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PATTERSON UTI ENERGY INC - Quarter Report: 2005 June (Form 10-Q)

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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, 2005
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___to ___
Commission file number 0-22664
PATTERSON-UTI ENERGY, INC.
(Exact name of registrant as specified in its charter)
     
DELAWARE   75-2504748
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer Identification No.)
4510 LAMESA HIGHWAY, SNYDER, TEXAS 79549
(Address of principal executive offices)       (Zip Code)
(325) 574-6300
(Registrant’s telephone number, including area code)
N/A
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ       No o
     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Yes þ       No o
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
171,706,441 shares of common stock, $0.01 par value, as of July 28, 2005
 
 

 


PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
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 Certification of CEO Pursuant to Rule 13a-14(a)15d-14(a)
 Certification of CFO Pursuant to Rule 13a-14(a)15d-14(a)
 Certification of CEO & CFO Pursuant to Section 906

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PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements
     The following unaudited condensed consolidated financial statements include all adjustments which, in the opinion of management, are necessary in order to make such financial statements not misleading.
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands, except share data)
                 
    June 30,     December 31,  
    2005     2004  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 70,077     $ 112,371  
Accounts receivable, net of allowance for doubtful accounts of $2,859 at June 30, 2005 and $1,909 at December 31, 2004
    298,802       214,097  
Inventory
    21,920       17,738  
Deferred tax assets, net
    17,919       15,991  
Other
    28,401       26,836  
 
           
Total current assets
    437,119       387,033  
Property and equipment, at cost, net
    973,938       828,875  
Goodwill
    101,326       101,326  
Other
    5,135       5,677  
 
           
Total assets
  $ 1,517,518     $ 1,322,911  
 
           
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable:
               
Trade
  $ 58,717     $ 54,553  
Accrued revenue distributions
    11,388       11,297  
Other
    3,816       2,309  
Accrued federal and state income taxes payable
    10,278       2,754  
Accrued expenses
    85,280       79,163  
 
           
Total current liabilities
    169,479       150,076  
Deferred tax liabilities, net
    169,809       162,040  
Other
    4,351       3,256  
 
           
Total liabilities
    343,639       315,372  
 
           
Commitments and contingencies
           
Stockholders’ equity:
               
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued
           
Common stock, par value $.01; authorized 300,000,000 shares with 174,734,503 and 171,625,841 issued and 171,621,407 and 168,512,745 outstanding at June 30, 2005 and December 31, 2004, respectively
    1,748       1,716  
Additional paid-in capital
    651,615       597,280  
Deferred compensation
    (12,095 )     (5,420 )
Retained earnings
    539,365       415,489  
Accumulated other comprehensive income
    6,383       11,611  
Treasury stock, at cost, 3,113,096 shares respectively
    (13,137 )     (13,137 )
 
           
Total stockholders’ equity
    1,173,879       1,007,539  
 
           
Total liabilities and stockholders’ equity
  $ 1,517,518     $ 1,322,911  
 
           
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share amounts)
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2005     2004     2005     2004  
Operating revenues:
                               
Contract drilling
  $ 329,503     $ 188,222     $ 624,892     $ 367,397  
Pressure pumping
    22,025       14,577       38,718       28,827  
Drilling and completion fluids
    29,587       23,424       58,993       41,563  
Oil and natural gas
    8,807       8,287       17,912       15,502  
 
                       
 
    389,922       234,510       740,515       453,289  
 
                       
Operating costs and expenses:
                               
Contract drilling
    180,185       134,387       355,651       262,378  
Pressure pumping
    12,622       8,328       22,986       16,416  
Drilling and completion fluids
    23,846       19,837       47,795       35,476  
Oil and natural gas
    2,418       2,768       4,588       4,336  
Depreciation, depletion and impairment
    36,959       30,451       71,359       57,734  
Selling, general and administrative
    9,925       7,910       19,604       14,708  
Bad debt expense
    143       217       366       307  
Other
    1,408       (187 )     1,498       (1,375 )
 
                       
 
    267,506       203,711       523,847       389,980  
 
                       
Operating income
    122,416       30,799       216,668       63,309  
 
                       
Other income (expense):
                               
Interest income
    634       204       1,067       455  
Interest expense
    (57 )     (54 )     (123 )     (130 )
Other
    16       172       20       257  
 
                       
 
    593       322       964       582  
 
                       
Income before income taxes
    123,009       31,121       217,632       63,891  
 
                       
Income tax expense (benefit):
                               
Current
    44,983       14,655       78,079       19,204  
Deferred
    361       (3,141 )     2,140       4,398  
 
                       
 
    45,344       11,514       80,219       23,602  
 
                       
Net income
  $ 77,665     $ 19,607     $ 137,413     $ 40,289  
 
                       
Net income per common share:
                               
Basic
  $ 0.46     $ 0.12     $ 0.81     $ 0.24  
 
                       
Diluted
  $ 0.45     $ 0.12     $ 0.80     $ 0.24  
 
                       
Weighted average number of common shares outstanding:
                               
Basic
    169,992       166,681       169,378       165,211  
 
                       
Diluted
    173,162       169,062       172,648       168,005  
 
                       
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY (Unaudited)

(in thousands)
                                                                 
    Common Stock                             Accumulated other              
                    Additional     Deferred     Retained     comprehensive              
    Number of shares     Amount     paid-in capital     compensation     earnings     income     Treasury stock     Total  
     
Balance,
December 31,
2004
  171,626     $ 1,716     $ 597,280     $ (5,420 )   $ 415,489     $ 11,611     $ (13,137 )   $ 1,007,539  
Issuance of restricted stock
    301       3       7,911       (7,914 )                        
Amortization of deferred compensation expense
                      1,108                         1,108  
Forfeitures of restricted shares
    (9 )           (131 )     131                          
Exercise of stock options
    2,816       29       29,285                               29,314  
Tax benefit related to exercise of stock options
                17,270                               17,270  
Foreign currency translation adjustment, net of tax of $3.7 million
                                  (5,228 )           (5,228 )
Payment of cash dividend
                            (13,537 )                 (13,537 )
Net income
                            137,413                   137,413  
 
                                               
Balance, June 30, 2005
    174,734     $ 1,748     $ 651,615     $ (12,095 )   $ 539,365     $ 6,383     $ (13,137 )   $ 1,173,879  
 
                                               
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS (Unaudited)

(in thousands)
                 
    Six Months Ended  
    June 30,  
    2005     2004  
Cash flows from operating activities:
               
Net income
  $ 137,413     $ 40,289  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, depletion and impairment
    71,359       57,734  
Provision for bad debts
    366       307  
Deferred income tax expense
    2,140       4,398  
Tax benefit related to exercise of stock options
    17,270       8,396  
Amortization of deferred compensation expense
    1,108       263  
Gain on sale of assets
    (1,053 )     (1,375 )
Changes in operating assets and liabilities, net of business acquired:
               
Accounts receivable
    (85,417 )     (21,969 )
Income taxes receivable
          16,953  
Inventory and other current assets
    (6,990 )     (2,206 )
Accounts payable
    4,481       5,260  
Income taxes payable
    7,533        
Accrued expenses
    5,056       (13,333 )
Other liabilities
    2,602       (4,033 )
 
