America. These unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

     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.

     The Company provides a dual presentation of its net income per common share in its Unaudited Consolidated Statements of Income: Basic net income per common share (“Basic EPS”) and diluted net income per common share (“Diluted EPS”). Basic EPS excludes dilution and is computed by dividing net income by the weighted average number of common shares outstanding during the period excluding nonvested restricted stock. Diluted EPS is based on the weighted-average number of common shares outstanding plus the impact of dilutive instruments, including stock options, restricted stock and stock unit awards using the treasury stock method. The following table presents information necessary to calculate net income per share for the three and six months ended June 30, 2008 and 2007 as well as potentially dilutive securities excluded from the weighted average number of diluted common shares outstanding, as their inclusion would have been anti-dilutive during the three and six months ended June 30, 2008 and 2007 (in thousands, except per share amounts):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Net income		$	81,422			$	139,551			$	158,831			$	255,352
Weighted average number of common shares outstanding excluding nonvested restricted stock			153,978				155,527				153,289				155,457
Basic net income per common share		$	0.53			$	0.90			$	1.04			$	1.64
Weighted average number of common shares outstanding excluding nonvested restricted stock			153,978				155,527				153,289				155,457
Dilutive effect of stock options, restricted shares and stock unit awards			2,459				2,385				2,477				2,123
Weighted average number of diluted common shares outstanding			156,437				157,912				155,766				157,580
Diluted net income per common share		$	0.52			$	0.88			$	1.02			$	1.62
Potentially dilutive securities excluded as anti-dilutive			655				1,785				2,380				2,435

     Reclassifications — Certain reclassifications have been made to the 2007 consolidated financial statements in order for them to conform with the 2008 presentation.

     The results of operations for the three and six months ended June 30, 2008 are not necessarily indicative of the results to be expected for the full year.

2. Stock-based Compensation

     The Company recognizes the cost of share-based awards under the fair-value method. The Company uses share-based awards to compensate employees and non-employee directors. All awards have been equity instruments in the form of stock options, restricted stock awards and stock unit awards and have included both service and, in certain cases, performance conditions. The Company issues shares of common stock when vested stock option awards are exercised, when restricted stock awards are granted and when stock unit awards vest.

     Stock Options. The Company estimates the grant date fair values of stock options using the Black-Scholes-Merton valuation model (“Black-Scholes”). Volatility assumptions are based on the historic volatility of the Company’s common stock over the most recent period equal to the expected term of the options as of the date the options are granted. The expected term assumptions are based on the Company’s experience with respect to employee stock option activity. Dividend yield assumptions are based on the expected dividends at the time the options are granted. The risk-free interest rate assumptions are determined by reference to United States Treasury yields. Weighted-average assumptions used to estimate the grant date fair values for stock options granted in the three and six-month periods ended June 30, 2008 and 2007 follow:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Volatility			35.74	%			36.36	%			35.73	%			36.38	%
Expected term (in years)			4.00				4.00				4.00				4.00
Dividend yield			1.64	%			2.00	%			1.68	%			1.96	%
Risk-free interest rate			2.92	%			4.56	%			2.94	%			4.56	%

     Stock option activity from January 1, 2008 to June 30, 2008 follows:

						Weighted
						Average
		Underlying				Exercise
		Shares				Price
Outstanding at January 1, 2008			7,403,084			$	17.52
Granted			694,500			$	28.75
Exercised			(2,284,041	)		$	11.11
Expired			(134	)		$	14.64
Outstanding at June 30, 2008			5,813,409			$	21.38
Exercisable at June 30, 2008			4,206,407			$	19.30

     Restricted Stock. Under restricted stock awards to date, shares were issued when granted. Nonvested shares are subject to forfeiture for failure to fulfill service conditions and, in certain cases, performance conditions. Nonforfeitable cash dividends are paid on nonvested restricted shares.

     Restricted stock activity from January 1, 2008 to June 30, 2008 follows:

						Weighted
						Average
						Grant Date
		Shares				Fair Value
Nonvested restricted stock outstanding at January 1, 2008			1,490,150			$	26.22
Granted			576,950			$	30.31
Vested			(534,337	)		$	24.36
Forfeited			(30,185	)		$	26.15
Nonvested restricted stock outstanding at June 30, 2008			1,502,578			$	28.45

     Stock Units. Under stock unit awards to date, shares are not issued until the awards vest. Awards are subject to forfeiture for failure to fulfill service conditions. Nonforfeitable cash dividend equivalents are paid on nonvested stock units.

