Patterson-UTI Energy 10Q 2007 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


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

For the quarterly period ended September 30, 2007


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

For the transition period from to

Commission file number 0-22664

Patterson-UTI Energy, Inc.

(Exact name of registrant as specified in its charter)


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

4510 LAMESA HIGHWAY,
SNYDER, TEXAS		79549
(Address of principal executive offices)		(Zip Code)

(325) 574-6300
(Registrant’s telephone number, including area code)

N/A
(Former name, former address and former fiscal year,
if changed since last report)

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

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

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

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

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

154,944,887 shares of common stock, $0.01 par value, as of November 2, 2007

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		13
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk		20
ITEM 4.	Controls and Procedures		20
Forward Looking Statements and Cautionary Statements for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995			20
PART II — OTHER INFORMATION
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		22
ITEM 5.	Other Information		22
ITEM 6.	Exhibits		22
Signatures			24
Change in Control Agreement - William L. Moll, Jr.
First Amendment to Change in Control Agreement - Mark S. Siegel
First Amendment to Change in Control Agreement - Douglas J. Wall
First Amendment to Change in Control Agreement - John E. Vollmer, III
First Amendment to Change in Control Agreement - Kenneth N. Berns
First Amendment to Change in Control Agreement - William L. Moll, Jr.
Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a)
Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a)
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

The following unaudited consolidated financial statements include all adjustments which, in the opinion of management, are necessary in order to make such financial statements not misleading.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(unaudited, in thousands, except share data)


	September 30,			December 31,
	2007			2006
ASSETS
Current assets:
Cash and cash equivalents	$	20,516		$	13,385
Accounts receivable, net of allowance for doubtful accounts of $9,100 at September 30, 2007 and $7,484 at December 31, 2006		398,649			484,106
Accrued federal and state income taxes receivable		—			5,448
Inventory		43,941			43,947
Deferred tax assets, net		35,153			48,868
Deposits on equipment purchase contracts		2,133			24,746
Other		42,813			32,170

Total current assets		543,205			652,670
Property and equipment, net		1,782,576			1,435,804
Goodwill		96,198			99,056
Other		4,921			4,973

Total assets	$	2,426,900		$	2,192,503

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	193,454		$	138,372
Accrued revenue distributions		15,136			15,359
Other		12,242			18,424
Accrued federal and state income taxes payable		1,011			—
Accrued expenses		131,806			145,463

Total current liabilities		353,649			317,618
Borrowings under line of credit		10,000			120,000
Deferred tax liabilities, net		216,199			187,960
Other		4,459			4,459

Total liabilities		584,307			630,037

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 177,348,319 and 176,656,401 issued and 154,943,287 and 156,542,512 outstanding at September 30, 2007 and December 31, 2006, respectively		1,773			1,766
Additional paid-in capital		697,415			681,069
Retained earnings		1,649,998			1,346,542
Accumulated other comprehensive income		19,400			8,390
Treasury stock, at cost, 22,405,032 and 20,113,889 shares at September 30, 2007 and December 31, 2006, respectively		(525,993	)		(475,301	)

Total stockholders’ equity		1,842,593			1,562,466

Total liabilities and stockholders’ equity	$	2,426,900		$	2,192,503

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						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Operating revenues:
Contract drilling	$	428,316		$	577,047		$	1,315,005		$	1,616,100
Pressure pumping		58,498			40,462			148,674			107,800
Drilling and completion fluids		27,348			46,163			97,775			155,221
Oil and natural gas		9,840			9,986			32,207			29,083

		524,002			673,658			1,593,661			1,908,204

Operating costs and expenses:
Contract drilling		242,352			267,345			716,803			737,021
Pressure pumping		28,682			20,960			75,610			56,545
Drilling and completion fluids		24,153			36,183			82,172			120,418
Oil and natural gas		2,474			3,222			8,213			11,241
Depreciation, depletion and impairment		66,523			49,215			182,401			140,245
Selling, general and administrative		16,593			13,777			47,584			39,428
Embezzlement costs (recoveries)		(1,145	)		(1,512	)		(43,080	)		2,941
Gain on disposal of assets		(330	)		(437	)		(16,603	)		(437	)
Other operating expenses		600			3,000			1,600			4,385

		379,902			391,753			1,054,700			1,111,787

Operating income		144,100			281,905			538,961			796,417

Other income (expense):
Interest income		1,091			948			1,917			5,579
Interest expense		(357	)		(363	)		(1,951	)		(476	)
Other		42			88			245			231

		776			673			211			5,334

Income before income taxes and cumulative effect of change in accounting principle		144,876			282,578			539,172			801,751

Income tax expense:
Current		40,190			106,151			149,973			288,476
Deferred		6,505			(9,563	)		35,666			(2,974	)

		46,695			96,588			185,639			285,502

Income before cumulative effect of change in accounting principle		98,181			185,990			353,533			516,249
Cumulative effect of change in accounting principle, net of related income tax expense of $398		—			—			—			687

Net income	$	98,181		$	185,990		$	353,533		$	516,936

Income before cumulative effect of change in accounting principle:
Basic	$	0.63		$	1.14		$	2.28		$	3.07

Diluted	$	0.62		$	1.12		$	2.24		$	3.03

Net income per common share:
Basic	$	0.63		$	1.14		$	2.28		$	3.08

Diluted	$	0.62		$	1.12		$	2.24		$	3.03

Weighted average number of common shares outstanding:
Basic		154,934			163,412			155,281			168,036

