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PATTERSON UTI ENERGY INC - Quarter Report: 2007 June (Form 10-Q)

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Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
Form 10-Q
 
 
     
þ
  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the quarterly period ended June 30, 2007
or
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from          to
 
Commission file number 0-22664
 
Patterson-UTI Energy, Inc.
(Exact name of registrant as specified in its charter)
 
 
     
DELAWARE   75-2504748
(State or other jurisdiction of   (I.R.S. Employer
incorporation or organization)   Identification No.)
     
4510 LAMESA HIGHWAY,
SNYDER, TEXAS
  79549
(Zip Code)
(Address of principal executive offices)    
 
(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.
 
157,190,147 shares of common stock, $0.01 par value, as of August 2, 2007
 


 

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
 
TABLE OF CONTENTS
 
                 
        Page
 
  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
  Management’s Discussion and Analysis of Financial Condition and Results of Operations   13
  Quantitative and Qualitative Disclosures About Market Risk   21
  Controls and Procedures   21
Forward Looking Statements and Cautionary Statements for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995   22
  Unregistered Sales of Equity Securities and Use of Proceeds   23
  Submission of Matters to a Vote of Security Holders   23
  Other Information   24
  Exhibits   24
  25
 Second Amended and Restated Bylaws
 Certification of CEO Pursuant to Rule 13a-14(a)/15d-14(a)
 Certification of CFO Pursuant to Rule 13a-14(a)/15d-14(a)
 Certification Pursuant to 18 U.S.C. Section 1350


Table of Contents

 
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)
 
                 
    June 30,
    December 31,
 
    2007     2006  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 27,475     $ 13,385  
Accounts receivable, net of allowance for doubtful accounts of $8,438 at June 30, 2007 and $7,484 at December 31, 2006
    393,448       484,106  
Accrued federal and state income taxes receivable
          5,448  
Inventory
    42,664       43,947  
Deferred tax assets, net
    36,504       48,868  
Deposits on equipment purchase contracts
    4,741       24,746  
Embezzlement recovery receivable
    42,500        
Other
    38,998       32,170  
                 
Total current assets
    586,330       652,670  
Property and equipment, net
    1,688,868       1,435,804  
Goodwill
    96,198       99,056  
Other
    5,484       4,973  
                 
Total assets
  $ 2,376,880     $ 2,192,503  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
Accounts payable:
               
Trade
  $ 190,129     $ 138,372  
Accrued revenue distributions
    18,161       15,359  
Other
    13,099       18,424  
Accrued federal and state income taxes payable
    831        
Accrued expenses
    123,874       145,463  
                 
Total current liabilities
    346,094       317,618  
Borrowings under line of credit
    15,000       120,000  
Deferred tax liabilities, net
    208,382       187,960  
Other
    4,560       4,459  
                 
Total liabilities
    574,036       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 177,312,704 and 176,656,401 issued and 157,182,797 and 156,542,512 outstanding at June 30, 2007 and December 31, 2006, respectively
    1,773       1,766  
Additional paid-in capital
    691,472       681,069  
Retained earnings
    1,570,507       1,346,542  
Accumulated other comprehensive income
    14,808       8,390  
Treasury stock, at cost, 20,129,907 and 20,113,889 shares at June 30, 2007 and December 31, 2006, respectively
    (475,716 )     (475,301 )
                 
Total stockholders’ equity
    1,802,844       1,562,466  
                 
Total liabilities and stockholders’ equity
  $ 2,376,880     $ 2,192,503  
                 
 
The accompanying notes are an integral part of these unaudited consolidated financial statements.


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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF INCOME
(unaudited, in thousands, except per share amounts)
 
                                 
    Three Months Ended
    Six Months Ended
 
    June 30,     June 30,  
    2007     2006     2007     2006  
 
Operating revenues:
                               
Contract drilling
  $ 419,191     $ 530,349     $ 886,689     $ 1,039,053  
Pressure pumping
    51,592       36,010       90,176       67,338  
Drilling and completion fluids
    39,667       59,877       70,427       109,058  
Oil and natural gas
    12,108       10,577       22,367       19,097  
                                 
      522,558       636,813       1,069,659       1,234,546  
                                 
Operating costs and expenses:
                               
Contract drilling
    228,297       235,902       474,451       469,676  
Pressure pumping
    25,777       17,935       46,928       35,585  
Drilling and completion fluids
    32,628       46,049       58,019       84,235  
Oil and natural gas
    2,461       5,364       5,739       8,019  
Depreciation, depletion and impairment
    59,947       47,481       115,878       91,030  
Selling, general and administrative
    16,322       12,840       30,991       25,651  
Embezzlement costs (recoveries)
    (41,935 )     673       (41,935 )     4,453  
(Gain) loss on disposal of assets
    (16,475 )     870       (16,273 )      
Other operating expenses
    400       786       1,000       1,385  
                                 
      307,422       367,900       674,798       720,034  
                                 
Operating income
    215,136       268,913       394,861       514,512  
                                 
Other income (expense):
                               
