Patterson-UTI Energy
Annual Report 2005

Plain-text annual report

2 0 0 5 A N N U A L R E P O R T Company Profile Patterson-UTI Energy, Inc. provides onshore contract drilling services to exploration and production companies in North America. The Company’s land-based drilling rigs operate in oil and natural gas producing regions of Texas, New Mexico, Oklahoma, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota and western Canada. Patterson-UTI Energy, Inc. is also engaged in the businesses of pressure pumping services and drilling and completion fluid services. Additionally, the Company has an exploration and production business that is based in Texas. Financial Highlights (in thousands, except per share amounts – unaudited) Revenues Operating income (loss) Net income (loss) Earnings (loss) per share Basic Diluted Total assets Long-term debt Shareholders’ equity Working capital Operational Highlights (dollars in thousands – unaudited) Operating days Average revenue per day Average margin per day (1) Average rigs operating Rig utilization percentage Year ended December 31, 2001 2002 2003 2004 2005 $989,975 $527,957 $ 776,170 $1,000,769 $1,740,455 259,721 159,572 1.04 1.01 (6,892) (4,140) (0.03) (0.03) 66,282 43,187 0.27 0.26 148,467 94,346 581,296 372,740 0.57 0.56 2.19 2.15 856,855 919,374 1,039,521 1,256,785 1,795,781 0 680,341 109,566 76,871 $ 10.93 $ 4.59 211 70% 0 724,248 166,885 0 789,814 198,399 0 961,501 235,480 0 1,367,011 382,448 45,919 68,798 $ $ 8.94 2.01 126 39% $ $ 9.30 2.39 188 56% $ $ 77,355 10.47 3.27 211 59% $ $ 100,591 14.77 7.05 276 69% (1) Average margin per day represents average revenue per day minus average direct operating costs per day and excludes provisions for bad debts, other charges, depreciation, depletion, amortization and impairment and selling, general and administrative expenses. Table of Contents Letter to Shareholders Form 10-K 5 9 Corporate Information Inside Back Cover 1 2 The Company also has a drilling and completion fluids business that operates in Texas, New Mexico, Oklahoma, Louisiana and in the Gulf of Mexico. Additionally, the Company has an exploration and production business that is based in Texas. CONTRACT DRILLING PRESSURE PUMPING Market Capitalization 6,000 5,000 4,000 3,000 2,000 1,000 0 ) s r a l l o d f o s n o i l l i m n i , 1 3 r e b m e c e D t a ( Drilling Rigs Owned 450 400 350 300 250 200 ) 1 3 r e b m e c e D t a ( 01 02 03 04 05 01 02 03 04 05 3 4 D E A R F E L L O W S H A R E H O L D E R S : WE ARE PLEASED TO REPORT RECORD RESULTS FROM OPERATIONS FOR 2005 AND TO SHARE OUR OUTLOOK FOR 2006, WHICH WE BELIEVE WILL BE ANOTHER RECORD YEAR FOR PATTERSON-UTI ENERGY, INC. In 2005 we achieved record-setting performances investing in upgrading and refurbishing from all of our operating units, including pressure existing equipment, and maintaining a pumping, drilling and completion fluids, oil strong infrastructure. and natural gas exploration and production, Increased Drilling Fleet: Five years ago along with our largest operating unit, contract Patterson and UTI owned 302 land-based Revenues land drilling, which generated 85 percent of drilling rigs; today we own 403 drilling rigs our revenue. Highlights From 2005 that operate primarily in the oil and natural gas producing regions of Texas, New Mexico, Oklahoma, Louisiana, Mississippi, Colorado, ■ Record Earnings: Net income increased Utah, Wyoming, Montana, North Dakota, by nearly 300 percent to $373 million, or South Dakota and western Canada. We have $2.15 per share. been able to significantly increase our drilling ■ Record Revenues: Revenues increased by rig fleet without mortgaging our future. These 74 percent to $1.7 billion. acquisitions have been financed primarily by ■ Strong Balance Sheet: Approximately cash generated from operations, rather than $136 million in cash and cash equivalents, through the issuance of common stock or the $382 million in working capital and no incurrence of debt. long-term debt as of December 31, 2005. Upgrading and Refurbishing Rigs: While we ■ Record Drilling Margin: Average drilling have increased the number of rigs that we own, margin increased by 116 percent to we have also invested in upgrading our existing $7,050 per operating day. rigs. In addition, we began a program of refurbishing stacked rigs in 2004 which Successful Strategy significantly increased our active rig fleet. We While 2005 was a positive year for our industry, continue to have a substantial portion of the it was a record-breaking year for Patterson-UTI incremental capacity in the land drilling industry. Energy, Inc. Our earnings increased nearly 300 Maintaining Key Field Personnel: We recognize percent on a 74 percent increase in revenues. the importance of maintaining key field personnel We believe that these results are a direct result and the need for attracting experienced of our consistent commitment to position managerial staff. We believe we have developed Patterson-UTI Energy for long-term growth an infrastructure that is able to react quickly and profitability by increasing our drilling fleet, and efficiently to the needs of our customers. 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 ) s r a l l o d f o s n o i l l i m n i ( 80 70 60 50 40 30 20 10 0 ) t n e c r e p n i ( 01 02 03 04 05 Rig Utilization 01 02 03 04 05 5 6 Favorable Commodity Environment have found that this measured approach allows Both oil and natural gas markets continued to us time to prepare rigs properly for activation be favorable in 2005. Oil averaged $56.49 per and to train crews, which permits us to maintain bbl (WTI), a 36 percent increase over the prior efficiency for our customers. year, and natural gas averaged $8.98 per mcf, a 51 percent increase over the prior year. With Stock Buyback Program these higher commodity prices, demand for On March 27, 2005 the Board approved an drilling services continued to increase significantly increase in the Company’s stock buyback during the year. Looking Ahead program, authorizing the purchase of up to $200 million of the Company’s common stock. The increase in the stock buyback program Looking ahead, we see continued strong demand demonstrates continued confidence in the for our rigs and an ongoing scarcity of rigs in Company’s strong cash flow and our continuing the overall market. To paraphrase a line from commitment to deploy excess capital in a manner Mark Twain and a recent analyst comment, we beneficial to shareholders. believe that the reports of the demise of the land drilling segment are greatly exaggerated. An Unfortunate Occurrence The demand for rigs, and indeed our services in Unfortunately, our record performance in 2005 pressure pumping and fluids, remains strong, was marred by the discovery in November 2005 and we continue to see a land drilling market that Jonathan D. Nelson, the former Chief characterized by a scarcity of rigs. We have seen Financial Officer, had embezzled approximately no indication that customers – whether large or $78 million from the Company over a more small – have retreated or plan to retreat from than five-year period. Upon the Company’s their drilling programs. discovery of the embezzlement: (a) the Although natural gas prices have declined Company obtained a confession from Mr. since the highs following Hurricane Katrina and Nelson, (b) the Company notified the SEC and the start of winter, we believe that current prices law enforcement authorities of the loss, and (c) and the expectations with respect to future prices the Company’s Audit Committee conducted a are such that our customers will continue with thorough investigation, which revealed the their expanded drilling efforts. We believe that means by which the embezzlement was the price expectations for natural gas, currently committed and the fact that no other Company reflected in the futures market, are well above the employees knowingly participated. As of today, “price deck” used by our customers to determine (i) the Company is current with all of its whether to drill wells. Based on what we are required public disclosure, (ii) Mr. Nelson has seeing from our customers, our plan for 2006 is pled guilty to wire fraud and money laundering to activate approximately 30 rigs in 2006. We and is awaiting sentencing, and (iii) the SEC Cash Flow From Operating Activities 500 450 400 400 350 300 250 200 150 100 50 0 ) s r a l l o d f o s n o i l l i m n i ( 01 02 03 04 05 7 has instituted a receivership proceeding to Conclusions recover the stolen money on behalf of the The positive results for 2005 would not have Company and other creditors. We deeply regret been possible without the skill and dedication that this embezzlement occurred, but we believe of employees throughout our Company – from that the Company’s management and Board of those who work in the field to those who serve Directors responded in a timely and intelligent in administrative and support roles. We appreciate manner to address the issues facing the Company their contribution and commitment to serving as soon as they were revealed. We firmly believe the needs of our customers. As always, we are that we have emerged a far stronger Company appreciative of the support that we have received and we continue to strive to use this unfortunate over the past year and are mindful of the fiduciary occurrence as an opportunity for improvement. responsibilities and obligations that we bear. We pledge to continue to do all that we can to be worthy of the trust and confidence that has been placed in us. Respectfully submitted, Mark S. Siegel Chairman Cloyce A. Talbott President and Chief Executive Officer 8 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K (Mark One) ¥ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Ñscal year ended December 31, 2005 or n 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 speciÑed in its charter) Delaware (State or other jurisdiction of incorporation or organization) 4510 Lamesa Highway, Snyder, Texas (Address of principal executive oÇces) 75-2504748 (I.R.S. Employer IdentiÑcation No.) 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 if the registrant is a well-known seasoned issuer, as deÑned in Rule 405 of the Securities Act. Yes ¥ or No n Indicate by check mark if the registrant is not required to Ñle reports pursuant to Section 13 or Section 15(d) of the Act. Yes n or No ¥ Indicate by check mark whether the registrant (1) has Ñled all reports required to be Ñled 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 Ñle such reports), and (2) has been subject to such Ñling requirements for the past 90 days. Yes ¥ No n Indicate by check mark if disclosure of delinquent Ñlers 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 deÑnitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¥ Indicate by check mark whether the registrant is a large accelerated Ñler, an accelerated Ñler, or a non- accelerated Ñler. See deÑnition of ""accelerated Ñler and large accelerated Ñler'' in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated Ñler ¥ Non-accelerated Ñler n Indicate by check mark whether the registrant is a shell company (as deÑned in Rule 12b-2 of the Accelerated Ñler n Act). Yes n No ¥ The aggregate market value of the voting and non-voting common equity held by non-aÇliates of the registrant as of June 30, 2005, the last business day of the registrant's most recently completed second Ñscal quarter, was $4,657,765,918, calculated by reference to the closing price of $27.83 for the common stock on the Nasdaq National Market on that date. As of March 29, 2006, the registrant had outstanding 172,653,028 shares of common stock, $.01 par value, its only class of voting common stock. Documents incorporated by reference: DeÑnitive Proxy Statement for the 2006 Annual Meeting of Stockholders (Part III). FORWARD LOOKING STATEMENTS 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 ""Risk Factors,'' beginning on page 11. Item 1. Business Available Information PART I 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 Ñled or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, are available free of charge through our Internet website (www.patenergy.com) as soon as reasonably practicable after we electronically Ñle such material with, or furnish it to, the United States Securities and Exchange Commission (""SEC''). 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, ‚ Montana, ‚ North Dakota, ‚ South Dakota, and ‚ Western Canada (Alberta, British Columbia and Saskatchewan). As of December 31, 2005, we had a drilling Öeet of 403 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 Öuids, completion Öuids 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 Öuids 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 and South Texas, Southeastern New Mexico, Utah and Mississippi. 1 Embezzlement and Restatements On November 3, 2005, we announced the resignation of our Chief Financial OÇcer (""CFO''), Jonathan D. Nelson (""Nelson''). On November 10, 2005, we announced that, based on information received by Company senior management on November 9, 2005, the Audit Committee of our Board of Directors began an investigation into an apparent embezzlement from us by Nelson. On December 22, 2005, upon recommendation of Company management and the Audit Committee of our Board of Directors, we announced that based on the results to date of the internal investigation into the facts and circumstances surrounding the embezzlement by Nelson, we would restate previously issued Ñnancial statements and amend our previously issued Annual Report on Form 10-K for the year ended December 31, 2004 and Quarterly Reports on Form 10-Q for the periods ended March 31, June 30 and September 30, 2005. These restatements reÖect losses incurred as a result of payments made to or for the beneÑt of Nelson that had been recognized in our accounting records and previously issued Ñnancial statements as payments for assets and services that we did not receive. Previously issued Ñnancial statements have also been restated for the eÅects of the correction of other errors that are immaterial both individually and in the aggregate. These other adjustments relate primarily to previously reported property and equipment balances that resulted from our review of our property and equipment records and the underlying physical assets in connection with investigation of the embezzlement. We have restated such Ñnancial statements, and on March 17, 2006, we Ñled our amended Annual Report on Form 10-K/A and on March 27, 2006, we Ñled our amended Quarterly Reports on Form 10-Q/A with the SEC. Most of the embezzled funds result from Nelson causing the wiring of Company funds aggregating approximately $72.3 million, to, or for the beneÑt of, entities owned and controlled by him. Nelson was originally able to initiate these wire transfers by requesting the wire transfers himself in telephone calls to one of the Company's banks. After changes to the Company's internal controls and procedures in 2004, Nelson initiated the wire transfers through instructions to one of his subordinates and by the creation of fraudulent invoices containing forged senior management approvals. This false documentation was created by Nelson to conceal the true nature of these transactions from the Company and its independent registered public accountants. Nelson also instructed certain former employees, who worked under his supervision, to alter management reports related to property and equipment expenditures. Nelson also created Ñctitious property and equipment approval forms with forged signatures. The total amount embezzled was approximately $77.5 million in cash, excluding any tax eÅects, beginning with the year ended December 31, 1998 through November 3, 2005 as follows (in thousands): From 1998 to December 31, 2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ From January 1, 2005 to September 30, 2005(1)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total through September 30, 2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ From October 1, 2005 to November 3, 2005 (net of $1,500 repayment)(1) ÏÏÏÏÏÏÏÏÏ Total embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $58,961 12,193 71,154 6,350 $77,504 (1) The total amount embezzled during 2005 was $18,543,000 and the Company incurred $1,500,000 of professional fees and expenses as a result of the embezzlement. Accordingly, the total embezzled funds and related expenses in 2005 were $20,043,000. We promptly advised the SEC when we became aware of the embezzlement. The SEC promptly obtained a freeze order on Nelson's assets (including assets held by entities controlled by him) and a Receiver was appointed to collect those assets. The United States attorney for the Northern District of Texas obtained an indictment against Nelson and investigation of this matter continues. The Company understands that the Receiver will ultimately liquidate the assets and propose a plan to distribute the proceeds. While the Company believes it has a claim for at least the full amount embezzled, other creditors have or may assert claims on the assets held by the Receiver. As a result, recovery by the 2 Company from the Receiver is uncertain as to timing and amount, if any. Recoveries, if any, will be recognized when they are considered collectable. The eÅects of the embezzlement on our Ñnancial position follow (in thousands): Decrease in amounts previously reported December 31, 2004 2003 Assets(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Liabilities(2) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Retained earnings and stockholders' equityÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $(56,133) (20,848) $(35,285) $(38,540) (15,044) $(23,496) (1) The amount includes a decrease in Federal and state income taxes receivable of $1.0 million in 2003. (2) Consists of an increase in Federal and state income taxes payable of $1.3 million in 2004 and decreases in deferred tax liabilities of $22.2 million and $15.0 million in 2004 and 2003, respectively. In December 2005, two purported derivative actions were Ñled in Texas state court in Scurry County, Texas, against our directors, alleging that the directors breached their Ñduciary duties to us as a result of alleged failure to timely discover the embezzlement. The Board of Directors formed a special litigation committee to review and inquire about these allegations and recommend our response, if any. The lawsuits seek recovery on behalf of and for us and do not seek recovery from us. The Ñnancial statements and related Ñnancial and statistical data contained in this Report have been restated to provide for, net of related tax eÅects, (1) the eÅects of losses incurred as a result of the embezzlement and (2) the eÅects of the correction of other errors that are immaterial both individually and in the aggregate. Industry Segments Our revenues, operating proÑts and identiÑable assets are primarily attributable to four industry segments: ‚ contract drilling, ‚ pressure pumping services, ‚ drilling and completion Öuids services, and ‚ oil and natural gas development, exploration, acquisition and production. With respect to these four segments: ‚ the contract drilling segment had operating proÑts in 2005, 2004 and 2003, ‚ the pressure pumping segment had operating proÑts in 2005, 2004 and 2003, ‚ the drilling and completion Öuids segment had operating proÑts in 2005 and 2004 and an operating loss in 2003, and ‚ the oil and natural gas segment had operating proÑts in 2005, 2004 and 2003. See ""Management's Discussion and Analysis of Financial Condition and Results of Operations'' and Note 17 of Notes to Consolidated Financial Statements included as a part of Items 7 and 8, respectively, of this Report for Ñnancial information pertaining to these industry segments. Contract Drilling Operations General Ì We market our contract drilling services to major and independent oil and natural gas operators. As of December 31, 2005, we owned 403 drilling rigs which were based in the following regions: ‚ 156 in the Permian Basin region (West Texas and Southeastern New Mexico), ‚ 53 in South Texas, 3 ‚ 42 in the Ark-La-Tex region and Mississippi, ‚ 88 in the Mid-Continent region (Oklahoma and North Central Texas), ‚ 46 in the Rocky Mountain region (Colorado, Utah, Wyoming, Montana, North Dakota and South Dakota), and ‚ 18 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, 42 are SCR electric rigs and 361 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 Öuid, ‚ blowout preventers, ‚ drill string (pipe), and ‚ other related equipment. Over time, components on a drilling rig are replaced or rebuilt. We spend signiÑcant 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 Ñscal years 2005, 2004 and 2003, we spent approximately $329 million, $141 million and $77 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 ‚ qualiÑed personnel, some of which have been in short supply from time to time. Drilling Contracts Ì 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. Customer demand for drilling contracts with a term of one or more years increased during 2005 due to the scarcity of available drilling rigs in the market place. In response to this demand, we entered into several long-term contracts in 2005, typically with a term of one year. We may continue to enter into long-term contracts when considered beneÑcial to the Company. 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 4 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. In the past we generally received a lower rate when the drilling rig was moving, or when drilling operations were interrupted or restricted by conditions beyond our control. Current market conditions have enabled us to receive rates at or near current daywork dayrates in many of these situations. 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 speciÑed conditions for a Ñxed price per foot. The customer provides drilling Öuids, casing, cementing and well design expertise. These 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 proÑts over those that would be attainable under a daywork contract. ProÑts 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 Ñre, blowouts and other risks. Due to current market conditions and improved rates received under daywork contracts, we are entering into fewer footage contracts than we did in the past. Turnkey Contracts Under turnkey contracts, we contract to drill a well to a certain depth under speciÑed conditions for a Ñxed 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 Öuids, 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 Ñres, 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 proÑts 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, proÑts can be signiÑcantly 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 diÅerent types of drilling contracts: daywork, footage and turnkey. Due to current market conditions and improved rates received under daywork contracts, we are entering into fewer turnkey contracts than we did in the past. 5 Revenues by Contract Type Ì Information regarding our contract drilling activity for the last three years follows: Type of Revenues Years Ended December 31, 2003 2004 2005 DayworkÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Footage ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Turnkey ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 98% 1 1 88% 6 6 83% 7 10 Contract Drilling Activity Ì Information regarding our contract drilling activity for the last three years follows: Years Ended December 31, 2003 2004 2005 Average rigs ownedÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average rigs operating(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average rig utilization rate ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Number of rigs operated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Number of wells drilled ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 397 276 359 211 336 188 69% 59% 56% 307 4,594 259 3,534 226 3,017 (1) A rig is operating when it is drilling, being moved, assembled, dismantled or otherwise earning revenue under contract. Drilling Rigs and Related Equipment Ì Certain drilling rig information as of December 31, 2005 follows: Depth Rating (Ft.) Mechanical Electric Total 4,000 to 9,999 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 10,000 to 11,999 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 12,000 to 14,999 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 15,000 to 30,000 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ TotalsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 79 76 139 67 361 Ì 2 8 32 42 79 78 147 99 403 At December 31, 2005, we owned 390 trucks and 467 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 eÇciency 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 Ì 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 Öow of oil and natural gas by pumping Öuids 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 Ì Our pressure pumping equipment at December 31, 2005 follows: ‚ 30 cement pumper trucks, ‚ 33 fracturing pumper trucks, ‚ 30 nitrogen pumper trucks, 6 ‚ 17 blender trucks, ‚ 10 bulk acid trucks, ‚ 37 bulk cement trucks, ‚ 10 bulk nitrogen trucks, ‚ 42 bulk sand trucks, ‚ 15 connection trucks, and ‚ 2 acid pumper trucks. Drilling and Completion Fluids Operations General Ì We provide drilling Öuids, completion Öuids and related services to oil and natural gas operators oÅshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. We serve our oÅshore 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 Ì Drilling Öuid 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 eÅectively to optimize drilling operations. Completion Fluids Ì After a well is drilled, the well casing is set and cemented into place. At that point, the drilling Öuid services are complete and the drilling Öuids are circulated out of the well and replaced with completion Öuids. Completion Öuids, also known as clear brine Öuids, are solids-free, clear salt solutions that have high speciÑc gravities. Combined with a range of specialty chemicals, these Öuids are used to control bottom-hole pressures and to meet speciÑc corrosion, inhibition, viscosity and Öuid loss requirements. Raw Materials Ì Our drilling and completion Öuids operations depend on the availability of the following raw materials: Drilling barite and bentonite Completion calcium chloride, calcium bromide and 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 Ì 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 Öuids. Other Equipment Ì We own 24 trucks and 79 trailers and lease another 24 trucks which are used to transport drilling and completion Öuids and related equipment. Oil and Natural Gas Operations General Ì 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 and South Texas, Southeastern New Mexico, Utah and Mississippi. We signiÑcantly 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. 