PATTERSON UTI ENERGY INC - Quarter Report: 2009 March (Form 10-Q)

 

 

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

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

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 Regulation S-T (section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o 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 (Do not check if a smaller reporting company)		Smaller reporting company 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.

     153,374,441 shares of common stock, $0.01 par value, as of May 1, 2009

 

 

		Page
PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements
Unaudited consolidated balance sheets			1
Unaudited consolidated statements of income			2
Unaudited consolidated statements of changes in stockholders’ equity			3
Unaudited consolidated statements of cash flows			5
Notes to unaudited consolidated financial statements			6
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			13
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk			18
ITEM 4. Controls and Procedures			18
Forward Looking Statements and Cautionary Statements for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995			18
PART II — OTHER INFORMATION
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds			19
ITEM 5. Other Information			19
ITEM 6. Exhibits			19
Signature			20
EX-31.1
EX-31.2
EX-32.1

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)

		March 31,				December 31,
		2009				2008
ASSETS
Current assets:
Cash and cash equivalents		$	192,288			$	81,223
Accounts receivable, net of allowance for doubtful accounts of $12,712 and $9,330 at March 31, 2009 and December 31, 2008, respectively			198,946				414,531
Federal and state income taxes receivable			13,002				10,175
Inventory			42,695				41,999
Deferred tax assets, net			39,443				35,928
Other			51,368				57,518
Total current assets			537,742				641,374
Property and equipment, net			1,994,881				1,937,112
Goodwill			86,234				86,234
Deposits on equipment purchases			23,527				43,944
Other			9,298				4,153
Total assets		$	2,651,682			$	2,712,817
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	108,657			$	169,958
Accrued expenses			108,275				132,655
Total current liabilities			216,932				302,613
Deferred tax liabilities, net			290,124				277,717
Other			5,580				5,545
Total liabilities			512,636				585,875
Commitments and contingencies (see Note 9)			—				—
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 180,218,075 and 180,192,093 issued and 153,102,083 and 153,094,803 outstanding at March 31, 2009 and December 31, 2008, respectively			1,801				1,801
Additional paid-in capital			769,652				765,512
Retained earnings			1,979,372				1,970,824
Accumulated other comprehensive income			5,406				5,774
Treasury stock, at cost, 27,115,992 shares and 27,097,290 shares at March 31, 2009 and December 31, 2008, respectively			(617,185	)			(616,969	)
Total stockholders’ equity			2,139,046				2,126,942
Total liabilities and stockholders’ equity		$	2,651,682			$	2,712,817

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 data)

		Three Months Ended
		March 31,
		2009				2008
Operating revenues:
Contract drilling		$	225,704			$	420,149
Pressure pumping			38,105				42,864
Drilling and completion fluids			27,830				32,550
Oil and natural gas			4,400				8,991
			296,039				504,554
Operating costs and expenses:
Contract drilling			126,321				244,367
Pressure pumping			27,006				28,505
Drilling and completion fluids			24,522				28,533
Oil and natural gas			1,976				2,067
Depreciation, depletion and impairment			70,347				63,726
Selling, general and administrative			15,984				16,996
Net loss on asset disposals/retirements			174				186
Other operating expenses			4,000				300
			270,330				384,680
Operating income			25,709				119,874
Other income (expense):
Interest income			61				343
Interest expense			(447	)			(277	)
Other			23				384
			(363	)			450
Income before income taxes			25,346				120,324
Income tax expense:
Current			38				28,712
Deferred			9,105				14,203
			9,143				42,915
Net income		$	16,203			$	77,409
Net income per common share:
Basic		$	0.11			$	0.50
Diluted		$	0.11			$	0.50
Weighted average number of common shares outstanding:
Basic			151,735				152,600
Diluted			151,829				154,325
Cash dividends per common share		$	0.05			$	0.12

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, 2008			180,192			$	1,801			$	765,512			$	1,970,824			$	5,774			$	(616,969	)		$	2,126,942
Comprehensive income:
Net income			—				—				—				16,203				—				—				16,203
Foreign currency translation adjustment, net of tax of $213			—				—				—				—				(368	)			—				(368	)
Total comprehensive income			—				—				—				16,203				(368	)			—				15,835
Issuance of restricted stock			17				—				—				—				—				—				—
Forfeitures of restricted stock			(9	)			—				—				—				—				—				—
Exercise of stock options			18				—				37				—				—				—				37
Stock-based compensation			—				—				4,694				—				—				—				4,694
Tax expense related to stock-based compensation			—				—				(591	)			—				—				—				(591	)
Payment of cash dividends			—				—				—				(7,655	)			—				—				(7,655	)
Purchase of treasury stock			—				—				—				—				—				(216	)			(216	)
Balance, March 31, 2009			180,218			$	1,801			$	769,652			$	1,979,372			$	5,406			$	(617,185	)		$	2,139,046