Interest income
    457       2,280       826       4,631  
Interest expense
    (831 )     (55 )     (1,594 )     (113 )
Other
    109       59       203       143  
                                 
      (265 )     2,284       (565 )     4,661  
                                 
Income before income taxes and cumulative effect of change in accounting principle
    214,871       271,197       394,296       519,173  
                                 
Income tax expense:
                               
Current
    56,350       98,394       109,783       182,325  
Deferred
    18,970       1,113       29,161       6,589  
                                 
      75,320       99,507       138,944       188,914  
                                 
Income before cumulative effect of change in accounting principle
    139,551       171,690       255,352       330,259  
Cumulative effect of change in accounting principle, net of related income tax expense of $398
                      687  
                                 
Net income
  $ 139,551     $ 171,690     $ 255,352     $ 330,946  
                                 
Income before cumulative effect of change in accounting principle:
                               
Basic
  $ 0.90     $ 1.02     $ 1.64     $ 1.94  
                                 
Diluted
  $ 0.88     $ 1.00     $ 1.62     $ 1.91  
                                 
Net income per common share:
                               
Basic
  $ 0.90     $ 1.02     $ 1.64     $ 1.94  
                                 
Diluted
  $ 0.88     $ 1.00     $ 1.62     $ 1.91  
                                 
Weighted average number of common shares outstanding:
                               
Basic
    155,527       168,894       155,457       170,351  
                                 
Diluted
    157,912       171,522       157,580       172,949  
                                 
 
The accompanying notes are an integral part of these unaudited consolidated financial statements.


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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
    576       6       (6 )                        
Exercise of stock options
    109       1       933                         934  
Stock based compensation
                8,416                         8,416  
Tax benefit for stock based compensation
                1,060                         1,060  
Forfeitures of restricted shares
    (28 )                                    
Foreign currency translation adjustment, net of tax of $3,625
                            6,418             6,418  
Payment of cash dividends
                      (31,387 )                 (31,387 )
Purchase of treasury stock
                                  (415 )     (415 )
Net income
                      255,352                   255,352  
                                                         
Balance, June 30, 2007
    177,313     $ 1,773     $ 691,472     $ 1,570,507     $ 14,808     $ (475,716 )   $ 1,802,844  
                                                         
 
The accompanying notes are an integral part of these unaudited consolidated financial statements.


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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS
(unaudited, in thousands)
 
                 
    Six Months Ended
 
    June 30,  
    2007     2006  
 
Cash flows from operating activities:
               
Net income
  $ 255,352     $ 330,946  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, depletion and impairment
    115,878       91,030  
Dry holes and abandonments
    786       3,101  
Provision for bad debts
    1,000       1,200  
Deferred income tax expense
    29,161       6,987  
Stock based compensation expense
    8,416       6,366  
Gain on disposal of assets
    (16,273 )      
Changes in operating assets and liabilities:
               
Accounts receivable
    90,703       (86,185 )
Embezzlement recovery receivable
    (42,500 )      
Inventory and other current assets
    14,352       (13,655 )
Accounts payable
    6,876       10,862  
Income taxes payable/receivable
    6,427       (12,561 )
Accrued expenses
    (18,864 )     11,959  
Other liabilities
    (4,730 )     2,778  
                 
Net cash provided by operating activities
    446,584       352,828  
                 
Cash flows from investing activities:
               
Purchases of property and equipment
    (325,592 )     (256,747 )
Proceeds from disposal of property and equipment
    26,803       4,264  
                 
Net cash used in investing activities
    (298,789 )     (252,483 )
                 
Cash flows from financing activities:
               
Purchases of treasury stock
    (415 )     (199,998 )
Dividends paid
    (31,387 )     (20,319 )
Proceeds from exercise of stock options
    934       1,261  
Tax benefit related to stock-based compensation
    1,060       845  
Proceeds from borrowings under line of credit
    82,500        
Repayment of borrowings under line of credit
    (187,500 )      
                 
Net cash used in financing activities
    (134,808 )     (218,211 )
                 
Effect of foreign exchange rate changes on cash
    1,103       460  
                 
Net increase (decrease) in cash and cash equivalents
    14,090       (117,406 )
Cash and cash equivalents at beginning of period
    13,385       136,398  
                 
Cash and cash equivalents at end of period
  $ 27,475     $ 18,992  
                 
Supplemental disclosure of cash flow information:
               
Net cash paid during the period for:
               
Interest expense
  $ 1,194     $ 113  
Income taxes
  $ 96,759     $ 184,501  
 
The accompanying notes are an integral part of these unaudited consolidated financial statements.