7 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 2005, no single customer accounted for 10% or more of our consolidated operating revenues. Competition Contract Drilling and Pressure Pumping Businesses Ì 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 Ì The drilling and completion Öuids 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 Öuids 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 Ì 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 Ñnancial 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, oilÑeld 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 signiÑcant 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 aÅected 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 aÅecting 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 eÅect 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 8 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 deÑnition 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 modiÑed 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 Öuids business. Failure to comply with ongoing requirements or inadequate coopera- tion 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 deÑnition 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, 9 ‚ Ñres, 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 ‚ Ñres. In addition, we could become subject to liability for reservoir damages. The occurrence of a signiÑcant event, including pollution or environmental damages, could materially aÅect our operations and Ñnancial 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 suÇcient to protect us against liability for all consequences of: ‚ personal injury, ‚ well disasters, ‚ extensive Ñre 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 diÇculties 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 indemniÑcation 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 indemniÑcations may not be supported by adequate insurance maintained by the customer. 10 Employees We employed approximately 8,600 full-time persons (450 oÇce personnel and 8,150 Ñeld personnel) at December 31, 2005. The number of Ñeld employees Öuctuates 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 signiÑcantly aÅect 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 ""Risk Factors,'' beginning on page 11 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 this Report. Item 1A. Risk Factors. 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 Ñlings 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, Ñnancing of operations, sources and suÇciency of funds and impact of inÖation. 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 identiÑed in this cautionary statement are important factors (but not necessarily all of the important factors) that could cause actual results to diÅer 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 diÅerences 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. 11 Taking this into account, the following are identiÑed 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 AÅected Our Operations. Our revenue, proÑtability 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 aÅected 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 Ñrst 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 $8.98 in 2005 resulting in an increase in demand for our drilling services. Our average number of rigs operating increased from 126 in 2002 to 276 in 2005. We expect oil and natural gas prices to continue to be volatile and to aÅect our Ñnancial condition and operations and ability to access sources of capital. A signiÑcant decrease in expected market prices for natural gas could result in a material decrease in demand for drilling rigs and reduction in our operating results. A General Excess of Operable Land Drilling Rigs Adversely AÅects Our ProÑt Margins Particularly in Times of Weaker Demand. The North American land drilling industry has experienced periods of downturn in demand over the last decade. During these periods, there have been substantially more drilling rigs available than necessary to meet demand. As a result, drilling contractors have had diÇculty sustaining proÑt margins during the downturn periods. In addition to adverse eÅects that future declines in demand could have on us, ongoing factors which could adversely aÅect 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 AÅects 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 signiÑcantly 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. 12 The Various Business Segments in Which We Operate Are Highly Competitive with Excess Capacity which may Adversely AÅect Our Operating Results. Our land drilling and pressure pumping businesses are highly competitive. While not the conditions at present, 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 Öuids 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 Öuids 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 AÅect Our Operating Results. During periods of increasing demand for contract drilling services, the industry experiences shortages of qualiÑed drilling rig personnel. During these periods, our ability to attract and retain suÇcient qualiÑed personnel to market and operate our drilling rigs is adversely aÅected which negatively impacts both our operations and proÑtability. Operationally, it is more diÇcult to hire qualiÑed personnel which adversely aÅects 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 Öeet over the past several years through mergers and acquisitions. The land drilling industry has experienced signiÑcant consolidation over the past several years, and there can be no 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 suÇcient capital resources to complete additional acquisitions, ‚ successfully integrate acquired operations and assets, ‚ eÅectively 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 Ñnancial condition, results of operations, business or prospects in any material manner as a result of any completed acquisition. We may incur substantial indebtedness to Ñnance future acquisitions and also may issue equity securities or convertible securities in connection with any such acquisitions. Debt service requirements could represent a signiÑcant burden on our results of operations and Ñnancial 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. 13 The Nature of our Business Operations Presents Inherent Risks of Loss that, if not Insured or IndemniÑed Against, Could Adversely AÅect Our Operating Results. Our operations are subject to many hazards inherent in the contract drilling, pressure pumping, and drilling and completion Öuids 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 indemniÑcation agreements with many of our customers. However, there is no assurance that such insurance or indemniÑcation 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 signiÑcantly 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 AÅect 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 Ñeld 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 signiÑcant risks. Under turnkey drilling contracts, we contract to drill a well to a certain depth under speciÑed conditions at a Ñxed price. Under footage contracts, we contract to drill a well to a certain depth under speciÑed conditions at a Ñxed 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 Ñre, machinery breakdowns and abnormal drilling conditions. Accordingly, if severe drilling problems are encountered in drilling wells under such contracts, we could suÅer substantial losses. Anti-takeover Measures in Our Charter Documents and Under State Law Could Discourage an Acquisition and Thereby AÅect 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 Ñnd it more diÇcult or be discouraged from attempting to eÅect 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. 14 Item 1B. Unresolved StaÅ Comments. None. Item 2. Properties Our corporate headquarters are located in Snyder, Texas. We also have a number of oÇces, 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: ‚ oÇce buildings with approximately 37,000 square feet of oÇce 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 Öeet, ‚ a truck fabrication and rigup shop with approximately 3,000 square feet used to prepare new trucks for service, ‚ 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 oÇces, 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 Ì Our drilling services are supported by several administrative oÇces and yard facilities located throughout our areas of operations including: ‚ Texas, ‚ New Mexico, ‚ Oklahoma, ‚ Colorado, ‚ Utah, ‚ Wyoming, and ‚ Western Canada. Pressure Pumping Ì Our pressure pumping services are supported by several oÇces and yard facilities located throughout our areas of operations including: ‚ Pennsylvania, ‚ Ohio, ‚ West Virginia, ‚ Kentucky, ‚ Tennessee, and ‚ Wyoming. 15 Drilling and Completion Fluids Ì Our drilling and completion Öuids services are supported by several administrative oÇces and stockpoint facilities located throughout our areas of operations including: ‚ Texas, ‚ Louisiana, ‚ New Mexico, and ‚ Oklahoma. Oil and Natural Gas Ì Our oil and natural gas operations are supported by administrative and Ñeld oÇces 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. In December 2005, two purported derivative actions were Ñled in Texas state court in Scurry County, Texas, against our directors, alleging that the directors breached their Ñduciary duties to us as a result of alleged failure to timely discover the embezzlement by Nelson, and against our principal accounting Ñrm, PricewaterhouseCoopers LLP, alleging that such Ñrm committed negligence and malpractice as a result of alleged failure to timely discover the embezzlement. The Board of Directors formed a special litigation committee to review and inquire about these allegations and recommend our response, if any. Further legal proceedings in these suits have been stayed pending completion of the work of the special litigation committee. The lawsuits seek recovery on behalf of and for us and do not seek recovery from us. We are party to various other 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 eÅect on our Ñnancial condition. Item 4. Submission of Matters to a Vote of Security Holders. None. 16 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 reÖect the two-for-one stock split on June 30, 2004: High Low 2005: First quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Second quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Third quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Fourth quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2004: First quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Second quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Third quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Fourth quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $26.66 29.33 36.79 36.73 $19.20 19.56 19.88 20.45 $17.15 22.38 27.79 28.45 $15.75 14.52 15.69 17.85 (b) Holders As of March 10, 2006, there were approximately 2,174 holders of record and approximately 92,452 beneÑcial holders of our common shares. (c) Dividends and Buyback Program 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 from $0.02 per share. Quarterly cash dividends in the amount of $0.04 per share were paid on March 4, 2005, June 1, 2005, September 1, 2005 and December 1, 2005. Total cash dividends in 2005 were approximately $27.3 million. The next quarterly cash dividend is to be paid to holders of record on March 15, 2006 and paid on March 30, 2006. 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, Ñnancial conditions, terms of our credit facilities and other factors. 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. 17 The table below sets forth the information with respect to purchases of our common stock made by or on our behalf during the quarter ended December 31, 2005. Period covered Total number of shares purchased(1) Average price paid per share Total number of shares (or units) purchased as part of publicly announced plans or programs(2) Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs(2) October 1Ó31, 2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Ì November 1Ó30, 2005 ÏÏÏÏÏÏÏÏÏÏÏÏ 355,000 December 1Ó31, 2005 ÏÏÏÏÏÏÏÏÏÏÏÏ Ì Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 355,000 $ Ì $34.23 $ Ì $34.23 Ì 355,000 Ì 355,000 $28,518,216 $16,364,873 $16,364,873 $16,364,873 (1) All of the reported shares were purchased in open-market transactions. (2) 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, which 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. On March 27, 2006, our Board of Directors increased the stock buyback program to allow the future purchases of up to $200 million of our outstanding common stock. (d) Securities Authorized for Issuance Under Equity Compensation Plans Equity compensation to our employees, oÇcers and directors as of December 31, 2005 follows: Plan Category Equity Compensation Plan Information Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights (a) Weighted- Average Exercise Price of Outstanding Options, Warrants and Rights (b) Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (Excluding Securities ReÖected in Column(a)) (c) Equity compensation plans approved by security holders ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 5,449,739 $15.11 5,464,217(1) Equity compensation plans not approved by security holders(2) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 888,304 Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 6,338,043 $ 9.87 $14.37 Ì 5,464,217 (1) The Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the ""2005 Plan'') provides for awards of incentive stock options, non-incentive stock options, tandem and freestanding stock appreciation rights, restricted stock awards, other stock unit awards, performance share awards, performance unit awards and dividend equivalents to key employees, oÇcers and directors, which are subject to certain vesting and forfeiture provisions. 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. All securities remaining available for future issuance under equity compensation plans approved by security holders in column (c) are available under this plan. 18 (2) The Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (the ""2001 Plan'') was approved by the Board of Directors in July 2001. In connection with the approval of the 2005 Plan, the Board of Directors approved a resolution that no further options, restricted stock or other awards would be granted under any equity compensation plan, other than the 2005 Plan. The terms of the 2001 Plan provided for grants of stock options, stock appreciation rights, shares of restricted stock and performance awards to eligible employees other than oÇcers and directors. No Incentive Stock Options could be awarded under the Plan. All options were 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 were set by the Compensation Committee of the Board of Directors. 19 Item 6. Selected Financial Data. Our selected consolidated Ñnancial data as of December 31, 2005, 2004, 2003, 2002 and 2001, and for each of the Ñve 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 Ñnancial data presented below was previously reported as restated to provide for (i) the retroactive eÅect of the merger with UTI Energy Corp., on May 8, 2001 accounted for as a pooling of interest; (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. The current and historical Ñnancial data presented below has been further restated to provide for, net of related tax eÅects, (i) the eÅects of losses incurred as a result of the embezzlement and (ii) the eÅects of the correction of other errors that are immaterial both individually and in the aggregate. See additional information about the embezzlement and restatement in footnote (1) to the restated selected Ñnancial data below. Certain reclassiÑcations have been made to the historical Ñnancial data to conform with the 2004 presentation. Years Ended December 31, 2005 2004 Restated (See Note 2) 2002 2003 2001 (In thousands) Income Statement Data: Operating revenues: Contract drilling ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Pressure pumping ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏ Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $1,485,684 93,144 122,011 39,616 1,740,455 $ 809,691 66,654 90,557 33,867 1,000,769 $639,694 46,083 69,230 21,163 776,170 $410,295 32,996 69,943 14,723 527,957 $839,931 39,600 94,456 15,988 989,975 Operating costs and expenses: Contract drilling ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Pressure pumping ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏ Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Depreciation, depletion, amortization and impairment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Selling, general and administrative ÏÏÏÏÏ Bad debt expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Merger costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Restructuring and other charges ÏÏÏÏÏÏÏ Embezzled funds and related expensesÏÏ Other (including gain or loss on sale of assets) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating income (loss) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other income (expense) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Income (loss) before income taxes and cumulative eÅect of change in accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Income tax expense (beneÑt) ÏÏÏÏÏÏÏÏÏÏÏ Income (loss) before cumulative eÅect of change in accounting principle ÏÏÏÏÏÏÏÏ Cumulative eÅect of change in accounting principle, net of related income tax beneÑt of approximately $287 ÏÏÏÏÏÏÏÏÏ Net income (loss) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 776,313 54,956 98,530 9,566 156,393 39,110 1,231 Ì Ì 20,043 3,017 1,159,159 581,296 3,463 556,869 37,561 76,503 7,978 122,800 31,983 897 Ì Ì 19,122 475,224 26,184 61,424 4,808 100,834 27,685 259 Ì Ì 17,849 318,201 19,802 60,762 3,956 92,778 26,116 320 Ì Ì 8,574 487,343 21,146 80,034 5,190 86,035 28,462 2,045 5,943 7,202 7,674 (1,411) 852,302 148,467 680 (4,379) 709,888 66,282 2,694 4,340 534,849 (6,892) 803 (820) 730,254 259,721 (677) 584,759 212,019 149,147 54,801 68,976 25,320 (6,089) (1,949) 259,044 99,472 372,740 94,346 43,656 (4,140) 159,572 Ì $ 372,740 Ì 94,346 $ (469) $ 43,187 Ì $ (4,140) Ì $159,572 20 2005 Years Ended December 31, Restated (See Note 2) 2002 (In thousands, except per share amounts) 2004 2003 2001 2.19 $ 0.57 $ 0.27 $ (0.03) $ 1.04 Ì $ Ì $ Ì $ Ì $ Ì 2.19 $ 0.57 $ 0.27 $ (0.03) $ 1.04 2.15 $ 0.56 $ 0.27 $ (0.03) $ 1.01 Ì $ Ì $ Ì $ Ì $ Ì 2.15 0.16 $ $ 0.56 0.06 $ $ 0.26 $ (0.03) $ 1.01 Ì $ Ì $ Ì Net income (loss) per common share: Basic: Income (loss) before cumulative eÅect of change in accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Cumulative eÅect of change in accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏ Net income (loss) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Diluted: Income (loss) before cumulative eÅect of change in accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Cumulative eÅect of change in accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏ Net income (loss) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Cash dividends per common shareÏÏÏÏÏÏ Weighted average number of common shares outstanding: Basic ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ $ $ $ $ $ $ Diluted ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 173,767 170,426 166,258 169,211 161,272 157,410 152,814 164,572 157,410 158,394 Balance Sheet Data: Total assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Stockholders' equityÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Working capital ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $1,795,781 1,367,011 382,448 $1,256,785 961,501 235,480 $1,039,521 789,814 198,399 $919,374 724,248 166,885 $856,855 680,341 109,566 (1) On November 3, 2005, we announced the resignation of our CFO, Jonathan D. Nelson. On Novem- ber 10, 2005, we announced that, based on information received by Company senior management on November 9, 2005, the Audit Committee of our Board of Directors began an investigation into an apparent embezzlement from us by Nelson. On December 22, 2005, upon recommendation of Company management and the Audit Committee of our Board of Directors, we announced that based on the results to date of the internal investigation into the facts and circumstances surrounding the embezzlement by Nelson, we would restate previously issued Ñnancial statements and amend our previously issued Annual Report on Form 10-K for the year ended December 31, 2004 and Quarterly Reports on Form 10-Q for the periods ended March 31, June 30 and September 30, 2005. These restatements reÖect losses incurred as a result of payments made to or for the beneÑt of Nelson that had been recognized in our accounting records and previously issued Ñnancial statements as payments for assets and services that we did not receive. Previously issued Ñnancial statements have also been restated for the eÅects of the correction of other errors that are immaterial both individually and in the aggregate. These other adjustments relate primarily to previously reported property and equipment balances that resulted from our review of our property and equipment records and the underlying physical assets in connection with investigation of the embezzlement. We have restated such Ñnancial statements, and on March 17, 2006, we Ñled our amended Annual Report on Form 10-K/A and on March 27, 2006, we Ñled our amended Quarterly Reports on Form 10-Q/A with the SEC. 21 Most of the embezzled funds result from Nelson causing the wiring of Company funds aggregating approximately $72.3 million, to, or for the beneÑt of, entities owned and controlled by him. Nelson was originally able to initiate these wire transfers by requesting the wire transfers himself in telephone calls to one of the Company's banks. After changes to the Company's internal controls and procedures in 2004, Nelson initiated the wire transfers through instructions to one of his subordinates and by the creation of fraudulent invoices containing forged senior management approvals. This false documentation was created by Nelson to conceal the true nature of these transactions from the Company and its independent registered public accountants. Nelson also instructed certain former employees, who worked under his supervision, to alter management reports related to property and equipment expenditures. Nelson also created Ñctitious property and equipment approval forms with forged signatures. The total amount embezzled was approximately $77.5 million in cash, excluding any tax eÅects, beginning with the year ended December 31, 1998 through November 3, 2005 as follows (in thousands): From 1998 to December 31, 2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ From January 1, 2005 to September 30, 2005(1)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total through September 30, 2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ From October 1, 2005 to November 3, 2005 (net of $1,500 repayment)(1) ÏÏÏÏÏÏÏÏÏ $58,961 12,193 71,154 6,350 Total embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $77,504 (1) The total amount embezzled during 2005 was $18,543,000 and the Company incurred $1,500,000 of professional fees and expenses as a result of the embezzlement. Accordingly, the total embezzled funds and related expenses in 2005 were $20,043,000. The eÅects of the restatement due to the embezzlement and other adjustments on operating income as previously reported for 2004 and prior years follow: Years Ended December 31, 2004 2003 2002 2001 (In thousands) Operating income (loss): As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Adjustment for eÅects of embezzlementÏÏÏÏÏÏÏ Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $171,214 (18,637) (4,110) $ 87,190 (17,375) (3,533) $ 3,398 (8,249) (2,041) $267,172 (7,461) 10 As restated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $148,467 $ 66,282 $(6,892) $259,721 22 The eÅects of the restatement due to the embezzlement and other adjustments on net income as previously reported for 2004 and prior years follow: Years Ended December 31, 2004 2003 2002 2001 (In thousands, except per share data) Net income (loss): As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $108,733 $ 56,419 $ 2,374 $164,162 Adjustments: Embezzled funds expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Embezzlement amounts previously expensed as depreciation and selling, general and administrative ÏÏÏÏÏÏÏÏÏÏÏÏ Embezzlement expense, net of amounts previously expensed ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Tax beneÑts ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ (19,122) (17,849) (8,574) (7,674) 485 474 325 213 (18,637) (4,110) 8,360 (17,375) (3,533) 7,676 (8,249) (2,041) 3,776 (7,461) 10 2,861 Net adjustmentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ (14,387) (13,232) (6,514) (4,590) Net income (loss) as restated ÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 94,346 $ 43,187 $(4,140) $159,572 Net income (loss) per common share: Basic: As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Adjustment for eÅects of embezzlementÏÏÏÏÏ Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ As restated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Diluted: As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Adjustment for eÅects of embezzlementÏÏÏÏÏ Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ As restated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ $ $ $ $ $ $ $ 0.65 (0.07) (0.02) 0.57 0.64 (0.07) (0.02) 0.56 $ $ $ $ $ $ $ $ 0.35 (0.07) (0.01) 0.27 0.34 (0.07) (0.01) 0.26 $ 0.02 $ (0.03) $ (0.01) $ (0.03) 0.01 $ $ (0.03) $ (0.01) $ (0.03) $ $ $ $ $ $ $ $ 1.07 (0.03) Ì 1.04 1.04 (0.03) Ì 1.01 23 The eÅects of the restatement due to the embezzlement and other adjustments on selected balance sheet data as previously reported for 2004 and prior years follow: Total assets: As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Adjustment for eÅects of embezzlement: Property and equipment and otherÏÏÏÏÏÏ Income taxes receivable ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other adjustments: Property and equipment and otherÏÏÏÏÏÏ Income taxes receivable ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ As restated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Stockholders' equity: December 31, 2004 2003 2002 2001 (In thousands) $1,322,911 $1,084,114 $942,823 $869,642 (56,133) Ì (56,133) (37,496) (1,044) (38,540) (20,121) (807) (20,928) (11,872) (531) (12,403) (9,993) Ì (9,993) $1,256,785 (5,883) (170) (6,053) $1,039,521 (2,350) (171) (2,521) $919,374 (309) (75) (384) $856,855 As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Adjustment for eÅects of embezzlementÏÏÏ Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ As restated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $1,007,539 (35,285) (10,753) $ 961,501 $ 819,749 (23,496) (6,439) $ 789,814 $737,731 (12,499) (984) $724,248 $687,142 (7,373) 572 $680,341 Working capital: As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Adjustment for eÅects of embezzlementÏÏÏ Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ As restated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 236,957 (1,311) (166) $ 235,480 $ 199,613 (1,044) (170) $ 198,399 $167,863 (807) (171) $166,885 $110,172 (531) (75) $109,566 24 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. The Ñnancial statements and related Ñnancial information for 2004 and all prior years presented herein have been amended and restated on our Annual Report on Form 10-K/A for the year ended December 31, 2004, Ñled on March 17, 2006. The determination to restate these Ñnancial statements and other information was made as a result of management's identiÑcation of an embezzlement. Further information on the restatement can be found in Note 2 to Consolidated Financial Statements included as a part of Item 8 of this Annual Report on Form 10-K. Management Overview Ì 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 Öuid 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, 2005, our operating revenues consisted of the following (dollars in thousands): 2005 2004 2003 Contract drilling ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Pressure pumping ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Drilling and completion Öuids ÏÏÏÏÏÏ Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $1,485,684 93,144 122,011 39,616 86% $ 809,691 66,654 90,557 33,867 5 7 2 81% $639,694 46,083 7 69,230 9 21,163 3 82% 6 9 3 $1,740,455 100% $1,000,769 100% $776,170 100% We provide our contract services to oil and natural gas operators in many of the oil and natural gas producing regions of North America. Our contract drilling operations are focused in various regions of Texas, New Mexico, Oklahoma, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota and Western Canada while our pressure pumping services are focused primarily in the Appalachian Basin. Our drilling and completion Öuids services are provided to operators in Texas, Southeastern New Mexico, Oklahoma, the Gulf Coast region of Louisiana and the Gulf of Mexico. Our oil and natural gas operations are primarily focused in West and South Texas, Southeastern New Mexico, Utah and Mississippi. We have been a leading consolidator of the land-based contract drilling industry over the past several years increasing our drilling Öeet to 403 rigs as of December 31, 2005. Based on publicly available information, we believe we are the second largest owner of land-based drilling rigs in North America. Our most signiÑcant transaction occurred in May 2001 when we merged with UTI Energy Corp. in a merger of equals which basically doubled our drilling Öeet and added the pressure pumping services business. Growth by acquisition has been a corporate strategy intended to expand both revenues and proÑts. The proÑtability 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 2005, our average number of rigs operating increased to 276 from 211 in 2004 and our average revenue per operating day increased to $14,770 from $10,470 in 2004. Primarily due to these improvements, we experienced an increase of approximately $278 million, or 295%, in consolidated net income in 2005. Our revenues, proÑtability and cash Öows 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 contained in Item 1A of this Report. 