           
Net cash provided by operating activities
    155,868       90,684  
 
           
Cash flows from investing activities:
               
Acquisitions, net of cash acquired
    (65,401 )     (32,514 )
Purchases of property and equipment
    (158,949 )     (89,723 )
Proceeds from sales of property and equipment
    8,839       1,986  
Restricted cash deposited to collateralize retained insurance losses
          (11,316 )
Change in other assets
    1,766        
 
           
Net cash used in investing activities
    (213,745 )     (131,567 )
 
           
Cash flows from financing activities:
               
Purchase of treasury stock
          (1,482 )
Dividends paid
    (13,537 )     (3,336 )
Proceeds from exercise of stock options
    29,314       8,698  
 
           
Net cash provided by financing activities
    15,777       3,880  
 
           
Effect of foreign exchange rate changes on cash
    (194 )     (127 )
 
           
Net decrease in cash and cash equivalents
    (42,294 )     (37,130 )
Cash and cash equivalents at beginning of period
    112,371       100,483  
 
           
Cash and cash equivalents at end of period
  $ 70,077     $ 63,353  
 
           
Supplemental disclosure of cash flow information:
               
Net cash received (paid) during the period for:
               
Interest expense
  $ (123 )   $ (130 )
Income taxes
  $ (48,585 )   $ 8,000  
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Consolidation and Presentation
     The interim condensed consolidated financial statements include the accounts of Patterson-UTI Energy, Inc. (the “Company”) and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.
     The interim condensed consolidated financial statements have been prepared by management of the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to such rules and regulations, although the Company believes the disclosures included herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments which are of a normal recurring nature considered necessary for presentation of the information have been included. The unaudited condensed consolidated balance sheet as of December 31, 2004, as presented herein, was derived from the audited balance sheet of the Company. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004.
     The U.S. dollar is the functional currency for all of the Company’s operations except for its Canadian operations, which use the Canadian dollar as their functional currency. The effects of exchange rate changes are reflected in accumulated other comprehensive income, which is a separate component of stockholders’ equity (see Note 4 of these Notes to Unaudited Condensed Consolidated Financial Statements).

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
1. Basis of Consolidation and Presentation — (continued)
     The Company provides a dual presentation of its earnings per share in its Unaudited Condensed Consolidated Statements of Income: Basic Earnings per Share (“Basic EPS”) and Diluted Earnings per Share (“Diluted EPS”). Basic EPS excludes dilution and is computed by dividing net income by the weighted average number of common shares outstanding. Diluted EPS is based on the weighted-average number of common shares outstanding and the assumed exercise of dilutive instruments, including stock options and warrants, less the number of treasury shares assumed to be purchased with the exercise proceeds. For the three and six months ended June 30, 2005 and 2004, all potentially dilutive options and warrants were included in the calculation of Diluted EPS. The following table presents information necessary to calculate earnings per share for the three and six months ended June 30, 2005 and 2004 as well as dividends per share paid for the three and six months ended June 30, 2005 (in thousands, except per share amounts).
                                 
    Three months ended     Six months ended  
    June 30,     June 30,  
    2005     2004     2005     2004  
Net income
  $ 77,665     $ 19,607     $ 137,413     $ 40,289  
Weighted average common shares outstanding
    169,992       166,681       169,378       165,211  
 
                       
Basic earnings per share
  $ 0.46     $ 0.12     $ 0.81     $ 0.24  
 
                       
Weighted average common shares outstanding
    169,992       166,681       169,378       165,211  
Assumed exercise of stock options
    3,170       2,381       3,270       2,794  
 
                       
Weighted average dilutive common shares outstanding
    173,162       169,062       172,648       168,005  
 
                       
Diluted earnings per share
  $ 0.45     $ 0.12     $ 0.80     $ 0.24  
 
                       
Cash dividends per share (a)
  $ 0.04     $ 0.02     $ 0.08     $ 0.02  
 
                       
 
     (a) During March 2005 and June 2005, cash dividends of $6.7 million and $6.8 million, respectively, were paid on outstanding shares of 168,679,334 and 169,741,460, respectively. During June 2004, a cash dividend of $3.3 million was paid on outstanding shares of 166,786,254.
     The results of operations for the three and six months ended June 30, 2005 are not necessarily indicative of the results to be expected for the full year.
     Certain reclassifications have been made to the 2004 consolidated financial statements in order for them to conform with the 2005 presentation.
2. Recent Acquisitions
     On January 15, 2005, the Company purchased land drilling assets from Key Energy Services, Inc. for $61.8 million. The assets included 25 active and 10 stacked land-based drilling rigs, related drilling equipment, yard facilities and a rig moving fleet consisting of approximately 45 trucks and 100 trailers. The transaction was accounted for as an acquisition of assets and the purchase price was allocated among the assets acquired based on their estimated fair market values.
     On June 17, 2005, the Company acquired one land-based drilling rig for $3.6 million. The transaction was accounted for as an acquisition of assets and the purchase price was allocated to the acquired drilling rig.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
3. Stock-based Compensation
     During June 2005, the Company’s shareholders approved the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 Plan”). In addition, the Board of Directors adopted a resolution that no future grants would be made under any of the previously existing equity plans of the Company. The Company accounts for activity under the 2005 Plan and previous activity of other equity plans using the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees (“APB 25”), and related interpretations. During the second quarters of 2004 and 2005, the Company granted restricted shares of the Company's common stock (the “Restricted Shares”) to certain key employees under the Patterson-UTI Energy, Inc 1997 Long-Term Incentive Plan, as amended, and the 2005 Plan. As required by APB 25, the Restricted Shares were valued based upon the market price of the Company’s common stock on the date of the grant. The resulting value is being amortized over the vesting period of the stock. For the three and six months ended June 30, 2005, compensation expense of $399,000 and $700,000, net of $56,000 and $131,000 of forfeitures and of $233,000 and $408,000 of taxes, respectively, was included as a reduction in net income. Compensation expense of $165,000, net of $97,000 of taxes, was included as a reduction in net income for the three and six months ended June 30, 2004. Other than the Restricted Shares discussed above, no additional stock-based employee compensation expense is reflected in net income, as all options granted under the plans discussed above had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and net income per share if the Company had applied the fair value recognition provisions of Financial Accounting Standards Board Statement No. 123, Accounting for Stock-Based Compensation (“SFAS 123”), to stock-based employee compensation (in thousands, except per share amounts):
                                 
    Three months ended     Six months ended  
    June 30,     June 30,  
    2005     2004     2005     2004  
Net income, as reported
  $ 77,665     $ 19,607     $ 137,413     $ 40,289  
Add: Stock-based employee compensation expense recorded, net of forfeitures and taxes
    399       165       700       165  
Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects
    (2,811 )     (3,187 )     (5,358 )     (6,161 )
 
                       
Pro-forma net income
  $ 75,253     $ 16,585     $ 132,755     $ 34,293  
 
                       
Net income per common share:
                               
