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PATTERSON UTI ENERGY INC - Annual Report: 2004 (Form 10-K)

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K
     
(Mark One)
   
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
    For the fiscal year ended December 31, 2004
 
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
(State or other jurisdiction of
incorporation or organization
)
  75-2504748
(I.R.S. Employer
Identification No
.)
     
4510 Lamesa Highway, Snyder, Texas
(Address of principal executive offices)
  79549
(Zip Code)
Registrant’s telephone number, including area code:
(325) 574-6300
Securities Registered Pursuant to 12(b) of the Act:
None
Securities Registered Pursuant to 12(g) of the Act:
(Title of class)
Common Stock, $.01 Par Value
      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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     þ
      Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes þ          No o
      The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2004, the last business day of the registrant’s most recently completed second fiscal quarter was $2,648,551,638, calculated by reference to the closing price of $16.67 for the common stock on the Nasdaq National Market on that date.
      As of February 24, 2005, the registrant had outstanding 168,651,600 shares of common stock, $.01 par value, its only class of voting common stock.
      Documents incorporated by reference:
      Definitive Proxy Statement for the 2005 Annual Meeting of Stockholders (Part III).
 
 


TABLE OF CONTENTS

PART I
Items 1 and 2. Business and Properties.
Item 3. Legal Proceedings.
Item 4. Submission of Matters to a Vote of Security Holders.
PART II
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities.
Item 6. Selected Financial Data.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Item 9A. Controls and Procedures.
Item 9B. Other Information
PART III
Item 10. Directors and Executive Officers of the Registrant.
Item 11. Executive Compensation.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Item 13. Certain Relationships and Related Transactions.
Item 14. Principal Accountant Fees and Services.
PART IV
Item 15. Exhibits and Financial Statement Schedule.
SIGNATURES
EXHIBIT INDEX
Asset Purchase Agreement
Form of Letter Agreement Regarding Termination
Summary Description of 2003 Cash Bonus Plan
Summary Description of Director Compensation
Subsidiaries
Consent of Independent Accountants - PricewaterhouseCoopers LLP
Consent of Independent Petroleum Engineer - M. Brian Wallace, P.E.
Certification of CEO
Certification of CFO
Certification of CEO and CFO - Section 906


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      This Annual Report on Form 10-K (including documents incorporated by reference herein) contains statements with respect to our expectations and beliefs as to future events. These types of statements are “forward-looking” and subject to uncertainties. Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under the heading: “Forward Looking Statements and Cautionary Statements for Purposes of the ’Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995” beginning on page 14.
      This Annual Report on Form 10-K, along with our Quarterly Reports on Form  10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, are available through our Internet website (www.patenergy.com) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
PART I
Items 1 and 2. Business and Properties.
Overview
      Based on publicly available information, we believe we are the second largest owner of land-based drilling rigs in North America. The Company was formed in 1978 and reincorporated in 1993 as a Delaware corporation. Our contract drilling business operates primarily in:
  •  Texas,
 
  •  New Mexico,
 
  •  Oklahoma,
 
  •  Louisiana,
 
  •  Mississippi,
 
  •  Colorado,
 
  •  Utah,
 
  •  Wyoming, and
 
  •  Western Canada (Alberta, British Columbia and Saskatchewan).
      As of December 31, 2004, we had a drilling fleet of 361 drilling rigs. A drilling rig includes the structure, power source and machinery necessary to cause a drill bit to penetrate earth to a depth desired by the customer.
      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 of West Texas, South Texas, Southeastern New Mexico, Utah and Mississippi.
Patterson/ UTI Merger
      Patterson Energy, Inc. and UTI Energy Corp. consummated a merger on May 8, 2001. The transaction was treated as a reorganization within the meaning of Section 368 (a) of the Internal Revenue Code of 1986, as amended, and accounted for as a pooling of interests for financial accounting purposes. Historical financial statements and related financial and statistical data contained in this Report have been restated to provide for the retroactive effect of the merger.

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Industry Segments
      Our revenues, operating results and identifiable operating assets are attributable to four industry segments:
  •  contract drilling,
 
  •  pressure pumping services,
 
  •  drilling and completion fluids services, and
 
  •  oil and natural gas development, exploration, acquisition and production.
      With respect to these four segments:
  •  the contract drilling segment had operating profits in 2004, 2003 and 2002,
 
  •  the pressure pumping segment had operating profits in 2004, 2003 and 2002,
 
  •  the drilling and completion fluids segment had an operating profit in 2004 and operating losses in 2003 and 2002, and
 
  •  the oil and natural gas segment had operating profits in 2004, 2003 and 2002.
      See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 16 of Notes to Consolidated Financial Statements included as a part of Items 7 and 8, respectively, of this Report for financial information pertaining to these industry segments.
Contract Drilling Operations
      General — We market our contract drilling services to major and independent oil and natural gas operators. As of December 31, 2004, we owned 361 drilling rigs which were based in the following regions:
  •  149 in the Permian Basin region (West Texas and Southeastern New Mexico),
 
  •  55 in South Texas,
 
  •  42 in the Ark-La-Tex region and Mississippi,
 
  •  77 in the Mid-Continent region (Oklahoma and North Central Texas),
 
  •  21 in the Rocky Mountain region (Colorado, Utah and Wyoming), and
 
  •  17 in Western Canada (Alberta, British Columbia and Saskatchewan).
      Our drilling rigs have rated maximum depth capabilities ranging from 4,000 feet to 30,000 feet. Of our drilling rigs, 40 are SCR electric rigs and 321 are mechanical rigs. An electric rig differs from a mechanical rig in that the electric rig converts the diesel power (the sole energy source for a mechanical rig) into electricity to power the rig.
      Drilling rigs are typically equipped with:
  •  engines,
 
  •  drawworks or hoists,
 
  •  derricks or masts,
 
  •  pumps to circulate the drilling fluid,
 
  •  blowout preventers,
 
  •  drill string (pipe), and
 
  •  other related equipment.

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      Over time, components on a drilling rig are replaced or rebuilt. We spend significant funds each year on an ongoing program to modify and upgrade our drilling rigs to ensure that our drilling equipment is well maintained and competitive. During fiscal years 2004, 2003 and 2002, we spent approximately $158 million, $95 million and $69 million, respectively, on capital improvements to modify and upgrade our drilling rigs.
      Depth of the well and drill site conditions are the principal factors in determining the size of drilling rig used for a particular job. We use our rigs for developmental and exploratory drilling and they are capable of vertical or horizontal drilling.
      Our contract drilling operations depend on the availability of:
  •  drill pipe,
 
  •  bits,
 
  •  replacement parts and other related rig equipment,
 
  •  fuel, and
 
  •  qualified personnel,
some of which have been in short supply from time to time.
      Drilling Contracts — Most of our drilling contracts are with established customers on a competitive bid or negotiated basis. Typically, the contracts are short-term to drill a single well or a series of wells.
      The drilling contracts obligate us to provide and operate a drilling rig and to pay certain operating expenses, including wages of drilling personnel and necessary maintenance expenses. The contracts are generally subject to termination by the customer on short notice. We generally indemnify our customers against claims by our employees and claims that might arise from surface pollution caused by spills of fuel, lubricants and other solvents within our control. The customers generally indemnify us against claims that might arise from other surface and subsurface pollution, except claims that might arise from our gross negligence.
      The contracts provide for payment on a daywork, footage, or turnkey basis, or a combination thereof. In each case, we provide the rig and crews. Our bid for each contract depends upon:
  •  location, depth and anticipated complexity of the well,
 
  •  on-site drilling conditions,
 
  •  equipment to be used,
 
  •  estimated risks involved,
 
  •  estimated duration of the job,
 
  •  availability of drilling rigs, and
 
  •  other factors particular to each proposed well.
Daywork Contracts
      Under daywork contracts, we provide the drilling rig and crew to the customer. The customer supervises the drilling of the well. Our compensation is based on a contracted rate per day during the period the drilling rig is utilized. We generally receive a lower rate when the drilling rig is moving, or when drilling operations are interrupted or restricted by conditions beyond our control. In addition, daywork contracts typically provide separately for mobilization of the drilling rig.
Footage Contracts
      Under footage contracts, we contract to drill a well to a certain depth under specified conditions for a fixed price per foot. The customer provides drilling fluids, casing, cementing and well design expertise. These

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contracts require us to bear the cost of services and supplies that we provide until the well has been drilled to the agreed depth. If we drill the well in less time than estimated, we have the opportunity to improve our profits over those that would be attainable under a daywork contract. Profits are reduced and losses may be incurred if the well requires more days to drill to the contracted depth than estimated. Footage contracts generally contain greater risks for a drilling contractor than daywork contracts. Under footage contracts, the drilling contractor assumes certain risks associated with loss of the well from fire, blowouts and other risks.
Turnkey Contracts
      Under turnkey contracts, we contract to drill a well to a certain depth under specified conditions for a fixed fee. In a turnkey arrangement, we are required to bear the costs of services, supplies and equipment beyond those typically provided under a footage contract. In addition to the drilling rig and crew, we are required to provide the drilling and completion fluids, casing, cementing, and the technical well design and engineering services during the drilling process. We also assume certain risks associated with drilling the well such as fires, blowouts, cratering of the well bore and other such risks. Compensation occurs only when the agreed scope of the work has been completed which requires us to make larger up-front working capital commitments prior to receiving payments under a turnkey drilling contract. Under a turnkey contract, we have the opportunity to improve our profits if the drilling process goes as expected and there are no complications or time delays. However, given the increased exposure we have under a turnkey contract, profits can be significantly reduced and losses incurred if complications or delays occur during the drilling process. Turnkey contracts generally involve the highest degree of risk among the three different types of drilling contracts: daywork, footage and turnkey.
      Revenues by Contract Type — Information regarding our contract drilling activity for the last three years follows:
                         
    Years Ended December 31,
     
Type of Revenues   2004   2003   2002
             
Daywork
    88 %     83 %     82 %
Footage
    6       7       11  
Turnkey
    6       10       7  
      Contract Drilling Activity — Information regarding our contract drilling activity for the last three years follows:
                         
    Years Ended December 31,
     
    2004   2003   2002
             
Average rigs owned
    359       336       323  
Average rigs operating(1)
    211       188       126  
Average rig utilization rate
    59 %     56 %     39 %
Number of rigs operated
    259       226       230  
Number of wells drilled
    3,534       3,017       2,012  
 
(1)  A rig is operating when it is drilling, being moved, assembled, dismantled or otherwise earning revenue under contract.
      Drilling Rigs and Related Equipment — Certain drilling rig information as of December 31, 2004 follows:
                   
Depth Rating (Ft.)   Mechanical   Electric
         
4,000 to 9,999
    63        
10,000 to 11,999
    68       2  
12,000 to 14,999
    126       7  
15,000 to 30,000
    64       31  
             
 
Totals
    321       40  
             

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      At December 31, 2004, we owned 288 trucks and 360 trailers used to rig down, transport and rig up our drilling rigs. This reduces our dependency upon third parties for these services and enhances the efficiency of our contract drilling operations particularly in periods of high drilling rig utilization.
      Most repair and overhaul work to our drilling rig equipment is performed at our yard facilities located in Texas, New Mexico, Oklahoma, Utah and Western Canada.
Pressure Pumping Operations
      General — We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. Pressure pumping services are primarily well stimulation and cementing for the completion of new wells and remedial work on existing wells. Most wells drilled in the Appalachian Basin require some form of fracturing or other stimulation to enhance the flow of oil and natural gas by pumping fluids under pressure into the well bore. Generally, Appalachian Basin wells require cementing services before production commences. The cementing process inserts material between the wall of the well bore and the casing to center and stabilize the casing.
      Equipment — Our pressure pumping equipment at December 31, 2004 follows:
  •  23 cement pumper trucks,
 
  •  26 fracturing pumper trucks,
 
  •  24 nitrogen pumper trucks,
 
  •  13 blender trucks,
 
  •  12 bulk acid trucks,
 
  •  28 bulk cement trucks,
 
  •  8 bulk nitrogen trucks,
 
  •  35 bulk sand trucks,
 
  •  11 connection trucks, and
 
  •  3 acid pumper trucks.
Drilling and Completion Fluids Operations
      General — 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. We serve our offshore customers through six stockpoint facilities located along the Gulf of Mexico in Texas and Louisiana and our land-based customers through eleven stockpoint facilities in Texas, Louisiana, Oklahoma and New Mexico.
      Drilling Fluids — Drilling fluid products and systems are used to cool and lubricate the bit during drilling operations, contain formation pressures (thereby minimizing blowout risk), suspend and remove rock cuttings from the hole and maintain the stability of the wellbore. Technical services are provided to ensure that the products and systems are applied effectively to optimize drilling operations.
      Completion Fluids — After a well is drilled, the well casing is set and cemented into place. At that point, the drilling fluid services are complete and the drilling fluids are circulated out of the well and replaced with completion fluids. Completion fluids, also known as clear brine fluids, are solids-free, clear salt solutions that have high specific gravities. Combined with a range of specialty chemicals, these fluids are used to control bottom-hole pressures and to meet specific corrosion, inhibition, viscosity and fluid loss requirements.

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      Raw Materials — Our drilling and completion fluids operations depend on the availability of the following raw materials:
         
Drilling   Completion
     
barite
    calcium chloride  
bentonite
    calcium bromide zinc bromide  
      We obtain these raw materials through purchases made on the spot market and supply contracts with producers of these raw materials.
      Barite Grinding Facility — We own and operate a barite grinding facility with two barite grinding mills in Houma, Louisiana. This facility allows us to grind raw barite into the powder additive used in drilling fluids.
      Other Equipment — We own 20 trucks and 71 trailers and lease another 22 trucks which are used to transport drilling and completion fluids and related equipment.
Oil and Natural Gas Operations
      General — We are engaged in the development, exploration, acquisition and production of oil and natural gas. Our oil and natural gas business operates primarily in producing regions of West Texas, South Texas, Southeastern New Mexico, Utah and Mississippi. We significantly expanded our oil and natural gas operations in 2004 through our acquisition of TMBR/ Sharp Drilling, Inc. (“TMBR”). The oil and natural gas assets acquired in the acquisition of TMBR included both proved reserves and undeveloped properties. Management is assessing the acquired undeveloped prospects and will make determinations as to the extent future capital will be expended to develop those prospects. We also selectively acquire leasehold acreage and producing properties.
      Oil and Natural Gas Reserves — Estimates, derived from reserve reports provided by M. Brian Wallace, an independent petroleum engineer, of our proved reserves and estimated future net revenues from our proved reserves as of December 31, 2004, 2003 and 2002 are in the table below. The estimates were based upon production histories, current market prices for oil and natural gas, and other geologic, ownership and engineering data provided by us. The present values (discounted at 10% before income taxes) of estimated future net revenues shown in the table are not intended to represent the current market value of the estimated oil and natural gas reserves. For further information concerning the present value of estimated future net revenues from these proved reserves, see Note 20 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.
      Proved oil and natural gas reserves are the estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reserves are considered proved if they are supported by either actual production or conclusive formation tests and future production is determined to be economical.
                           
    As of December 31,
     
    2004   2003   2002
             
    (In thousands)
Proved Reserves:
                       
 
Oil (Bbls)
    1,714       1,147       1,227  
 
Gas (Mcf)
    8,246       5,267       6,240  
 
Total (BOE)
    3,088       2,025       2,267  
Estimated future net revenues before income taxes
  $ 84,952     $ 47,873     $ 46,016  
Present value of estimated future net revenues before income taxes, discounted at 10%
  $ 59,519     $ 34,371     $ 32,308  
Standardized measure of discounted future net cash flows(1)
  $ 37,542     $ 23,950     $ 21,100  
 
(1)  For the calculation of standardized measure of discounted future net cash flows, see Note 20 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

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      A barrel (Bbl) of oil is 42 U.S. gallons and represents the basic unit for measuring production of crude oil and condensate.
      An Mcf of natural gas refers to a volume of 1,000 cubic feet under prescribed conditions of pressure and temperature and represents the basic unit for measuring volumes of produced natural gas. A barrel of equivalent (BOE) in reference to natural gas equivalents is determined using the rate of six Mcf of natural gas to one Bbl of crude oil or condensate.
      Production — At December 31, 2004, we held a working interest in 440 productive wells, of which 266 were considered oil and 174 were considered natural gas. A productive well is a well producing oil or natural gas in commercial quantities. A working interest is the operating interest under an oil or natural gas lease which gives the owner the right to explore for and produce oil or natural gas from the lease. We were the operator of 199 of these productive wells at December 31, 2004. The following table sets forth our average net oil and natural gas production, average sales price and average production costs. Production costs are costs incurred to operate and maintain our wells and related equipment. These costs include labor, well service and repair, utilities, field supervision, property taxes, production and severance taxes and related charges.
                           
    Years Ended December 31,
     
    2004   2003   2002
             
Average net daily production:
                       
 
Oil (Bbls)
    1,071       788       794  
 
Gas (Mcf)
    7,429       5,656       5,109  
 
Total (BOE)
    2,309       1,731       1,646  
Average sales prices:
                       
 
Oil (per Bbl)
  $ 39.12     $ 30.54     $ 25.02  
 
Gas (per Mcf)
    5.81       4.97       2.91  
Average production costs (per BOE)
  $ 7.18     $ 5.51     $ 5.11  
      Productive Wells — The number of productive wells in which we held a working interest as of December 31, 2004 are in the table below. One or more completions in the same well bore are reflected as one well.
                   