Diluted		157,339			165,742			157,491			170,339


Cash dividends per common share	$	0.12		$	0.08		$	0.32		$	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, 2006		176,656		$	1,766		$	681,069		$	1,346,542		$	8,390	$	(475,301	)	$	1,562,466
Issuance of restricted stock		601			6			(6	)		—			—		—			—
Exercise of stock options		159			2			1,298			—			—		—			1,300
Stock based compensation		—			—			13,979			—			—		—			13,979
Tax benefit for stock based compensation		—			—			1,074			—			—		—			1,074
Forfeitures of restricted shares		(68	)		(1	)		1			—			—		—			—
Foreign currency translation adjustment, net of tax of $6,287		—			—			—			—			11,010		—			11,010
Payment of cash dividends		—			—			—			(50,077	)		—		—			(50,077	)
Purchase of treasury stock		—			—			—			—			—		(50,692	)		(50,692	)
Net income		—			—			—			353,533			—		—			353,533

Balance, September 30, 2007		177,348		$	1,773		$	697,415		$	1,649,998		$	19,400	$	(525,993	)	$	1,842,593

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)


	Nine Months Ended
	September 30,
	2007			2006
Cash flows from operating activities:
Net income	$	353,533		$	516,936
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and impairment		182,401			140,245
Dry holes and abandonments		831			3,709
Provision for bad debts		1,600			4,200
Deferred income tax expense (benefit)		35,666			(2,576	)
Stock based compensation expense		13,979			9,710
Gain on disposal of assets		(16,603	)		(437	)
Changes in operating assets and liabilities:
Accounts receivable		87,060			(92,069	)
Inventory and other current assets		12,559			(36,086	)
Accounts payable		(16,819	)		40,280
Income taxes payable/receivable		6,734			4,789
Accrued expenses		(11,096	)		23,798
Other liabilities		(5,651	)		1,613

Net cash provided by operating activities		644,194			614,112

Cash flows from investing activities:
Purchases of property and equipment		(461,444	)		(423,422	)
Proceeds from disposal of property and equipment		32,190			7,983

Net cash used in investing activities		(429,254	)		(415,439	)

Cash flows from financing activities:
Purchases of treasury stock		(50,692	)		(352,393	)
Dividends paid		(50,077	)		(33,305	)
Proceeds from exercise of stock options		1,300			1,414
Tax benefit related to stock-based compensation		1,074			922
Proceeds from borrowings under line of credit		92,500			65,000
Repayment of borrowings under line of credit		(202,500	)		—
Debt issuance costs		—			(341	)

Net cash used in financing activities		(208,395	)		(318,703	)

Effect of foreign exchange rate changes on cash		586			577

Net increase (decrease) in cash and cash equivalents		7,131			(119,453	)
Cash and cash equivalents at beginning of period		13,385			136,398

Cash and cash equivalents at end of period	$	20,516		$	16,945

Supplemental disclosure of cash flow information:
Net cash paid during the period for:
Interest expense	$	1,761		$	476
Income taxes	$	133,806		$	272,541

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 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 herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments which are of a normal recurring nature considered necessary for a fair presentation 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, 2006, as presented herein, was derived from the audited balance sheet of the Company. 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 year ended December 31, 2006.

The U.S. dollar is the functional currency for all of the Company’s operations except for its Canadian operations, which use the Canadian dollar as their functional currency. The effects of exchange rate changes are reflected in accumulated other comprehensive income, which is a separate component of stockholders’ equity (see Note 3 of these Notes to Unaudited Consolidated Financial Statements).

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, warrants and restricted stock using the treasury stock method. The following table presents information necessary to calculate net income per share for the three and nine months ended September 30, 2007 and 2006 as well as cash dividends per share paid and 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 nine months ended September 30, 2007 and 2006 (in thousands, except per share amounts):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Net income	$	98,181	$	185,990	$	353,533	$	516,936
Weighted average number of common shares outstanding excluding nonvested restricted stock		154,934		163,412		155,281		168,036

Basic net income per common share	$	0.63	$	1.14	$	2.28	$	3.08

Weighted average number of common shares outstanding excluding nonvested restricted stock		154,934		163,412		155,281		168,036
Dilutive effect of stock options and nonvested restricted stock		2,405		2,330		2,210		2,303

Weighted average number of diluted common shares outstanding		157,339		165,742		157,491		170,339

Diluted net income per common share	$	0.62	$	1.12	$	2.24	$	3.03

Potentially dilutive securities excluded as anti-dilutive		2,385		800		2,435		800

The results of operations for the three and nine months ended September 30, 2007 are not necessarily indicative of the results to be expected for the full year.

2. Stock-based Compensation

The Company adopted Financial Accounting Standards Board (“FASB”) Statement No. 123 (revised 2004),Share-Based Payment(“FAS 123(R)”), on January 1, 2006 and recognizes the cost of share-based payments under the fair-value-based method. The Company uses share-based payments to compensate employees and non-employee directors. All awards have been equity instruments

in the form of stock options or restricted stock awards. The Company issues shares of common stock when vested stock option awards are exercised and when restricted stock awards are granted. As a result of the initial adoption of FAS 123(R) in 2006, the Company recognized income due to the cumulative effect of this change in accounting principle of $687,000, net of taxes of $398,000, related to previously expensed amortization of unvested restricted stock grants.

