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PATTERSON UTI ENERGY INC - Quarter Report: 2004 September (Form 10-Q)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

     
[x]
  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
 
   
  For the quarterly period ended September 30, 2004

OR

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

P. O. BOX 1416, 4510 LAMESA HIGHWAY, SNYDER, TEXAS, 79550
(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 [x]      No [  ]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes [x]      No [   ]

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

167,381,556 shares of common stock, $0.01 par value, as of October 29, 2004


 


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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 and CFO Pursuant to 18 USC Section 1350

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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)
                 
    September 30,   December 31,
    2004
  2003
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 69,766     $ 100,483  
Accounts receivable, net of allowance for doubtful accounts of $3,090 at September 30, 2004 and $2,133 at December 31, 2003
    196,287       156,345  
Federal and state income taxes receivable, net
          12,667  
Inventory
    16,382       15,206  
Deferred tax assets
    25,983       19,674  
Other
    22,103       15,697  
 
   
 
     
 
 
Total current assets
    330,521       320,072  
Property and equipment, at cost, net
    802,851       693,631  
Goodwill
    102,525       51,179  
Investment in equity securities
          19,771  
Other
    13,931       2,686  
 
   
 
     
 
 
Total assets
  $ 1,249,828     $ 1,087,339  
 
   
 
     
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable:
               
Trade
  $ 43,355     $ 41,093  
Accrued revenue distributions
    11,591       8,545  
Other
    2,440       6,743  
Accrued federal income taxes payable
    9,149        
Accrued expenses
    67,985       60,853  
 
   
 
     
 
 
Total current liabilities
    134,520       117,234  
Deferred tax liabilities
    160,472       145,742  
Other
    4,932       3,822  
 
   
 
     
 
 
Total liabilities
    299,924       266,798  
 
   
 
     
 
 
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 at September 30, 2004 and 200,000,000 shares at December 31, 2003 with 170,090,570 (affected by a two-for-one stock split) and 82,483,148 issued and 166,977,474 (affected by a two-for-one stock split) and 80,976,600 outstanding at September 30, 2004 and December 31, 2003, respectively
    1,701       825  
Additional paid-in capital
    578,194       506,018  
Deferred compensation
    (6,002 )      
Retained earnings
    381,148       318,419  
Accumulated other comprehensive income
    8,000       6,934  
Treasury stock, at cost, 3,113,096 shares (affected by a two-for-one stock split) and 1,506,548 shares at September 30, 2004 and December 31, 2003, respectively
    (13,137 )     (11,655 )
 
   
 
     
 
 
Total stockholders’ equity
    949,904       820,541  
 
   
 
     
 
 
Total liabilities and stockholders’ equity
  $ 1,249,828     $ 1,087,339  
 
   
 
     
 
 

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   Nine Months Ended
    September 30,
  September 30,
    2004
  2003
  2004
  2003
Operating revenues:
                               
Drilling
  $ 206,454     $ 169,077     $ 573,851     $ 468,609  
Pressure pumping
    19,663       13,198       48,490       31,509  
Drilling and completion fluids
    23,455       19,580       65,018       51,431  
Oil and natural gas
    9,602       5,160       25,104       16,329  
 
   
 
     
 
     
 
     
 
 
 
    259,174       207,015       712,463       567,878  
 
   
 
     
 
     
 
     
 
 
Operating costs and expenses:
                               
Drilling
    140,608       123,156       402,986       353,893  
Pressure pumping
    10,455       7,226       26,871       18,032  
Drilling and completion fluids
    19,851       17,180       55,327       45,483  
Oil and natural gas
    1,715       1,138       6,051       3,509  
Depreciation, depletion, amortization and impairment
    30,789       24,716       88,523       73,825  
General and administrative
    8,309       6,853       23,017       20,560  
Bad debt expense
    192       97       499       259  
Other
    (153 )     (705 )     (1,528 )     (4,034 )
 
   
 
     
 
     
 
     
 
 
 
    211,766       179,661       601,746       511,527  
 
   
 
     
 
     
 
     
 
 
Operating income
    47,408       27,354       110,717       56,351  
 
   
 
     
 
     
 
     
 
 
Other income (expense):
                               
Interest income
    233       263       688       808  
Interest expense
    (75 )     (68 )     (205 )     (216 )
Other
    56       169       313       1,829  
 
   
 
     
 
     
 
     
 
 
 
    214       364       796       2,421  
 
   
 
     
 
     
 
     
 
 
Income before income taxes and cumulative effect of change in accounting principle
    47,622       27,718       111,513       58,772  
 
   
 
     
 
     
 
     
 
 
Income tax expense (benefit):
                               
Current
    11,996       8,610       31,200       22,372  
Deferred
    5,662       1,922       10,060       (39 )
 
   
 
     
 
     
 
     
 
 
 
    17,658       10,532       41,260       22,333  
 
   
 
     
 
     
 
     
 
 
Income before cumulative effect of change in accounting principle
    29,964       17,186       70,253       36,439  
Cumulative effect of change in accounting principle, net of related income tax benefit of approximately $287
                      (469 )
 
   
 
     
 
     
 
     
 
 
Net income
  $ 29,964     $ 17,186     $ 70,253     $ 35,970  
 
   
 
     
 
     
 
     
 
 
Net income per common share:
                               
Basic:
                               
Income before cumulative effect of change in accounting principle
  $ 0.18     $ 0.11     $ 0.42     $ 0.23  
 
   
 
     
 
     
 
     
 
 
Cumulative effect of change in accounting principle
  $     $     $     $  
 
   
 
     
 
     
 
     
 
 
Net income
  $ 0.18     $ 0.11     $ 0.42     $ 0.22  
 
   
 
     
 
     
 
     
 
 
Diluted:
                               
Income before cumulative effect of change in accounting principle
  $ 0.18     $ 0.10     $ 0.42     $ 0.22  
 
   
 
     
 
     
 
     
 
 
Cumulative effect of change in accounting principle
  $     $     $     $  
 
   
 
     
 
     
 
     
 
 
Net income
  $ 0.18     $ 0.10     $ 0.42     $ 0.22  
 
   
 
     
 
     
 
     
 
 
Weighted average number of common shares outstanding:
                               
Basic
    167,006       161,808       165,744       161,070  
 
   
 
     
 
     
 
     
 
 
Diluted
    169,664       164,382       168,795       164,522  
 
   
 
     
 