Basic, as reported
  $ 0.46     $ 0.12     $ 0.81     $ 0.24  
 
                       
Basic, pro-forma
  $ 0.44     $ 0.10     $ 0.78     $ 0.21  
 
                       
Diluted, as reported
  $ 0.45     $ 0.12     $ 0.80     $ 0.24  
 
                       
Diluted, pro-forma
  $ 0.44     $ 0.10     $ 0.77     $ 0.20  
 
                       

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
4. Comprehensive Income (Expense)
     The following table illustrates the Company’s comprehensive income (expense) including the effects of foreign currency translation adjustments for the three and six months ended June 30, 2005 and 2004 (in thousands):
                                 
    Three months ended     Six months ended  
    June 30,     June 30,  
    2005     2004     2005     2004  
Net income
  $ 77,665     $ 19,607     $ 137,413     $ 40,289  
Other comprehensive income (expense):
                               
Foreign currency translation adjustment related to our Canadian operations
    (631 )     (1,424 )     (1,162 )     (1,891 )
Cumulative tax effect (1)
    (4,066 )           (4,066 )      
 
                       
Comprehensive income, net of tax
  $ 72,968     $ 18,183     $ 132,185     $ 38,398  
 
                       
    (1) Amount represents the cumulative impact of deferred taxes on foreign currency translation adjustments for the Canadian operations.
5. Property and Equipment
     Property and equipment consisted of the following at June 30, 2005 and December 31, 2004 (in thousands):
                 
    June 30,     December 31,  
    2005     2004  
Drilling rigs and related equipment
  $ 1,389,535     $ 1,217,497  
Other equipment
    102,697       83,683  
Oil and natural gas properties
    77,869       82,711  
Buildings
    15,404       13,008  
Land
    5,573       3,949  
 
           
 
    1,591,078       1,400,848  
Less accumulated depreciation and depletion
    (617,140 )     (571,973 )
 
           
 
  $ 973,938     $ 828,875  
 
           

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
6. Business Segments
     Our revenues, operating profits and identifiable assets are primarily attributable to four business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services, (iii) drilling and completion fluid services to operators in the oil and natural gas industry, and (iv) the exploration, development, acquisition and production of oil and natural gas. Each of these segments represents a distinct type of business based upon the type and nature of services and products offered. These segments have separate management teams which report to the Company’s chief executive officer and have distinct and 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,  
    2005     2004     2005     2004  
Revenues:
                               
Contract drilling (a)
  $ 330,027     $ 189,691     $ 626,604     $ 370,016  
Pressure pumping
    22,025       14,577       38,718       28,827  
Drilling and completion fluids (b)
    29,726       23,507       59,152       41,671  
Oil and natural gas
    8,807       8,287       17,912       15,502  
 
                       
Total segment revenues
    390,585       236,062       742,386       456,016  
Elimination of intercompany revenues (a)(b)
    663       1,552       1,871       2,727  
 
                       
Total revenues
  $ 389,922     $ 234,510     $ 740,515     $ 453,289  
 
                       
Income before income taxes:
                               
Contract drilling
  $ 116,333     $ 28,507     $ 206,035     $ 55,595  
Pressure pumping
    5,533       3,364       8,088       6,588  
Drilling and completion fluids
    2,793       1,166       5,495       1,388  
Oil and natural gas
    3,106       767       6,434       3,543  
 
                       
 
    127,765       33,804       226,052       67,114  
Corporate and other
    (5,349 )     (3,005 )     (9,384 )     (3,805 )
Interest income
    634       204       1,067       455  
Interest expense
    (57 )     (54 )     (123 )     (130 )
Other
    16       172       20       257  
 
                       
Income before income taxes
  $ 123,009     $ 31,121     $ 217,632     $ 63,891  
 
                       
                 
    June 30,     December 31,  
    2005     2004  
Identifiable assets:
               
Contract drilling
  $ 1,258,738     $ 1,044,147  
Pressure pumping
    72,580       62,866  
Drilling and completion fluids
    41,738       38,196  
Oil and natural gas
    72,172       66,734  
 
           
 
    1,445,228       1,211,943  
Corporate and other (c)
    72,290       110,968  
 
           
Total assets
  $ 1,517,518     $ 1,322,911  
 
           
(a)   Includes contract drilling intercompany revenues of approximately $524,000 and $1.5 million for the three months ended June 30, 2005 and 2004, respectively, and approximately $1.7 million and $2.6 million for the six months ended June 30, 2005 and 2004, respectively.
 
(b)   Includes drilling and completion fluids intercompany revenues of approximately $139,000 and $83,000 for the three months ended June 30, 2005 and 2004, respectively, and approximately $159,000 and $108,000 for the six months ended June 30, 2005 and 2004, respectively.
 
(c)   Corporate assets primarily include cash on hand managed by the parent corporation and certain deferred federal income tax assets.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
7. Recently Issued Accounting Standards
     The Financial Accounting Standards Board (“FASB”) issued Staff Position Financial Accounting Standard 19-1, Accounting for Suspended Well Costs (“FAS19-1”), in April 2005. FAS 19-1 provides guidance on accounting for exploratory well costs for entities that use the successful efforts method of accounting as described in Statement of Financial Accounting Standard No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, (“SFAS 19”). Exploration activities are frequently performed in more remote areas, to greater depths, and in more complex geological formations than the exploration activities that occurred when SFAS 19 was issued in 1977. These changes in exploration activities have resulted in an increased frequency of exploratory wells that successfully find reserves that cannot be recognized as proved when drilling is completed and a lengthened evaluation period for determining whether the reserves qualify as proved. The FASB staff believes that exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project and SFAS 19 is amended to clarify this position. The Company intends to adopt these accounting and disclosure requirements prospectively to existing and newly capitalized exploratory well costs in the third quarter of 2005 and does not expect a significant impact on financial position or results of operations.
     The FASB issued Staff Position FIN46(R)-5, Implicit Variable Interests Under FASB Interpretation No. 46 (revised December 2003), in March 2005. It addresses whether a reporting enterprise should consider whether it holds an implicit variable interest in a variable interest entity (“VIE”) or potential VIE when specific conditions exist. The Company does not expect any impact on its financial position or results of operations as a result of its adoption of FIN 46(R)-5 in the second quarter of 2005.
     The FASB issued Staff Position FIN 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143, in March 2005. The Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. The statement clarifies the term “conditional asset retirement obligation” as used in FASB 143. The Company believes that it is already in compliance with the statement and does not expect any impact on financial position or results of operations when adopted.
     The FASB issued Statement of Financial Accounting Standard No. 123 (revised 2004), Share-Based Payment (“SFAS 123(R)”), in December 2004; it replaces SFAS 123, and supersedes APB 25. Under SFAS 123(R), companies would have been required to implement the standard as of the beginning of the first interim reporting period that begins after June 15, 2005. However, in April 2005, the SEC announced the adoption of an Amendment to Rule 4-01(a) of Regulation S-X regarding the compliance date for SFAS 123(R) that amends the compliance dates and allows companies to implement SFAS 123(R) beginning with the first annual reporting period beginning on or after June 15, 2005. The Company intends to adopt SFAS 123(R) in its fiscal year beginning January 1, 2006.
     The Company currently uses the intrinsic value method to value stock options, and accordingly, no compensation expense has been recognized for stock options since the Company grants stock options with exercise prices equal to the Company’s common stock market price on the date of the grant. SFAS 123(R) requires the expensing of all stock-based compensation, including stock options and restricted shares, using the fair value method. The Company intends to expense stock options using the Modified Prospective Transition method as described in SFAS 123(R). This method will require expense to be recognized for stock options over their respective remaining vesting periods. No expense will be recognized for stock options vested in periods prior to the adoption of SFAS 123(R). The Company is evaluating the impact of its adoption of SFAS 123(R) on its results of operations and financial position. Adoption is not expected to have a material effect on the Company’s financial position or results of operations.
     The FASB issued Statement of Financial Accounting Standard No. 151, Inventory Costs — an amendment of ARB No. 43, Chapter 4 (“SFAS 151”). SFAS 151 is effective, and will be adopted, for inventory costs incurred