     Stock unit activity from January 1, 2008 to June 30, 2008 follows:

						Weighted
						Average
						Grant Date
		Shares				Fair Value
Nonvested stock units outstanding at January 1, 2008			—			$	—
Granted			17,500			$	31.60
Vested			—			$	—
Forfeited			—			$	—
Nonvested stock units outstanding at June 30, 2008			17,500			$	31.60

3. Comprehensive Income

     The following table reflects the Company’s comprehensive income after considering the effects of foreign currency translation adjustments for the three and six months ended June 30, 2008 and 2007 (in thousands):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Net income		$	81,422			$	139,551			$	158,831			$	255,352
Other comprehensive income (loss):
Foreign currency translation adjustment related to Canadian operations, net of tax			925				5,770				(2,081	)			6,418
Comprehensive income, net of tax		$	82,347			$	145,321			$	156,750			$	261,770

4. Property and Equipment

     Property and equipment consisted of the following at June 30, 2008 and December 31, 2007 (in thousands):

		June 30,				December 31,
		2008				2007
Equipment		$	2,811,632			$	2,748,007
Oil and natural gas properties			82,625				75,732
Buildings			56,328				50,955
Land			9,827				9,991
			2,960,412				2,884,685
Less accumulated depreciation and depletion			(1,086,901	)			(1,043,281	)
Property and equipment, net		$	1,873,511			$	1,841,404

5. Business Segments

     The Company’s revenues, operating profits and identifiable assets are primarily attributable to four business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services, (iii) drilling and completion fluid services and (iv) the investment, on a working interest basis, in oil and natural gas properties. Each of these segments represents a distinct type of business based upon the type and nature of services and products offered. These segments have separate management teams which report to the Company’s chief operating decision maker and have distinct and identifiable revenues and expenses. Separate financial data for each of our four business segments is provided in the table below (in thousands):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Revenues:
Contract drilling (a)		$	417,874			$	420,285			$	838,826			$	888,624
Pressure pumping			57,094				51,592				99,958				90,176
Drilling and completion fluids (b)			38,746				39,702				71,346				70,583
Oil and natural gas			13,609				12,108				22,600				22,367
Total segment revenues			527,323				523,687				1,032,730				1,071,750
Elimination of intercompany revenues (a)(b)			(1,040	)			(1,129	)			(1,893	)			(2,091	)
Total revenues		$	526,283			$	522,558			$	1,030,837			$	1,069,659
Income before income taxes:
Contract drilling		$	106,795			$	137,712			$	225,181			$	309,417
Pressure pumping			14,277				17,599				18,729				27,840
Drilling and completion fluids			4,055				3,906				4,722				6,182
Oil and natural gas			7,173				5,116				11,470				7,729
			132,300				164,333				260,102				351,168
Corporate and other			(8,602	)			(7,607	)			(16,344	)			(14,515	)
Embezzlement (costs) recoveries (c)			—				41,935				—				41,935
Gain on disposal of assets (d)			2,721				16,475				2,535				16,273
Interest income			493				457				836				826
Interest expense			(63	)			(831	)			(340	)			(1,594	)
Other			353				109				737				203
Income before income taxes		$	127,202			$	214,871			$	247,526			$	394,296

		June 30,				December 31,
		2008				2007
Identifiable assets:
Contract drilling		$	2,154,535			$	2,132,910
Pressure pumping			188,976				154,120
Drilling and completion fluids			101,154				91,989
Oil and natural gas			36,742				37,885
Corporate and other (e)			102,550				48,295
Total assets		$	2,583,957			$	2,465,199

6. Goodwill

     Goodwill is evaluated at least annually to determine if the fair value of recorded goodwill has decreased below its carrying value. At December 31, 2007 the Company performed its annual goodwill evaluation and determined no adjustment to impair goodwill was necessary. Goodwill at both June 30, 2008 and December 31, 2007 includes $86.2 million in the Contract Drilling segment and $10.0 million in the Drilling and Completion Fluids segment.

7. Accrued Expenses

     Accrued expenses consisted of the following at June 30, 2008 and December 31, 2007 (in thousands):

		June 30,				December 31,
		2008				2007
Salaries, wages, payroll taxes and benefits		$	26,656			$	33,816
Workers’ compensation liability			65,596				70,989
Sales, use and other taxes			10,027				12,119
Insurance, other than workers’ compensation			16,443				16,308
Other			4,106				3,602
		$	122,828			$	136,834

8. Asset Retirement Obligation

     Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” requires that the Company record a liability for the estimated costs to be incurred in connection with the abandonment of oil and natural gas properties in the future. The following table describes the changes to the Company’s asset retirement obligations during the six months ended June 30, 2008 and 2007 (in thousands):

		2008				2007
Balance at beginning of year		$	1,593			$	1,829
Liabilities incurred			261				151
Liabilities settled			(207	)			(632	)
Accretion expense			29				31
Revision in estimated costs of plugging oil and natural gas wells			1,025				289
Asset retirement obligation at end of period		$	2,701			$	1,668