     
 
     
 
 

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        
    Number           Additional                   other        
    of           paid-in   Deferred   Retained   comprehensive   Treasury    
    shares
  Amount
  capital
  compensation
  earnings
  income
  stock
  Total
Balance, December 31, 2003
    82,483     $ 825     $ 506,018     $     $ 318,419     $ 6,934     $ (11,655 )   $ 820,541  
Issuance of common stock
    1,388       14       49,462                               49,476  
Issuance of restricted stock
    195       2       6,749       (6,751 )                        
Amortization of deferred compensation expense
                      749                         749  
Exercise of stock options
    1,039       10       9,283                               9,293  
Tax benefit related to exercise of stock options
                6,682                               6,682  
Foreign currency translation adjustment
                                  1,066             1,066  
Purchase of treasury stock
                                        (1,482 )     (1,482 )
Payment of cash dividend (See Note 13)
                            (6,674 )                 (6,674 )
Effect of two-for-one stock split (See Note 13)
    84,986       850                   (850 )                  
Net income
                            70,253                   70,253  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Balance, September 30, 2004
    170,091     $ 1,701     $ 578,194     $ (6,002 )   $ 381,148     $ 8,000     $ (13,137 )   $ 949,904  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 

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)
                 
    Nine Months Ended
    September 30,
    2004
  2003
Cash flows from operating activities:
               
Net income
  $ 70,253     $ 35,970  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, depletion, amortization and impairment
    88,523       73,825  
Dry holes and abandonments
    593        
Provision for bad debts
    499       259  
Deferred income tax expense (benefit)
    10,060       (39 )
Tax benefit related to exercise of stock options
    6,682       5,992  
Amortization of deferred compensation
    749        
Gain on sale of property and equipment
    (1,528 )     (1,582 )
Cumulative effect of change in accounting principle, net of tax
          (469 )
Changes in operating assets and liabilities, net of acquired assets and liabilities assumed:
               
Accounts receivable
    (34,480 )     (41,189 )
Federal and state income taxes
    21,825       31,406  
Inventory and other current assets
    (6,997 )     (8,317 )
Accounts payable
    2,227       11,728  
Accrued expenses
    (5,416 )     25,681  
Other liabilities
    (6,729 )     1,037  
 
   
 
     
 
 
Net cash provided by operating activities
    146,261       134,302  
 
   
 
     
 
 
Cash flows from investing activities:
               
Acquisitions, net of cash acquired
    (32,514 )     (32,837 )
Purchases of property and equipment
    (136,835 )     (83,994 )
Proceeds from sales of property and equipment
    2,631       3,178  
Restricted cash deposited to collateralize retained insurance losses
    (11,316 )      
Change in other assets
          (1,479 )
 
   
 
     
 
 
Net cash used in investing activities
    (178,034 )     (115,132 )
 
   
 
     
 
 
Cash flows from financing activities:
               
Purchase of treasury stock
    (1,482 )      
Dividends paid
    (6,674 )      
Proceeds from exercise of stock options and warrants
    9,293       9,591  
 
   
 
     
 
 
Net cash provided by financing activities
    1,137       9,591  
 
   
 
     
 
 
Net increase (decrease) in cash and cash equivalents
    (30,636 )     28,761  
Foreign currency translation adjustment
    (81 )     402  
Cash and cash equivalents at beginning of period
    100,483       82,154  
 
   
 
     
 
 
Cash and cash equivalents at end of period
  $ 69,766     $ 111,317  
 
   
 
     
 
 
Supplemental disclosure of cash flow information:
               
Net cash received (paid) during the period for:
               
Interest
  $ (205 )   $ (216 )
Income taxes
  $ (500 )   $ 14,622  

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

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     Non-Cash investing and financing activities:

     In February 2004, the Company completed its merger with TMBR/Sharp Drilling, Inc. (“TMBR”) in which one of its wholly-owned subsidiaries acquired 100% of the remaining outstanding shares of TMBR for a net cash payment of approximately $32.5 million ($40.4 million paid to TMBR shareholders less $7.9 million in cash acquired in the transaction) and the issuance of 2.78 million shares of the Company’s common stock valued at $17.82 per share (adjusted to reflect the two-for-one stock split in the form of a stock dividend on June 30, 2004). The assets of TMBR included 18 land-based drilling rigs and related equipment, shop facilities, equipment yards and their oil and natural gas properties. The transaction was accounted for as a business combination and the purchase price was allocated among the assets acquired and liabilities assumed based on their estimated fair market values (See Note 2).

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, 2003, as presented herein, was derived from the audited balance sheet of the Company as of December 31, 2003. 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, 2003, as amended.

     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).

     On April 28, 2004, the Company’s Board of Directors authorized a two-for-one stock split in the form of a stock dividend which was distributed on June 30, 2004 to holders of record on June 14, 2004. At June 30, 2004, an adjustment was made to reclassify an amount from retained earnings to common stock to account for the par value of the common stock issued as a stock dividend. This adjustment had no overall effect on equity. The September 30, 2003 balance sheet was not restated as a result of this transaction; however, historical earnings per share amounts included in the statements of income and elsewhere in this report have been restated as if the two-for-one stock split had occurred on January 1, 2003.

     The Company provides a dual presentation of its earnings per share in its Condensed Consolidated Statements of Income: Basic Earnings per Share (“Basic EPS”) and Diluted Earnings per Share (“Diluted EPS”). Basic EPS is computed using the weighted average number of shares outstanding during the periods presented. Diluted EPS includes common stock equivalents, generally stock options and warrants which are dilutive to earnings per share. For the three months ended September 30, 2004 and 2003, dilutive securities included in the calculation of Diluted EPS were 2.7 million shares and 2.6 million shares, respectively. For the nine months ended September 30, 2004 and 2003, dilutive securities included in the calculation of Diluted EPS were 3.1 million shares and 3.5 million shares, respectively. For the three and nine months ended September 30, 2004, there were 540,000 potentially dilutive options and warrants which were excluded from the calculation of Diluted EPS as their exercise price was greater than the average market price for the period. For the three and nine months ended September 30, 2003, there were 2.3 million and 1.8 million, respectively, potentially dilutive options and warrants which were excluded from the calculation of Diluted EPS as their exercise price was greater than the average market price for the period.

     The results of operations for the three and nine months ended September 30, 2004 are not necessarily indicative of the results to be expected for the full year.