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
7. Recently Issued Accounting Standards — (continued)
during fiscal years beginning after June 15, 2005 and is to be applied prospectively. SFAS 151 amends the guidance in ARB No. 43, Chapter 4, Inventory Pricing, to require current period recognition of abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Adoption is not expected to have a material effect on the Company’s financial position or results of operations.
     The FASB issued Statement of Financial Accounting Standard No. 153, Exchanges of Nonmonetary Assets — an amendment of APB Opinion No. 29 (“SFAS 153”). SFAS 153 is effective, and will be adopted, for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005 and is to be applied prospectively. SFAS 153 eliminates the exception for fair value treatment of nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Adoption is not expected to have a material effect on the Company’s financial position or results of operations.
     The FASB issued Statement of Financial Accounting Standards No. 154, Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3 (“SFAS 154”). SFAS 154 is effective, and will be adopted, for accounting changes made in fiscal years beginning after December 15, 2005 and is to be applied retrospectively. SFAS 154 requires that retroactive application of a change in accounting principle be limited to the direct effects of the change. Adoption is not expected to have a material effect on the Company’s financial position or results of operations.
8. Goodwill
     Goodwill is evaluated to determine if the fair value of an asset has decreased below its carrying value. At December 31, 2004 the Company performed its annual goodwill evaluation and determined no adjustment to impair goodwill was necessary. Goodwill as of June 30, 2005 and December 31, 2004 are as follows (in thousands):
                 
    June 30,     December 31,  
    2005     2004  
Drilling:
               
Goodwill at beginning of year
  $ 91,362     $ 41,215  
Changes to goodwill
          50,147  
 
           
Goodwill at end of period
    91,362       91,362  
 
           
Drilling and completion fluids:
               
Goodwill at beginning of year
  $ 9,964     $ 9,964  
Changes to goodwill
           
 
           
Goodwill at end of period
    9,964       9,964  
 
           
Total goodwill
  $ 101,326     $ 101,326  
 
           

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
9. Accrued Expenses
     Accrued expenses consisted of the following at June 30, 2005 and December 31, 2004 (in thousands):
                 
    June 30,     December 31,  
    2005     2004  
Salaries, wages, payroll taxes and benefits.
  $ 23,865     $ 21,245  
Workers’ compensation liability
    38,099       38,677  
Sales, use and other taxes
    6,258       5,863  
Insurance, other than workers’ compensation.
    9,817       7,061  
Other
    7,241       6,317  
 
           
 
  $ 85,280     $ 79,163  
 
           
10. Asset Retirement Obligation
     Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS No. 143”), requires that the Company record a liability for the estimated costs to be incurred in connection with the abandonment of oil and natural gas properties in the future. The following table describes the changes to our asset retirement obligations during the six months ended June 30, 2005 and 2004 (in thousands):
                 
    2005     2004  
Balance at beginning of year
  $ 2,358     $ 1,163  
Liabilities incurred*
    19       1,113  
Liabilities settled
    (511 )     (70 )
Accretion expense
    37       15  
 
           
Asset retirement obligation at end of period.
  $ 1,903     $ 2,221  
 
           
 
     * The 2004 amount includes $1,091 of liabilities assumed in the acquisition of TMBR/Sharp Drilling, Inc. (“TMBR”).
11. Commitments, Contingencies and Other Matters
     The Company maintains letters of credit in the aggregate amount of approximately $56 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire at various times during each calendar year. No amounts have been drawn under the letters of credit.
     We are also party to various legal proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our financial condition.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
12. Stockholders’ Equity
     On February 16, 2005 and April 27, 2005, the Company’s Board of Directors approved cash dividends on its common stock in the amount of $0.04 per share. The dividends of approximately $6.7 million and $6.8 million were paid on March 4, 2005 and June 1, 2005, respectively. The amount and timing of all future dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of the Company’s credit facilities and other factors.
     During the second quarters of 2004 and 2005, the Company granted restricted shares of the Company's common stock to certain key employees under the Patterson-UTI Energy, Inc 1997 Long-Term Incentive Plan, as amended, and the 2005 Plan. As required by APB Opinion No. 25, the Restricted Shares were valued based upon the market price of the Company’s common stock on the date of the grant. The resulting value is being amortized over the vesting period of the stock. For the three and six months ended June 30, 2005, compensation expense of $399,000 and $700,000, net of $56,000 and $131,000 of forfeitures and of $233,000 and $408,000 of taxes, respectively, was included as a reduction in net income. Compensation expense of $165,000, net of $97,000 taxes, was included as a reduction in net income for the three and six months ended June 30, 2004.
13. Subsequent Event
     On July 27, 2005, the Company’s Board of Directors approved a quarterly cash dividend of $0.04 on each outstanding share of its common stock. The dividend is to be paid on September 1, 2005 to holders of record as of August 16, 2005.

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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, 2005 and 2004, our operating revenues consisted of the following (dollars in thousands):
                                                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2005     2004     2005     2004  
Contract drilling
  $ 329,503       84 %   $ 188,222       80 %   $ 624,892       84 %   $ 367,397       81 %
Pressure pumping
    22,025       6       14,577       6       38,718       5       28,827       6  
Drilling and completion fluids
    29,587       8       23,424       10       58,993       8       41,563       9  
Oil and natural gas.
    8,807       2       8,287       4       17,912       3       15,502       4  
 
                                               
 
  $ 389,922       100 %   $ 234,510       100 %   $ 740,515       100 %   $ 453,289       100 %
 