9. Borrowings Under Line of Credit

     The Company has an unsecured revolving line of credit (“LOC”) with a maximum borrowing capacity of $375 million. Interest is paid on outstanding LOC balances at a floating rate ranging from LIBOR plus 0.625% to 1.0% or the prime rate at the Company’s election. Any outstanding borrowings must be repaid at maturity on December 16, 2009. This arrangement includes various fees, including a commitment fee on the average daily unused amount (0.15% at June 30, 2008). There are customary restrictions and covenants associated with the LOC. Financial covenants provide for a maximum debt to capitalization ratio and a minimum interest coverage ratio. The Company does not expect that the restrictions and covenants will impact its ability to operate or react to opportunities that might arise. As of June 30, 2008, the Company had no borrowings outstanding under the LOC. However, the Company had $58.6 million in letters of credit outstanding and as a result, the Company had available borrowing capacity of approximately $316 million at June 30, 2008.

10. Commitments, Contingencies and Other Matters

     Commitments – As of June 30, 2008, the Company maintained letters of credit in the aggregate amount of $58.6 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 the calendar year and are typically renewed annually. As of June 30, 2008, no amounts had been drawn under the letters of credit.

     As of June 30, 2008, the Company had non-cancelable commitments to purchase approximately $61.7 million of equipment. In addition to commitments at June 30, 2008 the Company entered into agreements in July 2008 to purchase new drilling equipment totaling approximately $111 million.

     The Company is party to various legal proceedings arising in the normal course of its business. The Company does not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on its financial condition, results of operations or cash flows.

11. Stockholders’ Equity

     Cash Dividends — The Company paid cash dividends during the six months ended June 30, 2008 and 2007 as follows:

2008:		Per Share				Total
						(in thousands)
Paid on March 28, 2008		$	0.12			$	18,493
Paid on June 27, 2008			0.16				25,011
Total cash dividends		$	0.28			$	43,504

2007:		Per Share				Total
						(in thousands)
Paid on March 30, 2007		$	0.08			$	12,527
Paid on June 29, 2007			0.12				18,860
Total cash dividends		$	0.20			$	31,387

     On July 30, 2008, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.16 per share to be paid on September 30, 2008 to holders of record as of September 12, 2008. The amount and timing of all future dividend payments, if any, 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.

     On August 1, 2007, the Company’s Board of Directors approved a stock buyback program (“Program”), authorizing purchases of up to $250 million of the Company’s common stock in open market or privately negotiated transactions. As of June 30, 2008, the Company had authority remaining under the Program to purchase approximately $180 million of the Company’s outstanding common stock. Shares purchased under the Program are accounted for as treasury stock.

     The Company purchased 151,794 shares of treasury stock from employees during the six months ended June 30, 2008 to provide employees with the funds necessary to satisfy payroll tax withholding obligations upon the vesting of shares of restricted stock. The purchases were made at fair market value and the total purchase price for these shares was approximately $4.5 million. These purchases were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan and not pursuant to the Program.

12. Income Taxes

     The Company adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109 (“FIN 48”) on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of June 30, 2008, the Company had no unrecognized tax benefits. In connection with the adoption of FIN 48, the Company established a policy to account for interest and penalties with respect to income taxes as operating expenses. As of June 30, 2008, the tax years ended December 31, 2004 through December 31, 2007 are open for examination by U.S. taxing authorities. As of June 30, 2008, the tax years ended December 31, 2003 through December 31, 2007 are open for examination by Canadian taxing authorities.

13. Recently Issued Accounting Standards

     In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (“FAS 157”). FAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurement. The initial application of FAS 157 is limited to financial assets and liabilities and became effective on January 1, 2008 for the Company. The impact of the initial application was not material. The Company will adopt FAS 157 on a prospective basis for nonfinancial assets and liabilities that are not measured at fair value on a recurring basis on January 1, 2009. The application of FAS 157 to the Company’s nonfinancial assets and liabilities will primarily be limited to assets acquired and liabilities assumed in a business combination, asset retirement obligations and asset impairments, including goodwill and long-lived assets. This application of FAS 157 is not expected to have a material impact to the Company.

     In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”). FSB EITF 03-6-1 clarifies that share-based payment awards that entitle their holders to receive nonforfeitable dividends before vesting should be considered participating securities and, as such, should be included in the calculation of basic earnings-per-share using the two-class method. Certain of the Company’s share-based payment awards entitle the holders to receive nonforfeitable dividends and the application of the provisions of FSP EITF 03-6-1 may have the effect of reducing basic and diluted earnings-per-share by an immaterial amount. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, as well as interim periods within those years. Once effective, all prior-period earnings-per-share data presented must be adjusted retrospectively to conform with the provisions of the FSP. The FSP will be effective for the Company beginning in the quarter ending March 31, 2009 and early application is not permitted.