     Certain reclassifications have been made to the 2003 consolidated financial statements in order for them to conform with the 2004 presentation.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-
CONTINUED

2. Recent Acquisitions

     On February 11, 2004, the Company completed its merger with TMBR/Sharp Drilling, Inc. (“TMBR”), a Texas corporation, in which one of its wholly-owned subsidiaries acquired 100% of the remaining outstanding shares of TMBR. Operations of TMBR subsequent to February 11, 2004, are included in the Company’s consolidated financial statements. The transaction was accounted for as a business combination and the purchase price was allocated among the assets acquired and liabilities assumed based on their estimated fair market values. The assets of TMBR included 18 land-based drilling rigs and related equipment, shop facilities, equipment yards and their oil and natural gas properties.

     The purchase price was calculated as follows (in thousands, except per share data and exchange ratio):

         
Cash of $9.09 per share for the 4,447 TMBR shares outstanding at February 11, 2004, excluding the 1,059 TMBR shares owned by Patterson-UTI
  $ 40,423  
Patterson-UTI shares issued at $17.82 per share (4,447 TMBR shares X .624332 exchange ratio X $17.82)
    49,476  
1,059 TMBR shares previously acquired by the Company
    19,771  
Acquisition costs
    12,509  
Less: Cash acquired
    (7,909 )
 
   
 
 
Total purchase price
  $ 114,270  
 
   
 
 

     The purchase price was allocated among assets acquired and liabilities assumed based on their estimated fair market values as follows (in thousands):

         
Current assets
  $ 6,287  
Property and equipment
    61,369  
Other long term assets
    172  
Deferred tax assets
    11,216  
Goodwill
    51,346  
Current liabilities
    (6,382 )
Other long term liabilities.
    (677 )
Deferred tax liability
    (9,061 )
 
   
 
 
Total purchase allocation
  $ 114,270  
 
   
 
 

     The purchase price allocation is based on preliminary estimates, including estimates of federal tax contingencies, which are subject to change once additional information becomes available. Changes to these estimates could result in changes to the purchase price allocation.

     The Company acquired TMBR to increase its productive asset base in the Permian Basin, which is one of the most active land drilling regions in the U.S. TMBR was well established in the contract drilling industry and maintained favorable customer relationships. Goodwill was recognized in the transaction as a result of these factors.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-
CONTINUED

2. Recent Acquisitions — (continued)

     The following represents pro-forma unaudited financial information as if the merger had been completed on January 1, 2003 (in thousands, except per share amounts):

                         
    Three months    
    ended   Nine months ended
    September 30,
  September 30,
    2003
  2004
  2003
Revenue
  $ 217,686     $ 717,051     $ 600,705  
Income before cumulative effect of change in accounting principle
    18,118       69,954       37,205  
Net income
    18,118       69,954       36,736  
Earnings per share:
                       
Basic
  $ 0.11     $ 0.42     $ 0.23  
 
   
 
     
 
     
 
 
Diluted
  $ 0.11     $ 0.41     $ 0.22  
 
   
 
     
 
     
 
 

     Since the merger was completed on February 11, 2004, and the results of TMBR have been included subsequent to that date, no pro-forma information for the three months ended September 30, 2004 is necessary.

3. Stock-based Compensation

     At September 30, 2004, the Company had seven stock-based employee compensation plans, of which three were active. The Company accounts for those plans under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. During the second quarter of 2004, 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. 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. Compensation expense of $306,000 and $471,000, net of tax, was included in net income for the three and nine months ended September 30, 2004, respectively. 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 No. 123”) to stock-based employee compensation (in thousands, except per share amounts):

                                 
    Three months ended   Nine months ended
    September 30,
  September 30,
    2004
  2003
  2004
  2003
Net income, as reported
  $ 29,964     $ 17,186     $ 70,253     $ 35,970  
Add: Stock-based employee compensation expense recorded, net of tax
    306             471        
Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects
    (3,468 )     (2,776 )     (9,794 )     (7,816 )
 
   
 
     
 
     
 
     
 
 
Pro-forma net income
  $ 26,802     $ 14,410     $ 60,930     $ 28,154  
 
   
 
     
 
     
 
     
 
 
Net income per common share:
                               
Basic, as reported
  $ 0.18     $ 0.11     $ 0.42     $ 0.22  
 
   
 
     
 
     
 
     
 
 
Basic, pro-forma
  $ 0.16     $ 0.09     $ 0.37     $ 0.18  
 
   
 
     
 
     
 
     
 
 
Diluted, as reported
  $ 0.18     $ 0.10     $ 0.42     $ 0.22  
 
   
 
     
 
     
 
     
 
 
Diluted, pro-forma
  $ 0.16     $ 0.09     $ 0.36     $ 0.17  
 
   
 
     
 
     
 
     
 
 

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-
CONTINUED

4. Comprehensive Income

     The following table illustrates the Company’s comprehensive income including the effects of foreign currency translation adjustments for the three and nine months ended September 30, 2004 and 2003 (in thousands):

                                 
    Three months ended   Nine months ended
    September 30,
  September 30,
    2004
  2003
  2004
  2003
Net income
  $ 29,964     $ 17,186     $ 70,253     $ 35,970  
Other comprehensive income (expense):
                               
Foreign currency translation adjustment related to our Canadian operations
    2,957       (378 )     1,066       6,693  
 
   
 
     
 
     
 
     
 
 
Comprehensive income
  $ 32,921     $ 16,808     $ 71,319     $ 42,663  
 
   
 
     
 
     
 
     
 
 

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-
CONTINUED

5. 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 and (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   Nine months ended
    September 30,
  September 30,
    2004
  2003
  2004
  2003
Operating revenues:
                               
Drilling
  $ 206,454     $ 169,077     $ 573,851     $ 468,609  
Pressure pumping
    19,663       13,198       48,490       31,509  
Drilling and completion fluids
    23,455       19,580       65,018       51,431  
Oil and natural gas
    9,602       5,160       25,104       16,329  
 
   
 
     
 
     
 
     
 
 
Total operating revenues
  $ 259,174     $ 207,015     $ 712,463     $ 567,878  
 
   
 
     
 
     
 
     
 
 
Operating income:
                               
Drilling
  $ 39,628     $ 23,879     $ 95,223     $ 48,962  
Pressure pumping
    6,199       3,583       12,787       6,665  
Drilling and completion fluids
    1,100       (45 )     2,488       (1,202 )
Oil and natural gas
    3,674       1,580       7,217       5,066  
 