                                               
     We provide our contract services to oil and natural gas operators in many of the oil and natural gas producing regions of North America. Our contract drilling operations are focused in various regions of Texas, New Mexico, Oklahoma, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota and Western Canada, while our pressure pumping services are focused primarily in the Appalachian Basin. Our drilling and completion fluids services are provided to operators in Texas, Southeastern New Mexico, Oklahoma, the Gulf Coast region of Louisiana and the Gulf of Mexico. Our oil and natural gas operations are primarily focused in West and South Texas, Southeastern New Mexico, Utah and Mississippi.
     We have been a leading consolidator of the land-based contract drilling industry over the past several years, increasing our drilling fleet to 397 rigs as of June 30, 2005. Based on publicly available information, we believe we are the second largest owner of land-based drilling rigs in North America. Growth by acquisition has been a corporate strategy intended to expand both revenues and profits.
     The profitability of our business is most readily assessed by two primary indicators: our average number of rigs operating and our average revenue per operating day. During the second quarter of 2005, our average number of rigs operating increased to 265 from 263 in the first quarter of 2005 and 203 in the second quarter of 2004. Our average revenue per operating day increased to $13,690 in the second quarter of 2005 from $12,490 in the first quarter of 2005 and $10,190 in the second quarter of 2004. Primarily due to these improvements, we experienced an increase of approximately $58 million, or 296%, in consolidated net income for the second quarter of 2005 as compared to the second quarter of 2004.
     Our revenues, profitability and cash flows are highly dependent upon the market prices of oil and natural gas. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which results in increased demand for our contract services. Conversely, in periods of time when these commodity prices deteriorate, the demand for our contract services generally weakens and we experience downward pressure on pricing for our services. In addition, our operations are highly impacted by competition, the availability of excess equipment, labor issues and various other factors which are more fully described as risk factors in our “Forward Looking Statements and Cautionary Statements for Purposes of the ‘Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995” included in our Annual Report on Form 10-K for the year ended December 31, 2004, beginning on page 14.
     Management believes that the liquidity of our balance sheet as of June 30, 2005, which includes approximately $268 million in working capital (including $70 million in cash), no long-term debt and $144 million available under a $200 million line of credit (availability of $56 million is reserved for outstanding letters of credit), provides us with the ability to pursue acquisition opportunities, expand into new regions, make improvements to our assets and survive downturns in our industry.

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     Commitments and Contingencies — The Company has no commitments or contingencies which require disclosure in its financial statements other than letters of credit of approximately $56 million at June 30, 2005, maintained for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which may become payable under the terms of the underlying insurance contracts. No amounts have been drawn under the letters of credit.
     Trading and Investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits, money markets, and highly rated municipal and commercial bonds.
     Description of Business — We conduct our contract drilling operations in Texas, New Mexico, Oklahoma, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota and Western Canada. As of June 30, 2005, we owned 397 drilling rigs. We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. These services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. We provide drilling fluids, completion fluids and related services to oil and natural gas operators in Texas, Southeastern New Mexico, Oklahoma, the Gulf Coast region of Louisiana and the Gulf of Mexico. Drilling and completion fluids are used by oil and natural gas operators during the drilling process to control pressure when drilling oil and natural gas wells. We are also engaged in the development, exploration, acquisition and production of oil and natural gas. Our oil and natural gas operations are focused primarily in producing regions in West and South Texas, Southeastern New Mexico, Utah and Mississippi.
     The North American land drilling industry has experienced periods of downturn in demand over the last decade. During these periods, there have been substantially more drilling rigs available than necessary to meet demand. As a result, drilling contractors have had difficulty sustaining profit margins during the downturn periods.
     In addition to adverse effects that future declines in demand could have on us, ongoing factors which could adversely affect utilization rates and pricing, even in an environment of stronger oil and natural gas prices and increased drilling activity, include:
    movement of drilling rigs from region to region,
 
    reactivation of land-based drilling rigs, or
 
    new construction of drilling rigs.
     We cannot predict either the future level of demand for our contract drilling services or future conditions in the oil and natural gas contract drilling business.
Critical Accounting Policies
     In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. The following is a discussion of our critical accounting policies pertaining to property and equipment, oil and natural gas properties, goodwill, revenue recognition, and the use of estimates.
     Property and equipment ¾ Property and equipment, including betterments which extend the useful life of the asset, are stated at cost. Maintenance and repairs are charged to expense when incurred. We provide for the depreciation of our property and equipment using the straight-line method over their estimated useful lives. Our method of depreciation does not change when equipment becomes idle; we continue to depreciate idled equipment on a straight-line basis. No provision for salvage value is considered in determining depreciation of our property and equipment. We review our assets for impairment when events or changes in circumstances indicate that the carrying values of certain assets either exceed their respective fair values or may not be recovered over their estimated remaining useful lives. The cyclical nature of our industry has resulted in fluctuations in rig utilization over periods of time. Management believes that the contract drilling industry will continue to be cyclical and rig utilization will fluctuate. Based on management’s expectations of future trends we estimate future cash flows in our assessment of impairment assuming the following four-year industry cycle: one year projected with low utilization, one year

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projected as a recovery period with improving utilization and the remaining two years projecting higher utilization. Provisions for asset impairment are charged to income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book value. Impairment charges are recorded based on discounted cash flows. Other than to our oil and natural gas properties, there were no impairment charges to property and equipment during the six months ended June 30, 2005 or 2004.
     Oil and natural gas properties ¾ Oil and natural gas properties are accounted for using the successful efforts method of accounting. Under the successful efforts method of accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are charged to expense when such determination is made. In accordance with SFAS 19, costs of exploratory wells are initially capitalized to wells in progress until the outcome of the drilling is known. We review wells in progress quarterly to determine the related reserve classification. If the reserve classification is uncertain after one year following the completion of drilling, we consider the costs of the well to be impaired and recognize the costs as expense. Geological and geophysical costs, including seismic costs and costs to carry and retain undeveloped properties, are charged to expense when incurred. The capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment, lease acquisition costs, and intangible development costs, are depreciated, depleted, and amortized on the units-of-production method, based on petroleum engineer estimates of proved oil and natural gas reserves of each respective field. We review our proved oil and natural gas properties for impairment when an event occurs such as downward revisions in reserve estimates or decreases in oil and natural gas prices. Proved properties are grouped by field and undiscounted cash flow estimates are provided by our reserve engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between its net book value and discounted cash flow. Unproved oil and natural gas properties are reviewed quarterly to determine impairment. Our intent to drill, lease expiration, and abandonment of area are considered. Assessment of impairment is made on a lease-by-lease basis. If an unproved property is determined to be impaired, then costs related to that property are expensed. Impairment expense of approximately $216,000 and $818,000 for the three and six months ended June 30, 2005, respectively, and $1.7 million and $2.2 million for the three and six months ended June 30, 2004, respectively, is included in depreciation, depletion and impairment in the accompanying financial statements.
     Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. As such, we assess impairment of our goodwill annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value.
     Revenue recognition ¾ Revenues are recognized when services are performed, except for revenues earned under turnkey contract drilling arrangements which are recognized using the completed contract method of accounting, as described below. We follow the percentage-of-completion method of accounting for footage contract drilling arrangements. Under the percentage-of-completion method, management estimates are relied upon in the determination of the total estimated expenses to be incurred drilling the well. Due to the nature of turnkey contract drilling arrangements and risks therein, we follow the completed contract method of accounting for such arrangements. Under this method, all drilling revenues and expenses related to a well in progress are deferred and recognized in the period the well is completed. Provisions for losses on incomplete or in-process wells are made when estimated total expenses are expected to exceed estimated total revenues.
     In accordance with Emerging Issues Task Force Issue No. 00-14, we recognize reimbursements due from third parties for out-of-pocket expenses incurred as revenues and account for out-of-pocket expenses as direct costs.
     Use of estimates ¾ The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates.