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

     Management Overview — We are a leading provider of contract services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and, to a lesser extent, we provide pressure pumping services and drilling and completion fluid services. In addition to the aforementioned contract services, we also invest, on a working interest basis, in oil and natural gas properties. For the three and six months ended June 30, 2008 and 2007, our operating revenues consisted of the following (dollars in thousands):

		Three Months Ended June 30,																Six Months Ended June 30,
		2008								2007								2008								2007
Contract drilling		$	416,835				79	%		$	419,191				80	%		$	836,984				81	%		$	886,689				83	%
Pressure pumping			57,094				11				51,592				10				99,958				10				90,176				8
Drilling and completion fluids			38,745				7				39,667				8				71,295				7				70,427				7
Oil and natural gas			13,609				3				12,108				2				22,600				2				22,367				2
		$	526,283				100	%		$	522,558				100	%		$	1,030,837				100	%		$	1,069,659				100	%

     We provide our contract services to oil and natural gas operators in many of the oil and natural gas producing regions of North America. Our contract drilling operations are focused in various regions of Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Alabama, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota, Pennsylvania and Western Canada, while our pressure pumping services are focused primarily in the Appalachian Basin. Our drilling and completion fluids services are provided to operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. The oil and natural gas properties in which we hold working interests are primarily located in West and South Texas, Southeastern New Mexico, Utah and Mississippi.

     Our consolidated net income for the second quarter of 2008 decreased by $58.1 million or 42% as compared to the second quarter of 2007. Included in consolidated net income for the second quarter of 2007 was a pre-tax gain of approximately $41.9 million associated with the recovery of embezzled funds and approximately $16.5 million in net pre-tax gains from the disposal of certain oil and natural gas properties and other assets. Excluding the above-mentioned gains, our consolidated net income for the second quarter of 2007 would have been approximately $102 million and the decrease in net income for the second quarter of 2008 would have been approximately $20.2 million or 20%.

     Typically, the profitability of our business is most readily assessed by two primary indicators in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During the second quarter of 2008, our average number of rigs operating was 244 per day compared to 237 in the second quarter of 2007. Our average revenue per operating day was $18,740 in the second quarter of 2008 compared to $19,410 in the second quarter of 2007. The decrease in our consolidated net income was primarily due to our contract drilling segment experiencing a decrease in the average revenue per operating day and an increase in the average costs per operating day in the second quarter of 2008 as compared to the second quarter of 2007.

     Our revenues, profitability and cash flows are highly dependent upon prevailing prices for natural gas and, to a lesser extent, oil. 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 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” included as Item 1A in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

     We believe that the liquidity shown on our balance sheet as of June 30, 2008, which includes approximately $335 million in working capital (including $62.2 million in cash and cash equivalents) and approximately $316 million available under a $375 million line of credit, provides us with the ability to build new equipment, make improvements to our equipment, expand into new regions, pursue acquisition opportunities, pay cash dividends and survive downturns in our industry.

     Commitments and Contingencies — As of June 30, 2008, we maintained letters of credit in the aggregate amount of $58.6 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 and are typically renewed annually. As of June 30, 2008, no amounts had been drawn under the letters of credit.

     As of June 30, 2008, we had non-cancelable commitments to purchase approximately $61.7 million of equipment. In addition to commitments at June 30, 2008, we entered into agreements in July 2008 to purchase new drilling equipment totaling approximately $111 million.

     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 and money market accounts.

     Description of Business — We conduct our contract drilling operations in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Alabama, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota, Pennsylvania and Western Canada. As of June 30, 2008, we had approximately 350 currently marketable land-based drilling rigs. We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. These services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. We provide drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. Drilling and completion fluids are used by oil and natural gas operators during the drilling process to control pressure when drilling oil and natural gas wells. We also invest, on a working interest basis, in oil and natural gas properties.

     The North American land drilling industry has experienced periods of downturn in demand at various times during 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 continue to adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include:

	•		movement of drilling rigs from region to region,
	•		reactivation of land-based drilling rigs, or
	•		construction of new drilling rigs.

     As a result of an increase in drilling activity and increased prices for drilling services in 2005 and 2006, construction of new drilling rigs increased significantly in that time period. The addition of new drilling rigs to the market resulted in excess capacity compared to demand, and construction of new drilling rigs moderated in 2007. With a recent increase in demand in 2008, we believe that further construction of new drilling rigs will continue. We cannot predict either the future level of demand for our contract drilling services or future conditions in the oil and natural gas contract drilling business.

Critical Accounting Policies

     In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. No changes in our critical accounting policies have occurred since the filing of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

Liquidity and Capital Resources

     As of June 30, 2008, we had working capital of $335 million including cash and cash equivalents of $62.2 million. For the six months ended June 30, 2008, our sources of cash flow included:

•

$273 million from operating activities,

•

$4.4 million in proceeds from the disposal of property and equipment, and

•

$41.4 million from the exercise of stock options and tax benefits associated with stock-based compensation.