25 Management believes that the liquidity of our balance sheet as of December 31, 2005, which includes approximately $382 million in working capital (including $136 million in cash), no long term debt and $144 million available under a $200 million line of credit (availability of $56 million is reserved for outstanding letters of credit) provides us with the ability to pursue acquisition opportunities, expand into new regions, make improvements to our assets and survive downturns in our industry. Embezzlement and Restatements Ì On November 3, 2005, we announced the resignation of our CFO, Jonathan D. Nelson. On November 10, 2005, we announced that, based on information received by Company senior management on November 9, 2005, the Audit Committee of our Board of Directors began an investigation into an apparent embezzlement from us by Nelson. On December 22, 2005, upon recommendation of Company management and the Audit Committee of our Board of Directors, we announced that based on the results to date of the internal investigation into the facts and circumstances surrounding the embezzlement by Nelson, we would restate previously issued Ñnancial statements and amend our previously issued Annual Report on Form 10-K for the year ended December 31, 2004 and Quarterly Reports on Form 10-Q for the periods ended March 31, June 30 and September 30, 2005. These restatements reÖect losses incurred as a result of payments made to or for the beneÑt of Nelson that had been recognized in our accounting records and previously issued Ñnancial statements as payments for assets and services that we did not receive. Previously issued Ñnancial statements have also been restated for the eÅects of the correction of other errors that are immaterial both individually and in the aggregate. These other adjustments relate primarily to previously reported property and equipment balances that resulted from our review of our property and equipment records and the underlying physical assets in connection with investigation of the embezzlement. We have restated such Ñnancial statements, and on March 17, 2006, we Ñled our amended Annual Report on Form 10-K/A and on March 27, 2006, we Ñled our amended Quarterly Reports on Form 10-Q/A with the SEC. Most of the embezzled funds result from Nelson causing the wiring of Company funds aggregating approximately $72.3 million, to, or for the beneÑt of, entities owned and controlled by him. Nelson was originally able to initiate these wire transfers by requesting the wire transfers himself in telephone calls to one of the Company's banks. After changes to the Company's internal controls and procedures in 2004, Nelson initiated the wire transfers through instructions to one of his subordinates and by the creation of fraudulent invoices containing forged senior management approvals. This false documentation was created by Nelson to conceal the true nature of these transactions from the Company and its independent registered public accountants. Nelson also instructed certain former employees, who worked under his supervision, to alter management reports related to property and equipment expenditures. Nelson also created Ñctitious property and equipment approval forms with forged signatures. The total amount embezzled was approximately $77.5 million in cash, excluding any tax eÅects, beginning with the year ended December 31, 1998 through November 3, 2005 as follows (in thousands): From 1998 to December 31, 2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ From January 1, 2005 to September 30, 2005(1)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total through September 30, 2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ From October 1, 2005 to November 3, 2005 (net of $1,500 repayment)(1) ÏÏÏÏÏÏÏÏÏ $58,961 12,193 71,154 6,350 Total embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $77,504 (1) The total amount embezzled during 2005 was $18,543,000 and the Company incurred $1,500,000 of professional fees and expenses as a result of the embezzlement. Accordingly, the total embezzled funds and related expenses in 2005 were $20,043,000. Commitments and Contingencies Ì We maintain letters of credit in the aggregate amount of approxi- mately $56 million for the beneÑt of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These 26 letters of credit expire at various times during each calendar year. No amounts have been drawn under the letters of credit. We have signed non-cancelable commitments to purchase $118 million of equipment to be received throughout 2006. Net income for the years ended December 31, 2005, 2004 and 2003 include embezzled funds and related expenses of $20.0 million, $19.1 million and $17.8 million, respectively. On November 16, 2005, the SEC obtained a freeze order on Nelson's assets (including assets held by entities controlled by him) and a Receiver was appointed to collect those assets. The Company understands that the Receiver will ultimately liquidate the assets and propose a plan to distribute the proceeds. While the Company believes it has a claim for at least the full amount embezzled, other creditors have or may assert claims on the assets held by the Receiver. As a result, recovery by the Company from the Receiver is uncertain as to timing and amount, if any. Recoveries, if any, will be recognized when they are considered collectable. Net income for the year ended December 31, 2002, includes a charge of $4.7 million related to the Ñnancial failure in 2002 of a workers' compensation insurance carrier that had provided coverage for us in prior years. Net income for the year ended December 31, 2005, includes a charge of $4.2 million to increase this reserve. In December 2005, two purported derivative actions were Ñled in Texas state court in Scurry County, Texas, against our directors, alleging that the directors breached their Ñduciary duties to us as a result of alleged failure to timely discover the embezzlement. The Board of Directors formed a special litigation committee to review and inquire about these allegations and recommend our response, if any. Further legal proceedings in these suits have been stayed pending completion of the work of the special litigation committee. The lawsuits seek recovery on behalf of and for us and do not seek recovery from us. Trading and investing Ì 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 Ì We conduct our contract drilling operations in Texas, New Mexico, Oklahoma, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota and Western Canada. As of December 31, 2005, we owned 403 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 Öuids, completion Öuids 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 Öuids are used by oil and natural gas operators during the drilling process to control pressure when drilling oil and natural gas wells. We are also engaged in the development, exploration, acquisition and production of oil and natural gas. Our oil and natural gas operations are focused primarily in producing regions in West and South Texas, Southeastern New Mexico, Utah and Mississippi. The North American land drilling industry has experienced many downturns in demand over the last decade. During these periods, there have been substantially more drilling rigs available than necessary to meet demand. As a result, drilling contractors have had diÇculty sustaining proÑt margins during the downturn periods. In addition to adverse eÅects that future declines in demand could have on us, ongoing factors which could adversely aÅect 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. 27 Critical Accounting Policies In addition to established accounting policies, our consolidated Ñnancial 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 Ì 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 Öuctuations in rig utilization over periods of time. Management believes that the contract drilling industry will continue to be cyclical and rig utilization will Öuctuate. Based on management's expectations of future trends, we estimate future cash Öows 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 Öows, on an undiscounted basis, are less than the asset's net book value. Impairment charges are recorded based on discounted cash Öows. There were no impairment charges to property and equipment during the years 2005, 2004 or 2003. Oil and natural gas properties Ì Oil and natural gas properties are accounted for using the successful eÅorts method of accounting. Under the successful eÅorts method of accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are charged to expense when such determination is made. In accordance with 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 classiÑcation. If the reserve classiÑcation is uncertain after one year following the completion of drilling, we consider the costs of the well to be impaired and recognize the costs as expense. Geological and geophysical costs, including seismic costs and costs to carry and retain undeveloped properties, are charged to expense when incurred. The capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment, lease acquisition costs and intangible development costs, are depreciated, depleted and amortized on the units-of-production method, based on engineering estimates of proved oil and natural gas reserves of each respective Ñeld. 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 Ñeld and undiscounted cash Öow estimates are provided by an independent petroleum engineer. If the net book value of a Ñeld exceeds its undiscounted cash Öow estimate, impairment expense is measured and recognized as the diÅerence between its net book value and discounted cash Öow. 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 $4.4 million, $3.2 million and $1.4 million for the years ended December 31, 2005, 2004 and 2003, respectively, is included in depreciation, depletion and impairment in the accompanying Ñnancial statements. Goodwill Ì Goodwill is considered to have an indeÑnite 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. 28 Revenue recognition Ì 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 Ì The preparation of Ñnancial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that aÅect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the Ñnancial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could diÅer 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 and depletion, ‚ asset impairment, ‚ reserves for self-insured levels of insurance coverages, and ‚ fair values of assets and liabilities assumed in acquisitions. 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. Related Party Transactions We operate certain oil and natural gas properties in which certain of our aÇliated 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, 2005, aÇliated persons were working interest owners in 254 of 305 total wells we operated. We make sales of working interests to reduce our economic risk in the properties. Generally, it is more eÇcient for us to sell the working interests to these aÇliated 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 aÇliated persons was the same price at which working interests were sold to unaÇliated persons. Production revenues and joint interest costs of each of the aÇliated persons during 2005 for all wells operated by us in which the aÇliated persons have working interests are presented in the table below. These amounts do not necessarily represent their proÑts 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, 2005. These activities resulted in a payable to the aÇliated persons of approximately $1.5 million and $1.2 million 29 and a receivable from the aÇliated persons of approximately $1.2 million and $856,000 at December 31, 2005 and 2004, respectively. Name Cloyce A. Talbott ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Anita Talbott(3) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Jana Talbott, Executrix to the Estate of Steve Talbott(3) ÏÏÏÏÏÏÏÏÏÏ Stan Talbott(3) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ John Evan Talbott Trust(3) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Lisa Beck and Stacy Talbott(3) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ SSI Oil & Gas, Inc.(4) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ IDC Enterprises, Ltd.(5) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Year Ended December 31, 2005 Production Revenues(1) $ 195,491 88,824 19,373 7,639 3,725 1,158,657 210,825 13,432,098 Joint Interest Costs(2) $ 49,668 21,389 2,871 3,163 987 492,839 97,152 8,460,393 SubtotalÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 15,116,632 9,128,462 A. Glenn Patterson ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Robert Patterson(6) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Thomas M. Patterson(6) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ SubtotalÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Jonathan D. Nelson, former Chief Financial OÇcer ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 122,348 7,719 7,719 137,786 290,506 29,075 4,396 4,396 37,867 381,506 Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $15,544,924 $9,547,835 (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 beneÑcially owned 50% by Cloyce A. Talbott and directly owned 50% by A. Glenn Patterson. (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 2005, 2004 and 2003, we paid approximately $424,000, $914,000 and $740,000, respectively, to TMP Truck and Trailer LP (""TMP''), during the period it was 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 2005 and 2004, we paid approximately $273,000 and $39,000, respectively, to Melco Services (""Melco'') for dirt contracting services and $59,000 and $44,000, 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. See Note 2 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report for information pertaining to fraudulent payments made to or for the beneÑt of Jonathan D. Nelson, our former CFO. 30 Liquidity and Capital Resources As of December 31, 2005, we had working capital of $382 million including cash and cash equivalents of $136 million. For 2005, our sources of cash Öow included: ‚ $460 million from operations, ‚ $43 million from the exercise of stock options, and ‚ $13 million from sales of property and equipment. We used $74 million to purchase land drilling assets from Key Energy Services, Inc. and six additional land-based drilling rigs, $27 million to pay dividends on our common stock, $12 million to buy 355,000 shares of our common stock pursuant to the stock buyback program authorized by our Board of Directors on June 7, 2004 and $380 million: ‚ to make capital expenditures for the betterment and refurbishment of our drilling rigs, ‚ to acquire and procure drilling equipment, ‚ to fund capital expenditures for our pressure pumping and drilling and completion Öuids divisions, and ‚ to fund leasehold acquisition and exploration and development of oil and natural gas properties. As of December 31, 2005, $400,000 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 January 2005, we purchased land drilling assets of Key Energy Services, Inc. for $61.8 million. The assets acquired included 25 active and 10 stacked land-based drilling rigs, related drilling equipment, yard facilities and a rig moving Öeet consisting of approximately 45 trucks and 100 trailers. In June 2005, we acquired one land-based drilling rig for $3.6 million. In September 2005, we acquired Ñve land-based drilling rigs and related drilling equipment for $8.2 million. The transactions were accounted for as acquisitions of asset and the respective purchase prices were allocated among the assets acquired based on their estimated fair market values. We replaced our prior credit facility in December 2004 with a Ñve-year, $200 million unsecured revolving line of credit (""LOC''). Interest is to be paid on outstanding LOC balances at a Öoating 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, 2005). 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 $56 million at December 31, 2005. There were no outstanding borrowings under the LOC at December 31, 2005. In February 2005, our Board of Directors approved an increase in the quarterly cash dividend on our 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 March 15, 2006 and paid on March 30, 2006. 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. During the second quarter of 2004, we purchased 100,000 shares of our common stock in the open market for approximately $1.5 million (adjusted to reÖect the two-for-one stock split on June 30, 2004). During the fourth quarter of 2005, we purchased 355,000 shares of our common stock in the open market for approximately $12.2 million. These shares are included in treasury stock. On March 27, 2006, our Board of Directors increased the stock buyback program to allow the future purchases of up to $200 million of our outstanding common stock. We believe that the current level of cash and short-term investments, together with cash generated from operations, should be suÇcient to meet our capital needs. From time to time, acquisition opportunities are 31 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 Ñnancing or equity Ñnancing. However, there can be no assurance that such capital would be available. Results of Operations Comparison of the years ended December 31, 2005 and 2004 A summary of operations by business segment for the years ended December 31, 2005 and 2004 follows: Contract Drilling Years Ended December 31, Restated (See Note 2) 2004 % Change 2005 (Dollars in thousands) RevenuesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Direct operating costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Selling, general and administrative ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating incomeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating days ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average revenue per operating day ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average direct operating costs per operating dayÏÏÏÏÏÏÏÏÏ Number of owned rigs at end of period ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average number of rigs owned during periodÏÏÏÏÏÏÏÏÏÏÏÏ Average rigs operatingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Rig utilization percentage ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Capital expenditures ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $1,485,684 $ 776,313 $ 5,069 $ 131,740 $ 572,562 100,591 14.77 7.72 403 397 276 $ $ 69% $809,691 $556,869 $ 4,417 $101,779 $146,626 77,355 10.47 7.20 361 359 211 59% $ $ $ 329,073 $140,945 83.5% 39.4% 14.8% 29.4% 290.5% 30.0% 41.1% 7.2% 11.6% 10.6% 30.8% 16.9% 133.5% The market price of natural gas remained high in 2005. In fact, the average market price of natural gas improved to $8.98 per Mcf in 2005 compared to $5.95 per Mcf in 2004, resulting in an increase in demand for our contract drilling services. Our average number of rigs operating increased to 276 in 2005 from 211 in 2004. The average market price of natural gas and our average rigs operating for each of the Ñscal quarters in 2005 and 2004 follow: 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter 2005: Average natural gas price ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average rigs operating ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2004: Average natural gas price ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average rigs operating ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $6.62 263 $5.64 197 $7.14 265 $6.13 203 $9.82 283 $5.62 216 $12.64 292 $ 6.42 229 Revenues and direct operating costs increased as a result of the increased number of operating days, as well as an increase in the average revenue and average direct operating costs per operating day. Operating days and average rigs operating increased as a result of the increased demand for our contract drilling services, the acquisition of land drilling assets from Key Energy Services, Inc. in January 2005 and activation of refurbished stacked rigs. Average revenue per operating day increased as a result of increased demand and pricing for our drilling services. SigniÑcant capital expenditures were incurred during 2005 to activate additional drilling rigs to meet increased demand, to modify and upgrade our existing drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, Öuid circulating systems, rig hoisting systems and safety 32 enhancement equipment. Increased depreciation expense in 2005 was due to acquisitions and capital expenditures in 2004 and 2005. Pressure Pumping Revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Direct operating costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Selling, general and administrativeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total jobs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average revenue per job ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average direct operating costs per jobÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Capital expendituresÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2005 % Change Years Ended December 31, 2004 (Dollars in thousands) $66,654 $37,561 $ 7,234 $ 5,112 $16,747 7,444 8.95 $ $ 5.05 $17,705 $93,144 $54,956 $ 9,430 $ 7,094 $21,664 9,615 9.69 $ $ 5.72 $25,508 39.7% 46.3% 30.4% 38.8% 29.4% 29.2% 8.3% 13.3% 44.1% 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 2005 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 2005 was largely due to the expansion of the pressure pumping segment from 2003 through 2005 and related expenditures to acquire necessary equipment to facilitate the growth. Capital expenditures increased in 2005 compared to 2004 due to further expansion of services into Tennessee and Wyoming as well as modiÑcations and upgrades to existing equipment and facilities. Drilling and Completion Fluids 2005 % Change Revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Direct operating costsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Selling, general and administrative ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other operating ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total jobsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average revenue per job ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average direct operating costs per job ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Capital expenditures ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Years Ended December 31, Restated (See Note 2) 2004 (Dollars in thousands) $90,557 $76,503 $ 7,696 $ 2,156 $ Ì $ 4,202 2,205 $ 41.07 $ 34.70 $ 1,488 $122,011 $ 98,530 8,912 $ 2,368 $ $ 254 $ 11,947 1,980 61.62 49.76 3,042 $ $ $ 34.7% 28.8% 15.8% 9.8% N/A% 184.3% (10.2)% 50.0% 43.4% 104.4% Revenues and direct operating costs increased as a result of an increase in the average revenue and direct operating costs per job. Average revenue and direct operating costs per job increased primarily as a result of an increase in the size of our oÅshore jobs. Selling, general and administrative expense increased primarily due to increased incentive compensation resulting from higher proÑtability levels. Other expense from operations 33 includes a charge of $254,000 representing the deductible portion of the Company's insurance coverage for damage caused by the hurricanes in August and September 2005. Oil and Natural Gas Production and Exploration Revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Direct operating costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Selling, general and administrativeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Depreciation, depletion and impairment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Capital expendituresÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average net daily oil production (Bbls) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average net daily gas production (Mcf) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average oil sales price (per Bbl) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average gas sales price (per Mcf)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2005 % Change Years Ended December 31, 2004 (Dollars in thousands) $33,867 $ 7,978 $ 1,816 $13,309 $10,764 $14,451 1,071 7,429 $ 39.12 5.81 $ $39,616 $ 9,566 $ 2,189 $14,456 $13,405 $17,163 860 7,016 $ 54.30 7.64 $ 17.0% 19.9% 20.5% 8.6% 24.5% 18.8% (19.7)% (5.6)% 38.8% 31.5% Revenues increased due to increased market prices for oil and natural gas. Direct operating costs increased as a result of higher oilÑeld service cost and production taxes. Average net daily oil production decreased as a result of production declines and the sale of certain oil properties during 2005. Average net daily gas production also decreased as a result of the sale of certain natural gas properties, however, this decrease was partially oÅset by an increase in production. Depreciation, depletion and impairment expense includes approximately $4.4 million and $3.2 million of expenses incurred during 2005 and 2004, respectively, to impair certain oil and natural gas properties. Corporate and Other 2005 % Change Selling, general and administrative ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Bad debt expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other operating (including gain or loss on sale of assets)ÏÏÏÏ Embezzled funds and related expenses ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Interest income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Interest expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Capital expenditures ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Years Ended December 31, Restated (See Note 2) 2004 (Dollars in thousands) $10,820 897 $ $ 444 $(1,411) $19,122 $ 1,140 695 $ 235 $ $ Ì $13,510 $ 1,231 $ 735 $ 2,763 $20,043 $ 3,551 516 $ 428 $ $ 5,308 24.9% 37.2% 65.5% N/A% 4.8% 211.5% (25.8)% 82.1% N/A% Selling, general and administrative expenses increased primarily as a result of payroll taxes attributable to the exercise of employee stock options, increased professional fees and additional compensation expense related to the issuance of restricted shares to certain key employees in 2004 and 2005. Embezzled funds and related expenses includes fraudulent payments made to or for the beneÑt of Jonathan D. Nelson, our former CFO, for assets and services that were not received by the Company and professional fees and expenses incurred as a result of the embezzlement. Other expense from operations in 2005 includes a charge of $4.2 million to increase reserves related to the Ñnancial failure of a workers' compensation insurance carrier used previously by the Company. 