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
Comprehensive income:
Net income			—				—				—				77,409				—				—				77,409
Foreign currency translation adjustment, net of tax of $1,743			—				—				—				—				(3,006	)			—				(3,006	)
Total comprehensive income			—				—				—				77,409				(3,006	)			—				74,403
Issuance of restricted stock			12				—				—				—				—				—				—
Forfeitures of restricted stock			(11	)			—				—				—				—				—				—
Exercise of stock options			278				3				2,803				—				—				—				2,806
Stock-based compensation			—				—				5,118				—				—				—				5,118
Tax benefit related to stock-based compensation			—				—				541				—				—				—				541
Payment of cash dividends			—				—				—				(18,493	)			—				—				(18,493	)
Purchase of treasury stock			—				—				—				—				—				(347	)			(347	)
Balance, March 31, 2008			177,665			$	1,776			$	712,043			$	1,775,536			$	17,201			$	(546,498	)		$	1,960,058

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, in thousands)

		Three Months Ended
		March 31,
		2009				2008
Cash flows from operating activities:
Net income		$	16,203			$	77,409
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and impairment			70,347				63,726
Provision for bad debts			4,000				300
Dry holes and abandonments			127				(85	)
Deferred income tax expense			9,105				14,203
Stock-based compensation expense			4,694				5,118
Net loss on asset disposals/retirements			174				186
Changes in operating assets and liabilities:
Accounts receivable			211,182				(167	)
Income taxes receivable/payable			(1,152	)			26,230
Inventory and other assets			5,826				2,777
Accounts payable			(81,306	)			14,569
Accrued expenses			(24,340	)			(13,771	)
Other liabilities			35				(8,638	)
Net cash provided by operating activities			214,895				181,857
Cash flows from investing activities:
Purchases of property and equipment			(89,798	)			(84,606	)
Proceeds from disposal of assets			441				1,281
Net cash used in investing activities			(89,357	)			(83,325	)
Cash flows from financing activities:
Purchases of treasury stock			(216	)			(347	)
Dividends paid			(7,655	)			(18,493	)
Tax benefit (expense) related to stock-based compensation			(591	)			541
Repayment of borrowings under line of credit			—				(50,000	)
Line of credit issuance costs			(5,548	)			—
Proceeds from exercise of stock options			37				2,806
Net cash used in financing activities			(13,973	)			(65,493	)
Effect of foreign exchange rate changes on cash			(500	)			(146	)
Net increase in cash and cash equivalents			111,065				32,893
Cash and cash equivalents at beginning of period			81,223				17,434
Cash and cash equivalents at end of period		$	192,288			$	50,327
Supplemental disclosure of cash flow information:
Net cash paid during the period for:
Interest expense		$	15			$	287
Income taxes		$	264			$	864

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 unaudited interim 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. Except for wholly-owned subsidiaries, the Company has no controlling financial interests in any entity which would require consolidation.

     The unaudited interim consolidated financial statements have been prepared by management of the Company 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, 2008, 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, 2008.

     The U.S. dollar is the functional currency for all of the Company’s operations except for its Canadian operations, which uses the Canadian dollar as its 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”). The Company adopted the provisions of 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”) in the quarter ended March 31, 2009. FSP EITF 03-6-1 clarifies that share-based payment awards that entitle their holders to receive non-forfeitable dividends before vesting should be considered participating securities and, as such, should be included in the calculation of earnings-per-share using the two-class method. All earnings per share data presented for the three months ended March 31, 2008 has been adjusted retrospectively to conform with the provisions of FSP EITF 03-6-1. The impact of this retrospective application was to reduce basic EPS for the three months ended March 31, 2008 by $0.01.

     Basic EPS excludes dilution and is computed by first allocating earnings between common stockholders and holders of unvested shares of restricted stock. Basic EPS is then determined by dividing the earnings attributable to common stockholders by the weighted average number of common shares outstanding during the period.

     Diluted EPS is based on the weighted-average number of common shares outstanding plus the dilutive effect of potential common shares, including stock options, non-vested shares of restricted stock and restricted stock unit awards. The dilutive effect of stock options and restricted stock unit awards is determined based on the treasury stock method. The dilutive effect of non-vested shares of restricted stock is based on the more dilutive of the treasury stock method or the two-class method assuming a reallocation of undistributed earnings to common stockholders after considering the dilutive effect of potential common shares other than non-vested shares of restricted stock.