     During the six months ended June 30, 2008, we used $43.5 million to pay dividends on our common stock, $50.0 million to repay borrowings under our line of credit, $4.6 million to repurchase our common stock and $176 million:

•

to build new drilling rigs,

•

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

•

to acquire and procure drilling equipment and facilities to support our drilling operations,

•

to fund capital expenditures for our pressure pumping and drilling and completion fluids divisions, and

•

to fund investments in oil and natural gas properties on a working interest basis.

     As of June 30, 2008, we had no borrowings outstanding under our $375 million revolving line of credit. However, we had $58.6 million in letters of credit outstanding and as a result, we had available borrowing capacity of approximately $316 million at June 30, 2008.

     We paid cash dividends during the six months ended June 30, 2008 as follows:

		Per Share				Total
						(in thousands)
Paid on March 28, 2008		$	0.12			$	18,493
Paid on June 27, 2008			0.16				25,011
Total cash dividends		$	0.28			$	43,504

     On July 30, 2008, our Board of Directors approved a cash dividend on our common stock in the amount of $0.16 per share to be paid on September 30, 2008 to holders of record as of September 12, 2008. The amount and timing of all future dividend payments, if any, is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our credit facilities and other factors.

     On August 1, 2007, our Board of Directors approved a stock buyback program (“Program”), authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions. As of June 30, 2008, we had authority remaining under the Program to purchase approximately $180 million of our outstanding common stock. Shares purchased under the Program are accounted for as treasury stock.

     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 on reasonable terms, if at all.

Results of Operations

     The following tables summarize operations by business segment for the three months ended June 30, 2008 and 2007:

Contract Drilling		2008				2007				% Change
		(Dollars in thousands)
Revenues		$	416,835			$	419,191				(0.6	)%
Direct operating costs		$	251,381			$	228,297				10.1	%
Selling, general and administrative		$	1,297			$	1,400				(7.4	)%
Depreciation		$	57,362			$	51,782				10.8	%
Operating income		$	106,795			$	137,712				(22.5	)%
Operating days			22,245				21,597				3.0	%
Average revenue per operating day		$	18.74			$	19.41				(3.5	)%
Average direct operating costs per operating day		$	11.30			$	10.57				6.9	%
Average rigs operating			244				237				3.0	%
Capital expenditures		$	67,815			$	129,913				(47.8	)%

     Revenues in the second quarter of 2008 were relatively flat as compared to the second quarter of 2007 as a result of a slight increase in the number of operating days offset by a slight decrease in the average revenue per operating day. Direct operating costs in the second quarter of 2008 increased as compared to the second quarter of 2007 as a result of increases in operating days and average direct operating costs per operating day. The increase in average direct operating costs per operating day includes costs incurred in activating drilling rigs. Significant capital expenditures have been incurred to build new drilling rigs, 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. The increase in depreciation expense was a result of the capital expenditures discussed above.

Pressure Pumping		2008				2007				% Change
		(Dollars in thousands)
Revenues		$	57,094			$	51,592				10.7	%
Direct operating costs		$	32,506			$	25,777				26.1	%
Selling, general and administrative		$	5,834			$	4,808				21.3	%
Depreciation		$	4,477			$	3,408				31.4	%
Operating income		$	14,277			$	17,599				(18.9	)%
Total jobs			3,400				3,573				(4.8	)%
Average revenue per job		$	16.79			$	14.44				16.3	%
Average direct operating costs per job		$	9.56			$	7.21				32.6	%
Capital expenditures		$	17,689			$	14,206				24.5	%

     Revenues and direct operating costs increased as a result of an increase in the average revenue and average direct operating costs per job. Increased average revenue per job was due to increased pricing for our services and an increase in larger jobs being driven by demand for services associated with unconventional reservoirs in the Appalachian Basin. Average direct operating costs per job increased as a result of increases in compensation, maintenance and the cost of materials used in our operations, as well as an increase in larger jobs. Selling, general and administrative expense increased primarily as a result of expenses to support the expanding operations of the pressure pumping segment. Significant capital expenditures have been incurred to add capacity, expand our areas of operation and modify and upgrade existing equipment. The increase in depreciation expense is a result of the capital expenditures discussed above.

Drilling and Completion Fluids		2008				2007				% Change
		(Dollars in thousands)
Revenues		$	38,745			$	39,667				(2.3	)%
Direct operating costs		$	31,449			$	32,628				(3.6	)%
Selling, general and administrative		$	2,517			$	2,436				3.3	%
Depreciation		$	724			$	697				3.9	%
Operating income		$	4,055			$	3,906				3.8	%
Capital expenditures		$	1,525			$	1,023				49.1	%

     The results of operations in our drilling and completions fluids division in the second quarter of 2008 were relatively consistent with those in the second quarter of 2007.