34 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: Contract Drilling Revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Direct operating costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Selling, general and administrativeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating days ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average revenue per operating day ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average direct operating costs per operating day ÏÏÏÏÏÏÏÏÏÏÏÏ Number of owned rigs at end of periodÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average number of rigs owned during period ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average rigs operating ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Rig utilization percentage ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Capital expendituresÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ % Change 2004 Restated (See Note 2) Years Ended December 31, 2003 (Dollars in thousands) $639,694 $475,224 $ 4,401 $ 87,255 $ 72,814 68,798 9.30 6.91 343 336 188 56% $809,691 $556,869 $ 4,417 $101,779 $146,626 77,355 10.47 7.20 361 359 211 59% $ $ $ $ $140,945 $ 77,350 26.6% 17.2% 0.4% 16.6% 101.4% 12.4% 12.6% 4.2% 5.2% 6.8% 12.2% 5.4% 82.2% 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 Ñscal quarters in 2004 and 2003 follow: 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter 2004: Average natural gas price ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average rigs operatingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2003: Average natural gas price ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average rigs operatingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $5.64 197 $5.91 176 $6.13 203 $5.70 195 $5.62 216 $4.88 192 $6.42 229 $5.29 191 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. SigniÑcant 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, Öuid circulating systems, rig hoisting systems and safety enhancement 35 equipment. Increased depreciation expense in 2004 was due primarily to capital expenditures in 2003 and 2004, as well as acquisitions. Pressure Pumping Revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Direct operating costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Selling, general and administrativeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total jobs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average revenue per job ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average direct operating costs per jobÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Capital expendituresÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2004 % Change Years Ended December 31, 2003 (Dollars in thousands) $46,083 $26,184 $ 5,683 $ 3,774 $10,442 5,667 8.13 $ $ 4.62 $10,524 $66,654 $37,561 $ 7,234 $ 5,112 $16,747 7,444 8.95 $ $ 5.05 $17,705 44.6% 43.5% 27.3% 35.5% 60.4% 31.4% 10.1% 9.3% 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 modiÑcations and upgrades to existing equipment and facilities. Drilling and Completion Fluids Revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Direct operating costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Selling, general and administrativeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating income (loss) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total jobs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average revenue per job ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average direct operating costs per jobÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Capital expendituresÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2004 % Change Years Ended December 31, Restated (See Note 2) 2003 (Dollars in thousands) 30.8% $69,230 24.5% $61,424 3.3% $ 7,447 $ 2,279 (5.4)% $(1,920) N/A% 14.2% 14.6% 9.1% 63.2% 1,931 $ 35.85 $ 31.81 912 $ $90,557 $76,503 $ 7,696 $ 2,156 $ 4,202 2,205 $ 41.07 $ 34.70 $ 1,488 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 36 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. Oil and Natural Gas Production and Exploration Revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Direct operating costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Selling, general and administrativeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Depreciation, depletion and impairment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Capital expendituresÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average net daily oil production (Bbls) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average net daily gas production (Mcf) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average oil sales price (per Bbl) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Average gas sales price (per Mcf)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ % Change 2004 Years Ended December 31, 2003 (Dollars in thousands) $21,163 $ 4,808 $ 1,489 $ 7,082 $ 7,784 $10,015 788 5,656 $ 30.54 4.97 $ $33,867 $ 7,978 $ 1,816 $13,309 $10,764 $14,451 1,071 7,429 $ 39.12 5.81 $ 60.0% 65.9% 22.0% 87.9% 38.3% 44.3% 35.9% 31.3% 28.1% 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. Corporate and Other Selling, general and administrativeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Bad debt expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other operating (including gain or loss on sale of assets) ÏÏÏÏÏÏ Embezzled funds expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Interest incomeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Interest expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ % Change 2004 Years Ended December 31, Restated (See Note 2) 2003 (Dollars in thousands) $ 8,665 259 $ $ 444 $(4,379) $17,849 $ 1,116 $ 292 $ 1,870 $10,820 897 $ $ 444 $(1,411) $19,122 $ 1,140 695 $ 235 $ 24.9% 246.3% Ì% 67.8% 7.1% 2.2% 138.0% (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. Embezzled funds expense includes fraudulent payments made to or for the beneÑt of Jonathan D. Nelson, our former CFO, for assets and services that were not received by the Company. 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. 37 Income Taxes Years Ended December 31, Restated (See Note 2) Income before income tax ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Income tax expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ EÅective tax rateÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2003 2005 2004 (Dollars in thousands) $149,147 54,801 $584,759 212,019 $68,976 25,320 36.3% 36.7% 36.7% The signiÑcance of the impact of the permanent diÅerences to our eÅective income tax rate in 2005 was largely attributable to the new Domestic Production Activities Deduction. The deduction was enacted as part of the American Jobs Creation Act of 2004 eÅective for taxable years after December 31, 2004. The act allows a deduction of 3% in 2005 or 2006, 6% in 2007, 2008 or 2009, and 9% 2010 and after on the lesser of qualiÑed production activities income or taxable income. Our eÅective 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 diÅerences was not signiÑcant in 2004 or 2003. For tax purposes, we have available at December 31, 2005, Federal net operating loss carryforwards of approximately $11 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: 2006 Ì $1 million, 2011 Ì $2 million, 2018 Ì $4 million and 2019 Ì $4 million. The alternative minimum tax credit may be carried forward indeÑnitely. We record deferred Federal income taxes based primarily on the relationship between the amount of our unused Federal net operating loss carryforwards and the temporary diÅerences 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 diÅerences are expected to be settled. As a result of fully recognizing the beneÑt of our deferred income taxes, we incur deferred income tax expense as these beneÑts are utilized. We incurred deferred income tax expense of approximately $17.1 million, $14.8 million and $10.0 million for 2005, 2004 and 2003, respectively. Volatility of Oil and Natural Gas Prices Our revenue, proÑtability 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 aÅected 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 Ñrst 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 and $8.98 in 2005, resulting in an increase in demand for our drilling services. Our average number of rigs operating increased from 126 in 2002 to 276 in 2005. We expect oil and natural gas prices to continue to be volatile and to aÅect our Ñnancial condition and operations and ability to access sources of capital. A signiÑcant decrease in expected market prices for natural gas could result in a material decrease in demand for drilling rigs and reduction in our operation results. The North American land drilling industry has experienced many downturns in demand over the last decade. During these periods, there have been substantially more drilling rigs available than necessary to meet demand. As a result, drilling contractors have had diÇculty sustaining proÑt margins during the downturn periods. 38 Impact of InÖation We believe that inÖation will not have a signiÑcant near-term impact on our Ñnancial position. Recently-Issued Accounting Standards The Financial Accounting standards Board (""FASB'') issued StaÅ Position FIN 47, Accounting for Conditional Asset Retirement Obligations (""FIN 47''), an interpretation of FASB Statement No. 143, in March 2005. The statement clariÑes the term ""conditional asset retirement obligation'' as used in FASB 143. The provisions of FIN 47, which the Company adopted on December 31, 2005, did not have a material impact on the Company's Ñnancial position or results of operations. The 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. Under SFAS 123(R), companies would have been required to implement the standard as of the beginning of the Ñrst interim reporting period that begins after June 15, 2005. However, in April 2005, the SEC announced the adoption of an Amendment to Rule 4-01(a) of Regulation S-X regarding the compliance date for SFAS 123(R) that amends the compliance dates and allows companies to implement SFAS 123(R) beginning with the Ñrst annual reporting period beginning on or after June 15, 2005. The Company intends to adopt SFAS 123(R) on January 1, 2006. 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 intend to expense stock options using the ModiÑed Prospective Transition method as described in SFAS 123(R). This method will require expense to be recognized for stock options over their respective remaining vesting periods. No expense will be recognized for stock options vested in periods prior to the adoption of SFAS 123(R). We are evaluating the impact of the adoption of SFAS 123(R) on our results of operations and Ñnancial position. Adoption is not expected to have a material eÅect on our Ñnancial position or results of operations. The FASB issued Statement of Financial Accounting Standard No. 151, Inventory Costs Ì an amend of ARB No. 43, Chapter 4 (""SFAS 151''). SFAS 151 is eÅective, and will be adopted, for inventory costs incurred during Ñscal 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 eÅect on our Ñnancial position or results of operations. The FASB issued Statement of Financial Accounting Standard No. 153, Exchanges of Nonmonetary Assets Ì an amendment of APB Opinion No. 29 (""SFAS 153''). FAS 153 is eÅective, and will be adopted, for nonmonetary asset exchanges occurring in Ñscal 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 Öows of the entity are expected to change signiÑcantly as a result of the exchange. Adoption is not expected to have a material eÅect on our Ñnancial position or results of operations. The FASB issued Statement of Financial Accounting standards No. 154, Accounting changes and Error Corrections Ì a replacement of APB Opinion No. 20 and FASB Statement No. 3 (""SFAS 145''). SFAS 154 is eÅective, and will be adopted for accounting changes made in Ñscal years beginning after December 15, 2005 and is to be applied retrospectively. SFAS 154 requires that retroactive application of a change in accounting principle be limited to the direct eÅects of the change. Adoption is not expected to have a material eÅect on the Company's Ñnancial position or results of operations. 39 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 Öoating rate of the interest charged on that balance. The revolving credit facility calls for periodic interest payments at a Öoating 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 Öuctuated during the last several years. If the value of the Canadian dollar against the U.S. dollar weakens, revenues and earnings of our Canadian operations will be reduced and the value of our Canadian net assets will decline when they are translated to U.S. dollars. Item 8. Financial Statements and Supplementary Data. Financial Statements are Ñled 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. Background to the Fraud and Restatement In November 2005, the Company discovered that its former Chief Financial OÇcer, Jonathan D. Nelson (""Nelson''), had fraudulently diverted approximately $78 million in Company funds for his own beneÑt. Nelson's fraudulent diversions began in 1998 and continued until the fourth quarter of 2005 when he resigned from the Company. The funds fraudulently diverted were recorded as payments for assets or services that were not actually received by the Company. Beginning in 1998, and continuing until late 2000, Nelson wrote a series of checks aggregating approximately $4.9 million to himself and to, or for the beneÑt of, a company owned and controlled by him. During this time, Nelson had check writing authority on the Company's principal funding account, and also had the ability to intercept bank statement information sent to the Company. When Nelson intercepted that information, he removed the cancelled checks reÖecting the embezzled funds from the bank statements and then provided false information to other Company employees regarding those checks. Company employees used the false information Nelson provided in recording the transactions. In 1999, Nelson gained access to a form authorizing his salary increase and improperly added a provision to it that created an additional expense allowance beneÑt of $2,000 per month, along with a provision making the salary increase and unauthorized expense allowance retroactive for several months. Nelson added these provisions himself and then forged the initials of the Company's Chief Executive OÇcer on the form as authorization for these non-approved payments. Beginning in December 2000 and continuing until October 2005, Nelson caused the wiring of Company funds aggregating approximately $70.2 million to, or for the beneÑt of, entities owned and controlled by him. Nelson was originally able to initiate these wire transfers by requesting the wire transfers himself in telephone calls to one of the Company's banks. After changes to the Company's internal controls and procedures in 2004, Nelson initiated the wire transfers through instructions to one of his subordinates and by the creation of fraudulent invoices containing forged senior management approvals. In connection with an acquisition by the Company in early 2004, Nelson also used a wire transfer to fraudulently divert funds from the Company. At the time of the acquisition, Nelson initiated a wire transfer for approximately $2.1 million by sending an email to one of his subordinates in which he falsely represented that 40 the wired funds were to be used to pay oÅ the seller's obligation for an aircraft maintenance agreement relating to the acquired business. In reality, Nelson used the funds to purchase an airplane for his personal use. Finally, in October 2004, Nelson diverted Company funds of approximately $1.6 million to Ñnance an investment in a company. Nelson accomplished the fraudulent diversion of Company funds by improperly directing the bank to fund Nelson's personal investment. After Nelson resigned from the Company in November 2005, the Company became aware that Nelson had fraudulently diverted Company funds. As a result, the Audit Committee of the Board of Directors commenced an investigation into Nelson's activities. The Audit Committee retained independent counsel and independent forensic accountants to assist with the investigation. The investigation conÑrmed the above facts and revealed that Nelson exploited the reliance placed on him to create an environment at the Company which discouraged routine communication concerning Ñnancial and business information within the organization between senior management (other than Nelson) and those employees engaged in the Company's Ñnancial reporting and accounting functions (other than Nelson). Nelson also discouraged communication between employees involved in Ñnancial reporting and accounting functions and those involved in operational activities. The control environment at the Company resulted in Company employees placing trust in Nelson and placed Nelson at the center of information Öows about Ñnancial reporting and accounting matters. The control environment allowed Nelson to override certain of the Company's internal controls and procedures, and contributed to the failure of Company employees charged with certain Ñnancial and accounting duties to exercise appropriate judgment, skepticism and objectivity, such that prevention or detection of the override of established policies, procedures, controls and Nelson's inappropriate transactions did not occur while Nelson was employed by the Company. This allowed Nelson to make unauthorized payments for assets that were not, in fact, ordered by or delivered to the Company, and for services that were not actually provided to the Company and to conceal the fraudulent transactions within the Company's accounting and Ñnancial records and reports. On December 22, 2005, the Company announced that the Audit Committee of the Board of Directors had concluded that it was necessary to restate its previously reported consolidated Ñnancial statements for the years ended December 31, 2004, 2003 and 2002. The Company also restated its previously reported consolidated Ñnancial statements for the Ñrst three quarters of 2005 and all quarters in 2004 and 2003. The Company Ñled an Annual Report on Form 10-K/A on March 17, 2006, and Quarterly Reports on Form 10- Q/A on March 27, 2006 that included these restated consolidated Ñnancial statements. Restatement adjustments are further described in Note 2 of the Notes to the Consolidated Financial Statements. Disclosure Controls and Procedures Under the supervision and with the participation of our management, including our Chief Executive OÇcer (CEO) and current Chief Financial OÇcer (CFO), we conducted an evaluation of the eÅectiveness of our disclosure controls and procedures, as such term is deÑned in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities and Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this Annual Report on Form 10-K. Disclosure controls and procedures are designed to ensure that the information required to be disclosed by us in the reports we Ñle or submit under the Exchange Act is recorded, processed, summarized, and reported on a timely basis and that such information is accumulated and reported to management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosures. At the time of the Ñling of our Annual Report on Form 10-K for the year ended December 31, 2004, our CEO and former CFO concluded that our disclosure controls and procedures were eÅective as of Decem- ber 31, 2004. Subsequent to that evaluation, our CEO and current CFO concluded that our disclosure controls and procedures were not eÅective at a reasonable level of assurance, as of December 31, 2004, because of the material weaknesses discussed in the Annual Report on Form 10-K/A Ñled March 17, 2006. As described below under ""Management's Report on Internal Control Over Financial Reporting,'' the Company continues 41 to report material weaknesses in internal control over Ñnancial reporting as of December 31, 2005. The Company's CEO and current CFO have concluded that, as of the end of the period covered by this Annual Report on Form 10-K, the Company's disclosure controls and procedures were not eÅective at a reasonable level of assurance. Based upon the substantial work performed during the restatement process, management has concluded that the Company's consolidated Ñnancial statements for the periods covered by and included in this Annual Report on Form 10-K are fairly stated in all material respects. Management's Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over Ñnancial reporting as such term is deÑned in Exchange Act Rule 13a-15(f). Our management, including our CEO and current CFO, conducted an evaluation of the eÅectiveness of our internal control over Ñnancial reporting as of December 31, 2005 using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (COSO framework). Because of its inherent limitations, internal control over Ñnancial reporting may not prevent or detect misstatements. Also, projections of any evaluation of eÅectiveness 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. A material weakness is a control deÑciency, or combination of control deÑciencies, that results in more than a remote likelihood that a material misstatement of the annual or interim Ñnancial statements will not be prevented or detected. Our current management identiÑed the following material weaknesses in our internal control over Ñnancial reporting as of December 31, 2005: 1. Control environment. We did not maintain an eÅective control environment based on the criteria established in the COSO framework. SpeciÑcally, the Company did not maintain a control environment adequate to encourage the prevention or detection of the override of our controls or intentional misconduct, including misappropriation of assets and the preparation of false management reports, accounting records, Ñnancial statements and documents together with forged approval signatures. This lack of an eÅective control environment allowed our former CFO to take inappropriate actions that resulted in certain transactions not being properly reÖected in our consolidated Ñnancial statements for the years ended December 31, 2004, 2003 and 2002, each of the quarters of 2004 and 2003, and the Ñrst three quarters of 2005. This intentional misconduct by our former CFO included the preparation of false accounting records and documents to deceive accounting personnel under his supervision, other members of senior management, our Board of Directors and our independent registered public accountants. Additionally, the lack of an eÅective control environment allowed our lines of communication among, and our monitoring of, our operations and accounting personnel, including our former CFO, to not be eÅective in preventing or detecting these instances of intentional misconduct. Taken as a whole, our control environment did not adequately emphasize appropriate judgment, skepticism and objectivity, and our former CFO intentionally exploited this environment for his personal beneÑt, speciÑcally with respect to our controls over cash, payroll and property and equipment as follows: a. Cash. Our former CFO manipulated the process over the initiation and approval of cash wire transfers. This action was taken in order to accomplish the fraudulent diversion of cash from the Company to entities owned by our former CFO for goods and services which the Company neither requested nor received. False documentation was created by our former CFO to conceal the true nature of these transactions from the Company and its independent registered public accountants. b. Payroll. In 1999, our former CFO intentionally altered his payroll records to indicate that appropriate authorization had been given for a retroactive increase in his compensation and related beneÑts when in fact no such authorization had been provided. This false documentation was created by our former CFO to provide for an unauthorized increase to his compensation and to conceal the unauthorized compensation increase from the Company and its independent registered public accountants. 