   
 
     
 
     
 
     
 
 
 
    50,601       28,997       117,715       59,491  
Corporate and other (a)
    (3,193 )     (1,643 )     (6,998 )     (3,140 )
 
   
 
     
 
     
 
     
 
 
Operating income
  $ 47,408     $ 27,354     $ 110,717     $ 56,351  
 
   
 
     
 
     
 
     
 
 
                 
    September 30,   December 31,
    2004
  2003
Identifiable assets:
               
Drilling
  $ 970,638     $ 809,896  
Pressure pumping
    60,528       46,763  
Drilling and completion fluids
    35,322       30,860  
Oil and natural gas
    60,437       33,494  
Corporate and other (b)
    122,903       166,326  
 
   
 
     
 
 
 
  $ 1,249,828     $ 1,087,339  
 
   
 
     
 
 


(a)   Corporate and other relates to decisions of the executive management group regarding corporate strategy, credit risk, loss contingencies and restructuring activities. Due to the non-operating nature of these decisions, the related income and expenses have been separately presented and excluded from the results of specific segments. These income and expense items primarily relate to the Drilling segment.
 
(b)   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

6. Recently Issued Accounting Standards

     The Financial Accounting Standards Board (“FASB”) issued Interpretation No. 46R, “Consolidation of Variable Interest Entities” (“FIN 46R”) which addresses the consolidation of variable interest entities (“VIEs”) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise that has the majority of the risks or rewards associated with the VIE. The Company believes it has no material interests in VIEs that require disclosure or consolidation under FIN 46R.

     In March 2004, the FASB issued an exposure draft, “Share-Based Payment, an Amendment of FASB Statements No. 123 and 95”. This proposed statement would prohibit companies from using the intrinsic method of accounting for stock-based compensation currently permitted by APB No. 25, and would generally require the use of the fair-value method of accounting as prescribed in SFAS No. 123. If this exposure draft is approved, we would expect to record a charge to compensation expense associated with our employee stock options outstanding, and may incur additional compensation costs in future periods as outstanding employee stock options vest. On October 13, 2004, the FASB announced that it plans to issue a final standard related to this issue by December 31, 2004, and deferred the effective date of this proposed standard until interim and annual periods beginning after June 15, 2005.

7. Goodwill

     In accordance with Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” goodwill is evaluated to determine if fair value of the asset has decreased below its carrying value. At December 31, 2003, we performed the annual goodwill evaluation and determined no adjustment to impair goodwill was necessary. With respect to our drilling and completion fluids business, the determination that no impairment existed as of December 31, 2003, was based on our expectations of improvement in the results of operations for that business segment. If the expected improvement in results does not continue to occur, all or part of the goodwill of approximately $10 million associated with that business segment may be determined to be impaired. Goodwill as of September 30, 2004 and December 31, 2003 are as follows (in thousands):

                 
    September 30,   December 31,
    2004
  2003
Drilling:
               
Goodwill at beginning of period
  $ 41,215     $ 41,215  
Goodwill in TMBR
    50,181        
TMBR purchase price allocation adjustment
    1,165        
 
   
 
     
 
 
Goodwill at end of period
    92,561       41,215  
 
   
 
     
 
 
Drilling and completion fluids:
               
Goodwill at beginning of period
  $ 9,964     $ 9,964  
Changes to goodwill
           
 
   
 
     
 
 
Goodwill at end of period
    9,964       9,964  
 
   
 
     
 
 
Total goodwill
  $ 102,525     $ 51,179  
 
   
 
     
 
 

8. Restricted Cash

     During the second quarter of 2004, the Company entered into an agreement with its workers’ compensation insurance carrier to place restrictions on approximately $11.3 million in cash which is to be used as collateral for losses which may become payable under the terms of the underlying insurance contracts. The agreement restricts the Company from using the cash in operations for an indefinite period; however, the agreement does allow the Company to replace the cash with another form of collateral (such as a letter of credit) acceptable to the insurance carrier. The restricted cash is included in other long-term assets at September 30, 2004.

9. Investment in Equity Securities

     During 2002, the Company acquired approximately 19.5% of the outstanding shares of TMBR. Accordingly, the Company accounted for its investment using a method other than the equity method. On February 11, 2004, the Company acquired 100% of the remaining outstanding shares of TMBR. Accordingly, the Company was required to retroactively account for its investment using the equity method of accounting. Therefore, the Company has restated its prior period financial statements to reflect the equity method of accounting for its investment in TMBR for all prior periods.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-
CONTINUED

9. Investment in Equity Securities — (continued)

     The following table presents the restated balances as of December 31, 2003 and for the three and nine months ended September 30, 2003 using the equity method of accounting for its investment in TMBR (in thousands, except per share amounts):

                 
    As Previously   As
    Reported
  Restated
Balance Sheet as of December 31, 2003:
               
Investment in equity securities
  $ 20,274     $ 19,771  
Accumulated other comprehensive income
    8,554       6,934  
Deferred tax liability
    146,715       145,742  
Retained earnings
    316,329       318,419  
                                 
    Three months ended   Nine months ended
    September 30, 2003
  September 30, 2003
    As Previously   As   As Previously   As
Comprehensive Income
  Reported
  Restated
  Reported
  Restated
Comprehensive income
    15,922       16,808       42,016       42,663  
Income Statement
                               
Other income
    52       169       137       1,829  
Deferred income tax expense
    1,878       1,922       (682 )     (39 )
Net income
    17,113       17,186       34,921       35,970  
Net income per common share:
                               
Basic
  $ 0.11     $ 0.11     $ 0.22     $ 0.22  
 
   
 
     
 
     
 
     
 
 
Diluted
  $ 0.10     $ 0.10     $ 0.21     $ 0.22  
 
   
 
     
 
     
 
     
 
 

10. Accrued Expenses

     Accrued expenses consisted of the following at September 30, 2004 and December 31, 2003 (in thousands):

                 
    September 30,   December 31,
    2004
  2003
Salaries, wages, payroll taxes and benefits
  $ 15,393     $ 15,740  
Workers’ compensation liability
    34,598       31,646  
Contingent liabilities
    4,794       2,335  
Sales, use and other taxes
    6,632       5,796  
Insurance, other than workers’ compensation
    2,799       1,848  
Restructuring and merger related costs
    1,000       1,000  
Other
    2,769       2,488  
 
   
 
     
 
 
 
  $ 67,985     $ 60,853  
 
   
 
     
 
 

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-
CONTINUED

11. Asset Retirement Obligation

     The FASB issued Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), in June 2001. SFAS No. 143 requires that, beginning in 2003, we record a liability for the estimated costs to be incurred in connection with the abandonment of oil and natural gas properties in the future. We recorded a liability of approximately $1.1 million in the first quarter of 2003 upon initial adoption of SFAS No. 143. The following table describes the changes to our asset retirement obligations during the first nine months of 2004 (in thousands):

         
Balance at December 31, 2003.
  $ 1,163  
Liabilities incurred*
    1,242  
Liabilities settled
    (144 )
Accretion expense
    52  
 
   
 
 
Balance at September 30, 2004.
  $ 2,313  
 
   
 
 

* Includes $1,091 related to TMBR acquisition.