    Productive
    Wells
     
    Gross   Net
         
Oil
    266       53.26  
Gas
    174       24.65  
             
 
Total
    440       77.91  
             

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      Developed and Undeveloped Acreage — Developed and undeveloped acreage in which we owned a working interest at December 31, 2004 follows:
                                   
    Developed   Undeveloped
    Acreage   Acreage
         
Location   Gross   Net   Gross   Net
                 
Texas     74,379       14,027       40,484       10,551  
Kansas
    320       45              
Louisiana
    1,920       96              
New York
    160       131              
New Mexico
    19,959       3,943       23,693       3,943  
Mississippi
    2,920       668       8,366       1,840  
Oklahoma
    640       19              
Pennsylvania
    880       129              
Utah
                13,292       1,994  
                         
 
Total
    101,178       19,058       85,835       18,328  
                         
      Undeveloped acreage is leased acres on which wells have not been drilled to a point that would permit production of commercial quantities of oil and natural gas. Developed acreage is leased acres that have been assigned to productive wells. Our gross acreage is the total number of acres in which we own a working interest, regardless of the size of our working interest in the acreage. Our net acreage is the gross acreage proportionally reduced to our working interest percentage in the acreage.
      Many of our leases summarized in the table above as undeveloped acreage will expire at the end of their respective primary terms unless production has been obtained from the acreage prior to that date. If production is obtained, the lease will remain in effect until the cessation of production. Undeveloped acreage subject to leases summarized in the table above are scheduled to expire as follows:
                   
    Lease Acres
    Expiring
     
    Gross   Net
         
Year ending:
               
December 31, 2005
    29,865       5,711  
December 31, 2006
    16,281       3,693  
December 31, 2007 and later
    39,689       8,924  
             
 
Total
    85,835       18,328  
             
      Drilling Activities — The results of our participation in the drilling of developmental and exploratory wells during 2004, 2003 and 2002 follows:
                                                                 
    Developmental Wells   Exploratory Wells
         
    Productive   Dry Holes   Productive   Dry Holes
                 
    Gross   Net   Gross   Net   Gross   Net   Gross   Net
                                 
Year ending:
                                                               
December 31, 2004
    22       4.55                   10       2.01       6       1.71  
December 31, 2003
    27       4.58       11       2.52       12       1.99       4       0.88  
December 31, 2002
    24       4.17       11       2.67       6       0.56       1       0.25  
      In addition, we were participating in nine wells, 1.92 net, that were being drilled at December 31, 2004.
      Generally, a developmental well is a well that is drilled into an oil and natural gas reservoir that is known to be productive. An exploratory well is a well that is drilled to find oil and natural gas in an unproved area.

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Customers
      The customers of each of our four business segments are oil and natural gas operators or purchasers of these commodities. Our customer base includes both major and independent oil and natural gas operators. During 2004, no single customer accounted for 10% or more of our consolidated operating revenues.
Competition
      Contract Drilling and Pressure Pumping Businesses — Our land drilling and pressure pumping businesses are highly competitive. Often times, available land drilling rigs and pressure pumping equipment exceed the demand for such equipment. The equipment can also be moved from one market to another in response to market conditions.
      Drilling and Completion Fluids Business — The drilling and completion fluids industry is highly competitive and price is generally the most important factor. Other competitive factors include the availability of chemicals and experienced personnel, the reputation of the fluids services provider in the drilling industry and relationships with customers. Some of our competitors have substantially more resources and longer operating histories than we have.
      Oil and Natural Gas Business — There is substantial competition for the acquisition of oil and natural gas leases suitable for development and exploration and for experienced personnel. Our competitors in this business include:
  •  major integrated oil and natural gas operators,
 
  •  independent oil and natural gas operators, and
 
  •  drilling and production purchase programs.
      Our ability to increase our oil and natural gas reserves in the future is directly dependent upon our ability to select, acquire and develop suitable prospects. Many of our competitors have facilities and financial and human resources greater than ours.
Government and Environmental Regulation
      All of our operations and facilities are subject to numerous Federal, state, foreign, and local laws, rules and regulations related to various aspects of our business, including:
  •  drilling of oil and natural gas wells,
 
  •  containment and disposal of hazardous materials, oilfield waste, other waste materials and acids,
 
  •  use of underground storage tanks, and
 
  •  use of underground injection wells.
      To date, applicable environmental laws and regulations have not required the expenditure of significant resources. We do not anticipate any material capital expenditures for environmental control facilities or extraordinary expenditures to comply with environmental rules and regulations in the foreseeable future. However, compliance costs under existing laws or under any new requirements could become material and we could incur liability in any instance of noncompliance.
      Our business is generally affected by political developments and by Federal, state, foreign, and local laws and regulations, which relate to the oil and natural gas industry. The adoption of laws and regulations affecting the oil and natural gas industry for economic, environmental and other policy reasons could increase costs relating to drilling and production. They could have an adverse effect on our operations. Several state and Federal environmental laws and regulations currently apply to our operations and may become more stringent in the future.
      We use operating and disposal practices that are standard in the industry. However, hydrocarbons and other materials may have been disposed of or released in or under properties currently or formerly owned or

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operated by us or our predecessors. In addition, some of these properties have been operated by third parties over whom we have no control of their treatment of hydrocarbon and other materials or the manner in which they may have disposed of or released such materials.
      The Federal Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended, commonly known as CERCLA, and comparable state statutes impose strict liability on:
  •  owners and operators of sites, and
 
  •  persons who disposed of or arranged for the disposal of “hazardous substances” found at sites.
      The Federal Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes govern the disposal of “hazardous wastes.” Although CERCLA currently excludes petroleum from the definition of “hazardous substances,” and RCRA also excludes certain classes of exploration and production wastes from regulation, such exemptions by Congress under both CERCLA and RCRA may be deleted, limited, or modified in the future. If such changes are made to CERCLA and/or RCRA, we could be required to remove and remediate previously disposed of materials (including materials disposed of or released by prior owners or operators) from properties (including ground water contaminated with hydrocarbons) and to perform removal or remedial actions to prevent future contamination.
      The Federal Water Pollution Control Act and the Oil Pollution Act of 1990, as amended, and implementing regulations govern:
  •  the prevention of discharges, including oil and produced water spills, and
 
  •  liability for drainage into waters.
      The Oil Pollution Act is more comprehensive and stringent than previous oil pollution liability and prevention laws. It imposes strict liability for a comprehensive and expansive list of damages from an oil spill into waters from facilities. Liability may be imposed for oil removal costs and a variety of public and private damages. Penalties may also be imposed for violation of Federal safety, construction and operating regulations, and for failure to report a spill or to cooperate fully in a clean-up.
      The Oil Pollution Act also expands the authority and capability of the Federal government to direct and manage oil spill clean-up and operations, and requires operators to prepare oil spill response plans in cases where it can reasonably be expected that substantial harm will be done to the environment by discharges on or into navigable waters. We have spill prevention control and countermeasure plans in place for our oil and natural gas properties in each of the areas in which we operate and for each of the stockpoints operated by our drilling and completion fluids business. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party, such as us, to civil or criminal actions. Although the liability for owners and operators is the same under the Federal Water Pollution Act, the damages recoverable under the Oil Pollution Act are potentially much greater and can include natural resource damages.
      Our operations are also subject to Federal, state and local regulations for the control of air emissions. The Federal Clean Air Act, as amended, and various state and local laws impose certain air quality requirements on us. Amendments to the Clean Air Act revised the definition of “major source” such that emissions from both wellhead and associated equipment involved in oil and natural gas production may be added to determine if a source is a “major source.” As a consequence, more facilities may become major sources and thus would be required to obtain operating permits. This permitting process may require capital expenditures in order to comply with permit limits.
Risks and Insurance
      Our operations are subject to the many hazards inherent in the drilling business, including:
  •  accidents at the work location,
 
  •  blow-outs,
 
  •  cratering,

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  •  fires, and
 
  •  explosions.
      These hazards could cause:
  •  personal injury or death,
 
  •  suspension of drilling operations, or
 
  •  serious damage or destruction of the equipment involved and, in addition to environmental damage, could cause substantial damage to producing formations and surrounding areas.
      Damage to the environment, including property contamination in the form of either soil or ground water contamination, could also result from our operations, particularly through:
  •  oil or produced water spillage,
 
  •  natural gas leaks, and
 
  •  fires.
      In addition, we could become subject to liability for reservoir damages. The occurrence of a significant event, including pollution or environmental damages, could materially affect our operations and financial condition.
      As a protection against operating hazards, we maintain insurance coverage we believe to be adequate, including:
  •  all-risk physical damages,
 
  •  employer’s liability,
 
  •  commercial general liability, and
 
  •  workers compensation insurance.
      We believe that we are adequately insured for public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of:
  •  personal injury,
 
  •  well disasters,
 
  •  extensive fire damage,
 
  •  damage to the environment, or
 
  •  other hazards.
      We also carry insurance coverage for major physical damage to our drilling rigs. However, we do not carry insurance against loss of earnings resulting from such damage. In view of the difficulties that may be encountered in renewing such insurance at reasonable rates, no assurance can be given that:
  •  we will be able to maintain the type and amount of coverage that we believe to be adequate at reasonable rates, or
 
  •  any particular types of coverage will be available.
      In addition to insurance coverage, we also attempt to obtain indemnification from our customers for certain risks. These indemnity agreements typically require our customers to hold us harmless in the event of loss of production or reservoir damage. These contractual indemnifications may not be supported by adequate insurance maintained by the customer.

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Employees
      We employed approximately 6,800 full-time persons (300 office personnel and 6,500 field personnel) at December 31, 2004. The number of field employees fluctuates depending on the current and expected demand for our services. We consider our employee relations to be satisfactory. None of our employees are represented by a union.
Seasonality
      Seasonality does not significantly affect our overall operations. However, our pressure pumping division in Appalachia and our drilling operations in Canada are subject to slow periods of activity during the Spring thaw. In addition, our drilling operations in Canada are subject to slow periods of activity during the Fall.
Raw Materials and Subcontractors
      We use many suppliers of raw materials and services. These materials and services have historically been available, although there is no assurance that such materials and services will continue to be available on favorable terms or at all. We also utilize numerous independent subcontractors from various trades.
Incorporation by Reference
      The various factors disclosed under the caption “Forward Looking Statements and Cautionary Statements for Purposes of the ’Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995,” beginning on page 14 of this Report, are incorporated by this reference into Items 1 and 2 of this Report. Readers of this Report should review those factors in conjunction with their review of Items 1 and 2.
Corporate Headquarters, Field Offices and Other Facilities
      Our corporate headquarters are located in Snyder, Texas. We also have a number of offices, yards and stockpoint facilities located in our various operating areas.
      Our corporate headquarters are located at 4510 Lamesa Highway, Snyder, Texas, and our telephone number at that address is (325) 574-6300. There are a number of improvements at our headquarters, including:
  •  office buildings with approximately 34,000 square feet of office space and storage,
 
  •  a shop facility with approximately 7,000 square feet used for drilling equipment repairs and metal fabrication,
 
  •  a truck shop facility with approximately 10,000 square feet used to maintain, overhaul and repair our truck fleet,
 
  •  an engine shop facility with approximately 20,000 square feet used to overhaul and repair the engines that power our drilling rigs, and
 
  •  an open-ended metal storage facility with approximately 10,000 square feet.
      We have regional administrative offices, yards and stockpoint facilities in many of the areas in which we operate. The facilities are primarily used to support day-to-day operations, including the repair and maintenance of equipment as well as the storage of equipment, inventory and supplies and to facilitate administrative responsibilities and sales.
      Contract Drilling Operations — Our drilling services are supported by several administrative offices and yard facilities located throughout our areas of operations including:
  •  Texas,
 
  •  New Mexico,
 
  •  Oklahoma,

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  •  Colorado,
 
  •  Utah,
 
  •  Wyoming, and
 
  •  Western Canada.
      Pressure Pumping — Our pressure pumping services are supported by several offices and yard facilities located throughout our areas of operations including:
  •  Pennsylvania,
 
  •  Ohio,
 
  •  West Virginia,
 
  •  Kentucky,
 
  •  Wyoming, and
 
  •  Tennessee.
      Drilling and Completion Fluids — Our drilling and completion fluids services are supported by several administrative offices and stockpoint facilities located throughout our areas of operations including:
  •  Texas,
 
  •  Louisiana,
 
  •  New Mexico, and
 
  •  Oklahoma.
      Oil and Natural Gas — Our oil and natural gas services are supported by administrative and field offices in Texas.
      We own our headquarters in Snyder, Texas, as well as several of our other facilities. We also lease a number of facilities and we do not believe that any one of the leased facilities is individually material to our operations. We believe that our existing facilities are suitable and adequate to meet our needs.
Item 3. Legal Proceedings.
      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.
Item 4. Submission of Matters to a Vote of Security Holders.
      None.

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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
      From time to time, we make written or oral forward-looking statements, including statements contained in this Annual Report on Form 10-K, our other filings with the SEC, press releases and reports to stockholders. These forward-looking statements 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, sources and sufficiency of funds and impact of inflation. The words “believes,” “budgeted,” “expects,” “project,” “will,” “could,” “may,” “plans,” “intends,” “strategy,” or “anticipates,” and similar expressions are used to identify our forward-looking statements. We do not undertake to update, revise, or correct any of our forward-looking information.
      We include the following cautionary statement in accordance with the “Safe Harbor’ provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statement made by us, or on our behalf. The factors identified in this cautionary statement are important factors (but not necessarily all of the important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by us, or on our behalf. Where any such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results. The differences between assumed facts or bases and actual results can be material, depending upon the circumstances.
      Where, in any forward-looking statement, we express an expectation or belief as to the future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there can be no assurance that the statement of expectation or belief will result, or be achieved or accomplished. Taking this into account, the following are identified as important risk factors currently applicable to, or which could readily be applicable to, us:
We are Dependent on the Oil and Natural Gas Industry and Market Prices for Oil and Natural Gas. Declines in Oil and Natural Gas Prices Have Adversely Affected Our Operations.
      Our revenue, profitability and rate of growth are substantially dependent upon prevailing prices for oil and natural gas. For many years, oil and natural gas prices and, therefore, the level of drilling, exploration, development and production, have been extremely volatile. Prices are affected by:
  •  market supply and demand,
 
  •  international military, political and economic conditions, and
 
  •  the ability of the Organization of Petroleum Exporting Countries, commonly known as 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 and $5.95 in 2004 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 and to 211 in 2004. 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.
A General Excess of Operable Land Drilling Rigs Adversely Affects Our Profit Margins Particularly in Times of Weaker Demand.
      The North American land drilling industry has 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. As a result, drilling contractors have had difficulty sustaining profit margins.

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      In addition to adverse effects that future declines in demand could have on us, ongoing factors which could adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include:
  •  movement of drilling rigs from region to region,
 
  •  reactivation of land-based drilling rigs, or
 
  •  construction of new drilling rigs.
      We cannot predict either the future level of demand for our contract drilling services or future conditions in the oil and natural gas contract drilling business.
Shortages of Drill Pipe, Replacement Parts and Other Related Rig Equipment Adversely Affects Our Operating Results.
      During periods of increased demand for drilling services, the industry has experienced shortages of drill pipe, replacement parts and other related rig equipment. These shortages can cause the price of these items to increase significantly and require that orders for the items be placed well in advance of expected use. These price increases and delays in delivery may require us to increase capital and repairs expenditures in our contract drilling segment. Severe shortages could impair our ability to operate our drilling rigs.
The Various Business Segments in Which We Operate Are Highly Competitive with Excess Capacity which may Adversely Affect Our Operating Results.
      Our land drilling and pressure pumping businesses are highly competitive. Often times, available land drilling rigs and pressure pumping equipment exceed the demand for such equipment. This excess capacity has resulted in substantial competition for drilling and pressure pumping contracts. The fact that drilling rigs and pressure pumping equipment are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry.
      We believe that price competition for drilling and pressure pumping contracts will continue for the foreseeable future due to the existence of available rigs and pressure pumping equipment.
      In recent years, many drilling and pressure pumping companies have consolidated or merged with other companies. Although this consolidation has decreased the total number of competitors, we believe the competition for drilling and pressure pumping services will continue to be intense.
      The drilling and completion fluids services industry is highly competitive. Price is generally the most important factor. Other competitive factors include the availability of chemicals and experienced personnel, the reputation of the fluids services provider in the drilling industry and relationships with customers. Some of our competitors have substantially more resources and longer operating histories than we have.
Labor Shortages Adversely Affect Our Operating Results.
      During periods of increasing demand for contract drilling services, the industry experiences shortages of qualified drilling rig personnel. During these periods, our ability to attract and retain sufficient qualified personnel to market and operate our drilling rigs is adversely affected which negatively impacts both our operations and profitability. Operationally, it is more difficult to hire qualified personnel which adversely affects our ability to mobilize inactive rigs in response to the increased demand for our contract drilling services. Additionally, wage rates for drilling personnel are likely to increase, resulting in greater operating costs.
Continued Growth Through Rig Acquisition is Not Assured.
      We have increased our drilling rig fleet over the past several years through mergers and acquisitions. The land drilling industry has experienced significant consolidation over the past several years, and there can be no

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assurance that acquisition opportunities will continue to be available. Additionally, we are likely to continue to face intense competition from other companies for available acquisition opportunities.
      There can be no assurance that we will:
  •  have sufficient capital resources to complete additional acquisitions,
 
  •  successfully integrate acquired operations and assets,
 
  •  effectively manage the growth and increased size,
 
  •  successfully deploy idle or stacked rigs,
 
  •  maintain the crews and market share to operate drilling rigs acquired, or
 
  •  successfully improve our financial condition, results of operations, business or prospects in any material manner as a result of any completed acquisition.
      We may incur substantial indebtedness to finance future acquisitions and also may issue equity securities or convertible securities in connection with any such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and the issuance of additional equity would be dilutive to existing stockholders. Also, continued growth could strain our management, operations, employees and other resources.
The Nature of our Business Operations Presents Inherent Risks of Loss that, if not Insured or Indemnified Against, Could Adversely Affect Our Operating Results.
      Our operations are subject to many hazards inherent in the contract drilling, pressure pumping, and drilling and completion fluids businesses, which in turn could cause personal injury or death, work stoppage, or serious damage to our equipment. Our operations could also cause environmental and reservoir damages. We maintain insurance coverage and have indemnification agreements with many of our customers. However, there is no assurance that such insurance or indemnification agreements would adequately protect us against liability or losses from all consequences of the hazards. Additionally, there can be no assurance that insurance would be available to cover any or all of these risks, or, even if available, that insurance premiums or other costs would not rise significantly in the future, so as to make such insurance prohibitive.
      We have elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. For example, we maintain a $1.0 million per occurrence deductible on our workers’ compensation insurance and our general liability insurance coverages. These levels of self-insurance expose us to increased operating costs and risks.
Violations of Environmental Laws and Regulations Could Materially Adversely Affect Our Operating Results.
      The drilling of oil and natural gas wells is subject to various Federal, state, foreign, and local laws, rules and regulations. The cost of compliance with these laws and regulations could be substantial. Failure to comply with these requirements could expose us to substantial civil and criminal penalties. In addition, Federal law imposes a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages from such spills. As an owner and operator of land-based drilling rigs, we may be deemed to be a responsible party under Federal law. Our operations and facilities are subject to numerous state and Federal environmental laws, rules and regulations, including, without limitation, laws concerning the containment and disposal of hazardous substances, oil field waste and other waste materials, the use of underground storage tanks and the use of underground injection wells.
Some of Our Contract Drilling Services are Done Under Turnkey and Footage Contracts, Which are Financially Risky.
      A portion of our contract drilling is performed under turnkey and footage contracts, which involve significant risks. Under turnkey drilling contracts, we contract to drill a well to a certain depth under specified

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conditions at a fixed price. Under footage contracts, we contract to drill a well to a certain depth under specified conditions at a fixed price per foot. The risk to us under these types of drilling contracts are greater than on a well drilled on a daywork basis. Unlike daywork contracts, we must bear the cost of services until the target depth is reached. In addition, we must assume most of the risk associated with the drilling operations, generally assumed by the operator of the well on a daywork contract, including blowouts, loss of hole from fire, machinery breakdowns and abnormal drilling conditions. Accordingly, if severe drilling problems are encountered in drilling wells under such contracts, we could suffer substantial losses.
Anti-takeover Measures in Our Charter Documents and Under State Law Could Discourage an Acquisition and Thereby Affect the Related Purchase Price.
      We are a Delaware corporation subject to the Delaware General Corporation Law, including Section 203, an anti-takeover law enacted in 1988. We have also enacted certain anti-takeover measures, including a stockholders’ rights plan. In addition, our Board of Directors has the authority to issue up to one million shares of preferred stock and to determine the price, rights (including voting rights), conversion ratios, preferences and privileges of that stock without further vote or action by the holders of the common stock. As a result of these measures and others, potential acquirers might find it more difficult or be discouraged from attempting to effect an acquisition transaction with us. This may deprive holders of our securities of certain opportunities to sell or otherwise dispose of the securities at above-market prices pursuant to any such transactions.