42 c. Property and Equipment. Our former CFO instructed certain former employees, who worked under his supervision, to alter management reports related to property and equipment expenditures. Additionally, our former CFO created Ñctitious property and equipment approval forms with forged signatures. These actions had the eÅect of concealing his inappropriate and fraudulent diversion of cash. The activities by our former CFO deceived the Company and its independent registered public accountants as to the true nature of the Company's cash transfers and property and equipment expenditures. This control environment material weakness contributed to the embezzlement occurring, which in turn resulted in the restatement of our consolidated Ñnancial statements for the years ended December 31, 2004, 2003 and 2002, each of the quarters of 2004 and 2003, and the Ñrst three quarters of 2005. Additionally, this control environment material weakness could result in misstatements of any of our Ñnancial statement accounts that would result in a material misstatement to the annual or interim consolidated Ñnancial statements that would not be prevented or detected. Accordingly, our management has determined that this control deÑciency constitutes a material weakness. The material weakness in our control environment contributed to the existence of the following additional material weakness in controls over property and equipment as described below: 2. Controls over property and equipment. We did not maintain eÅective controls over the completeness and accuracy of our accounting for property and equipment. SpeciÑcally, our controls were not adequate to ensure (i) the timely and accurate depreciation of all property and equipment, (ii) the identiÑcation and recording of all property and equipment retirements when they occurred, and (iii) that property and equipment transferred between our locations was accurately and completely reÖected in our accounting records. This control deÑciency resulted in certain inaccuracies in our accounting for property and equipment and in the restatement of our consolidated Ñnancial statements for the years ended December 31, 2004, 2003 and 2002; each of the quarters of 2004 and 2003; and the Ñrst three quarters of 2005. Additionally, this control deÑciency could result in a misstatement of our property and equipment and related depreciation expense accounts that would result in a material misstatement to the annual or interim consolidated Ñnancial statements that would not be prevented or detected. Accordingly, our management has determined that this control deÑciency constitutes a material weakness. Our management, including our CEO and current CFO, have concluded that as a result of the material weaknesses described above, we did not maintain eÅective internal control over Ñnancial reporting as of December 31, 2005, based on the criteria in Internal Control-Integrated Framework issued by the COSO. Our assessment of the eÅectiveness of our internal control over Ñnancial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting Ñrm, as stated in their report which begins on page F-2 of this Annual Report on Form 10-K. Changes in Internal Control Over Financial Reporting Management is committed to remediating each of the material weaknesses identiÑed above by implementing changes to the Company's internal control over Ñnancial reporting. Management has imple- mented, or is in the process of implementing, the following changes to the Company's internal control systems and procedures: We are strengthening our tracking system for property and equipment to improve the tracking of those assets between our yards and rigs and to trigger the timely commencement of depreciation of assets placed in service. We are implementing procedures and processes to reinforce with our employees their responsibilities to exercise independence and judgment and to comply with the Company's compliance programs, including: ‚ formal certiÑcations of information contained in SEC Ñlings relating to their areas of responsibility; 43 ‚ annual written questionnaires from senior employees and accounting staÅ with respect to awareness as to questionable business practices; ‚ improved education and training programs for all employees covering ethics, compliance, Ñnancial reporting and good business practices; ‚ additional guidelines with respect to senior management's responsibilities for SEC Ñlings, Ñnancial reports, budgets and maintenance of controls over assets and expenditures; and ‚ annual reporting to the Audit Committee with respect to these processes and procedures. In addition, we will initiate a search for an in-house counsel whose responsibilities will include an active role in corporate compliance and governance. We have initiated structural changes and processes and procedures to increase communications between the Ñnancial reporting and accounting functions and operations and between the Ñnancial reporting and accounting functions and senior management. Additionally, management is committed to continued improvements in controls. In this regard, we are revising our internal audit reporting structure to further enhance its direct reporting to the audit committee and its program of monitoring controls. During the fourth quarter of 2005, we changed our wire transfer approval policies to require additional and more secure authorizations for wires to ensure that all wire transfers are to approved vendors, and to ensure that all such transactions are reÖected in the Company's accounts payable system and have appropriate supporting documentation. We also revised our property and equipment expenditure requirements to provide for improved controls over the authorization of Ñxed asset acquisitions. We have evaluated the design of these new procedures, placed them in operation for a suÇcient period of time, and subjected them to appropriate tests in order to conclude that they are operating eÅectively. These changes remediated the material weakness in controls over cash that was reported in Management's Report on Internal Control Over Financial Reporting included in the Company's Annual Report on Form 10-K/A for the year ended December 31, 2004 (""Management's 2004 Report''). In addition, these changes remediated the control failure over the authorization of property and equipment acquisitions as reported in Management's 2004 Report. Other than the changes described above, there have been no other changes in our internal control over Ñnancial reporting during the most recently completed Ñscal quarter that have materially aÅected, or are reasonably likely to materially aÅect, our internal control over Ñnancial reporting. The remaining remediation activities noted above were initiated in the fourth quarter of 2005 and the remaining controls will be implemented in 2006. Item 9B. Other Information None. 44 PART III The information required by Part III is omitted from this Report because we will Ñle a deÑnitive proxy statement pursuant to Regulation 14A of the Securities Exchange Act of 1934 no later than 120 days after the end of the Ñscal year covered by this Report and certain information included therein is incorporated herein by reference. Item 10. Directors and Executive OÇcers 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 BeneÑcial 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. 45 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 Ì Valuation and qualifying accounts is Ñled herewith on page S-1. All other Ñnancial statement schedules have been omitted because they are not applicable or the information required therein is included elsewhere in the Ñnancial statements or notes thereto. (a)(3) Exhibits The following exhibits are Ñled herewith or incorporated by reference herein. 3.1 Restated CertiÑcate of Incorporation, as amended (Ñled 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 CertiÑcate of Incorporation, as amended (Ñled 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 (Ñled March 19, 2002 as Exhibit 3.2 to the Company's Annual Report on Form 10-K for the Ñscal year ended December 31, 2001 and incorporated herein by reference). Rights Agreement dated January 2, 1997, between Patterson Energy, Inc. and Continental Stock Transfer & Trust Company (Ñled January 14, 1997 as Exhibit 2 to the Company's Registration Statement on Form 8-A and incorporated herein by reference). 4.1 4.3 4.4 4.2 Amendment to Rights Agreement dated as of October 23, 2001 (Ñled 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). Restated CertiÑcate of Incorporation, as amended (See Exhibits 3.1 and 3.2). Registration Rights Agreement with Bear, Stearns and Co. Inc., dated March 25, 1994, as assigned by REMY Capital Partners III, L.P.(Ñled March 19, 2002 as Exhibit 4.3 to the Company's Annual Report on Form 10-K for the Ñscal year ended December 31, 2001 and incorporated herein by reference). For additional material contracts, see Exhibits 4.1, 4.2 and 4.4. Patterson-UTI Energy, Inc., 1993 Stock Incentive Plan, as amended (Ñled 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).* Patterson-UTI Energy, Inc. Non-Employee Directors' Stock Option Plan, as amended (Ñled Novem- ber 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).* 10.1 10.2 10.3 10.4 Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (Ñled Novem- ber 27, 2002 as Exhibit 4.4 to Post EÅective Amendment No. 1 to the Company's Registration Statement on Form S-8 (File No. 333-60470) and incorporated herein by reference).* Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (Ñled 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).* 10.5 10.6 Amendment to the Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (Ñled 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).* 46 10.7 Amended and Restated Patterson-UTI Energy, Inc. Non-Employee Director Stock Option Plan(Ñled 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 (Ñled July 25, 2001 as Exhibit 4.4 to Post-EÅective Amendment No. 1 to the Company's Registration Statement on Form S-8 (File No. 333-60466) and incorporated herein by reference).* 1997 Stock Option Plan of DSI Industries, Inc. (Ñled July 25, 2001 as Exhibit 4.4 to Post-EÅective Amendment No. 1 to the Company's Registration Statement on Form S-8 (File No. 333-60470) and incorporated herein by reference).* 10.9 10.10 Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, including Form of Executive OÇcer Restricted Stock Award Agreement, Form of Executive OÇcer Stock Option Agreement, Form of Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee Director Stock Option Agreement (Ñled June 15, 2005 as Exhibit 10.1 to the Company's Current Report on Form 8-K, and incorporated herein by reference).* 10.11 Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and Mark S. Siegel (Ñled 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 (Ñled 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 (Ñled 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 (Ñled 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 John E. Vollmer III (Ñled 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).* 10.16 Patterson-UTI Energy, Inc. Change in Control Agreement, eÅective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Mark S. Siegel (Ñled 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).* 10.17 Patterson-UTI Energy, Inc. Change in Control Agreement, eÅective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and A. Glenn Patterson (Ñled 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).* 10.18 Patterson-UTI Energy, Inc. Change in Control Agreement, eÅective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (Ñled 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).* 10.19 Patterson-UTI Energy, Inc. Change in Control Agreement, eÅective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Kenneth N. Berns (Ñled 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).* 10.20 Patterson-UTI Energy, Inc. Change in Control Agreement, eÅective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and John E. Vollmer III (Ñled 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).* 10.21 Form of Letter Agreement regarding termination, eÅective 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 (Ñled on February 25, 2005 as Exhibit 10.23 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004 and incorporated herein by reference).* 47 10.22 Form of IndemniÑcation 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. HuÅ, Terry H. Hunt, Kenneth R. Peak, Nadine C. Smith and John E. Vollmer III (Ñled 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).* 10.23 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 (Ñled on December 23, 2004 as Exhibit 10.1 to the Company's Current Report on Form 8-K and incorporated herein by reference). 10.24 Summary Description of 2005 Bonus Compensation Program (Ñled on April 29, 2005 in the Company's Current Report on Form 8-K and incorporated herein by reference).* 14.1 10.25 Summary Description of Director Compensation (Ñled on February 25, 2005 as Exhibit 10.27 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004 and incorporated herein by reference).* Patterson-UTI Energy, Inc. Code of Business Conduct and Ethics for Senior Financial Executives (Ñled on February 4, 2004 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). Subsidiaries of the Registrant. Consent of Independent Registered Public Accounting Firm. CertiÑcation of Chief Executive OÇcer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended. CertiÑcation of Chief Financial OÇcer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended. CertiÑcation of Chief Executive OÇcer and Chief Financial OÇcer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 21.1 23.1 31.1 31.2 32.1 * Management Contract or Compensatory Plan identiÑed as required by Item 15(a)(3) of Form 10-K. 48 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page Report of Independent Registered Public Accounting Firm ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ F-2 Consolidated Financial Statements: Consolidated Balance Sheets as of December 31, 2005 and 2004ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ F-5 Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003 ÏÏÏÏÏÏÏ F-6 Consolidated Statements of Changes In Stockholders' Equity for the years ended December 31, 2005, 2004 and 2003 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ F-7 Consolidated Statements of Changes In Cash Flows for the years ended December 31, 2005, 2004 and 2003ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ F-8 Notes to Consolidated Financial Statements ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ F-9 Financial Statement Schedule ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ S-1 F-1 Report of Independent Registered Public Accounting Firm To the Board of Directors and Stockholders of Patterson-UTI Energy, Inc. We have completed integrated audits of Patterson-UTI Energy, Inc.'s 2005 and 2004 consolidated Ñnancial statements and of its internal control over Ñnancial reporting as of December 31, 2005, and an audit of its 2003 consolidated Ñnancial 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 Ñnancial statements and Ñnancial statement schedule In our opinion, the consolidated Ñnancial statements listed in the accompanying index present fairly, in all material respects, the Ñnancial position of Patterson-UTI Energy, Inc. and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash Öows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the Ñnancial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated Ñnancial statements. These Ñnancial statements and Ñnancial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these Ñnancial statements and Ñnancial 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 Ñnancial statements are free of material misstatement. An audit of Ñnancial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the Ñnancial statements, assessing the accounting principles used and signiÑcant estimates made by management, and evaluating the overall Ñnancial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 2 to the consolidated Ñnancial statements, the Company restated its 2004 and 2003 consolidated Ñnancial statements. Internal control over Ñnancial reporting Also, we have audited management's assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A, that Patterson-UTI Energy, Inc. did not maintain eÅective internal control over Ñnancial reporting as of December 31, 2005, because the Company did not maintain (1) an eÅective control environment and (2) eÅective controls over property and equipment, based on criteria established in Internal Control Ì Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining eÅective internal control over Ñnancial reporting and for its assessment of the eÅectiveness of internal control over Ñnancial reporting. Our responsibility is to express opinions on management's assessment and on the eÅectiveness of the Company's internal control over Ñnancial reporting based on our audit. We conducted our audit of internal control over Ñnancial 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 eÅective internal control over Ñnancial reporting was maintained in all material respects. An audit of internal control over Ñnancial reporting includes obtaining an understanding of internal control over Ñnancial reporting, evaluating management's assessment, testing and evaluating the design and operating eÅectiveness 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 Ñnancial reporting is a process designed to provide reasonable assurance regarding the reliability of Ñnancial reporting and the preparation of Ñnancial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over F-2 Ñnancial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reÖect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of Ñnancial 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 eÅect on the Ñnancial statements. Because of its inherent limitations, internal control over Ñnancial reporting may not prevent or detect misstatements. Also, projections of any evaluation of eÅectiveness 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. A material weakness is a control deÑciency, or combination of control deÑciencies, that results in more than a remote likelihood that a material misstatement of the annual or interim Ñnancial statements will not be prevented or detected. The following material weaknesses have been identiÑed and included in management's assessment as of December 31, 2005. 1. Control environment. The Company did not maintain an eÅective control environment based on the criteria established in the COSO framework. SpeciÑcally, the Company did not maintain a control environment adequate to encourage the prevention or detection of the override of controls or intentional misconduct, including misappropriation of assets and the preparation of false management reports, accounting records, Ñnancial statements and documents together with forged approval signatures. This lack of an eÅective control environment allowed the Company's former CFO to take inappropriate actions that resulted in certain transactions not being properly reÖected in the Company's consolidated Ñnancial statements for the years ended December 31, 2004, 2003 and 2002, each of the quarters of 2004 and 2003, and the Ñrst three quarters of 2005. This intentional misconduct by the Company's former CFO included the preparation of false accounting records and documents to deceive accounting personnel under his supervision, other members of senior management, the Board of Directors and its independent registered public accountants. Additionally, the lack of an eÅective control environment allowed the Company's lines of communication among, and their monitoring of, their operations and accounting personnel, including their former CFO, to not be eÅective in preventing or detecting these instances of intentional misconduct. Taken as a whole, the Company's control environment did not adequately emphasize appropriate judgment, skepticism and objectivity, and their former CFO intentionally exploited this environment for his personal beneÑt, speciÑcally with respect to the Company's controls over cash, payroll and property and equipment as follows: a. Cash. The Company's former CFO manipulated the process over the initiation and approval of cash wire transfers. This action was taken in order to accomplish the fraudulent diversion of cash from the Company to entities owned by their former CFO for goods and services which the Company neither requested nor received. False documentation was created by the Company's former CFO to conceal the true nature of these transactions from the Company and its independent registered public accountants. b. Payroll. In 1999, the Company's former CFO intentionally altered his payroll records to indicate that appropriate authorization had been given for a retroactive increase in his compensation and related beneÑts when in fact no such authorization had been provided. This false documentation was created by the Company's former CFO to provide for an unauthorized increase to his compensation and to conceal the unauthorized compensation increase from the Company and its independent registered public accountants. c. Property and Equipment. The Company's former CFO instructed certain former employ- ees, who worked under his supervision, to alter management reports related to property and equipment expenditures. Additionally, the Company's former CFO created Ñctitious property and equipment approval forms with forged signatures. These actions had the eÅect of concealing his F-3 inappropriate and fraudulent diversion of cash. The activities by the Company's former CFO deceived the Company and its independent registered public accountants as to the true nature of the Company's cash transfers and property and equipment expenditures. The Company's material weakness in its control environment contributed to the existence of the material weakness in controls over property and equipment as described below: 2. Controls over property and equipment. The Company did not maintain eÅective controls over the completeness and accuracy of their accounting for property and equipment. SpeciÑcally, the Company's controls were not adequate to ensure (i) the timely and accurate depreciation of all property and equipment, (ii) the identiÑcation and recording of all property and equipment retirements when they occurred, and (iii) that property and equipment transferred between Company locations was accurately and completely reÖected in their accounting records. This control deÑciency resulted in certain inaccuracies in the Company's accounting for property and equipment. The control deÑciencies described above resulted in the restatement of the Company's consolidated Ñnancial statements for the years ended December 31, 2004, 2003 and 2002, each of the quarters of 2004 and 2003, and the Ñrst three quarters of 2005. Additionally, each of the control deÑciencies described above could result in a misstatement in the aforementioned accounts or disclosures that would result in a material misstatement in the Company's annual or interim consolidated Ñnancial statement that would not be prevented or detected. Accordingly, the Company's management has determined that each of these control deÑciencies constitute material weaknesses. These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2005 consolidated Ñnancial statements, and our opinion regarding the eÅectiveness of the Company's internal control over Ñnancial reporting does not aÅect our opinion on those consolidated Ñnancial statements. In our opinion, management's assessment that Patterson-UTI Energy, Inc. did not maintain eÅective internal control over Ñnancial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control Ì Integrated Framework issued by the COSO. Also, in our opinion, because of the eÅects of the material weaknesses described above on the achievement of the objectives of the control criteria, Patterson-UTI Energy, Inc. has not maintained eÅective internal control over Ñnancial reporting as of December 31, 2005, based on criteria established in Internal Control Ì Integrated Framework issued by the COSO. PricewaterhouseCoopers LLP Houston, Texas March 29, 2006 F-4 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS December 31, Restated (See Note 2) 2004 2005 (In thousands, except share data) Current assets: ASSETS Cash and cash equivalents ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Accounts receivable, net of allowance for doubtful accounts of $2,199 and $1,909 at December 31, 2005 and 2004, respectively ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Inventory ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Deferred tax assets, netÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ OtherÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total current assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Property and equipment, at cost, netÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Goodwill ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ OtherÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total assetsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 136,398 $ 112,371 422,002 27,907 26,382 25,168 637,857 1,053,845 99,056 5,023 $1,795,781 214,097 17,738 15,991 26,836 387,033 765,019 99,056 5,677 $1,256,785 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable: TradeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Accrued revenue distributions ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ OtherÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Accrued Federal and state income taxes payable ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Accrued expenses ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total current liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Deferred tax liabilities, net ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ OtherÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Commitments and contingencies ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Stockholders' equity: Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued Common stock, par value $.01; authorized 300,000,000 shares with 175,909,274 and 171,625,841 issued and 172,441,178 and 168,512,745 outstanding at December 31, 2005 and 2004, respectively ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Additional paid-in capital ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Deferred compensation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Retained earnings ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Accumulated other comprehensive income, net of tax ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Treasury stock, at cost, 3,468,096 shares and 3,113,096 (aÅected by a two- $ 113,226 13,379 5,294 11,034 112,476 255,409 169,188 4,173 428,770 Ì $ 54,553 11,297 2,309 4,231 79,163 151,553 140,475 3,256 295,284 Ì Ì Ì 1,759 672,151 (9,287) 719,113 8,565 1,716 597,280 (5,420) 373,712 7,350 for-one stock split) shares at December 31, 2005 and 2004, respectivelyÏÏÏ Total stockholders' equity ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total liabilities and stockholders' equity ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ (25,290) 1,367,011 $1,795,781 (13,137) 961,501 $1,256,785 The accompanying notes are an integral part of these consolidated Ñnancial statements. F-5 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME Operating revenues: Contract drilling ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Pressure pumping ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating costs and expenses: Contract drilling ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Pressure pumping ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Depreciation, depletion and impairment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Selling, general and administrative ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Bad debt expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Embezzled funds and related expenses ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other (including gain or loss on sale of assets) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other income (expense): Interest income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Interest expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Years Ended December 31, Restated (See Note 2) 2005 2003 2004 (In thousands, except per share data) $1,485,684 93,144 122,011 39,616 1,740,455 $ 809,691 