     A charge of $469,000 (net of tax) was recorded as a cumulative effect of a change in accounting principle for the quarter ended March 31, 2003. The change relates to the cost associated with the future abandonment of oil and natural gas properties. There was no effect on diluted earnings per share as a result of the change in accounting principle for the three and nine months ended September 30, 2003.

12. Commitments, Contingencies and Other Matters

     During the second quarter of 2004, the Company entered into an agreement with its workers’ compensation insurance carrier to place restrictions on approximately $11.3 million in cash which is to be used as collateral for losses which may become payable under the terms of the underlying insurance contracts. The agreement restricts the Company from using the cash in operations for an indefinite period, however, the agreement does allow the Company to replace the cash with another form of collateral (such as a letter of credit) acceptable to the insurance carrier. The restricted cash is included in other long-term assets at September 30, 2004.

     The Company maintains letters of credit in the aggregate amount of $38.0 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 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

13. Stockholders’ Equity

     On April 28, 2004, the Company’s Board of Directors authorized a two-for-one stock split in the form of a stock dividend which was distributed on June 30, 2004 to holders of record on June 14, 2004. In connection with the two-for-one stock split, an adjustment was made to reclassify an amount from retained earnings to common stock to account for the par value of the common stock issued as a stock dividend. This adjustment had no overall effect on equity. The prior year balance sheet was not restated as a result of this transaction; however, historical earnings per share amounts included in the statements of income and elsewhere in this report have been restated as if the two-for-one stock split had occurred on January 1, 2003.

     On April 28, 2004, the Company’s Board of Directors approved the initiation of a quarterly cash dividend on each share of the Company’s common stock. The first quarterly dividend in the amount of $0.02 per share, or approximately $3.3 million was paid on June 2, 2004 to holders of record as of May 17, 2004. The second quarterly dividend in the amount of $0.02 per share, or approximately $3.3 million was paid on September 1, 2004 to holders of record as of August 16, 2004. On October 27, 2004, our Board of Directors approved a cash dividend of $0.02 per share on each share of our common stock to be paid on December 1, 2004 to holders of record on November 15, 2004. 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 conditions and other factors.

     On June 7, 2004, the Company’s Board of Directors authorized a stock buyback program for the purchase of up to $30 million of outstanding shares of the Company’s common stock. During the second quarter of 2004, the Company purchased 100,000 shares of its common stock in the open market for approximately $1.5 million. These shares are included in treasury stock at September 30, 2004.

     During the second quarter of 2004, the Company granted the Restricted Shares to certain key employees under the Patterson-UTI Energy, Inc. 1997 Long-Term Incentive Plan, as amended. 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. Compensation expense of $306,000 and $471,000, net of tax, was included in net income for the three and nine months ended September 30, 2004, respectively.

14. Subsequent Event

     On October 27, 2004, the Company’s Board of Directors approved a cash dividend on each share of its common stock in the amount of $0.02 per share. The dividend is to be paid to holders of record on November 15, 2004 and paid on December 1, 2004.

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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 nine months ended September 30, 2004 and 2003, our operating revenues consisted of the following (dollars in thousands):

                                                                 
    Three Months Ended   Nine Months Ended
    September 30,
  September 30,
    2004
  2003
  2004
  2003
Contract drilling
  $ 206,454       80 %   $ 169,077       82 %   $ 573,851       81 %   $ 468,609       82 %
Pressure pumping
    19,663       7       13,198       6       48,490       7       31,509       6  
Drilling and completion fluids
    23,455       9       19,580       9       65,018       9       51,431       9  
Oil and natural gas
    9,602       4       5,160       3       25,104       3       16,329       3  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
  $ 259,174       100 %   $ 207,015       100 %   $ 712,463       100 %   $ 567,878       100 %
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 

     We provide our contract services to oil and natural gas operators in North America. Our contract drilling operations are focused in various regions of Texas, New Mexico, Oklahoma, Louisiana, Mississippi, Colorado, Utah, Wyoming 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, New Mexico, Oklahoma, the Gulf Coast regions of Texas and Louisiana and the Gulf of Mexico. Our oil and natural gas operations are primarily focused in Texas, New Mexico and Mississippi.

     We have been a leading consolidator of the domestic land-based contract drilling industry over the past several years by increasing our drilling fleet to 361 rigs, which we believe is the second largest drilling fleet in North America. Growth by acquisition has been a corporate strategy intended to expand both revenues and market share.

     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 third quarter of 2004, our average number of rigs operating increased to 216 from 203 in the second quarter of 2004 and 192 in the third quarter of 2003. Our average revenue per operating day increased to $10,400 in the third quarter of 2004 from $10,200 in the second quarter of 2004 and $9,580 in the third quarter of 2003.

     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. Our operations are also impacted by competition, the availability of excess equipment, labor shortages 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, 2003, as amended, beginning on page 15.

     Management believes that the liquidity of our balance sheet as of September 30, 2004, which includes approximately $196 million in working capital (including $70 million in cash), no long term debt and $62 million available under our existing $100 million line of credit (availability of $38 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.

     Commitments and Contingencies — During 2004, the Company entered into an agreement with its workers’ compensation insurance carrier to place restrictions on approximately $11.3 million in cash which is to be used as collateral for losses which may become payable under the terms of the underlying insurance contracts. The agreement restricts the Company from using the cash in operations for an indefinite period, however, the agreement does allow the Company to replace the cash with another form of collateral (such as a letter of credit) acceptable to the insurance carrier. The restricted cash is included in other long-term assets at September 30, 2004.