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PART II
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities.
     (a)  Market Information
      Our common stock, par value $0.01 per share, is publicly traded on the Nasdaq National Market and is quoted under the symbol “PTEN.” Our common stock is included in the S&P MidCap 400 Index and several other market indexes. The following table provides high and low sales prices of our common shares for the periods indicated, adjusted to reflect the two-for-one stock split on June 30, 2004:
                 
    High   Low
         
2004:
               
First quarter
  $ 19.20     $ 15.75  
Second quarter
    19.56       14.52  
Third quarter
    19.88       15.69  
Fourth quarter
    20.45       17.85  
2003:
               
First quarter
  $ 17.75     $ 13.55  
Second quarter
    18.49       15.90  
Third quarter
    16.14       12.58  
Fourth quarter
    16.97       12.84  
     (b)  Holders
      As of January 24, 2005, there were approximately 940 holders of record and approximately 48,000 beneficial holders of our common shares.
     (c)  Dividends and Buyback Program
      No dividend was declared or paid in 2003. On April 28, 2004, our Board of Directors approved the initiation of a quarterly cash dividend of $0.02 on each share of our common stock which was paid on June 2, 2004. Quarterly cash dividends in the amount of $0.02 per share were also paid on September 1, 2004 and December 1, 2004. Total cash dividends paid in 2004 were approximately $10 million. In February 2005, our Board of Directors approved an increase in the quarterly cash dividend on our common stock to $0.04 per share form $0.02 per share. The next quarterly cash dividend is to be paid to holders of record on February 28, 2005 and paid on March 4, 2005. On April 28, 2004, our Board of Directors authorized a two-for-one stock split in the form of a stock dividend which was distributed on June 30, 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, terms of our credit facilities and other factors.
      On June 7, 2004, our Board of Directors authorized a stock buyback program for the purchase of up to $30 million of our outstanding common stock. Repurchases may be made from time to time as, in the opinion of management, market conditions warrant, in the open market or in privately negotiated transactions. We did not repurchase any of our shares in the fourth quarter of 2004.

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     (d)  Securities Authorized for Issuance Under Equity Compensation Plans
      Equity compensation to our employees, officers and directors as of December 31, 2004 follows:
                           
    Equity Compensation Plan Information
     
        Number of
    Number of       Securities
    Securities to   Weighted-   Remaining Available
    be Issued upon   Average Exercise   for Future Issuance
    Exercise of   Price of   under Equity
    Outstanding   Outstanding   Compensation Plans
    Options,   Options,   (Excluding
    Warrants and   Warrants and   Securities Reflected
Plan Category   Rights   Rights   in Column(a))
             
    (a)   (b)   (c)
Equity compensation plans approved by security holders
    8,635,720     $ 12.64       3,482,992 (1)
Equity compensation plans not approved by security holders(2)
    1,370,322     $ 9.74       78,161  
                   
 
Total
    10,006,042     $ 12.24       3,561,153  
                   
 
(1)  The Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan, as amended, allows for the grant of restricted shares and performance awards, in addition to stock options and stock appreciation rights, to key employees, officers and directors, which are subject to certain vesting and forfeiture provisions. Of the securities remaining available for future issuance under equity compensation plans approved by security holders in column (c), there are 2,997,992 securities available under this plan.
 
(2)  The Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan was approved by the Board of Directors in July 2001. The terms of the Plan provide for grants of stock options, stock appreciation rights, shares of restricted stock and performance awards to eligible employees other than officers and directors. No Incentive Stock Options may be awarded under the Plan. All options are granted with an exercise price equal to or greater than the fair market value of the common stock at the time of grant. The vesting schedule and term are set by the Compensation Committee of the Board of Directors.
 
     In July 2001, the Board of Directors approved option grants, not included in any of the stock option plans, for two non-employee directors. Each of the two non-employee directors was granted an option to purchase 24,000 shares of our common stock at an exercise price greater than the fair market value of our common stock on the grant date. The options vested in November 2001 and expire in November 2005. As of December 31, 2004, one of these options to purchase 24,000 shares of our common stock was outstanding.

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Item 6. Selected Financial Data.
      Our selected consolidated financial data as of December 31, 2004, 2003, 2002, 2001 and 2000, and for each of the five years then ended should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and related Notes thereto, included as Items 7 and 8, respectively, of this Report. The historical financial data presented below, has been restated to provide for (i) the retroactive effect of the merger with UTI Energy Corp., on May  8, 2001; (ii) the retroactive application of the equity method of accounting for our investment in TMBR and (iii) a two-for-one stock split that occurred in 2004. Certain reclassifications have been made to the historical financial data to conform with the 2004 presentation.
                                             
    Years Ended December 31,
     
    2004   2003   2002   2001   2000
                     
    (In thousands)
Income Statement Data:
                                       
Operating revenues:
                                       
 
Contract drilling
  $ 809,691     $ 639,694     $ 410,295     $ 839,931     $ 512,998  
 
Pressure pumping
    66,654       46,083       32,996       39,600       21,465  
 
Drilling and completion fluids
    90,557       69,230       69,943       94,456       32,053  
 
Oil and natural gas
    33,867       21,163       14,723       15,988       15,806  
                               
   
Total
    1,000,769       776,170       527,957       989,975       582,322  
                               
Operating costs and expenses:
                                       
 
Contract drilling
    556,869       475,224       318,201       487,343       384,840  
 
Pressure pumping
    37,561       26,184       19,802       21,146       13,403  
 
Drilling and completion fluids
    76,503       61,424       60,762       80,034       26,545  
 
Oil and natural gas
    7,978       4,808       3,956       5,190       4,872  
 
Depreciation, depletion, amortization and impairment
    119,395       97,998       91,216       86,159       61,464  
 
General and administrative
    32,007       27,709       26,140       28,561       22,190  
 
Bad debt expense
    897       259       320       2,045       570  
 
Merger costs
                      5,943        
 
Restructuring and other charges
          (2,452 )     4,700       7,202        
 
Other
    (1,655 )     (2,174 )     (538 )     (820 )     (147 )
                               
   
Total
    829,555       688,980       524,559       722,803       513,737  
                               
Operating income
    171,214       87,190       3,398       267,172       68,585  
                               
Other income (expense)
    680       2,694       803       (677 )     (8,481 )
Income before income taxes and cumulative effect of change in accounting principle
    171,894       89,884       4,201       266,495       60,104  
Income tax expense
    63,161       32,996       1,827       102,333       22,878  
                               
Income before cumulative effect of change in accounting principle
    108,733       56,888       2,374       164,162       37,226  
Cumulative effect of change in accounting principle, net of related income tax benefit of approximately $287
          (469 )                  
                               
Net income
  $ 108,733     $ 56,419     $ 2,374     $ 164,162     $ 37,226  
                               

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    Years Ended December 31,
     
    2004   2003   2002   2001   2000
                     
        (In thousands, except per share amounts)    
Net income per common share:
                                       
 
Basic:
                                       
   
Income before cumulative effect of change in accounting principle
  $ 0.65     $ 0.35     $ 0.02     $ 1.07     $ 0.26  
                               
   
Cumulative effect of change in accounting principle
  $     $  —     $     $  —     $  
                               
   
Net income
  $ 0.65     $ 0.35     $ 0.02     $ 1.07     $ 0.26  
                               
 
Diluted:
                                       
   
Income before cumulative effect of change in accounting principle
  $ 0.64     $ 0.35     $ 0.01     $ 1.04     $ 0.25  
                               
   
Cumulative effect of change in accounting principle
  $     $  —     $     $  —     $  
                               
   
Net income
  $ 0.64     $ 0.34     $ 0.01     $ 1.04     $ 0.25  
                               
Cash dividends per common share
  $ 0.06     $     $  —     $     $  
                               
Weighted average number of common shares outstanding:
                                       
 
Basic
    166,258       161,272       157,410       152,814       142,414  
                               
 
Diluted
    169,211       164,572       162,504       158,394       149,682  
                               
Balance Sheet Data:
                                       
Total assets
  $ 1,322,911     $ 1,084,114     $ 942,823     $ 869,642     $ 739,898  
Long-term debt
                            79,416  
Stockholders’ equity
    1,007,539       819,749       737,731       687,142       481,299  
Working capital
    236,957       199,613       167,863       110,172       127,299  
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
      This Item 7 contains forward-looking statements, which are made pursuant to the “Safe Harbor” provisions of the Private Securities Litigation Reform Act of 1995.
      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 years ended December 31, 2004, our operating revenues consisted of the following (dollars in thousands):
                                                 
    2004   2003   2002
             
Contract drilling
  $ 809,691       81 %   $ 639,694       82 %   $ 410,295       78 %
Pressure pumping
    66,654       7       46,083       6       32,996       6  
Drilling and completion fluids
    90,557       9       69,230       9       69,943       13  
Oil and natural gas
    33,867       3       21,163       3       14,723       3  
                                     
    $ 1,000,769       100 %   $ 776,170       100 %   $ 527,957       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,

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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, 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 Texas, 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 361 rigs as of December 31, 2004. Based on publicly available information, we believe we are the second largest owner of land-based drilling rigs in North America. Our most significant transaction occurred in May 2001 when we merged with UTI Energy Corp. in a merger of equals which basically doubled our drilling fleet and added the pressure pumping services business. 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 2004, our average number of rigs operating increased to 211 from 188 in 2003 and our average revenue per operating day increased to $10,470 from $9,300 in 2003. Primarily due to these improved operating results, we experienced an increase of approximately $52 million in consolidated net income in 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” contained on page 14 of this Report.
      Management believes that the liquidity of our balance sheet as of December 31, 2004, which includes approximately $237.0 million in working capital (including $112 million in cash), no long term debt and a $200 million line of credit with availability of $151 million (net of outstanding letters of credit totaling $49 million) provides us with the ability to pursue acquisition opportunities, expand into new regions, make improvements to our property and equipment and survive downturns in our industry.
      Commitments and Contingencies — We have no commitments or contingencies which require disclosure in our financial statements other than letters of credit of approximately $49 million at December 31, 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.
      Net income for the year ended December 31, 2002, includes a charge of $4.7 million related to the financial failure in 2002 of a workers’ compensation insurance carrier that had provided coverage for us in prior years.
      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 and Western Canada. As of December 31, 2004, we owned 361 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

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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 Texas, South Texas, Southeastern New Mexico, Utah and Mississippi.
      The North American land drilling industry has 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. As a result, drilling contractors have had difficulty sustaining profit margins.
      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, and
 
  •  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 — 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 years 2004, 2003 or 2002.
      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

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equipment, lease acquisition costs and intangible development costs, are depreciated, depleted and amortized on the units-of-production method, based on engineering 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 an independent petroleum 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 $3.2 million, $1.4 million and $700,000 for the years ended December 31, 2004, 2003 and 2002, 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. 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, 2004, was based on the segment’s improved operating results in 2004 and on our expectations that these improved results will continue. If the improved results do not continue, 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. 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, 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 received from third parties for out-of-pocket expenses incurred as revenues and account 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 certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures 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.
      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.
      For additional information on our accounting policies, see Note 1 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

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Related Party Transactions
      We operate certain oil and natural gas properties in which certain of our affiliated persons have participated, either individually or through entities they control, in the prospects or properties in which we have an interest. These participations, which have been on a working interest basis, have been in prospects or properties we originated or acquired. At December 31, 2004, affiliated persons were working interest owners in 237 of 300 total wells we operated. We make sales of working interests to reduce our economic risk in the properties. Generally, it is more efficient for us to sell the working interests to these affiliated persons than to market them to unrelated third parties. Sales of working interests were made at cost, including our costs of acquiring and preparing the working interests for sale. These costs were paid by the working interest owners on a pro rata basis based upon their working interest ownership percentage. The price at which working interests were sold to affiliated persons was the same price at which working interests were sold to unaffiliated persons.
      Production revenues and joint interest costs of each of the affiliated persons during 2004 for all wells operated by us in which the affiliated persons have working interests are presented in the table below. These amounts do not necessarily represent their profits or losses from these interests because the joint interest costs do not include the parties’ related drilling and leasehold acquisition costs incurred prior to January 1, 2004. These activities resulted in a payable to the affiliated persons of approximately $1.2 million and $871,000 and a receivable from the affiliated persons of approximately $856,000 and $888,000 at December 31, 2004 and 2003, respectively.
                     
    Year Ended
    December 31, 2004
     
        Joint
    Production   Interest
Name   Revenues(1)   Costs(2)
         
Cloyce A. Talbott
  $ 186,971     $ 42,313  
Anita Talbott(3)
    76,423       22,591  
Jana Talbott, Executrix to the Estate of Steve Talbott(3)
    11,655       2,940  
Stan Talbott(3)
    9,320       4,366  
John Evan Talbott Trust(3)
    3,124       668  
Lisa Beck and Stacy Talbott(3)
    978,607       410,334  
SSI Oil & Gas, Inc.(4)
    163,584       263,123  
IDC Enterprises, Ltd.(5)
    12,019,230       6,462,580  
             
 
Subtotal
    13,448,914       7,208,915  
             
A. Glenn Patterson
    123,583       27,468  
Robert Patterson(6)
    8,476       2,518  
Thomas M. Patterson(6)
    8,476       2,518  
             
 
Subtotal
    140,535       32,504  
             
Jonathan D. Nelson, Chief Financial Officer
    248,297       263,549  
             
   
Total
  $ 13,837,746     $ 7,504,968  
             
 
(1)  Revenues for production of oil and natural gas, net of state severance taxes.
 
(2)  Includes leasehold costs, tangible equipment costs, intangible drilling costs and lease operating expense billed during that period. All joint interest costs have been paid on a timely basis.
 
(3)  Anita Talbott is the wife of Cloyce A. Talbott. Stan Talbott, Lisa Beck and Stacy Talbott are Mr. Talbott’s adult children. Steve Talbott is the deceased son of Mr. Talbott. John Evan Talbott is Mr. Talbott’s grandson.
 
(4)  SSI Oil & Gas, Inc. is beneficially owned 50% by Cloyce A. Talbott and directly owned 50% by A. Glenn Patterson.

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(5)  IDC Enterprises, Ltd. is 50% owned by Cloyce A. Talbott and 50% owned by A. Glenn Patterson.
 
(6)  Robert and Thomas M. Patterson are A. Glenn Patterson’s adult children.
      In 2004, 2003 and 2002, we paid approximately $914,000, $740,000 and $279,000, respectively, to TMP Truck and Trailer LP (“TMP”), an entity owned by Thomas M. Patterson (son of A. Glenn Patterson), for certain equipment and metal fabrication services. Purchases from TMP were at current market prices.
      In 2004 and 2003, we paid approximately $39,000 and $209,000, respectively, to Melco Services (“Melco”) for dirt contracting services and $44,000 and $59,000, respectively, to L&N Transportation (“L&N”) for water hauling services. Both entities are owned by Lance D. Nelson, brother of Jonathan D. Nelson. Purchases from Melco and L&N were at current market prices.
Liquidity and Capital Resources
      As of December 31, 2004, we had working capital of $237.0 million including cash and cash equivalents of $112.4 million. For 2004, our sources of cash flow included:
  •  $222.3 million from operations,
 
  •  $24.5 million from the exercise of stock options and warrants, and
 
  •  $3.3 million from the sale of property and equipment.
      We used approximately $224.1 million:
  •  to make capital expenditures for the betterment and refurbishment of our drilling rigs,
 
  •  for the acquisition and procurement of drilling equipment,
 
  •  to fund capital expenditures for our pressure pumping and drilling and completion fluids divisions, and
 
  •  to fund leasehold acquisition and development and exploration of oil and natural gas properties.
      Additionally, $10.0 million was used to pay quarterly dividends on our common stock, $1.5 million was used to buy 100,000 shares of our common stock pursuant to the stock buyback program authorized by our Board of Directors on June 7, 2004 and issuance costs of $780,000 were incurred during 2004 relating to our new $200 million credit facility. As of December 31, 2004, $1.8 million of cash was pledged as collateral for losses which could become payable under the terms of our workers’ compensation insurance contracts and was therefore restricted as to use.
      In February 2004, we completed the acquisition of TMBR in which one of our wholly-owned subsidiaries acquired 100% of the remaining outstanding shares of TMBR for a net cash payment of $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 our common stock valued at $17.82 per share (adjusted to reflect the two-for-one stock split 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.
      We replaced our prior credit facility in December 2004 with a five-year, $200 million unsecured revolving line of credit (“LOC”). Interest is to be paid on outstanding LOC balances at a floating rate ranging from LIBOR plus 0.625% to 1.0% or the prime rate. This arrangement includes various fees, including a commitment fee on the average daily unused amount (0.15% at December 31, 2004). There are customary restrictions and covenants associated with the LOC. Financial covenants provide for a maximum debt to capitalization ratio and a minimum interest coverage ratio. We do not expect that the restrictions and covenants will restrict our ability to operate or react to opportunities that might arise. Availability under the LOC is reduced by outstanding letters of credit which totaled $49 million at December 31, 2004. There were no outstanding borrowings under the LOC at December 31, 2004. We incurred approximately $445,000 in costs to terminate the previous $100 million credit facility. These costs were expensed in 2004.