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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 presentation of the information 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 unrestricted common shares outstanding during the period. 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 shares using the treasury stock method. The following table presents information necessary to calculate net income per share for the three and six months ended June 30, 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 six months ended June 30, 2007 and 2006 (in thousands, except per share amounts):
 
                                 
    Three Months Ended
    Six Months Ended
 
    June 30,     June 30,  
    2007     2006     2007     2006  
 
Net income
  $ 139,551     $ 171,690     $ 255,352     $ 330,946  
Weighted average number of unrestricted common shares outstanding
    155,527       168,894       155,457       170,351  
                                 
Basic net income per common share
  $ 0.90     $ 1.02     $ 1.64     $ 1.94  
                                 
Weighted average number of unrestricted common shares outstanding
    155,527       168,894       155,457       170,351  
Dilutive effect of stock options and restricted shares
    2,385       2,628       2,123       2,598  
                                 
Weighted average number of diluted common shares outstanding
    157,912       171,522       157,580       172,949  
                                 
Diluted net income per common share
  $ 0.88     $ 1.00     $ 1.62     $ 1.91  
                                 
Cash dividends paid per common share
  $ 0.12     $ 0.08     $ 0.20     $ 0.12  
                                 
Potentially dilutive securities excluded as anti-dilutive
    1,785             2,435        
                                 


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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The results of operations for the six months ended June 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”), except for stock options granted prior to 1996 that are not subject to FAS 123(R). 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 were 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 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 six month periods ended June 30, 2007 and 2006 follow:
 
                                 
    Three Months Ended
    Six Months Ended
 
    June 30,     June 30,  
    2007     2006     2007     2006  
 
Volatility
    36.36 %     N/A       36.38 %     26.95 %
Expected term (in years)
    4.00       N/A       4.00       4.00  
Dividend yield
    2.00 %     N/A       1.96 %     0.47 %
Risk-free interest rate
    4.56 %     N/A       4.56 %     4.30 %
 
Stock option activity from January 1, 2007 to June 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
    (108,578 )   $ 8.60  
Forfeited
    (1,333 )   $ 14.64  
Expired
        $  
Cancelled
        $  
                 
Outstanding at June 30, 2007
    7,500,185     $ 17.36  
                 
Exercisable at June 30, 2007
    5,547,051     $ 14.48  
                 
 
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


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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 June 30, 2007 follows:
 
                 
          Weighted
 
          Average
 
          Grant Date
 
    Shares     Fair Value  
 
Nonvested at January 1, 2007
    1,188,200     $ 25.92  
Granted
    576,150     $ 24.71  
Vested
    (181,925 )   $ 19.00  
Forfeited
    (28,425 )   $ 24.68  
                 
Nonvested at June 30, 2007
    1,554,000     $ 26.31  
                 
 
3.   Comprehensive Income
 
The following table illustrates the Company’s comprehensive income including the effects of foreign currency translation adjustments for the three and six months ended June 30, 2007 and 2006 (in thousands):
 
                                 
    Three Months Ended
    Six Months Ended
 
    June 30,     June 30,  
    2007     2006     2007     2006  
 
Net income
  $ 139,551     $ 171,690     $ 255,352     $ 330,946  
Other comprehensive income:
                               
Foreign currency translation adjustment related to Canadian operations, net of tax
    5,770       2,703       6,418       2,538  
                                 
Comprehensive income, net of tax
  $ 145,321     $ 174,393     $ 261,770     $ 333,484  
                                 
 
4.   Property and Equipment
 
Property and equipment consisted of the following at June 30, 2007 and December 31, 2006 (in thousands):
 
                 
    June 30,
    December 31,
 
    2007     2006  
 
Equipment
  $ 2,485,203     $ 2,135,567  
Oil and natural gas properties
    80,174       85,143  
Buildings
    37,217       30,987  
Land
    10,117       7,507  
                 
      2,612,711       2,259,204  
Less accumulated depreciation and depletion
    (923,843 )     (823,400 )
                 
Property and equipment, net
  $ 1,688,868     $ 1,435,804  
                 


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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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
    Six Months Ended
 
    June 30,     June 30,  
    2007     2006     2007     2006  
 
Revenues:
                               
Contract drilling(a)
  $ 420,285     $ 531,904     $ 888,624     $ 1,041,668  
Pressure pumping
    51,592       36,010       90,176       67,338  
Drilling and completion fluids(b)
    39,702       60,098       70,583       109,322  
Oil and natural gas
    12,108       10,577       22,367       19,097  
                                 
Total segment revenues
    523,687       638,589       1,071,750       1,237,425  
Elimination of intercompany revenues(a)(b)
    1,129       1,776       2,091       2,879  
                                 
Total revenues
  $ 522,558     $ 636,813     $ 1,069,659     $ 1,234,546  
                                 
Income before income taxes:
                               
Contract drilling
  $ 137,712     $ 252,446     $ 309,417     $ 487,053  
Pressure pumping
    17,599       12,593       27,840       21,099  
Drilling and completion fluids
    3,906       10,562       6,182       18,480  
Oil and natural gas
    5,116       472       7,729       3,701  
                                 