Stock Options. The Company estimates 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. 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 were granted. The risk-free interest rate assumptions are determined by reference to United States Treasury yields. Weighted-average assumptions used to estimate grant date fair values for stock options granted in the three and nine month periods ended September 30, 2007 and 2006 follow:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2007		2006			2007			2006
Volatility		N/A		33.59	%		36.38	%		33.18	%
Expected term (in years)		N/A		4.00			4.00			4.00
Dividend yield		N/A		1.14	%		1.96	%		1.09	%
Risk-free interest rate		N/A		4.91	%		4.56	%		4.87	%

Stock option activity from January 1, 2007 to September 30, 2007 follows:


				Weighted-
				Average
	Underlying			Exercise
	Shares			Price
Outstanding at January 1, 2007		6,575,096		$	16.18
Granted		1,035,000		$	23.94
Exercised		(159,312	)	$	8.16
Forfeited		(2,083	)	$	14.64
Expired		(17	)	$	14.64
Cancelled		—		$	—

Outstanding at September 30, 2007		7,448,684		$	17.43

Exercisable at September 30, 2007		5,832,834		$	15.27

Restricted Stock. Under all restricted stock awards to date, shares were issued when granted, nonvested shares are subject to forfeiture for failure to fulfill service conditions and nonforfeitable dividends are paid on nonvested restricted shares. Additionally, certain restricted stock awards contain performance conditions related to the Company’s net income.

Restricted stock activity from January 1, 2007 to September 30, 2007 follows:


				Weighted
				Average
				Grant Date
	Shares			Fair Value
Nonvested at January 1, 2007		1,188,200		$	25.92
Granted		601,150		$	24.60
Vested		(182,306	)	$	19.02
Forfeited		(68,544	)	$	26.90

Nonvested at September 30, 2007		1,538,500		$	26.18

3. Comprehensive Income

The following table illustrates the Company’s comprehensive income including the effects of foreign currency translation adjustments for the three and nine months ended September 30, 2007 and 2006 (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Net income	$	98,181	$	185,990	$	353,533	$	516,936
Other comprehensive income:
Foreign currency translation adjustment related to Canadian operations, net of tax		4,592		478		11,010		3,016

Comprehensive income, net of tax	$	102,773	$	186,468	$	364,543	$	519,952

4. Property and Equipment

Property and equipment consisted of the following at September 30, 2007 and December 31, 2006 (in thousands):


	September 30,			December 31,
	2007			2006
Equipment	$	2,636,782		$	2,135,567
Oil and natural gas properties		73,334			85,143
Buildings		43,872			30,987
Land		10,001			7,507

		2,763,989			2,259,204
Less accumulated depreciation and depletion		(981,413	)		(823,400	)

Property and equipment, net	$	1,782,576		$	1,435,804

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 to operators in the oil and natural gas industry, and (iv) the exploration, development, acquisition and production of oil and natural gas. Each of these segments represents a distinct type of business based upon the type and nature of services and products offered. These segments have separate management teams which report to the Company’s chief operating decision maker and have distinct and identifiable revenues and expenses. Separate financial data for each of our four business segments is provided below (in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Revenues:
Contract drilling(a)	$	429,002		$	578,653		$	1,317,626		$	1,620,322
Pressure pumping		58,498			40,462			148,674			107,800
Drilling and completion fluids(b)		27,528			46,317			98,111			155,639
Oil and natural gas		9,840			9,986			32,207			29,083

Total segment revenues		524,868			675,418			1,596,618			1,912,844
Elimination of intercompany revenues(a)(b)		(866	)		(1,760	)		(2,957	)		(4,640	)

Total revenues	$	524,002		$	673,658		$	1,593,661		$	1,908,204

Income (loss) before income taxes:
Contract drilling	$	128,243		$	264,924		$	437,660		$	751,977
Pressure pumping		21,232			13,493			49,072			34,592
Drilling and completion fluids		(19	)		6,558			6,163			25,038
Oil and natural gas		887			3,276			8,616			6,977

		150,343			288,251			501,511			818,584
Corporate and other		(7,718	)		(8,295	)		(22,233	)		(19,663	)
Embezzlement (costs) recoveries(c)		1,145			1,512			43,080			(2,941	)
Gain on disposal of assets(d)		330			437			16,603			437
Interest income		1,091			948			1,917			5,579
Interest expense		(357	)		(363	)		(1,951	)		(476	)
Other		42			88			245			231

Income before income taxes and cumulative effect of change in accounting principle	$	144,876		$	282,578		$	539,172		$	801,751


	September 30,		December 31,
	2007		2006
Identifiable assets:
Contract drilling	$	2,082,764	$	1,849,923
Pressure pumping		158,177		111,787
Drilling and completion fluids		90,043		106,032
Oil and natural gas		51,956		65,443

		2,382,940		2,133,185
Corporate and other(e)		43,960		59,318

Total assets	$	2,426,900	$	2,192,503


(a)		Includes contract drilling intercompany revenues of approximately $686,000 and $1.6 million for the three months ended September 30, 2007 and 2006, respectively. Includes contract drilling intercompany revenues of approximately $2.6 million and $4.2 million for the nine months ended September 30, 2007 and 2006, respectively.

(b)		Includes drilling and completion fluids intercompany revenues of approximately $180,000 and $154,000 for the three months ended September 30, 2007 and 2006, respectively. Includes drilling and completion fluids intercompany revenues of approximately $336,000 and $418,000 for the nine months ended September 30, 2007 and 2006, respectively.

(c)		The Company’s former CFO has pleaded guilty to criminal charges and has been sentenced and is serving a term of imprisonment arising out of his embezzlement of funds from the Company. The Company expects to recover a total of approximately $43.6 million in assets that were seized by a court-appointed receiver from the former CFO and companies that he controlled. Cash payments from the receiver of approximately $40.2 million have been received as of September 30, 2007, with the remaining $3.4 million of the expected recovery consisting of notes receivable, investments and other


		assets that have been or are expected to be transferred to the Company. Embezzlement (costs) recoveries, includes the recognition of this recovery, net of professional and other costs incurred as a result of the embezzlement.

(d)		Gains or losses associated with the disposal of assets relate to decisions of the executive management group regarding corporate strategy. Accordingly, the related gains or losses have been separately presented and excluded from the results of specific segments.

(e)		Corporate assets primarily include cash and certain deferred federal income tax assets.