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      In December 2004, we entered into an agreement to acquire the U.S. land drilling assets of Key Energy Services, Inc. for approximately $62 million. The assets include 25 active and 10 stacked land-based drilling rigs, related drilling equipment, four yard facilities and a rig moving fleet consisting of approximately 45 trucks and 100 trailers. This transaction was completed in January 2005 using approximately $62 million of cash.
      In February 2005, our Board of Directors approved an increase in the quarterly cash dividend on the Company’s common stock to $0.04 per share from $0.02 per share. The next quarterly cash dividend is to be paid to holders of record on February 28, 2005 and paid on March 4, 2005.
      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 financing or equity financing. However, there can be no assurance that such capital would be available.
Results of Operations
Comparison of the years ended December 31, 2004 and 2003
      A summary of operations by business segment for the years ended December 31, 2004 and 2003 follows:
                         
    Years Ended December 31,
     
Contract Drilling   2004   2003   % Change
             
    (Dollars in thousands)
Revenues
  $ 809,691     $ 639,694       26.6 %
Direct operating costs
  $ 556,869     $ 475,224       17.2 %
Selling, general and administrative
  $ 4,441     $ 4,425       0.4 %
Depreciation
  $ 98,334     $ 84,379       16.5 %
Operating income
  $ 150,047     $ 75,666       98.3 %
Operating days
    77,355       68,798       12.4 %
Average revenue per operating day
  $ 10.47     $ 9.30       12.6 %
Average direct operating costs per operating day
  $ 7.20     $ 6.91       4.2 %
Number of owned rigs at end of period
    361       343       5.2 %
Average number of rigs owned during period
    359       336       6.8 %
Average rigs operating
    211       188       12.2 %
Rig utilization percentage
    59 %     56 %     5.4 %
Capital expenditures
  $ 157,916     $ 95,175       65.9 %
      The market price of natural gas remained high in 2004. In fact, the average market price of natural gas improved to $5.95 per Mcf in 2004 compared to $5.45 per Mcf in 2003, resulting in an increase in demand for our contract drilling services. Our average number of rigs operating increased to 211 in 2004 from 188 in 2003. The average market price of natural gas and our average rigs operating for each of the fiscal quarters in 2004 and 2003 follow:
                                 
    1st   2nd   3rd   4th
    Quarter   Quarter   Quarter   Quarter
                 
2004:
                               
Average natural gas price
  $ 5.64     $ 6.13     $ 5.62     $ 6.42  
Average rigs operating
    197       203       216       229  
2003:
                               
Average natural gas price
  $ 5.91     $ 5.70     $ 4.88     $ 5.29  
Average rigs operating
    176       195       192       191  

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      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 direct operating costs per operating day in 2004. Average revenue per operating day increased as a result of increased demand and pricing for our contract drilling services. Significant capital expenditures were incurred during 2004 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 in 2004 was due primarily to capital expenditures in 2003 and 2004, as well as acquisitions.
                         
    Years Ended December 31,
     
Pressure Pumping   2004   2003   % Change
             
    (Dollars in thousands)
Revenues
  $ 66,654     $ 46,083       44.6 %
Direct operating costs
  $ 37,561     $ 26,184       43.5 %
Selling, general and administrative
  $ 7,234     $ 5,683       27.3 %
Depreciation
  $ 5,112     $ 3,774       35.5 %
Operating income
  $ 16,747     $ 10,442       60.4 %
Total jobs
    7,444       5,667       31.4 %
Average revenue per job
  $ 8.95     $ 8.13       10.1 %
Average direct operating costs per job
  $ 5.05     $ 4.62       9.3 %
Capital expenditures
  $ 17,705     $ 10,524       68.2 %
      Revenues and direct operating costs for our pressure pumping operations 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 our expanded operations in the Appalachian regions of Kentucky, Tennessee and West Virginia, as well as increased demand for our services resulting from the improved industry conditions as discussed in “Contract Drilling” above. Increased average revenue per job was due primarily to increased pricing for our services. Selling, general and administrative expenses increased largely 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 2004 and 2003 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.
                         
    Years Ended December 31,
     
Drilling and Completion Fluids   2004   2003   % Change
             
    (Dollars in thousands)
Revenues
  $ 90,557     $ 69,230       30.8 %
Direct operating costs
  $ 76,503     $ 61,424       24.5 %
Selling, general and administrative
  $ 7,696     $ 7,447       3.3 %
Depreciation
  $ 2,196     $ 2,319       (5.3 )%
Operating income (loss)
  $ 4,162     $ (1,960 )     N/A  
Total jobs
    2,205       1,931       14.2 %
Average revenue per job
  $ 41.07     $ 35.85       14.6 %
Average direct operating costs per job
  $ 34.70     $ 31.81       9.1 %
Capital expenditures
  $ 1,488     $ 912       63.2 %
      The number of jobs increased as a result of the improved industry conditions as discussed in “Contract Drilling” above, as well as increased drilling activity in the Gulf of Mexico. Revenues and direct operating costs increased in 2004 primarily as a result of the increased number of jobs, as well as an increase in the

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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 completed in the Gulf of Mexico.
                         
    Years Ended December 31,
     
Oil and Natural Gas Production and Exploration   2004   2003   % Change
             
    (Dollars in thousands)
Revenues
  $ 33,867     $ 21,163       60.0 %
Direct operating costs
  $ 7,978     $ 4,808       65.9 %
Selling, general and administrative
  $ 1,816     $ 1,489       22.0 %
Depreciation, depletion and impairment
  $ 13,309     $ 7,082       87.9 %
Operating income
  $ 10,764     $ 7,784       38.3 %
Capital expenditures
  $ 14,451     $ 10,015       44.3 %
Average net daily oil production (Bbls)
    1,071       788       35.9 %
Average net daily gas production (Mcf)
    7,429       5,656       31.3 %
Average oil sales price (per Bbl)
  $ 39.12     $ 30.54       28.1 %
Average gas sales price (per Mcf)
  $ 5.81     $ 4.97       16.9 %
      Oil and gas revenues and direct operating costs increased in 2004 compared to 2003, primarily due to the oil and natural gas properties acquired in the acquisition of TMBR during February 2004 and increased market prices received for oil and natural gas during 2004. Direct operating costs further increased as a result of approximately $600,000 of dry hole costs incurred during 2004. Depreciation, depletion and impairment expense increased in 2004 primarily as a result of increased production and an increase of approximately $1.8 million of expenses incurred to impair certain oil and natural gas properties.
                         
    Years Ended December 31,
     
Corporate and Other   2004   2003   % Change
             
    (Dollars in thousands)
Selling, general and administrative
  $ 10,820     $ 8,665       24.9 %
Bad debt expense
  $ 897     $ 259       246.3 %
Depreciation
  $ 444     $ 444       %
Restructuring and other charges
  $     $ (2,452 )     N/A  
Other income from operations
  $ 1,655     $ 2,174       (23.9 )%
Interest income
  $ 1,140     $ 1,116       2.2 %
Interest expense
  $ 695     $ 292       138.0 %
Other income
  $ 235     $ 1,870       (87.4 )%
      Selling, general and administrative expenses increased primarily as a result of increased professional expenses (including expenses incurred during 2004 to comply with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002) and additional compensation expense related to the issuance of restricted shares to certain key employees. Interest expense in 2004 included approximately $445,000 of termination fees and other related charges incurred as a result of the replacement of our credit facility. Restructuring and other charges in 2003 includes a $2.5 million payment received as settlement for contract drilling services previously provided in Mexico by our wholly-owned subsidiary, Norton Drilling Company Mexico, Inc. The receivable had been reserved as uncollectible at the time of our acquisition of Norton Drilling Company Mexico, Inc. in 1999. Other income in 2003 includes approximately $1.7 million representing our pro rata share of the net income of TMBR using the equity method of accounting.

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Comparison of the years ended December 31, 2003 and 2002
      Operations by business segment for the years ended December 31, 2003 and 2002 follow:
                         
    Years Ended December 31,
     
Contract Drilling   2003   2002   % Change
             
    (Dollars in thousands)
Revenues
  $ 639,694     $ 410,295       55.9 %
Direct operating costs
  $ 475,224     $ 318,201       49.3 %
Selling, general and administrative
  $ 4,425     $ 3,987       11.0 %
Depreciation and amortization
  $ 84,379     $ 80,500       4.8 %
Operating income
  $ 75,666     $ 7,607       894.7 %
Operating days
    68,798       45,919       49.8 %
Average revenue per operating day
  $ 9.30     $ 8.94       4.0 %
Average direct operating costs per operating day
  $ 6.91     $ 6.93       (0.3 )%
Number of owned rigs at end of period
    343       324       5.9 %
Average number of rigs owned during period
    336       323       4.0 %
Average rigs operating
    188       126       49.2 %
Rig utilization percentage
    56 %     39 %     43.6 %
Capital expenditures
  $ 95,175     $ 68,516       38.9 %
      The average market price of natural gas and our average rigs operating for each of the fiscal quarters in 2003 and 2002 follow:
                                 
    1st   2nd   3rd   4th
    Quarter   Quarter   Quarter   Quarter
                 
2003:
                               
Average natural gas price
  $ 5.91     $ 5.70     $ 4.88     $ 5.29  
Average rigs operating
    176       195       192       191  
2002:
                               
Average natural gas price
  $ 2.51     $ 3.41     $ 3.20     $ 4.31  
Average rigs operating
    117       119       127       140  
      The average market price of natural gas improved to $5.45 per Mcf in 2003 compared to $3.36 per Mcf in 2002, resulting in an increase in demand for our contract drilling services. Our average number of rigs operating increased to 188 in 2003 from 126 in 2002.
      Revenues and direct operating costs increased as a result of the increased number of operating days in 2003. Revenue per operating day increased as a result of increased demand for our services which resulted in additional increases in revenues and operating income. As a result of the increased utilization of our drilling rigs in 2003, significant capital expenditures were incurred to modify and upgrade our existing drilling rigs and

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to acquire additional related equipment to meet the increased demand. Increased depreciation expense in 2003 resulted from this increased level of capital spending, as well as acquisitions.
                         
    Years Ended December 31,
     
Pressure Pumping   2003   2002   % Change
             
    (Dollars in thousands)
Revenues
  $ 46,083     $ 32,996       39.7 %
Direct operating costs
  $ 26,184     $ 19,802       32.2 %
Selling, general and administrative
  $ 5,683     $ 4,301       32.1 %
Depreciation
  $ 3,774     $ 2,803       34.6 %
Operating income
  $ 10,442     $ 6,090       71.5 %
Total jobs
    5,667       3,796       49.3 %
Average revenue per job
  $ 8.13     $ 8.69       (6.4 )%
Average direct operating costs per job
  $ 4.62     $ 5.22       (11.5 )%
Capital expenditures
  $ 10,524     $ 7,399       42.2 %
      The increases in revenues and expenses for our pressure pumping operations were attributable to improved industry conditions, as discussed in “Contract Drilling” above, and continued expansion of our pressure pumping services into the Appalachian regions of Kentucky and West Virginia. This expansion also resulted in increases in selling, general and administrative expenses and depreciation in 2003 compared to 2002.
                         
    Years Ended December 31,
     
Drilling and Completion Fluids   2003   2002   % Change
             
    (Dollars in thousands)
Revenues
  $ 69,230     $ 69,943       (1.0 )%
Direct operating costs
  $ 61,424     $ 60,762       1.1 %
Selling, general and administrative
  $ 7,447     $ 7,243       2.8 %
Depreciation and amortization
  $ 2,319     $ 2,216       4.6 %
Operating loss
  $ (1,960 )   $ (278 )     605.0 %
Total jobs
    1,931       1,457       32.5 %
Average revenue per job
  $ 35.85     $ 48.00       (25.3 )%
Average direct operating costs per job
  $ 31.81     $ 41.70       (23.7 )%
Capital expenditures
  $ 912     $ 1,571       (41.9 )%
      The decrease in revenues was primarily due to the decrease in larger jobs completed in the Gulf of Mexico as activity in the Gulf of Mexico continued to be slow despite improved natural gas prices in 2003. The decrease in revenues from the Gulf of Mexico was largely offset by increased demand for our land-based drilling and completion fluids services. Land-based drilling and completion fluids jobs typically generate less revenue per job than offshore jobs. As a result, our average revenue per job decreased in 2003 compared to 2002.

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    Years Ended December 31,
     
Oil and Natural Gas Production and Exploration   2003   2002   % Change
             
    (Dollars in thousands)
Revenues
  $ 21,163     $ 14,723       43.7 %
Direct operating costs
  $ 4,808     $ 3,956       21.5 %
Selling, general and administrative
  $ 1,489     $ 1,571       (5.2 )%
Depreciation and depletion
  $ 7,082     $ 5,251       34.9 %
Operating income
  $ 7,784     $ 3,945       97.3 %
Capital expenditures
  $ 10,015     $ 6,357       57.5 %
Average net daily oil production (Bbls)
    788       794       (0.8 )%
Average net daily gas production (Mcf)
    5,656       5,109       10.7 %
Average oil sales price (per Bbl)
  $ 30.54     $ 25.02       22.1 %
Average gas sales price (per Mcf)
  $ 4.97     $ 2.91       70.8 %
      Increased revenues and operating income are primarily attributable to increased prices received from sales of oil and natural gas and increased production of natural gas in 2003. Depreciation and depletion expense primarily increased as a result of increased production of natural gas in 2003 as compared to 2002, as well as an increase of approximately $700,000 associated with expenses incurred to partially impair certain oil and natural gas properties.
                         
    Years Ended December 31,
     
Corporate and Other   2003   2002   % Change
             
    (Dollars in thousands)
Selling, general and administrative
  $ 8,665     $ 9,038       (4.1 )%
Bad debt expense
  $ 259     $ 320       (19.1 )%
Depreciation
  $ 444     $ 446       (0.4 )%
Restructuring and other charges
  $ (2,452 )   $ 4,700       N/A  
Other income from operations
  $ 2,174     $ 538       304.1 %
Interest income
  $ 1,116     $ 1,110       0.5 %
Interest expense
  $ 292     $ 532       (45.1 )%
      In 2003, Restructuring and other charges reflects a payment received in the first quarter of 2003 of approximately $2.5 million as settlement for contract drilling services previously provided in Mexico by Norton Drilling Company Mexico, Inc., a wholly-owned subsidiary. The underlying accounts receivable balance had been reserved as uncollectible at the time of our acquisition of Norton Drilling Company Mexico, Inc. in 1999. In 2002, Restructuring and other charges reflects a $4.7 million charge due to the financial failure of a workers’ compensation insurance carrier we used from 1992 until March 2001.
Income Taxes
                         
    Years Ended December 31,
     
    2004   2003   2002
             
    (Dollars in thousands)
Income before income tax
  $ 171,894     $ 89,884     $ 4,201  
Income tax expense
    63,161       32,996       1,827  
Effective tax rate
    36.7 %     36.7 %     43.5 %
      Our effective income tax rate of 36.7% for 2004 and 2003 is primarily attributable to a Federal rate of 35.0% and state income tax rates of 1.6% and 1.5%, respectively. The impact of permanent differences was not significant in 2004 or 2003. The significance of the impact of the permanent differences of approximately 6% to our effective income tax rate in 2002 was largely attributable to our reduced 2002 pretax earnings.

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      For tax purposes, we have available at December 31, 2004, Federal net operating loss carryforwards of approximately $16 million and $118,000 of alternative minimum tax credit carryforwards. These carryforwards are attributable to the acquisition of TMBR in February 2004.
      The net operating loss carryforwards, if unused, are scheduled to expire as follows: 2005 — $5 million, 2006 — $1 million, 2011 — $2 million, 2018 — $4 million and 2019 — $4 million. The alternative minimum tax credit may be carried forward indefinitely.
      We record non-cash deferred Federal income taxes based primarily on the relationship between the amount of our unused Federal net operating loss carryforwards and the temporary differences between the book basis and tax basis in our assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be settled. As a result of fully recognizing the benefit of our deferred income taxes, we incur deferred income tax expense as these benefits are utilized. We incurred deferred income tax expense of approximately $23.5 million, $17.9 million and $23.7 million for 2004, 2003 and 2002, respectively.
Volatility of Oil and Natural Gas Prices
      Our revenue, profitability and rate of growth are substantially dependent upon prevailing prices for oil and natural gas, with respect to all of our operating segments. For many years, oil and natural gas prices and markets have been volatile. Prices are affected by market supply and demand factors as well as international military, political and economic conditions, and the ability of OPEC, to set and maintain production and price targets. All of these factors are beyond our control. 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 and $5.95 in 2004, 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 and 211 in 2004. 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 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. 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.
Recently-Issued Accounting Standards
      The Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard No. 123 (revised 2004), Share-Based Payment (“SFAS 123(R)”) in December 2004; it replaces FASB Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. This statement is effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. We will adopt SFAS 123(R) no later than our fiscal quarter beginning July 1, 2005.
      We currently use the intrinsic value method to value stock options, and accordingly, no compensation expense has been recognized for stock options since we grant stock options with exercise prices equal to our 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. We will expense stock options using the Modified Prospective Transition method as described in SFAS 123(R). This method requires expense to be recognized for new grants or modifications to existing grants issued in the period of adoption, plus the current period expense for non-vested awards issued prior to the adoption of SFAS 123(R). Compensation cost for the unvested stock-based awards will be recognized over the remaining vesting period. No expense will be recognized for stock options vested in periods prior to the adoption of SFAS 123(R).

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      We are evaluating the impact of the adoption of SFAS 123(R) on our results of operations and financial position. Adoption is not expected to have a material effect on our 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 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 our 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”). FAS 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 our financial position or results of operations.
Item 7A. 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 over 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 8. Financial Statements and Supplementary Data.
      Financial Statements are filed as a part of this Report at the end of Part IV hereof beginning at page F-1, Index to Consolidated Financial Statements, and are incorporated herein by this reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
      None.
Item 9A. Controls and Procedures.
      Disclosure Controls and Procedures. As of the end of the period covered by this Annual Report on Form 10-K, 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.

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      There were no changes in our internal control over financial reporting that occurred during our last fiscal quarter (the quarter ended December 31, 2004) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
      Management’s Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.
      Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2004. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework. Based on our assessment, we concluded that, as of December 31, 2004, our internal control over financial reporting is effective based on those criteria.
      Our management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2004, has been audited by PricewaterhouseCoopers LLP, the independent registered public accounting firm who also audited our consolidated financial statements as stated in their report which appears on page F-2 of this Report on Form 10-K.
Item 9B. Other Information
      On October 22, 2004, we entered into a written letter agreement with each of Mark S. Siegel, Kenneth N. Berns and John E. Vollmer III confirming and evidencing the existing agreement between us and each of Messrs. Siegel, Berns and Vollmer pursuant to which we have agreed to pay each such person within ten (10) days of the termination of his employment with us for any reason (including voluntary termination by them), an amount in cash equal to his annual base salary at the time of such termination. Any such payment made by us pursuant to the agreement evidenced in the letter agreement will reduce dollar for dollar any payment owed to such person, if any, pursuant to the Change in Control Agreement dated January 29, 2004 between the Company and such person or any agreement in substitution therefor.