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     We have no other commitments or contingencies which require disclosure in our financial statements other than letters of credit totaling $38.0 million at September 30, 2004, 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 — As a leading provider of onshore contract drilling services, we currently own 361 land-based drilling rigs. Our pressure pumping services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. Our drilling and completion fluids services are used 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.

     The contract drilling business experienced many downturns in demand over the last several years. During these periods, there have been substantially more drilling rigs available than necessary to meet demand in most operational and geographic segments of the North American land drilling industry. As a result, drilling contractors have had difficulty sustaining profit margins.

     In addition to adverse effects that future declines in demand could have on the Company, 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, intangible assets, revenue recognition, and the use of estimates.

     Property and equipment — 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 the 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 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. There were no impairment charges to property and equipment during the nine months ended September 30, 2004 or 2003.

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     Oil and natural gas properties — 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 determinations are made. In accordance with Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” (“SFAS No. 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. The Company reviews its 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. The Company’s 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 $891,000 and $3.0 million for the three and nine months ended September 30, 2004, respectively, is included in depreciation, depletion, amortization and impairment in the accompanying financial statements.

     Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized until its life is determined to be finite. 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. With respect to our drilling and completion fluids business, the determination that no impairment existed as of December 31, 2003, was based on our expectations of improvement in the results of operations for that business segment. If the expected improvement in results does not continue to occur, all or part of the goodwill of approximately $10 million associated with that business segment may be determined to be impaired.

     Revenue recognition — 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. The Company follows 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, the Company follows the completed contract method of accounting for such arrangements. Under this method, all drilling advances and costs related to a well in progress are deferred and recognized as revenues and expenses in the period the well is completed. Provisions for losses on incomplete or in-process wells are made when estimated total costs are expected to exceed estimated total revenues.

     In accordance with Emerging Issues Task Force Issue No. 00-14, the Company recognizes reimbursements received from third parties for out-of-pocket expenses incurred by the Company as revenues and accounts for out-of-pocket expenses as direct costs.

     Use of estimates — 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.

Liquidity and Capital Resources

     As of September 30, 2004, we had working capital of approximately $196 million, including cash and cash equivalents of $70 million. For the nine months ended September 30, 2004, our significant sources of cash flow were approximately:

  $146 million provided by operations,
 
  $9 million from the exercise of stock options, and
 
  $3 million from the proceeds from sales of property and equipment.

     We used approximately $33 million to acquire the remaining outstanding shares of TMBR and approximately $137 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.

     Additionally, approximately $6.7 million was used to pay dividends on the Company’s common stock and approximately $1.5 million was used to buy back 100,000 shares of the Company’s common stock pursuant to the stock buyback program authorized by the Company’s Board of Directors on June 7, 2004. Furthermore, restrictions on the Company’s use of approximately $11.3 million were put into place during the second quarter of 2004 as the Company pledged this cash as collateral for losses which could become payable under the terms of its workers’ compensation insurance contracts.

     In February 2004, the Company completed its merger with TMBR in which one of the Company’s wholly-owned subsidiaries acquired 100% of the remaining outstanding shares of TMBR for a net cash payment of approximately $33 million ($40.4 million paid to TMBR shareholders less $7.9 million in cash acquired in the transaction) and the issuance of 2.78 million shares of the Company’s common stock valued at $17.82 per share. The assets of TMBR included 18 land-based drilling rigs and related equipment, shop facilities, equipment yards and their oil and natural gas properties. The transaction was accounted for as a business combination and the purchase price was allocated among the assets acquired and liabilities assumed based on their estimated fair market values.

     On April 28, 2004, the Company’s Board of Directors approved the initiation of a quarterly cash dividend on each share of the Company’s common stock. The first quarterly dividend in the amount of $0.02 per share, or approximately $3.3 million was paid on June 2, 2004 to holders of record as of May 17, 2004. The second quarterly dividend in the amount of $0.02 per share, or approximately $3.3 million was paid on September 1, 2004 to holders of record as of August 16, 2004. On October 27, 2004, our Board of Directors approved a cash dividend of $0.02 per share on each share of our common stock to be paid on December 1, 2004 to holders of record on November 15, 2004. 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 conditions 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 reviewed. The timing, size or success of any acquisition and the associated capital commitments are unpredictable. Over the longer term, should further 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, and either debt or equity financing. However, there can be no assurance that such capital would be available.

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Commitments, Contingencies and Other Matters

     During 2004, the Company entered into an agreement with its workers’ compensation insurance carrier to place restrictions on approximately $11.3 million in cash which is to be used as collateral for losses which may become payable under the terms of the underlying insurance contracts. The agreement restricts the Company from using the cash in operations for an indefinite period, however, the agreement does allow the Company to replace the cash with another form of collateral (such as a letter of credit) acceptable to the insurance carrier. The restricted cash is included in other long-term assets at September 30, 2004.

     The Company maintains letters of credit in the aggregate amount of $38.0 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 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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Results of Operations

The following tables summarize operations by business segment for the three months ended September 30, 2004 and 2003:

                         
Contract Drilling
  2004
  2003
  % Change
    (dollars in thousands)        
Revenues
  $ 206,454     $ 169,077       22.1 %
Direct operating costs
  $ 140,608     $ 123,156       14.2 %
Selling, general, and administrative
  $ 1,092     $ 1,110       (1.6 )%
Depreciation and amortization
  $ 25,126     $ 20,932       20.0 %
Operating income
  $ 39,628     $ 23,879       66.0 %
Operating days
    19,855       17,652       12.5 %
Average revenue per operating day
  $ 10.40     $ 9.58       8.6 %
Average direct operating costs per operating day
  $ 7.08     $ 6.98       1.4 %
Number of owned rigs at end of period
    361       340       6.2 %
Average number of rigs owned during period
    361       340       6.2 %
Average rigs operating
    216       192       12.5 %
Rig utilization percentage
    60 %     56 %     7.1 %
Capital expenditures
  $ 40,511     $ 26,598       52.3 %
 
   
 
     
 
     
 
 

     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. Revenue per operating day increased as a result of increased pricing for our drilling services resulting from increased demand for our contract drilling services. Significant capital expenditures were incurred during the third quarter of 2004 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 significant capital expenditures, including the acquisition of 19 drilling rigs and related equipment during 2003 and 18 drilling rigs and related equipment acquired during the first quarter of 2004.