     The following table presents information necessary to calculate net income per share for the three months ended March 31, 2009 and 2008 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 months ended March 31, 2009 and 2008 (in thousands, except per share amounts):

		Three Months Ended
		March 31,
		2009				2008
BASIC EPS:
Net income		$	16,203			$	77,409
Less earnings attributed to holders of non-vested restricted stock			(144	)			(715	)
Earnings attributed to common stockholders		$	16,059			$	76,694
Weighted average number of common shares outstanding			151,735				152,600
Basic net income per common share		$	0.11			$	0.50
DILUTED EPS:
Earnings attributed to common stockholders		$	16,059			$	76,694
Add incremental earnings related to potential common shares			—				6
Adjusted earnings attributed to common stockholders		$	16,059			$	76,700
Weighted average number of common shares outstanding			151,735				152,600
Add dilutive effect of potential common shares			94				1,725
Weighted average number of diluted common shares outstanding			151,829				154,325
Diluted net income per common share		$	0.11			$	0.50
Potentially dilutive securities excluded as anti-dilutive			6,759				1,840

     The results of operations for the three months ended March 31, 2009 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-based method. The Company uses share-based awards to compensate employees and non-employee directors. All share-based awards have been equity instruments in the form of stock options, restricted stock awards or restricted stock unit awards and have included 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 restricted stock units 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 month periods ended March 31, 2009 and 2008 follow:

		Three Months Ended
		March 31,
		2009				2008
Volatility			47.26	%			35.42	%
Expected term (in years)			4.00				4.00
Dividend yield			5.56	%			2.46	%
Risk-free interest rate			1.28	%			3.26	%

     Stock option activity from January 1, 2009 to March 31, 2009 follows:

						Weighted
						Average
		Underlying				Exercise
		Shares				Price
Outstanding at January 1, 2009			5,933,572			$	21.20
Granted			40,000			$	11.51
Exercised			(18,000	)		$	2.06
Expired			—			$	—
Outstanding at March 31, 2009			5,955,572			$	21.20
Exercisable at March 31, 2009			4,651,627			$	20.03

     Restricted Stock. For all restricted stock awards to date, shares of common stock were issued when the awards were made. Non-vested shares are subject to forfeiture for failure to fulfill service conditions and, in certain cases, performance conditions. Non-forfeitable dividends are paid on non-vested shares of restricted stock. For restricted stock awards made prior to 2008, the Company used the “graded-vesting” attribution method to recognize periodic compensation cost over the vesting period. For restricted stock awards made in 2008 and thereafter, the Company uses the straight-line method to recognize periodic compensation cost over the vesting period.

     Restricted stock activity from January 1, 2009 to March 31, 2009 follows:

						Weighted
						Average
						Grant Date
		Shares				Fair Value
Non-vested restricted stock outstanding at January 1, 2009			1,429,571			$	28.49
Granted			17,000			$	11.92
Vested			(95,124	)		$	31.28
Forfeited			(9,018	)		$	28.44
Non-vested restricted stock outstanding at March 31, 2009			1,342,429			$	28.08

     Restricted Stock Units. For all restricted stock unit awards made to date, shares of common stock are not issued until the units vest. Restricted stock units are subject to forfeiture for failure to fulfill service conditions. Non-forfeitable cash dividend equivalents are paid on non-vested restricted stock units.

     Restricted stock unit activity from January 1, 2009 to March 31, 2009 follows:

						Weighted
						Average
						Grant Date
		Shares				Fair Value
Non-vested restricted stock units outstanding at January 1, 2009			17,500			$	31.60
Granted			—			$	—
Vested			—			$	—
Forfeited			—			$	—
Non-vested restricted stock units outstanding at March 31, 2009			17,500			$	31.60

3. Property and Equipment

     Property and equipment consisted of the following at March 31, 2009 and December 31, 2008 (in thousands):

		March 31,				December 31,
		2009				2008
Equipment		$	3,016,427			$	2,897,431
Oil and natural gas properties			88,161				89,809
Buildings			64,826				61,529
Land			10,220				10,196
			3,179,634				3,058,965
Less accumulated depreciation and depletion			(1,184,753	)			(1,121,853	)
Property and equipment, net		$	1,994,881			$	1,937,112

4. 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. The results of operations in these segments are regularly reviewed by the chief operating decision maker for purposes of determining resource allocation and assessing performance. Separate financial data for each of our four business segments is provided in the table below (in thousands):

		Three Months Ended
		March 31,
		2009				2008
Revenues:
Contract drilling (a)		$	225,822			$	420,952
Pressure pumping			38,105				42,864
Drilling and completion fluids (b)			27,830				32,600
Oil and natural gas			4,400				8,991
Total segment revenues			296,157				505,407
Elimination of intercompany revenues (a)(b)			(118	)			(853	)
Total revenues		$	296,039			$	504,554
Income (loss) before income taxes:
Contract drilling		$	41,011			$	118,386
Pressure pumping			(875	)			4,452
Drilling and completion fluids			518				667
Oil and natural gas			(3,556	)			4,297
			37,098				127,802
Corporate and other			(11,215	)			(7,742	)
Net loss on asset disposals/retirements (c)			(174	)			(186	)
Interest income			61				343
Interest expense			(447	)			(277	)
Other			23				384
Income before income taxes		$	25,346			$	120,324

		March 31,				December 31,
		2009				2008
Identifiable assets:
Contract drilling		$	2,105,672			$	2,255,421
Pressure pumping			215,430				210,805
Drilling and completion fluids			81,328				99,433
Oil and natural gas			25,540				31,760
Corporate and other (d)			223,712				115,398
Total assets		$	2,651,682			$	2,712,817

5. Goodwill

     Goodwill is evaluated at least annually to determine if the fair value of recorded goodwill has decreased below its carrying value. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. The Company’s reporting units for impairment testing have been determined to be its operating segments.