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PART III
      The information required by Part III is omitted from this Report because we will file a definitive proxy statement pursuant to Regulation 14A of the Securities Exchange Act of 1934 no later than 120 days after the end of the fiscal year covered by this Report and certain information included therein is incorporated herein by reference.
Item 10. Directors and Executive Officers of the Registrant.
      The information required by this Item is incorporated herein by reference to the Proxy Statement.
Item 11. Executive Compensation.
      The information required by this Item is incorporated herein by reference to the Proxy Statement.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
      The information required by this Item is incorporated herein by reference to the Proxy Statement.
Item 13. Certain Relationships and Related Transactions.
      The information required by this Item is incorporated herein by reference to the Proxy Statement.
Item 14. Principal Accountant Fees and Services.
      The information required by this Item is incorporated herein by reference to the Proxy Statement.

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PART IV
Item 15. Exhibits and Financial Statement Schedule.
      (a)(1) Financial Statements
      See Index to Consolidated Financial Statements on page F-1 of this Report.
      (a)(2) Financial Statement Schedule
      Schedule II — Valuation and qualifying accounts is filed herewith on page S-1.
      All other financial statement schedules have been omitted because they are not applicable or the information required therein is included elsewhere in the financial statements or notes thereto.
      (a)(3) Exhibits
      The following exhibits are filed herewith or incorporated by reference herein.
         
  2 .1   Asset Purchase Agreement among Key Energy Drilling, Inc., Key Energy Drilling Beneficial, L.P., Key Rocky Mountain, Inc., Key Four Corners, Inc. and Key Energy Services, Inc. and Patterson-UTI Drilling Company LP, LLLP and Patterson-UTI Energy, Inc., dated as of December 7, 2004.
 
  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).
 
  4 .1   Rights Agreement dated January 2, 1997, between Patterson Energy, Inc. and Continental Stock Transfer & Trust Company (filed January 14, 1997 as Exhibit 2 to the Company’s Registration Statement on Form 8-A and incorporated herein by reference).
 
  4 .2   Amendment to Rights Agreement dated as of October 23, 2001 (filed October 31, 2001 as Exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2001 and incorporated herein by reference).
 
  4 .3   Restated Certificate of Incorporation, as amended (See Exhibits 3.1 and 3.2).
 
  4 .4   Registration Rights Agreement with Bear, Stearns and Co. Inc., dated March  25, 1994, as assigned by REMY Capital Partners III, L.P.(filed March 19, 2002 as Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference).
 
  10 .1   For additional material contracts, see Exhibits 2.1, 4.1, 4.2 and 4.4.
 
  10 .2   Patterson-UTI Energy, Inc., 1993 Stock Incentive Plan, as amended (filed March 13, 1998 as Exhibit 10.1 to the Company’s Registration Statement on Form S-8 (File No. 333-47917) and incorporated herein by reference).*
 
  10 .3   Patterson-UTI Energy, Inc. Non-Employee Directors’ Stock Option Plan, as amended (filed November 4, 1997 as Exhibit 10.1 to the Company’s Registration Statement on Form S-8 (File No. 333-39471) and incorporated herein by reference).*
 
  10 .4   Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (filed November 27, 2002 as Exhibit 4.4 to Post Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60470) and incorporated herein by reference).*
 
  10 .5   Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 and incorporated herein by reference).*

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  10 .6   Amendment to the Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed August 9, 2004 as Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
 
  10 .7   Amended and Restated Patterson-UTI Energy, Inc. Non-Employee Director Stock Option Plan(filed July 28, 2003 as Exhibit 4.8 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 and incorporated herein by reference).*
 
  10 .8   Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee Stock Option Plan (filed July 25, 2001 as Exhibit 4.4 to Post-Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60466) and incorporated herein by reference).*
 
  10 .9   1997 Stock Option Plan of DSI Industries, Inc. (filed July 25, 2001 as Exhibit 4.4 to Post-Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60470) and incorporated herein by reference).*
 
  10 .10   Stock Option Agreement dated July 20, 2001 between Patterson-UTI Energy, Inc. and Kenneth R. Peak (filed March 19, 2002 as Exhibit 10.9 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference).*
 
  10 .11   Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed August 9, 2004 as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
 
  10 .12   Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed August 9, 2004 as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
 
  10 .13   Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and A. Glenn Patterson (filed August 9, 2004 as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
 
  10 .14   Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed August 9, 2004 as Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
 
  10 .15   Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Jonathan D. Nelson (filed August 9, 2004 as Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
 
  10 .16   Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed August 9, 2004 as Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
 
  10 .17   Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on February 4, 2004 as Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
 
  10 .18   Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and A. Glenn Patterson (filed on February 4, 2004 as Exhibit 10.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
 
  10 .19   Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed on February 4, 2004 as Exhibit 10.4 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
 
  10 .20   Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on February 4, 2004 as Exhibit 10.5 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
 
  10 .21   Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Jonathan D. Nelson (filed on February 4, 2004 as Exhibit 10.6 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*

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  10 .22   Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed on February 4, 2004 as Exhibit 10.7 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
 
  10 .23   Form of Letter Agreement regarding termination, effective as of January  29, 2004, entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. Vollmer III.*
 
  10 .24   Form of Indemnification Agreement entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, A. Glenn Patterson, Kenneth N. Berns, Robert C. Gist, Curtis W. Huff, Terry H. Hunt, Kenneth R. Peak, Nadine C. Smith, Jonathan D. Nelson and John E. Vollmer III (filed April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and incorporated herein by reference).*
 
  10 .25   Credit Agreement dated as of December 17, 2004 among Patterson-UTI Energy, Inc., as the Borrower, Bank of America, N.A., as administrative agent, L/ C Issuer and a Lender and the other lenders and agents party thereto (filed on December 23, 2004 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
 
  10 .26   Summary Description of 2003 Cash Bonus Plan.*
 
  10 .27   Summary Description of Director Compensation.*
 
  14 .1   Patterson-UTI Energy, Inc. Code of Business Conduct and Ethics for Senior Financial Executives (filed as Exhibit 14.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).
 
  21 .1   Subsidiaries of the Registrant.
  23 .1   Consent of Independent Registered Public Accounting Firm.
 
  23 .2   Consent of Independent Petroleum Engineer — M. Brian Wallace, P.E.
 
  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 identified as required by Item 15(a)(3) of Form 10-K.

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
         
    Page
     
Report of Independent Registered Public Accounting Firm
    F-2  
Consolidated Financial Statements:
       
Consolidated Balance Sheets as of December 31, 2004 and 2003
    F-4  
Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002
    F-5  
Consolidated Statements of Changes In Stockholders’ Equity for the years ended December 31, 2004, 2003 and 2002
    F-6  
Consolidated Statements of Changes In Cash Flows for the years ended December 31, 2004, 2003 and 2002
    F-7  
Notes to Consolidated Financial Statements
    F-9  

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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Patterson-UTI Energy, Inc.
      We have completed an integrated audit of Patterson-UTI Energy, Inc’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
      In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Patterson-UTI Energy, Inc. and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule on page S-1 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
Internal control over financial reporting
      Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
      A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial

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statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
  PricewaterhouseCoopers LLP
Houston, Texas
February 24, 2005

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
                       
    December 31,
     
    2004   2003
         
    (In thousands, except share
    data)
ASSETS
Current assets:
               
 
Cash and cash equivalents
  $ 112,371     $ 100,483  
 
Accounts receivable, net of allowance for doubtful accounts of $1,909 and $2,133 at December 31, 2004 and 2003, respectively
    214,097       156,345  
 
Federal and state income taxes receivable
          12,667  
 
Inventory
    17,738       15,206  
 
Deferred tax assets, net
    15,991       16,449  
 
Other
    26,836       15,697  
             
     
Total current assets
    387,033       316,847  
Property and equipment, at cost, net
    828,875       693,631  
Goodwill
    101,326       51,179  
Investment in equity securities
          19,771  
Other
    5,677       2,686  
             
     
Total assets
  $ 1,322,911     $ 1,084,114  
             
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
 
Accounts payable:
               
   
Trade
  $ 54,553     $ 41,093  
   
Accrued revenue distributions
    11,297       8,545  
   
Other
    2,309       6,743  
 
Accrued Federal and state income taxes payable
    2,754        
 
Accrued expenses
    79,163       60,853  
             
     
Total current liabilities
    150,076       117,234  
Deferred tax liabilities, net
    162,040       143,309  
Other
    3,256       3,822  
             
     
Total liabilities
    315,372       264,365  
             
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 December 31, 2004 and 200,000,000 shares at December 31, 2003 with 171,625,841 (affected by a two- for-one stock split) and 82,483,148 issued and 168,512,745 (affected by a two-for-one stock split) and 80,976,600 outstanding at December 31, 2004 and 2003, respectively
    1,716       825  
 
Additional paid-in capital
    597,280       506,018  
 
Deferred compensation
    (5,420 )      
 
Retained earnings
    415,489       317,627  
 
Accumulated other comprehensive income, net of tax
    11,611       6,934  
 
Treasury stock, at cost, 3,113,096 shares (affected by a two-for-one stock split) and 1,506,548 shares at December 31, 2004 and 2003, respectively
    (13,137 )     (11,655 )
             
     
Total stockholders’ equity
    1,007,539       819,749  
             
     
Total liabilities and stockholders’ equity
  $ 1,322,911     $ 1,084,114  
             
The accompanying notes are an integral part of these consolidated financial statements.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
                             
    Years Ended December 31,
     
    2004   2003   2002
             
    (In thousand, except per share data)
Operating revenues:
                       
 
Contract drilling
  $ 809,691     $ 639,694     $ 410,295  
 
Pressure pumping
    66,654       46,083       32,996  
 
Drilling and completion fluids
    90,557       69,230       69,943  
 
Oil and natural gas
    33,867       21,163       14,723  
                   
      1,000,769       776,170       527,957  
                   
Operating costs and expenses:
                       
 
Contract drilling
    556,869       475,224       318,201  
 
Pressure pumping
    37,561       26,184       19,802  
 
Drilling and completion fluids
    76,503       61,424       60,762  
 
Oil and natural gas
    7,978       4,808       3,956  
 
Depreciation, depletion, amortization and impairment
    119,395       97,998       91,216  
 
General and administrative
    32,007       27,709       26,140  
 
Bad debt expense
    897       259       320  
 
Restructuring and other charges
          (2,452 )     4,700  
 
Gain on sale of assets
    (1,655 )     (2,174 )     (538 )
                   
      829,555       688,980       524,559  
                   
Operating income
    171,214       87,190       3,398  
                   
Other income (expense):
                       
 
Interest income
    1,140       1,116       1,110  
 
Interest expense
    (695 )     (292 )     (532 )
 
Other
    235       1,870       225  
                   
      680       2,694       803  
                   
Income before income taxes and cumulative effect of change in accounting principle
    171,894       89,884       4,201  
                   
Income tax expense (benefit):
                       
 
Current
    39,688       15,088       (21,878 )
 
Deferred
    23,473       17,908       23,705  
                   
      63,161       32,996       1,827  
                   
Income before cumulative effect of change in accounting principle
    108,733       56,888       2,374  
Cumulative effect of change in accounting principle, net of related income tax benefit of approximately $287
          (469 )      
                   
Net income
  $ 108,733     $ 56,419     $ 2,374  
                   
Net income per common share:
                       
 
Basic:
                       
   
Income before cumulative effect of change in accounting principle
  $ 0.65     $ 0.35     $ 0.02  
                   
   
Cumulative effect of change in accounting principle
  $     $     $  
                   
   
Net income
  $ 0.65     $ 0.35     $ 0.02  
                   
 
Diluted:
                       
   
Income before cumulative effect of change in accounting principle
  $ 0.64     $ 0.35     $ 0.01  
                   
   
Cumulative effect of change in accounting principle
  $     $     $  
                   
   
Net income
  $ 0.64     $ 0.34     $ 0.01  
                   
 
Weighted average number of common shares outstanding:
                       
   
Basic
    166,258       161,272       157,410  
                   
   
Diluted
    169,211       164,572       162,504  
                   
The accompanying notes are an integral part of these consolidated financial statements.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
                                                                   
    Common Stock               Accumulated        
                    Other        
    Number       Additional           Comprehensive        
    of       Paid-In   Deferred   Retained   Income   Treasury    
    Shares   Amount   Capital   Compensation   Earnings   (Loss)   Stock   Total
                                 
    (In thousands)
December 31, 2001
    78,463     $ 784     $ 441,475     $     $ 258,834     $ (2,296 )   $ (11,655 )   $ 687,142  
 
Issuance of common stock
    650       7       16,933                               16,940  
 
Exercise of stock options and warrants
    2,464       25       15,714                               15,739  
 
Tax benefit related to exercise of stock options
                15,079                               15,079  
 
Foreign currency translation, net of tax
                                  457             457  
 
Net income
                            2,374                   2,374  
                                                 
December 31, 2002
    81,577       816       489,201             261,208       (1,839 )     (11,655 )     737,731  
 
Exercise of stock options and warrants
    906       9       10,277                               10,286  
 
Tax benefit related to exercise of stock options
                6,540                               6,540  
 
Foreign currency translation, net of tax
                                  8,773             8,773  
 
Net income
                            56,419                   56,419  
                                                 
December 31, 2003
    82,483       825       506,018             317,627       6,934       (11,655 )     819,749  
 
Issuance of common stock for acquisition
    1,388       14       49,462                               49,476  
 
Issuance of restricted stock
    189       2       6,640       (6,642 )                        
 
Amortization of deferred compensation expense
                      1,222                         1,222  
 
Exercise of stock options and warrants
    2,580       25       24,494                               24,519  
 
Tax benefit related to exercise of stock options
                10,666                               10,666  
 
Foreign currency translation, net of tax
                                  4,677             4,677  
 
Purchase of treasury stock
                                        (1,482 )     (1,482 )
 
Payment of cash dividend (See Note 11)
                            (10,021 )                 (10,021 )
 
Effect of two-for-one stock split (See Note 11)
    84,986       850                   (850 )                  
 
Net income
                            108,733                   108,733  
                                                 
December 31, 2004
    171,626     $ 1,716     $ 597,280     $ (5,420 )   $ 415,489     $ 11,611     $ (13,137 )   $ 1,007,539  
                                                 
The accompanying notes are an integral part of these consolidated financial statements.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS
                               
    Years Ended December 31,
     
    2004   2003   2002
             
    (In thousands)
Cash flows from operating activities:
                       
 
Net income
  $ 108,733     $ 56,419     $ 2,374  
 
Adjustments to reconcile net income to net cash provided by operating activities:
                       
 
Depreciation, depletion, amortization and impairment
    119,395       97,998       91,216  
 
Provision for bad debts
    897       259       320  
 
Deferred income tax expense
    23,473       17,908       23,705  
 
Tax benefit related to exercise of stock options
    10,666       6,540       15,079  
 
Amortization of deferred compensation expense
    1,222              
 
Gain on sale of assets
    (1,655 )     (2,174 )     (538 )
 
Cumulative effect of change in accounting principle, net of tax
          (469 )      
   
Changes in operating assets and liabilities, net of business acquired:
                       
     
Accounts receivable
    (50,682 )     (55,791 )     34,565  
     
Federal income taxes receivable
    15,470       10,919       (23,216 )
     
Inventory and other current assets
    (13,556 )     (8,984 )     (222 )
     
Accounts payable
    12,861       12,322       (11,079 )
     
Accrued expenses
    1,555       22,814       (771 )
     
Other liabilities
    (6,090 )     5,015       362  
                   
   
Net cash provided by operating activities
    222,289       162,776       131,795  
                   
Cash flows from investing activities:
                       
 
Acquisitions, net of cash acquired
    (32,514 )     (40,832 )      
 
Purchases of property and equipment
    (191,560 )     (116,626 )     (83,843 )
 
Proceeds from sales of property and equipment
    3,303       4,548       1,813  
 
Purchase of investment equity securities
                (17,659 )
 
Change in other assets
    (1,766 )     (1,693 )     735  
                   
   
Net cash used in investing activities
    (222,537 )     (154,603 )     (98,954 )
                   
Cash flows from financing activities:
                       
 
Purchase of treasury stock
    (1,482 )            
 
Dividends paid
    (10,021 )            
 
Line of credit issuance costs
    (780 )            
 
Proceeds from exercise of stock options and warrants
    24,519       10,286       15,739  
                   
   
Net cash provided by financing activities
    12,236       10,286       15,739  
                   
   
Effect of foreign exchange rate changes on cash
    (100 )     (130 )     (10 )
                   
     
Net increase in cash and cash equivalents
    11,888       18,329       48,570  
Cash and cash equivalents at beginning of year
    100,483       82,154       33,584  
                   
Cash and cash equivalents at end of year
  $ 112,371     $ 100,483     $ 82,154  
                   
Supplemental disclosure of cash flow information:
                       
 
Net cash received (paid) during the year for:
                       
     
Interest
  $ (245 )   $ (292 )   $ (532 )
     
Income taxes
    (12,500 )     2,730       13,492  
The accompanying notes are an integral part of these consolidated financial statements.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS — (Continued)
      Non-cash investing and financing activities:
      In February 2004, the Company completed its acquisition of 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 $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 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 consolidated financial statements.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Description of Business and Summary of Significant Accounting Policies
A description of the business and basis of presentation follows:
      Description of business — Patterson-UTI Energy, Inc., together with its wholly-owned subsidiaries, (collectively referred to herein as “Patterson-UTI” or the “Company”) is a leading provider of onshore contract drilling services to major and independent oil and natural gas operators in Texas, New Mexico, Oklahoma, Louisiana, Mississippi, Colorado, Utah, Wyoming and Western Canada. As of December 31, 2004, the Company owned 361 drilling rigs. The Company provides pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. The Company provides 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. The Company is also engaged in the development, exploration, acquisition and production of oil and natural gas. The Company’s oil and natural gas business operates primarily in producing regions of West Texas, South Texas, Southeastern New Mexico, Utah and Mississippi.
      Basis of presentation — As a result of the Company increasing its ownership of TMBR from 19.5% to 100% in 2004, the consolidated financial statements of Patterson-UTI Energy, Inc. and its wholly-owned subsidiaries have been restated to provide for the retroactive application of the equity method of accounting for the Company’s investment in TMBR (see Note 6).
      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.
      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 December 31, 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 these financial statements have been restated as if the two-for-one stock split had occurred on January 1, 2002.
A summary of the significant accounting policies follows:
      Principles of consolidation — The consolidated financial statements include the accounts of Patterson-UTI and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. The Company has no controlling financial interests in any entity which would require consolidation.
      Management 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.
      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

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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. The Company recognizes reimbursements received from third parties for out-of-pocket expenses incurred as revenues and accounts for out-of-pocket expenses as direct costs.
      Accounts receivable — Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts represents the Company’s estimate of the amount of probable credit losses existing in the Company’s accounts receivable. The Company determines the allowance based on historical write-off experience. The Company reviews the adequacy of its allowance for doubtful accounts monthly. Significant individual accounts receivable balances and balances which have been outstanding greater than 90 days are reviewed individually for collectibility. Account balances, when determined to be uncollectible, are charged against the allowance.
      Inventories — Inventories consist primarily of chemical products to be used in conjunction with the Company’s drilling and completion fluids activities. The inventories are stated at the lower of cost or market, determined by the first-in, first-out method.
      Property and equipment — Property and equipment is carried at cost less accumulated depreciation. Depreciation is provided on the straight-line method over the estimated useful lives. The method of depreciation does not change when equipment becomes idle. The estimated useful lives, in years, are defined below.
         