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, 2006 the Company performed its annual goodwill evaluation and determined no adjustment to impair goodwill was necessary. Goodwill as of September 30, 2007 is as follows (in thousands):


	September 30,
	2007
Contract Drilling:
Goodwill at beginning of year	$	89,092
Changes to goodwill		(2,858	)

Goodwill at end of period		86,234

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

Goodwill at end of period		9,964

Total goodwill	$	96,198

In connection with the implementation of FIN 48 as of January 1, 2007 as discussed in Note 12 of these Unaudited Consolidated Financial Statements, the Company determined that a tax reserve which had been established in connection with a business acquisition should be reduced. This reserve had originally been established in connection with the allocation of the purchase price in the transaction and was reflected as an increase in goodwill. The $2.9 million reduction of this reserve was reflected as a reduction to goodwill upon the adoption of FIN 48.

7. Accrued Expenses

Accrued expenses consisted of the following at September 30, 2007 and December 31, 2006 (in thousands):


	September 30,		December 31,
	2007		2006
Salaries, wages, payroll taxes and benefits	$	32,842	$	42,751
Workers’ compensation liability		63,970		69,330
Sales, use and other taxes		16,102		11,043
Insurance, other than workers’ compensation		15,124		13,328
Other		3,768		9,011

Accrued expenses	$	131,806	$	145,463

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 nine months ended September 30, 2007 and 2006 (in thousands):


	2007			2006
Balance at beginning of year	$	1,829		$	1,725
Liabilities incurred		207			83
Liabilities settled		(796	)		(48	)
Accretion expense		46			41
Revision in estimated cash flows		289			—

Asset retirement obligation at end of period	$	1,575		$	1,801

9. Borrowings Under Line of Credit

The Company entered into a five-year unsecured revolving line of credit (“LOC”) in December 2004. On August 2, 2006, the Company amended the LOC and increased the borrowing capacity to $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. 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 September 30, 2007). 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 September 30, 2007, the Company had $10.0 million in borrowings outstanding under the LOC and $59.4 million in letters of credit outstanding. As a result, the Company had available borrowing capacity of approximately $306 million at September 30, 2007. The weighted average interest rate on outstanding borrowings at September 30, 2007 was 7.75%.

10. Commitments, Contingencies and Other Matters

Commitments —The Company maintains letters of credit in the aggregate amount of $59.4 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 are typically renewed annually. No amounts have been drawn under the letters of credit.

As of September 30, 2007, the Company has signed non-cancelable commitments to purchase approximately $123 million of equipment. This amount excludes $2.1 million and $24.7 million at September 30, 2007 and December 31, 2006, respectively, related to deposits toward the purchase of drilling rig components. These payments are presented as Deposits on equipment purchase contracts in the Company’s unaudited consolidated balance sheets.

Contingencies —A receiver was appointed to take control of and liquidate the assets of the Company’s former CFO in connection with his embezzlement of Company funds. In May 2007, the court approved a plan of distribution of the assets that had been recovered by the receiver. The Company expects to recover a total of approximately $43.6 million pursuant to the approved plan and has recognized this recovery in the Company’s unaudited consolidated statement of income, net of additional professional fees associated with the embezzlement. Cash payments from the receiver of approximately $40.2 million have been received as of September 30, 2007, with the remaining $3.4 million of the expected recovery consisting of notes receivable, investments and other assets that have been or are expected to be transferred to the Company.

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 has paid cash dividends during the nine months ended September 30, 2007 as follows:


	Per Share		Total
			(in thousands)
Paid on March 30, 2007 to shareholders of record as of March 15, 2007	$	0.08	$	12,527
Paid on June 29, 2007 to shareholders of record as of June 14, 2007		0.12		18,860
Paid on September 28, 2007 to shareholders of record as of September 12, 2007		0.12		18,690

Total cash dividends	$	0.32	$	50,077

On October 31, 2007, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.12 per share to be paid on December 28, 2007 to holders of record as of December 12, 2007. The amount and timing of all future dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of the Company’s credit facilities and other factors.

The Company purchased 16,018 shares of treasury stock from employees on June 8, 2007. These shares were purchased at fair market value upon the vesting of restricted stock to provide the employees with the funds necessary to satisfy their respective tax withholding obligations. The total purchase price for these shares was approximately $415,000.

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. During the three months ended September 30, 2007 the Company purchased 2,275,000 shares of its common stock under the Program at a cost of approximately $50.3 million. As of September 30, 2007, the Company is authorized to purchase approximately $200 million of the Company’s outstanding common stock under the Program. Shares purchased under the Program have been accounted for as treasury stock.

12. Income Taxes

The Company adopted 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 a result of the adoption of FIN 48 the Company reduced a reserve for an uncertain tax position with respect to a business combination that had originally been recorded as goodwill (see Note 6). The impact of adjustments to reserves with respect to other uncertain tax positions was not material. 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 September 30, 2007, the years ended December 31, 2004 through 2006 are open for examination by U.S. taxing authorities. As of September 30, 2007, the years ended December 31, 2003 through 2006 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. FAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. FAS 157 will be effective for the Company beginning in the quarter ending March 31, 2008. The application of FAS 157 is not expected to have a material impact to the Company.

In February 2007, the FASB issued Statement No. 159,The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115(“FAS 159”). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value. FAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007 and will be effective for the Company beginning in the quarter ending March 31, 2008. The application of FAS 159 is not expected to have a material impact to the Company.

14. Subsequent Events

On October 9, 2007, the Company completed the acquisition of three recently refurbished SCR electric land drilling rigs and spare drilling equipment for $29.0 million. The transaction was accounted for as an acquisition of assets and the purchase price was allocated among the assets acquired based on their estimated fair market values.