      164,333       276,073       351,168       530,333  
Corporate and other
    (7,607 )     (5,617 )     (14,515 )     (11,368 )
Embezzlement (costs) recoveries(c)
    41,935       (673 )     41,935       (4,453 )
Gain (loss) on disposal of assets(d)
    16,475       (870 )     16,273        
Interest income
    457       2,280       826       4,631  
Interest expense
    (831 )     (55 )     (1,594 )     (113 )
Other
    109       59       203       143  
                                 
Income before income taxes and cumulative effect of change in accounting principle
  $ 214,871     $ 271,197     $ 394,296     $ 519,173  
                                 
 


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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                 
    June 30,
    December 31,
 
    2007     2006  
 
Identifiable assets:
               
Contract drilling
  $ 1,984,381     $ 1,849,923  
Pressure pumping
    147,581       111,787  
Drilling and completion fluids
    105,166       106,032  
Oil and natural gas
    62,856       65,443  
                 
      2,299,984       2,133,185  
Corporate and other(e)
    76,896       59,318  
                 
Total assets
  $ 2,376,880     $ 2,192,503  
                 
 
 
(a) Includes contract drilling intercompany revenues of approximately $1.1 million and $1.6 million for the three months ended June 30, 2007 and 2006, respectively. Includes contract drilling intercompany revenues of approximately $1.9 million and $2.6 million for the six months ended June 30, 2007 and 2006, respectively.
 
(b) Includes drilling and completion fluids intercompany revenues of approximately $35,000 and $221,000 for the three months ended June 30, 2007 and 2006, respectively. Includes drilling and completion fluids intercompany revenues of approximately $156,000 and $264,000 for the six months ended June 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 approximately $42.5 million in assets that have been seized from the former CFO and companies that he controlled by a court-appointed receiver. 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, embezzlement recovery receivable and certain deferred federal income tax assets.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
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 June 30, 2007 is as follows (in thousands):
 
         
    June 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 June 30, 2007 and December 31, 2006 (in thousands):
 
                 
    June 30,
    December 31,
 
    2007     2006  
 
Salaries, wages, payroll taxes and benefits
  $ 27,633     $ 42,751  
Workers’ compensation liability
    65,281       67,615  
Sales, use and other taxes
    9,489       11,043  
Insurance, other than workers’ compensation
    15,927       13,328  
Other
    5,544       10,726  
                 
Accrued expenses
  $ 123,874     $ 145,463  
                 


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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

8.   Asset Retirement Obligation
 
Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” requires that the Company record a liability for the estimated costs to be incurred in connection with the abandonment of oil and natural gas properties in the future. The following table describes the changes to the Company’s asset retirement obligations during the six months ended June 30, 2007 and 2006 (in thousands):
 
                 
    2007     2006  
 
Balance at beginning of year
  $ 1,829     $ 1,725  
Liabilities incurred
    151       63  
Liabilities settled
    (632 )     (45 )
Accretion expense
    31       27  
Revision in estimated cash flows
    289        
                 
Asset retirement obligation at end of period
  $ 1,668     $ 1,770  
                 
 
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 June 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 June 30, 2007, the Company had $15.0 million in borrowings outstanding under the LOC and $60.3 million in letters of credit were outstanding. As a result, the Company had available borrowing capacity of approximately $300 million at June 30, 2007. The weighted average interest rate on outstanding borrowings at June 30, 2007 was 8.25%.
 
10.   Commitments, Contingencies and Other Matters
 
Commitments — The Company maintains letters of credit in the aggregate amount of $60.3 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 June 30, 2007, the Company has signed non-cancelable commitments to purchase approximately $175 million of equipment. This amount excludes $4.7 million and $24.7 million at June 30, 2007 and December 31, 2006, respectively, related to deposits that have been paid pursuant to agreements that were entered into to purchase rig components to be used in the construction of 15 new land drilling rigs. 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 approximately $42.5 million pursuant to the approved plan and has recognized this recovery in the Company’s unaudited consolidated statement of income in the second quarter of 2007, net of additional professional fees associated with the embezzlement. Cash payments from the receiver of approximately $39.1 million were received in July 2007, with the remaining $3.4 million of the recovery consisting of notes receivable, investments and other assets that will be transferred to the Company.


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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 six months ended June 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  
                 
Total cash dividends
  $ 0.20     $ 31,387  
                 
 
On August 1, 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 September 28, 2007 to holders of record as of September 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 during the six months ended June 30, 2007. Shares were purchased from employees at fair market value upon the vesting of restricted stock to provide the respective 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, authorizing purchases of up to $250 million of the Company’s common stock in open market or privately negotiated transactions.
 
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 June 30, 2007, the years ended December 31, 2003 through 2006 are open for examination by U.S. taxing authorities. As of June 30, 2007, the years ended December 31, 2000 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.