    Useful Lives
     
Drilling rigs and related equipment
    2-15  
Office furniture
    3-10  
Buildings
    5-20  
Automotive equipment
    2-7  
Other
    3-7  
      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. Costs of exploratory wells are initially capitalized to wells in progress until the outcome of the drilling is known. The Company reviews wells in progress quarterly to determine the related reserve classification. If the reserve classification is uncertain after one year following the completion of drilling, the Company considers the costs of the well to be impaired and recognizes 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 engineering 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 an independent petroleum 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, costs related to that property are expensed.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. As such, the Company assess impairment of its 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 the Company’s drilling and completion fluids business, the determination that no impairment existed as of December 31, 2004, was based on the segment’s improved operating results in 2004 and on the Company’s expectations that these improved results will continue. If the improved results do not continue, all or part of the goodwill of approximately $10 million associated with that business segment may be determined to be impaired.
      The following table summarizes depreciation, depletion, amortization and impairment expense for 2004, 2003 and 2002 (in millions):
                           
    2004   2003   2002
             
Depreciation expense
  $ 106.0     $ 90.9     $ 85.8  
Depletion expense
    10.1       5.6       4.4  
Amortization expense
    0.1       0.1       0.3  
Impairment of oil and natural gas properties
    3.2       1.4       0.7  
                   
 
Total
  $ 119.4     $ 98.0     $ 91.2  
                   
      Maintenance and repairs — Maintenance and repairs are charged to expense when incurred. Renewals and betterments which extend the life or improve existing property and equipment are capitalized.
      Retirements — Upon disposition or retirement of property and equipment, the cost and related accumulated depreciation are removed and any resulting gain or loss is credited or charged to operations.
      Investments in equity securities — Investments in equity securities are accounted for under the equity method of accounting.
      Earnings per share — The Company provides a dual presentation of its earnings per share; 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 year. Diluted EPS includes common stock equivalents which are dilutive to earnings per share. For the years ended December 31, 2004, 2003 and 2002, dilutive securities, consisting of certain stock options and warrants, (See Note 12) included in the calculation of Diluted EPS were 3.0 million shares, 3.3 million shares and 5.1 million shares, respectively. At December 31, 2004, 2003 and 2002, there were potentially dilutive securities of 640,000, 1.9 million and 657,000, respectively, excluded from the calculation of Diluted EPS as their exercise prices were greater than the average market price for the respective year.
      Income taxes — The asset and liability method is used in accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for operating loss and tax credit carryforwards and for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. If applicable, a valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that such assets will be realized.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Stock based compensation — At December 31, 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 Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” (“APB 25”) 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 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 $773,000, net of tax, was included in net income for the twelve months ended December 31, 2004. Other than the Restricted Shares discussed above, no additional stock-based employee compensation cost is reflected in net income, as all options granted under the plans discussed above had an exercise price equal to or in excess of 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 (“FASB”) Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation,” (“SFAS 123”) to stock-based employee compensation (in thousands, except per share amounts):
                           
    Years Ended December 31,
     
    2004   2003   2002
             
Net income, as reported
  $ 108,733     $ 56,419     $ 2,374  
Add: Stock-based employee compensation expense recorded, net of tax
    773              
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects(1)
    (11,531 )     (10,506 )     (5,296 )
                   
Pro forma net income (loss)
  $ 97,975     $ 45,913     $ (2,922 )
                   
Earnings (loss) per share:
                       
 
Basic, as reported
  $ 0.65     $ 0.35     $ 0.02  
                   
 
Basic, pro forma
  $ 0.59     $ 0.28     $ (0.02 )
                   
 
Diluted, as reported
  $ 0.64     $ 0.34     $ 0.01  
                   
 
Diluted, pro forma
  $ 0.59     $ 0.28     $ (0.02 )
                   
Weighted-average fair value per share of options granted(1)
  $ 6.25     $ 5.59     $ 7.60  
 
(1)  See Note 12 for additional information regarding the computations presented here.
      Statement of cash flows — For purposes of reporting cash flows, cash and cash equivalents include cash on deposit, money market funds and investment grade municipal and commercial bonds with original maturities of 90 days or less.
      Recently Issued Accounting Standards — 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. This statement is effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. The Company will adopt SFAS 123(R) no later than its fiscal quarter beginning July 1, 2005.
      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)

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
requires the expensing of all stock-based compensation, including stock options and restricted shares, using the fair value method. The Company will expense stock options using the Modified Prospective Transition method as described in SFAS 123(R). This method requires expense to be recognized for new grants or modifications to existing grants issued in the period of adoption, plus the current period expense for non-vested awards issued prior to the adoption of SFAS 123(R). Compensation cost for the unvested stock-based awards will be recognized over the remaining vesting period. 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 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.
      Reclassifications — Certain reclassifications have been made to the 2003 and 2002 consolidated financial statements in order for them to conform with the 2004 presentation.
2. Acquisitions
      Key Energy Services, Inc. — In December 2004, the Company entered into an agreement to acquire the U.S. land-based drilling assets of Key Energy Services, Inc. for approximately $62 million. The assets include 25 active and 10 stacked drilling rigs, related drilling equipment, four yard facilities and a rig moving fleet consisting of approximately 45 trucks and 100 trailers. This transaction was completed in January 2005 using approximately $62 million of cash.
2004 Acquisition
      TMBR/ Sharp Drilling, Inc. — On February 11, 2004, the Company completed its acquisition of 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.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      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
    12,638  
Less: Cash acquired
    (7,909 )
       
 
Total purchase price
  $ 114,399  
       
      The purchase price was allocated among assets acquired and liabilities assumed based on their estimated fair market values as follows (in thousands):
           
Current assets
  $ 7,181  
Fixed assets
    60,784  
Other long term assets
    172  
Deferred tax assets
    13,080  
Goodwill
    50,147  
Current liabilities
    (7,080 )
Other long term liabilities
    (1,090 )
Deferred tax liability
    (8,795 )
       
 
Total purchase allocation
  $ 114,399  
       
      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.
      The following represents pro-forma unaudited financial information as if the acquisition had been completed on January 1, 2003 (in thousands, except per share amounts):
                   
    2004   2003
         
Revenue
  $ 1,005,357     $ 818,774  
Income before cumulative effect of change in accounting principle
    108,434       58,598  
Net income
    108,434       58,193  
Earnings per share:
               
 
Basic
  $ 0.65     $ 0.36  
             
 
Diluted
  $ 0.64     $ 0.35  
             
2003 Acquisitions
      SEI Drilling Company — On January 31, 2003, the Company acquired four land-based drilling rigs and related equipment from SEI Drilling Company for $6.0 million in cash. 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.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Mesa Drilling, Inc. — On February 7, 2003, the Company acquired three land-based drilling rigs, a yard and other related equipment from Mesa Drilling, Inc. and related entities for $10.5 million in cash. 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.
      Other — On April 28, 2003, the Company acquired two land-based drilling rigs for $3.9 million in cash. 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.
      Hexadyne Drilling Corporation — On May 30, 2003, the Company acquired seven land-based drilling rigs and related equipment from Hexadyne Drilling Corporation for $10.1 million in cash. 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.
      Fort Drilling LLC — On November 17, 2003, the Company acquired three land-based drilling rigs, a shop facility and related equipment from Fort Drilling LLC for $7.2 million in cash. 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.
      Other — In addition to the above mentioned acquisitions, the Company spent approximately $3.1 million on other acquisitions of assets and costs associated with the acquisitions completed during 2003.
2002 Acquisition
      Odin Drilling, Inc. — On March 21, 2002, the Company acquired five SCR electric land-based drilling rigs through the acquisition of Odin Drilling, Inc., for a purchase price of $16.9 million. The purchase price consisted of 1.3 million shares of common stock valued at $13.03 per share (adjusted to reflect the two-for-one stock split on June 30, 2004). A deferred tax liability of $4.1 million was recorded as a result of the transaction. 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.
3. Comprehensive Income
      The following table illustrates the Company’s comprehensive income including the effects of foreign currency translation adjustments for the years ended December 31, 2004, 2003 and 2002 (in thousands):
                         
    2004   2003   2002
             
Net income
  $ 108,733     $ 56,419     $ 2,374  
Other comprehensive income:
                       
Foreign currency translation adjustment related to Canadian operations, net of tax
    4,677       8,773       457  
                   
Comprehensive income
  $ 113,410     $ 65,192     $ 2,831  
                   

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
4. Property and Equipment
      Property and equipment consisted of the following at December 31, 2004 and 2003 (in thousands):
                 
    2004   2003
         
Drilling rigs and related equipment
  $ 1,217,497     $ 1,022,795  
Other equipment
    83,683       65,659  
Oil and natural gas properties
    82,711       57,625  
Buildings
    13,008       11,773  
Land
    3,949       3,684  
             
      1,400,848       1,161,536  
Less accumulated depreciation and depletion
    (571,973 )     (467,905 )
             
    $ 828,875     $ 693,631  
             
5. Goodwill
      Goodwill is evaluated to determine if the fair value of the 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. With respect to the Company’s drilling and completion fluids business, the determination that no impairment existed as of December 31, 2004 was based on the segment’s improved operating results in 2004 and on the Company’s expectations that these improved results will continue. If the improved results do not continue, all or part of the goodwill of approximately $10 million associated with that business segment may be determined to be impaired. Goodwill as of December 31, 2004 and 2003 are as follows (in thousands):
                         
    2004   2003
         
Drilling:
               
 
Goodwill at beginning of period
  $ 41,215     $ 41,215  
   
Goodwill in TMBR
    50,147        
             
     
Goodwill at end of period
    91,362       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
  $ 101,326     $ 51,179  
             
6. Investment in Equity Securities
      As a result of the Company increasing its ownership of TMBR from 19.5% to 100% in 2004, the consolidated financial statements of Patterson-UTI Energy, Inc. and its wholly-owned subsidiaries have been restated to provide for the retroactive application of the equity method of accounting for the Company’s investment in TMBR.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The following table presents the restated balances as of December 31, 2003, and for the twelve months ended December 31, 2003 and 2002 using the equity method of accounting for its investment in TMBR (in thousands, except share amounts):
                   
    Previously    
    Reported   Restated
         
Balance Sheet as of December 31, 2003:
               
 
Investment in equity securities
  $ 20,274     $ 19,771  
 
Accumulated other comprehensive income, net of tax
    8,554       6,934  
 
Deferred tax liability
    143,490       143,309  
 
Retained earnings
    316,329       317,627  
                                     
    Twelve Months Ended   Twelve Months Ended
    December 31, 2003   December 31, 2002
         
    Previously       Previously    
    Reported   Restated   Reported   Restated
                 
Comprehensive Income
                               
 
Comprehensive income, net of tax
  $ 65,689     $ 65,192     $ 2,656     $ 2,831  
Income Statement
                               
 
Other income
    143       1,870       (137 )     225  
 
Deferred income tax expense
    17,274       17,908       23,548       23,705  
 
Net income
    55,326       56,419       2,169       2,374  
 
Net income per common share:
                               
   
Basic
  $ 0.34     $ 0.35     $ 0.01     $ 0.02  
                         
   
Diluted
  $ 0.34     $ 0.34     $ 0.01     $ 0.01  
                         
7. Accrued Expenses
      Accrued expenses consisted of the following at December 31, 2004 and 2003 (in thousands):
                 
    2004   2003
         
Salaries, wages, payroll taxes and benefits
  $ 21,245     $ 15,772  
Workers’ compensation liability
    38,677       31,646  
Sales, use and other taxes
    5,863       5,809  
Insurance, other than workers’ compensation
    7,061       1,848  
Other
    6,317       5,778  
             
    $ 79,163     $ 60,853  
             

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
8. Asset Retirement Obligation
      Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS 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 Company recorded a liability of approximately $1.1 million in the first quarter of 2003 upon initial adoption of SFAS 143. The following table describes the changes to the Company’s asset retirement obligations during 2004 and 2003 (in thousands):
                 
    2004   2003
         
Balance at beginning of year
  $ 1,163     $ 1,056  
Liabilities incurred*
    1,277       173  
Liabilities settled
    (153 )     (100 )
Accretion expense
    71       34  
             
Asset retirement obligation at end of year
  $ 2,358     $ 1,163  
             
 
The 2004 amount includes $1,091 of liabilities assumed in the acquisition of TMBR.
      Had SFAS 143 been in effect as of January 1, 2001, the impact on the Company’s results of operations would have been immaterial for the year ended December 31, 2002, and the asset retirement obligation would have been $1.1 million and $1.0 million as of December 31, 2002 and 2001, respectively. In addition, the cumulative effect of this change in accounting principle of approximately $469,000, net of tax, was recorded in the first quarter of 2003.
9. Notes Payable
      The Company replaced its prior credit facility in December 2004 with a five-year, $200 million unsecured revolving line of credit (“LOC”). Interest is to be paid on outstanding LOC balances at a floating rate ranging from LIBOR plus 0.625% to 1.0% or the prime rate. This arrangement includes various fees, including a commitment fee on the average daily unused amount (0.15% at December 31, 2004). There are customary restrictions and covenants associated with the LOC. Financial covenants provide for a maximum debt to capitalization ratio and a minimum interest coverage ratio. The Company does not expect that the restrictions and covenants will restrict its ability to operate or react to opportunities that might arise. Availability under the LOC is reduced by outstanding letters of credit which totaled $49 million at December 31, 2004. There were no outstanding borrowings under the LOC at December 31, 2004. Costs of approximately $445,000 were expensed in 2004 to terminate the previous $100 million credit facility.
10. Commitments, Contingencies and Other Matters
      The Company maintains letters of credit in the aggregate amount of $49.0 million 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. These letters of credit expire variously during each calendar year. No amounts have been drawn under the letters of credit.
      Contingencies — The Company’s contract services and oil and natural gas exploration and production operations are subject to inherent risks, including blowouts, cratering, fire and explosions which could result in personal injury or death, suspended drilling operations, damage to, or destruction of equipment, damage to producing formations and pollution or other environmental hazards.
      As a protection against these hazards, the Company maintains general liability insurance coverage of $2.0 million per occurrence with $4.0 million of aggregate coverage and excess liability and umbrella

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
coverages up to $50.0 million per occurrence and in the aggregate. The Company maintains a $1.0 million per occurrence deductible on its workers’ compensation insurance and its general liability insurance coverages. These levels of self-insurance expose the Company to increased operating costs and risks.
      Net income for the year ended December 31, 2002 includes a charge of $4.7 million related to the financial failure in 2002 of a workers’ compensation insurance carrier that had provided coverage for the Company in prior years.
      The Company believes it is adequately insured for public liability and property damage to others with respect to its operations. However, such insurance may not be sufficient to protect the Company against liability for all consequences of well disasters, extensive fire damage, or damage to the environment. The Company also carries insurance to cover physical damage to, or loss of, its rigs; however, it does not carry insurance against loss of earnings resulting from such damage or loss.
      The Company is party to various legal proceedings arising in the normal course of its business. The Company does not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on its financial condition.
      Other Matters — Effective January 29, 2004, the Company entered into Change in Control Agreements with its Chairman of the Board, Chief Executive Officer, President and Chief Operating Officer, two Senior Vice Presidents and Chief Financial Officer (the “Key Employees”). Each Change in Control Agreement generally has a three-year term with automatic twelve month renewals unless the Company notifies the Key Employee at least ninety days before the end of such renewal period that the term will not be extended. If a change in control of the Company occurs during the term of the agreement and the Key Employee’s employment is terminated (i) by the Company other than for cause or other than automatically as a result of death, disability or retirement or (ii) by the Key Employee for good reason (as those terms are defined in the Change in Control Agreements), then the Key Employee shall be entitled to, among other things,
  •  bonus payment equal to the greater of the highest bonus paid after the Change in Control Agreement was entered into and the average of the two annual bonuses earned in the two fiscal years immediately preceding a change in control (such bonus payment prorated for the portion of the fiscal year preceding the termination date);
 
  •  a payment equal to 2.5 times (in the case of the Chairman of the Board, Chief Executive Officer and President and Chief Operating Officer) or 1.5 times (in the case of the Senior Vice Presidents and the Chief Financial Officer) of the sum of (i) the highest annual salary in effect for such Key Employee and (ii) the average of the three annual bonuses earned by the Key Employee for the three fiscal years preceding the termination date; and
 
  •  continued coverage under the Company’s welfare plans for up to three years (in the case of the Chairman of the Board, Chief Executive Officer and President and Chief Operating Officer) or two years (in the case of the Senior Vice Presidents and the Chief Financial Officer).
      Each Change in Control Agreement provides the Key Employee with a full gross-up payment for any excise taxes imposed on payments and benefits received under the Change in Control Agreements or otherwise, including other taxes that may be imposed as a result of the gross-up payment.
11. Stockholders’ Equity
      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 (adjusted to reflect the two-for-one stock split on June 30, 2004). These shares are included in treasury stock at December 31, 2004.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      During the second quarter of 2004, the Company granted Restricted Shares to certain key employees under the Patterson-UTI Energy, Inc. 1997 Long-Term Incentive Plan, as amended. 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. Compensation expense of approximately $773,000, net of tax, was included in net income for the year ended December 31, 2004.
      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 Consolidated Statements of Income and elsewhere in this Report have been restated as if the two-for-one stock split had occurred on January 1, 2002.
      On April 28, 2004, the Company’s Board of Directors approved the initiation of a quarterly cash dividend of $0.02 on each share of its common stock which was paid on June 2, 2004. Quarterly dividends in the amount of $0.02 per share were also paid on September 1, 2004 and December 1, 2004. Total dividends paid in 2004 were approximately $10 million. In February 2005, the Company’s Board of Directors approved an increase in the quarterly cash dividend on the Company’s common stock to $0.04 per share from $0.02 per share. The next quarterly cash dividend is to be paid to holders of record on February 28, 2005 and paid on March 4, 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.
      In February 2004, the Company completed its acquisition of TMBR in which one of its wholly-owned subsidiaries acquired 100% of the remaining outstanding shares of TMBR for a net cash payment of $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 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).
      During March 2002, the Company issued 1.3 million shares (adjusted to reflect the two-for-one stock split on June 30, 2004) of its common stock as consideration for the acquisition of Odin Drilling, Inc. (see Note 2). The common stock was valued at $13.03 per share, its fair market value on the date the terms of the transaction were agreed upon.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
12. Stock Options and Warrants
      Employee and Non-Employee Director Stock Option Plans — The Company has seven stock option plans of which three have shares available for grant. The remaining four plans are dormant and the Company does not intend to grant any further options under such plans. At December 31, 2004, the Company’s stock option plans were as follows:
                         
    Options       Options
    Authorized   Options   Available
Plan Name   for Grant   Outstanding   for Grant
             
Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan, as amended (“1997 Plan”)(1)
    16,500,000       7,711,776       2,997,992  
Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (“2001 Plan”)(2)
    2,000,000       1,346,322       78,161  
Amended and Restated Non-Employee Director Stock Option Plan of Patterson-UTI Energy, Inc. (“Non-Employee Director Plan”)
    1,200,000       370,000       485,000  
Patterson-UTI Energy, Inc. Non-Employee Directors’ Stock Option Plan, as amended (“1995 Non-Employee Director Plan”)
    240,000       24,000        
1997 Stock Option Plan of DSI Industries, Inc. (“DSI Plan”)
          2,144        
Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee Stock Option Plan (“1996 Plan”)
          176,600        
Patterson-UTI Energy, Inc., 1993 Incentive Stock Plan, as amended (“1993 Plan”)
    5,600,000       351,200        
 
(1)  Plan is for the benefit of employees of the Company, including officers and directors of the Company.
 