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

Management Overview — We are a leading provider of contract services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and, to a lesser extent, we provide pressure pumping services and drilling and completion fluid services. In addition to the aforementioned contract services, we also engage in the development, exploration, acquisition and production of oil and natural gas. For the three and nine months ended September 30, 2007 and 2006, our operating revenues consisted of the following (dollars in thousands):


	Three Months Ended September 30,								Nine Months Ended September 30,
	2007				2006				2007				2006
Contract drilling	$	428,316	82	%	$	577,047	86	%	$	1,315,005	83	%	$	1,616,100	84	%
Pressure pumping		58,498	11			40,462	6			148,674	9			107,800	6
Drilling and completion fluids		27,348	5			46,163	7			97,775	6			155,221	8
Oil and natural gas		9,840	2			9,986	1			32,207	2			29,083	2

	$	524,002	100	%	$	673,658	100	%	$	1,593,661	100	%	$	1,908,204	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, 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. Our oil and natural gas operations are primarily focused in West and South Texas, Southeastern New Mexico, Utah and Mississippi.

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 third quarter of 2007, our average number of rigs operating was 243 per day compared to 237 in the second quarter of 2007 and 301 in the third quarter of 2006. Our average revenue per operating day decreased to $19,150 in the third quarter of 2007 from $19,410 in the second quarter of 2007 and $20,810 in the third quarter of 2006. Our consolidated net income for the third quarter of 2007 decreased by $87.8 million or 47% as compared to the third quarter of 2006. This decrease was primarily due to our contract drilling segment experiencing a decrease in the average number of rigs operating, an increase in the average costs per operating day and a decrease in the average revenue per operating day in the third quarter of 2007 as compared to the third quarter of 2006.

Our revenues, profitability and cash flows are highly dependent upon the market prices of oil and natural gas. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which results in increased demand for our contract services. Conversely, in periods when these commodity prices deteriorate, the demand for our contract services generally weakens and we experience a decrease in the number of rigs operating and 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 year ended December 31, 2006.

We believe that the liquidity presented in our balance sheet as of September 30, 2007, which includes approximately $190 million in working capital (including $20.5 million in cash) and approximately $306 million available under a $375 million line of credit, provides us with the ability to pursue acquisition opportunities, expand into new regions, make improvements to our assets, pay cash dividends and survive downturns in our industry.

Commitments and Contingencies — The Company maintains letters of credit in the aggregate amount of $59.4 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire at various times during each calendar year. No amounts have been drawn under the letters of credit.

As of September 30, 2007, we have remaining non-cancelable commitments to purchase approximately $123 million of equipment.

A receiver was appointed to take control of and liquidate the assets of our former CFO in connection with his embezzlement of Company funds. In May 2007, the court approved a plan of distribution of the assets that had been recovered by the receiver. We expect to recover a total of approximately $43.6 million pursuant to the approved plan and have recognized this recovery in our unaudited consolidated statement of income, net of additional professional fees associated with the embezzlement. Cash payments

from the receiver of approximately $40.2 million have been received as of September 30, 2007, with the remaining $3.4 million of the recovery consisting of notes receivable, investments and other assets that are being transferred to us.

Trading and Investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits, money markets, and highly rated municipal and commercial bonds.

Description of Business — We conduct our contract drilling operations in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota, Pennsylvania and Western Canada. We have 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 are also engaged in the development, exploration, acquisition and production of oil and natural gas. Our oil and natural gas operations are focused primarily in producing regions in West and South Texas, Southeastern New Mexico, Utah and Mississippi.

The North American land drilling industry has experienced periods of downturn in demand over the last decade. During these periods, there have been substantially more drilling rigs available than necessary to meet demand. As a result, drilling contractors have had difficulty sustaining profit margins during the downturn periods.

In addition to adverse effects that future declines in demand could have on us, ongoing factors which could adversely affect utilization rates and pricing, even in an environment of 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.

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 period ended December 31, 2006.

Liquidity and Capital Resources

As of September 30, 2007, we had working capital of approximately $190 million including cash and cash equivalents of $20.5 million. For the nine months ended September 30, 2007, our significant sources of cash flow included:

	•		$644 million provided by operations,

	•		$32.2 million in proceeds from disposal of property and equipment, and

	•		$2.4 million from the exercise of stock options and related tax benefits associated with stock-based compensation.

During the nine months ended September 30, 2007, we used $50.7 million to repurchase shares of our common stock, $50.1 million to pay dividends on our common stock, $110 million to repay borrowings under our line of credit and $461 million:

	•		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 leasehold acquisition and exploration and development of oil and natural gas properties.

As of September 30, 2007, we had $10.0 million in borrowings outstanding under our $375 million revolving line of credit and $59.4 million in letters of credit outstanding such that we had available borrowing capacity of approximately $306 million at September 30, 2007.

We paid cash dividends during the nine months ended September 30, 2007 as follows:


	Per Share		Total
			(in thousands)
Paid on March 30, 2007 to shareholders of record as of March 15, 2007	$	0.08	$	12,527
Paid on June 29, 2007 to shareholders of record as of June 14, 2007		0.12		18,860
Paid on September 28, 2007 to shareholders of record as of September 12, 2007		0.12		18,690

Total cash dividends	$	0.32	$	50,077

On October 31, 2007, our Board of Directors approved a cash dividend on our common stock in the amount of $0.12 per share to be paid on December 28, 2007 to holders of record as of December 12, 2007. The amount and timing of all future dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of 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. During the three months ended September 30, 2007, we purchased 2,275,000 shares of our common stock under the Program at a cost of approximately $50.3 million. As of September 30, 2007, we are authorized to purchase approximately $200 million of our outstanding common stock under the Program. Shares purchased under the Program have been accounted for as treasury stock.