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ITEM 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Management Overview — We are a leading provider of contract services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and, to a lesser extent, we provide pressure pumping services and drilling and completion fluid services. In addition to the aforementioned contract services, we also engage in the development, exploration, acquisition and production of oil and natural gas. For the three and six months ended June 30, 2007 and 2006, our operating revenues consisted of the following (dollars in thousands):
 
                                                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2007     2006     2007     2006  
 
Contract drilling
  $ 419,191       80 %   $ 530,349       83 %   $ 886,689       83 %   $ 1,039,053       84 %
Pressure pumping
    51,592       10       36,010       6       90,176       8       67,338       5  
Drilling and completion fluids
    39,667       8       59,877       9       70,427       7       109,058       9  
Oil and natural gas
    12,108       2       10,577       2       22,367       2       19,097       2  
                                                                 
    $ 522,558       100 %   $ 636,813       100 %   $ 1,069,659       100 %   $ 1,234,546       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.
 
The profitability of our business is most readily assessed by two primary indicators in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During the second quarter of 2007, our average number of rigs operating was 237 per day compared to 255 in the first quarter of 2007 and 295 in the second quarter of 2006. Our average revenue per operating day decreased to $19,410 in the second quarter of 2007 from $20,350 in the first quarter of 2007 and $19,780 in the second quarter of 2006. Our consolidated net income for the second quarter of 2007 decreased by $32.1 million or 19% as compared to the second quarter of 2006. Included in consolidated net income for the second quarter of 2007 was a pre-tax gain of approximately $41.9 million associated with the expected recovery of embezzled funds and approximately $16.4 million in net pre-tax gains from the sale of certain oil and natural gas properties and the disposal of certain other assets. Excluding the above-mentioned gains, our consolidated net income for the second quarter of 2007 would have been approximately $102 million, which is a decrease of approximately $70.1 million or 41% as compared to the second quarter of 2006. This decrease was primarily due to our contract drilling segment experiencing an increase in the average costs per operating day, a decrease in the average revenue per operating day and a decrease in the average number of rigs operating in the second quarter of 2007 as compared to the second 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 of time 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 June 30, 2007, which includes approximately $240 million in working capital (including $27.5 million in cash) and $300 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.


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Commitments and Contingencies — The Company maintains letters of credit in the aggregate amount of $60.3 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 June 30, 2007, we have remaining non-cancelable commitments to purchase approximately $175 million of equipment.
 
A receiver has been 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 approximately $42.5 million pursuant to the approved plan and have recognized this recovery in our unaudited consolidated statement of income in the second quarter of 2007, net of additional professional fees associated with the embezzlement. Cash payments from the receiver of approximately $39.1 million were received in July 2007, with the remaining $3.4 million of the recovery consisting of notes receivable, investments and other assets that are expected to be 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 345 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.


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Liquidity and Capital Resources
 
As of June 30, 2007, we had working capital of approximately $240 million including cash and cash equivalents of $27.5 million. For the six months ended June 30, 2007, our significant sources of cash flow included:
 
  •  $447 million provided by operations,
 
  •  $26.8 million in proceeds from disposal of property and equipment, and
 
  •  $2.0 million from the exercise of stock options and related tax benefits associated with stock-based compensation.
 
We used $31.4 million to pay dividends on the Company’s common stock, $105 million to repay borrowings under our line of credit and $326 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 June 30, 2007, we had $15.0 million in borrowings outstanding under our $375 million revolving line of credit and $60.3 million in letters of credit were outstanding such that we had available borrowing capacity of approximately $300 million at June 30, 2007.
 
We paid cash dividends during the six months ended June 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  
                 
Total cash dividends
  $ 0.20     $ 31,387  
                 
 
On August 1, 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 September 28, 2007 to holders of record as of September 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, authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions.
 
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.


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Results of Operations
 
The following tables summarize operations by business segment for the three months ended June 30, 2007 and 2006:
 
                         
Contract Drilling
  2007     2006     % Change  
    (Dollars in thousands)  
 
Revenues
  $ 419,191     $ 530,349       (21.0 )%
Direct operating costs
  $ 228,297     $ 235,902       (3.2 )%
Selling, general and administrative
  $ 1,400     $ 1,733       (19.2 )%
Depreciation
  $ 51,782     $ 40,268       28.6 %
Operating income
  $ 137,712     $ 252,446       (45.4 )%
Operating days
    21,597       26,810       (19.4 )%
Average revenue per operating day
  $ 19.41     $ 19.78       (1.9 )%
Average direct operating costs per operating day
  $ 10.57     $ 8.80       20.1 %
Average rigs operating
    237       295       (19.7 )%
Capital expenditures
  $ 129,913     $ 124,909       4.0 %
 
Demand for our contract drilling services is 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 decrease resulted in our customers reducing their drilling activities beginning in the fourth quarter of 2006 and continuing into 2007. As a result of the decrease in drilling activities by our customers, our average rigs operating declined to 237 in the second quarter of 2007 compared to 255 in the first quarter of 2007 and 295 in the second quarter of 2006.
 
Revenues in the second quarter of 2007 decreased as compared to the second quarter of 2006 as a result of the decreased number of operating days in 2007 and a decrease of approximately $370 in the average revenue per operating day. The increase in average direct operating costs per day of approximately $1,770 resulted primarily from increased compensation costs and an increase in the cost of maintenance for our drilling rigs, partially caused by costs relating to the deactivating of drilling rigs. Selling, general and administrative expense decreased primarily as a result of the transfer of 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.
 