(2)  Plan is for the benefit of employees of the Company, other than officers and directors of the Company.
      The Company’s active plans are the 1997 Plan, the 2001 Plan and the Non-Employee Director Plan. A summary of each of these plans is set forth below.
1997 Plan
  •  Administered by the Compensation Committee of the Board of Directors.
 
  •  All employees including officers and employee directors are eligible for awards.
 
  •  Vesting schedule is set by the Compensation Committee, however, typically options vest over 3 or 5 years.
 
  •  The Compensation Committee sets the term of the option except that no Incentive Stock Option (“ISO”) can have a term of longer than 10 years. Typically options granted under the plan have a term of 10 years.
 
  •  The options granted under the plan, unless otherwise stated in the grant thereof, vest upon a change of control as defined in the plan. Options granted to non-executive employees typically do not vest upon a change of control.
 
  •  All options granted under the plan are granted with an exercise price equal to or greater than the fair market value of the Company’s common stock at the time the option is granted.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
  •  The plan allows for awards of tandem and independent stock appreciation rights, restricted stock and performance awards.
2001 Plan
      The terms and conditions of the 2001 Plan are identical to the 1997 Plan except as follows:
  •  Officers and directors of the Company are not eligible for grants of options under the 2001 Plan.
 
  •  No ISO’s may be awarded under the 2001 Plan.
 
  •  Unless the grant states otherwise, options granted under the 2001 Plan do not vest upon a change of control of the Company.
Non-Employee Director Plan
  •  Administered by the Compensation Committee of the Board of Directors.
 
  •  All options vest upon the first anniversary of the option grant.
 
  •  Each director receives options to purchase 40,000 shares upon becoming a director of the Company and options to purchase 20,000 shares on December 31st of each subsequent year in which the director serves as a director of the Company.
 
  •  The exercise price of the options is the fair market value of the Company’s common stock on the date of grant.
      1995 Non-Employee Director Plan — Options granted under the 1995 Non-Employee Director Plan vest on the first anniversary of the option grant. 1995 Non-Employee Director Plan options have five year terms. All options were granted with an exercise price equal to the fair market value of the Company’s common stock at the time of grant.
      DSI Plan — The options granted under the DSI plan typically vested at a rate of 33% per year with ten year terms. All options were granted with an exercise price equal to the fair market value of the Company’s common stock at the time of grant.
      1996 Plan — The options granted under the 1996 plan vested over one, four and five years as dictated by the Compensation Committee. These options had terms of five and ten years as dictated by the Compensation Committee. All options were granted with an exercise price equal to the fair market value of the Company’s common stock at the time of grant.
      1993 Plan — Options granted under the 1993 Plan, typically had terms of 10 years and vested over five years in 20% increments beginning at the end of the first year. These options vest in the event of a change of control as defined in the plan. All options were granted with an exercise price equal to the fair market value of the Company’s common stock at the time of grant.
      Additional Options — In July 2001, the Compensation Committee granted to each of two non-employee directors of the Company an option to purchase 24,000 shares of the Company’s common stock. These options vested on November 6, 2001 and terminate on November 5, 2005. The exercise price of each of the options was $14.3125, which was in excess of the fair market value of the Company’s common stock on the date of grant.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      A summary of the status of the Company’s stock options issued as of December 31, 2004, 2003 and 2002 and the changes during each of the years then ended are presented below (in thousands, except weighted average exercise price):
                                                   
    2004   2003   2002
             
    No. of   Weighted   No. of   Weighted   No. of   Weighted
    Shares of   Average   Shares of   Average   Shares of   Average
    Underlying   Exercise   Underlying   Exercise   Underlying   Exercise
    Options   Price   Options   Price   Options   Price
                         
Outstanding at beginning of year
    12,276     $ 10.31       12,277     $ 8.81       13,192     $ 5.20  
 
Granted
    640       19.19       1,830       16.24       4,297       13.39  
 
Exercised
    (2,852 )     5.55       (1,736 )     5.92       (4,914 )     3.21  
 
Surrendered/ Expired
    (58 )     8.76       (95 )     9.99       (298 )     7.66  
                                     
Outstanding at end of year
    10,006     $ 12.24       12,276     $ 10.31       12,277     $ 8.81  
                                     
Exercisable at end of year
    6,377     $ 11.68       5,972     $ 8.15       4,790     $ 5.44  
                                     
      The following table summarizes information about stock options outstanding at December 31, 2004:
                                         
    Options Outstanding   Options Exercisable
         
        Weighted        
        Average   Weighted       Weighted
        Remaining   Average       Average
    Number   Contracted   Exercise   Number   Exercise
Range of Exercise Prices   Outstanding   Life   Price   Exercisable   Prices
                     
$1.5625 to $ 2.50
    416,668       4.23     $ 2.31       416,668     $ 2.31  
$  2.51 to $ 5.00
    98,000       3.16     $ 4.94       98,000     $ 4.94  
$  5.01 to $ 7.50
    156,344       2.70     $ 7.32       156,344     $ 7.32  
$  7.51 to $10.00
    2,576,227       6.45     $ 8.02       1,365,617     $ 8.08  
$ 10.01 to $12.50
    95,000       2.88     $ 11.44       95,000     $ 11.44  
$ 12.51 to $15.00
    4,103,803       7.50     $ 13.35       3,085,833     $ 13.28  
$ 15.01 to $19.45
    2,560,000       7.98     $ 16.95       1,159,998     $ 16.19  
                               
      10,006,042       7.06     $ 12.24       6,377,460     $ 11.68  
                               
      Pro Forma Stock-Based Compensation Disclosure — Pro forma information in accordance with SFAS 123 regarding net income and earnings per share, as described in Note 1, has been determined as if the Company had accounted for its employee stock options under the fair value method as defined in that statement. The fair value of each stock option granted is estimated on the date of grant using the Black-Scholes option valuation model with the following weighted-average assumptions for grants in 1996 through 2004 respectively; dividend yield of 0.06% for all 2004 grants and 0.00% for all other grants; risk-free interest rates are different for each grant and range from 2.18% to 7.02%; the expected term ranges from 3 to 6 years; and a volatility of 38.68% for all 1996 grants, 35.97% for all 1997 grants, 51.08% for all 1998 grants, 61.97% for all 1999 grants, 67.71% for all 2000 grants, 68.33% for all 2001 grants, 63.02% for all 2002 grants, 44.04% for all 2003 grants and 36.84% for all 2004 grants. The effects of applying SFAS 123 in this pro forma disclosure are not indicative of future amounts. SFAS 123 does not apply to awards prior to 1996.
      Stock Purchase Warrants — In December 2001, the Company issued 650,000 warrants exercisable at $13.375 per share as partial consideration for the purchase of 17 drilling rigs and related equipment from Cleere Drilling Company. The warrants were fully exercisable at the date of issuance. All of the warrants were exercised in December 2004.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      In June 2000, the Company issued 254,000 warrants exercisable at $11 per share as partial consideration for the purchase of eight drilling rigs and related equipment from High Valley Drilling, Inc. The warrants were fully exercisable at the date of issuance. All of the warrants were exercised in 2003 and 2002.
      Tabular Summary — The following table summarizes information regarding the Company’s stock options and warrants granted under the provisions of the aforementioned plans as well as stock options and warrants issued pursuant to transactions described above (in thousands, except weighted average exercise prices):
                   
        Weighted
        Average
    Shares   Exercise Price
         
Granted
               
 
2004
    640     $ 19.19  
 
2003
    1,830       16.24  
 
2002
    4,297       13.39  
Exercised
               
 
2004
    3,502     $ 7.00  
 
2003
    1,941       6.46  
 
2002
    4,963       3.28  
Surrendered
               
 
2004
    58     $ 8.76  
 
2003
    95       9.99  
 
2002
    298       7.66  
Outstanding at Year End
               
 
2004
    10,006     $ 12.24  
 
2003
    12,926       10.47  
 
2002
    13,132       9.07  
Exercisable at Year End
               
 
2004
    6,377     $ 11.68  
 
2003
    6,622       8.66  
 
2002
    5,645       6.56  
13. Leases
      The Company incurred rent expense, consisting primarily of daily rental charges for the use of drilling equipment, of $9.1 million, $8.6 million and $5.7 million, for the years 2004, 2003 and 2002, respectively. The Company’s obligations under non-cancelable operating lease agreements are not material to the Company’s operations.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
14. Income Taxes
      Components of the income tax provision applicable for Federal, state and foreign income taxes are as follows (in thousands):
                           
    2004   2003   2002
             
Federal income tax expense (benefit):
                       
 
Current
  $ 32,438     $ 13,856     $ (18,064 )
 
Deferred
    20,375       15,143       21,844  
                   
      52,813       28,999       3,780  
State income tax expense (benefit):
                       
 
Current
    2,015       1,214       (1,811 )
 
Deferred
    2,170       76       1,117  
                   
      4,185       1,290       (694 )
Foreign income tax expense (benefit):
                       
 
Current
    5,235       18       (2,003 )
 
Deferred
    928       2,689       744  
                   
      6,163       2,707       (1,259 )
Total:
                       
 
Current
    39,688       15,088       (21,878 )
 
Deferred
    23,473       17,908       23,705  
                   
Total income tax expense
  $ 63,161     $ 32,996     $ 1,827  
                   
      The difference between the statutory Federal income tax rate and the effective income tax rate is summarized as follows:
                         
    2004   2003   2002
             
Statutory tax rate
    35.0 %     35.0 %     35.0 %
State income taxes
    1.6       1.5       2.8  
Permanent differences
    0.4       0.8       5.7  
Other, net
    (0.3 )     (0.6 )      
                   
Effective tax rate
    36.7 %     36.7 %     43.5 %
                   
      In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. The Company expects the deferred tax assets at December 31, 2004 to be realized as a result of the reversal during the carryforward period of existing taxable temporary differences giving rise to deferred tax liabilities and the generation of taxable income in the carryforward period; therefore, no valuation allowance is necessary.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The tax effect of significant temporary differences representing deferred tax assets and liabilities and changes therein were as follows (in thousands):
                                                             
    December 31,   Net   December 31,   Net   December 31,   Net   January 1,
    2004   Change   2003   Change   2002   Change   2002
                             
Deferred tax assets:
                                                       
 
Current:
                                                       
   
Federal net operating loss carryforwards
  $ 1,870     $ 1,870     $     $  —     $     $  —     $  
   
Workers’ compensation allowance
    14,877       1,545       13,332       6,159       7,173       2,663       4,510  
   
AMT credit
          (602 )     602             602             602  
   
Other
    6,978       1,238       5,740       (1,775 )     7,515       3,880       3,635  
                                           
      23,725       4,051       19,674       4,384       15,290       6,543       8,747  
                                           
 
Non-current:
                                                       
   
Federal net operating loss carryforwards
    4,115       4,115                                
   
AMT credit
    118       118                                
   
Federal benefit of foreign deferred tax liabilities
    6,708       933       5,775       2,019       3,756       744       3,012  
   
Federal benefit of state deferred tax liabilities
    4,160       639       3,521       1,470       2,051       556       1,495  
   
Other
    763       763                                
                                           
      15,864       6,568       9,296       3,489       5,807       1,300       4,507  
                                           
Total deferred tax assets
    39,589       10,619       28,970       7,873       21,097       7,843       13,254  
                                           
Deferred tax liabilities:
                                                       
 
Current:
                                                       
   
Other
    (7,734 )     (4,509 )     (3,225 )     (3,225 )                  
 
Non-current:
                                                       
   
Property and equipment basis difference
    (177,637 )     (27,182 )     (150,455 )     (18,077 )     (132,378 )     (35,607 )     (96,771 )
   
Other
    (267 )     1,883       (2,150 )     (1,575 )     (575 )     20       (595 )
                                           
      (177,904 )     (25,299 )     (152,605 )     (19,652 )     (132,953 )     (35,587 )     (97,366 )
                                           
Total deferred tax liabilities
    (185,638 )     (29,808 )     (155,830 )     (22,877 )     (132,953 )     (35,587 )     (97,366 )
                                           
Net deferred tax liability
  $ (146,049 )   $ (19,189 )   $ (126,860 )   $ (15,004 )   $ (111,856 )   $ (27,744 )   $ (84,112 )
                                           
      Other deferred tax assets consist primarily of various allowance accounts and tax deferred expenses expected to generate future tax benefit of approximately $7 million. Other deferred tax liabilities consist primarily of receivables from insurance companies not yet recognized for tax purposes.
      For tax purposes, the Company has available at December 31, 2004, Federal net operating loss carryforwards of approximately $16 million and $118,000 of alternative minimum tax credit carryforwards. These carryforwards are attributable to the acquisition of TMBR in February 2004.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The net operating loss carryforwards, if unused, are scheduled to expire as follows: 2005 — $5 million, 2006 — $1 million, 2011 — $2 million, 2018 — $4 million and 2019 — $4 million. The alternative minimum tax credit may be carried forward indefinitely.
15. Employee Benefits
      The Company maintains a 401(k) plan for all eligible employees. The Company’s operating results include expenses of approximately $2.2 million in 2004, $1.5 million in 2003 and $2.1 million in 2002 for the Company’s discretionary contributions to the plan.
16. Business Segments
      The Company conducts its business through four distinct operating segments: contract drilling of oil and natural gas wells, pressure pumping services and drilling and completion fluids services to operators in the oil and natural gas industry, and 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.
      Contract Drilling — The Company markets its contract drilling services to major and independent oil and natural gas operators. As of December 31, 2004, the Company owned 361 drilling rigs, of which 149 of the drilling rigs were based in the Permian Basin region, 55 in South Texas, 42 in the Ark-La-Tex region and Mississippi, 77 in the Mid-Continent region, 21 in the Rocky Mountain region and 17 in Western Canada. The Company operated 259 of its drilling rigs in 2004.
      Pressure Pumping — The Company provides pressure pumping services primarily in the Appalachian Basin. Pressure pumping services consist primarily of well stimulation and cementing for the completion of new wells and remedial work on existing wells. Well stimulation involves processes inside a well designed to enhance the flow of oil, natural gas, or other desired substances from the well. Cementing is the process of inserting material between the hole and the pipe to center and stabilize the pipe in the hole.
      Drilling and Completion Fluids — The Company provides 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. The drilling fluids operations were added by the Company during 1998 with its acquisition of two companies with operations in Texas, Southeastern New Mexico, Oklahoma and Colorado. The Company’s services were expanded to include completion fluids in October 2000 with the acquisition of the drilling and completion fluids division of Ambar, Inc., which had operations in the coastal areas of Texas, Louisiana and in the Gulf of Mexico.
      Oil and Natural Gas — The Company is engaged in the development, exploration, acquisition and production of oil and natural gas.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The following tables summarize selected financial information relating to the Company’s business segments (in thousands):
                           
    Years Ended December 31,
     
    2004   2003   2002
             
Revenues:
                       
 
Contract drilling(a)
  $ 815,683     $ 640,788     $ 410,752  
 
Pressure pumping
    66,654       46,083       32,996  
 
Drilling and completion fluids(b)
    90,858       69,286       69,966  
 
Oil and natural gas
    33,867       21,163       14,723  
                   
Total segment revenues
    1,007,062       777,320       528,437  
 
Elimination of intercompany revenues(a)(b)
    (6,293 )     (1,150 )     (480 )
                   
Total revenues
  $ 1,000,769     $ 776,170     $ 527,957  
                   
Income before income taxes:
                       
 
Contract drilling
  $ 150,047     $ 75,666     $ 7,607  
 
Pressure pumping
    16,747       10,442       6,090  
 
Drilling and completion fluids
    4,162       (1,960 )     (278 )
 
Oil and natural gas
    10,764       7,784       3,945  
                   
      181,720       91,932       17,364  
 
Corporate and other
    (10,506 )     (7,194 )     (9,266 )
 
Restructuring and other charges(c)
          2,452       (4,700 )
 
Interest income
    1,140       1,116       1,110  
 
Interest expense
    (695 )     (292 )     (532 )
 
Other
    235       1,870       225  
                   
Income before income taxes
  $ 171,894     $ 89,884     $ 4,201  
                   
 
(a)  Includes contract drilling intercompany revenues of approximately $6.0 million, $1.1 million and $457,000 for the years ended December 31, 2004, 2003 and 2002, respectively.
 
(b)  Includes drilling and completion fluids intercompany revenues of approximately $301,000, $56,000 and $23,000 for the years ended December 31, 2004, 2003 and 2002, respectively.
 