On October 10, 2007, we completed the acquisition of three recently refurbished SCR electric land drilling rigs and spare drilling equipment for $29.0 million.

We believe that the current level of cash and short-term investments, together with cash generated from operations, should be sufficient to meet our capital needs. From time to time, acquisition opportunities are evaluated. The timing, size or success of any acquisition and the associated capital commitments are unpredictable. Should opportunities for growth requiring capital arise, we believe we would be able to satisfy these needs through a combination of working capital, cash generated from operations, our existing credit facility and additional debt or equity financing. However, there can be no assurance that such capital would be available.

Results of Operations

The following tables summarize operations by business segment for the three months ended September 30, 2007 and 2006:


	2007		2006		% Change
Contract Drilling	(Dollars in thousands)
Revenues	$	428,316	$	577,047		(25.8	)%
Direct operating costs	$	242,352	$	267,345		(9.3	)%
Selling, general and administrative	$	1,616	$	1,817		(11.1	)%
Depreciation	$	56,105	$	42,961		30.6	%
Operating income	$	128,243	$	264,924		(51.6	)%
Operating days		22,362		27,725		(19.3	)%
Average revenue per operating day	$	19.15	$	20.81		(8.0	)%
Average direct operating costs per operating day	$	10.84	$	9.64		12.4	%
Average rigs operating		243		301		(19.3	)%
Capital expenditures	$	120,192	$	152,879		(21.4	)%

The reactivation and construction of new land drilling rigs in the United States has resulted in excess capacity compared to recent demand. As a result, our average rigs operating have declined to 243 in the third quarter of 2007 compared to 301 in the third quarter of 2006.

Revenues in the third quarter of 2007 decreased as compared to the third quarter of 2006 as a result of the decreased number of operating days in 2007 and a decrease of approximately $1,660 in the average revenue per operating day. Direct operating costs in the third quarter of 2007 decreased as compared to the third quarter of 2006 as a result of the decreased number of operating days partially offset by an approximately $1,200 increase in the average direct operating costs per operating day. This increase in average direct operating costs per day resulted primarily from increased compensation costs and an increase in the cost of maintenance for our drilling rigs. Selling, general and administrative expense decreased primarily as a result of the transfer of certain administrative staff to our corporate segment. Significant capital expenditures have been incurred to activate additional 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.


	2007		2006		% Change
Pressure Pumping	(Dollars in thousands)
Revenues	$	58,498	$	40,462		44.6	%
Direct operating costs	$	28,682	$	20,960		36.8	%
Selling, general and administrative	$	4,882	$	3,450		41.5	%
Depreciation	$	3,702	$	2,559		44.7	%
Operating income	$	21,232	$	13,493		57.4	%
Total jobs		4,065		3,116		30.5	%
Average revenue per job	$	14.39	$	12.99		10.8	%
Average direct operating costs per job	$	7.06	$	6.73		4.9	%
Capital expenditures	$	11,047	$	7,692		43.6	%

Revenues and direct operating costs increased as a result of the increased number of jobs, as well as an increase in the average revenue and average direct operating costs per job. The increase in jobs was attributable to increased demand for our services and increased operating capacity. Increased average revenue per job was due to increased pricing for our services and an increase in the number of larger jobs. Average direct operating costs per job increased as a result of increases in compensation and the cost of materials used in our operations, as well as an increase in the number of larger jobs. Selling, general and administrative expense increased primarily as a result of increased compensation cost and increases in other administrative 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 was a result of the capital expenditures discussed above.


	2007			2006		% Change
Drilling and Completion Fluids	(Dollars in thousands)
Revenues	$	27,348		$	46,163		(40.8	)%
Direct operating costs	$	24,153		$	36,183		(33.2	)%
Selling, general and administrative	$	2,486		$	2,733		(9.0	)%
Depreciation	$	728		$	689		5.7	%
Operating income (loss)	$	(19	)	$	6,558		N/A	%
Capital expenditures	$	460		$	1,122		(59.0	)%

Revenues and direct operating costs decreased primarily as a result of a decrease in the number of large jobs offshore in the Gulf of Mexico caused by a slowdown in drilling activity during the third quarter of 2007 in that area.


	2007		2006		% Change
Oil and Natural Gas Production and Exploration	(Dollars in thousands,
	except sales prices)
Revenues	$	9,840	$	9,986		(1.5	)%
Direct operating costs	$	2,474	$	3,222		(23.2	)%
Selling, general and administrative	$	695	$	684		1.6	%
Depreciation, depletion and impairment	$	5,784	$	2,804		106.3	%
Operating income	$	887	$	3,276		(72.9	)%
Capital expenditures	$	4,153	$	4,982		(16.6	)%
Average net daily oil production (Bbls)		920		961		(4.3	)%
Average net daily gas production (Mcf)		4,199		4,820		(12.9	)%
Average oil sales price (per Bbl)	$	73.57	$	68.66		7.2	%
Average natural gas sales price (per Mcf)	$	6.58	$	6.77		(2.8	)%

Revenues decreased primarily due to a decrease in the net daily production of oil and natural gas. Average net daily oil and natural gas production decreased primarily due to the sale of certain properties in the second quarter of 2007. The decrease in direct operating costs is primarily due to a decrease of approximately $564,000 in costs associated with the abandonment of exploratory wells. Depreciation, depletion and impairment expense in the third quarter of 2007 includes approximately $1.9 million incurred to impair certain oil and natural gas properties compared to approximately $889,000 incurred to impair certain oil and natural gas properties in the third quarter of 2006. Depletion expense increased approximately $2.0 million due to the completion of new wells in 2007.