                         
Pressure Pumping
  2007     2006     % Change  
    (Dollars in thousands)  
 
Revenues
  $ 51,592     $ 36,010       43.3 %
Direct operating costs
  $ 25,777     $ 17,935       43.7 %
Selling, general and administrative
  $ 4,808     $ 3,152       52.5 %
Depreciation
  $ 3,408     $ 2,330       46.3 %
Operating income
  $ 17,599     $ 12,593       39.8 %
Total jobs
    3,573       3,017       18.4 %
Average revenue per job
  $ 14.44     $ 11.94       20.9 %
Average direct operating costs per job
  $ 7.21     $ 5.94       21.4 %
Capital expenditures
  $ 14,206     $ 10,652       33.4 %
 
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 additional expenses to support the expanding operations of the pressure pumping segment. Significant capital expenditures


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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.
 
                         
Drilling and Completion Fluids
  2007     2006     % Change  
    (Dollars in thousands)  
 
Revenues
  $ 39,667     $ 59,877       (33.8 )%
Direct operating costs
  $ 32,628     $ 46,049       (29.1 )%
Selling, general and administrative
  $ 2,436     $ 2,592       (6.0 )%
Depreciation
  $ 697     $ 674       3.4 %
Operating income
  $ 3,906     $ 10,562       (63.0 )%
Total jobs
    434       532       (18.4 )%
Average revenue per job
  $ 91.40     $ 112.55       (18.8 )%
Average direct operating costs per job
  $ 75.18     $ 86.56       (13.1 )%
Capital expenditures
  $ 1,023     $ 979       4.5 %
 
Revenues and direct operating costs decreased primarily as a result of decreases in the average revenue and direct operating costs per job and in the number of total jobs. Average revenue and direct operating costs per job decreased primarily as a result of a decrease in the number of large jobs offshore in the Gulf of Mexico.
 
                         
Oil and Natural Gas Production and Exploration
  2007     2006     % Change  
    (Dollars in thousands, except sales prices)  
 
Revenues
  $ 12,108     $ 10,577       14.5 %
Direct operating costs
  $ 2,461     $ 5,364       (54.1 )%
Selling, general and administrative
  $ 674     $ 728       (7.4 )%
Depreciation, depletion and impairment
  $ 3,857     $ 4,013       (3.9 )%
Operating income
  $ 5,116     $ 472       983.9 %
Capital expenditures
  $ 4,619     $ 5,856       (21.1 )%
Average net daily oil production (Bbls)
    1,107       1,076       2.9 %
Average net daily gas production (Mcf)
    6,444       5,109       26.1 %
Average oil sales price (per Bbl)
  $ 63.04     $ 67.26       (6.3 )%
Average natural gas sales price (per Mcf)
  $ 7.84     $ 6.78       15.6 %
 
Revenues increased primarily due to an increase in the net daily production of natural gas and an increase in the average sales price of natural gas. Average net daily oil and natural gas production increased primarily due to the completion of wells subsequent to the second quarter of 2006, partially offset by production declines in existing wells and by the sale of certain properties in 2007. The decrease in direct operating costs is primarily due to a decrease of approximately $3.0 million in costs associated with the abandonment of exploratory wells. Depreciation, depletion and impairment expense in the second quarter of 2007 includes approximately $534,000 incurred to impair certain oil and natural gas properties compared to approximately $1.3 million incurred to impair certain oil and natural gas properties in the second quarter of 2006.
 
                         
Corporate and Other
  2007     2006     % Change  
    (Dollars in thousands)  
 
Selling, general and administrative
  $ 7,004     $ 4,635       51.1 %
Depreciation
  $ 203     $ 196       3.6 %
Other operating expenses
  $ 400     $ 786       (49.1 )%
(Gain) loss on disposal of assets
  $ (16,475 )   $ 870       N/A %
Embezzlement costs (recoveries)
  $ (41,935 )   $ 673       N/A %
Interest income
  $ 457     $ 2,280       (80.0 )%
Interest expense
  $ 831     $ 55       N/A %
Other income
  $ 109     $ 59       84.7 %
Capital expenditures
  $     $ 135       (100.0 )%


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Selling, general and administrative expense increased primarily as a result of compensation expense related to transfers of administrative staff to our corporate segment as well as increases in stock-based compensation expense and professional fees. In the second quarter of 2007 we sold certain oil and natural gas properties resulting in a gain of $20.3 million. This gain was reduced by approximately $3.8 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 the second quarter of 2007 includes an expected recovery of $42.5 million, reduced by approximately $600,000 in additional professional and other costs incurred as a result of the embezzlement. Embezzlement costs (recoveries) in the second quarter of 2006 include professional and other costs incurred as a result of the embezzlement. Interest income decreased due to the decrease in cash available to invest. During 2006, we repurchased $450 million of our common stock. Interest expense in 2007 increased primarily due to higher average borrowings that were outstanding under our line of credit during the second quarter of 2007.
 