     In connection with its annual goodwill impairment assessment performed as of December 31, 2008, the Company performed an impairment test of its contract drilling and drilling and completion fluids reporting units under the provisions of FAS 142. In light of the adverse market conditions affecting the Company’s common stock price beginning in the fourth quarter of 2008 and continuing into 2009, including a significant decrease in the number of its rigs operating and a significant decline in oil and natural gas commodity prices, management utilized a discounted cash flow methodology to estimate the fair values of the Company’s reporting units.

     Based on the results of the first step of the impairment test, management concluded that no impairment was indicated in its contract drilling reporting unit; however, an impairment was indicated in its drilling and completion fluids reporting unit. Management performed the second step of the analysis of its drilling and completion fluids reporting unit, allocating the estimated fair value to the identifiable tangible and intangible assets and liabilities of this reporting unit based on their respective values. This allocation indicated no residual value for goodwill, and accordingly the Company recorded an impairment charge of approximately $10.0 million in its drilling and completion fluids reporting unit in the fourth quarter of 2008 and reduced the carrying value of goodwill in that reporting unit to zero.

     As of March 31, 2009 and December 31, 2008 the Company had goodwill of $86.2 million in its contract drilling reporting unit. In the event that market conditions remain weak, the Company may be required to record an impairment of goodwill in its contract drilling reporting unit in the future, and such impairment could be material.

6. Accrued Expenses

     Accrued expenses consisted of the following at March 31, 2009 and December 31, 2008 (in thousands):

		March 31,				December 31,
		2009				2008
Salaries, wages, payroll taxes and benefits		$	13,911			$	30,334
Workers’ compensation liability			67,531				70,439
Sales, use and other taxes			8,570				12,015
Insurance, other than workers’ compensation			14,157				14,209
Other			4,106				5,658
		$	108,275			$	132,655

7. 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. This liability is included in the caption “other” in the liabilities section of the Company’s consolidated balance sheet. The following table describes the changes to the Company’s asset retirement obligations during the three months ended March 31, 2009 and 2008 (in thousands):

		2009				2008
Balance at beginning of year		$	3,047			$	1,593
Liabilities incurred			48				125
Liabilities settled			(37	)			(66	)
Accretion expense			30				15
Revision in estimated costs of plugging oil and natural gas wells			(14	)			1,025
Asset retirement obligation at end of period		$	3,074			$	2,692

8. Borrowings Under Line of Credit

     The Company entered into an unsecured revolving line of credit (“LOC”) on March 20, 2009 with a maximum borrowing and letter of credit capacity of $220 million, including a letter of credit sublimit of $150 million and a swing line sublimit of $40 million. In addition, the aggregate borrowing and letter of credit capacity under the LOC may, subject to the terms and conditions set forth therein including the receipt of additional commitments from lenders, be increased up to a maximum amount not to exceed $450 million. This LOC replaced an existing $375 million unsecured line of credit, which was terminated when the LOC was established. Interest is paid on the outstanding principal amount of LOC borrowings at a floating rate based on, at the Company’s election, LIBOR or a base rate. The margin on LIBOR loans ranges from 3.00% to 4.00% and the margin on base rate loans ranges from 2.00% to 3.00%, based on the Company’s debt to capitalization ratio. At March 31, 2009, the margin on LIBOR loans would have been 3.00% and the margin on base rate loans would have been 2.00%. Any outstanding borrowings must be repaid at maturity on January 31, 2012 and letters of credit may remain in effect up to six months after such maturity date. This LOC facility includes various fees, including a commitment fee on the actual daily unused commitment (such commitment fee rate was 1.00% at March 31, 2009).

     The company incurred debt issuance costs of approximately $5.5 million during the three months ended March 31, 2009 in connection with entering into the LOC. These costs are being amortized on a straight line basis over the contractual term of the LOC as an adjustment to interest expense.

     There are customary representations, warranties, 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 March 31, 2009, the Company had no borrowings outstanding under the LOC. The Company had $57.5 million in letters of credit outstanding at March 31, 2009, however, and as a result the Company had available borrowing capacity of $162.5 million at that date. Each domestic subsidiary of the Company has unconditionally guaranteed the existing and future obligations of the Company and each other guarantor under the LOC and related loan documents, as well as obligations of the Company and its subsidiaries under interest rate swap contracts entered into with lenders party to the LOC.

9. Commitments, Contingencies and Other Matters

     Commitments — As of March 31, 2009, the Company maintained letters of credit in the aggregate amount of $57.5 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 March 31, 2009, no amounts had been drawn under the letters of credit.

     As of March 31, 2009, the Company had commitments to purchase approximately $231 million of major equipment.

     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.