66,654 90,557 33,867 1,000,769 $639,694 46,083 69,230 21,163 776,170 776,313 54,956 98,530 9,566 156,393 39,110 1,231 20,043 3,017 1,159,159 581,296 3,551 (516) 428 3,463 556,869 37,561 76,503 7,978 122,800 31,983 897 19,122 (1,411) 852,302 148,467 1,140 (695) 235 680 475,224 26,184 61,424 4,808 100,834 27,685 259 17,849 (4,379) 709,888 66,282 1,116 (292) 1,870 2,694 Income before income taxes and cumulative eÅect of change in accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 584,759 149,147 68,976 Income tax expense (beneÑt): Current ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ DeferredÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Income before cumulative eÅect of change in accounting principle ÏÏÏÏÏÏ Cumulative eÅect of change in accounting principle, net of related income tax beneÑt of approximately $287 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 194,918 17,101 212,019 372,740 Ì $ 372,740 Net income per common share: Basic: Income before cumulative eÅect of change in accounting principle ÏÏ Cumulative eÅect of change in accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Diluted: Income before cumulative eÅect of change in accounting principle ÏÏ Cumulative eÅect of change in accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Weighted average number of common shares outstanding: BasicÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Diluted ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ $ $ $ $ $ 2.19 Ì $ Ì $ 2.19 2.15 $ $ 0.57 0.56 $ $ Ì $ Ì $ Ì 0.27 0.27 Ì 2.15 $ 0.56 $ 0.26 170,426 173,767 166,258 169,211 161,272 164,572 39,952 14,849 54,801 94,346 Ì 94,346 15,324 9,996 25,320 43,656 (469) $ 43,187 0.57 $ 0.27 $ $ The accompanying notes are an integral part of these consolidated Ñnancial statements. F-6 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY Common Stock Number of Shares Amount Additional Paid-In Capital Deferred Compensation Retained Earnings Accumulated Other Comprehensive Income (Loss) Treasury Stock Total 81,577 $ 816 $489,201 $ Ì $261,208 $(1,839) $(11,655) $ 737,731 Ì Ì Ì Ì Ì Ì 81,577 816 489,201 906 Ì Ì Ì 9 Ì Ì Ì 10,277 6,540 Ì Ì 82,483 825 506,018 Ì (12,499) Ì Ì (12,499) (1,659) 675 Ì (984) 247,050 (1,164) (11,655) 724,248 Ì Ì Ì 43,187 Ì Ì 5,553 Ì Ì Ì Ì Ì 10,286 6,540 5,553 43,187 290,237 4,389 (11,655) 789,814 Ì Ì Ì Ì Ì Ì Ì Ì (6,642) 1,388 189 Ì 2,580 Ì Ì Ì Ì 14 2 Ì 25 Ì Ì Ì Ì 84,986 Ì 850 Ì 49,462 6,640 Ì 1,222 24,494 10,666 Ì Ì Ì Ì Ì Ì Ì Ì Ì Ì Ì Ì Ì Ì Ì Ì Ì Ì Ì (10,021) (850) 94,346 Ì Ì Ì Ì Ì 2,961 Ì Ì Ì Ì 171,626 305 1,716 3 597,280 8,040 (5,420) (8,043) 373,712 Ì 7,350 Ì Ì (65) 4,043 Ì Ì Ì Ì Ì Ì Ì 40 Ì Ì Ì Ì Ì Ì (1,351) 43,434 24,748 Ì Ì Ì Ì 2,825 1,351 Ì Ì Ì Ì Ì Ì Ì Ì Ì Ì Ì Ì (27,339) 372,740 Ì Ì Ì Ì 1,215 Ì Ì Ì Ì Ì Ì Ì Ì Ì (1,482) Ì Ì Ì (13,137) Ì Ì Ì Ì Ì Ì (12,153) Ì Ì 49,476 Ì 1,222 24,519 10,666 2,961 (1,482) (10,021) Ì 94,346 961,501 Ì 2,825 Ì 43,474 24,748 1,215 (12,153) (27,339) 372,740 December 31, 2002, as previously reported ÏÏÏÏÏÏÏÏ Adjustment for eÅects of embezzlement (net of applicable income tax beneÑt of $7,622)(See Note 2)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other adjustments (net of applicable income tax beneÑt of $691) (See Note 2)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ December 31, 2002, as restated (See Note 2) ÏÏÏÏÏÏÏÏÏÏÏÏÏ Exercise of stock options and warrants ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Tax beneÑt related to exercise of stock options ÏÏ Foreign currency translation adjustment, (net of tax of $3,220) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Net income, as restated (See Note 2)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ December 31, 2003, as restated (See Note 2) ÏÏÏÏÏÏÏÏÏÏÏÏÏ Issuance of common stock for acquisition ÏÏÏÏÏÏÏÏÏÏ Issuance of restricted stock Amortization of deferred compensation expense ÏÏÏÏ Exercise of stock options and warrants ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Tax beneÑt related to exercise of stock options ÏÏ Foreign currency translation adjustment, (net of tax of $1,716) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Purchase of treasury stock ÏÏ Payment of cash dividend (see Note 12) ÏÏÏÏÏÏÏÏÏÏ EÅect of two-for-one stock split (see Note 12) ÏÏÏÏÏÏ Net income, as restated (See Note 2)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ December 31, 2004, as restated (See Note 2) ÏÏÏÏÏÏÏÏÏÏÏÏÏ Issuance of restricted stock Amortization of deferred compensation expense ÏÏÏÏ Forfeitures of restricted shares ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Exercise of stock options ÏÏÏ Tax beneÑt related to exercise of stock options ÏÏ Foreign currency translation adjustment, (net of tax of $705) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Purchase of treasury stock ÏÏ Payment of cash dividend (see Note 12) ÏÏÏÏÏÏÏÏÏÏ Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ December 31, 2005 ÏÏÏÏÏÏÏÏÏÏ 175,909 $1,759 $672,151 $(9,287) $719,113 $ 8,565 $(25,290) $1,367,011 The accompanying notes are an integral part of these consolidated Ñnancial statements. F-7 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS Cash Öows from operating activities: Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and impairmentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Provision for bad debtsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Deferred income tax expenseÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Tax beneÑt related to exercise of stock optionsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Amortization of deferred compensation expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Gain on sale of assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Cumulative eÅect of change in accounting principle, net of tax ÏÏ Changes in operating assets and liabilities, net of business acquired: Accounts receivable ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Federal income taxes receivable ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Inventory and other current assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Accounts payable ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Accrued expenses ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Net cash provided by operating activitiesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Cash Öows from investing activities: Acquisitions, net of cash acquiredÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Purchases of property and equipmentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Proceeds from sales of property and equipment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Change in other assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Net cash used in investing activitiesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Cash Öows from Ñnancing activities: Years Ended December 31, 2005 Restated (See Note 2) 2004 2003 (In thousands) $ 372,740 $ 94,346 $ 43,187 156,393 1,231 17,101 24,748 2,825 (1,253) Ì (208,248) 7,068 (9,402) 60,860 32,514 3,902 460,479 (73,577) (380,094) 12,674 1,766 (439,231) 122,800 897 14,849 10,666 1,222 (1,411) Ì (50,682) 15,734 (13,556) 12,861 1,555 (6,090) 203,191 100,834 259 9,996 6,540 Ì (1,927) (469) (55,791) 11,155 (8,984) 12,322 22,814 5,015 144,951 (30,387) (174,589) 3,303 (1,766) (203,439) (40,832) (98,801) 4,548 (1,693) (136,778) Purchase of treasury stock ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Dividends paidÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Line of credit issuance costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Proceeds from exercise of stock options and warrants ÏÏÏÏÏÏÏÏÏÏ Net cash provided by Ñnancing activities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ EÅect of foreign exchange rate changes on cashÏÏÏÏÏÏÏÏÏÏÏÏÏ Net increase in cash and cash equivalents ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Cash and cash equivalents at beginning of year ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Cash and cash equivalents at end of year ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ (12,153) (27,339) Ì 43,474 3,982 (1,203) 24,027 112,371 $ 136,398 (1,482) (10,021) (780) 24,519 12,236 (100) Ì Ì Ì 10,286 10,286 (130) 11,888 100,483 $ 112,371 18,329 82,154 $ 100,483 Supplemental disclosure of cash Öow information: Net cash received (paid) during the year for: Interest expenseÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Income taxes ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ (418) (156,709) $ (245) (12,500) $ (292) 2,730 The accompanying notes are an integral part of these consolidated Ñnancial statements. F-8 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Description of Business and Summary of SigniÑcant Accounting Policies A description of the business and basis of presentation follows: Description of business Ì 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, Montana, North Dakota, South Dakota and Western Canada. As of December 31, 2005, the Company owned 403 drilling rigs. The Company provides pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. The Company provides drilling Öuids, completion Öuids and related services to oil and natural gas operators oÅshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. 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 and South Texas, Southeastern New Mexico, Utah and Mississippi. Embezzlement and Restatement Ì The Company's former Chief Financial OÇcer (""CFO'') perpetrated an embezzlement over a period of more than Ñve years. The accompanying 2004 and 2003 consolidated Ñnancial statements have been restated to reÖect the eÅects of losses incurred as a result of the embezzlement in the periods of occurrence. Payments related to the embezzlement previously capitalized as property and equipment and goodwill acquired, and the related depreciation and other amounts expensed have been reversed from the Company's accounting records. Embezzled payments have been recognized as expense in the periods they were embezzled. The cumulative eÅects of the embezzlement prior to 2002, have been recognized as a reduction of retained earnings. The accompanying consolidated Ñnancial statements have also been restated for the eÅects of the correction of other errors that are immaterial both individually and in the aggregate (See Note 2). Basis of presentation Ì As a result of the Company increasing its ownership of TMBR/Sharp Drilling, Inc. (""TMBR'') from 19.5% to 100% in 2004, the consolidated Ñnancial statements of Patterson-UTI Energy, Inc. and its wholly-owned subsidiaries have been restated in accordance with the requirements of accounting for business combinations accounted for as a purchase, to provide for the retroactive application of the equity method of accounting for the Company's investment in TMBR (see Note 7). 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 eÅects of exchange rate changes are reÖected 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 eÅect on equity. Historical earnings per share amounts included in the Statements of Income and elsewhere in these Ñnancial statements have been restated as if the two-for-one stock split had occurred on January 1, 2003. A summary of the signiÑcant accounting policies follows: Principles of consolidation Ì The consolidated Ñnancial statements include the accounts of Patterson- UTI and its wholly-owned subsidiaries. All signiÑcant intercompany accounts and transactions have been eliminated. The Company has no controlling Ñnancial interests in any entity which would require consolidation. F-9 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) Management estimates Ì The preparation of Ñnancial statements in conformity with accounting princi- ples generally accepted in the United States of America requires management to make estimates and assumptions that aÅect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Ñnancial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could diÅer from such estimates. Revenue recognition Ì 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, manage- ment estimates are relied upon in the determination of the total estimated expenses to be incurred drilling the well. Due to the nature of turnkey contract drilling arrangements and risks therein, the Company follows the completed contract method of accounting for such arrangements. Under this method, all drilling 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 these out-of-pocket expenses as direct costs. Accounts receivable Ì 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 reviews the adequacy of its allowance for doubtful accounts monthly. SigniÑcant 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 Ì Inventories consist primarily of chemical products to be used in conjunction with the Company's drilling and completion Öuids activities. The inventories are stated at the lower of cost or market, determined by the Ñrst-in, Ñrst-out method. Property and equipment Ì 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 deÑned below. Useful Lives Drilling rigs and related equipment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ OÇce furniture ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Buildings ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Automotive equipment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2-15 3-10 5-20 2-7 3-7 Oil and natural gas properties Ì Oil and natural gas properties are accounted for using the successful eÅorts method of accounting. Under the successful eÅorts method of accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are charged to expense when such determination is made. 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 classiÑcation. If the reserve classiÑcation 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 F-10 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) 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 Ñeld. 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 Ñeld and undiscounted cash Öow estimates are provided by an independent petroleum engineer. If the net book value of a Ñeld exceeds its undiscounted cash Öow estimate, impairment expense is measured and recognized as the diÅerence between its net book value and discounted cash Öow. 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. Goodwill Ì Goodwill is considered to have an indeÑnite useful economic life and is not amortized. As such, the Company assesses 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. The following table summarizes depreciation, depletion and impairment expense for 2005, 2004 and 2003 (in millions): Restated (See Note 2) 2005 2004 2003 Depreciation expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Depletion expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Amortization expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Impairment of oil and natural gas properties ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $141.7 10.3 Ì 4.4 $109.4 10.1 0.1 3.2 $ 93.7 5.6 0.1 1.4 Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $156.4 $122.8 $100.8 Maintenance and repairs Ì 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 Ì Upon disposition or retirement of property and equipment, the cost and related accumu- lated depreciation are removed and any resulting gain or loss is credited or charged to operations. Investments in equity securities Ì Investments in equity securities are accounted for under the equity method of accounting. Earnings per share Ì 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, 2005, 2004 and 2003, dilutive securities, consisting of certain stock options and warrants (See Note 12), included in the calculation of Diluted EPS were 3.3 million shares, 3.0 million shares and 3.3 million shares, respectively. At December 31, 2005, there were no potentially dilutive securities and at December 31, 2004 and 2003, there were potentially dilutive securities of 640,000 and 1.9 million, 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 Ì 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 diÅerences between the Ñnancial 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 diÅerences F-11 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) are expected to be recovered or settled. The eÅect 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. Stock based compensation Ì During June 2005, the Company's shareholders approved the Patterson- UTI Energy, Inc. 2005 long-Term Incentive Plan (the ""2005 Plan''). In addition, the Board of Directors adopted a resolution that no future grants would be made under any of the previously existing equity plans of the Company. The Company accounts for activity under the 2005 Plan and previous activity of its other equity plans using the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees (""APB 25''), and related interpretations. During the second quarters of 2004 and 2005 and the third quarter of 2005, the company granted restricted shares of the Company's common stock (the ""Restricted Shares'') to certain key employees under the Patterson-UTI Energy, Inc. 1997 Long-Term Incentive Plan, as amended, and the 2005 Plan. As required by APB 25, the Restricted Shares were valued based upon the market price of the Company's common stock on the date of the grant. The resulting value is being amortized over the vesting period of the stock. For the years ended December 31, 2005 and 2004, compensation expense of $1.8 million and $773,000, net of $327,000 and $5,000 of forfeitures and of $1.0 million and $449,000 of taxes, respectively, was included as a reduction in net income. Other than the restricted Shares discussed above, no additional stock-based employee compensation expense is reÖected in net income, as all options granted under the plans discussed above had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the eÅect on net income and net income per share if the Company had applied the fair value recognition provisions of Financial Accounting Standards Board Statement No. 123, Accounting for Stock-Based Compensation (""SFAS 123''), to stock-based employee compensation (in thousands, except per share amounts): Net income, as reportedÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Add: Stock-based employee compensation expense recorded, Years Ended December 31, Restated (See Note 2) 2005 2004 2003 $372,740 $ 94,346 $ 43,187 net of forfeitures and taxes ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 1,795 773 Ì Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax eÅects(1)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ (11,119) (12,304) (10,506) Pro forma net incomeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $363,416 $ 82,815 $ 32,681 Earnings per share: Basic, as reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Basic, pro forma ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Diluted, as reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Diluted, pro forma ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Weighted-average fair value per share of options granted(1) $ $ $ $ $ 2.19 2.13 2.15 2.11 6.33 $ $ $ $ $ 0.57 0.50 0.56 0.49 6.25 $ $ $ $ $ 0.27 0.20 0.26 0.20 5.59 (1) See Note 13 for additional information regarding the computations presented here. Statement of cash Öows Ì For purposes of reporting cash Öows, 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. F-12 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) Recently Issued Accounting Standards Ì The Financial Accounting standards Board (""FASB'') issued StaÅ Position FIN 47, Accounting for Conditional Asset Retirement Obligations (""FIN 47''), an interpretation of FASB Statement No. 143, in March 2005. The statement clariÑes the term ""conditional asset retirement obligation'' as used in FASB 143. The provisions of FIN 47, which the Company adopted on December 31, 2005, did not have a material impact on the Company's Ñnancial position or results of operations. The 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. Under SFAS 123(R), companies would have been required to implement the standard as of the beginning of the Ñrst interim reporting period that begins after June 15, 2005. However, in April 2005, the SEC announced the adoption of an Amendment to Rule 4-01(a) of Regulation S-X regarding the compliance date for SFAS 123(R) that amends the compliance dates and allows companies to implement SFAS 123(R) beginning with the Ñrst annual reporting period beginning on or after June 15, 2005. The Company intends to adopt SFAS 123(R) on January 1, 2006. 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 intend to expense stock options using the ModiÑed Prospective Transition method as described in SFAS 123(R). This method will require expense to be recognized for stock options over their respective remaining vesting periods. No expense will be recognized for stock options vested in periods prior to the adoption of SFAS 123(R). We are evaluating the impact of the adoption of SFAS 123(R) on our results of operations and Ñnancial position. Adoption is not expected to have a material eÅect on our Ñnancial position or results of operations. The FASB issued Statement of Financial Accounting Standard No. 151, Inventory Costs Ì an amendment of ARB No. 43, Chapter 4 (""SFAS 151''). SFAS 151 is eÅective, and will be adopted, for inventory costs incurred during Ñscal 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 eÅect on our Ñnancial position or results of operations. The FASB issued Statement of Financial Accounting Standard No. 153, Exchanges of Nonmonetary Assets Ì an amendment of APB Opinion No. 29 (""SFAS 153''). FAS 153 is eÅective, and will be adopted, for nonmonetary asset exchanges occurring in Ñscal 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 Öows of the entity are expected to change signiÑcantly as a result of the exchange. Adoption is not expected to have a material eÅect on our Ñnancial position or results of operations. The FASB issued Statement of Financial Accounting standards No. 154, Accounting changes and Error Corrections Ì a replacement of APB Opinion No. 20 and FASB Statement No. 3 (""SFAS 154''). SFAS 154 is eÅective, and will be adopted for accounting changes made in Ñscal years beginning after December 15, 2005 and is to be applied retrospectively. SFAS 154 requires that retroactive application of a change in accounting principle be limited to the direct eÅects of the change. Adoption is not expected to have a material eÅect on the Company's Ñnancial position or results of operations. ReclassiÑcations Ì Certain reclassiÑcations have been made to the 2004 and 2003 consolidated Ñnancial statements in order for them to conform with the 2005 presentation. F-13 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) 2. Embezzlement and Restatements On November 3, 2005, the Company announced the resignation of its CFO, Jonathan D. Nelson (""Nelson''). On November 10, 2005, the Company announced that, based on information received by Company senior management on November 9, 2005, the Audit Committee of the Company's Board of Directors began an investigation into an apparent embezzlement from the Company by Nelson. On December 22, 2005, upon recommendation of Company management and the Audit Committee of its Board of Directors, the Company announced that based on the results to date of its internal investigation into the facts and circumstances surrounding the embezzlement by Nelson, the Company would restate previously issued Ñnancial statements and amend its previously issued Annual Report on Form 10-K for the year ended December 31, 2004 and Quarterly Reports on Form 10-Q for the periods ended March 31, June 30 and September 30, 2005. These restatements reÖect losses incurred as a result of payments made to or for the beneÑt of Nelson that had been recognized in the Company's accounting records and previously issued Ñnancial statements as payments for assets and services that were not received by the Company. Previously issued Ñnancial statements have also been restated for the eÅects of the correction of other errors that are immaterial both individually and in the aggregate. These other adjustments relate primarily to previously reported property and equipment balances that resulted from our review of our property and equipment records and the underlying physical assets in connection with investigation of the embezzlement. The Company has restated such Ñnancial statements, and on March 17, 2006, the Company Ñled its amended Annual Report on Form 10-K/A and on March 27, 2006, the Company Ñled its amended Quarterly Reports on Form 10-Q/A with the SEC. Most of the embezzled funds result from Nelson causing the wiring of Company funds aggregating approximately $72.3 million, to, or for the beneÑt of, entities owned and controlled by him. Nelson was originally able to initiate these wire transfers by requesting the wire transfers himself in telephone calls to one of the Company's banks. After changes to the Company's internal controls and procedures in 2004, Nelson initiated the wire transfers through instructions to one of his subordinates and by the creation of fraudulent invoices containing forged senior management approvals. This false documentation was created by our former CFO to conceal the true nature of these transactions from the Company and its independent registered public accountants. Nelson also instructed certain former employees, who worked under his supervision, to alter management reports related to property and equipment expenditures. Nelson also created Ñctitious property and equipment approval forms with forged signatures. The total amount embezzled was approximately $77.5 million in cash, excluding any tax eÅects, beginning with the year ended December 31, 1998 through November 3, 2005 as follows (in thousands): From 1998 to December 31, 2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ From January 1, 2005 to September 30, 2005(1)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total through September 30, 2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ From October 1, 2005 to November 3, 2005 (net of $1,500 repayment)(1) ÏÏÏÏÏÏÏÏÏ $58,961 12,193 71,154 6,350 Total embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $77,504 (1) The total amount embezzled during 2005 was $18,543,000 and the Company incurred $1,500,000 of professional fees and expenses as a result of the embezzlement. Accordingly, the total embezzled funds and related expenses in 2005 were $20,043,000. The Company promptly advised the United States Securities and Exchange Commission (""SEC'') when it became aware of the embezzlement. The SEC promptly obtained a freeze order on Nelson's assets F-14 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) (including assets held by entities controlled by him) and a Receiver was appointed to collect those assets. The United States attorney for the Northern District of Texas obtained an indictment against Nelson and investigation of this matter continues. The Company understands that the Receiver will ultimately liquidate the assets and propose a plan to distribute the proceeds. While the Company believes it has a claim for at least the full amount embezzled, other creditors have or may assert claims on the assets held by the Receiver. As a result, recovery by the Company from the Receiver is uncertain as to timing and amount, if any. Recoveries, if any, will