	2007			2006			% Change
Corporate and Other	(Dollars in thousands)
Selling, general and administrative	$	6,914		$	5,093			35.8	%
Depreciation	$	204		$	202			1.0	%
Other operating expenses	$	600		$	3,000			(80.0	)%
(Gain) loss on disposal of assets	$	(330	)	$	(437	)		(24.5	)%
Embezzlement costs (recoveries)	$	(1,145	)	$	(1,512	)		(24.3	)%
Interest income	$	1,091		$	948			15.1	%
Interest expense	$	357		$	363			(1.7	)%
Other income	$	42		$	88			(52.3	)%

The following tables summarize operations by business segment for the nine months ended September 30, 2007 and 2006:


	2007		2006		% Change
Contract Drilling	(Dollars in thousands)
Revenues	$	1,315,005	$	1,616,100		(18.6	)%
Direct operating costs	$	716,803	$	737,021		(2.7	)%
Selling, general and administrative	$	4,467	$	5,338		(16.3	)%
Depreciation	$	156,075	$	121,764		28.2	%
Operating income	$	437,660	$	751,977		(41.8	)%
Operating days		66,931		81,489		(17.9	)%
Average revenue per operating day	$	19.65	$	19.83		(1.0	)%
Average direct operating costs per operating day	$	10.71	$	9.04		18.5	%
Average rigs operating		245		298		(17.8	)%
Capital expenditures	$	403,381	$	377,165		7.0	%

Demand for our contract drilling services is largely dependent upon the prevailing prices for natural gas. The average market price of natural gas fell from $8.98 per Mcf in 2005 to $6.94 per Mcf in 2006. This resulted in our customers moderating their increase in drilling activities in 2007. This moderation combined with the reactivation and construction of new land drilling rigs in the United States has resulted in excess capacity compared to recent demand. As a result of these factors, our average rigs operating have declined to 245 for the first nine months of 2007 compared to 298 for the first nine months of 2006.

Revenues in the first nine months of 2007 decreased as compared to the first nine months of 2006 as a result of the decreased number of operating days in 2007 and a decrease of approximately $180 in the average revenue per operating day. Direct operating costs in the first nine months of 2007 decreased as compared to the first nine months of 2006 as a result of the decreased number of operating days partially offset by an approximately $1,670 increase in the average direct operating costs per operating day. This increase in average direct operating costs per day resulted primarily from increased compensation costs and an increase in the cost of maintenance for our drilling rigs. Selling, general and administrative expense decreased primarily as a result of the transfer of certain administrative staff to our corporate segment. Significant capital expenditures have been incurred to activate additional 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.


	2007		2006		% Change
Pressure Pumping	(Dollars in thousands)
Revenues	$	148,674	$	107,800		37.9	%
Direct operating costs	$	75,610	$	56,545		33.7	%
Selling, general and administrative	$	13,758	$	9,588		43.5	%
Depreciation	$	10,234	$	7,075		44.7	%
Operating income	$	49,072	$	34,592		41.9	%
Total jobs		10,477		8,844		18.5	%
Average revenue per job	$	14.19	$	12.19		16.4	%
Average direct operating costs per job	$	7.22	$	6.39		13.0	%
Capital expenditures	$	41,678	$	27,371		52.3	%


	2007		2006		% Change
Drilling and Completion Fluids	(Dollars in thousands)
Revenues	$	97,775	$	155,221		(37.0	)%
Direct operating costs	$	82,172	$	120,418		(31.8	)%
Selling, general and administrative	$	7,319	$	7,765		(5.7	)%
Depreciation	$	2,121	$	2,000		6.1	%
Operating income	$	6,163	$	25,038		(75.4	)%
Capital expenditures	$	2,581	$	3,052		(15.4	)%

Revenues and direct operating costs decreased primarily as a result of a decrease in the number of large jobs offshore in the Gulf of Mexico.


	2007		2006		% Change
	(Dollars in thousands,
Oil and Natural Gas Production and Exploration		except sales prices)
Revenues	$	32,207	$	29,083		10.7	%
Direct operating costs	$	8,213	$	11,241		(26.9	)%
Selling, general and administrative	$	2,017	$	2,050		(1.6	)%
Depreciation, depletion and impairment	$	13,361	$	8,815		51.6	%
Operating income	$	8,616	$	6,977		23.5	%
Capital expenditures	$	13,804	$	15,699		(12.1	)%
Average net daily oil production (Bbls)		1,042		944		10.4	%
Average net daily gas production (Mcf)		5,356		4,986		7.4	%
Average oil sales price (per Bbl)	$	63.82	$	66.24		(3.7	)%
Average natural gas sales price (per Mcf)	$	7.28	$	6.96		4.6	%

Revenues increased primarily due to increases in the net daily production of oil and natural gas. The increase in average net daily production of oil was partially offset by a decrease in the average oil sales price. Average net daily oil and natural gas production increased primarily due to the completion of wells subsequent to the third quarter of 2006, partially offset by the sale of certain properties in the second quarter of 2007. The decrease in direct operating costs is primarily due to a decrease of approximately $2.9 million in costs associated with the abandonment of exploratory wells. Depreciation, depletion and impairment expense in 2007 includes approximately $3.0 million incurred to impair certain oil and natural gas properties compared to approximately $2.2 million incurred to impair certain oil and natural gas properties in 2006. Depletion expense increased approximately $4.1 million due to the completion of new wells in 2007.