10. Stockholders’ Equity

     Cash Dividends — The Company paid cash dividends during the three months ended March 31, 2008 and 2009 as follows:

2008:		Per Share				Total
						(in thousands)
Paid on March 28, 2008		$	0.12			$	18,493
Total cash dividends		$	0.12			$	18,493

2009:		Per Share				Total
						(in thousands)
Paid on March 31, 2009		$	0.05			$	7,655
Total cash dividends		$	0.05			$	7,655

     On April 29, 2009, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.05 per share to be paid on June 30, 2009 to holders of record as of June 15, 2009. 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. No shares were purchased under the program during the three months ended March 31, 2009. As of March 31, 2009, the Company is authorized to purchase approximately $113 million of the Company’s outstanding common stock under the Program. Shares purchased under the Program have been accounted for as treasury stock.

     The Company purchased 18,702 shares of stock from employees during the three months ended March 31, 2009. These shares were purchased at fair market value upon the vesting of restricted stock to provide employees with the funds necessary to satisfy payroll tax withholding obligations and have been accounted for as treasury stock. The total purchase price for these shares was approximately $216,000. 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.

11. 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 was limited to financial assets and liabilities and became effective on January 1, 2008 for the Company. The impact of the initial application of FAS 157 was not material. On January 1, 2009, the Company adopted FAS 157 on a prospective basis for non-financial assets and liabilities that are not measured at fair value on a recurring basis. The application of FAS 157 to the Company’s non-financial assets and liabilities is primarily 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 has not had a material impact to the Company.

     In December 2007, the FASB issued Statement No. 141(R), Business Combinations (“FAS 141(R)”) and Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (“FAS 160”). FAS 141(R) is a revision of Statement No. 141, Business Combinations, and calls for significant changes from current practice in accounting for business combinations. FAS 141(R) is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. FAS 160 amends ARB 51 to establish accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. FAS 160 is effective for fiscal years beginning on or after December 15, 2008. Both FAS 141(R) and FAS 160 became effective for the Company on January 1, 2009. The application of FAS 141(R) and FAS 160 has not had a material impact to the Company.

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 months ended March 31, 2009 and 2008, our operating revenues consisted of the following (dollars in thousands):

		Three Months Ended March 31,
		2009								2008
Contract drilling		$	225,704				77	%		$	420,149				84	%
Pressure pumping			38,105				13				42,864				8
Drilling and completion fluids			27,830				9				32,550				6
Oil and natural gas			4,400				1				8,991				2
		$	296,039				100	%		$	504,554				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, Arizona, Utah, Wyoming, Montana, North Dakota, South Dakota, Pennsylvania, West Virginia 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, New Mexico, Oklahoma and Louisiana. The oil and natural gas properties in which we hold interests are primarily located in Texas, New Mexico, Mississippi and Louisiana.

     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 first quarter of 2009, our average number of rigs operating was 127 compared to 244 in the first quarter of 2008. Our average number of rigs operating during the first quarter of 2009 included 11 rigs under term contracts that earned standby revenues of $10.7 million. Rigs on standby earn a discounted dayrate and have lower costs. Additionally, we recognized $6.6 million of revenues during the first quarter of 2009 from the early termination of term contracts. Our average revenue per operating day was $19,670 in the first quarter of 2009 compared to $18,900 in the first quarter of 2008. Our consolidated net income for the first quarter of 2009 decreased by $61.2 million or 79% as compared to the first quarter of 2008. This decrease in consolidated net income was primarily due to our contract drilling segment experiencing a significant decrease in the average number of rigs operating as compared to the first quarter of 2008.

     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 generally 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. During recent months, there has been a significant decline in oil and natural gas prices. During this time there has also been a substantial deterioration in the global economic environment. As part of this deterioration, there has been substantial uncertainty in the capital markets and access to financing has been reduced. Due to these conditions, many of our customers have been reducing or curtailing their drilling programs, which has resulted in a decrease in demand for our services, as evidenced by the decline in our monthly average rigs operating from 283 in October 2008 to 92 in March 2009. Furthermore, these factors could result in certain of our customers experiencing an inability to pay suppliers, including us, if they are not able to access capital to fund their operations. We are also highly impacted by competition, the availability of excess equipment, labor issues and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see “Risk Factors” included as Item 1A in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

     We believe that the liquidity shown on our balance sheet as of March 31, 2009, which includes approximately $321 million in working capital (including $192 million in cash and cash equivalents) and $162.5 million available under our current $220 million line of credit, together with cash expected to be generated from operations, provides us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, expand into new regions, pay cash dividends and survive the current downturn in our industry.

     Commitments and Contingencies — As of March 31, 2009, we maintained letters of credit in the aggregate amount of $57.5 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 March 31, 2009, no amounts had been drawn under the letters of credit.

     As of March 31, 2009, we had commitments to purchase approximately $231 million of major equipment.