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     Key estimates used by management include:
    allowance for doubtful accounts,
 
    total expenses to be incurred on footage and turnkey drilling contracts,
 
    depreciation, depletion, and amortization,
 
    asset impairment,
 
    reserves for self-insured levels of insurance coverages, and
 
    fair values of assets and liabilities assumed in acquisitions.
Liquidity and Capital Resources
     As of June 30, 2005, we had working capital of approximately $267.6 million, including cash and cash equivalents of $70.1 million. For the six months ended June 30, 2005, our significant sources of cash flow included:
    $155.9 million provided by operations,
 
    $29.3 million from the exercise of stock options, and
 
    $8.8 million in proceeds from sales of property and equipment.
     We used $65.4 million to purchase land drilling assets from Key Energy Services, Inc. and one additional land-based drilling rig, $13.5 million to pay dividends on the Company’s common stock and $158.9 million:
    to make capital expenditures for the betterment and refurbishment of our drilling rigs,
 
    to acquire and procure drilling equipment,
 
    to fund capital expenditures for our pressure pumping and drilling and completion fluids divisions, and
 
    to fund leasehold acquisition and exploration and development of oil and natural gas properties.
     In January 2005, the Company purchased land drilling assets of Key Energy Services, Inc. for $61.8 million. The assets acquired included 25 active and 10 stacked land-based drilling rigs, related drilling equipment, yard facilities and a rig moving fleet consisting of approximately 45 trucks and 100 trailers. In June 2005, the Company acquired one land-based drilling rig for $3.6 million. The transactions were accounted for as acquisitions of assets and the respective purchase price was allocated among the assets acquired based on their estimated fair market values.
     On February 16, 2005 and April 27, 2005, the Company’s Board of Directors approved cash dividends on its common stock in the amount of $0.04 per share. The dividends of approximately $6.7 million and $6.8 million were paid on March 4, 2005 and June 1, 2005, respectively.
     On July 27, 2005, the Company’s Board of Directors approved a quarterly cash dividend of $0.04 on each outstanding share of its common stock to be paid on September 1, 2005 to holders of record as of August 16, 2005. The amount and timing of all future dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of the Company’s credit facilities and other factors.
     We believe that the current level of cash and short-term investments, together with cash generated from operations, should be sufficient to meet our capital needs. From time to time, acquisition opportunities are evaluated. The timing, size or success of any acquisition and the associated capital commitments are unpredictable. Should opportunities for growth requiring capital arise, we believe we would be able to satisfy these needs through a combination of working capital, cash generated from operations, our existing credit facility and additional debt or equity financing. However, there can be no assurance that such capital would be available.

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Results of Operations
     The following tables summarize operations by business segment for the three months ended June 30, 2005 and 2004:
                         
Contract Drilling   2005     2004     % Change  
    (dollars in thousands)        
Revenues
  $ 329,503     $ 188,222       75.1 %
Direct operating costs
  $ 180,185     $ 134,387       34.1 %
Selling, general and administrative
  $ 1,205     $ 1,080       11.6 %
Depreciation
  $ 31,780     $ 24,248       31.1 %
Operating income
  $ 116,333     $ 28,507       308.1 %
Operating days
    24,074       18,473       30.3 %
Average revenue per operating day
  $ 13.69     $ 10.19       34.3 %
Average direct operating costs per operating day
  $ 7.48     $ 7.27       2.9 %
Number of owned rigs at end of period
    397       361       10.0 %
Average number of rigs owned during period
    396       361       9.7 %
Average rigs operating
    265       203       30.5 %
Rig utilization percentage
    67 %     56 %     19.6 %
Capital expenditures
  $ 69,793     $ 42,980       62.4 %
     Revenues and direct operating costs increased as a result of the increased number of operating days, as well as an increase in the average revenue and average direct operating costs per operating day. Operating days and average rigs operating increased as a result of increased demand for our contract drilling services and the acquisition of land drilling assets from Key Energy Services, Inc. in January 2005. Average revenue per operating day increased as a result of increased demand and pricing for our drilling services. Significant capital expenditures were incurred during the second quarter of 2005 to activate additional drilling rigs to meet increased demand, to modify and upgrade our existing drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Increased depreciation expense was due to the acquisition described above and capital expenditures in 2004 and 2005.
                         
Pressure Pumping   2005     2004     % Change  
    (dollars in thousands)        
Revenues
  $ 22,025     $ 14,577       51.1 %
Direct operating costs
  $ 12,622     $ 8,328       51.6 %
Selling, general and administrative
  $ 2,192     $ 1,664       31.7 %
Depreciation
  $ 1,678     $ 1,221       37.4 %
Operating income
  $ 5,533     $ 3,364       64.5 %
Total jobs
    2,345       1,578       48.6 %
Average revenue per job
  $ 9.39     $ 9.24       1.6 %
Average direct operating costs per job
  $ 5.38     $ 5.28       1.9 %
Capital expenditures
  $ 7,075     $ 4,782       48.0 %
     Revenues and direct operating costs for our pressure pumping operations increased primarily as a result of the increased number of jobs. The increase in jobs was largely attributable to increased demand for our services and increased operating capacity which was added in 2004 and the first six months of 2005. Selling, general and administrative expenses increased largely as a result of the expanding operations of the pressure pumping segment. Increased depreciation expense for the 2005 quarter was largely due to the expansion of the pressure pumping segment through capital expenditures during 2004 and 2005. Significant capital expenditures were incurred during the second quarter of 2005 to modify and upgrade existing equipment and to add additional equipment to the segment’s expanded operations to meet increased demand.

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Drilling and Completion Fluids   2005     2004     % Change  
    (dollars in thousands)        
Revenues
  $ 29,587     $ 23,424       26.3 %
Direct operating costs
  $ 23,846     $ 19,837       20.2 %
Selling, general and administrative
  $ 2,367     $ 1,875       26.2 %
Depreciation
  $ 581     $ 546       6.4 %
Operating income
  $ 2,793     $ 1,166       139.5 %
Total jobs
    503       593       (15.2 )%
Average revenue per job
  $ 58.82     $ 39.50       48.9 %
Average direct operating costs per job
  $ 47.41     $ 33.45       41.7 %
Capital expenditures
  $ 766     $ 416       84.1 %
     Revenues and direct operating costs increased during the second quarter of 2005 compared to the second quarter of 2004 as a result of an increase in the average revenue and direct operating costs per job. Average revenue and direct operating costs per job increased primarily as a result of an increase in the number of larger jobs in the Gulf of Mexico and a decrease in the number of smaller land-based jobs during the second quarter of 2005. Selling, general and administrative expense increased in 2005 primarily due to increased incentive compensation resulting from higher profitability levels.
                         
Oil and Natural Gas Production and Exploration   2005     2004     % Change  
    (dollars in thousands, except sales prices)        
Revenues
  $ 8,807     $ 8,287       6.3 %
Direct operating costs
  $ 2,418     $ 2,768       (12.6 )%
Selling, general and administrative
  $ 552     $ 427       29.3 %
Depreciation, depletion and impairment
  $ 2,731     $ 4,325       (36.9 )%
Operating income
  $ 3,106     $ 767       305.0 %
Capital expenditures
  $ 3,407     $ 3,600       (5.4 )%
Average net daily oil production (Bbls)
    795       1,171       (32.1 )%
Average net daily gas production (Mcf)
    7,253       7,335       (1.1 )%
Average oil sales price (per Bbl)
  $ 51.52     $ 37.94       35.8 %
Average gas sales price (per Mcf)
  $ 6.44     $ 5.31       21.3 %
     Revenues increased in the second quarter of 2005 compared to the second quarter of 2004, due to increased market prices received for oil and natural gas. Average net daily oil production decreased as a result of production declines and the sale of certain oil and gas properties during the second quarter of 2005. Depreciation, depletion and impairment expense includes approximately $216,000 and $1.7 million of expenses incurred during the three months ended June 30, 2005 and 2004, respectively, to impair certain oil and natural gas properties.
                         