                         
Pressure Pumping
  2004
  2003
  % Change
    (dollars in thousands)        
Revenues
  $ 19,663     $ 13,198       49.0 %
Direct operating costs
  $ 10,455     $ 7,226       44.7 %
Selling, general, and administrative
  $ 1,725     $ 1,375       25.5 %
Depreciation
  $ 1,284     $ 1,014       26.6 %
Operating income
  $ 6,199     $ 3,583       73.0 %
Total jobs
    2,200       1,614       36.3 %
Average revenue per job
  $ 8.94     $ 8.18       9.3 %
Average direct operating costs per job
  $ 4.75     $ 4.48       6.0 %
Capital expenditures
  $ 3,508     $ 2,880       21.8 %
 
   
 
     
 
     
 
 

     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 in the quarter was largely due to the Company’s expanded operations in the Appalachian regions of Kentucky, Tennessee and West Virginia, as well as increased demand for our services resulting from the sustained high natural gas prices during 2004. Increased pricing for our services resulted in increased average revenue per job. General and administrative expenses increased as a result of the expanding operations of the pressure pumping segment. Increased depreciation expense for the 2004 quarter was largely due to the expansion of the pressure pumping segment during 2003 and 2004 and related expenditures to acquire necessary equipment to facilitate the growth. Capital expenditures increased in 2004 compared to 2003 due to further expansion of services into Tennessee and Wyoming as well as equipment modifications and upgrades.

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Drilling and Completion Fluids
  2004
  2003
  % Change
    (dollars in thousands)        
Revenues
  $ 23,455     $ 19,580       19.8 %
Direct operating costs
  $ 19,851     $ 17,180       15.5 %
Selling, general, and administrative
  $ 1,965     $ 1,870       5.1 %
Depreciation and amortization
  $ 539     $ 575       (6.3 )%
Operating income (loss)
  $ 1,100     $ (45 )     N/A %
Total jobs
    550       459       19.8 %
Average revenue per job
  $ 42.65     $ 42.66       %
Average direct operating costs per job
  $ 36.09     $ 37.43       (3.6 )%
Capital expenditures
  $ 354     $ 282       25.5 %

     Revenues and direct operating costs increased during the third quarter of 2004 compared to the third quarter of 2003 primarily as a result of the increased number of jobs.

                         
Oil and Natural Gas Production and Exploration
  2004
  2003
  % Change
    (dollars in thousands, except sales prices)        
Revenues
  $ 9,602     $ 5,160       86.1 %
Direct operating costs
  $ 1,715     $ 1,138       50.7 %
Selling, general, and administrative
  $ 484     $ 358       35.2 %
Depreciation, depletion and impairment
  $ 3,729     $ 2,084       78.9 %
Operating income
  $ 3,674     $ 1,580       132.5 %
Capital expenditures
  $ 2,739     $ 3,052       (10.3 )%
Average net daily oil production (Bbls)
    1,095       808       35.5 %
Average net daily gas production (Mcf)
    8,203       5,512       48.8 %
Average oil sales price (per Bbl)
  $ 42.60     $ 28.95       47.2 %
Average gas sales price (per Mcf)
  $ 6.13     $ 4.87       25.9 %

     Oil and natural gas revenues and direct operating costs increased in the third quarter of 2004 compared to the third quarter of 2003, primarily due to the acquisition of the oil and natural gas properties acquired in the merger with TMBR during February 2004 and increased market prices received for oil and natural gas during the third quarter of 2004. Depreciation, depletion and impairment expense increased in 2004 as a result of approximately $900,000 of expenses incurred to impair certain oil and natural gas properties during the 2004 quarter and significantly increased production of oil and natural gas as a result of the aforementioned merger with TMBR.

                         
Corporate and Other
  2004
  2003
  % Change
    (in thousands)        
Selling, general, and administrative
  $ 3,043     $ 2,140       42.2 %
Bad debt expense
  $ 192     $ 97       97.9 %
Depreciation and amortization
  $ 111     $ 111       %
Other income from operations
  $ 153     $ 705       (78.3 )%
Interest income
  $ 233     $ 263       (11.4 )%
Interest expense
  $ 75     $ 68       10.3 %
Other income
  $ 56     $ 169       (66.9 )%

     Selling, general and administrative expenses increased as a result of increased professional expenses, and additional compensation expense related to the Company’s issuance of restricted shares to certain key employees of the Company.

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     The following tables summarize operations by business segment for the nine months ended September 30, 2004 and 2003:

                         
Contract Drilling
  2004
  2003
  % Change
    (dollars in thousands)        
Revenues
  $ 573,851     $ 468,609       22.5 %
Direct operating costs
  $ 402,986     $ 353,893       13.9 %
Selling, general, and administrative
  $ 3,267     $ 3,339       (2.2 )%
Depreciation and amortization
  $ 72,375     $ 62,415       16.0 %
Operating income
  $ 95,223     $ 48,962       94.5 %
Operating days
    56,292       51,263       9.8 %
Average revenue per operating day
  $ 10.19     $ 9.14       11.5 %
Average direct operating costs per operating day
  $ 7.16     $ 6.90       3.8 %
Number of owned rigs at end of period
    361       340       6.2 %
Average number of rigs owned during period
    358       334       7.2 %
Average rigs operating
    205       188       9.0 %
Rig utilization percentage
    57 %     56 %     1.8 %
Capital expenditures
  $ 111,871     $ 67,537       65.6 %  

     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. Revenue per operating day increased as a result of increased pricing for our drilling services resulting from increased demand for our contract drilling services. Significant capital expenditures were incurred during the first nine months of 2004 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 significant capital expenditures, including the acquisition of 19 drilling rigs and related equipment during 2003 and 18 drilling rigs and related equipment acquired during the first quarter of 2004.