     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, Arizona, Utah, Wyoming, Montana, North Dakota, South Dakota, Pennsylvania, West Virginia and western Canada. As of March 31, 2009, we had approximately 350 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, New Mexico, Oklahoma and 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 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 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 recent years, construction of new drilling rigs increased significantly. The addition of new drilling rigs to the market and the recent decrease in demand has resulted in excess capacity. 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, 2008.

Liquidity and Capital Resources

     As of March 31, 2009, we had working capital of $321 million including cash and cash equivalents of $192 million. For the three months ended March 31, 2009, our sources of cash flow included $215 million from operating activities.

     During the three months ended March 31, 2009, we used $7.7 million to pay dividends on our common stock, $5.5 million to pay debt issuance costs related to our credit facility and $89.8 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 segments, and
	•		to fund investments in oil and natural gas properties on a working interest basis.

     We paid cash dividends during the three months ended March 31, 2009 as follows:

		Per Share				Total
						(in thousands)
Paid on March 31, 2009		$	0.05			$	7,655
Total cash dividends		$	0.05			$	7,655

     On April 29, 2009, our Board of Directors approved a cash dividend on our common stock in the amount of $0.05 per share to be paid on June 30, 2009 to holders of record as of June 15, 2009. 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. No shares were purchased under the Program during the three months ended March 31, 2009. As of March 31, 2009, we are authorized to purchase approximately $113 million of our outstanding common stock under the Program. Shares purchased under the Program have been accounted for as treasury stock.

     We have an unsecured revolving line of credit with a maximum borrowing and letter of credit capacity of $220 million. Interest is paid on the outstanding principal amount of borrowings under the revolving line of credit at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 3.00% to 4.00% and the margin on base rate loans ranges from 2.00% to 3.00%, based on our debt to capitalization ratio. Any outstanding borrowings must be repaid at maturity on January 31, 2012 and letters of credit may remain in effect up to six months after such maturity date. As of March 31, 2009, we had no borrowings outstanding under this revolving line of credit. We had $57.5 million in letters of credit outstanding at March 31, 2009, however, and as a result, we had available borrowing capacity of $162.5 million at such date.

     We believe that the current level of cash, short-term investments and borrowing capacity available under our current revolving line of credit, together with cash expected to be generated from operations, should be sufficient to meet our current 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 or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

Results of Operations

     The following tables summarize operations by business segment for the three months ended March 31, 2009 and 2008:

Contract Drilling		2009				2008				% Change
		(Dollars in thousands)
Revenues		$	225,704			$	420,149				(46.3	)%
Direct operating costs		$	126,321			$	244,367				(48.3	)%
Selling, general and administrative		$	986			$	1,524				(35.3	)%
Depreciation		$	57,386			$	55,872				2.7	%
Operating income		$	41,011			$	118,386				(65.4	)%
Operating days			11,473				22,233				(48.4	)%
Average revenue per operating day		$	19.67			$	18.90				4.1	%
Average direct operating costs per operating day		$	11.01			$	10.99				0.2	%
Average rigs operating			127				244				(48.0	)%
Capital expenditures		$	67,002			$	67,211				(0.3	)%

     Revenues and direct operating costs decreased in the first quarter of 2009 compared to the first quarter of 2008 primarily as a result of a decrease in the number of operating days. The decrease in operating days was due to decreased demand largely caused by lower commodity prices for natural gas and oil. Average revenue per operating day and average direct operating costs per operating day in the first quarter of 2009 were relatively flat compared to the first quarter of 2008. Our average rigs operating during the first quarter of 2009 included 11 rigs operating under term contracts that earned standby revenues of $10.7 million. Rigs on standby earn a discounted dayrate since they do not have crews and have lower costs. Additionally, we recognized $6.6 million of revenues during the first quarter of 2009 from the early termination of drilling contracts. Selling, general and administrative expenses decreased in the first quarter of 2009 compared to the first quarter of 2008 primarily as a result of lower professional fees. 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 these capital expenditures.

Pressure Pumping		2009				2008				% Change
		(Dollars in thousands)
Revenues		$	38,105			$	42,864				(11.1	)%
Direct operating costs		$	27,006			$	28,505				(5.3	)%
Selling, general and administrative		$	5,835			$	5,607				4.1	%
Depreciation		$	6,139			$	4,300				42.8	%
Operating income (loss)		$	(875	)		$	4,452				N/M
Total jobs			1,911				2,911				(34.4	)%
Average revenue per job		$	19.94			$	14.72				35.5	%
Average direct operating costs per job		$	14.13			$	9.79				44.3	%
Capital expenditures		$	21,820			$	12,959				68.4	%

     Our customers have increased their focus on the emerging development of unconventional reservoirs in the Appalachian Basin and the larger jobs associated therewith. As a result of this focus on unconventional reservoirs and declining commodity prices, we have experienced a decrease in the number of smaller traditional pressure pumping jobs, which has contributed to the overall decrease in the number of total jobs. Revenues and direct operating costs decreased primarily as a result of a decrease in the number of total jobs. Increased average revenue per job was due to an increase in the proportion of larger jobs to total jobs, which was driven by demand for services associated with unconventional reservoirs. 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, which require significantly more materials to complete. In anticipation of increased activity associated with the unconventional reservoirs in the Appalachian Basin, we have added facilities, equipment and personnel over the past two years. Delays in the development of these reservoirs and lower commodity prices have caused less demand for our pressure pumping services than we had expected, negatively impacting the profitability of this business. 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 these capital expenditures.