The following tables summarize operations by business segment for the six months ended June 30, 2007 and 2006:
 
                         
Contract Drilling
  2007     2006     % Change  
    (Dollars in thousands)  
 
Revenues
  $ 886,689     $ 1,039,053       (14.7 )%
Direct operating costs
  $ 474,451     $ 469,676       1.0 %
Selling, general and administrative
  $ 2,851     $ 3,521       (19.0 )%
Depreciation
  $ 99,970     $ 78,803       26.9 %
Operating income
  $ 309,417     $ 487,053       (36.5 )%
Operating days
    44,569       53,810       (17.1 )%
Average revenue per operating day
  $ 19.89     $ 19.31       3.0 %
Average direct operating costs per operating day
  $ 10.65     $ 8.73       22.0 %
Average rigs operating
    246       297       (17.2 )%
Capital expenditures
  $ 283,189     $ 224,286       26.3 %
 
Revenues in the first six months of 2007 decreased as compared to the first six months of 2006 as a result of the decreased number of operating days in 2007, partially offset by an increase of approximately $580 in the average revenue per operating day. Although the number of operating days decreased in 2007, direct operating costs increased due to an increase in average direct operating costs per operating day of approximately $1,920. The increase in average direct operating costs per day primarily resulted from increased compensation costs and an increase in the cost of maintenance for our drilling rigs, partially caused by costs relating to the deactivating of drilling rigs. Selling, general and administrative expense decreased primarily as a result of the transfer of 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.
 
                         
Pressure Pumping
  2007     2006     % Change  
    (Dollars in thousands)  
 
Revenues
  $ 90,176     $ 67,338       33.9 %
Direct operating costs
  $ 46,928     $ 35,585       31.9 %
Selling, general and administrative
  $ 8,876     $ 6,138       44.6 %
Depreciation
  $ 6,532     $ 4,516       44.6 %
Operating income
  $ 27,840     $ 21,099       31.9 %
Total jobs
    6,412       5,728       11.9 %
Average revenue per job
  $ 14.06     $ 11.76       19.6 %
Average direct operating costs per job
  $ 7.32     $ 6.21       17.9 %
Capital expenditures
  $ 30,631     $ 19,679       55.7 %


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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 additional 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.
 
                         
Drilling and Completion Fluids
  2007     2006     % Change  
    (Dollars in thousands)  
 
Revenues
  $ 70,427     $ 109,058       (35.4 )%
Direct operating costs
  $ 58,019     $ 84,235       (31.1 )%
Selling, general and administrative
  $ 4,833     $ 5,032       (4.0 )%
Depreciation
  $ 1,393     $ 1,311       6.3 %
Operating income
  $ 6,182     $ 18,480       (66.5 )%
Total jobs
    869       1,019       (14.7 )%
Average revenue per job
  $ 81.04     $ 107.02       (24.3 )%
Average direct operating costs per job
  $ 66.77     $ 82.66       (19.2 )%
Capital expenditures
  $ 2,121     $ 1,930       9.9 %
 
Revenues and direct operating costs decreased primarily as a result of decreases in the average revenue and direct operating costs per job and in the number of total jobs. Average revenue and direct operating costs per job decreased primarily as a result of a decrease in the number of large jobs offshore in the Gulf of Mexico.
 
                         
Oil and Natural Gas Production and Exploration
  2007     2006     % Change  
    (Dollars in thousands, except sales prices)  
 
Revenues
  $ 22,367     $ 19,097       17.1 %
Direct operating costs
  $ 5,739     $ 8,019       (28.4 )%
Selling, general and administrative
  $ 1,322     $ 1,366       (3.2 )%
Depreciation, depletion and impairment
  $ 7,577     $ 6,011       26.1 %
Operating income
  $ 7,729     $ 3,701       108.8 %
Capital expenditures
  $ 9,651     $ 10,717       (9.9 )%
Average net daily oil production (Bbls)
    1,104       935       18.1 %
Average net daily gas production (Mcf)
    5,944       5,070       17.2 %
Average oil sales price (per Bbl)
  $ 59.69     $ 64.98       (8.1 )%
Average natural gas sales price (per Mcf)
  $ 7.53     $ 7.04       7.0 %
 
Revenues increased due to increases in the net daily production of oil and natural gas and an increase in the average sales price of natural gas which was partially offset by a reduction in the average sales price of oil. Average net daily oil and natural gas production increased primarily due to the completion of wells subsequent to the second quarter of 2006, partially offset by production declines in existing wells and by the sale of certain properties in 2007. Direct operating costs decreased due primarily to a decrease of approximately $2.3 million in costs associated with the abandonment of exploratory wells. Depreciation, depletion and impairment expense increased due to the increases in net daily production of oil and natural gas.
 