(c)  Restructuring and other charges relate 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 charges have been separately presented and excluded from the results of specific segments. These charges are primarily related to the contract drilling segment.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
                           
    Years Ended December 31,
     
    2004   2003   2002
             
Identifiable assets:
                       
 
Contract drilling
  $ 1,044,147     $ 809,896     $ 694,020  
 
Pressure pumping
    62,866       46,763       35,084  
 
Drilling and completion fluids
    38,196       30,860       34,687  
 
Oil and natural gas
    66,734       33,494       20,854  
                   
      1,211,943       921,013       784,645  
 
Corporate and other(a)
    110,968       163,101       158,178  
                   
Total assets
  $ 1,322,911     $ 1,084,114     $ 942,823  
                   
Depreciation, depletion, amortization and impairment:
                       
 
Contract drilling
  $ 98,334     $ 84,379     $ 80,500  
 
Pressure pumping
    5,112       3,774       2,803  
 
Drilling and completion fluids
    2,196       2,319       2,216  
 
Oil and natural gas
    13,309       7,082       5,251  
                   
      118,951       97,554       90,770  
 
Corporate and other
    444       444       446  
                   
Total depreciation, depletion and amortization
  $ 119,395     $ 97,998     $ 91,216  
                   
Capital expenditures:
                       
 
Contract drilling
  $ 157,916     $ 95,175     $ 68,516  
 
Pressure pumping
    17,705       10,524       7,399  
 
Drilling and completion fluids
    1,488       912       1,571  
 
Oil and natural gas
    14,451       10,015       6,357  
                   
Total capital expenditures
  $ 191,560     $ 116,626     $ 83,843  
                   
 
(a)  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 CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
17. Quarterly Financial Information (unaudited)
      Quarterly financial information for the years ended December 31, 2004 and 2003 is as follows (in thousands, except per share amounts):
                                     
    1st   2nd   3rd   4th
    Quarter   Quarter   Quarter   Quarter
                 
2004
                               
Operating revenues
  $ 218,779     $ 234,510     $ 259,174     $ 288,306  
Operating income
    32,510       30,799       47,408       60,497  
Net income
    20,682       19,607       29,964       38,480  
Earnings per share:
                               
 
Basic
  $ 0.12     $ 0.12     $ 0.18     $ 0.23  
 
Diluted
  $ 0.12     $ 0.12     $ 0.18     $ 0.23  
2003
                               
Operating revenues
  $ 165,239     $ 195,624     $ 207,015     $ 208,292  
Operating income
    9,844       19,153       27,354       30,839  
Income before cumulative effect of change in accounting principle
    7,051       12,202       17,186       20,449  
Cumulative effect of change in accounting principle, net of related income tax benefit of approximately $287
    (469 )                  
Net income
    6,582       12,202       17,186       20,449  
Earnings per share:
                               
 
Basic:
                               
   
Income before cumulative effect of change in accounting principle
  $ 0.04     $ 0.08     $ 0.11     $ 0.13  
   
Net income
  $ 0.04     $ 0.08     $ 0.11     $ 0.13  
 
Diluted:
                               
   
Income before cumulative effect of change in accounting principle
  $ 0.04     $ 0.07     $ 0.10     $ 0.12  
   
Net income
  $ 0.04     $ 0.07     $ 0.10     $ 0.12  
18. Concentrations of Credit Risk
      Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of demand deposits, temporary cash investments and trade receivables.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The Company believes that it places its demand deposits and temporary cash investments with high credit quality financial institutions. At December 31, 2004 and 2003, the Company’s demand deposits and temporary cash investments consisted of the following (in thousands):
                                 
            2004   2003
                 
Deposits in FDIC and SIPC-insured institutions under $100,000   $ 2,023     $ (3,326 )
Deposits in FDIC and SIPC-insured institutions over $100,000     131,427       112,226  
             
      133,450       108,900  
Less outstanding checks and other reconciling items     (21,079 )     (8,417 )
             
Cash and cash equivalents   $ 112,371     $ 100,483  
             
      Concentrations of credit risk with respect to trade receivables are primarily focused on companies involved in the exploration and development of oil and natural gas properties. The concentration is somewhat mitigated by the diversification of customers for which the Company provides drilling services. As is general industry practice, the Company generally does not require customers to provide collateral. No significant losses from individual contracts were experienced during the years ended December 31, 2004, 2003, or 2002. The Company recognized bad debt expense for 2004, 2003 and 2002 of $897,000, $259,000 and $320,000, respectively.
      The carrying values of cash and cash equivalents, marketable securities and trade receivables approximate fair value due to the short-term maturity of these assets.
19. Related Party Transactions
      Joint Operation of Oil and Natural Gas Properties — The Company operates certain oil and natural gas properties in which certain of its affiliated persons have participated, either individually or through entities they control, in the prospects or properties in which the Company has an interest. These participations, which have been on a working interest basis, have been in prospects or properties originated or acquired by Patterson-UTI. At December 31, 2004, affiliated persons were working interest owners in 237 of 300 total wells operated by Patterson-UTI. Sales were made by Patterson-UTI at its cost, comprised of Patterson-UTI’s costs of acquiring and preparing the working interests for sale. These costs were paid by the working interest owners on a pro rata basis based upon their working interest ownership percentage. The price at which working interests were sold to affiliated persons was the same price at which working interests were sold to unaffiliated persons. The affiliated persons earned oil and natural gas production revenue (net of royalty) of $13.8 million, $11.1 million and $6.9 million from these properties in 2004, 2003 and 2002, respectively. These persons or entities in turn paid for joint operating costs (including drilling and other development expenses) of $7.5 million, $7.9 million and $5.5 million incurred in 2004, 2003 and 2002, respectively. These activities resulted in a payable to the affiliated persons of approximately $1.2 million and $871,000 and a receivable from the affiliated persons of approximately $856,000 and $888,000 at December 31, 2004 and 2003, respectively.
      Other — In 2004, 2003 and 2002, the Company paid approximately $914,000, $740,000 and $279,000, respectively, to TMP Truck and Trailer LP (“TMP”), an entity owned by Thomas M. Patterson (son of A. Glenn Patterson), for certain equipment and metal fabrication services. Purchases from TMP were at current market prices.
      In 2004 and 2003, the Company paid approximately $39,000 and $209,000, respectively, to Melco Services (“Melco”) for dirt contracting services and $44,000 and $59,000, respectively, to L&N Transportation (“L&N”) for water hauling services. Both entities are owned by Lance D. Nelson, brother of Jonathan D. Nelson, Patterson-UTI’s Chief Financial Officer. Purchases from Melco and L&N were at current market prices.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
20. Supplementary Oil and Natural Gas Reserve Information and Related Data (Unaudited)
Oil and Natural Gas Expenditures and Capitalized Costs:
      Gross oil and natural gas expenditures for the years ended December 31, 2004, 2003 and 2002 are summarized below (in thousands):
                         
    2004   2003   2002
             
Property acquisition costs
  $ 2,491     $ 1,120     $ 905  
Exploration costs
    10,242       7,572       6,267  
Development costs
    1,855       1,531       845  
                   
    $ 14,588     $ 10,223     $ 8,017  
                   
      The aggregate amount of capitalized costs of oil and natural gas properties as of December 31, 2004, 2003 and 2002 is comprised of the following (in thousands):
                         
    2004   2003   2002
             
Proved properties
  $ 71,731     $ 50,481     $ 44,849  
Unproved properties
    10,980       7,144       7,162  
Accumulated depreciation and depletion
    (45,506 )     (38,947 )     (35,684 )
                   
    $ 37,205     $ 18,678     $ 16,327  
                   
Results of operations for oil and natural gas producing activities:
      Results of operations for oil and natural gas producing activities as of December 31, 2004, 2003 and 2002 are summarized below (in thousands):
                         
    2004   2003   2002
             
Oil and natural gas sales
  $ 31,142     $ 19,058     $ 12,738  
Gain on sale of oil and natural gas properties
    123       571       303  
                   
      31,265       19,629       13,041  
                   
Costs and expenses:
                       
Lease operating and production costs
    6,076       3,735       3,171  
Exploration costs including dry holes and abandonments
    1,902       1,073       785  
Depreciation and depletion
    10,112       5,638       4,524  
Impairment of oil and natural gas properties
    3,197       1,444       727  
Income tax expense
    3,662       2,840       1,687  
                   
      24,949       14,730       10,894  
                   
Results of operations for oil and natural gas producing activities
  $ 6,316     $ 4,899     $ 2,147  
                   

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Oil and natural gas reserve quantities:
      The following table sets forth information (in thousands) with respect to quantities of net proved oil and natural gas reserves and changes in those reserves for the years ended December 31, 2004, 2003 and 2002. The quantities were estimated by an independent petroleum engineer. The Company’s proved oil and natural gas reserves are located entirely within the United States.
                 
    Oil (Bbls)   Gas (Mcf)
         
Estimated quantity, January 1, 2002
    1,047       4,634  
Revision in previous estimates
    145       2,103  
Extensions, discoveries and other additions
    331       1,420  
Sales of reserves
    (12 )     (110 )
Production
    (284 )     (1,807 )
             
Estimated quantity, January 1, 2003
    1,227       6,240  
Revision in previous estimates
    87       (1,123 )
Extensions, discoveries and other additions
    149       2,446  
Sales of reserves
    (27 )     (244 )
Production
    (289 )     (2,052 )
             
Estimated quantity, January 1, 2004
    1,147       5,267  
Revision in previous estimates
    (122 )     (1,807 )
Extensions, discoveries and other additions
    392       2,675  
Purchases
    695       4,920  
Sales of reserves
    (6 )     (90 )
Production
    (392 )     (2,719 )
             
Estimated quantity, January 1, 2005
    1,714       8,246  
             
      Estimates of the Company’s proved reserves and future net revenues are determined based on various assumptions such as oil and natural gas prices, operating costs, reservoir performance and economic conditions. The oil and natural gas prices and operating cost assumptions were based on the actual prices and costs in effect as of the date of such estimates. These assumptions are held constant throughout the life of the properties, except operating costs are adjusted for contractual escalations. The Company’s independent petroleum engineer estimates the assumptions relating to reservoir performance and economic conditions using information available and industry experience. The oil and natural gas prices used to value the Company’s reserves as of December 31, 2004 were $43.45 per Bbl of oil and $6.15 per Mcf of natural gas. Estimates of reserves and production performance are subjective and may change materially as actual production information becomes available.

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Standardized measure of future net cash flows of proved developed oil and natural gas reserves, discounted at 10% per annum (in thousands):
                         
    Years Ended December 31,
     
    2004   2003   2002
             
Future gross revenues
  $ 123,201     $ 70,894     $ 68,165  
Future development and production costs
    (37,820 )     (23,021 )     (22,149 )
Future income tax expense
    (30,995 )     (15,155 )     (15,964 )
                   
Future net cash flows
    54,386       32,718       30,052  
Discount at 10% per annum
    (16,844 )     (8,768 )     (8,952 )
                   
Standardized measure of discounted future net cash flows
  $ 37,542     $ 23,950     $ 21,100  
                   
Changes in the standardized measure of net cash flows of proved developed oil and natural gas reserves discounted at 10% per annum (in thousands):
                         
    Years Ended December 31,
     
    2004   2003   2002
             
Standardized measure at beginning of year
  $ 23,950     $ 21,100     $ 10,714  
Sales and transfers of oil and natural gas produced, net of production costs
    (15,257 )     (11,362 )     (8,342 )
Net changes in sales price and future production and development costs
    6,619       4,718       4,888  
Extensions, discoveries and improved recovery, less related costs
    8,259       10,052       6,017  
Sales of minerals-in-place
    (676 )     (2,017 )     (30 )
Purchase of reserves
    19,561              
Revision of previous quantity estimates
    4,288       (2,976 )     4,315  
Accretion of discount
    3,759       3,547       1,531  
Other
    (3,953 )     101       (9,358 )
Net change in income taxes
    (9,008 )     787       11,365  
                   
Standardized measure at end of year
  $ 37,542     $ 23,950     $ 21,100  
                   

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
                                   
        Charged to        
    Beginning   Costs and       Ending
Description   Balance   Expenses(1)   Deductions(2)   Balance
                 
    (In thousands)
Year Ended December 31, 2004
                               
Deducted from asset accounts:
                               
 
Allowance for doubtful accounts
  $ 2,133     $ 897     $ 1,121     $ 1,909  
Year Ended December 31, 2003
                               
Deducted from asset accounts:
                               
 
Allowance for doubtful accounts
  $ 3,144     $ 259     $ 1,270     $ 2,133  
Year Ended December 31, 2002
                               
Deducted from asset accounts:
                               
 
Allowance for doubtful accounts
  $ 4,021     $ 320     $ 1,197     $ 3,144  
 
(1)  Net of recoveries.
 
(2)  Uncollectible accounts written off.

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SIGNATURES
      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Patterson-UTI Energy, Inc. 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
  Chief Executive Officer
Date: February 25, 2005
      Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on behalf of Patterson-UTI Energy, Inc. and in the capacities indicated as of February 25, 2005.
         
Signature   Title
     
 
/s/ MARK S. SIEGEL
 
Mark S. Siegel
  Chairman of the Board
 
/s/ CLOYCE A. TALBOTT
 
Cloyce A. Talbott
(Principal Executive Officer)
  Chief Executive Officer and Director
 
/s/ A. GLENN PATTERSON
 
A. Glenn Patterson
  President, Chief Operating Officer and Director
 
/s/ KENNETH N. BERNS
 
Kenneth N. Berns
  Senior Vice President and Director
 
/s/ JONATHAN D. NELSON
 
Jonathan D. Nelson
(Principal Financial and Accounting Officer)
  Vice President, Chief Financial Officer, Secretary and Treasurer
 
/s/ ROBERT C. GIST
 
Robert C. Gist
  Director
 
/s/ CURTIS W. HUFF
 
Curtis W. Huff
  Director
 
/s/ TERRY H. HUNT
 
Terry H. Hunt
  Director
 
/s/ KENNETH R. PEAK
 
Kenneth R. Peak
  Director
 
/s/ NADINE C. SMITH
 
Nadine C. Smith
  Director


Table of Contents

EXHIBIT INDEX
         
  2 .1   Asset Purchase Agreement among Key Energy Drilling, Inc., Key Energy Drilling Beneficial, L.P., Key Rocky Mountain, Inc., Key Four Corners, Inc. and Key Energy Services, Inc. and Patterson-UTI Drilling Company LP, LLLP and Patterson-UTI Energy, Inc., dated as of December 7, 2004.
  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).
  4 .1   Rights Agreement dated January 2, 1997, between Patterson Energy, Inc. and Continental Stock Transfer & Trust Company (filed January 14, 1997 as Exhibit 2 to the Company’s Registration Statement on Form 8-A and incorporated herein by reference).
  4 .2   Amendment to Rights Agreement dated as of October 23, 2001 (filed October 31, 2001 as Exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2001 and incorporated herein by reference).
  4 .3   Restated Certificate of Incorporation, as amended (See Exhibits 3.1 and 3.2).
  4 .4   Registration Rights Agreement with Bear, Stearns and Co. Inc., dated March  25, 1994, as assigned by REMY Capital Partners III, L.P.(filed March 19, 2002 as Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference).
  10 .1   For additional material contracts, see Exhibits 2.1, 4.1, 4.2 and 4.4.
  10 .2   Patterson-UTI Energy, Inc., 1993 Stock Incentive Plan, as amended (filed March 13, 1998 as Exhibit 10.1 to the Company’s Registration Statement on Form S-8 (File No. 333-47917) and incorporated herein by reference).*
  10 .3   Patterson-UTI Energy, Inc. Non-Employee Directors’ Stock Option Plan, as amended (filed November 4, 1997 as Exhibit 10.1 to the Company’s Registration Statement on Form S-8 (File No. 333-39471) and incorporated herein by reference).*
  10 .4   Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (filed November 27, 2002 as Exhibit 4.4 to Post Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60470) and incorporated herein by reference).*
  10 .5   Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 and incorporated herein by reference).*
  10 .6   Amendment to the Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed August 9, 2004 as Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
  10 .7   Amended and Restated Patterson-UTI Energy, Inc. Non-Employee Director Stock Option Plan(filed July 28, 2003 as Exhibit 4.8 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 and incorporated herein by reference).*
  10 .8   Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee Stock Option Plan (filed July 25, 2001 as Exhibit 4.4 to Post-Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60466) and incorporated herein by reference).*
  10 .9   1997 Stock Option Plan of DSI Industries, Inc. (filed July 25, 2001 as Exhibit 4.4 to Post-Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60470) and incorporated herein by reference).*
  10 .10   Stock Option Agreement dated July 20, 2001 between Patterson-UTI Energy, Inc. and Kenneth R. Peak (filed March 19, 2002 as Exhibit 10.9 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 .11   Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed August 9, 2004 as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
  10 .12   Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed August 9, 2004 as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
  10 .13   Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and A. Glenn Patterson (filed August 9, 2004 as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
  10 .14   Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed August 9, 2004 as Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
  10 .15   Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Jonathan D. Nelson (filed August 9, 2004 as Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
  10 .16   Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed August 9, 2004 as Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
  10 .17   Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on February 4, 2004 as Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
  10 .18   Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and A. Glenn Patterson (filed on February 4, 2004 as Exhibit 10.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
  10 .19   Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed on February 4, 2004 as Exhibit 10.4 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
  10 .20   Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on February 4, 2004 as Exhibit 10.5 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
  10 .21   Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Jonathan D. Nelson (filed on February 4, 2004 as Exhibit 10.6 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
  10 .22   Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed on February 4, 2004 as Exhibit 10.7 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
  10 .23   Form of Letter Agreement regarding termination, effective as of January 29, 2004, entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. Vollmer III.*
  10 .24   Form of Indemnification Agreement entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, A. Glenn Patterson, Kenneth N. Berns, Robert C. Gist, Curtis W. Huff, Terry H. Hunt, Kenneth R. Peak, Nadine C. Smith, Jonathan D. Nelson and John E. Vollmer III (filed April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and incorporated herein by reference).*
  10 .25   Credit Agreement dated as of December 17, 2004 among Patterson-UTI Energy, Inc., as the Borrower, Bank of America, N.A., as administrative agent, L/ C Issuer and a Lender and the other lenders and agents party thereto (filed on December 23, 2004 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
  10 .26   Summary Description of 2003 Cash Bonus Plan.*


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  10 .27   Summary Description of Director Compensation.*
  14 .1   Patterson-UTI Energy, Inc. Code of Business Conduct and Ethics for Senior Financial Executives (filed as Exhibit 14.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).
  21 .1   Subsidiaries of the Registrant.
  23 .1   Consent of Independent Registered Public Accounting Firm.
  23 .2   Consent of Independent Petroleum Engineer — M. Brian Wallace, P.E.
  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 identified as required by Item 15(a)(3) of Form 10-K.