be recognized when they are considered collectable. The Ñnancial statements and related Ñnancial and statistical data contained in this Report have been restated to provide for, net of related tax eÅects, (1) the eÅects of losses incurred as a result of the embezzlement and (2) the eÅects of the correction of other errors that are immaterial both individually and in the aggregate. The eÅects of the embezzlement and other adjustments on the company's Ñnancial position follow: Previously Reported As of December 31, EÅects of Adjustment for Embezzlement EÅects of Other Adjustments (In thousands) Restated $1,400,848 (571,973) 828,875 101,326 1,322,911 2,754 162,040 315,372 415,489 $(55,211) 1,348 (53,863) (2,270) (56,133) 1,311 (22,159) (20,848) (35,285) $(6,866) (3,127) (9,993) Ì (9,993) 166 594 760 (6,492) $1,338,771 (573,752) 765,019 99,056 1,256,785 4,231 140,475 295,284 373,712 11,611 1,007,539 Ì (35,285) (4,261) (10,753) 7,350 961,501 2004: Property and equipment: At costÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Accumulated depreciation ÏÏÏÏÏÏÏÏÏ NetÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Goodwill ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Federal and state income taxes payable Deferred tax liabilities, net ÏÏÏÏÏÏÏÏÏÏ Liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Retained earnings ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Accumulated other comprehensive income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Stockholders' equity ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2003: Federal and state income taxes receivable ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 12,667 $ (1,044) $ (170) $ 11,453 Property and equipment: At costÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Accumulated depreciation ÏÏÏÏÏÏÏÏÏ NetÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Goodwill ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Deferred tax liabilities, net ÏÏÏÏÏÏÏÏÏÏ Liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Retained earnings ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Accumulated other comprehensive income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Stockholders' equity ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 1,161,536 (467,905) 693,631 51,179 1,084,114 143,309 264,365 317,627 6,934 819,749 F-15 (38,240) 890 (37,350) (146) (38,540) (15,044) (15,044) (23,496) Ì (23,496) (4,992) (891) (5,883) Ì (6,053) 386 386 (3,894) (2,545) (6,439) 1,118,304 (467,906) 650,398 51,033 1,039,521 128,651 249,707 290,237 4,389 789,814 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) The eÅects of the embezzlement and other adjustments on the Company's results of operations and cash Öows follow: 2004: Depreciation, depletion, amortization and impairmentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Selling, general and administrative ÏÏÏÏÏÏ Other (including gain or loss on sale of assets)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Embezzled funds expenseÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Income before income taxes ÏÏÏÏÏÏÏÏÏÏÏ Income tax expenseÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Per common share: Year Ended December 31, EÅects of EÅects of Other Adjustment for Adjustments Embezzlement Previously Reported (In thousands, except per share amounts) Restated $ 119,395 32,007 $ (461) (24) $ 3,866 Ì $ 122,800 31,983 1,655 Ì 171,214 171,894 63,161 108,733 Ì 19,122 (18,637) (18,637) (6,848) (11,789) (244) Ì (4,110) (4,110) (1,512) (2,598) (0.02) (0.02) 1,411 19,122 148,467 149,147 54,801 94,346 0.57 0.56 Basic ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Diluted ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 0.65 0.64 (0.07) (0.07) Net cash provided by (used in): Operating activities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Investing activitiesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Acquisitions ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Purchases of property and equipment ÏÏÏÏ 222,289 (222,537) 32,514 191,560 (19,098) 19,098 (2,127) (16,971) Ì Ì Ì Ì 203,191 (203,439) 30,387 174,589 F-16 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) 2003: Depreciation, depletion, amortization and impairmentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Selling, general and administrative ÏÏÏÏÏÏ Other (including gain or loss on sale of assets)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Embezzled funds expenseÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Income before income taxes and cumulative eÅect of change in accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Income tax expenseÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Income before cumulative eÅect of change in accounting principleÏÏÏÏÏÏÏÏ Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Per common share: Basic ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Diluted ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Net cash provided by (used in): Year Ended December 31, EÅects of EÅects of Other Adjustment for Adjustments Embezzlement Previously Reported (In thousands, except per share amounts) Restated $ 97,998 27,709 $ (450) (24) $ 3,286 Ì $ 100,834 27,685 4,626 Ì 87,190 89,884 32,996 56,888 56,419 0.35 0.34 Ì 17,849 (17,375) (17,375) (6,378) (10,997) (10,997) (0.07) (0.07) (247) Ì (3,533) (3,533) (1,298) (2,235) (2,235) (0.01) (0.01) 4,379 17,849 66,282 68,976 25,320 43,656 43,187 0.27 0.26 Operating activities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Investing activitiesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Purchases of property and equipment ÏÏÏÏ 162,776 (154,603) 116,626 (17,825) 17,825 (17,825) Ì Ì Ì 144,951 (136,778) 98,801 3. Acquisitions 2005 Acquisitions Key Energy Services, Inc. Ì On January 15, 2005, the Company purchased land drilling assets from Key Energy Services, Inc. for $61.8 million. The assets included 25 active and 10 stacked land-based drilling rigs, related drilling equipment, yard facilities and a rig moving Öeet consisting of approximately 45 trucks and 100 trailers. The transaction was accounted for as an acquisition of assets and the purchase price was allocated among the assets acquired based on their estimated fair market values. Other Ì On June 17, 2005, the Company acquired one land-based drilling rig for $3.6 million and on September 29, 2005, the Company acquired Ñve land-based drilling rigs and related drilling equipment for $8.2 million. The transactions were accounted for as acquisitions of assets and the purchase price was allocated among the assets acquired based on their estimated fair market values. 2004 Acquisition TMBR/Sharp Drilling, Inc. Ì 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 Ñnancial 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 F-17 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) estimated fair market values. The assets of TMBR included 18 land-based drilling rigs and related equipment, shop facilities, equipment yards and their oil and natural gas properties. The purchase price was calculated as follows (restated (See Note 2), 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 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 40,423 Patterson-UTI shares issued at $17.82 per share (4,447 TMBR shares X .624332 exchange ratio X $17.82)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 1,059 TMBR shares previously acquired by the Company ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Acquisition costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Less: Cash acquired ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 49,476 19,771 10,511 (7,909) Total purchase price ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $112,272 The purchase price was allocated among assets acquired and liabilities assumed based on their estimated fair market values as follows (restated (See Note 2), in thousands): Current assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Fixed assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other long term assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Deferred tax assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ GoodwillÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Current liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other long term liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Deferred tax liabilityÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 7,181 60,784 172 13,080 48,020 (7,080) (1,090) (8,795) Total purchase allocation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $112,272 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 Ñnancial information as if the acquisition had been completed on January 1, 2003 (in thousands, except per share amounts): Revenue ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Income before cumulative eÅect of change in accounting principle ÏÏÏÏÏ Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Earnings per share: Basic ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Diluted ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Restated (See Note 2) 2003 2004 $1,005,357 94,047 94,047 $818,774 45,430 44,961 $ $ 0.57 0.56 $ $ 0.28 0.27 F-18 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) 2003 Acquisitions SEI Drilling Company Ì 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. Mesa Drilling, Inc. Ì 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 Ì 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 Ì 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 Ì 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 Ì 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. 4. Comprehensive Income The following table illustrates the Company's comprehensive income including the eÅects of foreign currency translation adjustments for the years ended December 31, 2005, 2004 and 2003 (in thousands): Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other comprehensive income: Foreign currency translation adjustment related to Canadian Restated (See Note 2) 2005 2004 2003 $372,740 $94,346 $43,187 operationsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 1,215 2,961 5,553 Comprehensive incomeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $373,955 $97,307 $48,740 F-19 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) 5. Property and Equipment Property and equipment consisted of the following at December 31, 2005 and 2004 (in thousands): Equipment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Oil and natural gas properties ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ BuildingsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Land ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $1,633,911 79,079 22,490 5,611 2005 Restated (See Note 2) 2004 $1,239,519 82,711 12,892 3,649 Less accumulated depreciation and depletion ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 1,741,091 (687,246) 1,338,771 (573,752) $1,053,845 $ 765,019 6. Goodwill Goodwill is evaluated to determine if the fair value of the asset has decreased below its carrying value. At December 31, 2005 the Company performed its annual goodwill evaluation and determined no adjustment to impair goodwill was necessary. Goodwill as of December 31, 2005 and 2004 are as follows (in thousands): Restated (See Note 2) 2004 2005 Drilling: Goodwill at beginning of period ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Goodwill in TMBR ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $89,092 Ì Ì $41,069 48,020 3 Goodwill at end of period ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 89,092 89,092 Drilling and completion Öuids: Goodwill at beginning of period ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Changes to goodwill ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Goodwill at end of period ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 9,964 Ì 9,964 9,964 Ì 9,964 Total goodwill ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $99,056 $99,056 7. Investment in Equity Securities As a result of the Company increasing its ownership of TMBR from 19.5% to 100% in 2004, the Company's consolidated Ñnancial statements for 2003 were previously restated to provide for the retroactive application of the equity method of accounting for the investment in TMBR. F-20 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) The following tables present the eÅects of all restatements for the year ended December 31, 2003 (in thousands, except per share amounts): Other income (loss) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Deferred income tax expense ÏÏÏÏÏÏÏÏÏ Net incomeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Comprehensive income, net of taxÏÏÏÏÏ Net income per common share: Previously Reported on Cost Basis EÅects of Adjustment to Equity Method $ 143 $17,274 $55,326 $65,689 $1,727 $ 634 $1,093 $ (497) EÅects of Adjustment for Embezzlement EÅects of Other Adjustments Ì $ $ (6,615) $(10,997) $(10,997) $ Ì $(1,297) $(2,235) $(5,455) Restated $ 1,870 $ 9,996 $43,187 $48,740 Basic ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Diluted ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ $ 0.34 0.34 $ 0.01 $ 0.01 $ $ (0.07) (0.07) $ (0.01) $ (0.01) $ 0.27 $ 0.26 8. Accrued Expenses Accrued expenses consisted of the following at December 31, 2005 and 2004 (in thousands): 2005 2004 Salaries, wages, payroll taxes and beneÑts ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Workers' compensation liability ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Sales, use and other taxes ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Insurance, other than workers' compensation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 33,816 47,107 9,484 11,365 10,704 $21,245 38,677 5,863 7,061 6,317 $112,476 $79,163 9. 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 following table describes the changes to the Company's asset retirement obligations during 2005 and 2004 (in thousands): 2005 2004 Balance at beginning of yearÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Liabilities incurred* ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Liabilities settled ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Accretion expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $2,358 101 (808) 74 $1,163 1,277 (153) 71 Asset retirement obligation at end of year ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $1,725 $2,358 * The 2004 amount includes $1,091 of liabilities assumed in the acquisition of TMBR. As a result of the Company's adoption of SFAS 143, a cumulative eÅect of change in accounting principle of approximately $469,000, net of tax, was recorded in the Ñrst quarter of 2003. F-21 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) 10. Notes Payable The Company replaced its prior credit facility in December 2004 with a Ñve-year, $200 million unsecured revolving line of credit (""LOC''). Interest is to be paid on outstanding LOC balances at a Öoating 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, 2005). 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 $56 million at December 31, 2005. There were no outstanding borrowings under the LOC at December 31, 2005. Costs of approximately $445,000 were expensed in 2004 to terminate the previous $100 million credit facility. 11. Commitments, Contingencies and Other Matters The Company maintains letters of credit in the aggregate amount of $56.0 million for the beneÑt 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 Ì The Company's contract services and oil and natural gas exploration and production operations are subject to inherent risks, including blowouts, cratering, Ñre 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 coverages up to $75.0 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. We have signed non-cancelable commitments to purchase $118 million of equipment to be received throughout 2006. Net income for the year ended December 31, 2005 includes a charge of $4.2 million related to the Ñnancial failure 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 suÇcient to protect the Company against liability for all consequences of well disasters, extensive Ñre 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. In December 2005, two purported derivative actions were Ñled in Texas state court in Scurry County, Texas, against the directors of the Company, alleging that the directors breached their Ñduciary duties to the Company as a result of alleged failure to timely discover the embezzlement. The Board of Directors formed a special litigation committee to review and inquire about these allegations and recommend the Company's response, if any. Further legal proceedings in these suits have been stayed pending completion of the work of the special litigation committee. The lawsuits seek recovery on behalf of and for the Company and do not seek recovery from the Company. F-22 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) The Company is party to various other 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 eÅect on its Ñnancial condition. Other Matters Ì EÅective January 29, 2004, the Company entered into Change in Control Agreements with its Chairman of the Board, Chief Executive OÇcer, President, two Senior Vice Presidents and Nelson (the ""Key Employees''). On November 3, 2005, Nelson resigned, which resulted in the expiration of his Change in Control Agreement. Each Change in Control Agreement generally has a three-year term with automatic twelve month renewals unless the Company notiÑes 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 deÑned 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 Ñscal years immediately preceding a change in control (such bonus payment prorated for the portion of the Ñscal year preceding the termination date); ‚ a payment equal to 2.5 times (in the case of the Chairman of the Board, Chief Executive OÇcer and President and Chief Operating OÇcer) or 1.5 times (in the case of the Senior Vice Presidents) of the sum of (i) the highest annual salary in eÅect for such Key Employee and (ii) the average of the three annual bonuses earned by the Key Employee for the three Ñscal 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 OÇcer and President and Chief Operating OÇcer) or two years (in the case of the Senior Vice Presidents). Each Change in Control Agreement provides the Key Employee with a full gross-up payment for any excise taxes imposed on payments and beneÑts received under the Change in Control Agreements or otherwise, including other taxes that may be imposed as a result of the gross-up payment. 12. Stockholders' Equity During the second quarters of 2004 and 2005 and third quarter of 2005, the Company granted restricted shares of the Company's common stock (the ""Restricted Shares'') to certain key employees under the Patterson-UTI Energy, Inc. 1997 Long-Term Incentive Plan, as amended, and the 2005 Plan. As required by APB 25, the Restricted Shares were valued based upon the market price of the Company's common stock on the date of the grant. The 2005 grants consisted of 305,000 restricted shares with a weighted average grant date fair value of $26.37 per share. The resulting value is being amortized over the vesting period of the stock. For the years ended December 31, 2005 and 2004, compensation expense of $1.8 million and $773,000, net of $327,000 and $5,000 of forfeitures and of $1.0 million and $449,000 of taxes, respectively, was included as a reduction in net income. On June 7, 2004, the Company's Board of Directors authorized a stock buyback program for the purchase of up to $30 million of the Company's outstanding 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 reÖect the two-for-one stock split on June 30, 2004). During the fourth quarter of 2005, the Company purchased 355,000 shares of its common stock in the open market for approximately $12.2 million. These shares are included in treasury stock. On March 27, 2006, the Company's Board of Directors increased the stock buyback program to allow the future purchases of up to $200 million of the Company's outstanding common stock. F-23 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) 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 eÅect 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, 2003. 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. Quarterly cash dividends in the amount of $0.04 per share were paid on March 4, 2005, June 1, 2005, September 1, 2005 and December 1, 2005. Total cash dividends in 2005 were approximately $27.3 million. The next quarterly cash dividend is to be paid to holders of record on March 15, 2006 and paid on March 30, 2006. 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, Ñnancial 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 reÖect 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 3). 13. Stock Options and Warrants Employee and Non-Employee Director Stock Option Plans Ì The Company has eight stock option plans of which one has shares available for grant. The remaining six plans are dormant and the Company does not F-24 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) intend to grant any further options under such plans. At December 31, 2005, the Company's stock option plans were as follows: Plan Name Options Authorized for Grant Options Outstanding Options Available for Grant Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (""2005 Plan'')(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 6,250,000 Ì 5,464,217 Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan, as amended (""1997 Plan'') Amended and Restated Patterson-UTI Energy, Inc. 2001 Ì 5,010,603 Long-Term Incentive Plan (""2001 Plan'')ÏÏÏÏÏÏÏÏÏÏÏÏ Ì 888,304 Amended and Restated Non-Employee Director Stock Option Plan of Patterson-UTI Energy, Inc. (""Non- Employee Director Plan'') ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 1997 Stock Option Plan of DSI Industries, Inc. (""DSI Plan'')ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee Stock Option Plan (""1996 Plan'') ÏÏÏÏÏÏÏÏÏ Patterson-UTI Energy, Inc., 1993 Incentive Stock Plan, as amended (""1993 Plan'') ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Ì Ì Ì Ì 200,000 536 95,800 142,800 Ì Ì Ì Ì Ì Ì (1) Plan is for the beneÑt of employees of the Company, including oÇcers and directors of the Company. The Company's active plan is the 2005 Plan. A summary of this plan is set forth below. 2005 Plan ‚ Administered by the Compensation Committee of the Board of Directors. ‚ All employees including oÇcers and directors are eligible for awards. ‚ Vesting schedule is set by the Compensation Committee, however, typically awards vest over 4 years. ‚ The Compensation Committee sets the term of the award except that no option can have a term of longer than 10 years. ‚ The awards granted under the plan, unless otherwise stated in the grant thereof, do not vest upon a change of control as deÑned in the plan. ‚ 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. ‚ The plan provides for awards of incentive stock options, non-incentive stock options, tandem and freestanding stock appreciation rights, restricted stock awards, other stock unit awards, performance share awards, performance unit awards and dividend equivalents. 1997 Plan Ì Options granted under the 1997 Plan vest over three or Ñve years as dictated by the Compensation Committee. These options typically had terms of ten years. 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. Restricted Stock Awards granted under the 1997 Plan vest over four years. 2001 Plan Ì Options granted under the 2001 Plan vest over Ñve years as dictated by the Compensation Committee. These options had terms of ten years. 