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Corporate and Other
  2007     2006     % Change  
    (Dollars in thousands)  
 
Selling, general and administrative
  $ 13,109     $ 9,594       36.6 %
Depreciation
  $ 406     $ 389       4.4 %
Other operating expenses
  $ 1,000     $ 1,385       (27.8 )%
Gain on disposal of assets
  $ (16,273 )   $       N/A %
Embezzlement costs (recoveries)
  $ (41,935 )   $ 4,453       N/A %
Interest income
  $ 826     $ 4,631       (82.2 )%
Interest expense
  $ 1,594     $ 113       N/A %
Other income
  $ 203     $ 143       42.0 %
Capital expenditures
  $     $ 135       (100.0 )%
 
Selling, general and administrative expense increased primarily as a result of compensation expense related to transfers of administrative staff to our corporate segment as well as increases in stock-based compensation expense and professional fees. In 2007 we sold certain oil and natural gas properties resulting in a gain of $20.3 million. This gain was reduced by approximately $4.1 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 $42.5 million reduced by approximately $600,000 in 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. 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 oil and natural gas, with respect to all of our operating segments. 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 per Mcf for the full year of 2006 compared to $8.98 per Mcf for the full year of 2005. This decrease resulted in our customers reducing their drilling activities beginning in the fourth quarter of 2006 and continuing into 2007. As a result of this decrease in drilling activities by our customers, our average rigs operating have declined to 237 in the second quarter of 2007 compared to 255 in the first quarter of 2007 and 290 in the fourth quarter of 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

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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.
 
We conduct some business in Canadian dollars through our Canadian land-based drilling operations. The exchange rate between Canadian dollars and U.S. dollars has fluctuated during the last several years. If the value of the Canadian dollar against the U.S. dollar weakens, revenues and earnings of our Canadian operations will be reduced and the value of our Canadian net assets will decline when they are translated to U.S. dollars. This currency rate risk is not material to our results of operations or financial condition.
 
ITEM 4.   Controls and Procedures
 
Disclosure Controls and Procedures — We maintain disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) designed to ensure that the information required to be disclosed in the reports that we file with the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosure.
 
Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 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.


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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;
 
  •  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.


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PART II — OTHER INFORMATION
 
ITEM 2.   Unregistered Sales of Equity Securities and Use of Proceeds
 
The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended June 30, 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(1)     Share     or Programs     thousands)(2)  
 
April 1-30, 2007
        $           $  
May 1-31, 2007
        $           $  
June 1-30, 2007
    16,018     $ 25.95           $  
                                 
Total
    16,018     $ 25.95           $  
                                 
 
 
(1) Represents shares purchased from employees on June 9, 2007 to provide the respective employees with the funds necessary to satisfy their tax withholding obligations with respect to the vesting of restricted shares on that date. The price paid per share represents the closing price of our common stock on June 8, 2007.
 
(2) 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 4.   Submission of Matters to a Vote of Security Holders
 
On June 7, 2007, the Company held its Annual Meeting of Stockholders. At the meeting, the stockholders voted on the following matters:
 
1. The election of seven persons to serve as directors of the Company.
 
2. Ratification of the appointment of PricewaterhouseCoopers LLP as the independent registered public accounting firm of the Company for the fiscal year ending December 31, 2007.
 
The seven nominees to the Board of Directors of the Company were elected at the meeting, and the other proposal received the affirmative vote required for approval. The voting results were as follows:
 
                 
1. Election of Directors   Votes For     Votes Withheld  
 
Mark S. Siegel
    130,898,755       3,158,393  
Cloyce A. Talbott
    131,379,433       2,677,715  
Kenneth N. Berns
    126,257,416       7,799,732  
Charles O. Buckner
    133,306,445       750,703  
Curtis W. Huff
    133,273,715       783,433  
Terry H. Hunt
    128,661,402       5,395,746  
Kenneth R. Peak
    133,141,175       915,973  
 
                                 
          Votes
          Broker
 
    Votes For     Against     Abstentions     Non-votes  
 
2. Ratification of PricewaterhouseCoopers LLP as the Company’s independent registered public accounting firm
    133,664,121       276,006       117,021       0  


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ITEM 5.   Other Information
 
On August 1, 2007, the Board of Directors approved and adopted the Second Amended and Restated Bylaws of the Company, which amended the Amended and Restated Bylaws of the Company to provide that the Company may, in accordance with the General Corporation Law of the State of Delaware, issue both certificated and uncertificated shares of its stock. The Board of Directors approved the amendments in connection with recent rules promulgated by the Nasdaq Stock Market. A copy of the Second Amended and Restated Bylaws is attached hereto as Exhibit 3.3.
 
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.
  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.


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SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
PATTERSON-UTI ENERGY, INC.
 
  By: 
/s/  Cloyce A. Talbott
Cloyce A. Talbott
(Principal Executive Officer)
President & Chief Executive Officer
 
  By: 
/s/  John E. Vollmer III
John E. Vollmer III
(Principal Financial and Accounting Officer)
Senior Vice President-Corporate Development,
Chief Financial Officer and Treasurer
 
DATED: August 6, 2007


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