Oil and Natural Gas Production and Exploration		2008				2007				% Change
		(Dollars in thousands,
		except sales prices)
Revenues		$	13,609			$	12,108				12.4	%
Direct operating costs		$	3,529			$	2,461				43.4	%
Selling, general and administrative		$	—			$	674				(100.0	)%
Depreciation, depletion and impairment		$	2,907			$	3,857				(24.6	)%
Operating income		$	7,173			$	5,116				40.2	%
Capital expenditures		$	4,527			$	4,619				(2.0	)%
Average net daily oil production (Bbls)			814				1,107				(26.5	)%
Average net daily natural gas production (Mcf)			4,126				6,444				(36.0	)%
Average oil sales price (per Bbl)		$	123.71			$	63.04				96.2	%
Average natural gas sales price (per Mcf)		$	11.85			$	7.84				51.1	%

     Revenues increased due to an increase in the average sales price of oil and natural gas partially offset by a decrease in the average net daily production of oil and natural gas and by the elimination of well operations revenue due to the sale in the fourth quarter of 2007 of the operating responsibilities associated with oil and natural gas wells. Average net daily oil and natural gas production decreased primarily due to production declines. The increase in direct operating costs is due to an increase of approximately $610,000 in costs associated with the abandonment of exploratory wells, as well as increased production taxes and other production costs. Selling, general and administrative expenses decreased in the second quarter of 2008 due to the sale of operating responsibilities mentioned above and the resulting elimination of headcount in our oil and natural gas production and exploration segment. Depreciation, depletion and impairment expense in the second quarter of 2008 includes approximately $79,000 incurred to impair certain oil and natural gas properties compared to approximately $534,000 incurred to impair certain oil and natural gas properties in

the second quarter of 2007. Depletion expense decreased approximately $439,000 primarily due to the lower production of oil and natural gas.

Corporate and Other		2008				2007				% Change
		(Dollars in thousands)
Selling, general and administrative		$	8,099			$	7,004				15.6	%
Depreciation		$	203			$	203				0.0	%
Other operating expenses		$	300			$	400				(25.0	)%
Gain on disposal of assets		$	(2,721	)		$	(16,475	)			(83.5	)%
Embezzlement costs (recoveries)		$	—			$	(41,935	)			(100.0	)%
Interest income		$	493			$	457				7.9	%
Interest expense		$	63			$	831				(92.4	)%
Other income		$	353			$	109				223.9	%

     Selling, general and administrative expense increased primarily as a result of additional compensation expense and an increase in payroll tax expense associated with the exercise of stock options during the second quarter of 2008. The decrease in gain on disposal of assets in the second quarter of 2008 compared to the second quarter of 2007 is due to a sale in the second quarter of 2007 of certain oil and natural gas properties. Gains and losses on the disposal of assets are considered as part of our corporate activities due to the fact that such transactions relate to decisions of the executive management group regarding corporate strategy. Embezzlement costs (recoveries) in the second quarter of 2007 includes a recovery of $42.5 million, reduced by approximately $600,000 in professional and other costs incurred.

     The following tables summarize operations by business segment for the six months ended June 30, 2008 and 2007:

Contract Drilling		2008				2007				% Change
		(Dollars in thousands)
Revenues		$	836,984			$	886,689				(5.6	)%
Direct operating costs		$	495,748			$	474,451				4.5	%
Selling, general and administrative		$	2,821			$	2,851				(1.1	)%
Depreciation		$	113,234			$	99,970				13.3	%
Operating income		$	225,181			$	309,417				(27.2	)%
Operating days			44,478				44,569				(0.2	)%
Average revenue per operating day		$	18.82			$	19.89				(5.4	)%
Average direct operating costs per operating day		$	11.15			$	10.65				4.7	%
Average rigs operating			244				246				(0.8	)%
Capital expenditures		$	135,026			$	283,189				(52.3	)%

     Revenues in the first six months of 2008 decreased as compared to the first six months of 2007 as a result of decreases in the average revenue per operating day and in the number of operating days. Direct operating costs in the first six months of 2008 increased as compared to the first six months of 2007 as a result of the increase in average direct operating costs per operating day. The increase in average direct operating costs per operating day includes costs incurred in activating drilling rigs. The reactivation and construction of new land drilling rigs in the United States has resulted in excess capacity compared to demand. Operating days, average rigs operating and average revenue per operating day decreased in the first six months of 2008 as a result of the excess capacity of drilling rigs. Significant capital expenditures have been incurred to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. The increase in depreciation expense was a result of the capital expenditures discussed above.