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. Restricted Stock Awards granted under the 2001 Plan vest over four years. F-25 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) Non-Employee Director Plan Ì Options granted under the Non-Employee Director Plan vest on the Ñrst anniversary of the option grant. Non-Employee Director Plan options have Ñve 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 Ì 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 Ì Options granted under the 1996 plan vested over one, four and Ñve years as dictated by the Compensation Committee. These options had terms of Ñve 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 Ì Options granted under the 1993 Plan, typically had terms of 10 years and vested over Ñve years in 20% increments beginning at the end of the Ñrst year. These options vest in the event of a change of control as deÑned 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. A summary of the status of the Company's stock options issued as of December 31, 2005, 2004 and 2003 and the changes during each of the years then ended are presented below (in thousands, except weighted average exercise price): 2005 2004 2003 No. of Shares of Underlying Options Weighted Average Exercise Price No. of Shares of Underlying Options Weighted Average Exercise Price No. of Shares of Underlying Options Weighted Average Exercise Price Outstanding at beginning of year ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ GrantedÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Exercised ÏÏÏÏÏÏÏÏÏÏÏÏÏ Surrendered/Expired ÏÏÏÏ Outstanding at end of year Exercisable at end of year 10,006 675 (4,044) (299) 6,338 4,809 $12.24 24.63 10.75 15.23 $14.37 $13.33 12,276 640 (2,852) (58) 10,006 6,377 $10.31 19.19 5.55 8.76 $12.24 $11.68 12,277 1,830 (1,736) (95) 12,276 5,972 $ 8.81 16.24 5.92 9.99 $10.31 $ 8.15 F-26 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) The following table summarizes information about stock options outstanding at December 31, 2005: Range of Exercise Prices $1.5625 to $ 2.50 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2.51 to $ 5.00 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 5.01 to $ 7.50 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ $ 7.51 to $10.00 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 10.01 to $12.50 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 12.51 to $15.00 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 15.01 to $24.63 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Options Outstanding Options Exercisable Weighted Average Remaining Contracted Life 3.25 2.16 1.65 5.46 2.05 6.58 7.68 6.70 Number Outstanding 136,100 41,300 53,436 1,256,470 42,500 1,849,904 2,958,333 6,338,043 Weighted Average Exercise Price $ 2.24 $ 4.94 $ 7.36 $ 8.01 $11.48 $13.43 $18.53 Number Exercisable 136,100 41,300 53,436 879,170 42,500 1,680,771 1,976,111 Weighted Average Exercise Prices $ 2.24 $ 4.94 $ 7.36 $ 8.03 $11.48 $13.34 $16.81 $14.37 4,809,388 $13.33 Pro Forma Stock-Based Compensation Disclosure Ì 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 deÑned 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 2005 respectively; dividend yield of 0.65% for all 2005 grants, 0.06% for all 2004 grants and 0.00% for all other grants; risk-free interest rates are diÅerent 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, 36.84% for all 2004 grants and 26.95% for all 2005 grants. The eÅects 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 Ì 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. F-27 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) Tabular Summary Ì 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 Exercise Price Shares Granted 2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2003 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Exercised 2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2003 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Surrendered 2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2003 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Outstanding at Year End 675 640 1,830 4,044 3,502 1,941 299 58 95 2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2003 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 6,338 10,006 12,926 Exercisable at Year End 2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 2003 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 4,809 6,377 6,622 $24.63 $19.19 16.24 $10.75 $ 7.00 6.46 $15.23 $ 8.76 9.99 $14.37 $12.24 10.47 $13.33 $11.68 8.66 14. Leases The Company incurred rent expense, consisting primarily of daily rental charges for the use of drilling equipment, of $10.5 million, $9.1 million and $8.6 million, for the years 2005, 2004 and 2003, respectively. The Company's obligations under non-cancelable operating lease agreements are not material to the Company's operations. F-28 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) 15. Income Taxes Components of the income tax provision applicable for Federal, state and foreign income taxes are as follows (in thousands): Federal income tax expense (beneÑt): CurrentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Deferred ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $174,635 14,182 $32,686 12,366 $14,073 7,794 Restated (See Note 2) 2005 2004 2003 State income tax expense (beneÑt): CurrentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Deferred ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Foreign income tax expense (beneÑt): CurrentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Deferred ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 188,817 45,052 21,867 13,045 1,431 14,476 7,238 1,488 8,726 2,031 1,555 3,586 5,235 928 6,163 1,233 (487) 746 18 2,689 2,707 Total: CurrentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Deferred ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 194,918 17,101 39,952 14,849 15,324 9,996 Total income tax expenseÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $212,019 $54,801 $25,320 The diÅerence between the statutory Federal income tax rate and the eÅective income tax rate is summarized as follows: Restated (See Note 2) 2003 2004 2005 Statutory tax rate ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ State income taxes ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Permanent diÅerences ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other, netÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 35.0% 35.0% 35.0% 1.6 1.8 0.4 (0.6) (0.3) 0.1 1.5 0.8 (0.6) EÅective tax rateÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 36.3% 36.7% 36.7% 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 diÅerences 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, 2005 to be realized as a result of the reversal during the carryforward period of existing taxable temporary diÅerences giving rise to deferred tax liabilities and the generation of taxable income in the carryforward period; therefore, no valuation allowance is necessary. F-29 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) The tax eÅect of signiÑcant temporary diÅerences representing deferred tax assets and liabilities and changes therein were as follows (in thousands): December 31, 2005 Net Change December 31, 2004 Net Change Restated (See Note 2) December 31, 2003 Net Change January 1, 2003 Deferred tax assets: Current: Federal net operating loss carryforwardsÏÏ $ 1,870 $ Ì $ 1,870 $ 1,870 $ Ì $ Ì $ Ì Workers' compensation allowance ÏÏÏÏÏÏÏÏ AMT credit ÏÏÏÏÏÏÏÏ Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Non-current: Federal net operating loss carryforwardsÏÏ AMT credit ÏÏÏÏÏÏÏÏ Federal beneÑt of foreign deferred tax liabilities ÏÏÏÏÏÏÏÏÏ Federal beneÑt of state deferred tax liabilities ÏÏÏÏÏÏÏÏÏ Embezzled funds expense ÏÏÏÏÏÏÏÏÏÏ Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total deferred tax assets ÏÏ Deferred tax liabilities: Current: 19,461 Ì 11,364 32,695 4,584 Ì 4,386 8,970 14,877 Ì 6,978 23,725 1,545 (602) 1,238 4,051 13,332 602 5,740 19,674 6,159 Ì (1,775) 7,173 602 7,515 4,384 15,290 2,245 118 (1,870) Ì 4,115 118 4,115 118 Ì Ì Ì Ì Ì Ì 8,196 1,488 6,708 933 5,775 2,019 3,756 4,232 717 3,515 421 3,094 1,275 1,819 Ì 937 15,728 48,423 (22,178) 174 (21,669) (12,699) 22,178 763 37,397 61,122 7,193 763 13,543 17,594 14,985 Ì 23,854 43,528 6,713 Ì 10,007 14,391 8,272 Ì 13,847 29,137 Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ (6,313) 1,421 (7,734) (4,509) (3,225) (3,225) Ì Non-current: Property and equipment basis diÅerence ÏÏÏÏÏÏÏÏ Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total deferred tax (179,725) (5,191) (6,381) (663) (173,344) (4,528) (25,534) 167 (147,810) (4,695) (16,683) (4,795) (131,127) 100 (184,916) (7,044) (177,872) (25,367) (152,505) (21,478) (131,027) liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏ (191,229) (5,623) (185,606) (29,876) (155,730) (24,703) (131,027) Net deferred tax liabilityÏÏ $(142,806) $(18,322) $(124,484) $(12,282) $(112,202) $(10,312) $(101,890) Management expects to deduct accumulated net embezzlement losses in the Company's 2005 tax returns, which corresponds with the period in which the embezzlement was detected. F-30 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) Other deferred tax assets consist primarily of various allowance accounts and tax deferred expenses expected to generate future tax beneÑt of approximately $12 million. Other deferred tax liabilities consist primarily of receivables from insurance companies and tax deferred income not yet recognized for tax purposes. For tax purposes, the Company has available at December 31, 2005, Federal net operating loss carryforwards of approximately $11 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: 2006 Ì $1 million, 2011 Ì $2 million, 2018 Ì $4 million and 2019 Ì $4 million. The alternative minimum tax credit may be carried forward indeÑnitely. 16. Employee BeneÑts The Company maintains a 401(k) plan for all eligible employees. The Company's operating results include expenses of approximately $2.7 million in 2005, $2.2 million in 2004 and $1.5 million in 2003 for the Company's discretionary contributions to the plan. 17. 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 Öuids 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 oÅered. These segments have separate management teams which report to the Company's chief executive oÇcer and have distinct and identiÑable revenues and expenses. Contract Drilling Ì The Company markets its contract drilling services to major and independent oil and natural gas operators. As of December 31, 2005, the Company owned 403 drilling rigs, of which 156 of the drilling rigs were based in the Permian Basin region, 53 in South Texas, 42 in the Ark-La-Tex region and Mississippi, 88 in the Mid-Continent region, 46 in the Rocky Mountain region and 18 in Western Canada. The Company operated 307 of its drilling rigs in 2005. Pressure Pumping Ì 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 Öow 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 Ì The Company provides drilling Öuids, completion Öuids and related services to oil and natural gas operators oÅshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. Drilling and completion Öuids are used by oil and natural gas operators during the drilling process to control pressure when drilling oil and natural gas wells. The drilling Öuids 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 Öuids in October 2000 with the acquisition of the drilling and completion Öuids division of Ambar, Inc., which had operations in the coastal areas of Texas, Louisiana and in the Gulf of Mexico. Oil and Natural Gas Ì The Company is engaged in the development, exploration, acquisition and production of oil and natural gas. F-31 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) The following tables summarize selected Ñnancial information relating to the Company's business segments (in thousands): Years Ended December 31, 2005 Restated (See Note 2) 2003 2004 Revenues: Contract drilling(a) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Pressure pumpingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Drilling and completion Öuids(b) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $1,488,485 93,144 122,309 39,616 $ 815,683 66,654 90,858 33,867 $ 640,788 46,083 69,286 21,163 Total segment revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Elimination of intercompany revenues(a)(b)ÏÏÏÏÏÏÏÏ 1,743,554 1,007,062 (3,099) (6,293) 777,320 (1,150) Total revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $1,740,455 $1,000,769 $ 776,170 Income (loss) before income taxes: Contract drilling ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Pressure pumpingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 572,562 21,664 11,947 13,405 $ 146,626 16,747 4,202 10,764 $ Corporate and otherÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other charges(c) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Embezzled funds and related expenses(d) ÏÏÏÏÏÏÏÏÏÏ Interest incomeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Interest expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 619,578 (14,223) (4,016) (20,043) 3,551 (516) 428 178,339 (10,750) Ì (19,122) 1,140 (695) 235 72,814 10,442 (1,920) 7,784 89,120 (7,441) 2,452 (17,849) 1,116 (292) 1,870 Income before income taxes ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 584,759 $ 149,147 $ 68,976 IdentiÑable assets: Contract drilling ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Pressure pumpingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Corporate and other(e)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $1,421,779 72,536 90,904 60,785 1,646,004 149,777 $ 961,873 49,145 62,970 62,984 1,136,972 119,813 $ 766,039 35,066 56,215 37,111 894,431 145,090 Total assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $1,795,781 $1,256,785 $1,039,521 Depreciation, depletion and impairment: Contract drilling(d) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Pressure pumpingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 131,740 7,094 2,368 14,456 Corporate and otherÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 155,658 735 $ 101,779 5,112 2,156 13,309 122,356 444 $ 87,255 3,774 2,279 7,082 100,390 444 Total depreciation, depletion and impairment ÏÏÏÏÏÏÏÏÏ $ 156,393 $ 122,800 $ 100,834 F-32 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) Years Ended December 31, 2005 Restated (See Note 2) 2003 2004 Capital expenditures: Contract drilling(d) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Pressure pumpingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Corporate and otherÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 329,073 25,508 3,042 17,163 5,308 $ 140,945 17,705 1,488 14,451 Ì $ 77,350 10,524 912 10,015 Ì Total capital expenditures ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 380,094 $ 174,589 $ 98,801 (a) Includes contract drilling intercompany revenues of approximately $2.8 million, $6.0 million and $1.1 million for the years ended December 31, 2005, 2004 and 2003, respectively. (b) Includes drilling and completion Öuids intercompany revenues of approximately $298,000, $301,000 and $56,000 for the years ended December 31, 2005, 2004 and 2003, respectively. (c) 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 speciÑc segments. These charges are primarily related to the contract drilling segment. (d) The Company's former CFO perpetrated an embezzlement over a period of more than Ñve years. Embezzled funds expense includes adjustments to eliminate payments related to the embezzlement previously capitalized as property and equipment and goodwill acquired. The related depreciation and other amounts expensed have also been reversed from the Company's accounting records (See Note 2). (e) Corporate assets primarily include cash on hand managed by the parent corporation and certain deferred Federal income tax assets. 18. Quarterly Financial Information (unaudited) On December 22, 2005, upon recommendation of Company management and the Audit Committee of its Board of Directors, the Company announced that based on the results to date of its internal investigation into the facts and circumstances surrounding the embezzlement by Nelson, the Company would restate previously issued Ñnancial statements and amend its previously issued Annual Report on Form 10-K for the year ended December 31, 2004 and Quarterly Reports on Form 10-Q for the periods ended March 31, June 30 and September 30, 2005. These restatements reÖect losses incurred as a result of payments made to or for the beneÑt of Nelson that had been recognized in the Company's accounting records and previously issued Ñnancial statements as payments for assets and services that were not received by the Company. Previously issued Ñnancial statements have also been restated for the eÅects of the correction of other errors that are immaterial both individually and in the aggregate. These other adjustments relate primarily to previously reported property and equipment balances that resulted from our review of our property and equipment records and the underlying physical assets in connection with investigation of the embezzlement. The Company has restated such financial statements, and on March 17, 2006, the Company filed its amended Annual Report on Form 10-K/A and on March 27, 2006, the Company filed its amended Quarterly Reports on Form 10-Q/A with the SEC. Quarterly financial information and the F-33 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) related effects of the restatement due to the embezzlement and other adjustments for the years ended December 31, 2005 and 2004 is as follows (in thousands, except per share amounts): Restated (See Note 2) 2nd Quarter 3rd Quarter 1st Quarter 4th Quarter 2005 Operating revenuesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $350,593 Operating income: $389,922 $468,739 $531,201 As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 94,252 Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ (1,381) (1,038) $122,416 $173,511 $ (4,717) (1,048) (4,721) (1,344) Ì Ì Ì $ 91,833 $116,651 $167,446 $205,366 Net income: As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 59,748 (872) Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ (656) Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 77,665 $110,135 $ (2,978) (661) (2,981) (849) Ì Ì Ì $ 58,220 $ 74,026 $106,305 $134,189 Earnings per share: Basic: As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ $ Diluted: As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ $ 0.35 (0.01) $ $ Ì $ $ 0.34 0.35 (0.01) $ $ Ì $ $ 0.34 0.46 (0.02) $ $ Ì $ $ 0.44 0.45 (0.02) $ $ Ì $ $ 0.43 0.64 (0.02) $ $ Ì $ $ 0.62 0.63 (0.02) $ $ Ì $ $ 0.61 Ì Ì Ì 0.78 Ì Ì Ì 0.77 1st Quarter Restated (See Note 2) 2nd Quarter 3rd Quarter 4th Quarter 2004 Operating revenuesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $218,779 Operating income: $234,510 $259,174 $288,306 As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 32,510 (5,013) Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ (927) Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 30,799 (3,470) (1,002) $ 47,408 (4,642) (1,024) $ 60,497 (5,512) (1,157) $ 26,570 $ 26,327 $ 41,742 $ 53,828 F-34 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) 1st Quarter Restated (See Note 2) 2nd Quarter 3rd Quarter 4th Quarter Net income: As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 20,682 (3,164) Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ (585) Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 19,607 (2,186) (631) $ 29,964 (2,921) (645) $ 38,480 (3,518) (737) $ 16,933 $ 16,790 $ 26,398 $ 34,225 Earnings per share: Basic: As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ $ Diluted: As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ $ 19. Concentrations of Credit Risk 0.12 (0.02) $ $ Ì $ $ 0.10 0.12 (0.02) $ $ Ì $ $ 0.10 0.12 (0.01) $ $ Ì $ $ 0.10 0.12 (0.01) $ $ Ì $ $ 0.10 0.18 (0.02) $ $ Ì $ $ 0.16 0.18 (0.02) $ $ Ì $ $ 0.16 0.23 (0.02) Ì 0.20 0.23 (0.02) Ì 0.20 Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of demand deposits, temporary cash investments and trade receivables. The Company believes that it places its demand deposits and temporary cash investments with high credit quality Ñnancial institutions. At December 31, 2005 and 2004, the Company's demand deposits and temporary cash investments consisted of the following (in thousands): 2005 2004 Deposits in FDIC and SIPC-insured institutions under $100,000 ÏÏÏÏÏÏÏÏ Deposits in FDIC and SIPC-insured institutions over $100,000 ÏÏÏÏÏÏÏÏÏ Deposits in Foreign Banks ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 1,066 153,261 2,513 $ 2,023 131,427 Ì Less outstanding checks and other reconciling itemsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 156,840 (20,442) 133,450 (21,079) Cash and cash equivalents ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $136,398 $112,371 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 diversiÑcation 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 signiÑcant losses from individual contracts were experienced during the years ended December 31, 2005, 2004, or 2003. The Company recognized bad debt expense for 2005, 2004 and 2003 of $1.2 million, $897,000 and $259,000, respectively. The carrying values of cash and cash equivalents, marketable securities and trade receivables approxi- mate fair value due to the short-term maturity of these assets. F-35 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued) 20. Related Party Transactions Joint Operation of Oil and Natural Gas Properties Ì The Company operates certain oil and natural gas properties in which certain of its aÇliated 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, 2005, aÇliated persons were working interest owners in 254 of 305 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 aÇliated persons was the same price at which working interests were sold to unaÇliated persons. The aÇliated persons earned oil and natural gas production revenue (net of royalty) of $15.5 million, $13.8 million and $11.1 million from these properties in 2005, 2004 and 2003, respectively. These persons or entities in turn paid for joint operating costs (including drilling and other development expenses) of $9.5 million, $7.5 million and $7.9 million incurred in 2005, 2004 and 2003, respectively. These activities resulted in a payable to the aÇliated persons of approximately $1.5 million and $1.2 million and a receivable from the aÇliated persons of approximately $1.2 million and $856,000 at December 31, 2005 and 2004, respectively. Other Ì In 2005, 2004 and 2003, the Company paid approximately $424,000, $914,000 and $740,000, respectively, to TMP Truck and Trailer LP (""TMP''), during the period it was 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 2005 and 2004, the Company paid approximately $273,000 and $39,000, respectively, to Melco Services (""Melco'') for dirt contracting services and $59,000 and $44,000, respectively, to L&N Transporta- tion (""L&N'') for water hauling services. Both entities are owned by Lance D. Nelson, brother of Jonathan D. Nelson, Patterson-UTI's former CFO. Purchases from Melco and L&N were at current market prices. See Note 2 for information pertaining to fraudulent payments made to or for the beneÑt of Jonathan D. Nelson, our former CFO. F-36 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES SCHEDULE II Ì VALUATION AND QUALIFYING ACCOUNTS Description Year Ended December 31, 2005 Deducted from asset accounts: Beginning Balance Charged to Costs and Expenses(1) Deductions(2) Ending Balance (In thousands) Allowance for doubtful accounts ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $1,909 $1,231 $ 941 $2,199 Year Ended December 31, 2004 Deducted from asset accounts: Allowance for doubtful accounts ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $2,133 $ 897 $1,121 $1,909 Year Ended December 31, 2003 Deducted from asset accounts: Allowance for doubtful accounts ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $3,144 $ 259 $1,270 $2,133 (1) Net of recoveries. (2) Uncollectible accounts written oÅ. S-1 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 on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized. SIGNATURES PATTERSON-UTI ENERGY, INC. By: /s/ CLOYCE A. TALBOTT Cloyce A. Talbott Chief Executive OÇcer Date: March 30, 2006 Pursuant to the requirements of the Securities Exchange Act of 1934, this Report on Form 10-K has been signed by the following persons on behalf of Patterson-UTI Energy, Inc. and in the capacities indicated as of March 30, 2006. Signature Title /s/ MARK S. SIEGEL Mark S. Siegel /s/ CLOYCE A. TALBOTT Cloyce A. Talbott (Principal Executive OÇcer) Chairman of the Board Chief Executive OÇcer and Director /s/ A. GLENN PATTERSON President, Chief Operating OÇcer and Director A. Glenn Patterson /s/ KENNETH N. BERNS Kenneth N. Berns Senior Vice President and Director /s/ JOHN E. VOLLMER III John E. Vollmer III (Principal Financial and Accounting OÇcer) Senior Vice President Ì Corporate Development, Chief Financial OÇcer, Secretary and Treasurer /s/ ROBERT C. GIST Robert C. Gist /s/ CURTIS W. HUFF Curtis W. HuÅ /s/ TERRY H. HUNT Terry H. Hunt /s/ KENNETH R. PEAK Kenneth R. Peak /s/ NADINE C. SMITH Nadine C. Smith Director Director Director Director Director EXHIBIT 31.1 I, Cloyce A. Talbott, certify that, CERTIFICATIONS 1. I have reviewed this annual report on Form 10-K of Patterson-UTI Energy, Inc. 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the Ñnancial statements, and other Ñnancial information included in this report, fairly present in all material respects the Ñnancial condition, results of operations and cash Öows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying oÇcer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as deÑned in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over Ñnancial reporting (as deÑned in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over Ñnancial reporting, or caused such internal control over Ñnancial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of Ñnancial reporting and the preparation of Ñnancial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the eÅectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the eÅectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over Ñnancial reporting that occurred during the registrant's most recent Ñscal quarter (the registrant's fourth Ñscal quarter in the case of an annual report) that has materially aÅected, or is reasonably likely to materially aÅect, the registrant's internal control over Ñnancial reporting; and 5. The registrant's other certifying oÇcers and I have disclosed, based on our most recent evaluation of internal control over Ñnancial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all signiÑcant deÑciencies and material weaknesses in the design or operation of internal control over Ñnancial reporting which are reasonably likely to adversely aÅect the registrant's ability to record, process, summarize and report Ñnancial information; and (b) any fraud, whether or not material, that involves management or other employees who have a signiÑcant role in the registrant's internal control over Ñnancial reporting. Date: March 30, 2006 /s/ CLOYCE A. TALBOTT Cloyce A. Talbott Chief Executive OÇcer EXHIBIT 31.2 I, John E. Vollmer III, certify that: CERTIFICATIONS 1. I have reviewed this annual report on Form 10-K of Patterson-UTI Energy, Inc. 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the Ñnancial statements, and other Ñnancial information included in this report, fairly present in all material respects the Ñnancial condition, results of operations and cash Öows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying oÇcers and I are responsible for establishing and maintaining disclosure controls and procedures (as deÑned in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over Ñnancial reporting (as deÑned in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over Ñnancial reporting, or caused such internal control over Ñnancial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of Ñnancial reporting and the preparation of Ñnancial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the eÅectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the eÅectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over Ñnancial reporting that occurred during the registrant's most recent Ñscal quarter (the registrant's fourth Ñscal quarter in the case of an annual report) that has materially aÅected, or is reasonably likely to materially aÅect, the registrant's internal control over Ñnancial reporting; and 5. The registrant's other certifying oÇcers and I have disclosed, based on our most recent evaluation of internal control over Ñnancial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all signiÑcant deÑciencies and material weaknesses in the design or operation of internal control over Ñnancial reporting which are reasonably likely to adversely aÅect the registrant's ability to record, process, summarize and report Ñnancial information; and (b) any fraud, whether or not material, that involves management or other employees who have a signiÑcant role in the registrant's internal control over Ñnancial reporting. /s/ JOHN E. VOLLMER III John E. Vollmer III Senior Vice President Ì Corporate Development, Chief Financial OÇcer, Secretary and Treasurer Date: March 30, 2006 Corporate Information Corporate Office Directors Corporate Officers Mark S. Siegel Chairman Cloyce A. Talbott President and Chief Executive Officer Kenneth N. Berns Senior Vice President John E. Vollmer III Senior Vice President- Corporate Development, Chief Financial Officer, Secretary and Treasurer Patterson-UTI Energy, Inc. P.O. Box 1416 Snyder, Texas 79550 4510 Lamesa Highway Snyder, Texas 79549 Telephone: (325) 574-6300 Fax: (325) 574-6390 www.patenergy.com Common Stock Nasdaq: PTEN Transfer Agent Continental Stock Transfer & Trust Company 17 Battery Place New York, NY 10004 Toll-Free number: (800) 509-5586 www.continentalstock.com Independent Auditor PricewaterhouseCoopers LLP Corporate Counsel Fulbright & Jaworski LLP Mark S. Siegel Chairman, Patterson-UTI Energy, Inc.; President, Remy Investors and Consultants, Incorporated Cloyce A. Talbott President and Chief Executive Officer, Patterson-UTI Energy, Inc. Glenn Patterson Former President and Chief Operating Officer, Patterson-UTI Energy, Inc. Kenneth N. Berns Senior Vice President, Patterson-UTI Energy, Inc. Robert C. Gist Attorney at Law Curtis W. Huff President and Chief Executive Officer, Freebird Investments LLC Terry H. Hunt Energy Consultant and Investor Kenneth R. Peak President and Chief Executive Officer, Contango Oil & Gas Nadine C. Smith Business Consultant and Investor Patterson-UTI Energy, Inc. P.O. Box 1416 Snyder, Texas 79550 4510 Lamesa Highway Snyder, Texas 79549 Telephone: (325) 574-6300 Fax: (325) 574-6390 www.patenergy.com 

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