Corporate and Other   2005     2004     % Change  
    (in thousands)        
Selling, general and administrative
  $ 3,609     $ 2,864       26.0 %
Bad debt expense
  $ 143     $ 217       (34.1 )%
Depreciation
  $ 189     $ 111       70.3 %
Other (income) expense from operations
  $ 1,408     $ (187 )     N/A %
Interest income
  $ 634     $ 204       210.8 %
Interest expense
  $ 57     $ 54       5.6 %
Other income
  $ 16     $ 172       (90.7 )%
Capital expenditures
  $ 108     $       N/A %
     Selling, general and administrative expenses increased primarily as a result of payroll taxes attributable to the exercise of employee stock options, increased professional fees, and additional compensation expense related to the issuance of restricted shares to certain key employees in the second quarters of 2004 and 2005. Other (income) expense from operations in 2005 includes a charge of $2.6 million to increase reserves related to the financial failure of a workers’ compensation insurance carrier used previously by the Company and this charge is partially offset by a gain recognized on the sale of certain oil and natural gas properties.

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The following tables summarize operations by business segment for the six months ended June 30, 2005 and 2004:
                         
Contract Drilling   2005     2004     % Change  
    (dollars in thousands)        
Revenues
  $ 624,892     $ 367,397       70.1 %
Direct operating costs
  $ 355,651     $ 262,378       35.5 %
Selling, general and administrative
  $ 2,427     $ 2,175       11.6 %
Depreciation and amortization
  $ 60,779     $ 47,249       28.6 %
Operating income
  $ 206,035     $ 55,595       270.6 %
Operating days
    47,731       36,437       31.0 %
Average revenue per operating day
  $ 13.09     $ 10.08       29.9 %
Average direct operating costs per operating day
  $ 7.45     $ 7.20       3.5 %
Number of owned rigs at end of period
    397       361       10.0 %
Average number of rigs owned during period
    393       357       10.1 %
Average rigs operating
    264       200       32.0 %
Rig utilization percentage
    67 %     56 %     19.6 %
Capital expenditures
  $ 129,128     $ 71,360       81.0 %
     Revenues and direct operating costs increased as a result of the increased number of operating days, as well as an increase in the average revenue and average direct operating costs per operating day. Operating days and average rigs operating increased as a result of the increased demand for our contract drilling services, the acquisition of land drilling assets from Key Energy Services, Inc. in January 2005, and the acquisition of TMBR in February 2004. Average revenue per operating day increased as a result of increased demand and pricing for our drilling services. Significant capital expenditures were incurred during the first six months of 2005 to activate additional drilling rigs to meet increased demand, to modify and upgrade our existing drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Increased depreciation expense was due to the acquisitions described above and capital expenditures in 2004 and 2005.
                         
Pressure Pumping   2005     2004     % Change  
    (dollars in thousands)        
Revenues
  $ 38,718     $ 28,827       34.3 %
Direct operating costs
  $ 22,986     $ 16,416       40.0 %
Selling, general and administrative
  $ 4,394     $ 3,457       27.1 %
Depreciation
  $ 3,250     $ 2,366       37.4 %
Operating income
  $ 8,088     $ 6,588       22.8 %
Total jobs
    4,254       3,266       30.3 %
Average revenue per job
  $ 9.10     $ 8.83       3.1 %
Average direct operating costs per job
  $ 5.40     $ 5.03       7.4 %
Capital expenditures
  $ 14,733     $ 10,604       38.9 %
     Revenues and direct operating costs for our pressure pumping operations primarily increased as a result of the increased number of jobs. The increase in jobs was largely attributable to increased demand for our services and increased operating capacity which was added in 2004 and the first six months of 2005. Selling, general and administrative expenses increased largely as a result of the expanding operations of the pressure pumping segment. Increased depreciation expense in 2005 was largely due to the expansion of the pressure pumping segment through capital expenditures during 2004 and the first six months of 2005.

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Drilling and Completion Fluids   2005     2004     % Change  
    (dollars in thousands)        
Revenues
  $ 58,993     $ 41,563       41.9 %
Direct operating costs
  $ 47,795     $ 35,476       34.7 %
Selling, general and administrative
  $ 4,562     $ 3,585       27.3 %
Depreciation and amortization
  $ 1,141     $ 1,114       2.4 %
Operating income
  $ 5,495     $ 1,388       295.9 %
Total jobs
    1,030       1,111       (7.3 )%
Average revenue per job
  $ 57.27     $ 37.41       53.1 %
Average direct operating costs per job
  $ 46.40     $ 31.93       45.3 %
Capital expenditures
  $ 1,352     $ 627       115.6 %
     Revenues and direct operating costs increased during the first six months of 2005 compared to the first six months of 2004 as a result of an increase in the average revenue and direct operating costs per job. Average revenue and direct operating costs per job increased primarily as a result of an increase in the number of larger jobs in the Gulf of Mexico and a decrease in the number of smaller land-based jobs during 2005. Selling, general and administrative expense increased in 2005 primarily due to increased incentive compensation resulting from higher profitability levels.
                         
Oil and Natural Gas Production and Exploration   2005     2004     % Change  
    (dollars in thousands, except sales pries)          
Revenues
  $ 17,912     $ 15,502       15.5 %
Direct operating costs
  $ 4,588     $ 4,336       5.8 %
Selling, general and administrative
  $ 1,053     $ 840       25.4 %
Depreciation, depletion and impairment
  $ 5,837     $ 6,783       (13.9 )%
Operating income
  $ 6,434     $ 3,543       81.6 %
Capital expenditures
  $ 8,428     $ 7,132       18.2 %
Average net daily oil production (Bbls)
    846       1,050       (19.4 )%
Average net daily gas production (Mcf)
    7,922       7,488       5.8 %
Average oil sales price (per Bbl)
  $ 49.00     $ 36.14       35.6 %
Average gas sales price (per Mcf)
  $ 6.16     $ 5.35       15.1 %
     Revenues increased in 2005 compared to 2004, primarily due to increased market prices received for oil and natural gas. Depreciation, depletion and impairment expense includes approximately $817,000 and $2.2 million of expenses incurred during 2005 and 2004, respectively, to impair certain oil and natural gas properties.
                         