Pressure Pumping		2008				2007				% Change
		(Dollars in thousands)
Revenues		$	99,958			$	90,176				10.8	%
Direct operating costs		$	61,011			$	46,928				30.0	%
Selling, general and administrative		$	11,441			$	8,876				28.9	%
Depreciation		$	8,777			$	6,532				34.4	%
Operating income		$	18,729			$	27,840				(32.7	)%
Total jobs			6,311				6,412				(1.6	)%
Average revenue per job		$	15.84			$	14.06				12.7	%
Average direct operating costs per job		$	9.67			$	7.32				32.1	%
Capital expenditures		$	30,648			$	30,631				0.1	%

     Revenues and direct operating costs increased as a result of an increase in the average revenue and average direct operating costs per job. Increased average revenue per job was due to increased pricing for our services and an increase in larger jobs being driven by demand for services associated with unconventional reservoirs in the Appalachian Basin. Average direct operating costs per job increased as a result of increases in compensation, maintenance and the cost of materials used in our operations, as well as an increase in larger jobs. Selling, general and administrative expense increased primarily as a result of expenses to support the expanding operations of the pressure pumping segment. Significant capital expenditures have been incurred to add capacity, expand our areas of operation and modify and upgrade existing equipment. The increase in depreciation expense is a result of the capital expenditures discussed above.

Drilling and Completion Fluids		2008				2007				% Change
		(Dollars in thousands)
Revenues		$	71,295			$	70,427				1.2	%
Direct operating costs		$	59,982			$	58,019				3.4	%
Selling, general and administrative		$	5,143			$	4,833				6.4	%
Depreciation		$	1,448			$	1,393				3.9	%
Operating income		$	4,722			$	6,182				(23.6	)%
Capital expenditures		$	1,533			$	2,121				(27.7	)%

     Operating income in the first six months of 2007 included a reduction in direct operating costs of approximately $1.3 million related to a recovery received on an insurance claim. The results of operations in our drilling and completions fluids division in the first six months of 2008 were relatively consistent with those in the first six months of 2007 excluding the insurance recovery in 2007 mentioned above.

Oil and Natural Gas Production and Exploration		2008				2007				% Change
		(Dollars in thousands,
		except sales prices)
Revenues		$	22,600			$	22,367				1.0	%
Direct operating costs		$	5,596			$	5,739				(2.5	)%
Selling, general and administrative		$	—			$	1,322				(100.0	)%
Depreciation, depletion and impairment		$	5,534			$	7,577				(27.0	)%
Operating income		$	11,470			$	7,729				48.4	%
Capital expenditures		$	8,955			$	9,651				(7.2	)%
Average net daily oil production (Bbls)			758				1,104				(31.3	)%
Average net daily natural gas production (Mcf)			3,776				5,944				(36.5	)%
Average oil sales price (per Bbl)		$	111.23			$	59.69				86.3	%
Average natural gas sales price (per Mcf)		$	10.57			$	7.53				40.4	%

     Revenues increased due to an increase in the average sales price of oil and natural gas partially offset by a decrease in the average net daily production of oil and natural gas and by the elimination of well operations revenue due to the sale in the fourth quarter of 2007 of the operating responsibilities associated with oil and natural gas wells. Average net daily oil and natural gas production decreased primarily due to the sale of properties in 2007 and production declines. Selling, general and administrative expenses decreased in the first six months of 2008 due to the sale of the operating responsibilities mentioned above and the resulting elimination of headcount in our oil and natural gas production and exploration segment. Depreciation, depletion and impairment expense in the first six months of 2008 includes approximately $300,000 incurred to impair certain oil and natural gas properties compared to approximately $1.1 million incurred to impair certain oil and natural gas properties in the first six months of 2007. Depletion expense decreased approximately $1.2 million primarily due to the sale of certain properties in 2007.

Corporate and Other		2008				2007				% Change
		(Dollars in thousands)
Selling, general and administrative		$	15,338			$	13,109				17.0	%
Depreciation		$	406			$	406				0.0	%
Other operating expenses		$	600			$	1,000				(40.0	)%
Gain on disposal of assets		$	(2,535	)		$	(16,273	)			(84.4	)%
Embezzlement costs (recoveries)		$	—			$	(41,935	)			(100.0	)%
Interest income		$	836			$	826				1.2	%
Interest expense		$	340			$	1,594				(78.7	)%
Other income		$	737			$	203				263.1	%

     Selling, general and administrative expense increased primarily as a result of additional compensation expense and an increase in payroll tax expense associated with the exercise of stock options during the first six months of 2008. The decrease in gain on disposal of assets in the first six months of 2008 compared to the first six months of 2007 is due to a sale in 2007 of certain oil and natural gas properties. Gains and losses on the disposal of assets are considered part of our corporate activities due to the fact that such transactions relate to decisions of the executive management group regarding corporate strategy. Embezzlement costs (recoveries) in the first six months of 2007 included a recovery of $42.5 million, reduced by approximately $600,000 in professional and other costs incurred.