                         
Pressure Pumping
  2004
  2003
  % Change
    (dollars in thousands)        
Revenues
  $ 48,490     $ 31,509       53.9 %
Direct operating costs
  $ 26,871     $ 18,032       49.0 %
Selling, general, and administrative
  $ 5,182     $ 4,131       25.4 %
Depreciation
  $ 3,650     $ 2,681       36.1 %
Operating income
  $ 12,787     $ 6,665       91.9 %
Total jobs
    5,466       3,921       39.4 %
Average revenue per job
  $ 8.87     $ 8.04       10.3 %
Average direct operating costs per job
  $ 4.92     $ 4.60       7.0 %
Capital expenditures
  $ 14,112     $ 8,999       56.8 %

     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 in 2004 was largely due to the Company’s continued growth in the Appalachian regions of Kentucky, Tennessee and West Virginia, as well as increased demand for our services resulting from the sustained high natural gas prices during 2004. Increased pricing for our services resulted in increased average revenue per job. General and administrative expenses increased as a result of the expanding operations of the pressure pumping segment. Increased depreciation expense during 2004 was largely due to the expansion of the pressure pumping segment during 2003 and 2004 and related expenditures to acquire necessary equipment to facilitate the growth. Capital expenditures increased in 2004 compared to 2003 due to further expansion of services into Tennessee and Wyoming as well as modifications and upgrades to existing equipment and facilities.

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Drilling and Completion Fluids
  2004
  2003
  % Change
    (dollars in thousands)        
Revenues
  $ 65,018     $ 51,431       26.4 %
Direct operating costs
  $ 55,327     $ 45,483       21.6 %
Selling, general, and administrative
  $ 5,550     $ 5,418       2.4 %
Depreciation and amortization
  $ 1,653     $ 1,732       (4.6 )%
Operating income (loss)
  $ 2,488     $ (1,202 )     N/A %
Total jobs
    1,661       1,460       13.8 %
Average revenue per job
  $ 39.14     $ 35.23       11.1 %
Average direct operating costs per job
  $ 33.31     $ 31.15       6.9 %
Capital expenditures
  $ 981     $ 559       75.5 %

     Revenues and direct operating costs increased during the first nine months of 2004 compared to the first nine months of 2003 primarily 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. Average revenue and direct operating costs per job increased as a result of an increase in the number of larger jobs in the Gulf of Mexico.

                         
Oil and Natural Gas Production and Exploration
  2004
  2003
  % Change
    (dollars in thousands, except sales prices)
Revenues
  $ 25,104     $ 16,329       53.7 %
Direct operating costs
  $ 6,051     $ 3,509       72.4 %
Selling, general, and administrative
  $ 1,324     $ 1,090       21.5 %
Depreciation, depletion and impairment
  $ 10,512     $ 6,664       57.7 %
Operating income
  $ 7,217     $ 5,066       42.5 %
Capital expenditures
  $ 9,871     $ 6,899       43.1 %
Average net daily oil production (Bbls)
    1,065       788       35.2 %
Average net daily gas production (Mcf)
    7,728       5,798       33.3 %
Average oil sales price (per Bbl)
  $ 38.37     $ 30.53       25.7 %
Average gas sales price (per Mcf)
  $ 5.63     $ 5.20       8.3 %

     Oil and natural gas revenues and direct operating costs increased in 2004 compared to 2003, primarily due to the acquisition of the oil and natural gas properties acquired in the merger with TMBR during February 2004 and increased market prices received for oil and natural gas during the first nine months of 2004. Direct operating costs further increased as a result of approximately $600,000 of dry hole costs incurred during the 2004 period. Depreciation, depletion and impairment expense increased in 2004 primarily as a result of approximately $3.0 million of expenses incurred to impair certain oil and natural gas properties.

                         
Corporate and Other
  2004
  2003
  % Change
    (in thousands)        
Selling, general, and administrative
  $ 7,694     $ 6,582       16.9 %
Bad debt expense
  $ 499     $ 259       92.7 %
Depreciation and amortization
  $ 333     $ 333       %
Other income from operations
  $ 1,528     $ 4,034       (62.1 )%
Interest income
  $ 688     $ 808       (14.9 )%
Interest expense
  $ 205     $ 216       (5.1 )%
Other income
  $ 313     $ 1,829       (82.9 )%

     Selling, general and administrative expenses increased as a result of increased professional expenses, and additional compensation expense related to the Company’s issuance of restricted shares to certain key employees of the Company. In 2003, other income from operations includes a $2.5 million payment received as settlement for contract drilling services previously provided in Mexico by Norton Drilling Company Mexico, Inc., a wholly-owned subsidiary of the Company. The receivable had been reserved as uncollectible at the time of the Company’s acquisition of Norton Drilling Company Mexico, Inc. in 1999. Other income in 2003 includes approximately $1.7 million representing the Company’s pro rata share of the net income of TMBR for that nine month period, using the equity method of accounting.

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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. Historically, oil and natural gas prices and markets have been volatile. Prices are affected by market supply and demand factors as well as actions of state and local agencies, the United States and foreign governments, and international cartels. 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 to $5.45 in 2003 compared to $3.36 in 2002, resulting in an increase in demand for our drilling services. Our average number of rigs operating increased to 188 in 2003 from 126 in 2002. During the third quarter of 2004, the average market price of natural gas was $5.62 per Mcf and our average number of rigs operating increased to 216. 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 contract drilling business experienced many downturns in demand over the last several years. During these periods, there have been substantially more drilling rigs available than necessary to meet demand in most operational and geographic segments of the North American land drilling industry. As a result, drilling contractors have had difficulty sustaining profit margins.

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 significant exposure to interest rate market risk because 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 1.75 % to 2.75%. The applicable rate above LIBOR (1.75% at September 30, 2004) is based upon our trailing twelve-month EBITDA (earnings before interest expense, income taxes, and depreciation, depletion, and amortization expense). Our exposure to interest rate risk due to changes in LIBOR is not expected to be material.

     We conduct limited 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 ten 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

     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 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 Quarterly Report on Form 10-Q, 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 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, 2003, as amended, beginning on page 15.

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

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PART II — OTHER INFORMATION

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.(1)
 
   
3.2
    Amendment to Restated Certificate of Incorporation. (1)
 
   
3.3
    Amended and Restated Bylaws.(2)
 
   
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.*


*   Filed herewith.
 
(1)   Incorporated herein by reference to Item 6(a), “Exhibits and Reports on Form 8-K” to Form 10-Q filed with the Securities and Exchange Commission for the quarterly period ended June 30, 2004.
 
(2)   Incorporated herein by reference to Item 14, “Exhibits, Financial Statement Schedules and Reports on Form 8-K” to Annual Report on Form 10-K filed with the Securities and Exchange Commission for the fiscal year ended December 31, 2001.

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Table of Contents

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 Financial and Accounting Officer)
Vice President, Chief Financial Officer,
Secretary and Treasurer 
 
 

DATED: October 29, 2004

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