Corporate and Other   2005     2004     % Change  
    (in thousands)        
Selling, general and administrative
  $ 7,168     $ 4,651       54.1 %
Bad debt expense
  $ 366     $ 307       19.2 %
Depreciation and amortization
  $ 352     $ 222       58.6 %
Other (income) expense from operations
  $ 1,498     $ (1,375 )     N/A %
Interest income
  $ 1,067     $ 455       134.5 %
Interest expense
  $ 123     $ 130       (5.4 )%
Other income
  $ 20     $ 257       (92.2 )%
Capital expenditures
  $ 5,308     $       N/A %
     Selling, general and administrative expenses increased primarily as a result of payroll taxes attributable to the exercise of employee stock options, increased professional fees, and additional compensation expense related to the issuance of restricted shares to certain key employees in the second quarters of 2004 and 2005. Other (income) expense from operations in 2005 includes a charge of $2.6 million to increase reserves related to the financial failure of a worker’s compensation insurance carrier used previously by the Company.

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Volatility of Oil and Natural Gas Prices and its Impact on Operations
     Our revenue, profitability, and future rate of growth are substantially dependent upon prevailing prices for oil and natural gas, with respect to all of our operating segments. For many years, oil and natural gas prices 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. Natural gas prices fell from an average of $6.23 per Mcf in the first quarter of 2001 to an average of $2.51 per Mcf for the same period in 2002. During this same period, the average number of our rigs operating dropped by approximately 50%. The average market price of natural gas improved from $3.36 in 2002 to $5.45 in 2003 to $5.95 in 2004 and $6.94 in the second quarter of 2005, resulting in an increase in demand for our drilling services. Our average number of rigs operating increased from 126 in 2002 to 188 in 2003 to 211 in 2004 and 265 in the second quarter of 2005. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition and operations and ability to access sources of capital.
     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.
Impact of Inflation
     We believe that inflation will not have a significant near-term impact on our financial position.
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk
     We currently have no exposure to interest rate market risk as we have no outstanding balance under our credit facility. Should we incur a balance in the future, we would have exposure associated with the floating rate of the interest charged on that balance. The revolving credit facility calls for periodic interest payments at a floating rate ranging from LIBOR plus 0.625% to 1.0% or at the prime rate. The applicable rate above LIBOR is based upon our debt to capitalization ratio. Our exposure to interest rate risk due to changes in LIBOR is not expected to be material.
     We conduct some business in Canadian dollars through our Canadian land-based drilling operations. The exchange rate between Canadian dollars and U.S. dollars has fluctuated during the last several years. If the value of the Canadian dollar against the U.S. dollar weakens, revenues and earnings of our Canadian operations will be reduced when they are translated to U.S. dollars. Also, the value of our Canadian net assets in U.S. dollars may decline.
ITEM 4. Controls and Procedures
     Disclosure Controls and Procedures. As of the end of the period covered by this Quarterly Report on Form 10-Q, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934) was evaluated by our management, with the participation of our Chief Executive Officer, Cloyce A. Talbott (principal executive officer), and our Vice President, Chief Financial Officer, Secretary and Treasurer, Jonathan D. Nelson (principal financial and accounting officer). Messrs. Talbott and Nelson have concluded that our disclosure controls and procedures are effective, as of the end of the period covered by this Report, to help ensure that information we are required to disclose in reports that we file with the SEC is accumulated and communicated to management and recorded, processed, summarized and reported within the time periods prescribed by the SEC.
     There were no changes in our internal control over financial reporting that occurred during our last fiscal quarter ended June 30, 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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 this Report contains forward-looking statements which are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. These statements include, without limitation, statements relating to: liquidity; financing of operations; continued volatility of oil and natural gas prices; source and sufficiency of funds required for immediate capital needs and additional rig acquisitions (if further opportunities arise); and other matters. The words “believes,” “plans,” “intends,” “expected,” “estimates” or “budgeted” and similar expressions identify forward-looking statements. The forward-looking statements are based on certain assumptions and analyses we make in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. We do not undertake to update, revise or correct any of the forward-looking information. Factors that could cause actual results to differ materially from our expectations expressed in the forward-looking statements include, but are not limited to, the following:
    Changes in prices and demand for oil and natural gas;
 
    Changes in demand for contract drilling, pressure pumping and drilling and completion fluids services;
 
    Shortages of drill pipe and other drilling equipment;
 
    Labor shortages, primarily qualified drilling personnel;
 
    Effects of competition from other drilling contractors and providers of pressure pumping and drilling and completion fluids services;
 
    Occurrence of operating hazards and uninsured losses inherent in our business operations; and
 
    Environmental and other governmental regulation.
     For a more complete explanation of these various factors and others, see “Forward Looking Statements and Cautionary Statements for Purposes of the ‘Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995” included in our Annual Report on Form 10-K for the year ended December 31, 2004, beginning on page 14.
     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 4. Submission of Matters to a Vote of Security Holders.
     On June 15, 2005, the Company held its Annual Meeting of Stockholders. At the meeting, the stockholders voted on the following matters:
  1.   The election of nine persons to serve as directors of the Company.
 
  2.   Approval of the adoption of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 Plan”).
 
  3.   Ratification of the appointment of PricewaterhouseCoopers LLP as the independent accountants of the Company for the fiscal year ending December 31, 2005.
     The nine nominees to the Board of Directors of the Company were elected at the meeting, and the other proposals received the affirmative vote required for approval. The number of votes cast for, against or withheld, as well as the number of abstentions and broker non-votes, were as follows:
                     
        Votes For   Votes Withheld
1.
  Election of Directors                
 
  Mark S. Siegel     155,764,040       2,664,759  
 
  Cloyce A. Talbott     155,762,955       2,665,844  
 
  A. Glenn Patterson     155,763,338       2,665,461  
 
  Kenneth N. Berns     151,630,010       6,798,789  
 
  Robert C. Gist     152,198,666       6,230,133  
 
  Curtis W. Huff     157,004,971       1,423,828  
 
  Terry H. Hunt     157,003,923       1,424,876  
 
  Kenneth R. Peak     157,072,419       1,356,380  
 
  Nadine C. Smith     157,070,786       1,358,013  
                                     
                                Broker
        Votes For   Votes Against   Abstentions   Non-votes
2.
  Approval of the 2005 Plan     126,619,156       10,728,710       1,651,308       19,429,625  
                                     
                                Broker
        Votes For   Votes Against   Abstentions   Non-votes
3.
  Ratification of PricewaterhouseCoope rs LLP as the Company’s Independent Accountants     156,358,655       1,945,384       124,760       0  
ITEM 6. Exhibits
    (a) Exhibits.
 
    The following exhibits are filed herewith or incorporated by reference, as indicated:
 
3.1   Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
 
3.2   Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
 
3.3   Amended and Restated Bylaws (filed March 19, 2002 as Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference).

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10.1   Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, including Form of Executive Officer Restricted Stock Award Agreement, Form of Executive Officer Stock Option Agreement, Form of Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee Director Stock Option Agreement (incorporated by reference to Exhibit 10.1 to Patterson-UTI Energy, Inc.’s Current Report on Form 8-K, dated June 15, 2005, as filed with the SEC on June 21, 2005).*
 
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.
 
*   Management Contract or Compensatory Plan.

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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)
Chief Executive Officer
 
       
 
  By:    /s/ Jonathan D. Nelson 
 
      Jonathan D. Nelson
(Principal Accounting Officer)
Vice President, Chief Financial Officer,
Secretary and Treasurer
 
       
DATED: July 28, 2005
       

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