Recently Issued Accounting Standards

     In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (“FAS 157”). FAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurement. The initial application of FAS 157 is limited to financial assets and liabilities and became effective on January 1, 2008 for us. The impact of the initial application was not material. We will adopt FAS 157 on a prospective basis for nonfinancial assets and liabilities that are not measured at fair value on a recurring basis on January 1, 2009. The application of FAS 157 to our nonfinancial assets and liabilities will primarily be limited to assets acquired and liabilities assumed in a business combination, asset retirement obligations and asset impairments, including goodwill and long-lived assets. This application of FAS 157 is not expected to have a material impact to us.

     In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”). FSB EITF 03-6-1 clarifies that share-based payment awards that entitle their holders to receive nonforfeitable dividends before vesting should be considered participating securities and, as such, should be included in the calculation of basic earnings-per-share using the two-class method. Certain of our share-based payment awards entitle the holders to receive nonforfeitable dividends and the application of the provisions of FSP EITF 03-6-1 may have the effect of reducing basic and diluted earnings-per-share by an immaterial amount. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, as well as interim periods within those years. Once effective, all prior-period earnings-per-share data presented must be adjusted retrospectively to conform with the provisions of the FSP. The FSP will be effective for us beginning in the quarter ending March 31, 2009 and early application is not permitted.

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

     Our revenue, profitability, and rate of growth are substantially dependent upon prevailing prices for natural gas and, to a lesser extent, oil. For many years, oil and natural gas prices and markets have been volatile. Prices are affected by market supply and demand factors as well as international military, political and economic conditions, and the ability of OPEC to set and maintain production and price targets. All of these factors are beyond our control. During 2006, the average market price of natural gas retreated from record highs that were set in 2005. The price dropped from an average of $8.98 per Mcf in 2005 to an average of $6.94 per Mcf in 2006 and an average of $7.18 per Mcf in 2007. This resulted in our customers moderating their increase in drilling activities during 2007. This moderation combined with the reactivation and construction of new land drilling rigs in the United States resulted in excess capacity. Prices have rebounded to an average of $10.33 per Mcf for the first six months of 2008 and activity has increased. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. A significant decrease in market prices for natural gas could result in a material decrease in demand for drilling rigs and adversely affect our operating results.

     The North American land drilling industry has experienced many downturns in demand at various times during 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.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

     We currently have exposure to interest rate market risk associated with borrowings under our credit facility. The revolving credit facility calls for periodic interest payments at a floating rate ranging from LIBOR plus 0.625% to 1.0% or at the prime rate at our election. The applicable rate above LIBOR is based upon our debt to capitalization ratio. Our exposure to interest rate risk due to changes in the prime rate or LIBOR is not material due to the fact that we had no outstanding borrowings as of June 30, 2008.

     We conduct some business in Canadian dollars through our Canadian land-based drilling operations. The exchange rate between Canadian dollars and U.S. dollars has fluctuated during the last several years. If the value of the Canadian dollar against the

U.S. dollar weakens, revenues and earnings of our Canadian operations will be reduced and the value of our Canadian net assets will decline when they are translated to U.S. dollars. This currency rate risk is not material to our results of operations or financial condition.

ITEM 4. Controls and Procedures

     Disclosure Controls and Procedures — We maintain disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), designed to ensure that the information required to be disclosed in the reports that we file with the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosure.

     Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2008.

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

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

     “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in Item 2 of Part I of this Quarterly Report on Form 10-Q 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;
	•		Excess industry capacity of land drilling rigs resulting from the reactivation or construction of new land drilling rigs;
	•		Changes in demand for contract drilling, pressure pumping and drilling and completion fluids services;
	•		Shortages of drill pipe and other drilling equipment;
	•		Labor shortages, primarily qualified drilling personnel;
	•		Effects of competition from other drilling contractors and providers of pressure pumping and drilling and completion fluids services;
	•		Occurrence of operating hazards and uninsured losses inherent in our business operations; and
	•		Environmental and other governmental regulation.

     For a more complete explanation of these factors and others, see “Risk Factors” included as Item 1A in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

     You are cautioned not to place undue reliance on any of our forward-looking statements, which speak only as of the date of this Quarterly Report on Form 10-Q or, in the case of documents incorporated by reference, the date of those documents.

PART II — OTHER INFORMATION

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

     The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended June 30, 2008.

														Approximate Dollar
										Total Number of				Value of Shares
										Shares (or Units)				That May yet be
										Purchased as Part				Purchased Under the
		Total				Average Price				of Publicly				Plans or
		Number of Shares				Paid per				Announced Plans				Programs (in
Period Covered		Purchased				Share				or Programs				thousands)(1)
April 1-30, 2008 (2)			77,354			$	29.00				—			$	179,646
May 1-31, 2008			—			$	—				—			$	179,646
June 1-30, 2008 (3)			58,626			$	33.58				2,047			$	179,573
Total			135,980			$	30.98				2,047			$	179,573