Drilling and Completion Fluids		2009				2008				% Change
		(Dollars in thousands)
Revenues		$	27,830			$	32,550				(14.5	)%
Direct operating costs		$	24,522			$	28,533				(14.1	)%
Selling, general and administrative		$	2,175			$	2,626				(17.2	)%
Depreciation		$	615			$	724				(15.1	)%
Operating income		$	518			$	667				(22.3	)%
Capital expenditures		$	6			$	8				(25.0	)%

     Revenues and direct operating costs decreased in the first quarter of 2009 compared to the first quarter of 2008 due to decreased sales both on land and offshore in the Gulf of Mexico. Selling, general and administrative expenses decreased in the first quarter of 2009 compared to the first quarter of 2008 primarily due to a decrease in compensation costs for sales and support personnel due to headcount reductions.

Oil and Natural Gas Production and Exploration		2009				2008				% Change
		(Dollars in thousands,
		except sales prices)
Revenues		$	4,400			$	8,991				(51.1	)%
Direct operating costs		$	1,976			$	2,067				(4.4	)%
Depreciation, depletion and impairment		$	5,980			$	2,627				127.6	%
Operating income (loss)		$	(3,556	)		$	4,297				N/M
Capital expenditures		$	970			$	4,428				(78.1	)%
Average net daily oil production (Bbls)			882				701				25.8	%
Average net daily natural gas production (Mcf)			3,508				3,426				2.4	%
Average oil sales price (per Bbl)		$	39.48			$	96.75				(59.2	)%
Average natural gas sales price (per Mcf)		$	4.01			$	9.03				(55.6	)%

     Revenues decreased due to lower average sales prices of oil and natural gas. This decrease was partially offset by increases in the average net daily production of oil and natural gas. Average net daily oil and natural gas production increased primarily due to the addition of new wells. Depreciation, depletion and impairment expense in the first quarter of 2009 includes approximately $2.5 million incurred to impair certain oil and natural gas properties compared to approximately $221,000 incurred to impair certain oil and

natural gas properties in the first quarter of 2008. The increase in impairment charges in 2009 was due to a reduction in commodity price expectations and a decline in production of certain wells. Depletion expense increased approximately $1.1 million due to lower reserves, which resulted from decreased oil and natural gas commodity prices and increased production from new wells.

Corporate and Other		2009				2008				% Change
		(Dollars in thousands)
Selling, general and administrative		$	6,988			$	7,239				(3.5	)%
Depreciation		$	227			$	203				11.8	%
Other operating expenses		$	4,000			$	300				N/M
Net loss on asset disposals/retirements		$	174			$	186				(6.5	)%
Interest income		$	61			$	343				(82.2	)%
Interest expense		$	447			$	277				61.4	%
Other income		$	23			$	384				(94.0	)%

     Other operating expenses increased primarily due to an increase in bad debt expense of $3.7 million in the first quarter of 2009 compared to the first quarter of 2008.

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 was limited to financial assets and liabilities and became effective on January 1, 2008 for us. The impact of the initial application of FAS 157 was not material. On January 1, 2009, we adopted FAS 157 on a prospective basis for non-financial assets and liabilities that are not measured at fair value on a recurring basis. The application of FAS 157 to our non-financial assets and liabilities is primarily 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 has not had a material impact to us.

     In December 2007, the FASB issued Statement No. 141(R), Business Combinations (“FAS 141(R)”) and Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (“FAS 160”). FAS 141(R) is a revision of Statement No. 141, Business Combinations, and calls for significant changes from current practice in accounting for business combinations. FAS 141(R) is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. FAS 160 amends ARB 51 to establish accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. FAS 160 is effective for fiscal years beginning on or after December 15, 2008. Both FAS 141(R) and FAS 160 became effective for us on January 1, 2009. The application of FAS 141(R) and FAS 160 has not had a material impact to us.

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

     Our revenue, profitability, financial condition 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 extremely 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 2008, the monthly average market price of natural gas peaked in June at $13.06 per Mcf before rapidly declining to an average of $5.99 per Mcf in December. In March 2009, the average market price of natural gas declined further to $4.08 per Mcf. This has resulted in our customers significantly reducing their drilling activities beginning in the fourth quarter of 2008 and continuing into 2009. This reduction in demand combined with the reactivation and construction of new land drilling rigs in the United States during the last several years has resulted in excess capacity compared to demand. As a result of these factors, our average number of rigs operating has declined significantly. 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. Continued low market prices for natural gas will likely result in further decreases in demand for our drilling rigs and adversely affect our operating results and financial condition.