	2007			2006			% Change
Corporate and Other	(Dollars in thousands)
Selling, general and administrative	$	20,023		$	14,687			36.3	%
Depreciation	$	610		$	591			3.2	%
Other operating expenses	$	1,600		$	4,385			(63.5	)%
Gain on disposal of assets	$	(16,603	)	$	(437	)		N/A	%
Embezzlement costs (recoveries)	$	(43,080	)	$	2,941			N/A	%
Interest income	$	1,917		$	5,579			(65.6	)%
Interest expense	$	1,951		$	476			309.9	%
Other income	$	245		$	231			6.1	%
Capital expenditures	$	—		$	135			(100.0	)%

Selling, general and administrative expense increased primarily as a result of compensation expense related to transfers of certain administrative staff to our corporate segment as well as increases in stock-based compensation expense and professional fees. Other operating expenses decreased primarily due to a decrease in bad debt expense of $2.6 million. In 2007 we sold certain oil and natural gas properties resulting in a gain of $20.9 million. This gain was reduced by approximately $4.3 million in losses associated with the disposal of other assets. 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 2007 includes an expected recovery of $43.6 million reduced by additional professional and other costs incurred as a result of the embezzlement. Embezzlement costs (recoveries) in 2006 include professional and other costs incurred as a result of the embezzlement reduced by insurance proceeds of $2.0 million. Interest income decreased due to the decrease in cash available to invest from 2006 to 2007. Interest expense in 2007 increased primarily due to higher average borrowings that were outstanding under our line of credit during 2007.

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. FAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. FAS 157 will be effective for us beginning in the quarter ending March 31, 2008. The application of FAS 157 is not expected to have a material impact to us.

In February 2007, the FASB issued Statement No. 159,The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115(“FAS 159”). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value. FAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007 and will be effective for us beginning in the quarter ending March 31, 2008. The application of FAS 159 is not expected to have a material impact to us.

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 to an average of $6.94 and $7.18 per Mcf for the full year of 2006 and the first nine months of 2007, respectively, compared to $8.98 per Mcf for the full year of 2005. This resulted in our customers moderating their increase in drilling activities in 2007. This moderation combined with the reactivation and construction of new land drilling rigs in the United States has resulted in excess capacity compared to recent demand. As a result of these factors, our average rigs operating have declined to 245 for the nine months ended September 30, 2007 compared to 298 in the comparable period in 2006. 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 reduction in our operation results.

Impact of Inflation

We believe that inflation will not have a significant near-term impact on our financial position.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

We currently have 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. 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 given our current level of outstanding borrowings.

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 September 30, 2007.

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

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

	•		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 year ended December 31, 2006, beginning on page 10.

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

PART II — OTHER INFORMATION

ITEM 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 September 30, 2007.


							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)
July 1-31, 2007		—	$	—		—	$	—
August 1-31, 2007		1,195,125	$	21.80		1,195,000	$	223,948

September 1-30, 2007		1,080,000	$	22.43		1,080,000	$	199,726

Total		2,275,125	$	22.10		2,275,000	$	199,726


(1)		On August 1, 2007, our Board of Directors approved a stock buyback program authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions.

ITEM 5. Other Information

On November 1, 2007, we entered into amendments to existing change in control agreements with Mark S. Siegel, Douglas J. Wall, John E. Vollmer, III, Kenneth N. Berns and William L. Moll, Jr.. The purpose of these amendments was to bring the agreements into compliance with certain requirements of Section 409(a) of the Internal Revenue Code. In the case of Messrs. Vollmer and Berns, the amendment provides that in the event of a change in control of Patterson-UTI in which such employee’s employment is terminated by Patterson-UTI other than for cause or by such employee for good reason, such employee would be entitled to a payment equal to 2 times (rather than 1.5 times as stated in the original change in control agreement) the sum of (1) the highest annual salary in effect for such person and (2) the average of the three annual bonuses earned by such person for the three fiscal years preceding the termination date. The amendments to the change in control agreements are filed as Exhibits 10.8, 10.9, 10.10, 10.11 and 10.12 to this report.

ITEM 6. Exhibits

(a) Exhibits.

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

3.1		Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).

3.2		Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).

3.3		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		Indemnification Agreement between Douglas J. Wall and Patterson-UTI Energy, Inc. dated August 31, 2007 (form of which has been filed on April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and incorporated herein by reference).

10.2		Indemnification Agreement between William L. Moll, Jr. and Patterson-UTI Energy, Inc. dated August 31, 2007 (form of which has been filed on April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and incorporated herein by reference).

10.3		Indemnification Agreement between Gregory W. Pipkin and Patterson-UTI Energy, Inc. dated August 31, 2007 (form of which has been filed on April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and incorporated herein by reference).

10.4		Indemnification Agreement between Charles O. Buckner and Patterson-UTI Energy, Inc. dated August 31, 2007 (form of which has been filed on April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and incorporated herein by reference).

10.5		Severance Agreement between Patterson-UTI Energy, Inc. and Douglas J. Wall, effective as of August 31, 2007 (filed September 4, 2007 as Exhibit 10.3 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

10.6		Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of August 31, 2007, by and between Patterson-UTI and Douglas J. Wall (filed September 4, 2007 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

10.7		Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of August 31, 2007, by and between Patterson-UTI Energy, Inc. and William L. Moll, Jr.

10.8		First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into November 1, 2007.

10.9		First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into November 1, 2007.

10.10		First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and John E. Vollmer, III, entered into November 1, 2007.

10.11		First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into November 1, 2007.

10.12		First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and William L. Moll, Jr., entered into November 1, 2007.

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.

SIGNATURES

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


	PATTERSON-UTI ENERGY, INC.
	By:	/s/ Douglas J. Wall
		Douglas J. Wall
		(Principal Executive Officer) President and Chief Executive Officer



	By:	/s/ John E. Vollmer III
		John E. Vollmer III
		(Principal Financial Officer) Senior Vice President-Corporate Development, Chief Financial Officer and Treasurer



	By:	/s/ Gregory W. Pipkin
		Gregory W. Pipkin
		(Principal Accounting Officer) Chief Accounting Officer and Assistant Secretary

DATED: November 5, 2007

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

Patterson-UTI Energy (PTEN) 10-Q2007 Q3 Quarterly report

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