     The North American land drilling industry has experienced downturns in demand 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 and, at times, have incurred losses during the downturn periods.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

     We currently have exposure to interest rate market risk associated with any borrowings that we have under our revolving credit facility. The revolving credit facility calls for periodic interest payments at a floating rate ranging from LIBOR plus 3.00% to 4.00% or at a base rate plus 2.00% to 3.00%. The applicable rate above LIBOR or the prime rate is based upon our debt to capitalization ratio. As of March 31, 2009, we had no borrowings outstanding under our credit facility.

     We conduct a portion of our 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.

     The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value.

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 March 31, 2009.

     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

     Forward-looking statements may be made by management orally or in writing, including, but not limited to our filings with the SEC under the Exchange Act and the Securities Act of 1933. “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); impact of inflation; and other matters. Our forward-looking statements can be identified by the fact that they do not relate strictly to historic or current facts and often use words such as “believes,” “budgeted,” “expects,” “estimates,” “project,” “will,” “could,” “may,” “plans,” “intends,” “strategy,” or “anticipates,” and other words and expressions of similar meaning. 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. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct.

     Forward-looking statements are not guarantees of future performance and a variety of factors could cause actual results to differ materially from the anticipated or expected results expressed in or suggested by these forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, deterioration of global economic conditions, declines in oil and natural gas prices that could adversely affect demand for our services and their associated effect on day rates, rig utilization and planned capital expenditures, excess availability of land drilling rigs, including as a result of the reactivation or construction of new land drilling rigs, adverse industry conditions, adverse credit and equity market conditions, difficulty in integrating acquisitions, demand for oil and natural gas, shortages of rig equipment and ability to retain management and field personnel. Refer to “Risk Factors” contained in Part 1 of our Annual Report on Form 10-K for the year ended December 31, 2008 for a more complete discussion of these and other factors that might affect our performance and financial results. These forward-looking statements are intended to relay our expectations about the future, and speak only as of the date they are made. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

     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 March 31, 2009.

														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)
January 1-31, 2009 (2)			16,525			$	11.75				—			$	113,326
February 1-28, 2009 (2)			2,177			$	9.92				—			$	113,326
March 1-31, 2009			—			$	—				—			$	113,326
Total			18,702			$	11.54				—			$	113,326

ITEM 5. Other Information

     On April 28, 2009, the Compensation Committee of the Board of Directors of the Company granted performance unit awards to certain executive officers under the Company’s 2005 Long-Term Incentive Plan (the “2005 Plan”) for the performance period beginning April 1, 2009 and ending March 31, 2012 (the “2009 Performance Units”). The 2009 Performance Units provide an opportunity for those executive officers to receive a cash payment upon the achievement of certain performance goals established by the Company during a specified period. The performance metrics for the 2009 Performance Units are tied to the Company’s total shareholder return for the performance period as compared to total shareholder return for a peer group determined by the Compensation Committee. Total shareholder return for the Company will be measured based on $100 invested in the Company’s common stock on the first day of the performance period, with dividends reinvested. The recipients will receive a base payment if the Company’s total shareholder return is at or above the 25^th percentile but less than the 50^th percentile, two times the base if at or above the 50^th percentile but less than the 75^th percentile and four times the base if at the 75^th percentile or higher. The base amounts for Mark Siegel, Douglas Wall, John Vollmer and Kenneth Berns are $625,000, $468,750, $312,500 and $312,500, respectively.

     No cash payments will be made in respect of the 2009 Performance Units unless the Company has positive total shareholder return as of the end of the performance period; except, that if during the two year period ending March 31, 2014 the Company’s total shareholder return for any 30 consecutive day period equals or exceeds 18% on an annualized basis from April 1, 2009 through the end of such 30 consecutive day period, then cash payments, if any, will be made as set forth above based on the Company’s total shareholder return relative to the peer group as of March 31, 2012.

     The foregoing description of the 2009 Performance Units does not purport to be complete and is qualified in its entirety by reference to (i) the 2005 Plan, as amended, which is listed as Exhibits 10.8, 10.9 and 10.10 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, and incorporated herein by reference and (ii) the form of award agreement for the 2009 Performance Units, including terms and conditions, that will be filed by the Company with the SEC when the award agreements governing the awards are entered into between the Company and each of the executive officers referenced above.

ITEM 6. 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		Second Amended and Restated Bylaws (filed August 6, 2007 as Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 and incorporated herein by reference).

10.1		Credit Agreement dated March 20, 2009, among the Company, as borrower, Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender and lender, each of Amegy Bank, N.A., Comerica Bank, and HSBC Bank USA, N.A., as lender, Bank of America, N.A., as syndication agent, letter of credit issuer and lender, and The Bank of Tokyo-Mitsubishi UFJ, Ltd. As documentation agent and lender (filed March 25, 2009 as Exhibit 10.1 to the Company’s Current Report on Form 8-K 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.

SIGNATURE

     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.

DATED: May 4, 2009